TELLURIAN INC. /DE/ - Quarter Report: 2011 December (Form 10-Q)

TELLURIAN INC. /DE/ - Quarter Report: 2011 December (Form 10-Q)

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(MARK ONE)

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

For the quarterly period ended December 31, 2011

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

For the transition period from to

Commission files number 1-5507

MAGELLAN PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


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

7 Custom House Street, Portland, Maine		04101
(Address of principal executive offices)		(Zip Code)

(207) 619-8500

(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. x 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). x 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.

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

The number of shares outstanding of the issuer’s single class of common stock as February 3, 2012 was 53,835,594.

MAGELLAN PETROLEUM CORPORATION

FORM 10-Q

TABLE OF CONTENTS


		PAGE

PART I — FINANCIAL INFORMATION

ITEM 1	UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Condensed Consolidated Balance Sheets		1

	Condensed Consolidated Statements of Operations		2

	Condensed Consolidated Statements of Cash Flows		3

	Condensed Consolidated Statements of Comprehensive (Loss) Income		4

	Condensed Consolidated Statement of Changes in Equity		5

	Notes to Condensed Consolidated Financial Statements (unaudited)		6

ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17

ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		27

ITEM 4	CONTROLS AND PROCEDURES		27

PART II — OTHER INFORMATION

ITEM 1A	RISK FACTORS		28

ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		28

ITEM 4	MINE SAFETY		28

ITEM 5	OTHER EVENTS		29

ITEM 6	EXHIBITS		30

	SIGNATURES		32

	CERTIFICATIONS

EX-31	CERTIFICATIONS

EX-32	CERTIFICATIONS

PART I - FINANCIAL INFORMATION

ITEM 1 FINANCIAL STATEMENTS

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	December 31,			June 30,
	2011			2011
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	18,823,998		$	20,416,625
Marketable securities		2,599,595			—
Accounts receivable — trade (net of allowance for doubtful accounts of $0 and $66,702 as of December 31, 2011 and June 30, 2011, respectively)		1,863,518			4,356,621
Accounts receivable — working interest partners		636,819			453,843
Deposit on Evans Shoal		—			10,745,061
Inventories		599,398			731,672
Assets held for sale		2,082,278			—
Prepaid assets		625,293			517,482
Other assets		11,674			61,934

Total current assets		27,242,573			37,283,238


Property and equipment, net (successful efforts method):
Proved oil and gas properties		33,603,242			136,094,121
Less accumulated depletion, depreciation and amortization		(11,130,368	)		(115,916,596	)
Unproved oil and gas properties		3,182,195			3,367,972
Wells in progress		6,219,280			4,315,236
Land, buildings and equipment (net of accumulated depreciation of $2,311,021 and $3,984,985 as of December 31, 2011 and June 30, 2011, respectively)		975,212			1,293,450

Net property and equipment		32,849,561			29,154,183

Other non-current assets:
Securities available for sale		146,968			238,070
Goodwill		4,695,204			4,695,204
Other long term assets		241,928			204,457

Total other non-current assets		5,084,100			5,137,731


Total assets	$	65,176,234		$	71,575,152


LIABILITIES AND EQUITY
Current liabilities:
Short term line of credit	$	775,000		$	500
Current portion of note payable		528,000			552,000
Accounts payable		2,256,534			3,860,919
Accrued liabilities		2,243,912			2,056,717
Other liabilities		12,127			—
Liability related to assets held for sale		6,550,129			—

Total current liabilities		12,365,702			6,470,136

Long term liabilities:
Note payable		606,438			870,438
Other long term liabilities		312,094			309,758
Asset retirement obligations		5,175,581			11,397,410
Contingent liability		4,232,000			—

Total long term liabilities		10,326,113			12,577,606

Commitments and contingencies
Equity:
Common stock (par value $.01 per share): Authorized 300,000,000 shares, outstanding, 53,835,594 and 52,455,977 as of December 31, 2011 and June 30, 2011, respectively		538,354			524,558
Capital in excess of par value		90,002,236			93,617,424
Preferred stock (par value $.01 per share): Authorized 50,000,000 and -0- shares, outstanding, -0- and -0- as of December 31, 2011 and June 30, 2011, respectively		—			—
Accumulated deficit		(59,705,526	)		(56,073,255	)
Accumulated other comprehensive income		11,649,355			12,469,626

Total equity attributable to Magellan Petroleum Corporation		42,484,419			50,538,353
Non-controlling interest in subsidiaries		—			1,989,057

Total equity		42,484,419			52,527,410

Total liabilities and equity	$	65,176,234		$	71,575,152

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

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	THREE MONTHS ENDED December 31,						SIX MONTHS ENDED December 31,
	2011			2010			2011			2010
	(unaudited)						(unaudited)
REVENUES:
Oil production	$	2,700,682		$	2,756,212		$	5,996,343		$	4,926,858
Gas production		498,072			458,420			975,909			867,680
Other		3,584			1,246,372			(34,566	)		2,365,647

Total revenues		3,202,338			4,461,004			6,937,686			8,160,185

OPERATING EXPENSES:
Lease operating		3,258,822			2,520,539			6,276,697			4,359,702
Depletion, depreciation, amortization, and accretion		366,454			429,323			840,928			1,568,353
Exploration		1,006,278			614,569			1,993,766			1,028,239
General and administrative		3,346,791			5,036,713			5,858,056			9,323,059
Loss (gain) on sale of assets		97,832			(443,035	)		(4,009,888	)		(463,177	)

Total operating expenses		8,076,177			8,158,109			10,959,559			15,816,176

Loss from operations		(4,873,839	)		(3,697,105	)		(4,021,873	)		(7,655,991	)
Other income (expense)
Interest income, net		118,857			221,494			389,815			467,810
Other expenses		(213	)		—			(213	)		—

Total other income		118,644			221,494			389,602			467,810

Loss before income tax benefit		(4,755,195	)		(3,475,611	)		(3,632,271	)		(7,188,181	)
Income tax benefit		198,326			1,378,316			—			1,679,652

Net loss after income tax benefit		(4,556,869	)		(2,097,295	)		(3,632,271	)		(5,508,529	)
Net (loss) income attributable to non-controlling interest in subsidiaries		—			(1,838	)		15,401			33,275

Net loss attributable to Magellan Petroleum Corporation	$	(4,556,869	)	$	(2,099,133	)	$	(3,616,870	)	$	(5,475,254	)


Average number of basic and dilutive common shares outstanding		53,835,594			52,335,977			53,378,216			52,335,977

Net loss per basic and dilutive common shares attributable to Magellan Petroleum Corporation common shareholders	$	(0.08	)	$	(0.04	)	$	(0.07	)	$	(0.10	)

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

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	SIX MONTHS ENDED
	December 31,
	2011			2010
	(unaudited)
OPERATING ACTIVITIES:
Net loss	$	(3,632,271	)	$	(5,508,529	)
Adjustments to reconcile net loss to net cash used in operating activities

Foreign transaction (gain) loss (1)		(942,204	)		232,212
Depletion, depreciation and amortization		840,928			1,568,353
Interest earned on restricted deposits		(23,555	)		—
Accretion of contingent consideration		81,000			—
Amortization of loan fees		5,142			—
Deferred income taxes		—			(1,758,907	)
Gain on disposal of assets		(4,009,888	)		(463,177	)
Loss (gain) from sale of investments		—			(1,894	)
Exploration and dry hole costs		—			60,605
Stock based compensation		886,355			1,203,396
Net changes in operating assets and liabilities:
Accounts receivable		1,757,189			1,724,334
Inventories		(796,349	)		69,894
Prepayments and other current assets		(162,905	)		356,949
Accounts payable and accrued liabilities		(1,899,135	)		(245,467	)
Other long term liabilities		(17,074	)		—
Income taxes payable		60,645			(571,779	)


Net cash used in operating activities (1)		(7,852,127	)		(3,334,010	)

INVESTING ACTIVITIES:
Additions to property and equipment		(3,212,846	)		(3,373,694	)
Proceeds from sale of assets		5,000,709			467,844
Purchase of working interest in Poplar		(823,299	)		—
Refund of Deposit for Purchase of Evans Shoal (includes interest)		10,939,906			—
Marketable securities matured or sold		3,086,960			3,206,250
Marketable securities purchased		(5,686,555	)		(6,999,735	)


Net cash provided by (used in) investing activities		9,304,875			(6,699,335	)


FINANCING ACTIVITIES:
Proceeds from issuance of stock		35,000			—
Short term debt issuances		3,799,500			1,805,000
Short term debt repayments		(3,025,000	)		(1,924,408	)
Purchase of non-controlling interest - Nautilus Poplar, LLC		(3,461,120	)		(380,000	)
Non-controlling capital contribution - Nautilus Poplar, LLC		—			80,000
Long term debt repayments		(288,000	)		—


Net cash used in financing activities		(2,939,620	)		(419,408	)

Effect of exchange rate changes on cash and cash equivalents (1)		(105,760	)		4,952,402


Net decrease in cash and cash equivalents		(1,592,627	)		(5,500,351	)
Cash and cash equivalents at beginning of period		20,416,625			33,591,534


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	18,823,998		$	28,091,183


Cash Payments:
Income taxes		25,924			651,034
Interest paid, net of amount capitalized		55,720			37,198

Supplemental Schedule of Noncash Investing and Financing Activities:
Unrealized holding (loss) gain		(91,102	)		60,360
Revision to estimate of asset retirement obligations		—			189,108
Write off of expired license		—			79,921
Amounts in accounts payable and accrued liabilities related to property and equipment		917,510			831,687
Purchase of non-controlling interest for Stock and contingent consideration		4,729,316			—
Purchase of 3% working interest for Stock and contingent consideration		1,243,107			—

(1)	See Note 3 for explanation of restatement of prior period amount.

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

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME


	THREE MONTHS ENDED						SIX MONTHS ENDED
	December 31,						December 31,
	2011			2010			2011			2010
	(unaudited)						(unaudited)
Net loss	$	(4,556,869	)	$	(2,097,295	)	$	(3,632,271	)	$	(5,508,529	)
Foreign currency translation adjustments		512,734			2,517,107			(729,169	)		8,695,486
Unrealized holding (losses) gains, net of deferred tax of $0		(57,330	)		60,360			(91,102	)		60,360

Total comprehensive (loss) income		(4,101,465	)		480,172			(4,452,542	)		3,247,317
Net (loss) income attributable to non-controlling interest in subsidiary		—			(1,838	)		15,401			33,275

Comprehensive (loss) income attributable to Magellan Petroleum Corporation	$	(4,101,465	)	$	478,334		$	(4,437,141	)	$	3,280,592

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

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(unaudited)


	Common Stock		Preferred Stock		Capital in Excess of Par Value			Accumulated Deficit			Accumulated Other Comprehensive Income			Non- controlling Interest			Total

June 30, 2011	$	524,558		—	$	93,617,424		$	(56,073,255	)	$	12,469,626		$	1,989,057		$	52,527,410

Net loss									(3,616,870	)					(15,401	)		(3,632,271	)
Acquisition of non-controlling interest		9,302				(4,920,880	)		(15,401	)					(1,973,656	)		(6,900,635	)

Acquisition of working interest		2,525				386,306												388,831
Foreign currency translation adjustments												(729,169	)					(729,169	)
Unrealized holding loss, net of taxes												(91,102	)					(91,102	)
Stock and stock based compensation		1,750				884,605												886,355
Stock options exercised		219				34,781												35,000


December 31, 2011	$	538,354		—	$	90,002,236		$	(59,705,526	)	$	11,649,355		$	—		$	42,484,419

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

MAGELLAN PETROLEUM CORPORATION

ITEM 1 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 Basis of Presentation

Presentation

Magellan Petroleum Corporation (the “Company” or “Magellan” or “MPC” or “we” or “us”) is an independent energy company engaged in the acquisition, exploration, exploitation, development, production and sale of crude oil and natural gas. At December 31, 2011, MPC had two reporting segments: (1) 100% equity interest in its subsidiary, Magellan Petroleum Australia Limited (“MPAL”) headquartered in Brisbane, Australia and (2) 100% membership interest in Nautilus Poplar, LLC (“NP”), based in Denver, Colorado. Please refer to Note 4 for more details on corporate restructuring.

The accompanying unaudited condensed consolidated financial statements include the accounts of MPC and its subsidiaries, MPAL and NP. All intercompany transactions have been eliminated. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete 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. Operating results for the three and six months ended December 31, 2011, are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2012. For further information, refer to 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, 2011.

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

Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation.

Use of Estimates

Certain estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes have been made. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates.

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. ASC 350, Intangibles—Goodwill and Other (ASC 350) requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if events occur or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. The Company has determined that it has two reporting units, MPAL and NP. Historical goodwill in the amount of $4,020,704 relates to the acquisition of additional ownership interest in MPAL and $674,500 relates to the acquisition of a majority ownership stake in NP prior to the corporate restructuring as set forth in Note 4. The Company performs its goodwill test annually for both MPAL (during June) and NP (during October), or more often if circumstances require. No goodwill impairment was deemed necessary for the six months ended December 31, 2011 and 2010, respectively.

Securities available for sale

The Company classifies securities that have a readily determinable fair value and are not bought and held principally for the purpose to be sold in the near term, as securities available for sale. As of December 31, 2011, and June 30, 2011, securities available for sale consisted of a stock investment. Unrealized holding gains and losses related to securities available for sale are excluded from earnings and reported in accumulated other comprehensive income until realized. Net unrealized losses related to these securities was $91,102 for the six months ended December 31, 2011, and is included in accumulated other comprehensive income.

Note 2 Evans Shoal Agreement

On March 25, 2010, MPAL entered into an agreement with Santos Offshore Pty Ltd (“Asset Sales Deed”), to purchase Santos’ 40% interest in the Evans Shoal natural gas field (NT/P48) (“Evans Shoal Transaction”). On January 31, 2011, the Asset Sales Deed was amended pursuant to a Deed of Variation between the parties. On July 22, 2011, the Asset Sales Deed was terminated and MPAL received from Santos a refund of AUD $10,000,000 deposit, plus interest, pursuant to the terms of the Asset Sales Deed, as amended.

Please refer to Note 12 of our Annual Report on Form 10-K for the fiscal year ended June 30, 2011, for information on the July 22, 2011 termination of the Amended Asset Sales Deed.

Note 3 Restatement of Financial Information

Subsequent to the issuance of our 2010 Annual Report on Form 10-K, we determined that our consolidated statement of cash flows for the year ended June 30, 2010, reflected a foreign currency exchange loss in the line item “Effect of exchange rate changes on cash and cash equivalents,” rather than including it with the adjustments to reconcile net income (loss) to net cash used in operating activities. The exclusion of this adjustment to reconcile net loss resulted in overstating the net cash used in operating activities and overstating the effect of exchange rate changes on our cash and cash equivalents line items within the consolidated statement of cash flows.

This error also affected our condensed consolidated statements of cash flows for the nine month period ended March 31, 2010, the six month period ended December 31, 2010, and the three month period ended September 30, 2010. This error did not affect our condensed consolidated balance sheet or condensed consolidated statements of operations for any of the prior periods, nor did it affect the total cash increase or decrease reported for any of the periods.

The condensed consolidated statement of cash flows for the six months ended December 31, 2010, as contained herein has been adjusted for the restatement discussed above. The following is a summary of the items reclassified on the originally issued condensed consolidated statements of cash flows for the six months ended December 31, 2010:

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS


	December 31, 2010
	As Previously
	Reported			Adjustments			As Restated

Adjustments to reconcile net loss to net cash used in operating activities:
Foreign transaction loss	$	—		$	232,212		$	232,212
Net cash used in operating activities	$	(3,566,222	)	$	232,212		$	(3,334,010	)
Effect of exchange rate changes on cash and cash equivalents	$	5,184,614		$	(232,212	)	$	4,952,402

Note 4 Acquisition of minority interest in Nautilus Poplar LLC and acquisition of additional working interests

Poplar is composed of a 100% working interest in the oil and gas leases within the East Poplar Unit (“EPU”) in Roosevelt County, Montana, and the working interests in various oil and gas leases that are adjacent to or near EPU (“Northwest Poplar” or “NWP”) with such working interests varying between 63% and 100% in such leases (the Company’s combined working interests in EPU and NWP is herein referred to as “Poplar”). Prior to September 2, 2011, Poplar was owned entirely by NP (69%), the Company (28%), and Nautilus Technical Group, LLC (“NT”) (3%). NP was owned by the Company (83%), NT (10%), and Eastern Rider, LLC (“ER”) (7%).

On September 2, 2011, effective September 1, 2011, the Company entered into a series of transactions resulting in the Company becoming the 100% owner of the membership interest in NP and NP becoming the owner of 100% of Poplar (the “Nautilus Restructuring” or the “Transaction”). The Transaction enabled the Company to gain greater economic exposure to Poplar and to simplify processes and procedures relating to accounting, reporting, and capital funding. The Transaction consisted of (i) MPC acquiring all of the membership interests of NT and ER, (ii) MPC assigning its 28% share of Poplar to NP, (iii) NT assigning its 3% share of Poplar to NP, and (iv) MPC creating a new, wholly owned Delaware LLC, Magellan Petroleum North America (“MPNA”), and assigning, effective October 1, 2011, its 100% membership interest in NP to MPNA.

The terms of the Nautilus Restructuring are set forth in the September 2, 2011 Purchase and Sale Agreement (the “PSA”) between the Company and the owners of the interests in NT and ER (the “Nautilus Sellers”). The Nautilus Sellers included J. Thomas Wilson (an MPC director and now its President and CEO), a second individual who has served as a consultant to NP, and a third individual who was an employee of NP at the time of the Transaction (each a “Related Seller”), as well as certain other persons. The Company negotiated the consideration and terms of the Nautilus Restructuring with the intention of transacting with the Nautilus Sellers on fair value terms. The approach to valuation was consistent with this goal.

Due to the conflicting interests of the Related Sellers, the Board appointed a Special Transaction Committee (the “Committee”) to provide an independent forum for the consideration of the terms of the Nautilus Restructuring as set forth in the PSA and the related Registration Rights Agreement (Note 5). The Committee commissioned a fairness opinion from an independent investment bank to independently validate the fairness of the consideration underlying the Nautilus Restructuring. On August 24, 2011, the Committee approved and recommended that the Board approve the Transaction. On August 26, 2011, the Board approved the Transaction.

The PSA provided for the Company’s purchase of all membership interests in NT and ER in return for (i) $4,000,000 in cash (the “Cash Consideration”), (ii) $2,000,000 less certain costs and certain debt owed to MPC by NP, NT, and ER in privately issued shares of MPC’s common stock, par value $0.01 (“Common Stock”) (“Net Share Consideration”), and (iii) the potential for future production payments, payable in cash to the Nautilus Sellers, collectively, of up to $5,000,000 under certain conditions. The shares were sold pursuant to Section 4(2) of the Securities Act. The Cash Consideration was transferred on September 2, 2011. Consistent with the terms of the PSA, 1,182,742 shares of Common Stock were issued on September 23, 2011 (the “Issuance Date”). J. Thomas Wilson’s interest in the Nautilus Transaction approximated 52% of the consideration paid to the Nautilus Sellers.

The potential for future production payments is contingent upon achieving certain levels of production from Poplar. The first payout of $2.0 million is payable to the Nautilus Sellers when the sixty (60) day rolling average for production from Poplar has reached 1,000 barrels of oil equivalent per day as set forth in NP’s Reports of Production to the Board of Oil and Gas Conservation of the State of Montana (the “Reports”). The second payout in the amount of $3.0 million will be paid to the Nautilus Sellers when the sixty (60) day rolling average for production from Poplar has reached 2,000 barrels of oil equivalent per day as per the Reports. The fair value of these contingent payments was based on the estimated timing of the production payouts, which was based on the projections used in valuing MPC’s proved reserves as of June 30, 2011. The Company utilized a discount rate of 8% which is consistent with the rate used in valuing its asset retirement obligations and reflects the Company’s credit adjusted incremental borrowing rate. Management has applied assumptions to estimate the fair value of the liability related to the contingent payments consistently, which was valued at $4,232,000 and $0 as of December 31, 2011 and June 30, 2011, respectively.

The buy-out of the minority interests in NP from NT and ER was accounted for as an equity transaction with the impact reflected directly in equity at estimated fair value.

The acquisition of NT’s direct working interests in the affected leases within Poplar was treated as a business combination for accounting purposes. The fair value of assets acquired and liabilities assumed were recorded at estimated fair value. This estimate was made based on Level 3 or unobservable inputs (see Note 15). Unobservable inputs are defined in authoritative guidance as inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available at the time. A de minimis amount of revenues and earnings related to the working interests acquired are included in the accompanying unaudited condensed consolidated statements of operations for the six months ended December 31, 2011. No pro forma financial results are provided for the six months ended December 31, 2011, or 2010, due to the immaterial effect.

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


	December 31, 2011
	NT non- controlling interest in NP		NT working interest in Poplar		ER non- controlling interest in NP		Total
	(In thousands)
Consideration paid to Sellers (1):
Cash consideration	$	1,920	$	823	$	1,257	$	4,000
Share consideration (2)		907		389		526		1,822
Fair value of contingent consideration		1,993		854		1,304		4,151

	$	4,820	$	2,066	$	3,087	$	9,973


							Total
							(In thousands)
Recognized amount of identifiable assets acquired and liabilities assumed for Business combination:
Oil and gas assets (proved)							$	1,462
Oil and gas assets - Deep Intervals (unproved)								679
ARO liability								(75	)

							$	2,066

(1)	Excludes transaction costs

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

Note 5 Registration Rights Agreement between the Company and the Nautilus Sellers

On September 2, 2011, in connection with the purchase of the non-controlling interests in NP (Note 4), the Company and the Nautilus Sellers entered into a Registration Rights Agreement (“RRA”), pursuant to which the Company granted to the Nautilus Sellers certain registration rights with respect to the shares owned by each Nautilus Seller and issued under the Nautilus PSA (the “Registrable Securities”). On October 14, 2011, the Company filed a registration statement on Form S-3 with the SEC to register for public resale 1,182,742 shares of the Company’s common stock acquired in the Nautilus Restructuring by the Sellers (the “Registration Statement”). On November 18, 2011, the registration statement on Form S-3 became effective. The Company agreed to pay all expenses associated with the registration of the Registrable Securities except the fees and disbursements of counsel to the Nautilus Sellers.

Note 6 Sale Agreement between Magellan Petroleum (N.T) Pty Ltd and Santos QNT Pty Ltd and Santos Limited

On September 14, 2011, Magellan Petroleum (N.T.) Pty Ltd (“Magellan NT”), a wholly owned subsidiary of MPAL, and Santos QNT Pty Ltd (“Santos QNT”) and Santos Limited (collectively the “Santos Entities”) entered into a Sale Agreement (the “Santos SA”), dated September 14, 2011 (such transaction referred to herein as the “Santos Transaction”). On the date the Santos Transaction is completed (“Completion”), the Company will become the sole owner of the Palm Valley Interests (as defined below) and of the Dingo Interests (as defined below), while Santos will become the sole owner of the Mereenie Interests (as defined below). In

accordance with the terms of the Santos SA, upon completion, the Santos Transaction is deemed to be effective as of July 1, 2011 (the “Effective Date”), a net cash consideration of AUD $25 million shall be payable to the Company, subject to adjustments for the period from the Effective Date to Completion, and for a period of 20 years following the Effective Date, the Company shall be entitled to a series of contingent payments, based on meeting certain threshold volumes, adding a potential total payment of AUD $17.5 million.

The Santos SA provides for the transfer of the following assets:

•

Magellan NT’s 35% interest in each of the Mereenie Operating Joint Venture (Petroleum Leases 4 and 5 (“Mereenie Titles”) and associated property interests, related joint venture contracts (including a crude oil sales contract) and plant and equipment, subject to royalty obligations) and the Mereenie Pipeline Joint Venture (Pipeline License 2 and associated property interests, related joint venture contracts and plant and equipment) (collectively, the “Mereenie Interests”) to Santos QNT, giving the Santos Entities a combined 100% interest in the assets of each of the Mereenie Operating Joint Venture and the Mereenie Pipeline Joint Venture;

•

The Santos Entities’ combined interests of 48% in the Palm Valley Joint Venture (Petroleum Lease 3 and associated property interests, related joint venture contracts (including a GSPA defined below, see Note 8) and plant and equipment, subject to royalty obligations) (“Palm Valley Interests”) and combined interests of 66% in the Dingo Joint Venture (Retention License 2, associated joint venture contracts and plant and equipment, subject to royalty obligations) (“Dingo Interests”) to Magellan NT, giving Magellan NT a 100% interest in the assets of each of the Palm Valley Joint Venture and the Dingo Joint Venture.

The cash consideration payable for the sale of the Mereenie Interests by Magellan NT is AUD $28.0 million. The cash consideration payable for the sale of the Palm Valley Interests by the Santos Entities is AUD $2.9 million. The cash consideration payable for the sale of the Dingo Interests by the Santos Entities is AUD $0.1 million.

In addition, during the period from Completion until 20 years after the Effective Date, the Santos Entities will pay Magellan NT a series of contingent payments (the “Bonus Amounts”), based on meeting certain threshold volumes of net sales of petroleum from the Mereenie Titles (“Threshold Levels”) set out in the Santos SA. If, over a period of 90 consecutive days, the average daily net sales volumes exceed a Threshold Level, then the corresponding Bonus Amount shall be paid. Each Bonus Amount is only payable once and is payable on the first occasion the relevant Threshold Level is achieved. If all Threshold Levels are achieved, the cumulative Bonus Amount shall be AUD $17.5 million.

The Santos SA is subject to the satisfaction of certain customary conditions, which must be met by June 22, 2012. These conditions include approval of the Santos SA (and related transfers and dealings) under relevant petroleum legislation; approval by the Foreign Investment Review Board (which has now been obtained); execution of the GSPA defined below, (which has been executed and is only subject to Completion of the Santos SA, see Note 8); and obtaining certain third party approvals of the assignment of property interests, joint venture contracts, and royalty obligations (“Conditions”). Completion will occur five business days after the Conditions have been satisfied (or as otherwise agreed between the parties).

Because this transaction has not yet been finalized, our consideration of the accounting implications of this transaction is not complete as of this filing, and for this reason we are not in a position to provide an estimate of the financial effect of the transaction on the Company. The Company does not expect to report discontinued operations related to the proposed Santos Transaction.

The book value of the assets and liabilities related to the Mereenie Interests have been separated and classified as held for sale in the unaudited condensed consolidated balance sheet at December 31, 2011, as set forth in the table below:


	December 31, 2011
Assets
Inventories	$	691,405
Proved oil and gas properties		99,096,783
Less accumulated depletion and depreciation		(97,807,108	)
Land, buildings and equipment, net		101,198

Total assets held for sale	$	2,082,278


Liabilities
Asset retirement obligation	$	6,550,129

Liability related to assets held for sale	$	(6,550,129	)

The assets held for sale exclude goodwill. The Company intends to allocate the relative fair value of the goodwill to the assets being sold at Completion.

Note 7 Lease Purchase and Sale and Participation Agreement with VAALCO ENERGY (USA), INC.

On September 6, 2011 (the “Closing Date”), the Company and NP entered into a Lease Purchase and Sale and Participation Agreement (the “VAALCO PSA”) with VAALCO ENERGY (USA), INC (“VAALCO”).

Pursuant to the VAALCO PSA, the Company received $5.0 million in cash (the “Purchase Price”) on September 7, 2011. VAALCO also agreed to drill three new wells (the “Obligation Wells”), at its sole expense as operator, to the Bakken formation and to formations below the Bakken (the “Deep Intervals”) in Poplar. Upon completion of the Obligation Wells in the Deep Intervals of Poplar, VAALCO will have earned an undivided 65% of the Company’s working interest in the Deep Intervals within Poplar. One

well is required to be spud on or before June 1, 2012, and the second and third are required to be spud on or before December 31, 2012. On January 4, 2012, VAALCO spudded the first well in Poplar. One well will be drilled horizontally to test the Bakken Formation, one well will be drilled vertically to test the Red River Formation, and a third will be targeted within the Deep Intervals at VAALCO’s discretion. All production from an Obligation Well that is completed and the revenue from the sale of such production attributable to applicable leases shall be owned by NP and VAALCO consistent with their working interests of 35% and 65%, respectively, subject to all applicable burdens and taxes. Under the VAALCO PSA, if VAALCO fails to drill and, if applicable, complete, any of the Obligation Wells in accordance with the VAALCO PSA: (i) VAALCO will not be entitled to the assignment of the Deep Intervals; (ii) VAALCO shall have no further right to earn any interest in the Deep Intervals; (iii) the Company shall be entitled to retain the Purchase Price; (iv) VAALCO shall relinquish, effective as of the date of the failure, all of VAALCO’s rights, title, and interest in any Obligation Well that has been drilled and, if applicable, completed; and (v) the Company and NP shall have the right to terminate the VAALCO PSA. However, VAALCO shall be entitled to retain any production and the sale proceeds therefrom attributable to a relinquished Obligation Well that has accrued to VAALCO’s credit prior to the effective date of the relinquishment.

The VAALCO PSA also provides a process for the resolution of title defects reported through December 31, 2011. As of December 31, 2011, VAALCO did not claim any refund against the Purchase Price in relation to title defects.

MPC has agreed to indemnify VAALCO from all liabilities relating to the property to the extent such liabilities are attributable to the period prior to September 6, 2011, and arose from the inaccuracy of any representations by MPC in the agreement. Such indemnity shall be subject to a $50,000 deductible amount and is capped at $3.0 million in the aggregate.

MPC and VAALCO have agreed that should either party during the two years subsequent to September 6, 2011 agree to acquire an interest in oil and gas leases within a specified area of mutual interest, then such acquiring party shall offer to the non-acquiring party the right to purchase its proportionate share of such newly acquired interest (65% for VAALCO, 35% for MPC) by paying its proportionate share of the acquisition price.

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


	December 31, 2011
Cash consideration received	$	5,000,000
Net book value allocated to Deep Intervals		(829,140	)
Transaction costs		(161,690	)

Gain on sale recognized	$	4,009,170

Note 8 Gas Supply and Purchase Agreement between Magellan Petroleum (N.T) Pty Ltd and Santos QNT Pty Ltd

On September 14, 2011, Magellan NT entered into a Gas Supply and Purchase Agreement (the “GSPA”), dated September 14, 2011, with the Santos Entities (such transaction referred to herein as the “Santos Gas Contract”). See Note 6.

The GSPA is subject to Completion occurring under the Santos SA and provides for the sale by Magellan NT to the Santos Entities of a total contract gas quantity of 25.65 Petajoules (“PJ”) over the 17 year term of the GSPA, subject to certain limitations regarding deliverability into the Amadeus Pipeline.

The term of the GSPA shall commence on the later of Completion under the Santos SA, the first delivery of gas under a Concession GSPA (defined below) or January 16, 2012 (when the existing gas sales agreement for the Palm Valley Gas Field expires) and will expire if the total contract quantity is reached before the expiry of 17 years. Under the GSPA, the Santos Entities are required to use reasonable endeavors to enter into one or more agreements with their customers for the sale of gas solely from the Mereenie Gas Field, the Palm Valley Gas Field or other permissible fields under the GSPA and that collectively will require an average aggregate daily contract quantity for each day during the term of the GSPA of not less than 5.86 Terajoules (“TJ”) (“Concession GSPA”).

The price for gas supplied by Magellan NT shall be the weighted average of the prices obtained for all gas sold or to be sold by the Santos Entities from the Mereenie Titles during the relevant contract year.

The GSPA provides a detailed nomination procedure to be followed by the parties in determining the amount of gas that will be provided daily during each contract year. The maximum daily contract quantities under the GSPA (“Maximum DQ”) are based on a maximum annual contract quantity spread evenly over a year. In the last two (2) years of the term (known as the “Recovery Period”), the maximum annual contract quantity will be one half of the difference between the total contract quantity of 25.65PJ and what has been sold to the Santos Entities by Magellan NT up to that date. On any day, Magellan NT is obliged (subject to the usual exceptions for planned and unplanned maintenance and force majeure) to supply the lesser of the Maximum DQ, the daily contract forecast quantities provided by Magellan NT prior to the commencement of a contract year, and 80% of the quantities nominated by the Santos Entities’ customers under the Concession GSPAs (“Supply Obligation”).

If the term of the GSPA does not commence by April 15, 2012 (90 days after the expiry of the existing gas sales agreement for the Palm Valley Gas Field):

•

The Company is entitled to a AUD $2.0 million payment in January 2013;

•

Under the Santos SA, the Bonus Amount associated with lowest Threshold Level will decrease from AUD $5.0 million to AUD $2.0 million and the Bonus Amount associated with the second highest Threshold Level will be increased from AUD $0.3 million to AUD $1.3 million.

•

If, however, a Concession GSPA is entered part-way through 2012, the AUD $2.0 million payment and the Bonus Amounts will be decreased proportionately based on time.

Note 9 Capital and Stock Based Compensation

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

Options and non-vested shares

As of December 31, 2011, there were 335,000 shares available for future issuance under the Plan. Options outstanding have expiration dates ranging from November 28, 2015, through January 10, 2022.

The following is a summary of option transactions for the six months ended December 31, 2011:


Options Outstanding	Number of Shares			Weighted average Exercise Price ($)
June 30, 2011		5,200,000		$	1.49
Time-based options awarded		1,400,000		$	1.10
Performance-based options awarded		200,000		$	1.10
Options exercised		(21,875	)	$	1.60

December 31, 2011		6,778,125		$	1.40

Total non-cash stock based compensation included in the unaudited condensed consolidated statements of operations’ general and administrative expense for the three and six months ended December 31, 2011, was $490,723 and $886,355 respectively, as discussed below.

Total non-cash stock based compensation included under general and administrative expense in the unaudited condensed consolidated statements of operations for the three and six months ended December 31, 2010, was $817,943 and $1,203,396 respectively, as discussed below.

Non-employee options

There were no non-employee options issued during the six months ended December 31, 2011. In February 2009, the Company granted 262,500 time-based options, with an exercise price of $1.20 per share to J. Thomas Wilson, our President and CEO, who was then a non-employee consultant to the Company.

Since these options were issued to a non-employee, the Company determined their fair value at the end of each reporting period. The related option expense was recognized in the unaudited condensed consolidated statements of operations using the accelerated method. Effective September 27, 2011, J. Thomas Wilson became the President and CEO of the Company. This change in status from non-employee to employee triggered a re-measurement of the fair value of these awards.

The fair value of these time-based options at September 27, 2011, was determined based on the Black-Scholes valuation model using the following assumptions:


Risk free interest rate		1.55	%
Expected life		7.33	years
Expected volatility (based on historical price)		60.95	%
Fair value at remeasurement	$	219,172
Expire on		February 2, 2019

The expected life of the time-based options is the remaining contractual term. The Company recorded non-cash charges of $ 0 and ($49,825) respectively during the three and six months ended December 31, 2011, related to these non-employee time-based options for the period ended December 31, 2011. The credit entry was necessary to reverse previously recorded stock compensation expense related to the shares that were unvested as of the change in status from non-employee to employee. The unvested shares were then revalued as discussed above. Unrecognized compensation expense for these options is included below within the “employee option” section.

The Company recorded non-cash charges of $195,167 and $227,997 related to these time based options for the three and six months ended December 31, 2010.

Employee and Director option and share compensation

The Company’s compensation policy is designed to provide the Company’s directors with a portion of their annual Board compensation in the form of equity. The number of shares for each director award is, however, subject to a maximum annual cap of 15,000 shares. The Company issued 75,000 shares in July 2011, pursuant to this policy.

During the six months ended December 31, 2011, 1,600,000 non-qualified stock options were issued to employees of which 200,000 were performance-based (“PBOs”) and 750,000 issued outside of our stock incentive plan. During the six months ended December 31, 2010, 1,500,000 stock options were issued to employees, of which 200,000 were performance-based.

The 200,000 PBO’s contain three tranches of vesting criteria as follows: 1) 100,000 of these options will vest in full upon the completion of the Nautilus drilling program. As of December 31, 2011, these 100,000 options have vested in full as the drilling program referred to has been completed. 2) 50,000 of these options will vest in full upon the relocation of the Company’s headquarters to Denver, CO and 3) 50,000 of these options will vest in full upon the closing of the Santos SA (See Note 6). These options have a 10 year term.

The Company also issued 100,000 restricted shares to an employee during the three months ended December 31, 2011, 50,000 of which vest September 27, 2012 and 2013 respectively. The fair value of these shares was calculated as $107,000 and was based upon the closing stock price on November 7, 2011 (the grant date).


	Employee			Employee
	Time Based			PBO

Number of options		1,400,000			200,000
Risk free interest rate		1.06 to 1.25	%		1.03	%
Expected life		5.75 to 6.00	yrs		5.25	yrs
Expected volatility (based on historical price)		62.43 to 62.81	%		61.18	%
Expected dividend	$	0		$	0

Non-cash compensation expense of $490,772 and $936,180 was recorded for employees’ and directors’ options, restricted shares and non-vested shares for the three and six months ended December 31, 2011, and is included under general and administrative expense in the unaudited condensed consolidated statements of operations for the periods then ended. The fair value of the grants is being recognized over the requisite service period using the accelerated method. Unrecorded compensation expense for employee options was $1,339,883 as of December 31, 2011.

Employee and director non-cash option and unvested share expense of $622,776 and $975,399 for the three and six months ended December 31, 2010, respectively, was reflected in the unaudited condensed consolidated statements of operations for the period then ended.

Note 10 Earnings per Share

Income and losses per common share are based upon the weighted average number of common and common equivalent shares outstanding during the period. The reconciling items in the calculation of diluted earnings per share are the dilutive effect of stock options, warrants, and non-vested shares. The potential dilutive impact of non-vested shares is determined using either the treasury stock method or the two-class method, whichever leads to higher dilution. The dilutive impact of stock options and warrants is determined using the treasury stock method.

For the three and six months ended December 31, 2011, the Company had 0 and 7,547,826 options and warrants outstanding that had an exercise price below the average stock price that would have resulted in 0 and 748,473 incremental dilutive shares. The Company also had 204,167 non-vested shares of Company stock that would have resulted in 120,590 and 116,240 incremental dilutive shares for the three and six months ended December 31, 2011. There were no other potentially dilutive items at December 31, 2011. However, as a result of the net loss for the period, there is no dilutive effect.

For the three and six months ended December 31, 2010, the Company had 9,027,826 options and warrants outstanding that had an exercise price below the average stock price for the period that would have resulted in 3,349,430 and 2,919,315 incremental dilutive shares. The Company also had 208,334 non-vested shares of Company stock for the three and six months ended December 31, 2010, that would have resulted in 93,057 and 50,567 incremental dilutive shares for the period. There were no other potentially dilutive items at December 31, 2010. However, as a result of the net loss for the period, there was no dilutive effect.

Note 11 Segment Information

Prior to the Form 10-Q for the three months ended September 30, 2011, our reportable segments included MPC, NP, and MPAL. During the quarter ended September 30, 2011, MPC completed a restructuring of its North American assets (See Note 4) resulting in a change to its reportable segments. Segment groupings for the six months ended December 31, 2010, have been reclassified to conform to the current presentation.

The Company has two reportable segments, MPAL and NP, as well as a head office which is treated as a cost center. See Note 4 detailing the restructuring of our NP segment. The Company’s chief operating decision maker is J. Thomas Wilson (President and CEO of the Company) who reviews the results of the Australian and North American businesses on a regular basis. Both segments engage in business activities from which each may earn revenues and incur expenses. MPAL and its subsidiaries are considered one segment.

Segment information for the Company’s two operating segments is as follows:


	MPAL			NP			Corporate Overhead			Inter-segment Elimination			Total
	(In thousands)
Three months ended December 31,
2011
Revenues	$	1,551		$	1,651		$	—		$	—		$	3,202
Consolidated net loss attributable to MPC	$	(2,378	)	$	(307	)	$	(1,870	)	$	(2	)	$	(4,557	)

2010
Revenues	$	3,210		$	1,251		$	1,125		$	(1,125	)	$	4,461
Consolidated net income (loss) attributable to MPC	$	22		$	82		$	(2,203	)	$	—		$	(2,099	)

Six months ended December 31,
2011
Revenues	$	4,056		$	2,882		$	—		$	—		$	6,938
Consolidated net (loss) income attributable to MPC	$	(3,309	)	$	3,757		$	(4,060	)	$	(5	)	$	(3,617	)

2010
Revenues	$	5,843		$	2,317		$	1,125		$	(1,125	)	$	8,160
Consolidated Net (loss) income attributable to MPC	$	(1,151	)	$	38		$	(4,362	)	$	—		$	(5,475	)

Note 12 Asset Retirement Obligations

The fair values of asset retirement obligations (“AROs”) are based on management’s historical experience and best estimate of plugging and abandonment costs by field. Assumptions and judgments by management include determination of the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. Accretion expense is recorded under depletion, depreciation, amortization and accretion in the condensed consolidated statement of operations and was $156,865 and $314,479 for the three and six months December 31, 2011, respectively.


	December 31, 2011
Balance at June 30, 2011	$	11,397,410
Liabilities assumed		58,776
Liabilities incurred		315,066
Accretion expense		314,479
Reclassification to liabilities related to assets held for sale (Note 6)		(6,550,129	)
Exchange effect		(360,021	)

Balance at December 31, 2011	$	5,175,581

Note 13 Income Taxes

The Company has estimated the effective tax rate expected to be applicable for the full fiscal year. The Company’s effective tax rate used in providing for income taxes on a current year-to-date basis for the six months ended December 31, 2011, is 0% compared to 23% for the six months ended December 31, 2010. For the current fiscal year, we anticipate that we will be providing a full valuation allowance against the Company’s deferred tax assets. Deferred tax assets 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 tax credit carry forwards. A valuation allowance reduces deferred tax assets to estimated realizable value, which is the value that corresponds to the future taxable income in certain tax jurisdictions that management deems to be more likely than not achievable. We review our deferred tax assets and valuation allowance on a quarterly basis. As part of our review, we consider positive and negative evidence, including cumulative results in recent years. As a result of our review for the six months ended December 31, 2011, we provided for a full valuation allowance against the Company’s deferred tax assets.

We anticipate we will continue to record a valuation allowance against the deferred tax assets in all jurisdictions of the Company until such time as we are able to determine it is “more-likely-than-not” the deferred tax asset will be realized. Such a position is dependent on whether there will be sufficient positive evidence to realize such deferred tax assets.

Note 14 Marketable Securities

As of December 31, 2011, the following marketable securities were expected to be held until maturity:


	Par Value		Maturity Date	Carrying Amount		Fair Value
Short-term securities
U.S. Treasury Bills	$	600,000	January 12, 2012	$	599,911	$	599,994
U.S. Treasury Bills		2,000,000	April 12, 2012		1,999,684		1,999,780

Total	$	2,600,000		$	2,599,595	$	2,599,774

As of June 30, 2011, the Company had no held to maturity marketable securities.

Note 15 Fair Value Measurements

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

•

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

•

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

•

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

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

Items required to be measured at fair value on a nonrecurring basis include the assets acquired and liabilities assumed related to the acquisition of an additional 3% working interest in Poplar (see Note 4), and liabilities related to AROs.

Items required to be measured at fair value on a recurring basis include securities available for sale, classified as Level 1, and contingent payments (see Note 4), classified as Level 3.

Cash balances were $1,999,784 as of December 31, 2011, and the remaining $16,824,214 was held in time deposit accounts in several Australian banks that have terms of 90 days or less, and are therefore classified as cash and cash equivalents. The fair value of cash equivalents approximates carrying value due to the short term nature of those instruments.

The following table presents the amounts of assets carried at fair value at December 31, 2011, and June 30, 2011 by the level in which they are classified within the valuation hierarchy:


	December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets
Securities available for sale	$	146,968	$	—	$	—	$	146,968
Liabilities
Contingent liability	$	—	$	—	$	4,232,000	$	4,232,000

	June 30, 2011
	Level 1		Level 2		Level 3		Total
Assets
Securities available for sale	$	238,070	$	—	$	—	$	238,070
Liabilities
Contingent liability	$	—	$	—	$	—	$	—

Note 16 Oil and Gas Properties

The following table represents the capitalized costs under the successful efforts method for oil and gas properties at:


	December 31, 2011			June 30, 2011
Proved oil and gas properties:
United Kingdom	$	—		$	—
United States		22,841,426			19,185,630
Australia		10,761,816			116,908,491
Less accumulated depletion, depreciation, and amortization		(11,130,368	)		(115,916,596	)

Total net proved oil and gas properties	$	22,472,874		$	20,177,525


Unproved oil and gas properties:
United Kingdom	$	3,169,281		$	3,205,058
United States		12,914			162,914
Australia		—			—

Total unproved oil and gas properties:	$	3,182,195		$	3,367,972


Wells in Progress:
United Kingdom	$	2,839,874		$	2,054,668
United States		3,379,406			2,260,568
Australia		—			—

Total wells in progress	$	6,219,280		$	4,315,236

Note 17 Debt

Long-term debt relates to a note payable with monthly installments of varying amounts, plus interest at 6.25%, through June 25, 2014. As of December 31, 2011 and June 30, 2011 long-term debt consisted of the following:


	December 31, 2011		June 30, 2011

Note payable	$	1,134,438	$	1,422,438
Less current portion of note payable		528,000		552,000

Long-term debt, excluding current portion	$	606,438	$	870,438

As of December 31, 2011 the minimum future principal maturities of long-term debt were as follows:


	December 30, 2011
One year	$	528,000
Two years		432,000
Three years		174,438

Total	$	1,134,438

The variable rate of the note is based upon the Wall Street Journal Prime Rate (the “index”) plus 3.00%, subject to a floor rate of 6.25%. The index was 3.25% at December 31, 2011, resulting in an interest rate of 6.25% per annum as of December 31, 2011. Under the note payable, NP is required to maintain certain customary financial and restrictive covenants. As of December 31, 2011, NP was in compliance with all financial and restrictive covenants.

The Company has a $1.0 million working capital line of credit classified as short term debt. The amount due on the line of credit was $775,000 and $500 at December 31, 2011, and June 30, 2011, respectively. The line of credit bears interest at a variable rate, being 6.50% as of December 31, 2011. The line of credit also secures two letters of credit in the amount of $25,000 each, one in favor of the Bureau of Land Management and another secures a business credit card. As of December 31, 2011, $175,000 was available under this line of credit.

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

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

Note 18 Related Party Transactions

The Company leases its Denver office (the office of NP) from an entity owned, in part, by J. Thomas Wilson, President and CEO of the Company. The lease expires February 2012. The total paid to such entity under this arrangement for the six months ended December 31, 2011, and 2010, was $36,148 and $36,148, respectively.

J. Robinson West, Chairman of the Board of Directors is Chairman, Founder and CEO of PFC Energy (“PFC”), which has served as a consultant for the Company on various Australian projects. MPC had accrued liabilities of $0 and $106,417 included in the unaudited condensed consolidated balance sheets as of December 31, 2011, and December 31, 2010, respectively, for consulting services. The unaudited condensed consolidated statements of operations for the six months ended December 31, 2011, and 2010 include general and administrative expenses of $97,026 and 286,651, respectively.

Please refer to Note 4 for more information on the transactions with NT and ER during the three months ended September 30, 2011.

Young Energy Prize SA (“YEP”), a Luxembourg corporation and the Company’s largest shareholder, was engaged by the Company to help assist in the funding of the Evans Shoal Transaction. Mr. Nikolay Bogachev, a Director of the Company since July 2009, is the President and CEO of YEP as well as an equity owner of YEP.

On August 5, 2010, the Company executed a Securities Purchase Agreement (the “Second Purchase Agreement”), an Investor’s Agreement and Memorandum of Agreement with YEP to finalize the terms of its second Private Investment in a Public Equity (“PIPE”). Pursuant to the terms of the Second Purchase Agreement, the Company is required to use the proceeds from the PIPE to close the Evans Shoal Transaction. On February 11, 2011 and February 17, 2011, the Company and YEP executed amendments to the Second Purchase Agreement. On February 17, 2011 the Company and YEP also executed an Investment Agreement to document the terms of additional financing to be provided by YEP to the Company in order to facilitate the closing of the Evans Shoal Transaction.

Since the Amended Asset Sales Agreement was terminated and MPAL received back the additional AUD $10.0 million deposit made in connection with the Evans Shoal Transaction, the transactions contemplated by the Second Purchase Agreement, as amended, and the Investment Agreement, as amended, have not closed. As of October 12, 2011, the Company and YEP terminated these agreements.

Accounts receivable includes an estimate of $80,000 which is due from entities in which J. Thomas Wilson and Nikolay Bogachev are members.

Note 19 Commitments & Contingencies

Refer to the Commitments and Contingencies table in our Form 10-K as of June 30, 2011, for information on all commitments and contingencies. Additionally refer to Note 4 for information regarding contingent payments to the Nautilus Sellers.

Note 20 Subsequent Events

The Company has evaluated subsequent events and noted no additional events that require recognition or disclosure at February 9, 2012.

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 unaudited condensed consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 2011, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of Part II of this report, along with Forward-Looking Statements discussion at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview of the Company

Magellan Petroleum Corporation (“Magellan”) is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. Magellan is an oil and gas holding company listed on the NASDAQ since 1972. The Company conducts its operations through two wholly owned subsidiaries, Nautilus Poplar, LLC (“NP”), which owns Poplar, a highly attractive oil field in the Williston Basin, and Magellan Petroleum Australia Limited, (“MPAL”), a successful independent oil and gas company in Australia and the UK in existence since the 1960s. Our mission is to enhance shareholder value by economically establishing the full potential of our existing assets.

Currently, on a consolidated basis, our assets at Poplar include a 100% operated working interest in the interval from the surface to the top of the Bakken formation and a 35% non-operated working interest below that interval, which includes the Bakken and Red River formations. Our other assets include working interests in the Mereenie, Palm Valley, and Dingo Fields in the Amadeus Basin in Australia of 35%, 52%, and 34%, respectively; a large exploration license in the Bonaparte Basin in the Timor Sea, Australia; and 270,000 net acres in Weald-Wessex Basins in the UK that are prospective for unconventional and conventional hydrocarbon deposits.

Summary Results of Operations

Revenues for the three months ended December 31, 2011 totaled $3.2 million, compared to $4.5 million in the prior year period, a decrease of 28% resulting primarily from the end of the Amadeus Gas Trust contribution to Other revenues in June 2011. Operating loss for the three months ended December 31, 2011 totaled $4.9 million, compared to $3.7 million in the prior year period. Net loss for the three months ended December 31, 2011 totaled $4.6 million ($0.08 / basic share), compared to $2.1 million ($0.04 / basic share) in the prior year period. For further information, please refer to Comparison of Results between the Three Months Ended December 31, 2011 and 2010 below in this section.

Starting this quarter, we have changed the presentation of our financial statements to conform them to industry-specific norms. Specifically, we have modified the presentation of expenses in the condensed consolidated statements of operations and the presentation of property and equipment, net in the condensed consolidated balance sheets. As a result, certain reclassifications have been made to the prior period financial statements to align them with this revised presentation format. These reclassifications have no impact on previously reported statement of operations.

Highlights of Operational Activities

During the quarter ended December 31, 2011, the Company has been active in developing and enhancing the value of our assets. Key activities and events are discussed below. We remain confident that we can continue to expand our production capabilities in all three of our operating theaters.

Poplar (Montana, USA)

Magellan 100% operated intervals. During the quarter ended December 31, 2011, Magellan sold 19,260 bbl of oil attributable to its net revenue interests in Poplar, compared to 17,092 bbls of oil sold during the same period in 2010. These results represent a 13% increase in average daily sales during those periods, from 186 bopd to 209 bopd. Part of the increase in sales volumes can be attributed to the Nautilus Restructuring, which increased the Company’s ownership of the interests in EPU and NWP. This increase was offset by an equipment failure at Poplar’s production facility, which partially constrained production for three weeks before being corrected in December 2011.

During the quarter ended December 31, 2011, the Company focused its activities at Poplar on increasing production, refining its knowledge of the field, and preparing for a more extensive development program. Several workovers and recompletions were performed during this quarter. Additionally, EPU 119, the well that Magellan spud in October 2010 in order to substantiate the deep potential of the Poplar structure, was completed in October 2011 in the B-2 zone of the Charles formation. Pump testing of the B-2 zone continues while the Company evaluates the potential for a second interval in one of the zones behind pipe.

A second infill well, EPU 117, was spud in October 2011 and drilled to a total depth of 4,935 feet. This well has recently been completed as a new pool producer in the Amsden formation at a depth of approximately 4,800 feet. The well is currently producing (starting January 2012) approximately 106 barrels of oil per day with no appreciable water production on a 10/64^th choke with a flowing tubing pressure of 95 psi. This is the first production from this formation within the unit. This well will be closely monitored to determine its ultimate commercial viability.

VAALCO 65% operated intervals. Under the terms of the farm-out agreement with VAALCO (Note 7), on January 4, 2012, VAALCO spud its first well at Poplar, EPU 120. EPU 120 is a vertical well which VAALCO will use to core and test the Bakken, Three Forks, Nisku, and Red River formations, with top depths of 7,022 feet, 7,127 feet, and 8,534 feet, respectively. In addition, VAALCO will provide to the Company the logs and drilling data from this well relevant to the shallower formations at Poplar. This well is currently at a depth of 4,700 feet on its way to the first core point. Under the terms of the VAALCO PSA, VAALCO is required to spud two additional wells by the end of December 2012.

Australia

Mereenie. The Mereenie oil and gas field, which is operated by Santos, produced a gross average of approximately 511 bbls of oil and condensate per day for sale during the three months ended December 31, 2011. The average price of oil at Mereenie was AUD $117.97/bbl for the three months ended December 31, 2011, compared to AUD $86.15/bbl for prior year period. There was no natural gas sales at Mereenie during the quarter ended December 31, 2011, since there were no new gas sales contracts. Gas sales are expected to resume in February 2012 under a new gas sales contract.

Palm Valley. The Palm Valley gas field, which is operated by Magellan, produced a gross average of approximately 4.5 million cubic feet per day (MMcf/D) of natural gas for sale during the quarter ended December 31, 2011. The average price of gas at Palm Valley was AUD $2.31/Mcf for the quarter ended December 31, 2011, compared to AUD $2.27/Mcf for the prior year period. The Palm Valley Gas Purchase Agreement with the NT Power and Water Corporation terminated on January 16, 2012 after a 25 year term. New gas sales are expected to resume in February 2012.

United Kingdom

Northern Petroleum Operated Licenses. In the Weald Basin of Southern England, the Company (40% interest) participated in the Markwells Wood-1 exploration well, which was drilled in PEDL 126 in December 2010. On November 21, 2011, the Markwells Wood-1 well was completed for production testing to establish pressures and flow rates in the existing wellbore. Further stimulation of the well was performed in December and production testing is expected to continue through March 2012 to establish a stabilized oil rate. As operator of the well, Northern Petroleum will continue to publish periodic updates on the well status.

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

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

Acquisition and Divestitures Highlights

Santos Transactions

On September 14, 2011, Magellan executed a Sale Agreement with Santos QNT Pty Ltd (“Santos”) and a related Gas Supply and Purchase Agreement (the “GSPA”) (combined the “Santos Transactions”), the impact of which is not reflected in our second quarter results. Completion of the Santos Transactions remains subject to customary government and third party approvals, which Magellan and Santos are working diligently to achieve. By swapping our ownership interests with Santos, we will for the first time in our history own and operate 100% of our Australian productive base (the Palm Valley and Dingo Fields) and enjoy the flexibility to develop these assets according to our own needs. At the same time, the GSPA with Santos, who will now own 100% of the Mereenie Field, is expected to provide Magellan with over $100.0 million in undiscounted future revenue while preserving a key strategic relationship.

Unrelated to the Santos Transactions, the Company was refunded AUD $10.0 million on July 22, 2011, following the termination of the Assets Sale Deed between Santos Offshore Pty Ltd and MPAL.

For a complete description of these transactions please see Note 20 of our Form 10-K for the year ended June 30, 2011, as well as Notes 6 and 8 for the six month period ending December 31, 2011.

Consolidated Liquidity and Capital Resources

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

Uses of Funds

Capital Expenditures Plans. At Poplar, the Company does not face significant mandatory capital expenditure requirements to maintain its acreage position. Substantially all of the leases are held by production and contain producing wells with reserves adequate to sustain multi-year production. Furthermore, approximately 80% of the acreage has been unitized as a Federal Exploratory Unit which is held by production from any one well. This unit currently contains 25 producing wells. Magellan’s discretionary capital expenditure plans over the next two years will be determined by the results of ongoing technical analysis and are expected to include the drilling of additional wells in the shallow formations of Poplar to increase production and proved reserves, as well as the pilot phase of a CO₂-based enhanced oil recovery project within the EPU. In addition, to the extent that the three wells to be drilled by VAALCO are successful, Magellan plans to fund its 35% share of the cost of the future drilling program in the deeper formations of Poplar.

At Palm Valley, Magellan’s interest in the field is governed by Petroleum Lease No. 3, which is due to expire in 2023 (and subject to automatic renewal for another 21 years). The company is not obligated to undertake significant mandatory capital expenditure in order to maintain its position in the lease. Magellan’s discretionary capital expenditures plans are primarily focused on maximizing gas production from the existing facilities while maintaining a safe and efficient operation, conducted in accordance with good oil field practice.

At Dingo, Magellan’s interest in the field is governed by Retention License No. 2, which is due to expire in February 2014 (and subject to renewal for a further 5 years). No mandatory capital expenditure is required until new gas sales contracts are secured. Dingo contains 2 producer wells which are shut-in. Capital expenditures required to bring the field on-stream depend on the development option selected by the Company, and could include a 33 mile tie-in pipeline.

In the Bonaparte Basin, offshore Australia, Magellan holds a 100% interest in the NT/P82 Exploration Permit. Under the terms of the permit, which is due to expire in May 2016, Magellan committed to a minimum 46 square mile 3D seismic survey in 2012. At June 30, 2011 MPAL’s obligations regarding the NT/P82 permit were recorded at AUD $1.8 million, which were included in our disclosure of commitments and contingencies in Note 16 to our Form 10-K as of June 30, 2011.

In the UK, Magellan’s interests are governed by various Petroleum Exploration and Development Licenses. The majority of these licenses expire in 2014 and all are subject to drill-or-drop obligations. Magellan has minimal remaining capital expenditure obligations with respect to its interest in the Markwells Wood well operated by Northern Petroleum.

Contractual Obligations. Please refer to Note 4 for information regarding the contingent payments to the Nautilus Sellers of the non-controlling interest of NP. Please refer to the contractual obligations table in our Form 10-K as of June 30, 2011, for information on all other contractual obligations.

Sources of Funds

Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $18.8 million of cash and cash equivalents at December 31, 2011, compared to $20.4 million as of June 30, 2011. In addition, upon completion of the Santos Transaction, the Company is due to receive additional net cash proceeds of AUD $25.0 million plus certain adjustments.

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. Cash balances totaled $2.0 million as of December 31, 2011 and the remaining $16.8 million was held in time deposit accounts in several Australian banks that have terms of 90 days or less.

Due to the international nature of its operations, the Company is exposed to certain legal and tax constraints in matching the capital needs of its assets and its cash resources. As of December 31, 2011, $17.8 million, representing 95% of the Company’s consolidated cash and cash equivalents, were deposited in accounts held by MPAL.

Marketable Securities. On a consolidated basis, the Company had $2.6 million of marketable securities at December 31, 2011, compared to zero as of June 30, 2011. The Company’s marketable securities consist of investments in US Treasury Bills with maturities usually not exceeding six months. See Note 14 for further details.

Existing Credit Facilities. The following table sets forth summary information regarding the existing credit facilities for the dates indicated:


	December 31,		June 30,
	2011		2011
Outstanding borrowings:
Term loan	$	1,134,438	$	1,422,438
Line of credit		775,000		500

Total	$	1,909,438	$	1,422,938


Borrowing base	$	2,300,000	$	2,300,000

The Company, through its wholly owned subsidiary NP, maintains its only credit facilities with Jonah Bank of Wyoming. As of December 31, 2011, Magellan’s borrowing capacity under these facilities totaled $2.3 million, consisting of a $1.3 million Term loan and a $1.0 million Line of credit. Of this $1.0 million Line of credit, $0.8 million was drawn and $50,000 was being utilized for two letters of credit, one in favor of the Bureau of Land Management ($25,000) and one to secure a business credit card used by NP ($25,000), and an additional $0.2 million remains available to borrow. As of December 31, 2011, NP was in compliance with its financial covenants as set forth in the Term loan agreement. The credit facilities are collateralized by a first mortgage and an assignment of production for Poplar and are guaranteed by Magellan up to $6.0 million but not to exceed the amount of the principal owed, which was $1.9 million as of December 31, 2011. For further information regarding the terms of this credit facility, please refer to Note 17.

Other Sources of Financing. In addition to its cash and existing credit facilities, the Company has various alternatives to fund the development of its assets. These alternatives could potentially include entering into a reserve-based loan facility secured by the proven undeveloped reserves of Poplar; farming out a portion of the development program of some of the Company’s assets; and issuing new shares to equity investors.

Cash Flows

The following table sets forth summary information regarding cash flows for the periods indicated:


	Six Months Ended December 31,
	2011			2010
	(In thousands)
Cash (used in) provided by:
Operating activities	$	(7,852	)	$	(3,334	)
Investing activities		9,305			(6,699	)
Financing activities		(2,940	)		(419	)
Effect of exchange rate changes on cash and cash equivalents		(106	)		4,952

Net decrease in cash and cash equivalents	$	(1,593	)	$	(5,500	)

Cash used in operating activities during the six months ended December 31, 2011 and 2010 was $7.9 million and $3.3 million, respectively. The increase in cash used in operating activities was primarily the result of the decrease in revenues of $1.2 million over the same period.

Cash provided by investing activities was $9.3 million during the six months ended December 31, 2011, compared to cash used of $6.7 million over the same period in 2010. For the six months ended December 31, 2011, the Company received $5.0 million of proceeds from the VAALCO Transaction and $10.9 million from the refunded deposit related to the Evans Shoal Asset Sales Deed. The Company used part of these proceeds to fund a net investment in marketable securities of $2.6 million. For the six months ended December 31, 2011, the Company invested $3.2 million in the development of its assets, compared to $3.4 million in the same period in 2010. Of the $3.2 million, $1.7 million was incurred in relation to the recompletion of seven wells and the repair of one of our salt water disposal wells at Poplar, $0.5 million related to exploration activities at Poplar, primarily for the EPU 117 well, and $0.6 million was incurred in the UK, primarily for the Markwells Wood-1 well. Finally, the Company spent $0.8 million in the purchase of direct working interests in Poplar (see Note 4).

Cash used in financing activities totaled $2.9 million for the six months ended December 31, 2011, compared to $0.4 million for the same period in 2010. For the six months ended December 31, 2011, the Company spent $3.5 million on the purchase of non controlling interest in Poplar (see Note 4), which was partially mitigated by a net drawdown under the Company’s credit facilities of $0.5 million.

The effect of changes in foreign currency exchange rates negatively impacted the translation of our AUD denominated cash and cash equivalents balances into USD and resulted in a decrease of $0.1 million in cash and cash equivalents for the six months ended December 31, 2011.

Comparison of Results between the Three Months Ended December 31, 2011, and 2010

Oil and Gas Sales Volume

The following table sets forth summary information regarding oil and gas sales volume (after deducting royalties) for the periods indicated:

		115.75		115.75		115.75			115.75
	Three Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
Net sales by field:
Poplar (Mbbls)		19		17		2			12	%

Palm Valley gas (MMcf)		178		182		(4	)		(2	%)
Mereenie oil (Mbbls)		9		15		(6	)		(40	%)
Total Australia sales (Mboe)		39		46		(7	)		(15	%)

Consolidated sales (Mboe)		58		63		(5	)		(8	%)
Consolidated sales (boe/d)		630		685		(54	)		(8	%)

Net sales by product:
Oil (Mbbls)		28		32		(4	)		(13	%)
Gas (MMcf)		178		182		(4	)		(2	%)
Consolidated sales (Mboe)		58		63		(5	)		(8	%)

Sales volume for the three months ended December 31, 2011 totaled 58 Mboe (627 boepd) compared to 63 Mboe (685 boepd) sold in the prior year period, a decrease of 8%. Sales volume by product for the three months ended December 31, 2011 was 49% oil and 51% gas, compared to 52% oil and 48% gas in the prior year period. At Poplar, volumes were positively impacted by the Nautilus Restructuring, which increased the Company’s working interests in EPU and NWP and by increased maintenance activities at the field. The increase was offset by an equipment failure at Poplar’s production facility, which partially constrained production for three weeks before being corrected in December. At Mereenie, oil sales volumes declined due to the operator not making the October shipment of oil from the field. The production volume associated with this shipment was moved into inventory and is expected to be sold over the three months ending March 31, 2012. Gas sales volumes from Palm Valley reflected the natural field decline, but continued in line with the terms of its off-take contract, which ended on January 16, 2012, by operation of its terms after 25 years. In the UK, production testing of the Markwells Wood-1 well commenced on November 20, 2011; though no oil sales were made for the three months ended December 31, 2011.

Oil and Gas Prices

The following table sets forth summary information regarding average realized oil and gas prices for the periods indicated:

		115.75		115.75		115.75		115.75
	Three Months Ended December 31,						Percent change
	2011		2010		Difference		Percent change
Average realized price:
Poplar (USD/bbl)		85.75		73.04		12.71		17	%
Palm Valley (AUD/Mcf)		2.79		2.51		0.28		11	%
Mereenie oil (AUD/bbl)		115.75		99.01		16.74		17	%
Consolidated (USD/boe)		55.16		51.32		3.84		7	%

The average realized price for the three months ended December 31, 2011 was $55.16/boe which when compared to $51.32/boe in the prior year period, result in an increase of 7%. This increase in price is primarily the result of oil prices rising in the United States

and Australia during the three months ended December 31, 2011 relative to the prior year period. At present, the Company does not engage in any oil and gas hedging activities. Relative to the prior year period, the average realized price from oil sales at Poplar increased by 17% as a result of an increase in its benchmark price (WTI). The average realized gas price from Palm Valley went up by 11%, in line with the terms of its off-take contract. The average realized oil price from Mereenie increased by 17% as a result of an increase in its benchmark price (Tapis).

Revenues

The following table sets forth summary information regarding revenues for the periods indicated:


	Three Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
	(In thousands)
Net revenue by source:
Poplar (USD)	$	1,652	$	1,248	$	404			32	%
Palm Valley (USD)		498		456		42			9	%
Mereenie (USD)		1,049		1,508		(459	)		(30	%)
Other (USD)		3		1,248		(1,245	)		(100	%)

Total (USD)	$	3,202	$	4,460	$	(1,258	)		(28	%)


Palm Valley (AUD)	$	483	$	462	$	21			5	%
Mereenie (AUD)	$	1,017	$	1,527	$	(510	)		(33	%)

Net revenues by type (USD):
Oil	$	2,700	$	2,756	$	(56	)	$	(2	%)
Gas		498		459		39			8	%
Other		4		1,246		(1,242	)		(100	%)

Total	$	3,202	$	4,461	$	(1,259	)	$	(28	%)

Revenues for the three months ended December 31, 2011 totaled $3.2 million, compared to $4.5 million in the prior year period, a decrease of 28%. The $1.3 million decrease in sales was primarily attributable to the end of the Amadeus Gas Trust revenue stream on June 16, 2011, which arrangement contributed $1.2 million to the Company’s revenues in the prior period and a 8% decrease in oil and gas sales volumes, which was mitigated by a 7% increase in average realized prices (per boe).

Operating and Other Expenses

The following table sets forth summary information regarding operating expenses for the periods indicated:


	Three Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	3,259	$	2,521	$	738			29	%
Depletion, depreciation, amortization, and accretion	$	366	$	429	$	(63	)		(15	%)
Exploration	$	1,006	$	615	$	391			64	%
General and administrative	$	3,347	$	5,037	$	(1,690	)		(34	%)

Selected operating expenses (USD/boe):
Lease operating	$	56	$	40	$	16			40	%
Depletion, depreciation, amortization, and accretion	$	6	$	7	$	(1	)		(14	%)
Exploration	$	17	$	10	$	7			70	%
General and administrative	$	58	$	80	$	(22	)		(28	%)

Lease Operating Expenses. Lease operating expenses increased from $2.5 million in the three months ended December 31, 2010 to $3.3 million in the same period in 2011, an increase of 29% or $16/boe. This increase was driven primarily by increased workover and maintenance activities at Poplar, relative to the prior year period, as well as increased salaries and benefits and field material costs at MPAL. A significant number of workovers are required to maintain production as most of Poplar’s producing wells were drilled in the 1950s and 1970s.

Depletion, Depreciation, Amortization, and Accretion. The following table sets forth summary information regarding depletion, depreciation, amortization, and accretion for the periods indicated:


	Three Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
	(In thousands)
Depreciation	$	116	$	59	$	57			97	%
Depletion		91		201		(110	)		(55	%)
ARO accretion		159		169		(10	)		(6	%)

Total	$	366	$	429	$	(63	)		(15	%)

Depletion, depreciation, amortization, and accretion expenses decreased by $63,000, or 15%, for the three months ended December 31, 2011, relative to the prior year period, primarily due to a decrease at NP.

Exploration Expenses. Exploration expenses increased from $0.6 million in the three months ended December 31, 2010 to $1.0 million in the same period in 2011, an increase of 64% or $7/boe. The $1.0 million in expenses incurred for the three months ended December 31, 2011 consisted primarily of $0.6 million of geological and geotechnical costs related to the Celtique Energie operated licenses in the UK and $0.2 million of costs related to the preparation of the acquisition of 2D and 3D seismic data for NT/P82, the wholly owned exploration block located in the Bonaparte Basin, offshore Northern Territory, Australia.

General and Administrative Expenses. The following table sets forth summary information regarding general and administrative expenses for the periods indicated:


	Three Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
	(In thousands)
General and administrative (excluding stock-based compensation and foreign transaction (gain) loss)	$	2,492	$	4,326	$	(1,834	)		(42	%)
Stock-based compensation		719		268		451			168	%
Foreign transaction (gain) loss		136		443		(307	)		(69	%)

Total	$	3,347	$	5,037	$	(1,690	)		(34	%)

General and administrative expenses decreased by $1.7 million, or 34%, for the three months ended December 31, 2011 compared to the same period in 2010. This decrease was driven primarily by a $1.6 million decrease in consulting costs which related to prior year activities. Decreases in severance payments of $0.6 million, and in costs related to the activities of the Board of Directors of $0.2 million, were mitigated by an increase in legal costs of $0.6 million.

Comparison of Results between the Six Months Ended December 31, 2011, and 2010

Oil and Gas Sales Volume

The following table sets forth summary information regarding oil and gas sales volume (after deducting royalties) for the periods indicated:


	Six Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
Net sales by field:
Poplar (Mbbls)		34		33		1			3	%

Palm Valley gas (MMcf)		357		365		(8	)		(2	%)
Mereenie oil (Mbbls)		24		28		(4	)		(14	%)
Total Australia sales (Mboe)		84		89		(5	)		(6	%)

Consolidated sales (Mboe)		118		122		(4	)		(3	%)
Consolidated sales (boe/d)		640		662		(22	)		(3	%)

Net sales by product:
Oil (Mbbls)		58		61		(3	)		(5	%)
Gas (MMcf)		357		365		(8	)		(2	%)

Consolidated sales (Mboe)		118		122		(4	)		(3	%)

Sales volume for the six months ended December 31, 2011 totaled 118 Mboe (640 boepd) compared to 122 Mboe (662 boepd) sold in the prior year period, a decrease of 3%. Sales volume by product for the six months ended December 31, 2011 was 49% oil and 51% gas, compared to 50% oil and 50% gas in the prior year period. At Poplar, volumes were positively impacted by the Nautilus Restructuring, which increased the Company’s working interests in EPU and NWP and by increased maintenance activities at the field. The increase was offset by an equipment failure at Poplar’s production facility, which partially constrained production for three weeks before being corrected in December. At Mereenie, oil sales volumes declined due to the operator not making the October shipment of oil from the field. The production volume associated with this shipment was moved into inventory and is expected to be sold over the three months ending March 31, 2012. Gas sales volumes from Palm Valley continued in line with the terms of its off-take contract, which ended on January 16, 2012, by operation of its terms after 25 years. In the UK, production testing of the Markwells Wood-1 well commenced on November 20, 2011; though no oil sales were made for the quarter ended December 31, 2011.

Oil and Gas Prices

The following table sets forth summary information regarding average realized oil and gas prices for the periods indicated:


	Six Months Ended December 31,						Percent change
	2011		2010		Difference		Percent change
Average realized price:
Poplar (USD/bbl)		84.52		69.63		14.89		21	%
Palm Valley (AUD/Mcf)		2.72		2.36		0.36		15	%
Mereenie oil (AUD/bbl)		128.63		93.77		34.86		37	%

Consolidated (USD/boe)		59.19		47.55		11.64		24	%

The average realized price for the six months ended December 31, 2011 was $59.19/boe compared to $47.55/boe in the prior year period, an increase of 24%. The increase in the realized average price of $11.64/boe is primarily the result of increased oil prices in the U.S. and Australia. At present, the Company does not engage in any oil and gas hedging activities. Relative to the prior year period, the average realized price from oil sales at Poplar increased by 21% as a result of an increase in its benchmark price (WTI). The average realized gas prices from Palm Valley went up by 15%, in line with the terms of its off-take contract. The average realized oil price from Mereenie increased by 37% as a result of an increase in its benchmark price (Tapis).

Revenues

The following table sets forth summary information regarding revenues for the periods indicated:


	Six Months Ended December 31,								Percent change
	2011			2010		Difference			Percent change
	(In thousands)
Net revenue by source:
Poplar (USD)	$	2,876		$	2,312	$	564			24	%
Palm Valley (USD)		970			863		107			12	%
Mereenie (USD)		3,120			2,615		505			19	%
Other (USD)		(28	)		2,370		(2,398	)		(101	%)

Total (USD)	$	6,938		$	8,160	$	(1,222	)		(15	%)


Palm Valley (AUD)	$	931		$	912	$	19			2	%
Mereenie (AUD)	$	2,987		$	2,753	$	234			8	%

Net revenues by type (USD):
Oil	$	5,996		$	4,927	$	1,069			22	%
Gas		976			868		108			12	%
Other		(34	)		2,365		(2,399	)		(101	%)

Total	$	6,938		$	8,160	$	(1,222	)		(15	%)

Revenues for the six months ended December 31, 2011 totaled $6.9 million, compared to $8.2 million in the prior year period, a decrease of 15%. Revenues for the six months ended December 31, 2011 were negatively impacted by the end of the Amadeus Gas Trust revenue stream on June 16, 2011, which agreement contributed $2.4 million to the Company’s revenues for the prior year period. The decrease in other revenues was partially offset by a 24% increase in average realized prices (per boe), which was mitigated by a 3% decrease in oil and gas sales volumes.

Operating and Other Expenses

The following table sets forth summary information regarding operating expenses for the periods indicated:


	Six Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	6,277	$	4,360	$	1,917			44	%

Depletion, depreciation, amortization, and accretion	$	841	$	1,568	$	(727	)		(46	%)
Exploration	$	1,994	$	1,028	$	966			94	%
General and administrative	$	5,858	$	9,323	$	(3,465	)		(37	%)

Selected operating expenses (USD/boe):
Lease operating	$	53	$	36	$	17			47	%

Depletion, depreciation, amortization, and accretion	$	7	$	13	$	(6	)		(46	%)
Exploration	$	17	$	8	$	9			113	%
General and administrative	$	50	$	76	$	(26	)		(34	%)

Lease Operating Expenses. Lease operating expenses increased from $4.4 million in the six months ended December 31, 2010 to $6.3 million in the same period in 2011, an increase of 44% or $17/boe. This increase was driven primarily by increased workover and maintenance activities at Poplar, as well as increased salaries and benefits and field material costs at MPAL. A significant number of workovers are required to maintain production, as most of Poplar’s producing wells were drilled in the 1950s and 1970s.


	Six Months Ended December 31,							Percent change
	2011		2010		Difference			Percent change
	(In thousands)
Depreciation	$	224	$	117	$	107			91	%
Depletion		300		1,133		(833	)		(74	%)
ARO accretion		317		318		(1	)		(0	%)

Total	$	841	$	1,568	$	(727	)		(46	%)

Depletion, depreciation, amortization, and accretion expenses decreased by $0.7 million, or 46%, for the six months ended December 31, 2011 relative to the prior year period, primarily because MPAL’s Australia oil and gas assets were fully depleted as of September 30, 2010, resulting in zero depletion for MPAL activity in the current six month period.

Exploration Expenses. Exploration expenses increased from $1.0 million in the six months ended December 31, 2010, to $2.0 million in the same period in 2011, an increase of 94% or $9/boe. The $2.0 million of exploration expenses incurred for the six months ended December 31, 2011, primarily consisted of $1.3 million of ongoing exploration costs in the UK, including $1.0 million acquisition costs of seismic data related to the UK licenses operated by Celtique Energie, and $0.4 million of geological and geotechnical costs related to Mereenie.

General and Administrative Expenses. The following table sets forth summary information regarding general and administrative expenses for the periods indicated:


	Six Months Ended December 31,								% change
	2011			2010		Difference			% change
	(In thousands)
General and administrative (excluding stock-based compensation and foreign transaction (gain) loss)	$	5,398		$	7,024	$	(1,626	)		(23	%)
Stock-based compensation		886			530		356			67	%
Foreign transaction (gain) loss		(426	)		1,769		(2,195	)		(124	%)

Total	$	5,858		$	9,323	$	(3,465	)		(37	%)

General and administrative expenses decreased by $3.5 million, or 37%, for the six months ended December 31, 2011 compared to the same period in 2010. This decrease was driven primarily by a $1.6 million decrease in general and administrative expenses excluding stock based compensation and foreign transaction (gain) loss, which resulted from decreases of $2.1 million and $0.6 million in consulting costs which related to prior year activities and severance payments, respectively. These decreases were mitigated by increases in accounting costs of $0.3 million and legal costs of $0.9 million for the six months ended December 31, 2011. In addition, an unrealized $0.4 million foreign transaction gain was recorded for the six months ended December 31, 2011, compared to an unrealized $1.8 million foreign transaction loss for the same period in 2010.

Loss (gain) on sale of assets reflects the gain from the VAALCO Transaction.

Off-Balance Sheet Arrangements

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

Critical Accounting Policies

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended June 30, 2011.

Forward Looking Statements

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

Among these risks and uncertainties are: (1) the ability of Magellan and Santos to complete and implement the terms of the asset swap in the Amadeus Basis and the related gas sales agreement; (2) whether the Company can successfully achieve cost savings while delivering revenue growth; (3) whether the workovers, recompletions and other drilling at Poplar will result in increased production and cash generation and/or will otherwise successfully assist in the development of Poplar; and (4) the production levels from the properties in which Magellan, through its subsidiaries, have interests, the recoverable reserves at those properties and the prices that will ultimately be applied to the sale of such reserves. 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 of the Company’s Form 10-K for the year ended June 30, 2011. Any forward-looking information provided in this report should be considered with these factors in mind. Magellan assumes no obligation to update any forward-looking statements contained in this report, whether as a result of new information, future events or otherwise.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company’s exposure to market risk relates to fluctuations in foreign currency and world prices for crude oil, as well as market risk related to investment in marketable securities. The exchange rates between the Australian dollar and the U.S. dollar, as well as the exchange rates between the Australian dollar and the U.K. pound sterling, have changed in recent periods and may fluctuate substantially in the future. Any change in the exchange rate between the Australian and U.S. dollar could have a negative impact on our revenue, operating income and net income. Because of our U.K. development program, a portion of our expenses, including exploration costs and capital and operating expenditures will continue to be denominated in U.K. pound sterling. Accordingly, any material appreciation of the U.K. pound sterling against the Australian dollar and U.S. dollar could have a negative impact on our business, operating results and financial condition. A 10% change in the Australian foreign currency rate compared to the U.S. dollar would increase or decrease revenues and expenses by $0.3 million and $0.7 million, and $0.8 million and $1.1 million respectively, for the three and six months ended December 31, 2011.

For the three months ended December 31, 2011, oil sales represented approximately 84% of total oil and gas revenues. Based on the current three month’s sales volume and revenues, a 10% change in oil price would increase or decrease oil revenues by $0.3 million. Gas sales, which represented approximately 16% of total oil and gas revenues in the current three month period, are derived primarily from the Palm Valley field in the Northern Territory of Australia and the gas prices are set according to long term contracts that are subject to changes in the Australian Consumer Price Index for the three months ended December 31, 2011.

At December 31, 2011, the value of our investments in securities available for sale was $146,968.

ITEM 4 CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities and Exchange Act of 1934) was performed as of December 31, 2011. This evaluation was performed under the supervision and with the participation of the Company’s management, including J. Thomas Wilson, the Company’s President and Chief Executive Officer (“CEO”), and Antoine J. Lafargue, the Company’s Chief Financial Officer (“CFO”).

Based upon the evaluation, the CEO and the CFO concluded that, because the reliability of the internal control process requires repeatable execution, the successful remediation of the material weakness identified in our prior fiscal year will require review and evidence of effectiveness for more than one quarter prior to management concluding that the controls are now effective. Accordingly, the Company’s CEO and CFO concluded that the Company’s disclosure controls and procedures were ineffective at December 31, 2011 due to the un-remediated material weaknesses described in Item 9A of the Company’s Form 10-K for the period ended June 30, 2011. However, the Company believes that the consolidated financial statements included in this Form 10-Q fairly present, in all material respects, the Company’s financial position, results of operations and cash flows for the periods presented.

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 six months ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting, except those described below.

The Company continues to work with its third party accounting experts to improve its internal control over financial reporting and process surrounding the Statement of Cash Flows including the following steps:

•

The Company has augmented its financial reporting and technical accounting resources to enable more detailed and rigorous reviews of the cash flow statement preparation process and financial reporting. This includes the recruitment of a full time financial reporting manager.

•

Improved communication surrounding new or unusual transactions.

•

Conducting additional training of subsidiary personnel to assist in the preparation of documents supporting the preparation of the statement of cash flows.

•

Regular reports are issued to the Audit Committee and Board of Directors as to the progress of the remediation.

PART II - OTHER INFORMATION

ITEM 1A RISK FACTORS

Item 1A (“Risk Factors”), of our most recently filed Form 10-K sets forth information relating to important risks and uncertainties that could materially affect our business, financial condition or operating results. Except as described below, there have been no material changes from the Risk Factors described in our Annual Report on Form 10-K for the year ended June 30, 2011; however, those Risk Factors continue to be relevant to an understanding of our business, financial condition and operating results and, 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.

There is a risk that the Mereenie/Palm Valley swap transactions will not be completed, or timely completed, because of a failure to satisfy the specified conditions to the closing;

There is a risk that VAALCO’s well drilling efforts will not be successful.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Share Repurchase Plan

The following schedule sets forth the number of shares that the Company has repurchased under any of its repurchase plans for the stated periods, the cost per share of such repurchases and the number of shares that may yet be repurchased under the plans:


Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan (1)		Maximum Number of Shares that May Yet Be Purchased Under Plan
October 1-31, 2011		—		—		—		319,150
November 1-30, 2011		—		—		—		319,150
December 1-31, 2011		—		—		—		319,150

(1)

The Company through its stock repurchase plan may purchase up to one million shares of its common stock in the open market. Through December 31, 2011, the Company had purchased 680,850 of its shares at an average price of $1.01 per share or a total cost of approximately $686,000, all of which shares have been cancelled.

ITEM 4 MINE SAFETY DISCLOSURES

Disclosures regarding mine safety is not applicable to the Company.

ITEM 5 – OTHER EVENTS

There have been no material changes from the legal proceedings as previously disclosed in our Form 10-K for the period ended June 30, 2011, in response to Item 3 of Part I of such Form 10-K.

ITEM 6 EXHIBITS


3.1		Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware and Amendment of Article Twelfth filed on February 12, 1988 with the State of Delaware, filed as Exhibit 4(b) to the Company’s Form S-8 Registration Statement (File No. 333-70567), filed on January 14, 1999, are incorporated herein by reference.

3.2		Certificate of Amendment to Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware, filed as Exhibit 3(a) to the Company’s quarterly report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference.

3.3		Certificate of Amendment to Certificate of Incorporation related to Article Twelfth as filed on October 15, 2009 with the State of Delaware, filed as Exhibit 3.3 to the Company’s quarterly report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference.

3.4		Certificate of Amendment to 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 Company’s quarterly report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference.

3.5		Certificate of Amendment to Certificate of Incorporation as filed on December 10, 2010 with the Secretary of State, filed as Exhibit 3.1 to the Company’s current report on Form 8-K filed on December 13, 2010 and incorporated herein by reference.

3.6		Amended and Restated Bylaws, as of March 10, 2010, filed as Exhibit 3.1 to the Company’s current report on Form 8-K filed on March 15, 2010 and incorporated herein by reference.

10.1		Employment Agreement between the Company and J. Thomas Wilson dated November 2, 2011, filed as Exhibit 10.1 to the Company’s current report on Form 8-K filed on November 16, 2011 and incorporated herein by reference.

10.2		Indemnification Agreement between the Company and J. Thomas Wilson dated November 2, 2011, filed as Exhibit 10.2 to the Company’s current report on Form 8-K filed on November 16, 2011 and incorporated herein by reference.



10.3		Nonqualified Stock Option Award Agreement between the Company and J. Thomas Wilson dated November 16, 2011, filed as Exhibit 10.3 to the Company’s current report on Form 8-K filed on November 16, 2011 and incorporated herein by reference.

10.4		Restricted Stock Award Agreement between the Company and J. Thomas Wilson dated November 16, 2011 and incorporated herein by reference.

10.5		Offer letter to Milam Randolph Pharo dated November 16, 2011 and accepted on November 30, 2011, filed herewith.

10.6		Nonqualified Stock Option Award and Subscription Agreement between the Company and Milam Randolph Pharo dated November 30, 2011, filed herewith.

10.7		Non Qualified Stock Option Award Agreement between the Company and Antoine J. Lafargue dated November 30, 2011, filed herewith.

10.8		Nonqualified Stock Option Performance Award Agreement between the Company Antoine J. Lafargue dated November 30, 2011, filed herewith.

10.9		Nonqualified Stock Option Award and Subscription Agreement between the Company and Blaine K. Spies dated December 14, 2011 is filed herewith.

31.1		Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, is filed herewith.

31.2		Certification of Antoine J. Lafargue, Chief Financial Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, is filed herewith.

32.1		Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, is furnished herewith.

32.2		Certification of Antoine J. Lafargue, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, is furnished herewith.

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

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 10, 2012	By	/s/ John Thomas Wilson
	John Thomas Wilson, President and Chief Executive Officer (Duly Authorized Officer)

	By	/s/ Antoine J. Lafargue
	Antoine J. Lafargue, Chief Financial Officer and Treasurer (as Principal Financial Officer)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company