10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(MARK ONE)

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

For the quarterly period ended September 30, 2012

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

For the transition period from    to

Commission File Number 001-5507

MAGELLAN PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

DELAWARE	06-0842255
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 1950, Denver, CO	80203
(Address of principal executive offices)	(Zip Code)

(720) 484-2400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No

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

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

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

The number of shares outstanding of the issuer’s single class of common stock as of November 1, 2012 was 53,885,594.

TABLE OF CONTENTS

ITEM		PAGE
	PART I — FINANCIAL INFORMATION
ITEM 1	FINANCIAL STATEMENTS (UNAUDITED)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Comprehensive Loss	3
	Condensed Consolidated Statement of Stockholders' Equity	4
	Condensed Consolidated Statements of Cash Flows	5
	Notes to Condensed Consolidated Financial Statements (unaudited)	7
ITEM 2	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	23
ITEM 4	CONTROLS AND PROCEDURES	24
	PART II — OTHER INFORMATION
ITEM 1	LEGAL PROCEEDINGS	25
ITEM 1A	RISK FACTORS	25
ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	25
ITEM 6	EXHIBITS	26
	SIGNATURES	27

PART I - FINANCIAL INFORMATION

ITEM 1 FINANCIAL STATEMENTS (UNAUDITED)

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(In thousands, except per share amounts)

	September 30, 2012			June 30, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	37,939		$	41,215
Accounts receivable — trade	1,037			1,152
Accounts receivable — working interest partners	216			231
Inventories	470			499
Prepaid and other assets	258			511
Total current assets	39,920			43,608
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
Proved oil and gas properties	33,499			33,927
Less accumulated depletion, depreciation, and amortization	(5,537		)	(5,740		)
Unproved oil and gas properties	6,501			7,091
Wells in progress	3,707			3,744
Land, buildings, and equipment (net of accumulated depreciation of $2,174 and $2,077 as of September 30, 2012, and June 30, 2012, respectively)	1,540			1,422
Net property and equipment	39,710			40,444
OTHER NON-CURRENT ASSETS:
Goodwill	2,174			2,174
Deferred income taxes	6,287			5,951
Other long term assets	376			397
Total other non-current assets	8,837			8,522
Total assets	$	88,467		$	92,574
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Short term line of credit	$	100		$	50
Current portion of note payable	456			480
Current portion of asset retirement obligations	339			329
Accounts payable	3,543			3,672
Accrued and other liabilities	3,170			3,000
Total current liabilities	7,608			7,531
LONG TERM LIABILITIES:
Note payable	282			390
Asset retirement obligations	7,349			7,455
Contingent consideration payable	4,152			4,072
Other long term liabilities	213			218
Total long term liabilities	11,996			12,135

COMMITMENTS AND CONTINGENCIES (Note 10)
EQUITY:
Common stock (par value $0.01 per share): Authorized 300,000,000 shares, outstanding, 53,885,594 and 53,835,594 as of September 30, 2012, and June 30, 2012, respectively	539			538
Capital in excess of par value	91,098			90,753
Preferred stock (par value $0.01 per share): Authorized 50,000,000 shares, outstanding, 0 as of September 30, 2012, and June 30, 2012, respectively	—			—
Accumulated deficit	(34,900		)	(29,590		)
Accumulated other comprehensive income	12,126			11,207
Total equity attributable to Magellan Petroleum Corporation	68,863			72,908
Total liabilities and equity	$	88,467		$	92,574

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

1

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

(In thousands, except per share amounts)

	THREE MONTHS ENDED
	September 30,
	2012			2011
REVENUES:
Oil production	$	1,460		$	3,296
Gas production	200			439
Total revenues	1,660			3,735
OPERATING EXPENSES:
Lease operating	2,051			3,018
Depletion, depreciation, amortization, and accretion	316			474
Exploration	622			987
General and administrative	3,663			2,512
Impairment	890			—
Gain on sale of assets	—			(4,108		)
Total operating expenses	7,542			2,883
(Loss) income from operations	(5,882		)	852
OTHER INCOME (EXPENSE)
Net interest income	221			271
Other income	15			—
Total other income	236			271
(Loss) income before income tax	(5,646		)	1,123
Income tax benefit (provision)	336			(198		)
Net (loss) income after income tax	(5,310		)	925
Net income attributable to non-controlling interest in subsidiaries	—			15
Net (loss) income attributable to Magellan Petroleum Corporation	$	(5,310	)	$	940
Earnings per common share (Note 8)
Weighted average number of basic shares outstanding	53,849,181			52,915,811
Weighted average number of diluted shares outstanding	53,849,181			54,720,728
Net (loss) income per basic share outstanding	$	(0.10	)	$	0.02
Net (loss) income per diluted share outstanding	$	(0.10	)	$	0.02

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

2

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)

(In thousands)

	THREE MONTHS ENDED
	September 30,
	2012			2011
Net (loss) income attributable to Magellan Petroleum Corporation	$	(5,310	)	$	925
Foreign currency translation adjustments	941			(1,242		)
Unrealized holding losses on securities available for sale, net of deferred tax of $0	(22		)	(34		)
Total comprehensive loss	(4,391		)	(351		)
Net income attributable to non-controlling interest in subsidiary	—			15
Comprehensive loss attributable to Magellan Petroleum Corporation	$	(4,391	)	$	(336	)

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

3

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)

(In thousands)

	Common Stock		Preferred Stock		Capital in Excess of Par Value		Accumulated Deficit			Accumulated Other Comprehensive Income			Total Stockholders' Equity
June 30, 2012	$	538	$	—	$	90,753	$	(29,590	)	$	11,207		$	72,908
Net loss	—		—		—		(5,310		)	—			$	(5,310	)
Foreign currency translation adjustments	—		—		—		—			941			$	941
Unrealized holding loss on securities available for sale, net of taxes	—		—		—		—			(22		)	$	(22	)
Stock and stock based compensation	1		—		345		—			—			$	346
September 30, 2012	$	539	$	—	$	91,098	$	(34,900	)	$	12,126		$	68,863

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

4

MAGELLAN PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(In thousands)

	THREE MONTHS ENDED
	September 30,
	2012			2011
OPERATING ACTIVITIES:
Net (loss) income after income tax	$	(5,310	)	$	925
Adjustments to reconcile net loss to net cash used in operating activities
Foreign transaction gain	—			(562		)
Depletion, depreciation, amortization and accretion	316			474
Interest earned on restricted deposits	—			(24		)
Fair value increase of contingent consideration payable	80			—
Deferred income taxes	(336		)	—
Gain on disposal of assets	—			(4,108		)
Stock based compensation	346			396
Impairment loss	890			—
Severance benefit costs	780			—
Net changes in operating assets and liabilities:
Accounts receivable	143			3,165
Inventories	57			(80		)
Prepayments and other current assets	255			188
Accounts payable and accrued liabilities	(871		)	(2,598		)
Income taxes payable	—			197
Net cash used in operating activities	(3,650		)	(2,027		)
INVESTING ACTIVITIES:
Additions to property and equipment	(385		)	(1,242		)
Proceeds from sale of assets	—			5,001
Purchase of working interest in Poplar	—			(823		)
Refund of Deposit for Purchase of Evans Shoal (includes interest)	—			10,940
Marketable securities purchased, net	—			(2,400		)
Net cash (used in) provided by investing activities	(385		)	11,476
FINANCING ACTIVITIES:
Proceeds from issuance of stock	—			35
Short term debt issuances	550			1,925
Short term debt repayments	(500		)	(1,225		)
Purchase of non-controlling interest in Nautilus Poplar LLC	—			(3,415		)
Long term debt repayments	(132		)	(144		)
Net cash used in financing activities	(82		)	(2,824		)
Effect of exchange rate changes on cash and cash equivalents	841			(1,319		)
Net (decrease) increase in cash and cash equivalents	(3,276		)	5,306
Cash and cash equivalents at beginning of period	41,215			20,417
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	37,939		$	25,723

5

Cash Payments:
Income taxes	—		—
Interest paid, net of amount capitalized	—		34
Supplemental Schedule of Noncash Investing and Financing Activities:
Unrealized holding (loss) gain	(22	)	34
Revision to estimate of asset retirement obligations	(306	)	—
Amounts in accounts payable and accrued liabilities related to property and equipment	58		162
Accrued transaction costs	—		102
Purchase of non-controlling interest for Stock and contingent consideration	—		4,729
Purchase of 3% working interest for Stock and contingent consideration	—		1,243

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

6

ITEM 1 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Basis of Presentation

Description of Operations

Magellan Petroleum Corporation (the "Company" or "Magellan" or "we" or "us") is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. As of September 30, 2012, Magellan had two reporting segments: (i) a 100% membership interest in Nautilus Poplar LLC ("NP"), based in Denver, Colorado, and (ii) a 100% equity interest in its subsidiary, Magellan Petroleum Australia Limited ("MPAL"), headquartered in Brisbane, Australia, which includes our operations in the United Kingdom.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP and MPAL, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and in accordance with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. 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. All intercompany transactions have been eliminated. Operating results for the three months ended September 30, 2012, are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2013. This report should be read in conjunction with the consolidated financial statements and footnotes included in the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2012.

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

Reclassification

As of December 31, 2011, we changed the presentation of our financial statements to conform them to industry-specific norms and to improve our reporting to shareholders and stakeholders. Specifically, we have modified the presentation of expenses in the unaudited condensed consolidated statements of operations and the presentation of property and equipment in the unaudited 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. There was no impact on previously reported results.

Use of Estimates

The preparation of unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Foreign Currency Translation

The functional currencies of our foreign subsidiaries are their local currencies. Assets and liabilities of foreign subsidiaries are translated to United States dollars at period-end exchange rates, and our unaudited condensed consolidated statements of operations and cash flows are translated at average exchange rates during the period. Resulting translation adjustments are recorded as a separate component of stockholders' equity as accumulated other comprehensive income or loss.

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

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. GAAP requires goodwill to be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. We adopted the new guidance for our annual impairment test in fiscal year 2012 as allowed by ASU 2011-08 and therefore perform an annual assessment of qualitative factors for our impairment test. The qualitative factors used in our assessment include macroeconomic conditions, industry and market conditions, cost factors, and overall financial performance. For the three months ended September 30, 2012, there were no events or circumstances that would indicate that a goodwill impairment exists.

7

Business Combinations

The Company applies the acquisition method of recording business combinations. Under this method, the Company recognizes and measures the identifiable assets acquired from, the liabilities assumed from, and any non-controlling interest in the acquiree. Any goodwill or gain is identified and recorded. We engage independent valuation consultants to assist us in determining the fair values of crude oil and natural gas properties acquired and other third party specialists as needed to assist us in assessing the fair value of other assets and liabilities assumed. These valuations require management to make significant estimates and assumptions, especially with respect to the oil and gas properties.

Note 2 - Acquisitions and Divestitures

Sale Agreement between Magellan Petroleum (N.T.) Pty Ltd and Santos QNT Pty Ltd and Santos Limited. On May 25, 2012, Magellan Petroleum (N.T.) Pty Ltd ("Magellan NT"), a wholly owned subsidiary of MPAL, and Santos QNT Pty Ltd ("Santos") and Santos Limited (collectively the "Santos Entities") completed a Sale Agreement (the "Santos SA"). Under the Santos SA, MPAL became the sole owner of the Palm Valley Interests (as defined below) and the Dingo Interests (as defined below), and Santos became the sole owner of the Mereenie Interests (as defined below). The Santos SA is deemed to be effective as of July 1, 2011 and resulted in net cash proceeds of $26.6 million, including adjustments of $1.1 million, and a gain on sale of assets in the amount of $36.2 million. The Santos SA provided for the transfer of the following assets:

• Magellan NT's 35% interest in each of the Mereenie Operating Joint Venture and the Mereenie Pipeline Joint Venture (collectively, the "Mereenie Interests") to Santos;

• the Santos Entities' combined interests of 48% in the Palm Valley Joint Venture ("Palm Valley Interests") and combined interests of 66% in the Dingo Joint Venture ("Dingo Interests") to Magellan NT.

Pursuant to the Santos SA, Magellan NT is also entitled to a series of contingent payments of up to $17.5 million. The Company has not recognized a contingent asset related to the series of contingent payments, as such amounts are not reasonably assured. The Company accounted for the Santos SA using the relative fair value method of accounting, which allocates the fair value of the assets received in the asset transfer to the Palm Valley Interests and the Dingo Interests. No goodwill or other intangible assets were recorded as a result of the Santos SA. However, goodwill in the amount of $2.5 million was recorded as a component of the gain on sale of assets. The purchase price allocation was considered final as of June 30, 2012.

The following table summarizes the allocation of the consideration received for the assets transferred as a result of the Santos SA as of June 30, 2012.

	Total
	(In thousands)
Consideration received
Net purchase price per Santos SA	$	25,493
Purchase price adjustments	1,138
Total	$	26,631
Allocation of the consideration received to fair value of assets
Proved oil and gas properties (Palm Valley)	$	3,403
Unproved oil and gas properties (Dingo)	2,957
Land, buildings, and equipment (Palm Valley)	370
Total allocation of the fair value received	6,730
Mereenie liabilities given up, net	2,805
Gain on sale of assets	(36,166		)
Total	$	(26,631	)

8

Note 3 - Debt

Long term debt relates to a $1.7 million note payable re-issued in January 2011. This note will be fully amortized in June 2014. The outstanding principal as of September 30, 2012, and June 30, 2012, consisted of the following:

	September 30, 2012			June 30, 2012
	(In thousands)
Note payable	$	738		$	870
Less current portion of note payable	(456		)	(480		)
Long term debt, excluding current portion	$	282		$	390

As of September 30, 2012, the minimum future principal maturities of long term debt were as follows:

	September 30, 2012
	(In thousands)
One year	$	456
Two years	282
Total	$	738

The variable rate of the note is based upon the Wall Street Journal Prime Rate (the "Index") plus 1.00%, subject to a floor rate of 6.25%. The Index was 3.25% at September 30, 2012, resulting in an interest rate of 6.25% per annum as of September 30, 2012. Under the note payable, NP is required to maintain certain customary financial and restrictive covenants. As of September 30, 2012, NP was in compliance with all financial and restrictive covenants.

In addition, 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 $0.1 million as of September 30, 2012. The line of credit bears interest at a variable rate, which was 6.25% as of September 30, 2012. The line of credit also secures both a letter of credit in the amount of $25 thousand in favor of the Bureau of Land Management and business credit cards in the amount of $25 thousand. As of September 30, 2012, $0.8 million was available under this line of credit.

The note payable, letters of credit, and business credit cards are collateralized by a first mortgage and an assignment of production from Poplar and are guaranteed by Magellan 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, due to its variable interest rate, which resets based on the market rates.

Note 4 - Asset Retirement Obligations

The estimated valuation 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 made by management when assessing an ARO include: (i) the existence of a legal obligation; (ii) estimated probabilities, amounts, and timing of settlements; (iii) the credit-adjusted risk-free rate to be used; and (iv) inflation rates. Accretion expense is recorded under depletion, depreciation, amortization, and accretion in the unaudited condensed consolidated statement of operations.

The following table summarizes the asset retirement obligation activity for the three months ended September 30, 2012:

	Total
	(In thousands)
June 30, 2012	$	7,784
Accretion expense	111
Revision to estimate	(306		)
Effect of exchange rate changes	99
September 30, 2012	7,688
Less current asset retirement obligation	339
Long term asset retirement obligation	$	7,349

9

Note 5 - 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. During the three months ended September 30, 2012, and 2011, there have been no transfers in and/or out of Level 1, Level 2, or Level 3.

Items required to be measured at fair value on a non-recurring basis include liabilities related to AROs. Items required to be measured at fair value on a recurring basis include cash and cash equivalents and securities available for sale, classified as Level 1, and the contingent consideration payable related to the acquisition of the non-controlling interest and additional working interest in Nautilus Poplar LLC, classified as Level 3.

As of September 30, 2012, the Company had $37.9 million in cash and cash equivalents, with $19.3 million held in cash and $18.6 million classified as cash equivalents. The cash equivalents were held in time deposit accounts in several Australian banks with maturities of 90 days or less.

The following table presents the amounts of assets and liabilities carried at fair value by the level in which they are classified within the valuation hierarchy for the three months ended:

	September 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	37,939	$	—	$	—	$	37,939
Securities available for sale (1)	133		—		—		133
	$	38,072	$	—	$	—	$	38,072
Liabilities
Contingent consideration payable	$	—	$	—	$	4,152	$	4,152
	June 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	41,215	$	—	$	—	$	41,215
Securities available for sale (1)	155		—		—		155
	$	41,370	$	—	$	—	$	41,370
Liabilities
Contingent consideration payable	$	—	$	—	$	4,072	$	4,072

⁽¹⁾ Included in the unaudited condensed consolidated balance sheets under prepaid and other assets.

10

The following table presents a roll forward of liabilities measured at fair value using significant unobservable inputs (Level 3) for the three months ended:

	September 30, 2012
	(In thousands)
June 30, 2012	$	4,072
Accretion of contingent consideration payable	80
September 30, 2012	$	4,152

The fair value of the contingent consideration payable is calculated using production projections and the estimated timing of production payouts. The Company also utilizes a discount that is consistent with the rate used in valuing its asset retirement obligations and reflective of the Company’s credit adjusted borrowing rate.

Note 6 - 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 three months ended September 30, 2012, is 5.96% compared to 0% for the three months ended September 30, 2011. 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 amount management believes is more likely than not the deferred tax assets that will be realized in future periods.

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. We anticipate we will continue to record a valuation allowance against the deferred tax assets in all jurisdictions of the Company, except for the deferred asset related to the Australian Petroleum Resource Rent Tax ("PRRT"), until such time as we are able to determine it is "more-likely-than-not" those deferred tax assets will be realized.

Note 7 - Stock Based Compensation

The Stock Plan

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

Stock Option Grants

Stock option grants contain both time based and performance based vesting provisions. The time based options are expensed on a straight-line basis over the vesting period. Performance based options are recognized when the achievement of the performance conditions is considered probable. Management re-assesses whether satisfaction of performance conditions are probable at the end of each reporting period. If changes in the estimated outcome of the performance conditions affect the quantity of the awards expected to vest, the cumulative effect of the change is recognized in the period of change. As of September 30, 2012, management believes the achievement of the performance conditions related to the PBOs is probable. Accordingly, the Company has recognized expense on these awards over the period of time the performance condition is expected to be achieved.

As of September 30, 2012, 460,000 shares were available for future issuance under the Stock Plan. Of the 925,000 options granted during the three months ended September 30, 2012, 75,000 were issued as PBOs and 800,000 options were issued outside of the Stock Plan. Options outstanding have expiration dates ranging from November 28, 2015, through September 5, 2022.

11

The following table summarizes the stock option activity for the three months ended:

	September 30, 2012
	Number of Shares		WAEPS (1)
June 30, 2012	6,753,125		$1.44
Granted	925,000		$1.31
Forfeited	(483,334	)	$1.13
September 30, 2012	7,194,791		$1.37
Weighted average remaining contractual term	5.1 years

⁽¹⁾ Weighted average exercise price per share

The fair value of stock option grants was estimated using the following weighted average assumptions for the three months ended:

	September 30,
	2012					2011
Number of options (1)	925,000					—
Weighted average grant date fair value per share	$1.31					$0.00
Expected dividend	$0.00					$0.00
Risk free interest rate	0.6	%	-	0.8	%	—	%	-	—	%
Expected life	5.13 years		-	6.00 years		0 years		-	0 years
Expected volatility (based on historical price)	60.7	%	-	63.5	%	—	%	-	—	%

⁽¹⁾ There were no stock option grants for the three months ended September 30, 2011.

Stock Compensation Expense

The Company recorded $0.3 million and $0.4 million of related stock compensation expense for the three months ended September 30, 2012, and 2011, respectively. Stock based compensation is included in general and administrative expense in the unaudited condensed consolidated statements of operations. The unrecorded expected future compensation expense related to stock option awards was $0.9 million as of September 30, 2012.

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 subject to an annual maximum of 15,000 shares. As of September 30, 2012, no shares were issued by the Company pursuant of this policy.

Note 8 - Earnings Per Common Share

The following table summarizes the computation of basic and diluted earnings per share for the three months ended:

	September 30,
	2012			2011
	(In thousands, except share and per share amounts)
Net (loss) income attributable to Magellan Petroleum Corporation	$	(5,310	)	$	940
Basic weighted average shares outstanding	53,849,181			52,915,811
Add: dilutive effects of stock options and unvested stock grants (1)	—			1,804,917
Diluted weighted average common shares outstanding	53,849,181			54,720,728
Net (loss) income per basic share outstanding	$	(0.10	)	$	0.02
Net (loss) income per diluted share outstanding	$	(0.10	)	$	0.02

⁽¹⁾ There is no dilutive effect on earnings per share in periods with net losses.

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Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following for the three months ended:

	September 30,
	2012	2011
Stock options	75,000	7,697,826
Non-vested restricted stock	—	104,167
Total	75,000	7,801,993

Note 9 - Segment Data

The Company conducts its operations through two wholly owned subsidiaries, NP, which operates in the United States, and MPAL, which is primarily active in Australia. The following table presents each segment as follows:

	NP			MPAL			Corporate			Inter-Segment Elimination			Total
	(In thousands)
Three months ended September 30, 2012
Revenues	$	1,460		$	200		$	—		$	—		$	1,660
Consolidated net income (loss)	$	(272	)	$	(1,824	)	$	(3,043	)	$	(171	)	$	(5,310	)
Three months ended September 30, 2011
Revenues	$	1,231		$	2,504		$	—		$	—		$	3,735
Consolidated net income (loss)	$	3,868		$	(932	)	$	(1,993	)	$	(3	)	$	940

Note 10 - Commitments and Contingencies

Refer to the Note 10 - Commitments, in our Form 10-K as of June 30, 2012, for information on all commitments. Additionally see Note 5 above for information regarding the contingent consideration payable related to the Nautilus Transaction.

On August 28, 2012, Stratex Oil & Gas Holdings, Inc. ("Stratex") announced an unsolicited proposal for the acquisition of each outstanding share of the Company's common stock for $0.65 in cash and one share of Stratex common stock, the closing price for which as reported by the OTCQB on August 27, 2012 was $1.65 per share. On September 10, 2012, the Company announced that its Board of Directors, after carefully considering the unsolicited proposal and consulting with its financial and legal advisors, had determined not to pursue the Stratex proposal. On September 12, 2012, the Company received a subpoena from the U.S. Securities and Exchange Commission (the "SEC") for the production of documents in connection with these announcements. On September 14, 2012, the Company received a letter from the Financial Industry Regulatory Authority ("FINRA") indicating that FINRA is conducting a review of trading in the Company's common stock surrounding the August 28, 2012 announcement by Stratex, and requesting information and documents from the Company in connection therewith. The Company is cooperating fully with the SEC and FINRA in these matters.

Note 11 - Related Party Transactions

U.S. Federal Tax Withholdings. During the third quarter of fiscal year 2012, the Company identified a potential liability of approximately $2.0 million related to the Company's non-payment of required U.S. Federal tax withholding in the course of its initial acquisition of a part of NP. In October 2009, Magellan acquired 83.5% of the membership interests in NP (the "Poplar Acquisition"), from the two majority owners of NP, White Bear LLC ("White Bear") and YEP I, SICAV-FES ("YEP I"). Both of these entities are affiliated with Mr. Bogachev, a Director of Magellan and a foreign national. Due to the status of YEP I as a foreign entity and the members of White Bear as foreign nationals, Magellan was required to make U.S. Federal tax withholdings from the payments to or for the benefit of White Bear and YEP I. Of the $2.0 million liability, $1.3 million was estimated to relate to the interest sold by White Bear, $0.6 million to the interest sold by YEP I, and $0.1 million to Magellan's interest on late payment of the U.S. Federal tax withholdings.

Upon the filing of U.S. income tax returns in relation to the Poplar Acquisition and payment of corresponding income taxes by White Bear and YEP I, Magellan is deemed to be relieved of its liability for the U.S. Federal tax withholdings as well as related penalties and interest except for Magellan's interest on late payment of the U.S. Federal tax withholdings. With regards to White Bear, Magellan has confirmed that as of the date of this filing, Mr. Bogachev has filed his U.S. income tax return and paid taxes due on the Poplar Acquisition, which were estimated at $0.3 million. Magellan has paid Mr. Bogachev $0.3 million in additional compensation during the quarter ended September 30, 2012. Had Mr. Bogachev not filed and paid his tax return, Magellan's liability in relation to its

13

U.S. Federal tax withholdings requirements was estimated at $1.3 million. With regards to YEP I, Magellan continues to seek from YEP I or, because YEP I is a now defunct entity, from its successor entities, the filing of its U.S. income tax return.

As of September 30, 2012, we have recorded a total liability of $0.7 million under accrued and other liabilities in the consolidated balance sheets related to this matter. That amount is comprised of the $0.6 million in withholdings, penalties, and interest related to YEP I and $0.1 million related to Magellan's interest on its late payment of the U.S. Federal tax withholdings. There was no effect on the unaudited condensed consolidated statements of operations for the three months ended September 30, 2012, related to this transaction.

Note 12 - Oil and Gas Activities

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

	September 30, 2012			June 30, 2012
	(In thousands)
Proved oil and gas properties:
United Kingdom	$	—		$	—
United States	24,299			24,207
Australia	9,200			9,720
Less accumulated depletion, depreciation, and amortization	(5,537		)	(5,740		)
Total net proved oil and gas properties	$	27,962		$	28,187
Unproved oil and gas properties:
United Kingdom	$	1,936		$	2,598
United States	104			104
Australia	4,461			4,389
Total unproved oil and gas properties:	$	6,501		$	7,091
Wells in Progress:
United Kingdom	$	1,934		$	2,026
United States	1,773			1,718
Australia	—			—
Total wells in progress	$	3,707		$	3,744

During the three months ended September 30, 2012, Magellan allowed a license in the United Kingdom to expire at the end of its term. Subsequently an impairment of $0.9 million was recorded in the unaudited condensed consolidated statement of operations.

Note 13 - Employee Termination Costs

The Company is required to record charges for one-time employee termination benefits and other associated costs as incurred. In July 2012, the Company incurred severance costs related to certain employees relating to their termination in accordance with their employment agreements. For the three months ended September 30, 2012, the Company expensed total employee-related termination costs of $0.8 million, all of which was charged to general and administrative expense in the unaudited condensed consolidated statement of operations. The Company does not project any additional benefits or other associated costs related to these terminations. The liability related to these termination costs are included in the unaudited condensed consolidated balance sheet under accrued and other liabilities.

A reconciliation of the beginning and ending liability balance for charges to general and administrative expense and cash payments for the three months ended September 30, 2012, is as follows:

	Total
	(In thousands)
June 30, 2012	$	—
Charges to general and administrative expense	828
Cash payments	(48		)
September 30, 2012	$	780

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

The following discussion and analysis should be read in conjunction with our 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, 2012, 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. Unless otherwise indicated, all references in this discussion to Notes are to the Notes to the unaudited condensed consolidated financial statements included in Part I, Item I of this report. 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 the 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

The Company is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. The Company conducts its operations through 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 existence since 1964 active in Australia and the United Kingdom.

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

Our strategy is to enhance shareholder value by maximizing the value of our existing assets. Our portfolio of operations includes several early stage oil and gas exploration and development projects, the successful development of which requires significant capital, engineering, and management resources. We are committed to investing the necessary resources in these projects to establish their technical and economic viability. In turn, we will determine the most efficient way to create value and returns for our shareholders.

SUMMARY RESULTS OF OPERATIONS

Revenues for the three months ended September 30, 2012, totaled $1.7 million, compared to $3.7 million in the prior year period, a decrease of 56%. The Company does not anticipate an increase in its revenues until the Company's assets move to the development phase. Operating loss for the three months ended September 30, 2012, totaled $5.9 million, compared to a $0.9 million gain in the prior year period. Net loss for the three months ended September 30, 2012, totaled $5.3 million ($(0.10)/basic share), compared to a $0.9 million gain ($0.02/basic share) in the prior year period. For further information, please refer to the discussion below in this section under Comparison of Results between the Three Months Ended September 30, 2012, and 2011.

HIGHLIGHTS OF OPERATIONAL ACTIVITIES

During the three months ended September 30, 2012, management articulated a strategy focused on proving up the value of its existing assets as the most economic way of increasing shareholder value. Towards that end, management has begun a number of initiatives to evaluate and determine the potential of its oil and gas properties.

Poplar (Montana, USA)

Magellan 100% operated intervals. During the three months ended September 30, 2012, Magellan sold 18 Mbbls of oil attributable to its net revenue interests in Poplar, compared to 15 Mbbls of oil sold during the same period in 2011. These results represent a 20% increase in average daily sales for the year from 160 boepd to 200 boepd. The increase in production is primarily due to constrained production in the prior year period caused by the temporary suspension of one of Poplar's salt water disposal wells, which resulted in the temporary shut in of several producing wells; greater ownership in Poplar as a result of the Nautilus Restructuring in September 2011; a workover program instituted at Poplar in the summer of 2012; and sales from the EPU 117 well, which produces out of the Amsden Formation, a new pool discovery made in January 2012.

During this period, Magellan focused heavily on advancing its plans for a CO₂-enhanced oil recovery project ("CO₂-EOR") project in the Charles Formation at Poplar. In August 2012, Core Laboratories, on behalf of Magellan, finalized its analyses of oil samples taken from the Charles Formation, including tests of minimum miscibility pressure, CO₂ solubility swelling, and viscosity reduction. The results of these analyses were all supportive of the viability of a CO₂-EOR project at Poplar. Subsequent to these findings, Magellan identified a location for, and began the permitting process to drill and implement, a five-well CO₂-EOR pilot project to be conducted during fiscal year 2013. The permitting process is ongoing and is expected to be completed in the third quarter of fiscal year 2013, with the drilling of the five wells to follow. In parallel to the permitting process, Magellan has been evaluating

15

various options for the CO₂ supply for its pilot project. Also during the period, Magellan continued to experiment with and evaluate production enhancing technologies on existing wells at Poplar, including water shut-off and stim-oil treatments. Evaluation of the effectiveness of these treatments is ongoing.

VAALCO 65% operated intervals. Under the terms of our Lease Purchase and Sale and Participation Agreement with VAALCO (the "VAALCO PSA"), VAALCO is required to spud and complete three test wells in the deeper Formations at Poplar by December 31, 2012, in order to earn a 65% working interest in these Formations. VAALCO's second test well, EPU 133-H, was completed as a horizontal well in the Bakken/Three Forks Formation in September 2012. This well was found to be water-bearing and is temporarily shut-in while VAALCO evaluates its options.

Australia

Palm Valley. The Palm Valley gas field, which is operated by MPAL, produced a gross average of approximately 0.4 MMcf/d of natural gas for sale for the three months ended September 30, 2012, compared to 4.5 MMcf/d during the same period in 2011. Gas sales volumes at Palm Valley decreased due to the termination of the gas sales contract with Northern Territory Power and Water Corporation (the "PWC Contract") during January 2012. Gas volumes during this period were sold under a long-term gas sales contract with Santos. To date, gas volumes sold under this arrangement have been significantly lower than under the PWC Contract, although volumes are expected to increase by fiscal year 2015 to levels similar to, and at prices significantly higher than, those realized under the PWC Contract.

Dingo. During the period ended September 30, 2012, the Company has continued its marketing efforts to identify and attract long-term customers for Dingo's gas resources.

NT/P82. During the three months ended September 30, 2012, Magellan worked to permit and commission a 3-D and 2-D seismic survey over its NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia. The permitting process, which included an environmental assessment, was satisfactorily completed in October 2012. Simultaneous with the permitting, Magellan held discussions with several contractors to conduct the seismic survey, and, in October 2012, the Company executed a contract with Seabird Exploration FZ-LLC for the seismic recording vessel Voyager Explorer to undertake a 75 square mile 3-D and an 84 square mile 2-D seismic survey within its NT/P82 permit area. The seismic survey is expected to commence during the second week of December 2012, and to take approximately two weeks to complete. Magellan plans to process and analyze the seismic data over the following three months to assess the presence of hydrocarbons in NT/P82. This is an important milestone in Magellan's strategy to prove up the value of its assets.

United Kingdom

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. During the three months ended September 30, 2012, Magellan, in conjunction with Celtique, focused on evaluating the prospects for an exploratory well in one of these licenses. Such a well would serve to assess the hydrocarbon potential of the Kimmeridge and Liassic Formations which are considered to have significant non-conventional hydrocarbon potential.

Northern Petroleum-Operated Licenses. In the Weald and Wessex Basins, Magellan owns working interests of between 23% and 40% in five licenses operated by Northern Petroleum (PEDL 126, 155, 240, and 256 and P1916), which expire between June 2014 and January 2016. During the three months ended September 30, 2012, the Markwells Wood-1 well drilled in 2011 remained temporarily suspended following a long-term production test conducted during fiscal year 2012. During the same period, the Company continued to evaluate the exploration options for its most recently acquired license, P1916, which lies offshore, west of the Isle of Wight, and is prospective for a Wytch Farm extension play.

Magellan Operated Licenses. In the Weald Basin, Magellan owns a 100% interest in two licenses (PEDL 137 and 246), which expire in September 2013 and June 2014, respectively. During the period ended September 30, 2012, the Company allowed PEDL 135 to expire at the end of its term on September 30, 2012. Magellan had previously owned a 100% interest in the license. Magellan acquired PEDL 135 to target similar to those targeted by its licenses co-owned with Celtique, but subsequently determined that the prospectivity of this license had been downgraded and did not warrant further exploration in this area. Also during the period, Magellan renewed its license for PEDL 137, originally set to expire on September 30, 2012, for an additional year.

ACQUISITIONS AND DIVESTITURES

Withholding Tax Liability

During the third quarter of fiscal year 2012, the Company identified a potential liability of approximately $2.0 million related to the Company's non-payment of required U.S. Federal tax withholding in the course of its initial acquisition of a part of NP. In October 2009, Magellan acquired 83.5% of the membership interests in NP (the "Poplar Acquisition"), from the two majority owners of NP, White Bear LLC ("White Bear") and YEP I, SICAV-FES ("YEP I"). Both of these entities are affiliated with Mr. Bogachev, a Director of Magellan and a foreign national. Due to the status of YEP I as a foreign entity and the members of White Bear as foreign nationals, Magellan was required to make U.S. Federal tax withholdings from the payments to or for the benefit of White Bear and YEP I. Of the

16

$2.0 million liability, $1.3 million was estimated to relate to the interest sold by White Bear, $0.6 million to the interest sold by YEP I, and $0.1 million to Magellan's interest on late payment of the U.S. Federal tax withholdings.

Upon the filing of U.S. income tax returns in relation to the Poplar Acquisition and payment of corresponding income taxes by White Bear and YEP I, Magellan is deemed to be relieved of its liability for the U.S. Federal tax withholdings as well as related penalties and interest except for Magellan's interest on late payment of the U.S. Federal tax withholdings. With regards to White Bear, Magellan has confirmed that as of the date of this filing, Mr. Bogachev has filed his U.S. income tax return and paid taxes due on the Poplar Acquisition, which were estimated at $0.3 million. Magellan has paid Mr. Bogachev $0.3 million in additional compensation during the quarter ended September 30, 2012. Had Mr. Bogachev not filed and paid his tax return, Magellan's liability in relation to its U.S. Federal tax withholdings requirements was estimated at $1.3 million. With regards to YEP I, Magellan continues to seek from YEP I or, because YEP I is a now defunct entity, from its successor entities, the filing of its U.S. income tax return.

As of September 30, 2012, we have recorded a total liability of $0.7 million under accrued and other liabilities in the consolidated balance sheets related to this matter. That amount is comprised of the $0.6 million in withholdings, penalties, and interest related to YEP I and $0.1 million related to Magellan's interest on its late payment of the U.S. Federal tax withholdings. There was no effect on the unaudited condensed consolidated statements of operations for the three months ended September 30, 2012, related to this transaction.

Sopak AG and Glencore International plc

On September 28, 2012, Sopak AG, Glencore International plc, and various related entities (together, "Glencore") filed a Schedule 13D with the SEC stating that Glencore had acquired beneficial ownership of 9,264,637 issued and outstanding shares of Magellan common stock (the "Issued Shares") and beneficial ownership of a warrant to purchase 4,347,826 shares of Magellan common stock (together with the Issued Shares, the "Transferred Shares"). The Transferred Shares were previously pledged by Young Energy Prize ("YEP"), an entity controlled by Nikolay Bogachev, a Director of Magellan, pursuant to the Pledge and Security Agreement dated July 7, 2009, amended as of July 8, 2009, and March 11, 2010 (the "Pledge Agreement"). On September 21, 2012, Sopak AG delivered a letter to the Company instructing the Company to cancel the original certificate for the Transferred Shares and deliver a replacement certificate to Sopak AG. On October 11, 2012, the 9,264,637 Issued Shares were re-registered in the name of Sopak AG.

CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES

Historically, we have funded our activities from cash from operations and our existing cash balance. Following the recent end of the long term PWC Contract and the completion of the Santos SA, the source of the Company's funds for the implementation of its strategy will come primarily from the Company's existing cash balance. In addition, we may fund our development strategy through a prioritization of assets which may include farmouts, or a partial or total divestiture. The Company has limited capital expenditure obligations related to its leases and licenses, which allow for significant flexibility in the use of its capital resources. Based on its existing cash position and the various alternative sources of funds generally available to the Company, the Company believes it 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. Approximately 80% of the acreage has been unitized as a Federal Exploratory Unit, which is held by production from any one well. Currently, Poplar contains 35 producing wells. In the shallow intervals, which are 100% owned and operated by the Company, discretionary capital expenditure plans over the next two years will be determined by the results of ongoing engineering and technical analysis. In fiscal year 2013, the Company intends to evaluate the potential of CO₂-EOR in the Charles Formation at Poplar by drilling a five-well pilot, including one CO₂ injector well and four producing wells. Magellan expects to incur up to $10.0 million in capital drilling costs on these wells. Timing of the drilling of these wells will depend on the permitting process and drilling rig availability. The four producing wells are designed to yield conventional oil production from the Charles Formation in addition to enhanced production as a result of the CO₂-EOR. As such, these four wells will constitute a portion of the wells to be drilled in the projections of our proved undeveloped reserves reported at June 30, 2012.

In the deeper intervals, which are operated by VAALCO and in which the Company has a 35% working interest, capital expenditures will be determined by the results of the three test wells that VAALCO is required to spud by the end of calendar year 2012, and for which VAALCO will bear 100% of the capital expenditures. If these test wells are deemed successful, the Company plans to fund its 35% share of the cost of the future drilling program in the deeper formations of Poplar.

At Palm Valley, the Company's interest in the field is governed by Petroleum Lease No. 3, which expires in November 2024 (and is subject to automatic renewal for another 21 years). The Company is not obligated to undertake significant mandatory capital expenditures in order to maintain its position in the lease. The Company's discretionary capital expenditure plans are primarily focused

17

on maintaining gas production from the existing facilities to meet the Santos Gas Contract demand while maintaining a safe and efficient operation, conducted in accordance with good oil field practice.

At Dingo, the Company's interest in the field is governed by Retention License No. 2, which expires in February 2014 (and is subject to renewal for a further 5 years). No mandatory capital expenditure is required until new gas sales contracts are secured. Dingo contains two suspended wells which are capable of production. The Company is currently evaluating a number of options for the future development of this field and is in the process of identifying potential new gas customers.

In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in the NT/P82 Exploration Permit. In October 2012, the Company executed a contract with Seabird Exploration FZ-LLC (the "Seabird Agreement") for the seismic recording vessel Voyager Explorer to undertake a seismic survey within its NT/P82 permit area. The estimated cost of shooting, processing, and analyzing the seismic survey is approximately $4.5 million.

In the United Kingdom, the Company'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" terms.

Contractual Obligations. As of September 30, 2012, the Company is committed to make future payments for seismic data survey services under the Seabird Agreement of approximately $4.5 million within a twelve month period. Please refer to the contractual obligations table in Part II, Item 7 of our Form 10-K for the fiscal year ended June 30, 2012, for information on all other material contractual obligations.

Sources of Funds

Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $37.9 million of cash and cash equivalents at September 30, 2012, compared to $41.2 million as of June 30, 2012.

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 $19.3 million as of September 30, 2012, with the remaining $18.6 million held in several Australian banks in time deposit accounts 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 September 30, 2012, $19.3 million of the Company's consolidated cash and cash equivalents, representing 51% of the total, were deposited in accounts held by MPAL. To the extent that the Company repatriates cash amounts from MPAL to the U.S., the Company will potentially be liable for incremental U.S. Federal and state income tax, which may be reduced by the U.S. Federal and state net operating loss and foreign tax credit carry forwards available to the Company at that time.

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

	September 30, 2012		June 30, 2012
	(In thousands)
Outstanding borrowings:
Term loan	$	738	$	870
Line of credit	100		50
Total	$	838	$	920

The Company, through its wholly owned subsidiary NP, maintains its only credit facility with Jonah Bank of Wyoming. As of September 30, 2012, the Company’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 the $1.0 million line of credit, $0.1 million was drawn, $25 thousand secured business credit cards used by NP, $25 thousand secured a line of credit in favor of the Bureau of Land Management, and $0.8 million remained available to borrow. As of September 30, 2012, 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 the Company up to $6.0 million but not to exceed the amount of the principal owed, which was $0.8 million as of September 30, 2012.

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 corporate credit facility, a reserve-based loan facility, a farm-out of a portion of the development program of some of the Company's assets, and an issuance of new shares to equity investors.

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Cash Flows

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

	September 30,
	2012			2011
	(In thousands)
Cash (used in) provided by:
Operating activities	$	(3,650	)	$	(2,027	)
Investing activities	(385		)	11,476
Financing activities	(82		)	(2,824		)
Effect of exchange rate changes on cash and cash equivalents	841			(1,319		)
Net decrease in cash and cash equivalents	$	(3,276	)	$	5,306

Cash used in operating activities during the three months ended September 30, 2012, was $3.7 million, compared to cash used of $2.0 million for the same period in 2011. The increase in cash used in operating activities primarily related to a decrease in revenues of $2.1 million over the same period and a $0.4 million decrease in exploration expense.

Cash used in investing activities during the three months ended September 30, 2012, was $0.4 million, compared to cash provided of $11.5 million for the same period in 2011. For the three months ended September 30, 2012, the cash used in investing activities consisted of expenditures on the development of our assets. For the same period in 2011, $5.0 million in proceeds was received from the VAALCO PSA and a $10.9 million deposit related to the Evans Shoal Asset Sales Deed was refunded both of which were offset by $0.8 million spent on the purchase of non-controlling interests in Poplar, and $1.2 million in expenditures on the development of our assets.

Cash used in financing activities during the three months ended September 30, 2012, was $0.1 million, compared to cash used of $2.8 million for the same period in 2011. The increase in cash provided by financing activities for the three months ended September 30, 2012, related to the Company's $3.4 million purchase of the non-controlling interest in Poplar in the prior year.

During the three months ended September 30, 2012, the effect of changes in foreign currency exchange rates positively impacted the translation of our AUD denominated cash and cash equivalent balances into USD and resulted in an increase of $0.8 million in cash and cash equivalents, compared to a decrease of $1.3 million for the same period in 2011.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATION

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) attributable to Magellan, plus (i) depletion, depreciation, amortization, and accretion expense, (ii) exploration expense, (iii) stock based compensation expense, (iv) foreign transaction loss (gain), (v) impairment expense, (vi) gain on sale of assets, (vii) net interest income, (viii) other income, (ix) income tax benefit (provision), and net income attributable to non-controlling interest in subsidiaries. Adjusted EBITDAX is not a measure of net income or cash flow as determined by accounting principles generally accepted in the United States ("GAAP"), and excludes certain items that we believe affect the comparability of operating results.

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

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

	THREE MONTHS ENDED
	September 30,
	2012			2011
	(In thousands)
Net (loss) income attributable to Magellan Petroleum Corporation	$	(5,310	)	$	940
Depletion, depreciation, amortization, and accretion expense	316			474
Exploration expense	622			987
Stock based compensation expense	346			396
Foreign transaction gain	(1		)	(562		)
Impairment expense	890			—
Gain on sale of assets	—			(4,108		)
Net interest income	(221		)	(271		)
Other income	(15		)	—
Income tax benefit (provision)	(336		)	198
Net income attributable to non-controlling interest in subsidiaries	—			(15		)
Adjusted EBITDAX	$	(3,709	)	$	(1,961	)

COMPARISON OF RESULTS BETWEEN THE THREE MONTHS ENDED SEPTEMBER 30, 2012, AND 2011

Oil and Gas Sales Volume

The following table presents oil and gas sales volumes for the three months ended:

	September 30,
	2012	2011	Difference		Percent change
Net sales by field:
Poplar (Mbbls)	18	15	3		20	%
Palm Valley gas (MMcf)	34	179	(145	)	(81	)%
Mereenie oil (Mbbls)	—	15	(15	)	(100	)%
Total Australia sales (Mboe)	6	45	(39	)	(87	)%
Net sales by product:
Oil (Mbbls)	18.44	29.97	(11.53	)	(38	)%
Gas (MMcf)	33.52	178.57	(145.05	)	(81	)%
Consolidated sales (Mboe)	24.03	59.73	(35.70	)	(60	)%
Consolidated sales (boepd)	261.20	649.24	(388.04	)	(60	)%

Sales volume for the three months ended September 30, 2012, totaled 24 Mboe (261 boepd), compared to 60 Mboe (649 boepd) sold in the prior year period, a decrease of 60%. Sales volume by product for the three months ended September 30, 2012, was 77% oil and 23% gas, compared to 50% oil and 50% gas in the prior year period. At Poplar, the increase in production was primarily the result of constrained production in the prior year period caused by the temporary suspension of one of Poplar's salt water disposal wells, which resulted in the temporary shut in of several producing wells; greater ownership in Poplar as a result of the Nautilus Restructuring in September 2011; a workover program instituted at Poplar in the summer of 2011; and sales from the EPU 117 well, which produces out of the Amsden Formation, a new pool discovery made in January 2012. Gas sales volumes at Palm Valley decreased due to the termination of the 25-year PWC Contract in January 2012. Gas volumes during this period were sold under a long term gas sales contract with Santos. To date, gas volumes sold under this arrangement have been significantly lower than under the PWC Contract, although volumes are expected to increase by fiscal year 2015 to levels similar to those realized under the PWC Contract. Following Magellan's divestiture in May 2012 of its interests in Mereenie under the terms of the Santos SA, the Company has ceased to report sales volumes from this asset.

20

Oil and Gas Prices

The following table presents the average realized oil and gas prices for the three months ended:

	September 30,
	2012	2011	Difference		Percent change
Average realized price:
Poplar (USD/bbl)	79.19	83.00	(3.81	)	(5	)%
Palm Valley (AUD/Mcf)	5.76	2.31	3.45		149	%
Mereenie oil (AUD/bbl)	—	112.63	(112.63	)	(100	)%
Consolidated (USD/boe)	69.11	62.53	6.58		11	%

The average realized price for the three months ended September 30, 2012, was $69/boe compared to $63/boe in the prior year period, an increase of 11%. 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 decreased by 5% as a result of decreased benchmark pricing (WTI). The average realized gas price from Palm Valley increased by 149%, which reflects higher prices realized under the current long term gas sales contract with Santos relative to the 25-year PWC Contract which terminated in January 2012.

Revenues

The following table presents revenues for the three months ended:

	September 30,
	2012		2011		Difference			Percent change
	(In thousands)
Consolidated net revenue by source (USD):
Poplar	$	1,460	$	1,225	$	235		19	%
Palm Valley	200		439		(239		)	(54	)%
Mereenie	—		2,071		(2,071		)	(100	)%
Total	$	1,660	$	3,735	$	(2,075	)	(56	)%
MPAL net revenue by source (AUD):
Palm Valley	$	193	$	448	$	(255	)	(57	)%
Mereenie	—		1,969		(1,969		)	(100	)%
Total	$	193	$	2,417	$	(2,224	)	(92	)%
Consolidated net revenues by type (USD):
Oil	$	1,460	$	3,296	$	(1,836	)	(56	)%
Gas	200		439		(239		)	(54	)%
Total	$	1,660	$	3,735	$	(2,075	)	(56	)%

Revenues for the three months ended September 30, 2012, totaled $1.7 million, compared to $3.7 million in the prior year period, a decrease of 56%. The $2.1 milliondecrease in revenue was primarily due to the sale of the Mereenie asset to Santos, offset by increased revenues at Poplar.

21

Operating and Other Expenses

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

	September 30,
	2012		2011		Difference			Percent change
	(In thousands)
Selected operating expenses (USD):
Lease operating	$	2,051	$	3,018	$	(967	)	(32	)%
Depletion, depreciation, amortization, and accretion	$	316	$	474	$	(158	)	(33	)%
Exploration	$	622	$	987	$	(365	)	(37	)%
General and administrative	$	3,663	$	2,512	$	1,151		46	%
Selected operating expenses (USD/boe):
Lease operating	$	85	$	50	$	35		70	%
Depletion, depreciation, amortization, and accretion	$	13	$	8	$	5		63	%
Exploration	$	26	$	16	$	10		63	%
General and administrative	$	153	$	42	$	111		264	%

Lease Operating Expenses. Lease operating expenses decreased$1.0 million to $2.1 million, or $85/boe, during the three months ended September 30, 2012. At Poplar, lease operating expenses increased by approximately $0.6 million due to increased workovers and maintenance activity compared to the same period in the prior year. A significant number of workovers are required to maintain production at Poplar as most of its producing wells were drilled in the 1950s and 1970s. In addition, Magellan incurred additional costs in the current period on production-enhancing technologies at Poplar, including water shut off and stimoil treatments. Evaluation of the effectiveness of these treatments is ongoing. At MPAL, lease operating expenses decreased by $1.5 million primarily because MPAL recorded no lease operating expenses related to the Mereenie oil and gas field, which it sold to Santos in May 2012 under the terms of the Santos SA.

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

	September 30,
	2012		2011		Difference			Percent change
	(In thousands)
Depreciation and Amortization	$	76	$	92	$	(16	)	(17	)%
Depletion	129		224		(95		)	(42	)%
ARO accretion	111		158		(47		)	(30	)%
Total	$	316	$	474	$	(158	)	(33	)%

Depletion, depreciation, amortization, and accretion expenses decreased$158 thousand to $316 thousand, or $13/boe, during the three months ended September 30, 2012. Accretion expense decreased as a result of the disposal of the Mereenie interests in the Santos SA which consequently reduced AROs. Disposal of oil and gas properties in the same transaction also resulted in decreased depletion expense compared to the prior year period.

Exploration Expenses. Exploration expenses decreased by $0.4 million to $0.6 million, or $26/boe, during the three months ended September 30, 2012. The $0.4 million decrease related to reduced general exploration costs in the UK. Minimal exploration costs were incurred in the three months ended September 30, 2012.

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

	September 30,
	2012			2011			Difference			Percent change
	(In thousands)
General and administrative (excluding stock-based compensation and foreign transaction (gain) loss)	$	3,318		$	2,678		$	640		24	%
Stock based compensation	346			396			(50		)	(13	)%
Foreign transaction gain	(1		)	(562		)	561			(100	)%
Total	$	3,663		$	2,512		$	1,151		46	%

22

General and administrative expenses increased $1.2 million to $3.7 million, or $153/boe, during the three months ended September 30, 2012. General and administrative expenses, excluding stock based compensation and foreign transaction losses and gains, increased by $0.6 million to $3.3 million, or $138/boe. This increase is due primarily to a $0.8 million accrual for severance costs payable to former officer and employee, offset by a decrease of $0.2 million spent on legal services, investor relations, and corporate fees and taxes. Following the completion of the Santos SA in May 2012, foreign transaction loss (gain) is expected to be minimal in the future.

OFF-BALANCE SHEET ARRANGEMENTS

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

CRITICAL ACCOUNTING POLICIES

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, 2012.

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 report, 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 expressed or implied 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: (i) whether the Company can successfully achieve cost savings while delivering revenue growth; (ii) 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 (iii) the production levels from the properties in which the Company, 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; (iv) operational risks in exploration, development, and production; (v) delays or changes in plans with respect to exploration or development projects or capital expenditures; (vi) risks associated with equipment procurement and equipment failure; (vii) whether seismic data will confirm the resource potential of the NT/P82 license; (viii) fluctuations in oil and gas prices; and (ix) access to capital markets and other uncertainties related to funding.

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, 2012. Any forward looking information provided in this report should be considered with these factors in mind. The Company assumes no obligation to update any forward looking statements contained in this report, whether as a result of new information, future events, or otherwise, except as required by securities laws.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company'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 U.S. dollar and the British pound, have changed in recent periods and may fluctuate substantially in the future. Any appreciation of the U.S. dollar against the Australian dollar is likely to 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 British pound. Accordingly, any material appreciation of the British pound against the Australian and U.S. dollars could have a negative impact on our business, operating results, and financial condition.

23

For the three months ended September 30, 2012, oil sales represented approximately 77% 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 $0.1 million. Gas sales, which represented approximately 23% 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 September 30, 2012.

At September 30, 2012, the value of our investments in securities available for sale was $0.1 million.

ITEM 4 CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2012, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

24

PART II - OTHER INFORMATION

ITEM 1 LEGAL PROCEEDINGS

There have been no material changes from the legal proceedings as previously disclosed in our Form 10-K for the fiscal year ended June 30, 2012, in response to Item 3 of Part I of such Form 10-K.

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 fiscal year ended June 30, 2012. 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.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ISSUER PURCHASES OF EQUITY SECURITIES

The table below provides information about purchases of the Company's common stock by the Company during the periods indicated.

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number or Dollar Value of Shares that May Yet be Purchased Under the Program (1)
July 1, 2012 - July 31, 2012	—	$	—	—	319,150
August 1, 2012 - August 31, 2012	—	$	—	—	319,150
September 1, 2012 - September 30, 2012	—	$	—	—	$	2,000,000
Total	—	$	—	—

⁽¹⁾ On December 8, 2000, the Company announced that its Board of Directors had approved a stock repurchase plan whereby the Company was authorized to purchase up to one million shares of its common stock in the open market. Through September 24, 2012, the Company had purchased 680,850 of its shares under this plan at an average price of $1.01 per share, or a total cost of approximately $0.7 million, all of which shares have been canceled. No shares were purchased by the Company under this plan during the three months ended September 30, 2012. On September 24, 2012, the Company announced that its Board of Directors had approved a stock repurchase program whereby the Company is authorized to repurchase up to a total of $2.0 million in shares of its common stock. This authorization supersedes the prior plan announced by the Company on December 8, 2000, and will expire on August 21, 2014. The shares may be repurchased from time to time in open market or privately negotiated transactions, subject to market conditions and other factors, including compliance with securities laws. Stock repurchases may be funded with existing cash balances or internal cash flow. The stock repurchase program may be suspended or discontinued at any time. Through September 30, 2012, no shares were repurchased by the Company under this program.

25

ITEM 6 EXHIBITS

3.1	Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware, as amended by an Amendment of Article Twelfth as filed on February 12, 1988 with the State of Delaware (filed as Exhibit 4.B. to the registrant's Registration Statement on Form S-8 filed on January 14, 1999 (Registration No. 333-70567) and incorporated herein by reference).
3.2	Certificate of Amendment of Restated Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware (filed as Exhibit 3(a) to the registrant's Quarterly Report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference).
3.3	Certificate of Amendment of Restated Certificate of Incorporation related to Articles Twelfth and Fourteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.3 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference).
3.4	Certificate of Amendment of Restated Certificate of Incorporation related to Article Thirteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.4 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference).
3.5	Certificate of Amendment of Restated Certificate of Incorporation related to Article Fourth as filed on December 10, 2010 with the State of Delaware (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on December 13, 2010 and incorporated herein by reference).
3.6	By-Laws, as amended on March 10, 2010 (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on March 15, 2010 and incorporated herein by reference).
10.1 *+	Employment Agreement dated August 28, 2012 between Magellan Petroleum Corporation and C. Mark Brannum.
10.2 *+	Nonqualified Stock Option Award and Subscription Agreement dated August 28, 2012, between Magellan Petroleum Corporation and C. Mark Brannum.
10.3 *+	Restricted Stock Award and Subscription Agreement dated August 28, 2012, between Magellan Petroleum Corporation and C. Mark Brannum.
10.4 *+	Indemnification Agreement dated September 5, 2012, between Magellan Petroleum Corporation and C. Mark Brannum.
10.5 *+	Indemnification Agreement dated November 30, 2011, between Magellan Petroleum Corporation and Milam Randolph Pharo.
10.6 *+	Letter Agreement dated September 7, 2012, between Magellan Petroleum Corporation and Nikolay V. Bogachev.
10.7 *	Agreement for 2-D and 3-D Data Acquisition Services dated October 26, 2012, between Magellan Petroleum (Offshore) PTY LTD and Seabird Exploration FZ LLC.
31.1 *	Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2 *	Certification of Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1 **	Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 **	Certification of Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS ***	XBRL Instance Document
101.SCH ***	XBRL Taxonomy Extension Schema Document
101.CAL ***	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF ***	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB ***	XBRL Taxonomy Extension Label Linkbase Document
101.PRE ***	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

*** Furnished herewith. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

+ Management contract or compensatory plan or arrangement.

26

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)
		By:	/s/ J. Thomas Wilson
			John Thomas Wilson, President and Chief Executive Officer
			(as Principal Executive Officer)
		By:	/s/ Antoine J. Lafargue
			Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer
			(as Principal Financial and Accounting Officer)
Date:	November 9, 2012

27

EX-10.7

ex107magellanseabird

DATED 26 October 2012 MAGELLAN PETROLEUM (OFFSHORE) PTY LTD AND SEABIRD EXPLORATION FZ-LLC AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES NT/P82 Bonaparte Basin, Timor Sea Offshore Northern Territory, Australia

REVISION HISTORY Rev. Date Description By Chkd App. Rev A 10th January 2012 First version FR Rev B 16 January 2012 Second draft MVC FR Rev C 8 October 2012 Third draft IDJ FR Rev D 13 October 2012 Fourth draft TT Rev E 16 October 2012 Fifth draft IDJ/MVC Rev F 26 October 2012 Sixth Draft - Final MB/MVC/TT FR MVC/MB/TT Prepared for Magellan by: Enquest Pty Ltd Tel. +61 418 681 314 Fax +61 428 681 314 Email F.Renton@enquest.com.au

-1- AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES THIS AGREEMENT is made the 26th day of October 2012 BETWEEN MAGELLAN PETROLEUM (OFFSHORE) PTY LTD (ABN 40 105 292 644) of Level1, 167 Eagle Street, Brisbane, Queensland 4000 (the "Company") of the one part; And SEABIRD EXPLORATION FZ-LLC (ABN 51 140 306 994) of Media City Shatha Tower, PO BOX 500549, Dubai, United Arab Emirates (the "Contractor") of the one part; WHEREAS A. The Company is engaged in the offshore exploration in Petroleum Exploration Permit NT/P82 in the Bonaparte Basin and wishes to engage the Contractor to perform the Services. B. The Contractor is engaged in the business of, and is ready, willing and able to carry out, the Services under this Agreement on the terms and conditions contained herein. NOW IT IS AGREED AS FOLLOWS:- This agreement and the following Annexures attached hereto (“Agreement”) contain the entire contract between the parties and supersede and replace any oral or written communications between them relating to the Services: Annexure A – Contract Summary Attachment 1 – Contractor Supplied Items Attachment 2 – Contractor Supplied Personnel Attachment 3 – Company Supplied Items Attachment 4 – Schedule of Rates Annexure B – Terms and Conditions for Data Acquisition Services Annexure C – Compliance with Statutory Regulations Annexure D – Acquisition Parameters and Quality Control Standards Annexure E – Operations Map and Coordinates Annexure F - HSE Requirements Unless otherwise stated, if there is any conflict between the abovementioned documents, the order of precedence shall be as listed. NOTES: The Safety Management Plan and the Environmental Management Plans are not included in this document. They will be in accord with the contract and legislative and regulatory requirements and will be developed jointly by the Contractor and Company to cover the Contract period.

-3- ANNEXURE A AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES SUMMARY 1 SERVICES Acquisition of approximately 135 line kilometres of 2D seismic data and 195 square kilometres (full fold) 3D seismic data in the Bonaparte Basin, offshore Northern Territory, Australia, at the locations as shown in Annexure E of this Agreement. The map and coordinates shown in Annexure E are subject to the final results of the migration aperture study. 2 TERM The Services shall commence on or about the 6 December 2012, but no later than the 14 December 2012, as agreed between the Company and the Contractor. The services shall terminate upon the earlier of the fulfilment of the Parties’ respective obligations unless otherwise terminated as provided in the Agreement. 3 MODE The Services shall be conducted 24 hours per day, 7 days per week, except as otherwise directed by the Company. Acquisition will be most efficient whilst the Survey vessel is able to maintain continuous production. 4 COMPLIANCE The Contractor shall: 4.1 Provide the equipment and personnel listed in Attachments 1 and 2 of Annexure A 4.2 Comply with the terms and conditions contained in Annexure B 4.3 Comply with statutory requirements as acknowledged in Annexure C 4.4 Comply with acquisition parameters and quality control standards in Annexure D 4.5 Comply with the Contractor’s Project Plan for the Data Acquisition and the relevant portions of the Contractor’s QHSE Management Systems 4.6 Comply with the Company’s Environment Plan for the Data Acquisition and the relevant portions of the Contractor’s QHSE Management Systems 5 REPORTS In addition to the reports referred to in Clause 3.3 of Annexure B and section 4 of Annexure D, the Contractor shall provide the following reports which shall be consistent with the requirements of Part 7 Division 3 Subdivision 3.3 the the Offshore Petroleum and Greenhouse Storage (Resource Management and Administration) Regulations 2011: 5.1 Daily, weekly and monthly progress report of the Services in the format as directed by the Company. 5.2 Final operations report including comprehensive description of equipment used, system malfunctions, calibration and test results and all pertinent geometric relations between echo sounder transponders, sea level, positioning antennae, seismic sources and spread. Tape channel identification, digital format information and the like, will be fully documented. Schematic

-4- source array and spread diagram, summary of sea and weather conditions and complete operational statistics will also be provided. 5.3 2 hard copies and 4 electronic copies of the final operations report on CDs, within 30 days of the completion of the Services in the Contractor’s standard format. 6 DATA DELIVERY The Contractor shall deliver the field tapes, observer’s reports and other pertinent field data to the Company's address for notices as provided in Clause 13 of Annexure A or such other destination as the Company may direct. 7 PRE-PLOTS At least 2 weeks before the commencement of the Services, the Contractor shall supply pre-plots of the program sail lines based on coordinates supplied by the company for the Survey programs. These pre- plots shall be provided digitally and in the form of maps and coordinate printouts, using the geodetic reference system and mapping projection specified in Annexure D. 8 NAVIGATION DATA The Contractor shall ensure that navigation data shall be recorded digitally. Post-plotted navigation data will be submitted within one month of completion of the survey on a magnetic tape in UKOOA/SPS format as defined in Annexure D. The post-plotted navigation data shall show the shot point location relative to antenna location, centre of the source array and the common mid-point between the source and nearest receiver, the centre of the receiver array to the receiver location and the location of each gravity and magnetic survey station. 9 CONTRACTOR’S BASE The Contractor's Base shall be Dubai. 10 CONTRACTOR'S ITEMS The Contractor shall provide at its sole cost and expense all Services and equipment, machinery, tools, spare parts, materials and supplies necessary to efficiently perform the Services, including, without limitation those items listed in Attachment 1 of Annexure A. Replenishment of the Contractor's Items shall be carried out by the Contractor at its expense and the Contractor shall be responsible for maintaining adequate stock levels. 11 CONTRACTOR'S PERSONNEL The Contractor shall provide at its sole cost and expense all personnel necessary to perform the Services including, without limitation to the foregoing, the personnel listed in Attachment 2 of Annexure A and as requested by the Company. Adequate provision will be made for rotational leave to ensure all positions are filled at all times with qualified and competent personnel for the duration of the Operations. Additional personnel, if required by the Company, will be provided at additional cost to the Company. All personnel are to be certified to be trained in sea survival and helicopter underwater evacuation to OPITO standard or equivalent. The Contractor must provide an HSE training matrix of the crew to Company at least 2 weeks prior to the start of Operations.

-5- 12 ITEMS TO BE FURNISHED BY THE COMPANY The Company will furnish and replace as necessary, at its expense, the equipment, machinery, tools, supplies, material and Services as specified in Attachment 3 of Annexure A. The Company shall not be required to furnish anything not listed therein, except as otherwise agreed in writing by the parties. 13 ADDRESSEES FOR NOTICES The Company: Magellan Petroleum (Offshore) Pty Ltd Level 1, 167 Eagle Street Brisbane, Qld 4000 Attention: Merv Cowie Title: Operations Director Facsimile: +61 (7) 3224 1699 Email: mcowie@magpet.com.au & magadmin@magpet.com.au The Contractor: Seabird Exploration FZ-LLC Media City Shatha Tower PO BOX 500549, Dubai, United Arab Emirates Attention: _Kjell Mangeroy Facsimile: +971 4429 0544 Title: Vice President Business Development Email: kjell.mangeroy@sbexp.com 14 DESIGNATED REPRESENTATIVES: The Company: Company shall appoint a Quality Control Supervisor as its Designated Representative pursuant to Clause 15.2 of Annexure B, and shall advise Contractor in writing of the name of the Company’s Designated Representative. Company may substitute its Designated Representative at any time, but will give written notice to the Contractor of any changes. Company shall, through its appointed Designated Representative, give such advice and information as it deems necessary for the best conduct of the Operations. All directions, instructions or requests given or made by the Company’s Designated Representative shall be deemed to be the directions, instructions or requests of Company. Company agrees that whatever operational problems may arise may be discussed by Contractor with the Company’s Designated Representative and any decision agreed to in writing by the Company’s Designated Representative shall be binding upon Company. The Company’s Designated Representative will have the right to stop Operations if the quality control standards set forth in this Agreement, including Annexure D and the Safety Management Plan are not met. The Company’s Designated Representative will have the right to suitably deviate or terminate planned Survey lines and to reduce quality control standards if deemed desirable operationally. It is acknowledged that the Company’s Designated Representative shall not have authority to agree to any amendment or variation of any terms or provisions of this Agreement or to waive any of the rights, duties or liabilities of the Parties and no action of the Company’s Designated Representative shall have such effect. The Contractor: Contractor shall appoint a Quality Control Supervisor as its Designated Representative pursuant to Clause 15.2 of Annexure B, and shall advise Company in writing of the name of the Contractor’s Designated Representative. Contractor may substitute its Designated Representative by written notice to Company. The Company will have final approval on all such substitutions.

-6- Contractor shall, through its appointed Designated Representative, give such advice and information, as it deems necessary for the best conduct of the Operations. All directions, instructions or requests given or made by the Contractor’s Designated Representative shall be deemed to be the directions, instructions or requests of Contractor. Contractor agrees that whatever operational problems may arise may be discussed by Company with the Company’s Designated Representative and any decision agreed to in writing by the Contractor’s Designated Representative shall be binding upon Contractor. The Contractor’s Designated Representative will have the responsibility to notify the Company if the quality control standards set forth in this Agreement, including Annexure D and the Safety Management Plan, are not met and shall advise the Company's Designated Representative immediately the quality of the data acquisition falls below the Quality Control Standards. 15 SPECIAL CONDITIONS 15.1 COMMENCEMENT TIME The Commencement Time shall be the time the Contractor achieves acceptable production on the first line following the mobilisation of all of the Contractor’s items and personnel to Operations Area and the Contractor is fully capable of performing the remainder of the Services, as confirmed in writing by the Company’s Quality Control Supervisor. Should the Contractor be in the Operations Area and unable to acquire data on the first line for conditions as defined under Standby Rate in Section 3 of Attachment 4, then this time shall be regarded as Standby Time. Following any such Standby Time if, in the opinion of the Company, the Contractor is not capable of performing the Services for reasons other than those defined as Standby Time or equipment problems directly attributable to Standby Time then the Standby Time shall be reduced by the length of the subsequent Downtime from the end of the Standby Time until commencement of the Services. The Contractor shall adhere to Part A. Standard Management Procedures of the EPBC Act Policy Statement 2.1 – Interaction between offshore seismic exploration and whales (September 2008) using the 2 km low power zone, which must be implemented during the seismic survey operations to minimise impacts to whales.

-7- ATTACHMENT 1 CONTRACTOR SUPPLIED ITEMS 1 RECORDING VESSEL M/V "Voyager Explorer" (Full details for the recording vessel be provided by Contractor) Vessel Name Voyager Explorer Flag State Panama Port of Registry Panama Call Sign 3FTG9 IMO Number 9319052 Classification Society ABS Classification ID No. 05152281 Owners Koleth (S) PTE LTD / 1504998 100% Operators Seabird Exploration FZ-LLC Where Built CHINA When Built 2005 Builders Name JIANGSUZHENJIANGSHIPYARDCO.,LTD. Originally Built As PSV Last Major Upgrade 2006 Overall Length (LOA) 67.8m Beam (Max) 16m Draft (Max) 4.65m GRT (National/International) 2943 tons GRT Canals (Panama/ Suez) - NRT (National/International) 883 Tons NRT Canals (Panama/ Suez) - Lightship Displacement 2331.4 Bollard Pull Capacity at 5 kts. 28 Tones Main Engines 2 x Caterpillar 3516B, total 4200 hp Number of Propellers & Blades 2 x 4-blade, variable pitch,2.60-m props,Kort nozzles Thrusters Bow 1 x Cummins 815 BHP @ 1800 RPM Stern N/A Azimuth N/A Main Generator 3 x 350 kW, 415v-3-50hz Aux Generator Emergency 1 x 78 KW, 415-3-50 Clean Power (UPS/GMDSS) 60Kva UPS Seismic Incinerator (Garbage) 1 X Incinerator, 1 X Compactor Capacities Main Engine Lube Oil 14 m3

-8- Cable Oil (Clean/Separated/Dirty) 22m3 Fuel Total/Useful 800.0 m3 Bunkering Connections (Type/Locations) Inline and either side at sea bunker capacity Fuel Consumption During Transit 10.0 cub.m per day @ 10 kts, Whilst Surveying 13 cub.m @ on seismic Cruising Speed 10 knots Cruising Range 19,000 nautical miles Survey Endurance with Tendered Trailing Equipment 5 Weeks without resupply Potable Water Capacity 157.0 cubic meters Maker Production 13.0 m3/day Reverse Osmosis Desalination System Radars 1 X Furuno FAR-2137s, 1 X Furuno FAR-2127 Inmarsat Fleet 77 VSAT GIS/MTM 320Kbs C-Band Bridge Radios GMDSS station Furuno RC1800-IT-E, areas A1, A2, A3 (VHF, MF, HF, Inmarsat C). UHF 8 – ICON UHF Seismic VHF 1 x Sailor TT-3064A Maritime Telephone 8 x portable VHF, 1 x Sailor RT-2048 VHF MF/HF GMDSS station Furuno RC1800-IT-E, areas A1, A2, A3 (VHF, MF, HF, Inmarsat C). Aircraft Airband VHF Helicopter Beacon NDB, Call Sign EXYZ, Frequency 300MHz Ship’s Navigation 2 x Furuno X and S band Gyro Compass 1 X Anshutz STD-20 STD-22 (Vessel) Autopilot Robertson AP9MkIII & Robtrack STS500 Raytheon NP60 Fathometer Furuno FE - 700 (bridge), Simrad EA400 (Seismic) GPS Receiver 1 x Furuno GP-90, 1 x Furuno GP-80 Speed Log Furuno DS-80 Weather Facsimile Via GMDSS Station Navtex Receiver 1 x Furuno NX-500 / Furuno AIS FA-100 ECDIS (Electronic Charting Display) 1 x Furuno Radio Direction Finder No, only non-directional beacon for aircraft Emergency Communication GMDSS station Furuno RC1800-IT-E, areas A1, A2, A3 (VHF, MF, HF, Inmarsat C). Total Berths 48 Conference/Training Rm. HeliDeck Waiting Room Air Draft (Max Antenna) 22m Helideck NDB, Call Sign EXYZ, Frequency 300MHz; Kongsberg Helideck Monitor System (HMS 100) Diameter D value = 20 Rating t = 9.3 Deck Markings Standard CAP437

-9- Lifeboats N/A Lifeboat Radios 6x MDSS VHF, 2 x JOTRON SART Liferafts 4 x Viking 25DK+ (4 x 25 pers), 1x6 pers Viking 6DK Lifejackets 108 pcs lifejackets Survival Suits, thermo-insulated (Number, Manufacturer, Type) Lalizas, HYF - 54 pcs Working Suits, thermo-insulated (Number, Manufacturer, Type) Crewsaver – 8 pcs; Secumar – 10 pcs MOB 1x6 pers Viking 6DK Fire Detection & Alarm Systems MINERVA T1016 Fire Main System Fixed CO2, Water spray systems, Fire main, Portable foam extinguishers, Foam Over Seismic Reels Fire Pumps (Number, Location, Type, Capacity) 2 x 65 m3/hour, 1 x 35 m3/hour Foam Fire Boxes Fire Monitors (Number, Location) Two, Helipad Fire Fighting Equipment As per SOLAS + helideck Fixed HiFog and CO2 for engine spaces, Foam for seismic reels, Foam helideck Portable 4x SETS + 16x CYLYNDERS IOPP Equipment Approved SOPEP plan and equipment as per SOLAS Sludge & Waste Oil Incinerator 1 x Atlas T50SL Bilge/Oily Water Separator RWO SKIT10 Oily Water/Sludge Holding Tank Capacities 22m3 Oil Spill Absorbent & Damage Control 1 x Main SOPEP station + smaller kits around the vessel. Sewage Treatment Plant Hamworthy RT40 Deck Cranes & Freight Elevators Cranes (Type, Location/Capacity) 2 x PLIMSOL 7ton located top deck centre Freight Elevators N/A Certificates, Categories & Compliances ABS Classification Machinery System YES Class Approved Maintenance System TM Master v.2 (TEROMARINE) International Safety Management (ISM) Code Compliance YES Safety Equipment Certificate YES Communication Equipment Class YES Official Number 3FTG9 Safe Manning Certificate YES Contact Information Inmarsat 435348112@inmc.eik.com Telephone No. Captain: +47 5164 5675 PC: +47 5164 5677 Telex No. 435348112

-10- Fax No. +870 765 090 017 (Fleet 77) Norsat-Sea Link As per above Telephone/Fax No. E-mail Addresses for Vessel mastervoyager@sbexp.com pcvoyager@sbexp.com 2 SUPPORT/CHASE VESSEL (Full details for the support vessel to be provided by Contractor) Vessel Name First Class Flag State Australia Builder Geraldton Boat Builders Date 1995 Classification – M&H 4189 Classification - USL 2B 12 + 6 (max) Length overall 23.6 m Beam 5.5 m Design draft 1.8 m Main engines X CAT c18 740 kw at 2,1000 RPM propulsoipn Twin Screw Generator X Isuzu 30 kVa Full operating speed 25 knots @ 300 L/hr Cruising speed 20 knots @ 250 L/hr In poer consumption 100 L/day Cargo approx. 10 Tonne Clear deck Approx 50 sq m Fuel 16,000 L Water 1,000 L & Desal @ 2,000 L/day Sewerage 1,000 L Hull Aluminium Monohull, Fendering on sides transom 5.5 m open Radio Marine VHF & HF Radar Furuno Echo sounder Furuno Plotter Maxesa GPS 2 x Furuno Auto pilot Saura AIS Furuno FA-50 Accommodation Galley, fully air-conditioned, shower & toilet Berths 7 Miscellaneous equipment Medivac stretched, moon pool

-11- 3 TRANSPORT 3.1 The cost of all air transport of Contractor’s personnel, equipment, spares, replacement parts and supplies, between completion of mobilisation and start of demobilisation, unless otherwise provided by Company. 3.2 The cost of any sea transportation of Contractor’s personnel, equipment, spares, replacement parts and supplies, between completion of mobilisation and start of demobilisation, unless otherwise provided by Company. 4 MISCELLANEOUS 4.1 Maintenance, spares, replacement parts and supplies to operate Contractor supplied items. 4.2 Any permits, licences, visas and like authorisations for the Contractor to carry on business and its personnel to work in Australia. 4.3 All Personnel Protective Equipment including life vests and any other requirements such as sun hats, sunscreen, wetsuit boots, Polaroid sunglasses etc.

-12- ATTACHMENT 2 CONTRACTOR SUPPLIED PERSONNEL (Full details for the all crew members to be provided by Contractor) MARINE CREW (Seismic Vessel) - NAME/NATIONALITY CREW 1 & NAME/NATIONALITY CREW 2   MARINE CREW (Seismic Vessel) NAME/NATIONALITY CREW 1 NAME/NATIONALITY CREW 2 Master Maksym Skrypny-Ukraine Valerii Khytry- Ukraine Chief Mate Oleksandr Pipchenko-Ukraine Sergii Koshterek-Ukraine Second Mate Andriy Savchuk-Ukraine Anatoly Adamovsky-Ukraine Chief Engineer Oleksandr Chubko-Ukraine Oleksandr Chernenko-Ukraine First Engineer not part of crew model not part of crew model Second Engineer Volodymyr Mishchenko-Ukraine Sergiy Yablonsky-Ukraine Integrated Rating Eladio Ayson-Filipino Roman Strypa-Ukraine Integrated Rating Reynaldo Conje-Filipino Cermino Constantino-Filipino Integrated Rating Ievgenii Grigoryev-Ukraine Roman Podkhalyuzin -Ukraine Integrated Rating Mykhaliv Mykola-Ukraine Ievgen Skrypnyk-Ukraine Chief Cook Luis Medina-Filipino Dennis Arshykov-Ukraine Second Cook Edgardo Ayson-Filipino Oleg Tymoshchuk-Ukraine Chief Steward Alberto Arguilles-Filipino Iulia Parfenova-Ukraine Second Steward not part of crew model not part of crew model SEISMIC CREW Party Manager Kenneth Davies-British Martin Kenny-British Assistant Party Manager not part of crew model not part of crew model Chief Observer Igor Zhigalov-Russian Michael Povey-British Shift Leader Observer Iurii Tishkov-Russian Aleksei Zhigalov-Russian Shift Leader Observer Vicente Miranda-Filipino Ilia Gai-Russian Observer Raqi Rosla-Malaysian Peter Benedistkiy-Russian Observer Rhuari Coe-British Diosdado Primor-Filipino Chief Gun Mechanic Sergey Grigoryev-Russian Mikhail Kokhovich-Russian Shift leader Gun Mechanic Bradley Perry-British Alexey Popov--Russian Gun Mechanic Alex Fityushchenko-Russian Petar Kolev-Bulgarian Gun Mechanic Robert Henzell-British Valery Pozdnukhov-Russian Compressor Mechanic Dmytro Yurkevych-Ukraine Kostyantyn Goncharuk-Ukraine Compressor Mechanic none none Chief Navigator Vitaly Proskura-Ukraine Yury Avdeev-Russian Navigator Aleksei Kazakov-Russian Michael Laletin Navigation QC Pascal Guillou-French Igor Kuraev Technician/Safety Officer Colin Finnigan-American Mykhailo Shypkov Geophysicist/ QC Supervisor Nikolay Blokhin-Russian Chong Wee Chen-Malaysian Geophysicist Alexander Tatsyuk-Russian Ivan Lukianov-Russian

-13-   MARINE CREW (Support Vessel) – TBA by Contractor Master _________________________ _________________________ Chief Mate _________________________ _________________________ Second Mate _________________________ _________________________ Chief Engineer _________________________ _________________________ First Engineer _________________________ _________________________ Integrated Rating _________________________ _________________________ Integrated Rating _________________________ _________________________ Integrated Rating _________________________ _________________________ Chief Cook _________________________ _________________________ ONSHORE PERSONNEL Vessel Supervisor/Administrator _________________________

-14- ATTACHMENT 3 COMPANY SUPPLIED ITEMS 1 OPERATIONS APPROVALS All governmental approvals and permits necessary for the performance of the Services within the Operations Area, but excluding those referred to in clause 1 of Attachment 4 to Annexure A. 2 PROGRAM DATA 2.1 A complete description of the Surveys. 2.2 Maps at a suitable scale. 2.3 Coordinates for 2D survey lines and 3D survey boundaries referenced to the datum to be used for surveys. 3 ADDITIONAL SUPPORT VESSELS AND PERSONNEL Any supplementary vessels and personnel required to perform any safety and environmental functions specifically required in the Operations Area.

-15- ATTACHMENT 4 SCHEDULE OF RATES 1 MOBILISATION/DEMOBILISATION The mobilisation fee shall be invoiced at the Commencement Time. The demobilisation fee shall be invoiced at the Termination Time. Mobilisation Fee US$600,000 Demobilisation Fee US$$300,000 These rates shall include provision of all Contractor’s Items and Personnel and Services. This includes the following items at no additional cost to Company: All costs associated with mobilisation and demobilisation of the Contractor supplied items and personnel including all agencies fees, customs duties or fees and permit fees associated with their entry to and departure from the Operations Area. All time involved in required pre-Survey calibrations of any nature. All costs including vessel time associated with port clearance (in and out), including agencies fees, Labour fee or any other expense incident to obtaining harbour clearance. The mobilisation and demobilisation fees are based on this project being awarded as a standalone project. - 2 DATA ACQUISITION RATES The following rates describe the remuneration that will be paid to the Contractor for conducting the Services over the Term. These rates shall include all Contractor’s Items and Personnel and Services. This includes all of the following items at no additional cost to Company: (a) The cost of all seismic supplies, all field tapes used to record seismic and navigation data, all printer paper, echo sounder and seismic sections. Such supplies shall be warranted to be new, first class and free from defect. (b) All costs, other than those incurred during allowed equipment down time, which may be sustained due to failure of any navigation system signals, or recording or other equipment, or if anything falls below minimum quality control standards. (c) All costs of post processed navigation tapes in UKOOA/SPS format in the working datum. (d) All reporting costs (e) All costs associated with Contractor’s survey vessel, and one support/chase vessel if required to conduct the Operations, including mobilisation/demobilisation, rental, manning, fuel, provisions, water, waste management, crew changes, spares replacement and resupply, unless provided by Company.

-16- 2.1 3D Prime Acquisition Rates Rates will apply for all data acquisition work where the Contractor meets all Quality Control Standards agreed for the Work with the recording parameters defined. The hourly rate will apply to all times when the vessel is recording seismic data on line or is on line change. Data acquisition conducted east - west US$8,431 per Full Fold Square Kilometre or US$ 7,285 per hour up to a maximum daily charge of US$174,735 per day Using 4 streamers at a separation of 100 metres The rates will not include: • Standby time as defined below, when the standby rate will apply • Downtime, when no charges will apply 2.2 3D Infill Acquisition Rates Rates will apply for all infill data acquisition work where the Contractor meets all Quality Control Standards agreed for the Work. The hourly rate will apply to all times when the vessel is recording infill seismic data on line or is on line change Data acquisition conducted east - west US$ 8,875 per Full Fold Square Kilometre or US$7,285per hour up to a maximum daily charge of US$174,735 per day Using 4 streamers at a separation of 100 metres The rates will not include: • Standby time as defined below, when the standby rate will apply • Downtime, when no charges will apply

-17- 2.3 2D Prime Acquisition Rates Rates will apply for all data acquisition work where the Contractor meets all Quality Control Standards agreed for the Work with the recording parameters defined. The hourly rate will apply to all times when the vessel is recording seismic data on line or is on line change. US$ 1,016.66 per full fold Kilometre or US$6,595 per hour up to a maximum daily charge of US$ 158,100 per day The rates will not include: • Standby time as defined below, when the standby rate will apply • Downtime, when no charges will apply 3 STANDBY RATE Standby Rate will apply in the following circumstances: a) During time lost due to weather conditions, sea conditions or atmospheric disturbances, always provided that this is the only reason that acquisition cannot continue. Standby rate will also apply if environmental conditions prevent the repair of trailing equipment. b) During time lost due to waiting on tides or currents and their effect on streamer feather, provided such waiting is at the specific request of Company’s Designated Representative, who may decide what streamer feather is acceptable. c) During time lost due to third party interference in the Operations Area, such as fishing, drilling, shipping, military, seismic or similar activities, over which Contractor has no direct control, inclusive of interruptions due to interference from other vessels at sea, which may be in the form of unacceptable streamer coherent noise levels and/or obstructions. d) During time lost due to fishing vessels, nets, traps, buoys or lines obstructing the vessel or fouling or damaging the trailing equipment or any other object or living creature fouling or damaging the trailing equipment. e) During time lost while waiting on suitable environmental conditions of any kind in order to allow Operations in shallow, or otherwise dangerous, areas. f) During time spent scouting hazardous areas for obstructions and/or adequate water depths, with the approval of Company Designated Representative. h) During time lost due to the failure of Company to provide personnel, instructions, program details, permits or services for which it is responsible. i) During time lost due to restrictions imposed by Australian Governmental or military agencies, provided Contractor has not caused the restrictions to be imposed. e) During time spent changing from one streamer or source configuration to another, if requested by Company. f) During time spent recovering and deploying trailing equipment which is directly associated with moving from one Operations Area to another. k) During time spent conducting any experimental work, trials, repeat calibrations or non- geophysical operations at Company’s request, or time spent moving the vessel at Company’s request for data drops, personnel or equipment changes not scheduled by Contractor. l) During time lost due to streamer damage or loss and resulting streamer repair, search and re- ballasting time caused by collision with fixed subsurface obstructions, unless the locations of such obstructions are notified to Contractor by Company in writing before the incident. Company’s responsibility for payment is limited to payment for time involved. Payment of such time charges does not infer or imply any Company liability for damage to Contractor’s equipment, which will at all times be the sole responsibility of the Contractor.

-18- m) During time lost as a result of the presence of cetaceans in the Operations Area, causing cessation of acquisition in accordance with the Environmental Assessment and Management Plan. n) When the vessel is in the Operations area, ready to deploy trailing equipment, but cannot do so because of weather conditions. o) While standing by for reasons of Force Majeure or any suspension of Services at Company convenience. p) During time lost due to absence of usable GPS navigation signals, attributable to reason other than Contractor or their Subcontractors equipment breakdown, malfunction or operator error. q) Time during which acquisition is interrupted due to growth of marine life on the streamers (e.g., barnacle growth), inclusive of time cleaning the streamers, provided that the Contractor, shall ensure on-going streamer cleaning whenever possible during non-productive time. The Contractor shall ensure the streamers are clean of marine growth on the Commencement Date. US$6,255per hour up to a maximum daily charge of US$150,100 per day Any time not specifically described under the above circumstances will be to the Contractor’s account. However if Contractor downtime occurs just before a Standby Time situation, Standby Rate shall apply from the time when the Contractor has demonstrated that the Contractor’s seismic vessel and equipment meets specification required under this Agreement or is fully functioning. 4 EXTRA ITEMS Data transmission charges associated with QC or QA processing will be included in the costs for those items and will not be chargeable as a separate item. 5 SUPPORT/CHASE VESSEL(S) One support/chase vessel is included in the acquisition rates (capped at US$12,000/day). In the event that additional vessels are required these will be supplied on a reimbursable basis. 6 REIMBURSABLE ITEMS Additional goods, vessels or third party services provided by Contractor pursuant to this Agreement shall be acquired only with the prior written approval of the Company. Subject to the provisions of item 3 of Attachment 3, the Contractor shall be paid at cost (plus 10% administration fee) by Company for providing the additional goods (including fuel for the additional Vessel and support/chase vessel) or third party services. 7. EARLIER TERMINATION If the work is terminated after signing the contract and less than 20 days before the commencement, the Company shall pay the Contractor the quoted Mob/Demob fees and 25% of the costs of the scheduled work not performed.

-19- ANNEXURE B AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES TERMS AND CONDITIONS 1. INTERPRETATION 1.1 Definitions In this Agreement the following terms shall have the meaning set out in this Clause unless the context otherwise implies or requires: "Agreement" means this document including any annexures, attachments and schedules to it. "Commencement Time" means the time when Contractor records the first acceptable shotpoint of data. "Contractor's Items" means all items to be furnished by the Contractor pursuant to Clause 5.1 including those listed in Annexure A; "Designated Representative(s)" means the person(s) designated pursuant to Clause 15.2; "US$” means United States dollars; "Downtime" has the meaning ascribed in Clause 7.2.2; "Force Majeure" has the meaning ascribed in Clause 13.1; “Normal Termination” means the time specified in clause 2.3; "Parties" means the Company and the Contractor; "Services" means all or any of the Services referred to in Clause 1 and Annexure A; "Standby Time" means time during which the Standby Rate is payable; "Term" means the period from the Commencement Time and continuing until Normal Termination or earlier termination as provided herein; "Operations Area" means at or near to the area at which the Services are to be performed; "Operations" means the seismic data acquisition on the survey or surveys of the Company utilising the Services; "Vessel" means any vessel used by the Contractor in conjunction with the Services. 1.2 References Unless the context otherwise requires: References to Annexures or Attachments are references to Annexures and Attachments of this Agreement; references to a Clause by a number or a letter and a number are to clauses of that number in that part of the Agreement in which the reference is made unless otherwise stated; and plural includes the singular and vice versa. 1.3 Governing Law All questions arising out of this Agreement or its validity, interpretations, performance or breach shall be governed by the laws of the State of Queensland (as agreed by both parties) and the parties agree to submit to the jurisdiction of the Courts of that State and Courts having jurisdiction to hear appeals from Courts of that State. 1.4 Effect of Captions The captions appearing in this Agreement are for convenience only, and are not to be used to interpret the contents of their clauses. 1.5 Effect of Prior Agreements This Agreement contains the entire agreement between the parties with respect to the subject matter herein and no prior stipulation, agreement or understanding by the parties or any of their representatives shall be of any effect.

-20- 1.6 Variations If during the continuance of the Agreement the Company or the Contractor wishes to vary any provision in the Agreement by addition or deletion, each party shall meet with a view to agreeing upon such variation but such variation shall not be effective until it is recorded in writing and signed by both the Company and the Contractor. 1.7 Effect of Waiver of Performance The waiver of, or failure to, require the performance of any covenant or obligation contained herein shall not be deemed to constitute a waiver of a similar later breach. 1.8 Statutes Reference to any statute herein shall include a reference to that statute as amended, modified or replaced and includes orders, ordinances, regulations and rules and by-laws made under or pursuant thereto. 1.9 Severance Each of the terms and conditions of the Agreement shall be deemed to be separate and several from the other of them and if any one or more thereof are determined to be invalid or unenforceable by any Court of competent jurisdiction, such determination and the consequential severance (if any) shall not invalidate the rest of the Agreement which shall remain in full force and effect as if such term and conditions had not been made a part thereof. 1.10 Costs of Obligation Unless otherwise provided for in this Contract, where in this Contract any obligation is imposed upon or undertaken by any party the costs of complying with that obligation shall be the responsibility of the party assuming or undertaking the obligation. 2. TERM OF THE AGREEMENT 2.1 Duration and Commencement Time This Agreement shall apply to all Services performed by the Contractor for the Company during the Term commencing on the date and continuing for a period so specified in Annexure A. The Company shall give the Contractor notice to commence the Services and upon receipt of the notice from the Company, the Contractor shall do all things necessary to commence the Services by the date specified in the notice from the Company. 2.2 Duration of the Services The Contractor shall complete the Services as described in the Operations with all due diligence. 2.3 Normal Termination Time The Normal Termination Time shall be the time when the last receiver group is recovered and when the Operations are completed to the satisfaction of the Company, and the crew is ready to demobilise or to depart the work area or to commence work for another client. 2.4 Early Termination Without prejudice to any other rights at law, this Agreement may be terminated prior to the Normal Termination Time as follows:- 2.4.1 By the Company (without penalty to the Company): (a) Immediately, in the event of failure by the Contractor to commence the Services as directed by the Company as provided in Clause 2.1;

-21- (b) If the Contractor makes default in the performance or observance of any obligation, term, condition or stipulation contained in this Agreement which the Contractor is required to perform or observe, the Company may in addition to any other rights or remedies it has at law, give the Contractor notice specifying the default and requiring the Contractor to remedy the same at the Contractor's expense. If within 3 days after such notice is given, the Contractor fails in the opinion of the Company to so remedy or provide adequate assurance that the default will be rectified and the Services satisfactorily completed, then the Company may at any time thereafter by notice take the Services remaining to be performed out of the hands of the Contractor or terminate this Agreement; (c) At any time after the commencement time, provided that the Company gives not less than 5 days written notice to the Contractor; (d) For reasons of Force Majeure pursuant to Clause 13.4; or (e) Immediately in the event that a Receiver or Manager is appointed to manage or control the affairs or assets of the Contractor under any security or pursuant to any applicable law or if the Contractor goes into liquidation or if proceedings are commenced for any of those purposes. 2.4.2 By the Contractor if the Company defaults in the payment of the Contractor's invoice by more than 30 day and for reasons of Force Majeure pursuant to clause 13.4. 2.5 Consequences of Termination In the event of termination pursuant to Clause 2.4.1: 2.5.1 The Contractor shall, on receipt of the notice of termination: (a) perform only the Services specified in the notice; (b) comply in all respects with any directions contained in the notice; and (c) immediately give to the Company all deliverables (whether or not they are completed) relating to the part of the Services to which the termination applies and for which Contractor has received full payment from Company. 2.5.2 The Company's sole liability arising from the termination shall be to pay to the Contractor such sums as may be due and owing to the Contractor on the date of termination for Services performed up to the effective date of termination. 2.5.3 No action taken by the Company under Clauses 2.4 or 2.5 shall operate to the prejudice of the rights, remedies, powers, authorities and discretions of the Company and accrued liabilities and obligations of the Contractor (all of which shall continue in full force and effect as if there had been no such termination) nor, without limiting the generality of the foregoing, shall such action operate to the prejudice of the rights of the Company to recover from the Contractor all moneys whatsoever from time to time due and payable to the Company by the Contractor whether under or in relation to this Agreement or otherwise howsoever. 3. SERVICES 3.1 General The Contractor shall perform the Services as described in Annexure A at the Company's direction at the Operations Area using the Contractor's Items. 3.2 Manner of Performing the Services 3.2.1 Standards of Performance (a) The Contractor represents that it has the technical competence, financial capacity, management skills, competent and qualified personnel and equipment necessary to perform the Services.

-22- (b) The Contractor shall conduct all Services hereunder in a prompt, diligent, skilful and workmanlike manner, in accordance with: (i) good maritime and oil field practice and sound engineering principles; (ii) any specifications and other documents as the Company shall furnish to the Contractor to detail the Services to be performed; (iii) the standards prescribed by law or by Regulatory Authorities having the lawful right to prescribe minimum standards; and (iv) Society of Exploration Geophysicists Recommended Practices applicable to the Contractor's Items and the Services. (c) The Contractor shall be deemed to have knowledge of the Operations Area and all matters relating to the conduct of the work in the Operations Area and accordingly the Contractor shall have no claim for extra remuneration nor shall it be relieved of its obligations hereunder as a consequence of any actual lack of knowledge as to the nature of the Operations Area, local facilities or climatic conditions. 3.2.2 Independent Contractor All of the Services are those of an independent Contractor, and it is not, and none of its personnel, subcontractors or agents are an employee, subcontractor or agent of the Company. Use of subcontractors by the Contractor shall not relieve the Contractor from any liability or obligation under this Agreement. The Company may instruct and direct the Contractor as to the results to be achieved by the Contractor, but the Contractor as an independent Contractor shall have the sole and complete control, supervision and direction over the Contractor's Items and its personnel and over all the Services and the method and manner of achieving such results. The presence of, and supervision of the Services by the Company's Designated Representative at the Operations Area shall not relieve the Contractor of its obligations hereunder. It shall be the sole and exclusive responsibility of the Contractor to determine, at all times, whether Services can be safely undertaken or continued including, without limitation, that the Contractor's Items are in all respects suitable to undertake any contemplated Services under the then existing conditions. 3.2.3 Safe Practices The Contractor shall: (a) take all measures reasonably necessary or proper to provide safe working conditions; (b) give notice to all persons engaged in the Services of all safety regulations and standards including, without limitation, those referred to in Annexure C and the Safety Management Plan, and emergency procedures to be complied with by them; (c) ensure that all personnel are fully informed of all such regulations and comply with same; (d) ensure that its personnel participate in periodical safety drills conducted by the Contractor; (e) maintain guards and other safety devices to lessen hazards during the performance of the Services. 3.2.4 Abnormal and Hazardous Conditions If at any time while operating the Contractor believes that continuance of the Services will result in unsafe conditions it shall immediately notify the Company and in the meantime exert best efforts to overcome the difficulty. In any such case the Contractor shall be entitled to stop the Services under the safest possible conditions and consult with the Company. The Contractor shall, at the request of the Company’s Designated Representative, provide written reasons why the Contractor cannot continue to perform the Operations.

-23- 3.2.5 Compliance with Laws In addition to any other requirement in this Agreement the Contractor agrees to comply with and use all reasonable efforts to ensure that its personnel, subcontractors and agents comply with all laws and regulations pertaining to the Services including, but without limitation, the legislation and direction referred to in Annexure C. Where any further directions are given to the Company, the Company will give copies thereof to the Contractor. The Contractor further agrees not to do or omit to do anything which could thereby result in the Company being in breach of any such laws, regulations or directions and in particular, but without limitation, the Contractor shall ensure that it complies with the matters listed in Annexure C. 3.2.6 Environmental Protection The Contractor shall minimise damage to property and the environment and shall comply with Environmental procedures listed in the Environment Plan. 3.3 Reports 3.3.1 Accurate Logs and Records The Contractor shall keep a complete and accurate history and a log of all Services performed on forms approved by the Company, which shall be open at all reasonable times to inspection by the Company and its Designated Representative. The daily reports on which invoicing is based shall be agreed to and signed each day by the Company’s Designated Representative before they are accepted. 3.3.2 Contractor to Furnish Reports The Contractor shall furnish the Company's Designated Representative with the following written legible and accurate reports in the form specified or as approved by the Company: (a) report of the Services performed as specified in Annexure A; (b) reports on personnel and equipment movements, safety inspections, equipment maintenance and equipment failure as requested by the Company; (c) accident and incident reports as soon as practicable, and in reasonable detail, after occurrence resulting in injuries to the Contractor's personnel or third parties, or damage to property, arising out of or during the course of Services and thereafter to review the cause(s) of the occurrence and put in place appropriate procedures to prevent recurrence; and (d) such other reports reasonably required by the Operator. The Contractor shall immediately report verbally hazards or hazardous incidents, which could lead to an accident if left unattended. 3.4 Company to Inspect Services The Contractor shall at all times permit the Company's Designated Representative to inspect all Services performed and all Contractor's Items supplied hereunder and to witness and check all measurements and tests made in connection with the Services and to have access to the Contractor's Items and to observe all the Services at Company's sole risk.

-24- 4. COMPANY-FURNISHED ITEMS 4.1 Company's General Obligation 4.1.1 The Company will furnish and replace as necessary the equipment, machinery, tools, supplies, material and Services listed in Annexure A. The Company shall not be required to furnish anything not listed therein, except as otherwise agreed by the parties. 4.1.2 The Designated Representatives of the Company and the Contractor shall, so far as applicable to the Services, jointly take a written inventory of all material, supplies and Contractor's Items in connection with the Services, if any, as of Commencement Time and Normal Termination Time or earlier termination time as the case may be. 5. CONTRACTOR'S ITEMS 5.1 Equipment, Services, Supplies Except for those items specifically provided in Clause 4.1 to be furnished by the Company, the Contractor shall provide all Services and equipment, machinery, tools, spare parts, materials and supplies that may be necessary or reasonably required for full performance of the Services by the Contractor under this Agreement, including but without limitation the Contractor's Items listed in Annexure A. The Contractor shall maintain adequate stock levels of spares necessary to efficiently perform the Services at the Operations Area and at the Contractor's Base. 5.2 Maintenance and Compliance The Contractor must maintain the Contractor's Items during the term of this Agreement in first-class operating condition and the Contractor must make any necessary replacements or repairs promptly in order so to do. To attain this objective the Contractor shall use airfreight or air charter Services, or both, when and if necessary. Without prejudice to this obligation, the Company shall endeavour to avail the Contractor of the transport Services utilised by the Company provided that the Contractor, at the discretion of the Company, shall reimburse the Company for the costs of transport provided by the Company. 5.3 Warranty of Suitability The Contractor warrants that the Contractor's Items, subject to their respective design limitations, will operate efficiently in the conditions encountered in the Operations Area. In the event this warranty should be breached, the Contractor shall replace the same with suitable Items. Where such Contractor’s Items persistently failed to operate efficiently, Company may, at its option and without waiving any other remedy it may have for such breach, terminate this Agreement by giving 5 days written notice to the Contractor and the Contractor will be entitled to compensation at the applicable rate set forth in Clause 7 for all Services completed prior to such termination, but shall be responsible for the cost of demobilising the Contractor's Items. 5.4 Improved Technology The Contractor shall advise the Company of any equipment which becomes available for use with improved technology over the Contractor's Items then supplied and, upon the request of the Company, shall make the new equipment available to the Company at rates to be agreed. 5.5 Removal of Equipment The Contractor shall remove all of its items from the Operations Area on completion of the Services whether or not the Items have been declared total or constructive total loss. 5.6 Contractor’s Warranty The Contractor warrants that the Services will be performed in accordance with good geophysical and engineering practices and with all the requirements of this Agreement and will, at the time of

-25- performance, comply with the technical and other specifications contained in this Agreement. All other warranties, express or implied, or whether relating to merchantability, fitness for a particular purpose, or otherwise, are hereby excluded and disclaimed. 5.7 Interpretation of Data Any interpretation of seismic data (whether made directly from seismic data provided to or by Contractor, or by data processing or otherwise) or interpretation of test or other data, and any recommendation or reservoir description based upon such interpretations, are opinions based upon inferences from measurements and empirical relationship and assumptions, which inferences and assumptions are not infallible, and with respect to which professional geophysicists or analysts may differ. Accordingly, Contractor cannot and does not warrant the accuracy, correctness or completeness of any such interpretation, recommendation or reservoir description. Under no circumstances should any such interpretation, recommendation or reservoir description be relied upon as the sole basis for any drilling, production, or financial decision or any procedure to be performed by Company or any of its other contractors. Company has full responsibility for all such decisions and for all decisions concerning other procedures relating to the drilling, production or any other of Company's Operations. 5.8 Data transmission Contractor does not warrant the accuracy of seismic data transmitted to the Company by electronic processes and will not be responsible for any liability resulting from breach of the integrity of the data, including any accidental or international interception of such data by others. 5.9 Defective or Inaccurate Data The parties acknowledge that defective, inaccurate or incorrect data delivered to Company will normally become apparent within a short time after completion of the Services. Contractor shall not be liable for any claims submitted in respect of such data more than three months after completion of the Services. Contractor’s liability shall be limited to correction of any warranted defect or reimbursement of the amount originally charged to Company which is directly related to that portion of Contractor’s defective services or products. Contractor reserves the right to determine whether to perform corrective measures or to reimburse Company, but reimbursement or completion of the corrective measures must be made or completed within one month of the date of the Company’s notification of defective, inaccurate or incorrect data. Contractor reserves the right to perform any corrective measures itself. 6. CONTRACTOR'S PERSONNEL 6.1. Personnel to be Supplied The Contractor shall furnish at all times during the Services all personnel as may be required to perform the Services including without limitation the personnel specified, if any, in Annexure A Attachment 2. All personnel shall be duly qualified, competent and experienced to conduct the tasks required by the Services. All the Contractor's personnel shall be subject to approval by the Company prior to commencement of work in connection with the Services. This approval shall be on the basis of previous experience and performance of the personnel. 6.2. Adjustments to Numbers / Classifications The Contractor shall not vary the numbers and/or classifications of the personnel from those specified in Annexure A – Attachment 2, without the Company's consent. At the Company's discretion, the Contractor shall replace missing personnel immediately at its own cost. If the Company requests the Contractor to provide additional personnel to that specified in Annexure A – Attachment 2, the Contractor shall furnish the additional personnel at rates to be agreed. 6.3. Replacement of Personnel on Request The Contractor will remove and replace in a reasonable time any of the Contractor's personnel if the Company so requests in writing, and if the Company can show reasonable grounds for its requirement.

-26- 6.4. Industrial Relations 6.4.1 The Contractor acknowledges that it is essential to the satisfactory performance of the Services, that the Contractor shall promptly at all times take such steps as are required to maintain good labour relations with its personnel to the extent that such requirement is consistent with sound business practice. 6.4.2 Whenever the Contractor becomes aware of any demand, claim or proposal for increased wages or reduced hours of work for any of its personnel engaged in performance of the Services or of any application or threat to make an application to vary or amend any award, rates, conditions or hours of work for personnel so engaged, or of any other action by whomsoever commenced which may result in an industrial dispute or a variation of rates of wages or hours of work payable to personnel so engaged or which could affect other operations of the Company in the Operations Area, the Contractor shall forthwith give notice and particulars thereof in writing to the Company. 6.5 Personnel Requirements The Contractor shall be solely responsible for providing all requirements of all of its personnel, including but not limited to: (a) salaries, wages, insurance (including Workers' Compensation Insurance) termination payments, rest leave allowances and benefits under applicable law including all taxes, contributions or levies in respect thereof; (b) medical attention; (c) fulfilment of immigration requirements, including passports, visas, medical examinations, personal customs duties and personnel work permits; (d) transportation and accommodation (except as otherwise provided herein); and (e) safety and environmental training. 7. COMPENSATION 7.1 Basis of Compensation The Company will pay the Contractor the fees and applicable rates as set forth in Annexure A in consideration of and as full compensation for performance by the Contractor of all its obligations under this Agreement. No payments shall be due to the Contractor other than those specifically mentioned in this Agreement. 7.2 Downtime 7.2.1 Contractor shall not be entitled to any payment for Downtime. 7.2.2 "Downtime" means and includes time the Contractor's Items are not available when called upon for the Services due to repair, replacement, inspection or maintenance of the Items or are available, but not in proper working order and recording cannot be performed, or any other reason resulting from Contractor’s inability to provide Services to specification, but does not include Standby Time, time incurred repairing damage caused by the environment in the Operations area, providing such damage is not due to negligence by the Contractor. 7.2.3 In the event of any delay in the supply of Contractor’s Items or Personnel at mobilisation or any mechanical failure, inspection or maintenance of a Contractor's Item during the term which does not result in a suspension of Services, but results in Services being slowed down or carried out less efficiently, the amounts payable to the Contractor shall be reduced in a direct relation to the percentage that Services are carried out less efficiently or are slowed down as agreed by the Designated Representatives of the respective Parties, but failing agreement by them, as determined by an Expert pursuant to Clause 18. 7.2.4 No compensation shall be payable for any time incurred to satisfy any work order from the any

-27- Government authorities in relation to a matter which is the responsibility of the Contractor during which the Contractor is not able to perform the Services as directed by the Company. 7.2.5 The provisions of this Clause 7.2 shall be without prejudice to any other remedies the Company may have at law or otherwise. 8. INVOICES, PAYMENTS, AUDIT 8.1 The Contractor's Invoices 8.1.1 The Contractor shall submit a GST compliant tax invoice to the Company for Services performed and reimbursable charges incurred hereunder during each calendar month within 15 days of the end of that month, but in any event not later than 6 months. The Company shall not be liable for, and the Contractor hereby releases the Company from, payment of any invoices submitted more than 6 months after completion by the Contractor of all Services performed notwithstanding any rule of law to the contrary. 8.1.2 All invoices shall be in accordance with the reports described in Clause 3.3 and other such charges as have been approved by the Company. All invoices shall include the Agreement Number. 8.2 Time / Place of Payment Subject to Clauses 8.5 and 17, the Company shall pay the Contractor's invoices within 30 days of receipt thereof. All payments shall be made by the Company in the manner and to the account as stated in the Contractor's invoice. 8.3 Interest on Late Payments Undisputed portions of invoices and invoices not paid within 30 days shall bear interest at the rate of 1% per month or pro-rata for part thereof. 8.4 Currency of Payments References to monetary amounts herein are (unless otherwise specified) in US$ and all payments required to be made by the Company to the Contractor pursuant to this Agreement shall be made in US$. If any currency conversions are required pursuant to the Agreement, the calculation shall be based on the Reserve Bank of Australia rate (RBA rate), being the unit of foreign currency per $A calculated by the RBA at 4:00pm Australian Eastern time on each business day, for the day before the date of issue of the relevant invoice or as otherwise agreed, permitted or required by applicable GST legislation. 8.5 Withholding from Invoices The Company will have the right to withhold payment of any portion of any invoice or statement presented by the Contractor and shall advise the Contractor of the reasons for the withholding within 30 days of the receipt of the invoice for: (a) reasonable verification thereof until the Contractor has provided the verification to the satisfaction of the Company. Interest will not be payable on the amount withheld. The Contractor shall not be entitled to discontinue the Services by reason only of non-payment of a disputed invoice where the dispute has not been resolved; (b) withholding income tax or other taxes as required by Australian law provided the Company promptly pays the withheld amount to the respective government authority. Company shall provide Contractor with all receipts in respect of payment of the amounts so withheld within 30 days of making such payment; and (c) amounts owing by the Contractor to the Company pursuant to the provisions of this Agreement.

-28- 8.6 Disputes Where there is a dispute as to the amount payable to the Contractor in respect of any invoice, the parties shall use their best endeavours to resolve the dispute promptly and fairly and the Company shall pay the amount agreed or found to be due at law within 30 days of such agreement or finding. Any portion of the amount which is not in dispute shall be paid in accordance with Clause 8.2. The Contractor shall continue to perform the Services pending the resolution of any dispute aforesaid. 8.7 Payment without Prejudice Payment of an invoice shall not prejudice the right of the Company to question the correctness of the same provided the question is raised not later than 2 years after the date of payment. 8.8 Audit The Company or its authorised representatives shall have the right to examine any books, records and other documents of the Contractor directly pertaining to costs when such costs are the basis of compensation to the Contractor hereunder. The Company will give the Contractor reasonable notice of such intended examination. The Company recognises that it’s right to examine any books, records or other documents:- (a) shall not include any inquiry into the Contractor's general overhead or profit margins, and (b) shall not require the Contractor to maintain any such books and records for a period in excess of 2 years after the completion of the Services. 9. PAYMENT OF TAXES AND GST 9.1 Taxes Contractor shall be responsible for, and shall hold Company harmless from, the reporting, filing and payment of any Australian taxes, duties, charges or fees (and any related fines, penalties or interest) imposed directly on Contractor or its subcontractors, employees, agents or servants as a result of Contractor’s performance of this Agreement including: (a) All income or other Australian taxes imposed upon Contractor or its subcontractors on account of earnings; (b) All Australian taxes assessed or levied against or on account of salaries or other benefits paid to the agents, servants and employees of Contractor or its subcontractors; and (c) All fines penalties additional Australian taxes (excluding Goods and Services Tax) and interest pertaining to any of the above taxes arising from or as a result or consequence of the non- performance by Contractor under this Section. Prices and rates quoted in this Agreement (including all Annexures and Schedules) are based on fiscal and other legislation, treaties and agreements in force at the time of commencement, and their current application in Peru. 9.2 GST “GST”, “Supply”, “Taxable Supply”, “Tax Invoice”, “Adjustment Note”, “Input Tax Credit”, and “Recipient” have the same meaning as provided under A New Tax System (Goods and Services Tax) Act 1999 (Commonwealth of Australia). Unless otherwise agreed, if GST is or becomes payable on any Supply made under this Agreement, the consideration for that Supply is to be considered exclusive of GST and the person making the Supply may recover from the Recipient the amount of the GST at the same time and in the same manner as the consideration for that Supply is payable or at such later time that the person making the Supply becomes aware of the GST liability.

-29- If the Recipient is entitled to withhold a disputed portion of an amount on which GST is payable, the Recipient is not required to pay the non-withheld portion until the person making the Supply issues a replacement Tax Invoice or Adjustment Note permitting the Recipient to claim all applicable Input Tax Credits for the amount not withheld. Once the dispute regarding the withheld amount is resolved, the Recipient shall make payment of the applicable amount upon receipt of a further Tax Invoice or Adjustment Note issued by the person making the Supply. 10. INSURANCE 10.1 Coverage Without limiting the Contractor's liabilities or obligations contained herein, at all times during the term of this Agreement the Contractor shall arrange for the following insurances to be maintained with reputable companies with provision of 30 days' written notice to the Company in the event of cancellation and non- replacement: (a) Workers' Compensation Insurance as required by law, including Common Law Liability; (b) General Public Liability Insurance for death, personal injury and property damage to an amount of not less than A$20,000,000 for any one occurrence; (c) Insurance to cover loss of or damage to the Contractor's Items (for their full replacement value) except such risks as the Company is liable for under Clause 11.1; (d) Hull and Machinery Insurance on Contractor’s owned Vessel to the full replacement value of the Vessel; (e) Protection and Indemnity Insurance in an amount of not less than US$5,000,000 including pollution originating from above the surface and indemnity in respect of wreck removal. 10.2 Additional Insured Insurance Policies under Clauses 10.1.(b) and (e) shall provide that the Company is included as additionally insured as respects work performed by and to the extent of the liabilities assumed by Contractor under this Agreement and that the underwriters so waive their rights of recourse on the Company. 10.3 Verification The Contractor shall furnish certificates of insurance to the Company no later than 30 days prior to commencement of work and of all renewals thereafter. 10.4 Default If the Contractor fails to produce certificates of insurance then the Company may, at its option, either itself arrange such insurance and recover the reasonable premiums payable in respect thereof from the Contractor or deduct same from any amount due or becoming due to the Contractor, or may refuse to make any payments otherwise due to the Contractor until such policies or evidence are produced. 10.5 Prejudicial Activities The Contractor shall not knowingly do any act which provides grounds for an insurer to refuse payment of any claim. 10.6 Claims The Contractor shall in the event of any loss, injury, damage or claim do all things necessary to obtain the full benefit of all the said insurances including, but without limitation, the giving of prompt notice of any loss or claim.

-30- 11. LIABILITIES AND INDEMNITIES 11.1 Indemnity (a) Property (i) Company Group’s property The Company shall be responsible for and shall save, indemnify, defend and hold harmless the Contractor; (ii) its parent, subsidiary and affiliated or related corporation(s), partnership(s), and limited liability companies; its officers, directors, shareholders, employees, agents, assigns, representatives, managers, and consultants of all of the foregoing the “Contractor Group” from and against all claims, losses, damages, costs (including reasonable legal costs) expenses and liabilities in respect of or resulting from loss of or damage to property of any of the Company Group (whether owned, hired, leased or otherwise provided by or in the possession or control of any of the Company Group) arising from or relating to the performance of this Contract regardless of the negligence in any form or breach of duty (statutory or otherwise) of any member of Contractor Group. (ii) Contractor Group’s property The Contractor shall be responsible for and shall save, indemnify, defend and hold harmless the Company; (ii) its parent, subsidiary and affiliated or related corporation(s), partnership(s), and limited liability companies; (iii) the contractors and subcontractors (of every tier) of (i) and (ii) above; and (iv) the officers, directors, shareholders, employees, agents, assigns, representatives, managers, and consultants of all of the foregoing “Company Group” from and against all claims, losses, damages, costs (including reasonable legal costs) expenses and liabilities in respect of or resulting from loss of or damage to property of any of the Contractor Group (whether owned, hired, leased or otherwise provided by the Contractor Group) arising from or relating to the performance of this Contract regardless of the negligence in any form or breach of duty (statutory or otherwise) of any member of Company Group. (b) Personnel (i) Company Group’s personnel The Company shall be responsible for and shall save, indemnify, defend and hold harmless the Contractor Group from and against all claims, losses, damages, costs (including reasonable legal costs) expenses and liabilities in respect of or resulting from personal injury including death or disease to any person employed by any of the Company Group arising from or relating to the performance of this Agreement regardless of the negligence in any form or breach of duty (statutory or otherwise) of any member of Contractor Group. (ii) Contractor Group’s personnel The Contractor shall be responsible for and shall save, indemnify, defend and hold harmless the Company Group from and against all claims, losses, damages, costs (including reasonable legal costs) expenses and liabilities in respect of or resulting from personal injury including death or disease to any person employed by any of the Contractor Group arising from or relating to the performance of this agreement regardless of the negligence in any form or breach of duty (statutory or otherwise) of any member of Company Group. (c) THIRD PARTY CLAIMS (i) THIRD PARTY PERSONNEL AND PROPERTY The Contractor shall be responsible for and shall save, indemnify, defend and hold harmless the Company Group from and against all claims, losses, damages, costs (including reasonable legal costs) expenses and liabilities in respect of or resulting from personal injury including death or disease to any third party or loss of or damage to the property of any third party to the extent

-31- that any such injury, loss or damage is caused by the negligence or breach of duty (whether statutory or otherwise) of any of the Contractor Group in connection with the performance of this agreement. The Company shall be responsible for and shall save, indemnify, defend and hold harmless the Contractor Group from and against all claims, losses, damages, costs (including reasonable legal costs) expenses and liabilities in respect of or resulting from personal injury including death or disease to any third party or loss of or damage to the property of any third party to the extent that any such injury, loss or damage is caused by the negligence or breach of duty (whether statutory or otherwise) of any of the Company Group in connection with the performance of this agreement. For the purpose of this clause, “third party” shall mean any party other than members of the Contractor Group and Company Group. 11.2 Consequential Damages If any breach or default of this Agreement gives a party a right to damages, such damages shall be limited to damages for direct and reasonably foreseeable loss attributable to such breach or default. Notwithstanding any other term or condition of this Agreement, each party covenants to the others that it shall not make any claim or enforce any liability or indemnity against any other party for any loss of generation, production, revenue or profit (other than revenue or profit derived directly from payments for goods or services already delivered under the express terms of this Agreement) or business opportunity or for any other indirect or consequential cost, loss, expense or damage (including any claim for special or punitive loss or damages) howsoever arising in respect of any circumstances under or in relation to this Agreement or to the performance or non-performance of the Services. 11.3 Tape Liability The Contractor shall be responsible to the Company for any loss or damage to any data tapes or records relating to the Services occurring prior to the delivery of the tapes or records to a Courier selected by the Company as provided in Annexure A. In the event of loss or damage to the field tapes prior to delivery to the courier or if the Company notifies the Contractor of any loss or damage within 21 days of the Company’s receipt of the data tapes Contractor shall, at the Company’s option, either: (a) re-record corresponding tapes in order to re-acquire the lost or damaged data, if the needed recording vessel(s) are still in the general area relating to the services or within a reasonable time to be agreed with the Company if the vessel is not in the vicinity of the Operations Area; or (b) refund the sum payable to another Seismic Contractor for acquiring the lost or damaged data. Notwithstanding the above, if Company requires the use of a specific common carrier to transport the seismic data tapes, then Company shall bear the risk of loss, damage or destruction of the tapes during such transport and Contractor shall bear no liability therefore. The above sets out the entire liability of Contractor and Company’s exclusive remedies in the event of lost or damaged data tapes or records. 11.4 Data Storage Unless specifically and separately contracted and paid for, Contractor assumes no liability for, and shall not be responsible for, any gratuitous bailment or storage requested in writing by Company in addition to the Services of any seismic data, whether on tape, in physical sections, in computer memory or in any other form whatsoever, Contractor shall not be liable for any damage, destruction, loss or theft of any such seismic data and Company agrees to defend, indemnify and hold Contractor harmless from any and all claims brought by third parties in relation to such seismic data. 11.5 Patent Infringement The Contractor represents and warrants that the use or construction of the Contractor's Items does not infringe any licence or patent, which has been issued or applied for. The Contractor further agrees to indemnify and hold harmless the Company from any claims, demands and causes of action arising out of

-32- any infringement of patent, design, trademark, or trade name, copyright or other protected right arising out of the furnishing of or use of the Contractor's Items by Contractor. 11.6 Indemnity as to charges 11.6.1 The Contractor shall indemnify and hold the Company harmless from and against any costs, charges fees and losses incurred as a result of defending any charges laid by any governmental authority against the Company directly arising solely from the Contractor’s wrongful or negligent act or omission in providing or in connection with the Services. 11.6.2 The Company shall indemnify and hold the Contractor harmless from and against any costs, charges fees and losses incurred as a result of defending any charges laid by any governmental authority against the Contractor directly arising solely from the Company’s wrongful or negligent act or omission in connection with the Services. 11.7 Indemnity Application 11.7.1 Except as otherwise specifically provided in this Agreement, the indemnities and exclusions of liability contained in this Agreement shall apply without regard to the cause or causes thereof including, but not limited to strict liability, breach of warranty (express or implied), pre-existing condition (patent or latent) or the negligence of any party or parties, including the party indemnified or benefiting from an exclusion of liability and any of its subcontractors employees, servants or agents and whether such negligence (excluding gross negligence or wilful misconduct) be sole, joint or concurrent, active or passive, and whether the claim is based on common law, civil law, maritime law, or statute. 11.7.2 The indemnities contained in this Agreement : (a) in favour of the Company shall be deemed to extend to the Participant, its affiliated companies, its contractors (excluding the Contractor) insurers and their respective employees, directors, officers and agents all to the extent that they are involved in the Services; (b) in favour of the Contractor shall be deemed to extend to the Contractor's sub-Contractors of any tier, it’s subcontractors’ affiliated companies, and their respective employees, agents, officers, directors, representatives and agents all to the extent they are involved in the Services; (c) in favour of individuals shall be deemed to extend to dependants, heirs, executors and assigns; and (d) shall survive the termination of this Agreement for whatever reason and shall be continuing obligations in regard to equipment furnished, personnel provided, or the Services performed. 11.8 Pollution Contractor shall be liable for and shall release, defend, indemnify and hold harmless the Company from and against any and all claims related to or arising from pollution (including control and removal thereof) emanating from Contractor’s equipment and vessels during the performance of this agreement regardless of the negligence in any form or breach of duty (statutory or otherwise) of the Company, its employees, agents, representatives or subcontractors. 11.9 Exclusion zone The parties acknowledge that in the performance of the Services, Contractor would not normally be required to operate within a 500 metre radius of any offshore Installation. In the event the Company requires the Contractor to operate within a 500 metre radius of any offshore Installation, then notwithstanding any provisions to the contrary in this agreement, Company shall be liable for and shall release, defend, indemnify and hold harmless Contractor, its employees, agents representatives or subcontractors from and against any and all claims relating to and/or arising from such operations including claims relating to and/or arising from the loss of or damage to any property of any type,

-33- regardless of the negligence in any form or breach of duty (statutory or otherwise) of the Contractor, its employees, agents, representatives or subcontractors. For purpose of this clause, “offshore Installation” shall mean: (i) a fixed permanent oil and gas platform, (ii) a floating, production, storage and off take vessel, (iii) a semi-submersible or jack-up drilling unit, (iv) a pipe lay vessel, (v) a well intervention vessel or any other vessel or installation, (vi) or other object connected to the seafloor or otherwise not readily removable. 12. ASSIGNMENT The Contractor shall not assign this Agreement in whole or in part, nor sublet or subcontract any portion of the work under this Agreement, without the prior written consent of the Company, which consent shall not be unreasonably withheld. Such consent shall not relieve the Contractor of its obligations hereunder unless specifically stated therein. The Company reserves the right to assign its rights under this Agreement at any time and from time to time during the term. Such assignment shall not relieve the Company of their obligations under this Agreement. 13 FORCE MAJEURE 13.1 Definition For the purposes of this Agreement, Force Majeure means any act, circumstance or event beyond the reasonable control of either of the parties, including but not limited to earthquakes, cyclones, fires, storms or other acts of God, whether similar or dissimilar, industrial disputes (except those initiated or substantially contributed to by Contractor or Contractor's personnel) and dispositions or orders of governmental authority (whether such authority be actual or assumed) but shall not include lack of funds or economic hardship or the events listed in section 2.1 of Attachment 4 of Annexure A. 13.2 Relief from Obligations If, by reason of Force Majeure, the Contractor's performance of this Agreement is prevented or delayed or the Company is unable to make use of the Contractor's Items and Services under this Agreement, the party so affected shall be relieved of its obligations under this Agreement (other than payment by the Company of the Force Majeure Rate) while the Force Majeure continues provided that the Contractor has strictly complied with clause 13.3. 13.3 Notice In such event, such party shall give written notice to the other party by the fastest means of communication available, specifying the circumstances which that party believes constitute Force Majeure and the estimated duration thereof, and shall make all reasonable efforts to relieve such Force Majeure condition. 13.4 Extended Suspension Notwithstanding the foregoing, it is expressly agreed that should an act of Force Majeure occur causing the suspension of the Services for a period of 7 days or more, the Company shall have the right to terminate this Agreement by giving the Contractor 5 days written notice to that effect.

-34- 14 NOTICES Except as otherwise specifically provided in Clause 15.1 or elsewhere in this Agreement, all notices and other communications required to be given hereunder must be given in writing. Transmittal shall be by prepaid certified or registered mail with delivery confirmation receipt requested, or in person with a copy of the notice or communication signed as received by the receiving party, or by facsimile at the appropriate address as provided in Annexure A (or other address from time to time notified by a Party thereof to the other party) and shall be effective from the time of receipt thereof. Notices and other communications shall be deemed to have been received upon delivery or, for those sent by certified or registered mail on the second day after posting and those sent by facsimile, on the next business day following successful transmission. 15 DESIGNATED REPRESENTATIVES 15.1. Authority The Company and the Contractor shall each appoint a Designated Representative (to be present at the Operations Area) for the purpose of giving or receiving any instruction, information or notice which should or may be given to or by the party he represents in regard to the Services. The Designated Representatives shall not, without express written authority, be entitled to vary or terminate this Agreement or approve any invoice or compromise or settle any claim by or against, or waive any right of the party he represents. 15.2. Appointment The Company and the Contractor hereby appoint the persons as stated in Annexure A respectively as their Designated Representative. Such appointments may be changed from time to time by notice in writing from the appointing party to the other. The foregoing shall not exclude the giving or receipt of any instruction, information or notice by any other authorised person or means permitted or required under this Agreement or at law. 16 CONFIDENTIALITY 16.1 Obligations of the Parties The Contractor recognises the confidential nature of the Operations of the Company, and the Contractor shall respect such confidentiality and shall keep secret and confidential and shall not directly or indirectly disclose to any third party any information relating to the business affairs, work, investigations or operations of the Company including data, Surveys, specifications, drawings, design features, records, reports, accounts or other documents or things supplied or which come into the Contractor's possession and the Contractor shall take or cause to be taken such precautions as may be necessary to maintain such secrecy and confidentiality and prevent such disclosure of the same and the Contractor will use its best endeavours to ensure that its employees, agents and sub-Contractors also respect such confidentiality. Company shall maintain confidential and shall at no time without the prior written agreement of the Contractor use, reproduce, copy, disclose to, place at the disposal of or use on behalf of any third party or enable any third party to use, peruse or copy any documents, drawings, data, computer software or other information belonging to or relating in any way to the business and affairs of the Contractor (including any specifications, techniques, know-how, procedures or equipment used or provided by the Contractor in performing the Services) which may be disclosed to or learnt by Company in connection with this agreement. Company shall endeavour that all contractors, employees, agents or servants of Company and any other contractors associated with the Services shall observe the same obligations in respect of any documents, drawings, data, computer software or other information referred to above which may be disclosed to or learnt by them in connection with or as a result of their activities in connection with this agreement.

-35- 16.2 Press Releases The Contractor shall not issue any news releases, advertising, publicity or promotional material relating to the Services to be performed herein without the prior written approval of the Company. 17 DEFAULT 17.1 Right to Withhold Payments Without prejudice to any other provision of this Agreement or any other remedies at law, if the Contractor fails to perform or observe any obligation, terms, condition or stipulation contained in this Agreement which is to be performed or observed by it, then the Company may, without prejudice to any other right that the Company may have under this Agreement and without prior notice to the Contractor, withhold payment of any amount payable to the Contractor under this Agreement that relates to the failure to perform or observe any obligation, terms, condition or stipulation until the matter is remedied or until such earlier time as the Company may determine. 17.2 Notice The Company shall notify the Contractor of the details of any amount withheld by the Company pursuant to Clause 17.1 in writing at the time that the payment would, but for this condition, be due to the Contractor. 18. EXPERT 18.1 Appointment Where, by the terms of this Agreement, it is provided that any matter in dispute may be referred to an Expert or in the event of there being any dispute between the parties or any of them (other than any dispute as to the interpretation of this Agreement) as to the rights obligations or interests of the parties under any of the other provisions the dispute may by agreement of the parties in dispute in either case be referred to an Expert in accordance with the following provisions: (a) if the parties can agree upon the person who is to be appointed as the Expert within 7 days (unless the Operations are currently underway, then the time shall be reduced to 24 hours) of the Date of Reference (being the date upon which the parties in dispute agree to refer the matter to an Expert) the matter in dispute shall thereupon be referred to such Expert; (b) if the parties cannot agree on the appointment of an Expert within the period of 14 days they will forthwith and in any event within 1 month of the Date of Reference, each appoint an expert and those experts between them will appoint an Expert to whom the matter in dispute shall be referred; (c) if a party fails to appoint an expert in accordance with the provisions of (b) above then if one expert has been appointed then that expert shall thereupon be deemed to be the Expert appointed pursuant to the provisions of this Clause 18 and the matter in dispute shall be referred to that expert accordingly (d) if the experts appointed by the parties under (b) above fail to appoint an Expert within 7 days of the Date of Reference any party to the dispute may ask the Chairman for the time being of Australian Petroleum Production and Exploration Association Limited to appoint an Expert and the matter in dispute shall thereupon be referred to the Expert appointed by the Chairman; and (e) all moneys awarded by an Expert (including all moneys awarded for damages hereunder and/or the costs of reference to the Expert) shall attract interest at 15% and shall be compounded on a monthly basis. Such interest shall accrue on and from the date that each dispute was first referred for determination in accordance with the provisions of this Clause 18. All moneys awarded by an Expert in accordance with the provisions of this Clause 18 (including interest due thereon) shall be paid within one month of the Expert's determination.

-36- 18.2 Performance to Continue Notwithstanding the fact that any matter in dispute between the parties is to be referred or has already been referred to an Expert, the parties shall continue to observe and perform their respective obligations and duties hereunder as if no such dispute had arisen. 18.3 Determination Binding In the event of a reference to an Expert, his opinion shall be final and binding on the parties in dispute. 18.4 Not Arbitration In making his determination the Expert shall act as an expert and not as an arbitrator and the provisions of the Commercial Arbitration Act 1985 shall not apply.

-37- ANNEXURE C AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES COMPLIANCE WITH STATUTORY REGULATIONS (PART 1 - THE CONTRACTOR) In addition to any other requirement of the Agreement, the Contractor shall comply and take all reasonable efforts to ensure that the Contractor's Personnel comply with the requirements of the provisions of all statutory requirements and regulations, and with the lawful requirements of public, municipal and other authorities in any way affecting or applicable to the performance of the Services. Without limiting the generality of the foregoing the Contractor shall ensure that: (a) any Contractor's Items to be supplied or furnished by it hereunder shall comply with the requirements and standards of all laws, regulations and directions; (b) each person employed by the Contractor (either directly or indirectly through a subcontractor or third party) is familiar with the Schedule and emergency response manuals to the extent relevant to that person's employment or purpose at the worksite upon arrival at the worksite or prior to the performance of any work or services as the case may be and that each person will observe and comply with, the requirements applicable to the area of operation while at the worksite during the performance of the Services; and (c) provide confirmation that each person referred to in (b) above confirms in writing in a form provided by Operator that he has been made familiar with the requirements of the Schedule and an undertaking that he will so comply. The Contractor shall ensure that each subcontractor provides to the Operator an undertaking to comply with the "Specific Requirements" on the form in Part 2 or other approved Form. Dated this day of 2012 For and on behalf of the Contractor: (Signature) (Name of authorised signatory)

-38- (PART 2 - SUBCONTRACTORS) Name of Contractor ________________________________________ Name of Subcontractor ________________________________________ Subcontract Services ________________________________________ The undersigned is a subcontractor to the Contractor for the performance of the services and hereby confirms that it and its personnel are familiar with the requirements of the statutes and regulations to the extent that those requirements apply to the Subcontract Services: Dated this day of 2012 For and on behalf of the Sub-Contractor: (Sub-Contractor’s name) (Name of authorised signatory) (Signature)

-39- ANNEXURE D AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES ACQUISITION PARAMETERS & QUALITY CONTROL STANDARDS 1 GENERAL 1.1 Location The Surveys are located as shown in Annexure E of this agreement 1.2 Survey Size 3D data acquisition will total approximately 195 square kilometres in size. 2D data acquisition will total approximately 135 line kilometres in size The Company reserves the right to increase/decrease the program by a factor of 25% of the stated totals. Notification of any modification to the program size will be made in writing to the Contractor prior to completion of the assigned program. 1.3 Water Depth The data acquisition is in open water with no surface obstructions. The 3D survey area covers a number of shoal areas which, according to marine charts rise to approximately 22 metres (LAT) in the shallowest area. These areas may result in unpredictable currents and feathering. Tides in this area are of low magnitude, 1 to 2 metres. Recognition of these facts will allow the Contractor to complete the assigned program safely, as prevailing conditions allow, without endangering the personnel, vessels or equipment and without causing delays as a result of the water depths. 1.4 Start Date The start date for the Operations will be 6 December 2012, but no later than the 14 December 2012, 1.5 Vessel Positioning and Navigation Contractor will supply the navigation and positioning systems required to conduct the Operations to the required specifications. 1.6 Supervision The Contractor will provide qualified and experienced QC personnel capable of providing total quality control of all seismic and navigation data acquired. The Company will also supply qualified and experienced QA personnel. 2 ACQUISITION PARAMETERS 2.1 For 3D Data Acquisition Services Streamer Number of streamers : Minimum 4 Streamer length : 6000m Group interval : 12.5m Streamer Separation : 100m Streamer Depth : 7 metres Source Type : Tuned Airgun Array Source volume : 3080_ cubic inches Number of sources : 2 Number of sub arrays/source : 2

-40- Source operating pressure : 2000 psi Source Separation : 50 metres Shot Point Interval : 18.75m flip-flop Source Depth : 5 metres Offset : Approximately 120 metres Recording System Low Cut : 3Hz @ 12dB/Oct (or similar) High Cut : 206Hz @ 276dB/Octave (or similar) Record Length : 6 secs Sample Rate : 2 ms Recording Format : SEG-D Media : IBM 3590/3592 2.2 For 2D Data Acquisition Services Streamer Number of streamers : 1 Streamer length : 8000m Group interval : 12.5m Streamer Separation : 100m Streamer Depth : 7 metres Source Type : Tuned Airgun Array Source volume : 3080 cubic inches Number of sources : 1 Number of sub arrays : 2 Source operating pressure : 2000 psi Shot Point Interval : 25 metres Source Depth : 5 metres Offset : Approximately 120 metres Recording System Low Cut : 3Hz @ 12dB/Oct (or similar) High Cut : 206Hz @ 276dB/Octave (or similar) Record Length : 8 secs Sample Rate : 2 ms Recording Format : SEG-D Media : IBM 3590/3592 3 QUALITY CONTROL STANDARDS 3.1 Standards These standards will be strictly adhered to. However, the Company’s Quality Control Supervisor will have the right to suitably alter them in order to accommodate the variable operating conditions. Contractor shall evaluate data quality using all available systems. At the start of the Operations all equipment shall comply with all technical specifications. During each 24-hour period, daily instrument tests shall be undertaken and analysed, and results submitted to the Company’s quality control supervisor for approval. 3.2 Requirements During Mobilisation During mobilisation Contractor shall undertake the following and inform Company’s quality control supervisor of the results before sailing: • Provide a copy of recent performance statistics for streamer compasses. • Provide recent Gyro compass calibration, calculated from static or dynamic observations. • Monthly seismic instrument tests, which must be no less than 48 hours old.

-41- • Provide a list of onboard equipment spares. When on location during streamer deployment Contractor shall provide the following: • Streamer configuration and deployment diagrams • Antenna diagrams and location of any navigation reference points • Printout of all Survey parameters input into INS • Results of analysis of monthly instrument tests 3.3 Unacceptable Misfire Rates A line or line segment shall not be accepted if there are: 8 or more consecutive misfires, 12 misfires in any 24 consecutive records, 16 misfires in any 40 consecutive records The cumulative misfires shall not exceed 5.0% for a line or line segment or 2.0% for the Survey. Definition of a Misfire Any one of the following shall be considered as a misfire: • No seismic data recorded (or incomplete record) • No navigation data recorded (or incomplete record) • Loss of time zero • No shot fired • Tape parity error • Data extraction errors • Source synchronisation error • Acquisition/recording parameters do not meet performance specification • Recording instruments do not meet performance specification • Streamer parameters and performance do not meet performance specification • Streamer feathering exceeds performance specifications • Streamer noise levels exceeds performance specifications • Streamer balance/depth do not meet performance specification • Number of bad streamer channels do not meet performance specification • Source signature does not meet performance specification • Source volume does not meet performance specification • Air pressure does not meet performance specification • Source timing and/or synchronisation does not meet performance specification • Source depth does not meet performance specification • Failure of source depth indicators for any particular gunstring • Vessel primary positioning does not meet performance specification • Source positioning does not meet performance specification • No gyro information • Fathometer not operating for more than 5 kilometres unless an alternate method of depth determination is readily available. • Any QA system not operating for more than 5 kilometres, in real time or post processing. 3.4 Acquisition Procedures and Minimum Line Lengths All of the following acquisition procedures and minimum line lengths shall be met/ adhered to: • Line run-in distance shall be sufficient to ensure that the streamer is optimally positioned prior to the start of acquisition on each sail line, unless otherwise approved by the Company Quality Control Supervisor • Guns shall be fired in sufficient time prior to start of line to allow for warming up and tuning. • Source firing shall be initiated with a single gun or cluster. • Single guns or clusters will be added to the source after each 3 shots until operational volume is achieved.

-42- • Line run outs to achieve full fold coverage are required at the end of each line • The minimum acceptable line segment shall not be less than 1 streamer length. • The maximum number of allowable line segments per line shall be 3. • Any line re-shoot shall be recorded in the same direction as the original line. • Line naming convention will be as follows Sail line numbers will have the format CCYYLLLLXSSS, where: CC is the Company/Survey Identifier YY is the Year of Acquisition LLLL is the Sail Line Number X is the Shooting Code P for prime, A/B/C for reshoot or resumed line, J/K/L for infill SSS is the Acquisition Sequence Number • Resumed lines will bear a suffix such that A represents a second attempt, B a third attempt etc. • Every line attempt shall be accorded a unique consecutive number regardless of whether the line is accepted or subsequently rejected (Sequence Number). • Shot number convention will be such that the ends of the lines with the lowest shot numbers will all be aligned towards one side of the Survey. As such lines will have incrementing or decrementing shot numbers depending on the direction of shooting. • The practice of incrementing shotpoints by 1,000 or 10,000 etc. for re-shoots shall not be used. 3.5 Energy Source For each of the airgun arrays used for the Operations, a synthetic signature report and the Frequency Spectra must be supplied together with the exact gun sizes, depth, the delay time for the guns and any other data used to produce the above report and the frequency spectra. Synthetic signatures shall also be run to support proposed gun drop specifications. No change in the airgun parameters, including gun drop specifications, must take place without re-running the synthetic signature and gaining approval from the Company’s Quality Control Supervisor. Validity of the above information will be established prior to the start of the Operations. Source Minimum Requirements Energy source shall meet all of the following minimum requirements. • The air pressure shall be displayed in the recording room and recorded on the seismic tape; • Individual guns shall be monitored by a hydrophone and/or a transducer located as close to the centre of explosion as practical; • Source controller systems shall be able to: o detect and display the fire time of each individual gun relative to the fire command time to an accuracy of 0.25 milliseconds; o display individual timing errors graphically; o synchronise all guns within a specific time window; o provide alarms for: ? autofiring guns; and ? out of sequence firing (flip/flop); and ? single gun misfires. o determine standard deviation of timing errors for each gun at each shot and display graphically; and o at the end of each line produce a summary of gun performance during the line and display graphically. Source Performance Specifications A gun is considered to have misfired and shall be shut down under any one of the following conditions: • autofiring; • air leak; • variations in the near field signature, and/or • synchronisation more than ±1.25 millisecond from time zero.

-43- The following specifications shall govern the operation of the source(s). Individual records which do not meet these specifications shall be considered as a misfire: • malfunction of source controller system; • source depth exceeds ±1 metre from specified depth; • autofiring gun(s); • variations or inconsistencies in signature from shot to shot; • Average deviation in the 10 to 70 Hz bandwidth form the spectrum of the full array exceeds +/-1.5 dB. • Maximum deviation from the spectrum of the full array exceeds +/- 3 dB anywhere in the 10-70 Hz bandwidth. • loss of time break. Source QC Checks and Tests The following checks shall be undertaken prior to start of Operations and at any other time at Company’s Quality Control Supervisor's request: • signature evaluation using seismic QC and/or processing systems; • verification of delay between start of record and field time break; • verification that record length and speed are compatible with source re-cycle times; • measurement of towing ropes, wires and chains; • correct operation of source mask (flip/flop) identifier using single trace recorder or seismic QC system; and • verification of in-line source to near trace offset. 3.5.2 Gun Drop Specifications Full set of drop out specifications are inserted in Annexure G . 3.6 Seismic Streamers Contractor’s seismic streamers shall meet the following minimum requirements, performance specifications, and QC checks and tests. Streamer Minimum Requirements Contractor’s seismic streamer(s) shall meet the following minimum requirements. • The streamer skin shall be suitable for the area of operation; • Towing speed shall be between 4.5 and 5.5 knots (through the water); • Initial balancing shall be undertaken in the area of Operations, with depth controllers and modules in place and the vessel at Survey speed (nominally 5.0 knots) until the streamer is neutrally buoyant at the specified depth; • After streamer balancing, wing angles of depth controllers shall not permanently exceed 5º ; • Depth controllers shall be spaced not more than 300 metres apart; • Depth controllers shall be fitted with depth indicators; and • Streamer section depth indicators (other than depth controllers) shall be equally spaced midway between each depth controller (i.e. nominally 300 metres apart). Streamer Performance Specifications At a minimum, Contractor’s seismic streamer(s) shall meet the following performance specifications. Contractor shall endeavour to reduce the number of any bad traces at each new streamer deployment. The following specifications shall govern the operation of the streamer(s). Individual records which do not meet these specifications shall be considered as a misfire: • at the start of, or during a line the maximum number of bad traces per streamer shall not exceed: • 2 randomly distributed in any 80 or • 4 randomly distributed in any 160 or • 8 randomly distributed in any 320 or • 16 randomly distributed in any 640

-44- • the near trace shall always be operational • there shall be no more than 2 adjacent bad traces • the maximum number of bad traces in the near third of each streamer shall not be more than 1% of the total number of traces • average streamer depth shall not vary by more than ±1 metre from specified depth; and • maximum distance between depth indicators shall not exceed 400 metres. Bad Trace Definitions Any of the following conditions shall qualify as a bad trace: • Any hydrophone within a group is reversed polarity • Sensitivity down by more than 3 dB from manufacturer’s specifications; • Trace is dead; • Trace is spiking or wild; or • Signal distorted or out of phase by more than 30º or 1 millisecond. Streamer Noise Definitions Streamer noise shall be given in microbars RMS (Root Mean Square) and measured over the full recording cycle with recording filters and with the streamer at the specified tow depth. The following guidelines shall be used for determination of acceptable levels of coherent noise and swell noise, but shall depend on geophysical objectives. Whenever possible the use of onboard processing/QC systems shall be used to further evaluate the effects of noise on the data. In any case the final decision shall rest with Company in consultation with its Designated Representative. Ambient noise levels shall not exceed 250/(L) µbar for the first 10 traces, 100/(L) µbar for traces near the depth controllers and modules; and 62.5/(L) µbar, for all other traces, where L = group length in metres, and noise levels are measured through an 8 Hz low cut filter. Swell noise of up to 25 µbar can be tolerated if appearing on less than 5% of shot records on any line and is less than 2 seconds in duration. Higher noise levels may be acceptable subject to Company Quality Control Supervisor’s approval. Coherent noise shall be assessed according to the following: • amplitude of the interfering signal; • duration of the noise; • repetition and synchronisation of the interference; and • moveout of the interference. Constant interference up to 10 µbar shall only be tolerated up to a maximum duration of 4 seconds; As a general rule, coherent noise shall not exceed the following limits: Noise coming from astern of the streamer: Moveout Max. Noise (µbar RMS) More than 250 milliseconds 25 µbar 125-250 milliseconds 12 µbar 0-125 milliseconds 5 µbar Noise coming from ahead of the streamer: Moveout Max. Noise (µbar RMS) More than 2000 milliseconds 25 µbar 1400-2000 milliseconds 12 µbar 0-700 milliseconds 5 µbar

-45- Streamer Feathering As agreed with the Company’s on board Quality Control Supervisor and dependent on sea conditions. However, consistent matching of streamer feather angles on adjacent sail lines will be a critical factor in the data acquisition process. Maximum streamer feathering should be less than 10 degrees (<10 degress) Streamer QC Checks and Tests Trace polarity shall be in accordance with SEG (Society of Exploration Geophysicists) convention namely a compression wave shall produce a negative number on tape, downward deflection on camera monitor and a white trough on the trace recorder. Streamer sensitivity, electrical resistance, crossfeed and insulation shall be verified daily or at any time if requested by Company’s Quality Control Supervisor. Streamer sensitivity shall be evaluated from a series of fixed gain displays. Streamer noise tests shall be undertaken on the run in and at the end of every line and recorded on the production tape. A reference signal shall also be recorded on an auxiliary channel. During noise tests: • the vessel shall be at Survey speed (nominally 4.75 knots); • the recording settings shall be as per the specified acquisition parameters; and • the streamer shall be at the specified depth. The source to near trace in-line offset shall be verified at the start of each line by using waterbreak phones or acoustic devices or any other reliable method. A change in linear source to near trace offset of more than 1/2 group length from the mean shall be investigated and remedied. 3.7 Recording System Contractor’s recording system shall meet the following minimum requirements; performance specifications; and QC checks and tests. Recording System Minimum Requirements Contractor’s recording system shall meet all of the following minimum requirements: • The equipment shall be calibrated and meet manufacturer’s specifications; • Polarity shall be in accordance with SEG convention • Only new recording media shall be used. • Acceptable media is IBM 3590/3592 compatible cartridge tapes; • No data shall be recorded after the end of tape marker; • The last record on each tape shall be followed by a double EOF (End of File); and • The seismic channels shall be displayed on oscilloscopes. Recording System Performance Specifications Individual records which exhibit any of the following do not meet these specifications and shall be considered as a misfire: • loss of time zero; • tape parity errors; • data extraction errors; • loss of synchronisation between field time break and start of data; • loss of more than 3 channels; • performance below manufacturer’s specifications; • no data recorded; • incomplete record; • loss of multichannel monitor or section plotter for more than one (1) km • loss of fathometer for more than one (1)km

-46- Recording Instruments QC Checks and Tests Instrument tests shall be performed in accordance with manufacturer’s recommendations and/or Contractor's procedures approved by Company’s Quality Control Supervisor and shall comprise all of the following: Monthly tests for IFP (Instant Floating Point) systems shall comprise, but not be limited to, the following: • Preamplifier calibration; • Amplifier RMS noise and DC offset; • Equivalent input noise and offset referenced to 1 µvolt (with and without low cut filter); • Hydrophone group sensitivity; • Filter impulse response; • Harmonic distortion; • Cross feed checks; and • Dynamic range determination. Daily tests for IFP systems shall comprise, but not be limited to, the following: • Dynamic range determination; • Equivalent input noise and offset referenced to 1 µvolt (with and without low cut filter); • Streamer noise test; • Streamer continuity and leakage test; • Data transmission validity; and • Amplifier RMS noise and DC offset. Daily tests shall be recorded on media equivalent to that of the production tapes. Monthly tests shall be processed by Contractor onboard the vessel. Equipment which does not meet manufacturer’s specifications shall be replaced and another set of tests performed. A set of monthly tests shall be undertaken following any software and/or hardware changes. A polarity check shall be made at the start of the Operations and whenever a streamer section is replaced. Polarity may be determined by a tap test or evaluation of first break arrivals (if feasible). Multi-channel camera records shall be taken every 1 kilometre. Tapes All seismic data will be recorded on new magnetic tapes of Company approved manufacture and brand. Tape labels will be systematically annotated. Proper precautions will be observed in storing and transporting both new and recorded tapes. 3.8 Positioning and Data Quality Assurance 3.8.1 Integrated Navigation System (INS) Contractor’s integrated navigation system shall meet all of the following minimum requirements, binning display minimum requirements, recording requirements and filtering requirements. INS Minimum Requirements The system shall be able to determine in real time the location of the vessel, sources and all receiver arrays by integration of satellite positioning data, gyro compass data, streamer compass data, laser systems data (if used) and acoustic systems data at the same instant in time. Where time de-skewing is required to correct for age of data, this shall be kept to a minimum. The system shall be able to: • interface positioning data from satellite systems • record up to 20 lines of position and use up to 10 lines of position in a single computation, using a least squares solution, for both vessel, headbuoys and tailbuoys; • compute and display in real time residual range values for each LOP (Line of Position);

-47- • mix LOP's from multiple interfaced systems in a single computation; • compute and display in real time, • position differences between primary, secondary and tertiary systems • the locations of all positioning nodes on the towed Survey spread; • the location of all source and receiver positions in the Survey spread • compute and display in real time LOP geometry and the standard deviation of the least squares solutions; • navigate between 2 points in either great circle or grid line mode; • undertake seven parameter datum transformation calculations; • compute Survey line pre-plots; • display vessel progress along each Survey line to include speed and distance off-line; • compute and display coordinates in either geographic or rectangular coordinate systems referenced to the specified Survey datum, spheroid and projection; • generate an unambiguous remote display to facilitate steering of the vessel along the Survey line; • produce end of line QC plots in the form of histograms, scatter grams and time series plots for each system used for positioning and for each computation made by the INS, for end of line statistical analysis; and • generate shotpoint closures in either time or distance mode. INS Recording Requirements The system shall record to industry standard 3590 cartridge tapes, all raw positions solutions and sensor data in UKOOA (United Kingdom Offshore Operators Association) P2/94 format (other formats require Company approval). As minimum at each shot the following parameters shall be recorded: • time (UTC); • shot number; • all raw positioning data for all systems and sensors (radio, satellite, laser etc.); • primary position; • secondary position; • number of GPS (Global Positioning System) SV's (Satellite Vehicles) and ID's (Identifications) used with elevations; • GPS HDOP (Horizontal Dilution of Precision) and PDOP (Position Dilution of Precision) values; • standard deviation of the least squares position for primary system (or 95% horizontal error ellipse for DGPS (Differential Global Positioning System) systems); • standard deviation of the least squares position for secondary system (or 95% horizontal error ellipse for DGPS systems) • gyro heading and water depth. All C-O's, delays, propagation velocity factors shall be input into the INS software not the mobiles. Before the start of line a file containing all initialization paramaters shall be recorded containing: i) spheroid/datum parameters ii) projection parameters iii) wide area differential station locations iv) all antenna and other fixed offsets INS Filtering Where any form of filtering is applied to raw sensor data, the minimum filter value that is consistent with non-erratic navigation, shall be selected. In any case all raw unfiltered data shall be retained and recorded as specified. Company’s Quality Control Supervisor shall be informed regarding the application of smoothing filters. 3.8.2 Positioning Contractor shall verify all geodetic parameters, station coordinates and datum transformation parameters to be used for the work and shall ensure that these are correct and appropriate for the area of operation.

-48- Contractor shall provide the necessary onboard positioning and navigation quality control computers to achieve the specified accuracy and tolerances. DGPS Positioning Contractor’s DGPS positioning system shall meet all of the following specifications; including network minimum requirements; performance specifications; height aiding requirements; mobilisation requirements; QC checks and tests; streamer compasses; and towing geometry. Any Differential Global Positioning System supplied by Contractor shall have an acceptable proven QC system. Statistical testing utilising the F-test and W-test shall be carried out for each position fix to identify and eliminate systematic bias errors and range outliers. The 95% a-posteriori horizontal error ellipse of the 2-dimensional position shall be used as the basis for acceptance. For vessel positioning, the semi-major axis of the a-posteriori horizontal error ellipse shall not exceed 5 metres for at least 90% of shot points on a line and shall not exceed 7 metres for more than 5% of shotpoints on a line. In instances when the Marginally Detectable Error (MDE) indicates a possible horizontal movement of greater than 5 metres, the positions will be carefully investigated and other pertinent QC parameters checked.. Data latency shall be better than 10 seconds. Computation update rates shall be better than 3 seconds. DGPS Network Minimum Requirements Contractor’s DGPS network shall meet all of the following minimum requirements: • A minimum of 4 reference stations shall be continuously monitored from the mobile site; • Reference stations and mobile station shall monitor the same satellite constellation; • There shall be at least one monitoring station which shall be continuously manned (such monitoring station may be located at a reference station); • Spares complement of 100% (preferably in "hot standby" mode) including emergency generating power, for each reference station and monitor station; • Spares complement at the mobile installation shall be 100% to include receivers, antennas, cabling, power supply and computer hardware and software; • Transmission formats shall adhere to recognised standards e.g. RTCM-104 (Radio Transmission Common Code); • Distances from the Operations area to individual reference stations shall be kept to a minimum; • For “Local” DGPS systems, maximum distance from reference stations to Operations area shall not be more than 2000 kilometres. Wide Area DGPS systems with multi-reference station options shall be considered on a case by case basis. • Satellite prediction software with latest updated almanac shall be available throughout the Operations. Such software shall be used to plan Operations and identify any poor coverage windows. • Contractor or its subcontractor shall make every effort to verify there are no additional users of equipment, operating in or near to the Operations area, which transmit on a frequency or frequencies, likely to impair the performance of the system. DGPS Performance Specifications The following specifications shall govern the operation of the DGPS. Individual records which do not meet these specifications shall be considered as a misfire: For Vessel Positioning: Whenever possible the maximum available number of healthy satellites which meet minimum elevation criteria shall be used in any computation. A multiple reference station derived position may be used

-49- subject to the above requirements. Height Aiding Height aiding (i.e. where the equipotential surface is treated as a pseudo position line) may only be used if: • the physical variation in antenna height due to tide, pitch, roll and heave, is less than 2 metres • an average ellipsoid height has been determined from a statistically analysed dataset of continuous readings whose standard deviations are less than 2 metres. • it's use is minimal and in any case for never more than 30 minutes on any single Survey line DGPS Requirements During Mobilisation During mobilisation if possible, Contractor’s DGPS system shall meet all of the following requirements: • Integrity Monitor Check (as detailed in 2.5 not found??) • During the verification the complete fully interfaced installation, to include all reference stations, Contractor's INS, all hardware and software shall be verified; • During mobilisation the DGPS shall be installed in the proposed configuration for the Operations while the vessel is stationary at the dockside where the differential corrections can be correctly received; • DGPS positions shall be determined over a period of 30 minutes of good satellite coverage • A scatter plot shall be produced showing the distribution about the coordinated location from which the following shall be determined and provided: • mean excursion eastings; • maximum excursion eastings • mean excursion northings; • maximum excursion northings; • mean excursion height; and • maximum excursion height. • A similar check may be required at the end of the Operations or at any time during the Operations if necessary or if requested by Company’s Quality Control Supervisor. If Contractor cannot meet the above mobilisation requirements an alternative method of DGPS system calibration, acceptable to the Company, shall be clearly delineated and executed by the Contractor. DGPS QC Checks and Tests Contractor shall conduct all of the following QC checks and tests on Contractor’s DGPS system: • As a matter of routine monitor station information concerning status and health of all satellites shall be continuously available and monitored; • Internally generated quality control indicators such as HDOP, GDOP, PDOP, VDOP shall be continuously available and monitored; Streamer Compasses Where streamer compasses are to be used for determination of streamer feathering the following shall apply: • the latest value of magnetic declination (horizontal intensity) to be used shall be obtained from either latest IGRF (International Geomagnetic Reference Field) published tables or from a recognised magnetic observatory, and/or • Contractor shall provide information on the most recent dynamic verification check. Towing Geometry When the required geometry has been established, towing wires and chains shall be marked to ensure the geometry remains the same following each deployment. Near trace offset (i.e. the linear distance between centre source and centre near trace) shall not vary by more than ± 1/2 group length unless such variation is as a result of tides and/or currents influencing

-50- towing characteristics. During mobilisation the following components shall be accurately measured and documented: Streamer front end: • lead in; • stretch sections; • gun locations and distances; 3.9 Ancillary Equipment The following minimum requirements shall apply to all of Contractor’s ancillary equipment. Gyro Compass Minimum Requirements The following minimum requirements apply to Contractor’s gyrocompass: • One or more units are required and shall be interfaced to the INS; • The unit shall be calibrated against a known azimuth, during mobilisation while the vessel is stationary at the dockside or using statistics derived from dynamic observations; • Dockside calibrations shall be undertaken by an experienced Surveyor. Each gyro heading shall agree with the Surveyed azimuth to within 0.5º; • No dockside calibration shall be started until the gyrocompass has been allowed to stabilise for 2 hours; • Additional calibrations shall be undertaken during the course of the Operations and at the end of the Operations if requested by Company’s Quality Control Supervisor; • Contractor shall provide historical information regarding previous gyro calibration results; Single Trace Recorder Minimum Requirements The following minimum requirements shall apply to Contractor’s single trace recorder: • As minimum Contractor shall provide a method for displaying near trace data throughout the Operations. Such system shall be able to be used to assist in the detection of source out of sequence firing in multi-source Operations. Shot Record Monitor Minimum Requirements The following minimum requirements shall apply to Contractor’s shot record monitor: • Contractor shall provide a means for monitoring and displaying all seismic channels from which dead, weak, or otherwise bad or noisy channels may be identified and the level of noise quantified; • Records shall be annotated with date, line number and shot number and shall be taken at the beginning and end of each line and at intervals of 1 kilometre or as requested by Company Designated Representative. Fathometer Minimum Requirements The following minimum requirements shall apply to Contractor’s fathometer: • A dual frequency digital fathometer shall be available throughout the Operations; • The unit shall be calibrated in accordance with manufacturer’s specifications; • Every opportunity shall be taken throughout the course of the Operations to verify fathometer accuracy during port calls and/or when crossing well locations; • A diagram showing location of fathometer transducer relative to the primary antenna or navigation reference point shall be provided. Sound Velocity Measures A properly calibrated and working system shall be available throughout the Operations to periodically determine velocity of sound in water (from surface to sea bed) for use with all acoustic devices and for

-51- processing purposes. 4 DELIVERABLES 4.1 Brute Stack: A processing sequence should be implemented such that a single brute stack is produced for each vessel pass, the choice of source and streamer should be rotated between lines. The processing sequence should be designed such that noise is not attenuated and a true representation of recorded data is presented. Such a processing sequence may include (without limitation) the following steps; Trace Decimation Gain Recovery DBS Swell Noise and Linear Noise attenuation NMO correction – using either a regional function supplied by the client Post NMO mute – picked by onboard contractor processing staff Stack Gun and Cable correction TVF Amplitude balancing and display 4.2 Shot Gathers: Every 20 shots (configurable) – viewed interactively online, every shot. 4.3 f-k Plots: Every 20 shots (configurable) Rectangular time/trace window selected by client 4.4 RMS Analysis: Computed in two rectangular time/trace windows. One of the time trace windows is further analysed in three frequency windows. 4.5 Low Fold Cube A processing sequence should be implemented to allow the production of a Low Fold Cube which will include the near trace. The low fold cube should be merged with available navigation data and processed to a time of 1.0 second TWT. 4.6 SEG D Header Analysis Multiple SegD header attributes. 4.7 SEG Y Deliverables Concatenated brute stacks in SEGY format. Single Trace Cube in SEGY format preferred trace is 3 or 4. 4.8 On Line Displays Brute stacks Attribute analysis to optionally include Header Attributes, RMS analysis attributes Shot gathers (optional shot increment) f-k Plots (optional shot increment) 4.10 Survey Data Deliverables Contractor shall provide the following on completion of the Operations:

-52- • Dual copies of all seismic field tapes. • Digital Copies of all observer’s logs and instrument test results in pdf format. • Dual copies of Post plotted positioning data tapes in UKOOA P1/90 format upon completion of seismic data acquisition; • Dual copies of All field raw positioning data tapes in UKOOA P2/94 format; • Six copies of final post mission report of all field activity in pdf format; and • Six copies of final post mission report of all navigation processing in pdf format. Positioning Post Processing Wherever possible Contractor shall process all positioning data onboard the Survey vessel and provide UKOOA P1/90 format tapes on completion of the work. Full quality control and processing of all positioning data is required. Contractor shall undertake additional QC as necessary at Contractor’s offices onshore, on lines, which have been identified as being problematic, by either Quality Control Supervisor. Contractor shall provide a full description of the equipment and algorithms used for the post plotting of all navigation and positioning data, together with a description of the quality control procedures for each phase of the processing. 5 OPERATIONS DATUM AND MAPPING PARAMETERS All navigation systems used during acquisition will be operated using WGS84 as the reference datum. Ancillary systems which may require to work on a plane will use the following projection on the reference spheroid. Projection : U.T.M. Zone : 52 S Central Meridian : 52 S Zone Width : 6° False Northing : 10,000,000 False Easting : 500,000 Scale Factor along C.M. : 0.9996

-53- 6 CMP BINNING REQUIREMENTS FOR 3D ACQUISITION The CMP binning system shall be capable of dividing each streamer into at least four equal (or near equal) segments to monitor offset distribution. The data shall be collected utilising flexible bins as specified below. Each of the selected segments of each streamer shall contain the full number of unique offset traces as specified below. The binning system shall utilise suitable graphical display capabilities so as far as to ensure that the required offset CMP distribution specifications have been achieved. Cell flex is defined herein as the distance from the bin centre to the edge of the flexed cell, i.e. for a 25 metre bin width, a 100% flex is defined as each side of the cell being flexed by 12.5 metres (giving a total flexed cell width from edge to edge of 50 metres). The following set of bin flexing parameters will be applied. The spread will be steered to maximise the coverage on the Near Segment. Binning Parameters Streamer Segments Nears Near / Mids Far / Mids Far Offset Range (metres) 0 - 1500 1500 - 3000 3000 - 4500 4500 – 6000 Nominal Fold Coverage 20 fold 20 fold 20 fold 20 fold Flex Binning Technique Linear taper Linear taper Linear taper Linear taper Static Bin Width 25 metres 25 metres 25 metres 25 metres Flex at beginning of Segment 100% 150% 220% 320% Flex at end of Segment 150% 225% 320% 450% Near Trace Bin Width (Flexed) 50 metres 62.5 metres 81.25 metres 105 metres Far Trace Bin Width (Flexed) 62.5 metres 81.25 metres 105 metres 137.5 metres Coverage Parameters (with Flex applied) Coverage (%) Minimum Fold Near trace coverage ≥90% 18 Near-Mid trace coverage ≥80% 16 Near-Far trace coverage ≥70% 14 Far trace coverage ≥60% 12 Total 60

-54- ANNEXURE E AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES OPERATIONS MAP AND COORDINATES The following map and coordinates are subject to the final results of the migration aperture study. 195 SQUARE KILOMETRES 3D BOUNDARY COORDINATES E N Latitude Longitude 537523 8826166 10 37 07.11 S 129 20 34.95 E 537523 8817716 10 41 42.26 S 129 20 35.26 E 556432 8817716 10 41 41.40 S 129 30 57.73 E 556432 8818977 10 41 00.32 S 129 30 57.66 E 561124 8818977 10 41 00.06 S 129 33 32.11 E 561124 8826166 10 37 06.00 S 129 33 31.68 E 3 x 2D LINES 105 KILOMETRES FULL FOLD IN TOTAL E N Latitude Longitude Line 1 599610 8848628 10 24 51.79 S 129 54 36.10 E 608036 8823925 10 38 15.16 S 129 59 15.76 E Line 2 605193 8823244 10 38 37.62 S 129 57 42.2 E 606610 8849685 10 24 16.70 S 129 58 26.2 E Line 3 609747 8831646 10 34 03.63 S 130 00 11.25 E 557959 8824039 10 38 15.44 S 129 31 47.65 E BEGULA-1 WELL LOCATION E N Latitude Longitude 605608 8831150 10 34 20.20S 129 57 55.12E

-55- ANNEXURE F AGREEMENT FOR 2D AND 3D DATA ACQUISITION SERVICES HSE REQUIREMENTS 1.1 All activities will be carried out in accordance with the Company’s Environmental Plan for the Operations. If the Company employs a Marine Mammal Observer(s) to implement the Environmental Plan then all Contractor staff must accept the authority of the Marine Mammal Observer on matters involving marine mammals. 1.2 All activities will be carried out in accordance with the Project Management Plan, which will be developed by the Contractor and approved by the Company prior to commencement of the Operations. 1.3 Without limiting or in any way affecting the obligations of the Contractor to perform the Services, the Contractor shall comply with all legislative and Company health, safety and environment requirements relating to the safety of persons in relation to the provision of the Services in relation to the services. 1.4 The Contractor shall: (a) take necessary and reasonably practicable precautions to ensure the safety and health of its employees, Consultants, Subcontractors, suppliers, or any other person who may work on the data acquisition or any other place where Services under this Agreement are being performed, and shall take the same precautions in respect of all Company employees, agents, consultants, separate contractors, members of the public and any third party; (b) before commencing any work on data acquisition, provide and obtain Company’s approval of a HSE Policy and Management System which: (i) includes a risk assessment based on Oil & Gas Industry standard of activities to be performed to determine areas of risk, their level based upon an assessment and mitigation strategies to reduce the level of risk to ALARP (as low as reasonably practicable). A copy of the risk register is to be supplied to Company as well as updates against Risk Register actions including reports on progress of closure of actions; (ii) details how the Contractor will comply with its HSE obligations under the Services Agreement and in particular this Schedule; (iii) is consistent with Company's HSE Policies; (iv) is applied to all work performed under this agreement and which is incorporated into all subcontracts entered into by the Contractor; and (v) details the management structure for the Services including the management of subcontractor relationships. (c) maintain and administer the HSE Policy and management system to discharge its safety obligations under this Agreement and in particular this Schedule; (d) institute an induction program approved by Company to ensure all employees, consultants, subcontractors, suppliers, separate contractors and any other person visiting or performing work on or near the Operations Area receive appropriate instruction in relation to health and safety issues, the Safety Management Plan and any HSE protocols prepared by the Contractor; (e) if requested by the Company’s Designated Representative, be responsible for the preparation of a HSE audit schedule in consultation with Company and,

-56- (i) provide Company with the option to participate as an observer during HSEMS audits, and (ii) supply Company with a copy of the report. (f) Notwithstanding the above audit requirements, Company reserves the right to conduct system audits and/or random audits of the Contractor’s HSEMS; (g) maintain and provide to the Company’s Designated Representative (or any person nominated by him or her in writing), if so requested, all documentary evidence that the Contractor has developed and implemented such safety protocols, plans, induction programs and training programs required in order to discharge the Contractor's obligations under this Agreement in particular this Schedule; (h) immediately discontinue any practice or remove any equipment considered by the Company’s Designated Representative to be dangerous; (i) promptly remove from the survey vessel or project any person employed by the Contractor who Company requests to be removed; (j) ensure that all necessary and adequate supervision is provided at all times to ensure compliance with Legislative Requirements and this Agreement; (k) comply with any reasonable direction given by the Company’s Designated Representative to improve or rectify the Contractor's safety precautions; (l) provide prompt and thorough incident reporting to Company and facilitate any requirement by Company to investigate an incident. The transfer of information between the Contractor and Company, which shall: (i) in the first instance, and as soon as possible after the incident event becomes known to the Contractor but not later than 4 hours after the event, be reported verbally to the Company’s Designated Representative ; and (ii) be followed up in writing using an agreed format within 1 business day of the initial notification; and (iii) be the subject to an investigation of a standard approved by Company with the outcome of such investigation being provided to Company, (iv) include written reporting and plans detailing measures to prevent future occurrence and to rectify any deficiencies identified during the investigation. (m) shall comply with the relevant Acts and Regulations in relation to injury management and rehabilitation and put a system in place to manage the rehabilitation and return to work of injured persons; (n) introduce an inspection program that maintains high standards of workplace housekeeping. 1.5 HSE performance data is to be provided by the Contractor to Company at the end of the Operations. This information shall include, but not be limited to the following: - Number of employees - Number of contractors - Hours worked by (a) employees and (b) contractors;

-57- - Number of inductions; - Number of Lost Time Cases (LTC) as agreed by Company; - Number of Return to Work Cases (RWC) as above; - Number of Medical Treatment Cases (MTC) as above; - Number of First Aid cases (as above); - Number of Near Misses (as above); - Number of Hazard reports lodged. From time to time Company may require additional information to be provided in such reports.

-58- ANNEXURE G LINE COORDINATES FARFIELD SIGNATURE LISTING Farfield signature was generated by Nucleus+ version 2.1.0 Farfield signature was generated by Marine source modelling version 1.5.0 Name of farfield dataset : 3080_050_2000 Source array name : 3080_050_2000 Total array volume (cu.in.) : 3080.0 Source average depth (m) : 5.0 Average pressure (psi) : 2000.0 Ghost strength : -1.00 Primary amplitude (bar m) : 44.82 Peak-peak amplitude (bar m) : 91.67 Pulse/Bubble ratio : 25.74 Bubble period (+) (ms) : 98.88 Bubble period (-) (ms) : 164.62 Geometrical spreading : 2.00 Sea water temperature (C) : 20.0 Sea water velocity (m/s) : 1521.6 Filter parameters Filter type : Sercel SEAL mp_3/6-200/370 Low cut frequency (Hz) : 3.0 High cut frequency (Hz) : 200.0 Low cut slope (dB/oct) : 6.0 High cut slope (dB/oct) : 370.0 Start time (ms) : -64.0 Index of time zero : 129 Sample interval (ms) : 0.5 Farfield position Farfield distance (m) : 9000.0 Dip angle (degrees) : 0.0 Azimuth angle (degrees) : 0.0 Amplitudes are in bar m Time is increasing horizontally 0.000 0.000 0.000 0.000 0.000 0.000 -0.000 -0.000 -0.000 0.000 0.000 0.000 0.000 0.000 -0.000 -0.000 -0.000 -0.000 -0.000 0.000 0.000 0.000 0.000 0.000 -0.000 -0.000 -0.001 -0.001 -0.000 0.000 0.001 0.002 0.002 0.001 -0.001 -0.002 -0.003 -0.003 -0.001 0.002 0.005 0.006 0.005 0.002 -0.004 -0.009 -0.011 -0.009 -0.002 0.008 0.017 0.019 0.014 0.001 -0.016 -0.029 -0.031 -0.020 0.002 0.029 0.047 0.049 0.028 -0.009 -0.049 -0.076 -0.073 -0.037 0.022 0.082 0.117 0.106 0.046 -0.045 -0.131 -0.175 -0.148 -0.052 0.083 0.204 0.254 0.201 0.052 -0.144 -0.307 -0.361 -0.265 -0.039 0.237 0.450 0.499 0.338 0.007 -0.375 -0.647 -0.678 -0.419 0.058 0.575 0.915 0.906 0.503 -0.172 -0.865 -1.280 -1.198 -0.587 0.363 1.289 1.789 1.586 0.665 -0.681 -1.935 -2.541 -2.135 -0.727 1.244 3.023

-59- 3.800 3.035 0.728 -2.469 -5.378 -6.608 -4.996 -0.002 8.053 18.022 28.222 36.885 42.636 44.824 43.607 39.770 34.353 28.244 21.879 15.170 7.679 -1.035 -11.046 -21.819 -32.201 -40.676 -45.794 -46.629 -43.108 -36.082 -27.117 -18.066 -10.574 -5.662 -3.529 -3.626 -4.937 -6.379 -7.156 -6.969 -6.022 -4.836 -3.988 -3.851 -4.452 -5.484 -6.446 -6.855 -6.434 -5.209 -3.488 -1.730 -0.375 0.307 0.296 -0.203 -0.862 -1.359 -1.496 -1.252 -0.767 -0.259 0.070 0.113 -0.106 -0.458 -0.769 -0.892 -0.768 -0.433 -0.004 0.377 0.599 0.617 0.464 0.228 0.014 -0.099 -0.081 0.044 0.213 0.357 0.427 0.410 0.330 0.232 0.165 0.157 0.212 0.307 0.407 0.479 0.504 0.481 0.429 0.373 0.337 0.331 0.355 0.397 0.438 0.467 0.475 0.465 0.448 0.433 0.428 0.438 0.458 0.482 0.502 0.514 0.516 0.511 0.504 0.500 0.501 0.509 0.520 0.533 0.543 0.551 0.555 0.557 0.559 0.562 0.568 0.576 0.585 0.593 0.600 0.606 0.610 0.614 0.618 0.623 0.629 0.636 0.642 0.649 0.655 0.660 0.665 0.670 0.676 0.682 0.688 0.694 0.700 0.706 0.711 0.716 0.722 0.727 0.733 0.738 0.744 0.750 0.755 0.760 0.765 0.770 0.775 0.781 0.787 0.793 0.798 0.803 0.806 0.808 0.808 0.807 0.804 0.801 0.798 0.794 0.791 0.788 0.785 0.783 0.783 0.783 0.786 0.790 0.796 0.804 0.813 0.823 0.834 0.844 0.855 0.865 0.874 0.884 0.894 0.904 0.914 0.925 0.935 0.945 0.954 0.963 0.971 0.978 0.985 0.991 0.996 1.000 1.004 1.006 1.008 1.008 1.008 1.006 1.003 0.999 0.995 0.990 0.984 0.978 0.972 0.965 0.958 0.951 0.944 0.937 0.930 0.924 0.918 0.911 0.904 0.897 0.889 0.879 0.869 0.857 0.844 0.828 0.811 0.792 0.771 0.747 0.722 0.695 0.666 0.635 0.604 0.573 0.542 0.511 0.483 0.455 0.431 0.409 0.390 0.374 0.360 0.350 0.341 0.334 0.328 0.321 0.314 0.305 0.294 0.279 0.260 0.237 0.208 0.174 0.134 0.089 0.039 -0.016 -0.075 -0.136 -0.199 -0.262 -0.324 -0.383 -0.437 -0.485 -0.526 -0.557 -0.577 -0.588 -0.587 -0.577 -0.556 -0.527 -0.490 -0.446 -0.398 -0.345 -0.289 -0.231 -0.172 -0.114 -0.056 0.001 0.056 0.110 0.162 0.214 0.264 0.314 0.362 0.410 0.456 0.500 0.543 0.583 0.621 0.656 0.690 0.721 0.751 0.778 0.802 0.824 0.843 0.859 0.872 0.882 0.889 0.894 0.897 0.896 0.893 0.885 0.872 0.852 0.825 0.790 0.743 0.684 0.610 0.520 0.410 0.280 0.127 -0.048 -0.243 -0.456 -0.682 -0.918 -1.156 -1.390 -1.614 -1.824 -2.012 -2.176 -2.312 -2.417 -2.492 -2.536 -2.552 -2.542 -2.510 -2.462 -2.401 -2.333 -2.262 -2.191 -2.121 -2.056 -1.993 -1.935 -1.879 -1.825 -1.771 -1.719 -1.665 -1.610 -1.553 -1.493 -1.430 -1.364 -1.296 -1.226 -1.154 -1.083 -1.012 -0.942 -0.875 -0.809 -0.746 -0.687 -0.630 -0.576 -0.525 -0.478 -0.434 -0.393 -0.355 -0.320 -0.287 -0.256 -0.229 -0.203 -0.181 -0.160 -0.143 -0.128 -0.115 -0.104 -0.095 -0.089 -0.084 -0.082 -0.081 -0.083 -0.086 -0.091 -0.098 -0.105 -0.114 -0.122 -0.131 -0.139 -0.147 -0.154 -0.160 -0.164 -0.168 -0.169 -0.169 -0.167 -0.164 -0.159 -0.152 -0.144 -0.135 -0.125

-60- -0.114 -0.102 -0.090 -0.077 -0.064 -0.051 -0.037 -0.023 -0.009 0.005 0.018 0.032 0.046 0.059 0.073 0.086 0.098 0.111 0.123 0.135 0.147 0.158 0.169 0.179 0.189 0.199 0.208 0.217 0.225 0.233 0.241 0.248 0.255 0.261 0.267 0.272 0.278 0.282 0.286 0.290 0.294 0.297 0.299 0.301 0.303 0.304 0.305 0.306 0.306 0.305 0.304 0.303 0.301 0.298 0.296 0.292 0.288 0.284 0.279 0.274 0.269 0.262 0.256 0.249 0.241 0.233 0.224 0.215 0.205 0.195 0.184 0.173 0.161 0.149 0.137 0.125 0.112 0.100 0.088 0.075 0.063 0.052 0.040 0.029 0.019 0.010 0.001 -0.008 -0.015 -0.022 -0.028 -0.032 -0.036 -0.039 -0.041 -0.043 -0.043 -0.042 -0.041 -0.038 -0.035 -0.031 -0.027 -0.022 -0.016 -0.009 -0.003 0.005 0.012 0.021 0.029 0.038 0.047 0.056 0.066 0.076 0.086 0.096 0.106 0.116 0.126 0.137 0.147 0.157 0.167 0.178 0.188 0.198 0.208 0.218 0.228 0.237 0.247 0.257 0.266 0.276 0.285 0.294 0.303 0.312 0.321 0.330 0.338 0.347 0.356 0.364 0.373 0.381 0.389 0.397 0.405 0.414 0.422 0.430 0.438 0.446 0.454 0.462 0.470 0.477 0.485 0.493 0.501 0.508 0.516 0.523 0.531 0.538 0.545 0.551 0.558 0.564 0.570 0.576 0.581 0.586 0.590 0.593 0.596 0.599 0.600 0.601 0.600 0.599 0.597 0.593 0.589 0.583 0.575 0.567 0.557 0.546 0.533 0.519 0.504 0.487 0.469 0.449 0.428 0.406 0.382 0.357 0.332 0.305 0.278 0.250 0.221 0.192 0.163 0.134 0.105 0.076 0.047 0.018 -0.010 -0.039 -0.068 -0.097 -0.126 -0.154 -0.183 -0.211 -0.240 -0.267 -0.294 -0.320 -0.345 -0.369 -0.392 -0.414 -0.434 -0.453 -0.470 -0.486 -0.501 -0.515 -0.528 -0.540 -0.551 -0.562 -0.572 -0.581 -0.591 -0.599 -0.607 -0.615 -0.622 -0.629

-61- DROPOUT SIGNATURE DROPOUT SIGNATURE STATISTICS FILE File format number : 5 Statistics created by Nucleus+ version 2.1.0 Statistics created by Marine source modelling version 1.5.0 User reference : Computed dropout signature statistics. Correlation measure : Cross correlation. Project name : Voyager Dropout signature dataset : 3080_050_ALL_DropOut_Listing Dropout array name : 3080_050_DO_2000 Reference array name : 3080_050_DO_2000 Instrument filter : Sercel SEAL mp_3/6-200/370 Primary pick window (ms) : -64.00 - 30.00 Bubble pick window (ms) : 50.00 - 200.00 Amplitude option : Positive peak amplitude. Frequency analysis option : Average absolute spectral deviation. Bandwidth of analysis (Hz) : 10.00 - 70.00 Water velocity (m/s) : 1521.65 Water temperature (C) : 20.00 Reflection coefficient : -1.00 Farfield dip angle (deg) : 0.00 Farfield azimuth (deg) : 0.00 Farfield distance (m) : 9000.00 In the table below : Peak - Primary positive peak amplitude %ch - Percentage change P/B - Primary/Bubble ratio X-cor - Cross correlation coefficient (normalized) AvgdB - Average absolute deviation (dB) MaxdB - Maximum absolute deviation (dB) (Negative gun number means activated spare gun) Index Dropped gun numbers Gun volumes Peak %ch P/B %ch X-cor AvgdB MaxdB 1 Full Array 0 45.8 0 28.4 0 1 0 0 2 1 1 100 44.2 -3.5 30.2 6.5 0.9996 0.33 -1 3 1 2 100 44.3 -3.4 30 5.7 0.9996 0.32 -1 4 1 3 110 44.3 -3.3 26.1 -8.1 0.9996 0.22 0.5 5 1 4 250 44 -4.1 28.8 1.6 0.9955 0.77 -3.6 6 1 5 250 44 -4 29.6 4.3 0.9955 0.77 -3.6 7 1 6 150 44.4 -3.2 33.3 17.5 0.9994 0.33 1.6 8 1 7 150 44.4 -3.1 33.5 18.1 0.9994 0.32 1.6 9 1 8 40 45 -1.7 27.8 -1.9 0.9997 0.07 0.2 10 1 9 90 44.2 -3.7 25.7 -9.3 0.9997 0.23 0.6 11 1 10 150 44 -4 25 -11.9 0.9989 0.48 -2.3 12 1 11 150 44 -4 24.8 -12.6 0.9989 0.48 -2.4 13 2 1 100 44.3 -3.4 30 5.7 0.9996 0.32 -1 14 2 2 100 44.2 -3.5 30.2 6.5 0.9996 0.33 -1 15 2 3 110 44.3 -3.3 26.1 -8.1 0.9996 0.22 0.5 16 2 4 250 44 -4 29.6 4.3 0.9955 0.77 -3.6 17 2 5 250 44 -4.1 28.8 1.6 0.9955 0.77 -3.6

-62- Index Dropped gun numbers Gun volumes Peak %ch P/B %ch X-cor AvgdB MaxdB 18 2 6 150 44.4 -3.1 33.5 18.1 0.9994 0.32 1.6 19 2 7 150 44.4 -3.2 33.3 17.5 0.9994 0.33 1.6 20 2 8 40 45 -1.7 27.8 -1.9 0.9997 0.07 0.2 21 2 9 90 44.2 -3.7 25.7 -9.3 0.9997 0.23 0.6 22 2 10 150 44 -4 24.8 -12.6 0.9989 0.48 -2.4 23 2 11 150 44 -4 25 -11.9 0.9989 0.48 -2.3 24 1 1 1 2 100 100 42 -8.4 26.4 -6.9 0.9995 0.66 1.3 25 1 1 1 3 100 110 42.6 -7.1 25.1 -11.6 0.9992 0.56 1.4 26 1 1 1 4 100 250 42.4 -7.6 30.9 9.1 0.9959 0.93 -3.2 27 1 1 1 5 100 250 42.4 -7.5 30.5 7.7 0.9958 0.93 -3.2 28 1 1 1 6 100 150 42.8 -6.6 34.4 21.2 0.9994 0.54 1 29 1 1 1 7 100 150 42.8 -6.5 34.5 21.8 0.9994 0.53 1 30 1 1 1 8 100 40 43.5 -5.2 30 5.9 0.9992 0.38 1.1 31 1 1 1 9 100 90 42.6 -7.1 30.5 7.5 0.9993 0.52 1.1 32 1 1 1 10 100 150 42.4 -7.5 28.4 0.3 0.9987 0.73 3 33 1 1 1 11 100 150 42.4 -7.5 28.3 -0.1 0.9986 0.73 3 34 1 1 2 1 100 100 42.7 -6.9 23.4 -17.4 0.9982 0.67 2 35 1 1 2 2 100 100 42.6 -7 23.6 -16.8 0.9983 0.67 2 36 1 1 2 3 100 110 42.7 -6.7 28 -1.2 0.9992 0.52 1.5 37 1 1 2 4 100 250 42.4 -7.5 28.3 -0.1 0.995 0.96 -3.6 38 1 1 2 5 100 250 42.4 -7.6 27.8 -1.9 0.9951 0.97 -3.5 39 1 1 2 6 100 150 42.8 -6.6 36.6 29 0.9992 0.54 1.1 40 1 1 2 7 100 150 42.8 -6.6 36.4 28.3 0.9992 0.55 1.1 41 1 1 2 8 100 40 43.5 -5.2 30.1 6 0.9992 0.38 1.2 42 1 1 2 9 100 90 42.6 -7.1 30.5 7.6 0.9993 0.51 1.1 43 1 1 2 10 100 150 42.4 -7.5 28.1 -0.8 0.9986 0.72 3 44 1 1 2 11 100 150 42.4 -7.5 28.2 -0.4 0.9987 0.73 3 45 1 2 1 3 100 110 42.6 -7 24.9 -12.1 0.9991 0.55 1.4 46 1 2 1 4 100 250 42.4 -7.5 31 9.2 0.9959 0.92 -3.2 47 1 2 1 5 100 250 42.4 -7.4 30.6 7.8 0.9958 0.91 -3.2 48 1 2 1 6 100 150 42.8 -6.6 34.2 20.8 0.9994 0.53 1 49 1 2 1 7 100 150 42.9 -6.5 34.4 21.4 0.9993 0.52 1 50 1 2 1 8 100 40 43.5 -5.1 29.8 5.2 0.9991 0.37 1.1 51 1 2 1 9 100 90 42.6 -7.1 30.3 6.7 0.9992 0.51 1.1 52 1 2 1 10 100 150 42.4 -7.4 30 5.9 0.9987 0.72 3 53 1 2 1 11 100 150 42.5 -7.4 28.3 -0.3 0.9986 0.71 3 54 1 2 2 1 100 100 42.7 -6.8 23.3 -17.8 0.9981 0.66 2 55 1 2 2 2 100 100 42.7 -6.9 23.4 -17.4 0.9982 0.67 2 56 1 2 2 3 100 110 42.8 -6.7 28 -1.2 0.9991 0.51 1.5 57 1 2 2 4 100 250 42.4 -7.5 28.4 0 0.9949 0.95 -3.6 58 1 2 2 5 100 250 42.4 -7.5 27.8 -2.1 0.995 0.96 -3.5 59 1 2 2 6 100 150 42.9 -6.5 36.3 28.1 0.9991 0.53 1.1 60 1 2 2 7 100 150 42.8 -6.6 36.3 27.9 0.9992 0.54 1.1 61 1 2 2 8 100 40 43.5 -5.1 29.9 5.3 0.9991 0.37 1.2 62 1 2 2 9 100 90 42.6 -7 30.3 6.9 0.9992 0.51 1.1 63 1 2 2 10 100 150 42.5 -7.4 28 -1.1 0.9986 0.71 3 64 1 2 2 11 100 150 42.4 -7.4 29.8 5 0.9987 0.72 3 65 1 3 1 4 110 250 42.2 -7.8 31 9.5 0.9955 0.93 -3.2 66 1 3 1 5 110 250 42.3 -7.8 30.6 8 0.9954 0.92 -3.3 67 1 3 1 6 110 150 42.9 -6.4 33.6 18.5 0.9987 0.54 2 68 1 3 1 7 110 150 42.9 -6.4 33.7 19 0.9986 0.53 2 69 1 3 1 8 110 40 43.6 -4.9 25.8 -9.1 0.9987 0.29 0.6 70 1 3 1 9 110 90 42.7 -6.9 26.2 -7.5 0.9988 0.45 0.9 71 1 3 1 10 110 150 42.5 -7.3 23.1 -18.5 0.9984 0.69 2.3 72 1 3 1 11 110 150 42.5 -7.3 22.9 -19.1 0.9982 0.68 2.4 73 1 3 2 1 110 100 42.8 -6.7 28 -1.2 0.9991 0.51 1.5 74 1 3 2 2 110 100 42.7 -6.7 28 -1.2 0.9992 0.52 1.5 75 1 3 2 3 110 110 42.8 -6.5 23.7 -16.5 0.9985 0.45 1 76 1 3 2 4 110 250 42.5 -7.3 28.3 -0.1 0.9947 0.91 -3.6 77 1 3 2 5 110 250 42.5 -7.4 27.6 -2.5 0.9948 0.91 -3.5 78 1 3 2 6 110 150 42.9 -6.3 29.4 3.6 0.9985 0.53 1.9

-63- Index Dropped gun numbers Gun volumes Peak %ch P/B %ch X-cor AvgdB MaxdB 79 1 3 2 7 110 150 42.9 -6.4 29.2 3.1 0.9986 0.53 1.9 80 1 3 2 8 110 40 43.6 -5 25.5 -10.1 0.9987 0.29 0.6 81 1 3 2 9 110 90 42.7 -6.9 26 -8.5 0.9988 0.45 0.8 82 1 3 2 10 110 150 42.5 -7.2 22.7 -19.8 0.9982 0.68 2.4 83 1 3 2 11 110 150 42.5 -7.3 22.9 -19.2 0.9983 0.69 2.3 84 1 4 1 5 250 250 41.8 -8.8 34.4 21.4 0.9974 0.81 3.1 85 1 4 1 6 250 150 42.4 -7.6 21.2 -25.2 0.995 0.94 4.2 86 1 4 1 7 250 150 42.4 -7.4 20.5 -27.5 0.995 0.92 4.3 87 1 4 1 8 250 40 43.2 -5.9 27.7 -2.4 0.9951 0.81 -3.5 88 1 4 1 9 250 90 42.3 -7.7 26 -8.1 0.9947 0.96 3.8 89 1 4 1 10 250 150 42.1 -8.1 25.6 -9.7 0.9949 1.02 3.7 90 1 4 1 11 250 150 42.1 -8.1 25.5 -10 0.9949 1.01 3.6 91 1 4 2 1 250 100 42.4 -7.5 27.8 -2.1 0.995 0.96 -3.5 92 1 4 2 2 250 100 42.4 -7.6 27.8 -1.9 0.9951 0.97 -3.5 93 1 4 2 3 250 110 42.5 -7.4 27.6 -2.5 0.9948 0.91 -3.5 94 1 4 2 4 250 250 42.1 -8.1 10.9 -61.6 0.9774 1.68 7.6 95 1 4 2 5 250 250 42.1 -8.2 10.7 -62.1 0.9774 1.69 7.7 96 1 4 2 6 250 150 42.5 -7.2 26.8 -5.5 0.9927 1.03 5.5 97 1 4 2 7 250 150 42.5 -7.3 26.6 -6.3 0.9927 1.04 5.5 98 1 4 2 8 250 40 43.2 -5.8 28.2 -0.5 0.9951 0.81 -3.5 99 1 4 2 9 250 90 42.3 -7.7 26.3 -7.4 0.9947 0.95 3.9 100 1 4 2 10 250 150 42.1 -8.1 25.4 -10.5 0.9945 1.04 3.6 101 1 4 2 11 250 150 42.1 -8.1 25.3 -10.7 0.9946 1.04 3.7 102 1 5 1 6 250 150 42.4 -7.4 20 -29.5 0.9948 0.93 4.4 103 1 5 1 7 250 150 42.4 -7.4 20.2 -28.6 0.9947 0.93 4.3 104 1 5 1 8 250 40 43.2 -5.8 28.3 -0.1 0.9949 0.81 -3.5 105 1 5 1 9 250 90 42.3 -7.7 26.4 -6.7 0.9946 0.95 3.9 106 1 5 1 10 250 150 42.1 -8.1 26.1 -7.8 0.995 1.01 3.8 107 1 5 1 11 250 150 42.2 -8 26.1 -8.1 0.9949 1 3.7 108 1 5 2 1 250 100 42.4 -7.5 28.4 0 0.9949 0.95 -3.6 109 1 5 2 2 250 100 42.4 -7.5 28.3 -0.1 0.995 0.96 -3.6 110 1 5 2 3 250 110 42.5 -7.3 28.3 -0.1 0.9947 0.91 -3.6 111 1 5 2 4 250 250 42.1 -8 11 -61.1 0.9774 1.66 7.6 112 1 5 2 5 250 250 42.1 -8.1 10.9 -61.6 0.9774 1.68 7.6 113 1 5 2 6 250 150 42.6 -7.1 27.6 -2.6 0.9926 1.02 5.5 114 1 5 2 7 250 150 42.5 -7.2 27.4 -3.3 0.9926 1.03 5.6 115 1 5 2 8 250 40 43.2 -5.8 29 2.2 0.9949 0.81 -3.6 116 1 5 2 9 250 90 42.3 -7.7 26.8 -5.5 0.9946 0.95 4 117 1 5 2 10 250 150 42.2 -8 25.9 -8.8 0.9945 1.03 3.7 118 1 5 2 11 250 150 42.1 -8 25.8 -8.9 0.9945 1.04 3.8 119 1 6 1 7 150 150 42.5 -7.2 36.2 27.7 0.9985 0.6 2 120 1 6 1 8 150 40 43.4 -5.3 32.5 14.7 0.9989 0.41 1.8 121 1 6 1 9 150 90 42.7 -6.8 27.5 -3 0.9989 0.54 2.2 122 1 6 1 10 150 150 42.5 -7.2 26.9 -5.3 0.9982 0.76 -2.2 123 1 6 1 11 150 150 42.6 -7.1 26.6 -6.3 0.9981 0.75 -2.3 124 1 6 2 1 150 100 42.8 -6.6 36.3 27.9 0.9992 0.54 1.1 125 1 6 2 2 150 100 42.8 -6.6 36.4 28.3 0.9992 0.55 1.1 126 1 6 2 3 150 110 42.9 -6.4 29.2 3.1 0.9986 0.53 1.9 127 1 6 2 4 150 250 42.5 -7.2 27.4 -3.3 0.9926 1.03 5.6 128 1 6 2 5 150 250 42.5 -7.3 26.6 -6.3 0.9927 1.04 5.5 129 1 6 2 6 150 150 43 -6.2 31.6 11.4 0.9973 0.66 3.6 130 1 6 2 7 150 150 42.9 -6.3 31.4 10.7 0.9974 0.67 3.6 131 1 6 2 8 150 40 43.6 -4.9 32.3 13.9 0.9988 0.39 1.8 132 1 6 2 9 150 90 42.7 -6.8 33.3 17.6 0.9988 0.53 2.3 133 1 6 2 10 150 150 42.6 -7.2 26.2 -7.6 0.9982 0.75 -2.2 134 1 6 2 11 150 150 42.5 -7.2 26.4 -6.8 0.9983 0.75 -2.1 135 1 7 1 8 150 40 43.5 -5.2 32.7 15.2 0.9987 0.4 1.8 136 1 7 1 9 150 90 42.7 -6.8 27.6 -2.6 0.9987 0.53 2.2 137 1 7 1 10 150 150 42.6 -7.1 26.9 -5.1 0.9982 0.75 -2.3 138 1 7 1 11 150 150 42.6 -7.1 26.6 -6.1 0.9981 0.75 -2.4 139 1 7 2 1 150 100 42.9 -6.5 36.3 28.1 0.9991 0.53 1.1

-64- Index Dropped gun numbers Gun volumes Peak %ch P/B %ch X-cor AvgdB MaxdB 140 1 7 2 2 150 100 42.8 -6.6 36.6 29 0.9992 0.54 1.1 141 1 7 2 3 150 110 42.9 -6.3 29.4 3.6 0.9985 0.53 1.9 142 1 7 2 4 150 250 42.6 -7.1 27.6 -2.6 0.9926 1.02 5.5 143 1 7 2 5 150 250 42.5 -7.2 26.8 -5.5 0.9927 1.03 5.5 144 1 7 2 6 150 150 43 -6.2 31.8 12.1 0.9972 0.65 3.6 145 1 7 2 7 150 150 43 -6.2 31.6 11.4 0.9973 0.66 3.6 146 1 7 2 8 150 40 43.6 -4.8 32.4 14.4 0.9987 0.38 1.8 147 1 7 2 9 150 90 42.7 -6.7 33.5 18.1 0.9987 0.52 2.3 148 1 7 2 10 150 150 42.6 -7.1 26.3 -7.3 0.9981 0.74 -2.3 149 1 7 2 11 150 150 42.6 -7.1 26.5 -6.6 0.9982 0.74 -2.2 150 1 8 1 9 40 90 43.1 -6 24.7 -12.8 0.9987 0.35 0.8 151 1 8 1 10 40 150 43.2 -5.8 24.8 -12.5 0.9986 0.55 -2.3 152 1 8 1 11 40 150 43.2 -5.7 24.6 -13.2 0.9985 0.55 -2.3 153 1 8 2 1 40 100 43.5 -5.1 29.9 5.3 0.9991 0.37 1.2 154 1 8 2 2 40 100 43.5 -5.2 30.1 6 0.9992 0.38 1.2 155 1 8 2 3 40 110 43.6 -5 25.5 -10.1 0.9987 0.29 0.6 156 1 8 2 4 40 250 43.2 -5.8 29 2.2 0.9949 0.81 -3.6 157 1 8 2 5 40 250 43.2 -5.8 28.2 -0.5 0.9951 0.81 -3.5 158 1 8 2 6 40 150 43.6 -4.8 32.4 14.4 0.9987 0.38 1.8 159 1 8 2 7 40 150 43.6 -4.9 32.3 13.9 0.9988 0.39 1.8 160 1 8 2 8 40 40 44.3 -3.4 27.3 -3.8 0.9988 0.14 0.4 161 1 8 2 9 40 90 43.4 -5.4 25.3 -10.8 0.9988 0.3 0.8 162 1 8 2 10 40 150 43.2 -5.7 24.3 -14.2 0.9985 0.54 -2.3 163 1 8 2 11 40 150 43.2 -5.8 24.5 -13.5 0.9986 0.55 -2.3 164 1 9 1 10 90 150 42.1 -8.1 23.8 -16.1 0.9989 0.71 -1.9 165 1 9 1 11 90 150 42.2 -8 23.7 -16.4 0.9987 0.71 -2 166 1 9 2 1 90 100 42.6 -7 30.3 6.9 0.9992 0.51 1.1 167 1 9 2 2 90 100 42.6 -7.1 30.5 7.6 0.9993 0.51 1.1 168 1 9 2 3 90 110 42.7 -6.9 26 -8.5 0.9988 0.45 0.8 169 1 9 2 4 90 250 42.3 -7.7 26.8 -5.5 0.9946 0.95 4 170 1 9 2 5 90 250 42.3 -7.7 26.3 -7.4 0.9947 0.95 3.9 171 1 9 2 6 90 150 42.7 -6.7 33.5 18.1 0.9987 0.52 2.3 172 1 9 2 7 90 150 42.7 -6.8 33.3 17.6 0.9988 0.53 2.3 173 1 9 2 8 90 40 43.4 -5.4 25.3 -10.8 0.9988 0.3 0.8 174 1 9 2 9 90 90 42.5 -7.3 24.7 -12.8 0.9988 0.48 1.2 175 1 9 2 10 90 150 42.3 -7.7 24.5 -13.5 0.9985 0.69 -2.2 176 1 9 2 11 90 150 42.3 -7.7 24.7 -12.9 0.9986 0.69 -2.1 177 1 10 1 11 150 150 41.5 -9.5 23.9 -15.6 0.9994 0.85 2 178 1 10 2 1 150 100 42.4 -7.4 29.8 5 0.9987 0.72 3 179 1 10 2 2 150 100 42.4 -7.5 28.2 -0.4 0.9987 0.73 3 180 1 10 2 3 150 110 42.5 -7.3 22.9 -19.2 0.9983 0.69 2.3 181 1 10 2 4 150 250 42.1 -8 25.8 -8.9 0.9945 1.04 3.8 182 1 10 2 5 150 250 42.1 -8.1 25.3 -10.7 0.9946 1.04 3.7 183 1 10 2 6 150 150 42.6 -7.1 26.5 -6.6 0.9982 0.74 -2.2 184 1 10 2 7 150 150 42.5 -7.2 26.4 -6.8 0.9983 0.75 -2.1 185 1 10 2 8 150 40 43.2 -5.8 24.5 -13.5 0.9986 0.55 -2.3 186 1 10 2 9 150 90 42.3 -7.7 24.7 -12.9 0.9986 0.69 -2.1 187 1 10 2 10 150 150 42.2 -8 23 -18.9 0.9948 0.99 -4.3 188 1 10 2 11 150 150 42.1 -8.1 23.1 -18.4 0.9949 0.99 -4.2 189 1 11 2 1 150 100 42.5 -7.4 28 -1.1 0.9986 0.71 3 190 1 11 2 2 150 100 42.4 -7.5 28.1 -0.8 0.9986 0.72 3 191 1 11 2 3 150 110 42.5 -7.2 22.7 -19.8 0.9982 0.68 2.4 192 1 11 2 4 150 250 42.2 -8 25.9 -8.8 0.9945 1.03 3.7 193 1 11 2 5 150 250 42.1 -8.1 25.4 -10.5 0.9945 1.04 3.6 194 1 11 2 6 150 150 42.6 -7.1 26.3 -7.3 0.9981 0.74 -2.3 195 1 11 2 7 150 150 42.6 -7.2 26.2 -7.6 0.9982 0.75 -2.2 196 1 11 2 8 150 40 43.2 -5.7 24.3 -14.2 0.9985 0.54 -2.3 197 1 11 2 9 150 90 42.3 -7.7 24.5 -13.5 0.9985 0.69 -2.2 198 1 11 2 10 150 150 42.2 -8 22.9 -19.2 0.9946 0.99 -4.3 199 1 11 2 11 150 150 42.2 -8 23 -18.9 0.9948 0.99 -4.3 200 2 1 2 2 100 100 42 -8.4 26.4 -6.9 0.9995 0.66 1.3

-65- Index Dropped gun numbers Gun volumes Peak %ch P/B %ch X-cor AvgdB MaxdB 201 2 1 2 3 100 110 42.6 -7 24.9 -12.1 0.9991 0.55 1.4 202 2 1 2 4 100 250 42.4 -7.4 30.6 7.8 0.9958 0.91 -3.2 203 2 1 2 5 100 250 42.4 -7.5 31 9.2 0.9959 0.92 -3.2 204 2 1 2 6 100 150 42.9 -6.5 34.4 21.4 0.9993 0.52 1 205 2 1 2 7 100 150 42.8 -6.6 34.2 20.8 0.9994 0.53 1 206 2 1 2 8 100 40 43.5 -5.1 29.8 5.2 0.9991 0.37 1.1 207 2 1 2 9 100 90 42.6 -7.1 30.3 6.7 0.9992 0.51 1.1 208 2 1 2 10 100 150 42.5 -7.4 28.3 -0.3 0.9986 0.71 3 209 2 1 2 11 100 150 42.4 -7.4 30 5.9 0.9987 0.72 3 210 2 2 2 3 100 110 42.6 -7.1 25.1 -11.6 0.9992 0.56 1.4 211 2 2 2 4 100 250 42.4 -7.5 30.5 7.7 0.9958 0.93 -3.2 212 2 2 2 5 100 250 42.4 -7.6 30.9 9.1 0.9959 0.93 -3.2 213 2 2 2 6 100 150 42.8 -6.5 34.5 21.8 0.9994 0.53 1 214 2 2 2 7 100 150 42.8 -6.6 34.4 21.2 0.9994 0.54 1 215 2 2 2 8 100 40 43.5 -5.2 30 5.9 0.9992 0.38 1.1 216 2 2 2 9 100 90 42.6 -7.1 30.5 7.5 0.9993 0.52 1.1 217 2 2 2 10 100 150 42.4 -7.5 28.3 -0.1 0.9986 0.73 3 218 2 2 2 11 100 150 42.4 -7.5 28.4 0.3 0.9987 0.73 3 219 2 3 2 4 110 250 42.3 -7.8 30.6 8 0.9954 0.92 -3.3 220 2 3 2 5 110 250 42.2 -7.8 31 9.5 0.9955 0.93 -3.2 221 2 3 2 6 110 150 42.9 -6.4 33.7 19 0.9986 0.53 2 222 2 3 2 7 110 150 42.9 -6.4 33.6 18.5 0.9987 0.54 2 223 2 3 2 8 110 40 43.6 -4.9 25.8 -9.1 0.9987 0.29 0.6 224 2 3 2 9 110 90 42.7 -6.9 26.2 -7.5 0.9988 0.45 0.9 225 2 3 2 10 110 150 42.5 -7.3 22.9 -19.1 0.9982 0.68 2.4 226 2 3 2 11 110 150 42.5 -7.3 23.1 -18.5 0.9984 0.69 2.3 227 2 4 2 5 250 250 41.8 -8.8 34.4 21.4 0.9974 0.81 3.1 228 2 4 2 6 250 150 42.4 -7.4 20.2 -28.6 0.9947 0.93 4.3 229 2 4 2 7 250 150 42.4 -7.4 20 -29.5 0.9948 0.93 4.4 230 2 4 2 8 250 40 43.2 -5.8 28.3 -0.1 0.9949 0.81 -3.5 231 2 4 2 9 250 90 42.3 -7.7 26.4 -6.7 0.9946 0.95 3.9 232 2 4 2 10 250 150 42.2 -8 26.1 -8.1 0.9949 1 3.7 233 2 4 2 11 250 150 42.1 -8.1 26.1 -7.8 0.995 1.01 3.8 234 2 5 2 6 250 150 42.4 -7.4 20.5 -27.5 0.995 0.92 4.3 235 2 5 2 7 250 150 42.4 -7.6 21.2 -25.2 0.995 0.94 4.2 236 2 5 2 8 250 40 43.2 -5.9 27.7 -2.4 0.9951 0.81 -3.5 237 2 5 2 9 250 90 42.3 -7.7 26 -8.1 0.9947 0.96 3.8 238 2 5 2 10 250 150 42.1 -8.1 25.5 -10 0.9949 1.01 3.6 239 2 5 2 11 250 150 42.1 -8.1 25.6 -9.7 0.9949 1.02 3.7 240 2 6 2 7 150 150 42.5 -7.2 36.2 27.7 0.9985 0.6 2 241 2 6 2 8 150 40 43.5 -5.2 32.7 15.2 0.9987 0.4 1.8 242 2 6 2 9 150 90 42.7 -6.8 27.6 -2.6 0.9987 0.53 2.2 243 2 6 2 10 150 150 42.6 -7.1 26.6 -6.1 0.9981 0.75 -2.4 244 2 6 2 11 150 150 42.6 -7.1 26.9 -5.1 0.9982 0.75 -2.3 245 2 7 2 8 150 40 43.4 -5.3 32.5 14.7 0.9989 0.41 1.8 246 2 7 2 9 150 90 42.7 -6.8 27.5 -3 0.9989 0.54 2.2 247 2 7 2 10 150 150 42.6 -7.1 26.6 -6.3 0.9981 0.75 -2.3 248 2 7 2 11 150 150 42.5 -7.2 26.9 -5.3 0.9982 0.76 -2.2 249 2 8 2 9 40 90 43.1 -6 24.7 -12.8 0.9987 0.35 0.8 250 2 8 2 10 40 150 43.2 -5.7 24.6 -13.2 0.9985 0.55 -2.3 251 2 8 2 11 40 150 43.2 -5.8 24.8 -12.5 0.9986 0.55 -2.3 252 2 9 2 10 90 150 42.2 -8 23.7 -16.4 0.9987 0.71 -2 253 2 9 2 11 90 150 42.1 -8.1 23.8 -16.1 0.9989 0.71 -1.9 254 2 10 2 11 150 150 41.5 -9.5 23.9 -15.6 0.9994 0.85 2

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EX-31.1

Exhibit 31.1

RULE 13a-14(a) CERTIFICATIONS

I, John Thomas Wilson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Magellan Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	November 9, 2012	/s/ J. Thomas Wilson
		John Thomas Wilson, President and Chief Executive Officer
		(as Principal Executive Officer))

EX-31.2

Exhibit 31.2

RULE 13a-14(a) CERTIFICATIONS

I, Antoine J. Lafargue, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Magellan Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	November 9, 2012	/s/ Antoine J. Lafargue
		Antoine J. Lafargue, Chief Financial Officer and Treasurer
		(as Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

SECTION 1350 CERTIFICATIONS

In connection with the Quarterly Report of Magellan Petroleum Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Thomas Wilson, President and Chief Executive Officer of the Company, do hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated:	November 9, 2012	/s/ J. Thomas Wilson
		John Thomas Wilson, President and Chief Executive Officer
		(as Principal Executive Officer))

EX-32.2

Exhibit 32.2

SECTION 1350 CERTIFICATIONS

In connection with the Quarterly Report of Magellan Petroleum Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Antoine J. Lafargue, Chief Financial Officer of the Company, do hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

Dated:	November 9, 2012	/s/ Antoine J. Lafargue
		Antoine J. Lafargue, Chief Financial Officer and Treasurer
		(as Principal Financial and Accounting Officer)

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Income Taxes - Income Before Income Tax, Domestic and Foreign (Details)	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Net Income (Loss) Before Income Taxes
Effective Income Tax Rate, Continuing Operations	5.96%	0.00%

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Oil and Gas Activities - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		12 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Jun. 30, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Impairment of Oil and Gas Properties	$ 890	$ 0
Proved	27,962		28,187
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Increase (Decrease)	(5,537)		(5,740)
Unproved	6,501		7,091
Exploration Costs	3,707		3,744
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved	24,299		24,207
Unproved	104		104
Exploration Costs	1,773		1,718
Australia
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved	9,200		9,720
Unproved	4,461		4,389
Exploration Costs	0		0
United Kingdom
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved	0		0
Unproved	1,936		2,598
Exploration Costs	$ 1,934		$ 2,026

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Commitments (Details) (USD $)	Aug. 28, 2012	Aug. 27, 2012
Commitments and Contingencies Disclosure [Abstract]
Cash per share in unsolicited tender offer	$ 0.65
Shares offered per share in unsolicited tender offer	1
Share Price		$ 1.65

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Debt - Long Term Debt Instruments (Details) (USD $)	3 Months Ended
	Sep. 30, 2012	Jun. 30, 2012	Jan. 31, 2011
Long-term Debt, Current and Noncurrent [Abstract]
Note payable	$ 738,000
Short term line of credit	100,000	50,000
Notes Payable | Note Payable Due June 2014
Long-term Debt, Current and Noncurrent [Abstract]
Note payable	738,000	870,000
Less current portion of note payable	(456,000)	(480,000)
Long term debt, excluding current maturities	282,000	390,000
Note payable issued amount			1,700,000
Basis Spread on Wall Street Journal Prime Rate	1.00%
Variable Rate Floor	6.25%
Variable Interest Rate Applicable at Period End	3.25%
Interest Rate at Period End	6.25%
Line of Credit | Working Capital Line of Credit
Long-term Debt, Current and Noncurrent [Abstract]
Variable Interest Rate Applicable at Period End	6.25%
Maximum Borrowing Capacity	1,000,000
Short term line of credit	100,000
Amount Available Under Line of Credit	800,000
Letter of Credit | Working Capital Line of Credit
Long-term Debt, Current and Noncurrent [Abstract]
Amount Outstanding	25,000
Business Credit Cards | Working Capital Line of Credit
Long-term Debt, Current and Noncurrent [Abstract]
Amount Outstanding	25,000
Collateralized Debt Obligations | Payment Guarantee
Long-term Debt, Current and Noncurrent [Abstract]
Guarantee Maximum Exposure	$ 6,000,000

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Fair Value Measurements (Tables)

3 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table presents the amounts of assets and liabilities carried at fair value by the level in which they are classified within the valuation hierarchy for the three months ended:

	September 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	37,939	$	—	$	—	$	37,939
Securities available for sale (1)	133		—		—		133
	$	38,072	$	—	$	—	$	38,072
Liabilities
Contingent consideration payable	$	—	$	—	$	4,152	$	4,152
	June 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	41,215	$	—	$	—	$	41,215
Securities available for sale (1)	155		—		—		155
	$	41,370	$	—	$	—	$	41,370
Liabilities
Contingent consideration payable	$	—	$	—	$	4,072	$	4,072

⁽¹⁾ Included in the unaudited condensed consolidated balance sheets under prepaid and other assets.

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

The following table presents a roll forward of liabilities measured at fair value using significant unobservable inputs (Level 3) for the three months ended:

	September 30, 2012
	(In thousands)
June 30, 2012	$	4,072
Accretion of contingent consideration payable	80
September 30, 2012	$	4,152

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Stock Based Compensation - Fair Value of Shares Issued Under the Stock Plan and Weighted-Average Assumptions (Details) (USD $)	3 Months Ended
	Sep. 30, 2012		Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of options	925,000	[1]	0	[1]
Weighted-average grant date fair value per share	$ 1.31		$ 0.00
Expected dividend	$ 0.00		$ 0.00
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility, Minimum	60.70%		0.00%
Expected volatility, Maximum	63.50%		0.00%
Stock options | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	0.60%		0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	5 years 1 month 17 days		0 years
Stock options | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	0.80%		0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	6 years		0 years

[1] There were no stock option grants for the three months ended September 30, 2011.

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Fair Value Measurements - Assets and Liabilities Carried at Fair Value by Classification Level in Valuation Hierarchy (Details) (Recurring, USD $) In Thousands, unless otherwise specified	Sep. 30, 2012		Jun. 30, 2012
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	$ 37,939		$ 41,215
Securities available for sale	133	[1]	155	[1]
Assets	38,072		41,370
Contingent consideration payable	0		0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	0		0
Securities available for sale	0	[1]	0	[1]
Assets	0		0
Contingent consideration payable	0		0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	0		0
Securities available for sale	0	[1]	0	[1]
Assets	0		0
Contingent consideration payable	4,152		4,072
Estimate of Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents	37,939		41,215
Securities available for sale	133	[1]	155	[1]
Assets	38,072		41,370
Contingent consideration payable	$ 4,152		$ 4,072

[1] Included in the unaudited condensed consolidated balance sheets under prepaid and other assets.

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012 US Federal Tax Withholding	Sep. 30, 2012 US Federal Tax Withholding Accrued and Other Liabilities	Sep. 30, 2012 US Federal Tax Withholding, Interest Accrued and Other Liabilities	Mar. 31, 2012 Young Energy Prize S.A. (YEP) US Federal Tax Withholding	Mar. 31, 2012 White Bear, LLC US Federal Tax Withholding	Oct. 31, 2009 Nautilus Poplar, LLC (NP) owner	Mar. 31, 2012 Nautilus Poplar, LLC (NP) US Federal Tax Withholding	Jun. 30, 2012 Mr. Bogachev	Jun. 30, 2012 Mr. Bogachev US Federal Tax Withholding	Sep. 30, 2012 Mr. Bogachev US Federal Tax Withholding Accrued and Other Liabilities
Related Party Transaction [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 0.1			$ 0.6	$ 1.3		$ 2.0		$ 0.3
Loss Contingency, Additional Compensation								0.3
Business Acquisition, Percentage of Membership Interests Acquire						83.50%
Number of Majority Owners						2
Loss Contingency Accrual, at Carrying Value		$ 0.7	$ 0.1							$ 0.6

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Basis of Presentation

3 Months Ended

Sep. 30, 2012

Basis Of Presentation And Significant Accounting Policies [Abstract]

Basis Of Presentation

Note 1 - Basis of Presentation

Description of Operations

Magellan Petroleum Corporation (the "Company" or "Magellan" or "we" or "us") is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. As of September 30, 2012, Magellan had two reporting segments: (i) a 100% membership interest in Nautilus Poplar LLC ("NP"), based in Denver, Colorado, and (ii) a 100% equity interest in its subsidiary, Magellan Petroleum Australia Limited ("MPAL"), headquartered in Brisbane, Australia, which includes our operations in the United Kingdom.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP and MPAL, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and in accordance with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. 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. All intercompany transactions have been eliminated. Operating results for the three months ended September 30, 2012, are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2013. This report should be read in conjunction with the consolidated financial statements and footnotes included in the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2012.

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

Reclassification

As of December 31, 2011, we changed the presentation of our financial statements to conform them to industry-specific norms and to improve our reporting to shareholders and stakeholders. Specifically, we have modified the presentation of expenses in the unaudited condensed consolidated statements of operations and the presentation of property and equipment in the unaudited 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. There was no impact on previously reported results.

Use of Estimates

The preparation of unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Foreign Currency Translation

The functional currencies of our foreign subsidiaries are their local currencies. Assets and liabilities of foreign subsidiaries are translated to United States dollars at period-end exchange rates, and our unaudited condensed consolidated statements of operations and cash flows are translated at average exchange rates during the period. Resulting translation adjustments are recorded as a separate component of stockholders' equity as accumulated other comprehensive income or loss.

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

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. GAAP requires goodwill to be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. We adopted the new guidance for our annual impairment test in fiscal year 2012 as allowed by ASU 2011-08 and therefore perform an annual assessment of qualitative factors for our impairment test. The qualitative factors used in our assessment include macroeconomic conditions, industry and market conditions, cost factors, and overall financial performance. For the three months ended September 30, 2012, there were no events or circumstances that would indicate that a goodwill impairment exists.

Business Combinations

The Company applies the acquisition method of recording business combinations. Under this method, the Company recognizes and measures the identifiable assets acquired from, the liabilities assumed from, and any non-controlling interest in the acquiree. Any goodwill or gain is identified and recorded. We engage independent valuation consultants to assist us in determining the fair values of crude oil and natural gas properties acquired and other third party specialists as needed to assist us in assessing the fair value of other assets and liabilities assumed. These valuations require management to make significant estimates and assumptions, especially with respect to the oil and gas properties.

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Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Sep. 30, 2012		Sep. 30, 2011
Earnings Per Share [Abstract]
Net income (loss) attributable to Magellan Petroleum Corporation	$ (5,310)		$ 940
Weighted Average Number of Shares Outstanding Reconciliation [Abstract]
Basic weighted-average shares outstanding (in shares)	53,849,181		52,915,811
Add: dilutive effects of stock options and unvested stock grants	0	[1]	1,804,917	[1]
Diluted weighted-average common shares outstanding (in shares)	53,849,181		54,720,728
Basic net loss per common share (dollars per share)	$ (0.10)		$ 0.02
Diluted net loss per common share (dollars per share)	$ (0.10)		$ 0.02

[1] There is no dilutive effect on earnings per share in periods with net losses.

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Oil and Gas Activities (Tables)

3 Months Ended

Sep. 30, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure

Note 12 - Oil and Gas Activities

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

	September 30, 2012			June 30, 2012
	(In thousands)
Proved oil and gas properties:
United Kingdom	$	—		$	—
United States	24,299			24,207
Australia	9,200			9,720
Less accumulated depletion, depreciation, and amortization	(5,537		)	(5,740		)
Total net proved oil and gas properties	$	27,962		$	28,187
Unproved oil and gas properties:
United Kingdom	$	1,936		$	2,598
United States	104			104
Australia	4,461			4,389
Total unproved oil and gas properties:	$	6,501		$	7,091
Wells in Progress:
United Kingdom	$	1,934		$	2,026
United States	1,773			1,718
Australia	—			—
Total wells in progress	$	3,707		$	3,744

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Segment and Geographic Data (Tables)

3 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

The Company conducts its operations through two wholly owned subsidiaries, NP, which operates in the United States, and MPAL, which is primarily active in Australia. The following table presents each segment as follows:

	NP			MPAL			Corporate			Inter-Segment Elimination			Total
	(In thousands)
Three months ended September 30, 2012
Revenues	$	1,460		$	200		$	—		$	—		$	1,660
Consolidated net income (loss)	$	(272	)	$	(1,824	)	$	(3,043	)	$	(171	)	$	(5,310	)
Three months ended September 30, 2011
Revenues	$	1,231		$	2,504		$	—		$	—		$	3,735
Consolidated net income (loss)	$	3,868		$	(932	)	$	(1,993	)	$	(3	)	$	940

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Earnings Per Share - Schedule of Antidilutive Securities (Details)	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Potentially dilutive securities	75,000	7,801,993
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Potentially dilutive securities	75,000	7,697,826
Non-vested restricted stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Potentially dilutive securities	0	104,167

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Termination Costs (Tables)

3 Months Ended

Sep. 30, 2012

Termination Costs [Abstract]

Schedule of Restructuring and Related Costs [Table Text Block]

A reconciliation of the beginning and ending liability balance for charges to general and administrative expense and cash payments for the three months ended September 30, 2012, is as follows:

	Total
	(In thousands)
June 30, 2012	$	—
Charges to general and administrative expense	828
Cash payments	(48		)
September 30, 2012	$	780

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Basis of Presentation - Description of Operations (Details)	3 Months Ended
	Sep. 30, 2012 segment
Presentation and Significant Accounting Policies Information [Line Items]
Number of Reportable Segments	2
Nautilus Poplar, LLC (NP)
Presentation and Significant Accounting Policies Information [Line Items]
Subsidiary, Ownership Percentage	100.00%
Magellan Petroleum Australia Limited (MPAL)
Presentation and Significant Accounting Policies Information [Line Items]
Subsidiary, Ownership Percentage	100.00%

XML

Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Net income (loss) after income tax	$ (5,310)	$ 925
Adjustments to reconcile net loss to net cash used in operating activities
Foreign transaction (gain) loss	0	(562)
Depletion, depreciation and amortization	316	474
Interest earned on restricted deposits	0	(24)
Fair value increase of contingent consideration payable	80	0
Deferred income taxes	(336)	0
Gain on disposal of assets	0	(4,108)
Stock based compensation	346	396
Impairment loss	890	0
Severance Costs	780	0
Net changes in operating assets and liabilities:
Accounts receivable	143	3,165
Inventories	57	(80)
Prepayments and other current assets	255	188
Accounts payable and accrued liabilities	(871)	(2,598)
Income taxes payable	0	197
Net cash (used in) provided by operating activities	(3,650)	(2,027)
INVESTING ACTIVITIES:
Additions to property and equipment	(385)	(1,242)
Proceeds from sale of assets	0	5,001
Purchase of working interest in Poplar	0	(823)
Refund (Payment) of Deposit for Purchase of Evans shoal (includes interest)	0	10,940
Securities purchased	0	(2,400)
Net cash provided by (used in) investing activities	(385)	11,476
FINANCING ACTIVITIES:
Proceeds from issuance of stock	0	35
Short term debt issuances	550	1,925
Short term debt repayments	(500)	(1,225)
Purchase of non-controlling interest - Nautilus Poplar LLC	0	(3,415)
Long term debt repayments	(132)	(144)
Net cash (used in) provided by financing activities	(82)	(2,824)
Effect of exchange rate changes on cash and cash equivalents	841	(1,319)
Net increase (decrease) in cash and cash equivalents	(3,276)	5,306
Cash and cash equivalents at beginning of period	41,215	20,417
CASH AND CASH EQUIVALENTS AT END OF PERIOD	37,939	25,723
Income taxes	0	0
Interest Paid, net of amount capitalized	0	34
Supplemental Schedule of Noncash Investing and Financing Activities:
Unrealized holding gain (loss)	(22)	34
Revision to estimate of asset retirement obligations	(306)	0
Accounts payable related to property plant and equipment	58	162
Other Significant Noncash Transaction, Value of Consideration Given	0	102
Purchase of non-controlling interest for Stock and contingent consideration	0	4,729
Purchase of 3% working interest for stock and contingent consideration	$ 0	$ 1,243

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Acquisitions and Divestitures - Purchase Price Allocation and Other Disclosures (Details) (Santos Sales Agreement, USD $)	3 Months Ended	12 Months Ended
	Sep. 30, 2012	Jun. 30, 2012	Sep. 30, 2012 Mereenie Operating Joint Venture	May 25, 2012 Dingo Joint Venture	May 25, 2012 Palm Valley Joint Venture [Member]
Disposal Group, Other Information [Abstract]
Ownership Interest Sold			35.00%
Goodwill, Written off Related to Sale of Business Unit		$ 2,500,000
Joint Venture, Ownership Interest Sold by Third Party				66.00%	48.00%
Other Payments to Acquire Businesses		17,500,000
Disposal Group, Cost of Disposed Entity [Abstract]
Consideration received, net purchase price per Santos SA	25,493,000
Consideration received, purchase price adjustments	1,138,000
Consideration received total	26,631,000
Disposal Group, Consideration Received Allocation [Abstract]
Allocation of the consideration received, proved oil and gas properties (Palm Valley)	3,403,000
Allocation of the consideration received, unproved oil and gas properties (Dingo)	2,957,000
Allocation of the consideration received, land, buildings, and equipment (Palm Valley)	370,000
Total allocation of the fair value received	6,730,000
Mereenie liabilities given up, net	2,805,000
Gain on sale of assets	$ (36,166,000)

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Stock Based Compensation - Additional Information (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Director	Dec. 08, 2010 1998 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				7,205,000
Share-based compensation expense	$ 0.3	$ 0.4
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 0.9
Maximum number of shares allowed to be issued each year			15,000

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012	Jun. 30, 2012
Current Assets:
Cash and cash equivalents	$ 37,939	$ 41,215
Accounts receivable — trade	1,037	1,152
Accounts receivable - working interest partners	216	231
Inventories	470	499
Prepaid assets	258	511
Total current assets	39,920	43,608
Property and equipment, net (succesful efforts method):
Proved oil and gas properties	33,499	33,927
Less accumulated depletion, depreciation and amortization	(5,537)	(5,740)
Unproved oil and gas properties	6,501	7,091
Wells in progress	3,707	3,744
Land, buildings and equipment (net of accumulated depreciation of $2,174 and $2,077 as of September 30, 2012, and June 30, 2012, respectively)	1,540	1,422
Net property and equipment	39,710	40,444
Other Non-current Assets:
Goodwill	2,174	2,174
Deferred income taxes	6,287	5,951
Other long term assets	376	397
Total other non-current assets	8,837	8,522
Total assets	88,467	92,574
Current liabilities:
Short term line of credit	100	50
Current portion of note payable	456	480
Current portion of asset retirement obligations	339	329
Accounts payable	3,543	3,672
Accrued and other liabilities	3,170	3,000
Total current liabilities	7,608	7,531
Long term liabilities:
Note payable	282	390
Asset retirement obligations	7,349	7,455
Contingent consideration payable	4,152	4,072
Other long term liabilities	213	218
Total long term liabilities	11,996	12,135
Equity:
Common stock (par value $.01 per share): Authorized 300,000,000 shares, outstanding, 53,835,594 and 53,835,594 as of September 30, 2012 and June 30, 2012, respectively	539	538
Capital in excess of par value	91,098	90,753
Preferred stock (par value $.01 per share): Authorized 50,000,000 shares, outstanding, 0 as of September 30, 2012 and June 30, 2012, respectively	0	0
Accumulated deficit	(34,900)	(29,590)
Accumulated other comprehensive income	12,126	11,207
Total equity attributable to Magellan Petroleum Corporation	68,863	72,908
Total equity	68,863	72,908
Total liabilities and equity	$ 88,467	$ 92,574

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Segment and Geographical Data (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2012 segment	Sep. 30, 2011
Segment Reporting Information [Line Items]
Number of Reportable Segments	2
Revenues	$ 1,660	$ 3,735
Consolidated net income (loss)	(5,310)	940
Nautilus Poplar, LLC (NP)
Segment Reporting Information [Line Items]
Revenues	1,460	1,231
Consolidated net income (loss)	(272)	3,868
Magellan Petroleum Australia Limited (MPAL)
Segment Reporting Information [Line Items]
Revenues	200	2,504
Consolidated net income (loss)	(1,824)	(932)
Corporate
Segment Reporting Information [Line Items]
Revenues	0	0
Consolidated net income (loss)	(3,043)	(1,993)
Inter-segment Elimination
Segment Reporting Information [Line Items]
Revenues	0	0
Consolidated net income (loss)	$ (171)	$ (3)

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Consolidated Statements of Comprehensive Income (Loss) (Parentheticals) (USD $)	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Statement of Other Comprehensive Income [Abstract]
Unrealized holding (losses) gains on securities available for sale, tax	$ 0	$ 0

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Asset Retirement Obligations - Roll-Forward (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Jun. 30, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of period	$ 7,784
Accretion expense	111
Revision to estimate	(306)
Effect of exchange rate changes	99
Balance at end of period	7,688
Less current asset retirement obligation	339	329
Long term asset retirement obligation	$ 7,349	$ 7,455

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Acquisitions and Divestitures (Tables)

3 Months Ended

Sep. 30, 2012

Acquisitions and Divestitures [Abstract]

Schedule of Purchase Price Allocation

The following table summarizes the allocation of the consideration received for the assets transferred as a result of the Santos SA as of June 30, 2012.

	Total
	(In thousands)
Consideration received
Net purchase price per Santos SA	$	25,493
Purchase price adjustments	1,138
Total	$	26,631
Allocation of the consideration received to fair value of assets
Proved oil and gas properties (Palm Valley)	$	3,403
Unproved oil and gas properties (Dingo)	2,957
Land, buildings, and equipment (Palm Valley)	370
Total allocation of the fair value received	6,730
Mereenie liabilities given up, net	2,805
Gain on sale of assets	(36,166		)
Total	$	(26,631	)

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Fair Value Measurements - Textuals (Details) (USD $)	3 Months Ended
	Sep. 30, 2012 Time Deposits Maximum	Sep. 30, 2012 Fair Value, Measurements, Recurring	Sep. 30, 2012 Fair Value, Inputs, Level 1 Fair Value, Measurements, Recurring	Jun. 30, 2012 Fair Value, Inputs, Level 1 Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents			$ 37,939,000	$ 41,215,000
Cash		19,300,000
Cash equivalents		$ 18,600,000
Cash Equivalent, Maturity Period	90 days

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Asset Retirement Obligations (Tables)

3 Months Ended

Sep. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations Roll-Forward

The following table summarizes the asset retirement obligation activity for the three months ended September 30, 2012:

	Total
	(In thousands)
June 30, 2012	$	7,784
Accretion expense	111
Revision to estimate	(306		)
Effect of exchange rate changes	99
September 30, 2012	7,688
Less current asset retirement obligation	339
Long term asset retirement obligation	$	7,349

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Consolidated Statement of Stockholders' Equity (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Jun. 30, 2012
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 68,863	$ 72,908
Net income (loss) attributable to Magellan Petroleum Corporation	(5,310)
Foreign currency translation adjustments	941
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares, Beginning Balance	52,455,977
Unrealized holding gain (loss) on securities available for sale, net of taxes	(22)
Stock and stock based compensation	346
Shares, Ending Balance	53,835,594
Common Stock
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	539	538
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock and stock based compensation	1
Capital in Excess of Par Value
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	91,098	90,753
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock and stock based compensation	345
Accumulated Deficit
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	(34,900)	(29,590)
Net income (loss) attributable to Magellan Petroleum Corporation	(5,310)
Accumulated Other Comprehensive Income
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	12,126	11,207
Foreign currency translation adjustments	941
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Unrealized holding gain (loss) on securities available for sale, net of taxes	$ (22)

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Consolidated Balance Sheets (Parentheticals) (USD $)	Sep. 30, 2012	Jun. 30, 2012
Allowance for doubtful accounts	$ 0	$ 0
Accumulated depreciation	$ 2,174,000	$ 2,077,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, authorized	300,000,000	300,000,000
Common stock, outstanding	53,835,594	52,455,977
Preferred stock, par value	$ 0.01	$ 0.01
Preferred Stock, authorized	50,000,000	50,000,000
Preferred stock, outstanding	0	0

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Commitments

3 Months Ended

Sep. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments

Note 10 - Commitments and Contingencies

Refer to the Note 10 - Commitments, in our Form 10-K as of June 30, 2012, for information on all commitments. Additionally see Note 5 above for information regarding the contingent consideration payable related to the Nautilus Transaction.

On August 28, 2012, Stratex Oil & Gas Holdings, Inc. ("Stratex") announced an unsolicited proposal for the acquisition of each outstanding share of the Company's common stock for $0.65 in cash and one share of Stratex common stock, the closing price for which as reported by the OTCQB on August 27, 2012 was $1.65 per share. On September 10, 2012, the Company announced that its Board of Directors, after carefully considering the unsolicited proposal and consulting with its financial and legal advisors, had determined not to pursue the Stratex proposal. On September 12, 2012, the Company received a subpoena from the U.S. Securities and Exchange Commission (the "SEC") for the production of documents in connection with these announcements. On September 14, 2012, the Company received a letter from the Financial Industry Regulatory Authority ("FINRA") indicating that FINRA is conducting a review of trading in the Company's common stock surrounding the August 28, 2012 announcement by Stratex, and requesting information and documents from the Company in connection therewith. The Company is cooperating fully with the SEC and FINRA in these matters.

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Document and Entity Information	3 Months Ended
	Sep. 30, 2012	Nov. 01, 2012
Document Information [Line Items]
Document Type	10-Q
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2013
Current Fiscal Year End Date	--06-30
Entity Central Index Key	0000061398
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Registrant Name	MAGELLAN PETROLEUM CORP /DE/
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock Shares Outstanding		53,885,594

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Related Party Transactions

3 Months Ended

Sep. 30, 2012

Related Party Transactions [Abstract]

Related Party Transactions

Note 11 - Related Party Transactions

U.S. Federal Tax Withholdings. During the third quarter of fiscal year 2012, the Company identified a potential liability of approximately $2.0 million related to the Company's non-payment of required U.S. Federal tax withholding in the course of its initial acquisition of a part of NP. In October 2009, Magellan acquired 83.5% of the membership interests in NP (the "Poplar Acquisition"), from the two majority owners of NP, White Bear LLC ("White Bear") and YEP I, SICAV-FES ("YEP I"). Both of these entities are affiliated with Mr. Bogachev, a Director of Magellan and a foreign national. Due to the status of YEP I as a foreign entity and the members of White Bear as foreign nationals, Magellan was required to make U.S. Federal tax withholdings from the payments to or for the benefit of White Bear and YEP I. Of the $2.0 million liability, $1.3 million was estimated to relate to the interest sold by White Bear, $0.6 million to the interest sold by YEP I, and $0.1 million to Magellan's interest on late payment of the U.S. Federal tax withholdings.

Upon the filing of U.S. income tax returns in relation to the Poplar Acquisition and payment of corresponding income taxes by White Bear and YEP I, Magellan is deemed to be relieved of its liability for the U.S. Federal tax withholdings as well as related penalties and interest except for Magellan's interest on late payment of the U.S. Federal tax withholdings. With regards to White Bear, Magellan has confirmed that as of the date of this filing, Mr. Bogachev has filed his U.S. income tax return and paid taxes due on the Poplar Acquisition, which were estimated at $0.3 million. Magellan has paid Mr. Bogachev $0.3 million in additional compensation during the quarter ended September 30, 2012. Had Mr. Bogachev not filed and paid his tax return, Magellan's liability in relation to its U.S. Federal tax withholdings requirements was estimated at $1.3 million. With regards to YEP I, Magellan continues to seek from YEP I or, because YEP I is a now defunct entity, from its successor entities, the filing of its U.S. income tax return.

As of September 30, 2012, we have recorded a total liability of $0.7 million under accrued and other liabilities in the consolidated balance sheets related to this matter. That amount is comprised of the $0.6 million in withholdings, penalties, and interest related to YEP I and $0.1 million related to Magellan's interest on its late payment of the U.S. Federal tax withholdings. There was no effect on the unaudited condensed consolidated statements of operations for the three months ended September 30, 2012, related to this transaction.

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Consolidated Statement of Operations (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
REVENUES:
Oil production	$ 1,460	$ 3,296
Gas production	200	439
Total revenues	1,660	3,735
OPERATING EXPENSES:
Lease operating	2,051	3,018
Depletion, depreciation, amortization, and accretion	316	474
Exploration	622	987
General and administrative	3,663	2,512
Impairment	890	0
Gain on sale of assets	0	(4,108)
Total operating (income) expense	7,542	2,883
Income (loss) from operations	(5,882)	852
Other income (expense)
Net interest income	221	271
Other income	15	0
Total other income (expense)	236	271
Income (loss) before income tax	(5,646)	1,123
Income tax benefit (provision)	336	(198)
Net income (loss) after income tax	(5,310)	925
Net loss attributable to non-controlling interest in subsidiaries	0	15
Net income (loss) attributable to Magellan Petroleum Corporation	$ (5,310)	$ 940
Earnings per common share (Note 8):
Weighted average number of basic shares outstanding (in shares)	53,849,181	52,915,811
Weighted average number of diluted shares outstanding (in shares)	53,849,181	54,720,728
Net income (loss) per basic share outstanding (dollars per share)	$ (0.10)	$ 0.02
Net income (loss) per diluted share outstanding (dollars per share)	$ (0.10)	$ 0.02

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Fair Value Measurements

3 Months Ended

Sep. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 5 - 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. During the three months ended September 30, 2012, and 2011, there have been no transfers in and/or out of Level 1, Level 2, or Level 3.

Items required to be measured at fair value on a non-recurring basis include liabilities related to AROs. Items required to be measured at fair value on a recurring basis include cash and cash equivalents and securities available for sale, classified as Level 1, and the contingent consideration payable related to the acquisition of the non-controlling interest and additional working interest in Nautilus Poplar LLC, classified as Level 3.

As of September 30, 2012, the Company had $37.9 million in cash and cash equivalents, with $19.3 million held in cash and $18.6 million classified as cash equivalents. The cash equivalents were held in time deposit accounts in several Australian banks with maturities of 90 days or less.

The following table presents the amounts of assets and liabilities carried at fair value by the level in which they are classified within the valuation hierarchy for the three months ended:

	September 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	37,939	$	—	$	—	$	37,939
Securities available for sale (1)	133		—		—		133
	$	38,072	$	—	$	—	$	38,072
Liabilities
Contingent consideration payable	$	—	$	—	$	4,152	$	4,152
	June 30, 2012
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets
Cash and cash equivalents	$	41,215	$	—	$	—	$	41,215
Securities available for sale (1)	155		—		—		155
	$	41,370	$	—	$	—	$	41,370
Liabilities
Contingent consideration payable	$	—	$	—	$	4,072	$	4,072

⁽¹⁾ Included in the unaudited condensed consolidated balance sheets under prepaid and other assets.

The following table presents a roll forward of liabilities measured at fair value using significant unobservable inputs (Level 3) for the three months ended:

	September 30, 2012
	(In thousands)
June 30, 2012	$	4,072
Accretion of contingent consideration payable	80
September 30, 2012	$	4,152

The fair value of the contingent consideration payable is calculated using production projections and the estimated timing of production payouts. The Company also utilizes a discount that is consistent with the rate used in valuing its asset retirement obligations and reflective of the Company’s credit adjusted borrowing rate.

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Asset Retirement Obligations

3 Months Ended

Sep. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 4 - Asset Retirement Obligations

The estimated valuation 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 made by management when assessing an ARO include: (i) the existence of a legal obligation; (ii) estimated probabilities, amounts, and timing of settlements; (iii) the credit-adjusted risk-free rate to be used; and (iv) inflation rates. Accretion expense is recorded under depletion, depreciation, amortization, and accretion in the unaudited condensed consolidated statement of operations.

The following table summarizes the asset retirement obligation activity for the three months ended September 30, 2012:

	Total
	(In thousands)
June 30, 2012	$	7,784
Accretion expense	111
Revision to estimate	(306		)
Effect of exchange rate changes	99
September 30, 2012	7,688
Less current asset retirement obligation	339
Long term asset retirement obligation	$	7,349

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Debt (Tables)

3 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

Long term debt relates to a $1.7 million note payable re-issued in January 2011. This note will be fully amortized in June 2014. The outstanding principal as of September 30, 2012, and June 30, 2012, consisted of the following:

	September 30, 2012			June 30, 2012
	(In thousands)
Note payable	$	738		$	870
Less current portion of note payable	(456		)	(480		)
Long term debt, excluding current portion	$	282		$	390

Minimum Future Principal Maturities

As of September 30, 2012, the minimum future principal maturities of long term debt were as follows:

	September 30, 2012
	(In thousands)
One year	$	456
Two years	282
Total	$	738

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Oil and Gas Activities

3 Months Ended

Sep. 30, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Gas Activities

Note 12 - Oil and Gas Activities

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

	September 30, 2012			June 30, 2012
	(In thousands)
Proved oil and gas properties:
United Kingdom	$	—		$	—
United States	24,299			24,207
Australia	9,200			9,720
Less accumulated depletion, depreciation, and amortization	(5,537		)	(5,740		)
Total net proved oil and gas properties	$	27,962		$	28,187
Unproved oil and gas properties:
United Kingdom	$	1,936		$	2,598
United States	104			104
Australia	4,461			4,389
Total unproved oil and gas properties:	$	6,501		$	7,091
Wells in Progress:
United Kingdom	$	1,934		$	2,026
United States	1,773			1,718
Australia	—			—
Total wells in progress	$	3,707		$	3,744

During the three months ended September 30, 2012, Magellan allowed a license in the United Kingdom to expire at the end of its term. Subsequently an impairment of $0.9 million was recorded in the unaudited condensed consolidated statement of operations.

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Earnings Per Share

3 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

Earnings Per Share

Note 8 - Earnings Per Common Share

The following table summarizes the computation of basic and diluted earnings per share for the three months ended:

	September 30,
	2012			2011
	(In thousands, except share and per share amounts)
Net (loss) income attributable to Magellan Petroleum Corporation	$	(5,310	)	$	940
Basic weighted average shares outstanding	53,849,181			52,915,811
Add: dilutive effects of stock options and unvested stock grants (1)	—			1,804,917
Diluted weighted average common shares outstanding	53,849,181			54,720,728
Net (loss) income per basic share outstanding	$	(0.10	)	$	0.02
Net (loss) income per diluted share outstanding	$	(0.10	)	$	0.02

⁽¹⁾ There is no dilutive effect on earnings per share in periods with net losses.

Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following for the three months ended:

	September 30,
	2012	2011
Stock options	75,000	7,697,826
Non-vested restricted stock	—	104,167
Total	75,000	7,801,993

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Income Taxes

3 Months Ended

Sep. 30, 2012

Income Tax Disclosure [Abstract]

Income Taxes

Note 6 - 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 three months ended September 30, 2012, is 5.96% compared to 0% for the three months ended September 30, 2011. 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 amount management believes is more likely than not the deferred tax assets that will be realized in future periods.

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. We anticipate we will continue to record a valuation allowance against the deferred tax assets in all jurisdictions of the Company, except for the deferred asset related to the Australian Petroleum Resource Rent Tax ("PRRT"), until such time as we are able to determine it is "more-likely-than-not" those deferred tax assets will be realized.

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Stock Based Compensation

3 Months Ended

Sep. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Based Compensation

Note 7 - Stock Based Compensation

The Stock Plan

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

Stock Option Grants

Stock option grants contain both time based and performance based vesting provisions. The time based options are expensed on a straight-line basis over the vesting period. Performance based options are recognized when the achievement of the performance conditions is considered probable. Management re-assesses whether satisfaction of performance conditions are probable at the end of each reporting period. If changes in the estimated outcome of the performance conditions affect the quantity of the awards expected to vest, the cumulative effect of the change is recognized in the period of change. As of September 30, 2012, management believes the achievement of the performance conditions related to the PBOs is probable. Accordingly, the Company has recognized expense on these awards over the period of time the performance condition is expected to be achieved.

As of September 30, 2012, 460,000 shares were available for future issuance under the Stock Plan. Of the 925,000 options granted during the three months ended September 30, 2012, 75,000 were issued as PBOs and 800,000 options were issued outside of the Stock Plan. Options outstanding have expiration dates ranging from November 28, 2015, through September 5, 2022.

The following table summarizes the stock option activity for the three months ended:

	September 30, 2012
	Number of Shares		WAEPS (1)
June 30, 2012	6,753,125		$1.44
Granted	925,000		$1.31
Forfeited	(483,334	)	$1.13
September 30, 2012	7,194,791		$1.37
Weighted average remaining contractual term	5.1 years

⁽¹⁾ Weighted average exercise price per share

The fair value of stock option grants was estimated using the following weighted average assumptions for the three months ended:

	September 30,
	2012					2011
Number of options (1)	925,000					—
Weighted average grant date fair value per share	$1.31					$0.00
Expected dividend	$0.00					$0.00
Risk free interest rate	0.6	%	-	0.8	%	—	%	-	—	%
Expected life	5.13 years		-	6.00 years		0 years		-	0 years
Expected volatility (based on historical price)	60.7	%	-	63.5	%	—	%	-	—	%

⁽¹⁾ There were no stock option grants for the three months ended September 30, 2011.

Stock Compensation Expense

The Company recorded $0.3 million and $0.4 million of related stock compensation expense for the three months ended September 30, 2012, and 2011, respectively. Stock based compensation is included in general and administrative expense in the unaudited condensed consolidated statements of operations. The unrecorded expected future compensation expense related to stock option awards was $0.9 million as of September 30, 2012.

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 subject to an annual maximum of 15,000 shares. As of September 30, 2012, no shares were issued by the Company pursuant of this policy.

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Segment and Geographical Data

3 Months Ended

Sep. 30, 2012

Segment Reporting [Abstract]

Segment and Geographic Data

Note 9 - Segment Data

The Company conducts its operations through two wholly owned subsidiaries, NP, which operates in the United States, and MPAL, which is primarily active in Australia. The following table presents each segment as follows:

	NP			MPAL			Corporate			Inter-Segment Elimination			Total
	(In thousands)
Three months ended September 30, 2012
Revenues	$	1,460		$	200		$	—		$	—		$	1,660
Consolidated net income (loss)	$	(272	)	$	(1,824	)	$	(3,043	)	$	(171	)	$	(5,310	)
Three months ended September 30, 2011
Revenues	$	1,231		$	2,504		$	—		$	—		$	3,735
Consolidated net income (loss)	$	3,868		$	(932	)	$	(1,993	)	$	(3	)	$	940

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Debt - Debt Maturities Schedule (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2012
Debt Disclosure [Abstract]
One year	$ 456
Two years	282
Note payable	$ 738

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Basis of Presentation (Policies)

3 Months Ended

Sep. 30, 2012

Basis Of Presentation And Significant Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP and MPAL, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and in accordance with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. 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. All intercompany transactions have been eliminated. Operating results for the three months ended September 30, 2012, are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2013. This report should be read in conjunction with the consolidated financial statements and footnotes included in the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2012.

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

Use of Estimates

Use of Estimates

The preparation of unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Foreign Currency Translation

Foreign Currency Translation

The functional currencies of our foreign subsidiaries are their local currencies. Assets and liabilities of foreign subsidiaries are translated to United States dollars at period-end exchange rates, and our unaudited condensed consolidated statements of operations and cash flows are translated at average exchange rates during the period. Resulting translation adjustments are recorded as a separate component of stockholders' equity as accumulated other comprehensive income or loss.

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

Goodwill

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. GAAP requires goodwill to be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. We adopted the new guidance for our annual impairment test in fiscal year 2012 as allowed by ASU 2011-08 and therefore perform an annual assessment of qualitative factors for our impairment test. The qualitative factors used in our assessment include macroeconomic conditions, industry and market conditions, cost factors, and overall financial performance. For the three months ended September 30, 2012, there were no events or circumstances that would indicate that a goodwill impairment exists.

Business Combinations

Business Combinations

The Company applies the acquisition method of recording business combinations. Under this method, the Company recognizes and measures the identifiable assets acquired from, the liabilities assumed from, and any non-controlling interest in the acquiree. Any goodwill or gain is identified and recorded. We engage independent valuation consultants to assist us in determining the fair values of crude oil and natural gas properties acquired and other third party specialists as needed to assist us in assessing the fair value of other assets and liabilities assumed. These valuations require management to make significant estimates and assumptions, especially with respect to the oil and gas properties.

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Stock Based Compensation (Tables)

3 Months Ended

Sep. 30, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Option Activity

The following table summarizes the stock option activity for the three months ended:

	September 30, 2012
	Number of Shares		WAEPS (1)
June 30, 2012	6,753,125		$1.44
Granted	925,000		$1.31
Forfeited	(483,334	)	$1.13
September 30, 2012	7,194,791		$1.37
Weighted average remaining contractual term	5.1 years

⁽¹⁾ Weighted average exercise price per share

Fair Value of Shares Issued Under the Stock Plan and Weighted-Average Assumptions

The fair value of stock option grants was estimated using the following weighted average assumptions for the three months ended:

	September 30,
	2012					2011
Number of options (1)	925,000					—
Weighted average grant date fair value per share	$1.31					$0.00
Expected dividend	$0.00					$0.00
Risk free interest rate	0.6	%	-	0.8	%	—	%	-	—	%
Expected life	5.13 years		-	6.00 years		0 years		-	0 years
Expected volatility (based on historical price)	60.7	%	-	63.5	%	—	%	-	—	%

⁽¹⁾ There were no stock option grants for the three months ended September 30, 2011.

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Termination Costs (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2012
Termination Costs [Abstract]
Restructuring Costs	$ 828
Supplemental Unemployment Benefits, Severance Benefits	0
Payments for Postemployment Benefits	(48)
Supplemental Unemployment Benefits, Severance Benefits	$ 780

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Stock Based Compensation - Stock Option Activity (Details) (USD $)	3 Months Ended
	Sep. 30, 2012		Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Balance at beginning of year (in shares)	6,753,125
Granted (in shares)	925,000	[1]	0	[1]
Forfeited (in shares)	(483,334)
Options outstanding at year end (in shares)	7,194,791
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	5 years 1 month 6 days	[2]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Weighted Average Exercise Price per Share, Balance at beginning of year	$ 1.44	[2]
Weighted Average Exercise Price Per Share, Granted	$ 1.31	[2]
Weighted Average Exercise Price, Forfeited	$ 1.13	[2]
Weighted Average Exercise Price per Share, Options outstanding at year end	$ 1.37	[2]
Stock options | 1998 Stock Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant	460,000
Performance Based Options
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Granted (in shares)	75,000
Other Options
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Granted (in shares)	800,000

[1] There were no stock option grants for the three months ended September 30, 2011.

[2] Weighted average exercise price per share

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Consolidated Statements of Comprehensive Income (Loss) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ (5,310)	$ 925
Foreign currency translation adjustments	941	(1,242)
Unrealized holding (losses) gains on securities available for sale, net of deferred tax of $0	(22)	(34)
Total comprehensive income (loss)	(4,391)	(351)
Net loss attributable to non-controlling interest in subsidiary	0	(15)
Comprehensive income (loss) attributable to Magellan Petroleum Corporation	(4,391)	(336)
Accumulated Other Comprehensive Income (Loss)
Foreign currency translation adjustments	941
Unrealized holding (losses) gains on securities available for sale, net of deferred tax of $0	$ (22)

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Debt

3 Months Ended

Sep. 30, 2012

Debt Disclosure [Abstract]

Debt

Note 3 - Debt

Long term debt relates to a $1.7 million note payable re-issued in January 2011. This note will be fully amortized in June 2014. The outstanding principal as of September 30, 2012, and June 30, 2012, consisted of the following:

	September 30, 2012			June 30, 2012
	(In thousands)
Note payable	$	738		$	870
Less current portion of note payable	(456		)	(480		)
Long term debt, excluding current portion	$	282		$	390

As of September 30, 2012, the minimum future principal maturities of long term debt were as follows:

	September 30, 2012
	(In thousands)
One year	$	456
Two years	282
Total	$	738

The variable rate of the note is based upon the Wall Street Journal Prime Rate (the "Index") plus 1.00%, subject to a floor rate of 6.25%. The Index was 3.25% at September 30, 2012, resulting in an interest rate of 6.25% per annum as of September 30, 2012. Under the note payable, NP is required to maintain certain customary financial and restrictive covenants. As of September 30, 2012, NP was in compliance with all financial and restrictive covenants.

In addition, 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 $0.1 million as of September 30, 2012. The line of credit bears interest at a variable rate, which was 6.25% as of September 30, 2012. The line of credit also secures both a letter of credit in the amount of $25 thousand in favor of the Bureau of Land Management and business credit cards in the amount of $25 thousand. As of September 30, 2012, $0.8 million was available under this line of credit.

The note payable, letters of credit, and business credit cards are collateralized by a first mortgage and an assignment of production from Poplar and are guaranteed by Magellan 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, due to its variable interest rate, which resets based on the market rates.

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Earnings Per Share (Tables)

3 Months Ended

Sep. 30, 2012

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The following table summarizes the computation of basic and diluted earnings per share for the three months ended:

	September 30,
	2012			2011
	(In thousands, except share and per share amounts)
Net (loss) income attributable to Magellan Petroleum Corporation	$	(5,310	)	$	940
Basic weighted average shares outstanding	53,849,181			52,915,811
Add: dilutive effects of stock options and unvested stock grants (1)	—			1,804,917
Diluted weighted average common shares outstanding	53,849,181			54,720,728
Net (loss) income per basic share outstanding	$	(0.10	)	$	0.02
Net (loss) income per diluted share outstanding	$	(0.10	)	$	0.02

⁽¹⁾ There is no dilutive effect on earnings per share in periods with net losses.

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following for the three months ended:

	September 30,
	2012	2011
Stock options	75,000	7,697,826
Non-vested restricted stock	—	104,167
Total	75,000	7,801,993

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Fair Value Measurements - Unobservable Input Reconciliation (Details) (Recurring, Level 3, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2012	Jun. 30, 2012
Recurring | Level 3
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Business Acquisition, Contingent Consideration, at Fair Value	$ 4,152	$ 4,072
Accretion Expense	$ 80

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Termination Costs

3 Months Ended

Sep. 30, 2012

Termination Costs [Abstract]

Compensation Related Costs, General [Text Block]

Note 13 - Employee Termination Costs

The Company is required to record charges for one-time employee termination benefits and other associated costs as incurred. In July 2012, the Company incurred severance costs related to certain employees relating to their termination in accordance with their employment agreements. For the three months ended September 30, 2012, the Company expensed total employee-related termination costs of $0.8 million, all of which was charged to general and administrative expense in the unaudited condensed consolidated statement of operations. The Company does not project any additional benefits or other associated costs related to these terminations. The liability related to these termination costs are included in the unaudited condensed consolidated balance sheet under accrued and other liabilities.

A reconciliation of the beginning and ending liability balance for charges to general and administrative expense and cash payments for the three months ended September 30, 2012, is as follows:

	Total
	(In thousands)
June 30, 2012	$	—
Charges to general and administrative expense	828
Cash payments	(48		)
September 30, 2012	$	780