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Document and Entity Information (USD $)
12 Months Ended
Jun. 30, 2013
Sep. 12, 2013
Dec. 31, 2012
Document And Entity Information [Abstract]
Document Type 10-K
Document Period End Date Jun 30, 2013
Amendment Flag false
Document Fiscal Period Focus FY
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 Smaller Reporting Company
Entity Registrant Name MAGELLAN PETROLEUM CORP /DE/
Entity Voluntary Filers No
Entity Well-known Seasoned Issuer No
Entity Common Stock Shares Outstanding 45,359,647
Entity Public Float $ 33,470,909
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Consolidated Balance Sheets (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2013
Jun. 30, 2012
CURRENT ASSETS:
Cash and cash equivalents $ 32,469 $ 41,215
Accounts receivable — trade 794 1,152
Accounts receivable — working interest partners 58 231
Inventories 555 499
Prepaid and other assets 1,422 511
Total current assets 35,298 43,608
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
Proved oil and gas properties 35,377 33,927
Less accumulated depletion, depreciation, and amortization (5,814) (5,740)
Unproved oil and gas properties 5,312 7,091
Wells in progress 923 3,744
Land, buildings and equipment (net of accumulated depreciation of $1,810 and $2,077 as of June 30, 2013, and 2012, respectively) 1,382 1,422
Net property and equipment 37,180 40,444
OTHER NON-CURRENT ASSETS:
Goodwill 2,174 2,174
Deferred income taxes 7,217 5,951
Other long term assets 403 397
Total other non-current assets 9,794 8,522
Total assets 82,272 92,574
CURRENT LIABILITIES:
Short term line of credit 51 50
Current portion of note payable 390 480
Current portion of asset retirement obligations 476 329
Accounts payable 1,948 3,672
Accrued and other liabilities 2,757 3,000
Accrued dividends 202 0
Total current liabilities 5,824 7,531
LONG TERM LIABILITIES:
Note payable 0 390
Asset retirement obligations 6,403 7,455
Contingent consideration payable 3,940 4,072
Other long term liabilities 163 218
Total long term liabilities 10,506 12,135
COMMITMENTS AND CONTINGENCIES (Note 12)      
Series A convertible preferred stock (par value $0.01 per share): Issued 19,239,734 and 0 as of June 30, 2013, and 2012, respectively; liquidation preference $27,227 23,502 0
EQUITY (Note 9):
Common stock (par value $0.01 per share): Authorized 300,000,000 shares, issued, 54,057,159 and 53,835,594 as of June 30, 2013, and 2012, respectively 540 538
Treasury stock (at cost): 9,414,176 and 0 shares as of June 30, 2013 and 2012, respectively (9,333) 0
Capital in excess of par value 90,786 90,753
Accumulated deficit (50,079) (29,590)
Accumulated other comprehensive income 10,526 11,207
Total equity attributable to Magellan Petroleum Corporation 42,440 72,908
Total liabilities, preferred stock and equity $ 82,272 $ 92,574
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Consolidated Balance Sheets (Parentheticals) (USD $)
Jun. 30, 2013
Jun. 30, 2012
Statement of Financial Position [Abstract]
Accumulated depreciation $ 1,810,000 $ 2,077,000
Preferred stock, par value $ 0.01 $ 0.01
Preferred stock, outstanding 19,239,734 0
Preferred stock, liquidation preference $ 27,227,000 $ 0
Common stock, par value $ 0.01 $ 0.01
Common stock, authorized 300,000,000 300,000,000
Common stock, outstanding 54,057,159 53,835,594
Treasury Stock, Shares, Acquired 9,414,176 0
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Consolidated Statement of Operations (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Jun. 30, 2013
Jun. 30, 2012
REVENUES:
Oil production $ 6,131 $ 12,405
Gas production 939 1,307
Total revenues 7,070 13,712
OPERATING EXPENSES (INCOME):
Lease operating 7,037 12,897
Depletion, depreciation, amortization, and accretion 1,534 1,744
Exploration 8,267 6,291
General and administrative 11,829 13,091
Impairment 890 328
Gain on sale of assets 0 (40,413)
Total operating expense (income) 29,557 (6,062)
(LOSS) INCOME FROM OPERATIONS (22,487) 19,774
OTHER INCOME:
Net interest income 624 749
Other income 830 9
Total other income 1,454 758
(LOSS) INCOME BEFORE INCOME TAX (21,033) 20,532
Income tax benefit 1,266 5,951
(LOSS) INCOME AFTER INCOME TAX (19,767) 26,483
Net loss attributable to non-controlling interest in subsidiaries 0 15
NET (LOSS) INCOME APPLICABLE TO MAGELLAN PETROLEUM CORPORATION (19,767) 26,498
Preferred stock dividend and accretion of preferred stock (722) 0
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS $ (20,489) $ 26,498
(Loss) Earnings per common share (Note 10):
Weighted average number of basic shares outstanding 49,642,083 53,592,958
Weighted average number of diluted shares outstanding 49,642,083 54,041,227
Net (loss) income per basic share outstanding (dollars per share) $ (0.41) $ 0.49
Net (loss) income per diluted share outstanding (dollars per share) $ (0.41) $ 0.49
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Consolidated Statements of Comprehensive (Loss) Income (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Statement of Other Comprehensive Income [Abstract]
(LOSS) INCOME AFTER INCOME TAX $ (19,767) $ 26,483
Foreign currency translation adjustments (569) (1,180)
Unrealized holding losses on securities available for sale, net of deferred tax of $0 (112) (83)
TOTAL COMPREHENSIVE (LOSS) INCOME (20,448) 25,220
Net loss attributable to non-controlling interest in subsidiary 0 15
COMPREHENSIVE (LOSS) INCOME ATTRIBUTABLE TO MAGELLAN PETROLEUM CORPORATION $ (20,448) $ 25,235
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Consolidated Statements of Comprehensive (Loss) Income (Parentheticals) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Statement of Other Comprehensive Income [Abstract]
Unrealized holding (losses) gains on securities available for sale, tax $ 0 $ 0
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Consolidated Statement of Stockholders' Equity (USD $)
In Thousands, except Share data, unless otherwise specified
Total
Common Stock
Capital in Excess of Par Value
Treasury Stock
Accumulated Deficit
Accumulated Other Comprehensive Income
Non-Controlling Interest
Amount, Beginning Balance at Jun. 30, 2011 $ 52,528 $ 525 $ 93,617 $ 0 $ (56,073) $ 12,470 $ 1,989
Shares, Beginning Balance at Jun. 30, 2011 52,455,977
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income 26,483 26,498 (15)
Foreign currency translation adjustments (1,180) (1,180)
Unrealized holding losses on securities available for sale, net of deferred tax of $0 (83) (83)
Stock and stock based compensation (in shares) 175,000
Stock and stock based compensation 1,560 2 1,558
Stock options exercised (in shares) 21,875 21,875
Stock options exercised 35 0 35
Acquisition of non-controlling interest (in shares) 927,352
Acquisition of non-controlling interest (6,824) 9 (4,844) (15) (1,974)
Acquisition of working interest (in shares) 255,390
Acquisition of working interest 389 2 387
Amount, Ending Balance at Jun. 30, 2012 72,908 538 90,753 0 (29,590) 11,207 0
Shares, Ending Balance at Jun. 30, 2012 53,835,594
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (19,767) (19,767)
Foreign currency translation adjustments (569) (569)
Unrealized holding losses on securities available for sale, net of deferred tax of $0 (112) (112)
Stock and stock based compensation (in shares) 221,565
Stock and stock based compensation 848 2 846
Stock options exercised (in shares) 0
Stock options exercised (9,333) (9,333)
Warrants repurchased and retired (813) (813)
Preferred stock accretion to fair value (520) (520)
Preferred stock dividend (202) (202)
Amount, Ending Balance at Jun. 30, 2013 $ 42,440 $ 540 $ 90,786 $ (9,333) $ (50,079) $ 10,526 $ 0
Shares, Ending Balance at Jun. 30, 2013 54,057,159
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Consolidated Statements of Cash Flows (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Jun. 30, 2013
Jun. 30, 2012
OPERATING ACTIVITIES:
(LOSS) INCOME AFTER INCOME TAX $ (19,767) $ 26,483
Adjustments to reconcile net loss to net cash used in operating activities:
Foreign transaction loss (gain) 18 (1,038)
Depletion, depreciation, amortization, and accretion 1,534 1,744
Interest earned on restricted deposits 0 (24)
Fair value decrease of contingent consideration payable (132) (79)
Deferred income taxes (1,266) (5,951)
Gain on disposal of assets 0 (40,413)
Exploration costs previously capitalized 2,299 2,930
Stock based compensation 848 1,560
Related party withholding tax (Note 13) 0 1,082
Impairment loss 890 328
Severance benefit costs 418 0
Net changes in operating assets and liabilities:
Accounts receivable 401 3,021
Inventories (47) 142
Prepayments and other current assets 80 (36)
Accounts payable and accrued liabilities (3,255) (138)
Other long term liabilities (51) (113)
Income taxes payable 0 61
Net cash used in operating activities (18,030) (10,441)
INVESTING ACTIVITIES:
Additions to property and equipment (2,925) (9,577)
Proceeds from sale of assets 0 35,089
Purchase of working interest in Poplar 0 (823)
Refund of deposit for purchase of Evans shoal (includes interest) 0 10,940
Net cash (used in) provided by investing activities (2,925) 35,629
FINANCING ACTIVITIES:
Proceeds from issuance of stock 0 35
Repurchase of common stock (9,333) 0
Repurchase of warrant (813) 0
Proceeds from issuance of preferred stock, net of $520 issuance cost 22,982 0
Short term debt issuances 2,000 6,075
Short term debt repayments (1,999) (6,025)
Purchase of non-controlling interest - Nautilus Poplar LLC 0 (3,461)
Long term debt repayments (480) (552)
Net cash provided by (used in) financing activities 12,357 (3,928)
Effect of exchange rate changes on cash and cash equivalents (148) (462)
Net (decrease) increase in cash and cash equivalents (8,746) 20,798
Cash and cash equivalents at beginning of period 41,215 20,417
CASH AND CASH EQUIVALENTS AT END OF PERIOD 32,469 41,215
Cash payments (receipts):
Interest paid 63 109
Supplemental schedule of non-cash investing and financing activities:
Unrealized holding loss (112) (83)
Revision to estimate of asset retirement obligation (758) (603)
Asset retirement obligation assumed 3 3,035
Accounts payable related to capital expenditure 81 155
Accrued preferred stock dividends 202 0
Accretion of preferred stock to fair value 520 0
Amounts in accrued and other liabilities related to Sopak (See Note 13) 1,000 0
Amounts in prepaid and other assets related to Sopak (See Note 13) 1,000 0
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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Consolidated Statements of Cash Flows (Parentheticals) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Jun. 30, 2013
Payments of stock issuance costs $ 520
Nautilus Poplar, LLC (NP)
Additional working interest acquired 3.00%
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Basis of Presentation
12 Months Ended
Jun. 30, 2013
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. The Company conducts its operations through three wholly owned subsidiaries: Nautilus Poplar LLC ("NP"), which owns and operates an oil field covering the Poplar Dome ("Poplar") located in the Williston Basin in eastern Montana; Magellan Petroleum Australia Pty Ltd ("MPA"), which owns and operates gas fields in Australia; and Magellan Petroleum (UK) Limited ("MPUK"), which owns a large acreage position in the Weald and Wessex Basins in southern England for conventional and unconventional oil and gas production.

Basis of Presentation
The accompanying consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP, MPA and MPUK, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") and the instructions to Form 10-K and Regulation S-X published by the US Securities and Exchange Commission (the "SEC"). All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the prior year net income, accumulated deficit, net assets or total shareholders' equity. The Company has evaluated events or transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements. All amounts presented are in US dollars, unless otherwise noted. Amounts expressed in Australian currency are indicated as "AUD."

Use of Estimates
The preparation of 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 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 currency of our foreign subsidiaries is their local currency. Assets and liabilities of foreign subsidiaries are translated to US dollars at period-end exchange rates, and our consolidated statements of operations and cash flows are translated at average exchange rates during the reporting period. Resulting translation adjustments are recorded as a separate component of stockholders' equity as accumulated other comprehensive (loss) income.
Transactions denominated in currencies other than the local currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in foreign currency transaction gains and losses that are reflected in results of operations as unrealized (based on period end translation) or realized (upon settlement of the transactions) and reported under general and administrative expenses in the consolidated statements of operations.

Cash and Cash Equivalents and Concentration of Credit Risk
The Company considers all highly liquid short term investments with original maturities of three months or less at the date of acquisition to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short term nature of these instruments.
The Company's financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents. Cash and cash equivalents are held in several Australian banks in time deposit accounts that have terms of 90 days or less. The Company regularly assesses the level of credit risk we are exposed to and whether there are better ways of managing credit risk. The Company invests its cash and cash equivalents with reputable financial institutions. At times, balances deposited may exceed FDIC insured limits. The Company has not incurred any losses related to these deposits.

Accounts Receivable
Trade accounts receivable consist mainly of receivables from oil and gas purchasers. For receivables from working interest partners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, oil and gas receivables are collected within two months. The collectability of accounts receivable is continuously monitored and analyzed based upon historical experience. The use of judgment is required to establish a provision for allowance for doubtful accounts for specific customer collection issues identified. The allowance for doubtful accounts were $0 as of June 30, 2013, and 2012, respectively.

Inventories
Our inventories consist of oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies, ordinary maintenance materials, and parts and production equipment for use in future drilling operations or repair operations. All inventories are carried at the lower of cost or net realizable value.

Oil and Gas Exploration and Production Activities
The Company follows the successful efforts method of accounting for its oil and gas exploration and production activities. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost. Exploration expenses include dry hole costs, geological and geophysical expenses, and the costs of carrying and retaining unproved properties.
Depreciation, depletion, and amortization ("DD&A") of capitalized costs related to proved oil and gas properties is calculated on a property-by-property basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. The Company records its proportionate share in joint venture operations in the respective classifications of assets, liabilities, and expenses.
The sale of a partial interest in a proved oil and gas property is accounted for as normal retirement, and no gain or loss is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. A gain or loss is recognized for all other sales of producing properties and is included in the accompanying consolidated statements of operations.
The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of estimated future cash flows, net of estimated operating and development costs, using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.

Land, Buildings, and Equipment
Land, buildings, and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets which range from three to fifteen years.

Securities Available for Sale
Securities available for sale are comprised of investments in publicly traded securities and are carried at quoted market prices and included in the consolidated balance sheets under prepaid and other assets. Unrealized gains and losses are excluded from earnings and recorded as a component of accumulated other comprehensive (loss) income in shareholders' equity, net of deferred income taxes, until realized.

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 during fiscal year 2012 as allowed by ASU No. 2011-08, and therefore an assessment of qualitative factors for our annual impairment test is now performed.
A triggering event occurred in fiscal 2013 which required the Company to test its Goodwill for impairment. See Note 1 - Basis of Presentation, for additional information regarding the Company's realignment of its reporting segments. As of June 30, 2013 and 2012, management concluded that there is no impairment of goodwill. The qualitative factors used in our assessment include macroeconomic conditions, industry and market conditions, cost factors, and overall financial performance.
Historical goodwill in the amount of $0.7 million relates to the acquisition of a majority ownership stake in NP, and $4.0 million relates to the acquisition of an additional ownership interest in MPA. The decrease in goodwill during fiscal 2012 relates to the disposition of a portion of the MPA reporting segment associated with the Santos SA (see Note 2).
As of June 30, 2013, $0.7 million of recorded goodwill related to NP, $1.3 million related to MPA, and $0.2 million related to MPUK. Changes in goodwill can be summarized as follows for the years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Fiscal year opening balance
$
2,174

 
$
4,695

Sale of Mereenie interests (see Note 2)

 
2,521

Fiscal year closing balance
$
2,174

 
$
2,174



Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase in the carrying value of the related long-lived asset are recorded at the time a well is acquired or the liability to plug is legally incurred. The increase in carrying value is included in proved oil and gas properties in the accompanying consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs, net of estimated salvage values, and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties (see Note 4).

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

Major Customers
For our NP reporting segment, revenue from a single customer accounted for approximately 87%, and 45% of the Company's consolidated oil and gas production revenue for the years ended June 30, 2013, and 2012, respectively. For our MPA reporting segment, revenue from one customer accounted for approximately 13% and 0%, and revenue from a second customer accounted for approximately 0%, and 45% of consolidated oil and gas production revenue for the years ended June 30, 2013, and 2012, respectively.

Preferred Stock
The Company has 50.0 million shares of preferred stock authorized, par value $0.01 per share, issuable from time to time in one or more series at the discretion of the Company's Board of Directors. As of June 30, 2013, 19,239,734 shares of preferred stock were issued and outstanding.

Stock Based Compensation
Stock option grants may contain both time based or performance based vesting provisions. The time based options are expensed on a straight-line basis over the vesting period. Performance based options ("PBOs") are recognized when the achievement of the performance conditions are considered probable. Accordingly, the Company recognizes stock based compensation expense on PBOs over the period of time the performance condition is expected to be achieved. Management re-assesses whether achievement of performance conditions is probable at the end of each reporting period. If changes in the estimated outcome of the performance conditions affect the quantity of the awards expected to vest, the cumulative effect of the change is recognized in the period of change.
The Company estimates the fair value of PBOs and time based stock options using the Black-Scholes-Merton pricing model. The fair value of the stock options is determined on the grant date and is affected by our stock price and other assumptions regarding a number of complex and subjective variables. These variables include our expected stock price volatility over the term of the awards, risk free interest rates, expected dividends, and the expected option exercise term. The Company uses the simplified method to estimate the expected term of stock options due to a lack of related historical data of exercise, cancellation and forfeiture rates.

Accounting for Income Taxes
The Company follows the liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company records a valuation allowance for deferred tax assets when it is more likely than not that such assets will not be recovered.
GAAP prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the financial statements uncertain tax positions that the Company has taken or expects to take in its tax returns. Under GAAP, the Company recognizes tax positions when it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company has presumed that its positions will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The next step consists of measurement. A tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. A tax position is measured at the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. An uncertain income tax position will not be recognized if it does not meet the more-likely-than-not threshold. To appropriately account for income tax matters, the Company is required to make significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. There are no uncertain tax positions that would meet the more-likely-than-not recognition threshold for the fiscal years ended June 30, 2013, or 2012.
The Company has adopted an accounting policy to record all tax related interest under the interest expense and tax related penalties under general and administrative expense in the consolidated statement of operations.

Financial Instruments
The carrying value for cash and cash equivalents, accounts receivable, accounts payable, and debt approximates fair value based on the timing of the anticipated cash flows and current market conditions.

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.
The fair value of the contingent consideration payable is calculated using production projections and the estimated timing of production payouts. The Company also utilized a discount which is consistent with the the Company’s credit adjusted incremental borrowing rate.

Segment Information
During the quarter ended June 30, 2013, the Company completed a corporate restructuring of its wholly owned subsidiary in the UK whereby the equity interest in MPUK was transferred from MPA to MPC. The Company benefits from this improved structure through (i) simplified accounting and the elimination of administrative redundancies, (ii) enhanced communication and clarity for investors, and (iii) increased flexibility in the structuring of investment and operating decisions. This realignment in corporate structure required the Company to re-evaluate its reportable segments under Financial Accounting Standards Board (the "FASB") ASC Topic 280, Segment Reporting. As of June 30, 2013, the Company determined, based on the criteria of FASB ASC Topic 280, it operates in three segments, NP, MPA and MPUK, as well as a head office, Magellan ("Corporate"), which is treated as a cost center. As of June 30, 2013, these three operating segments met the minimum quantitative threshold to qualify for separate segment reporting. As of June 30, 2012, MPUK did not meet the criteria as a separate reporting segment under FASB ASC Topic 280.
The Company's chief operating decision maker is J. Thomas Wilson (President and CEO of the Company), who reviews the results and manages operations of the Company in the three reporting segments being NP, MPA, and MPUK. The presentation of all historical segment information herein has been changed to conform to this segment reporting structure, which also reflects the manner in which the Company's management monitors performance and allocates resources. For information pertaining to our reporting segments, see Note 11 - Segment Information.

(Loss) Earnings per Common Share
Income and losses per common share are based upon the weighted average number of common and common equivalent shares outstanding during the period. The effect of potential dilutive securities in the determinations of diluted earnings per share are the dilutive effect of stock options, non-vested restricted stock, and the shares of Series A convertible preferred stock. The potential dilutive impact of stock options, and non-vested restricted stock is determined using the treasury stock method. The potential dilutive impact of the shares of Series A convertible preferred stock is determined using the "if-converted" method. In applying the if-converted method, conversion is not assumed for purposes of computing dilutive shares if the effect would be antidilutive. The preferred stock is convertible at a rate of one common share to one preferred share. We did not include any stock options or common stock issuable upon the conversion of the Series A convertible preferred stock in the calculation of diluted (loss) earnings per share during the fiscal year ended June 30, 2013, as they would be antidilutive.

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

Recently Issued Accounting Standards
In May 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-04, which improves comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with GAAP and International Financial Reporting Standards and clarifies the application of existing fair value measurement requirements including (i) the application of the highest and best use and valuation premise concepts, (ii) measuring the fair value of an instrument classified in a reporting entity's shareholders' equity, and (iii) quantitative information required for fair value measurements categorized within Level 3. ASU No. 2011-04 also provides guidance on measuring the fair value of financial instruments managed within a portfolio and application of premiums and discounts in a fair value measurement. In addition, ASU No. 2011-04 requires additional disclosure for Level 3 measurements regarding the sensitivity of fair value to changes in unobservable inputs and any interrelationships between those inputs. This guidance is effective prospectively for interim and annual periods beginning after December 15, 2011. The Company adopted this standard on July 1, 2012. The adoption of this standard did not have a material effect on the Company's financial statements.
In February 2013, the FASB issued ASU No. 2013-02, which requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required to be reclassified in its entirety to net income. For other amounts that are not required to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures that provide additional detail about those amounts. ASU No. 2013-02 does not change the current requirements for reporting net income or other comprehensive income in financial statements. This guidance is effective prospectively for interim and annual periods beginning after December 15, 2012. The Company adopted this standard on July 1, 2012. The adoption of this standard did not have a material effect on the Company's financial statements.
There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of June 30, 2013.
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Acquisitions and Divestitures
12 Months Ended
Jun. 30, 2013
Business Combinations [Abstract]
Acquisitions and Divestitures
Note 2 - Acquisitions and Divestitures
Evans Shoal Agreement. During the year ended June 30, 2010, MPA entered into an agreement with Santos Offshore Pty Ltd to purchase their 40% interest in the Evans Shoal natural gas field (NT/P48). On July 22, 2011, this agreement was terminated, and MPA received a deposit refund of AUD $10.0 million plus interest, pursuant to the terms of the agreement.
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 MPA, Santos QNT Pty Ltd ("Santos QNT"), and Santos Limited (collectively "Santos") completed a Sale Agreement (the "Santos SA"), referred to herein as the "Santos Transaction" and became the sole owner of the Palm Valley Interests (as defined below) and of the Dingo Interests (as defined below), while Santos became the sole owner of the Mereenie Interests (as defined below). In accordance with the terms of the Santos SA, the Santos Transaction is deemed to be effective as of July 1, 2011. The Santos SA 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 QNT;
Santos' 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 to be paid based on production levels at Mereenie achieved subsequent to the Santos Transaction. The maximum cumulative proceeds of the series of contingent payments is A$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 allocated to the group of assets sold and recorded as a component of the gain on sale of assets. The purchase price allocation was considered final as of June 30, 2012 and the Santos SA was deemed to be effective as of July 1, 2011.
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 (including basis in properties exchanged and allocated goodwill)
2,805

Gain on sale of assets
(36,166
)
Total
$
(26,631
)

Lease Purchase and Sale and Participation Agreement with VAALCO Energy (USA), Inc. ("VAALCO"). On September 6, 2011, the Company entered into a Lease Purchase and Sale and Participation Agreement (the "VAALCO PSA") with VAALCO. Pursuant to the VAALCO PSA, the Company received $5.0 million in cash, and VAALCO received an undivided 65% of the Company’s working interest in formations below the top of the Bakken/Three Forks (the "Deep Intervals") in Poplar.
The accounting for this transaction is set forth in the table below:
 
Total
 
(In thousands)
Cash consideration received
$
5,000

Net book value allocated to Deep Intervals
(829
)
Transaction costs
(162
)
Gain on sale recognized
$
4,009


Acquisition of Non-Controlling Interest in Nautilus Poplar LLC and Acquisition of Additional Working Interests. On September 2, 2011, the Company entered into a Purchase and Sale Agreement (the "Nautilus PSA") between the Company and the non-controlling interest owners of NP, being the Nautilus Technical Group, LLC ("NT") and Eastern Rider, LLC ("ER") (the "Nautilus Sellers"). The Nautilus Sellers included J. Thomas Wilson (a Magellan director and now its President and CEO), a second individual who has served as a consultant to NP, and a third individual who was an employee of NP at the time of the transaction, as well as certain other persons.
The Nautilus PSA provided for the Company's purchase of all membership interests from the Nautilus Sellers in return for (i) $4.0 million in cash (the "Cash Consideration"), (ii) $2.0 million, less certain costs and certain debt owed to Magellan by the Nautilus Sellers, in unregistered shares of Magellan’s common stock, par value $0.01 (the "Net Share Consideration"), and (iii) the potential for future production payments ("Contingent Production Payments"), payable in cash to the Nautilus Sellers, collectively, of up to $5.0 million if certain increased average daily production milestones are achieved. The shares were sold pursuant to Section 4(2) of the Securities Act of 1933. The Cash Consideration was transferred on September 2, 2011. Consistent with the terms of the Nautilus PSA, 1,182,742 of shares in the Net Share Consideration were issued on September 23, 2011. J. Thomas Wilson’s interest in this transaction approximated 52% of the consideration paid to the Nautilus Sellers.
The discounted fair value of the future contingent consideration payable is calculated at the end of each fiscal quarter using a consistent valuation methodology and assumptions. As of June 30, 2013, and 2012, the contingent consideration payable was valued at $3.9 million and $4.1 million, respectively, and is reported in the consolidated balance sheet as contingent consideration payable.
The acquisition of NT’s direct working interests was treated as a business combination for accounting purposes. The fair value of assets acquired and liabilities assumed were recorded at estimated fair value. This estimate was made based on significant unobservable (Level 3) inputs and based on the best information available at the time (see Note 5). A de minimis amount of revenues and earnings related to the working interests acquired is included in the accompanying consolidated statements of operations for the year ended June 30, 2012.
The table below summarizes the consideration paid to the Nautilus Sellers under the Nautilus PSA and the estimated fair value of the assets acquired and liabilities assumed for the working interests acquired from NT.
 
NT non-
controlling
 interest in NP
 
NT working
 interest in
 Poplar
 
ER non-
controlling
 interest in NP
 
Total
 
(In thousands)
Consideration paid to the Nautilus Sellers (1):
 
 
 
 
 
 
 
Cash consideration
$
1,920

 
$
823

 
$
1,257

 
$
4,000

Share consideration (2)
907

 
389

 
526

 
1,822

Fair value of contingent consideration payable
1,993

 
854

 
1,304

 
4,151

Total
$
4,820

 
$
2,066

 
$
3,087

 
$
9,973

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
(In thousands)
Allocation of the consideration paid to the fair value of assets:
 
 
 
 
 
 
 
Oil and gas assets (proved)
 
 
 
 
 
 
$
1,462

Oil and gas assets - Deep Intervals (unproved)
 
 
 
 
 
 
679

ARO liability
 
 
 
 
 
 
(75
)
Total
 
 
 
 
 
 
$
2,066

(1) Excludes transaction costs.
(2) Common stock valued at $1.54 per share closing price on the date of the transaction.
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Debt
12 Months Ended
Jun. 30, 2013
Debt Disclosure [Abstract]
Debt
Note 3 - Debt
Long term debt relates to a $1.7 million note payable re-financed by NP in January 2011 (the "Note Payable"). This Note Payable will be fully amortized in June 2014. The outstanding principal consisted of the following for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Note payable
$
390

 
$
870

Less current portion of note payable
(390
)
 
(480
)
Long term debt, excluding current portion
$

 
$
390


As of June 30, 2013, the minimum future principal maturities of long term debt were as follows:
 
Total
 
(In thousands)
One year
$
390


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 June 30, 2013, resulting in an interest rate of 6.25% per annum as of June 30, 2013. Under the Note Payable, NP is subject to certain customary financial and restrictive covenants. As of June 30, 2013, 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 "Line of Credit"). The amount due on the Line of Credit was $51 thousand and $50 thousand as of June 30, 2013, and 2012, respectively. The Line of Credit bears interest at a variable rate, which was 6.25% as of June 30, 2013. The Line of Credit also secures a letter of credit in the amount of $25 thousand in favor of the Bureau of Land Management. As of June 30, 2013, $0.9 million was available under this Line of Credit.
The Note Payable and Line of Credit 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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Asset Retirement Obligations
12 Months Ended
Jun. 30, 2013
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 consolidated statement of operations.
If the fair value of a recorded AROs change, a revision is recorded to both the ARO and the asset retirement capitalized cost. The revision recognized during fiscal year ended June 30, 2013, primarily resulted from a change in the expected timing of estimated abandonment cost for our oil and gas properties.
The following table summarizes the asset retirement obligation activity for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Fiscal year opening balance
$
7,784

 
$
11,397

Liabilities assumed
3

 
3,035

Liabilities incurred

 
398

Accretion expense
433

 
568

Sale of assets

 
(6,773
)
Revision to estimate
(758
)
 
(603
)
Effect of exchange rate changes
(583
)
 
(238
)
Fiscal year closing balance
6,879

 
7,784

Less current asset retirement obligation
476

 
329

Long term asset retirement obligation
$
6,403

 
$
7,455

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Fair Value Measurements
12 Months Ended
Jun. 30, 2013
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 using market participant assumptions at the measurement date. 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 three levels are defined as follows:
Level 1: Quoted prices in active markets for identical assets.
Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets 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 inputs to the valuation model are unobservable inputs.
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 years ended June 30, 2013, and 2012, there have been no transfers in and/or out of Level 1, Level 2, or Level 3.

Assets and liabilities measured on a recurring basis
The Company's financial instruments, including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short term maturity of these instruments. The recorded value of the Line of Credit and Note Payable (see Note 3), approximates fair value due their variable rate structure. The Company's other financial and non-financial assets and liabilities measured on a recurring basis are measured and reported at fair value.
The following table presents items required to be measured at fair value on a recurring basis by the level in which they are classified within the valuation hierarchy for the fiscal years ended:
 
June 30, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Cash equivalents (1)
$
26,270

 
$

 
$

 
$
26,270

Securities available for sale (2)
44

 

 

 
44

 
$
26,314

 
$

 
$

 
$
26,314

Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable
$

 
$

 
$
3,940

 
$
3,940

 
 
 
 
 
 
 
 
 
June 30, 2012
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Cash equivalents (1)
$
38,565

 
$

 
$

 
$
38,565

Securities available for sale (2)
155

 

 

 
155

 
$
38,720

 
$

 
$

 
$
38,720

Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable
$

 
$

 
$
4,072

 
$
4,072


(1) Cash equivalents have maturities of 90 days or less. In the US cash equivalents were held in US Treasury notes and in Australia cash equivalents were held in several time deposit accounts.
(2) Included in the consolidated balance sheets under prepaid and other assets.
The contingent consideration payable is a standalone liability that is measured at fair value on a recurring basis for which there is no available quoted market price, principal market, or market participants. The inputs for this instrument are unobservable and therefore classified as Level 3 inputs. The calculation of this liability is a significant management estimate and uses drilling and production projections, consistent with the Company's reserve report for NP, to estimate future production bonus payments, and a discount rate that is reflective of the Company's credit adjusted borrowing rate. Inputs are reviewed by management on an annual basis and the liability is estimated by converting estimated future production bonus payments to a single net present value using a discounted cash flow model. Payment of future production bonuses are sensitive to the Company's 60 day rolling production average. The contingent consideration payable would increase with significant production increases, and or a reduction in the discount rate.
The following table presents information about significant unobservable inputs to the Company's Level 3 financial liability measured at fair value on a recurring basis for the fiscal years ended:
 
 
 
 
 
 
June 30,
Description
 
Valuation technique
 
Significant unobservable inputs
 
2013
 
2012
Contingent consideration payable
 
Discounted cash flow model
 
Discount rate
 
8.0%
 
8.0%
 
 
 
 
First production payout
 
December 31, 2015
 
December 31, 2013
 
 
 
 
Second production payout
 
December 31, 2016
 
December 31, 2015

Adjustments to the fair value of the contingent consideration payable is recorded in the consolidated statements of operations under net interest income. The following table presents a roll forward of the contingent consideration payable for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Fiscal year beginning balance
$
4,072

 
$

Liability assumed

 
4,151

Accretion expense
326

 
247

Revision to estimate
(458
)
 
(326
)
Fiscal year closing balance
$
3,940

 
$
4,072


Assets and liabilities measured on a nonrecurring basis
Due to the unobservable nature of the significant inputs required to measure these items at fair value, they are classified within Level 3. The following table presents information about significant unobservable inputs to the Company's Level 3 financial assets and liabilities measured at fair value on a nonrecurring basis: fiscal years ended:
Description
 
Fair value
 
Valuation technique
 
Significant unobservable inputs
 
Range of inputs
 
 
(In thousands)
 
 
 
 
 
 
Acquisition of oil and gas properties under the Nautilus PSA
 
$
2,141

 
Combination of discounted cash flow model and market value approach
 
Adjusted oil price
 
$95/bbl
Discount rate
10.0%
 
 
 
 
 
 
 
 
 
Palm Valley oil and gas properties acquired in Santos SA
 
$
3,403

 
Discounted cash flow model
 
Contract period
 
17 to 19 years
Discount rate
10.0% to 11.5%
 
 
 
 
 
 
 
 
 
Issuance of preferred stock to One Stone
 
$
23,502

 
Market value approach
 
Issuance price
 
$1.22149381

The Company also utilizes fair value to perform impairment tests as required on its oil and gas properties. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and is also classified within Level 3.
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Income Taxes
12 Months Ended
Jun. 30, 2013
Income Tax Disclosure [Abstract]
Income Taxes
Note 6 - Income Taxes
The domestic and foreign components of our (loss) income before income taxes are as follows for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
United States
$
(9,449
)
 
$
(6,646
)
Australia
(7,537
)
 
30,876

United Kingdom
(4,047
)
 
(3,698
)
(LOSS) INCOME BEFORE INCOME TAX
$
(21,033
)
 
$
20,532


The following reconciles the Company's effective tax rate to the federal statutory tax rate for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Tax provision computed per federal statutory rate
$
(6,310
)
 
$
6,160

State taxes, net of federal benefit
(40
)
 
190

Foreign rate differential
(60
)
 
76

Non taxable Australian revenue
288

 
(8
)
Goodwill write off

 
756

Decreases related to lapse of applicable statute of limitations
685

 
1,571

Change in valuation allowance
7,897

 
9,352

Australian petroleum resource rent tax
(10,354
)
 
(5,951
)
Australian petroleum resource rent tax - income tax effect
3,106

 
1,785

Taxable dividends from subsidiaries, net of foreign tax credits
(709
)
 
(1,152
)
Foreign tax credit adjustment
787

 
649

Capital loss adjustment
309

 
(3,006
)
Additional basis related to the Santos SA

 
(18,118
)
Impact of rate change
140

 
457

Foreign currency translation differential
2,912

 
1,375

Other items
83

 
(87
)
Consolidated income tax benefit
$
(1,266
)
 
$
(5,951
)

The following summarizes components of our income tax provision for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Current income tax:
 
 
 
United States
$

 
$

Australia

 

United Kingdom

 

Total current income tax provision

 

 
 
 
 
Deferred income tax:
 
 
 
United States

 

Australia
(1,266
)
 
(5,951
)
United Kingdom

 

Total deferred income benefit provision
(1,266
)
 
(5,951
)
Consolidated income benefit provision
$
(1,266
)
 
$
(5,951
)
 
 
 
 
Effective tax rate
6
%
 
(29
)%

The Company's effective tax rate was increased to positive 6% primarily due to the extension of the Australian Petroleum Resource Rent Tax ("PRRT") to onshore projects which increased the related deferred tax asset.
Significant components of the Company's deferred tax assets and liabilities can be summarized as follows for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Deferred tax liabilities:
 
 
 
Land, buildings and equipment
$
(4,132
)
 
$
(2,767
)
Stepped up basis of oil and gas properties

 
(550
)
Australian petroleum resource rent tax - income tax effect
(2,165
)
 
(1,785
)
Other items
(237
)
 
(261
)
Total deferred tax liabilities
(6,534
)
 
(5,363
)
 
 
 
 
Deferred tax assets:
 
 
 
Asset retirement obligations
2,194

 
2,210

Net operating losses, capital losses, and foreign tax credit carry forwards
31,354

 
28,139

Australian petroleum resource rent tax
13,145

 
5,951

United Kingdom exploration costs and net operating losses
3,777

 
3,224

Stock option compensation
1,971

 
1,851

Interest

 
539

Australian capitalized legal costs
343

 
514

Other items
557

 
579

Total deferred tax asset
53,341

 
43,007

Valuation allowance
(39,590
)
 
(31,693
)
Net long term deferred tax asset
$
7,217

 
$
5,951


For the fiscal year ended June 30, 2013, the valuation allowance increased by $7.9 million, primarily due to additional book losses and a partial valuation allowance against the increase in the PRRT deferred tax assets.
The tax benefit recorded for fiscal year 2013 totals $1.3 million. In addition to corporate income tax, the income tax benefit includes the tax effect of the Company's obligation related to the Australian PRRT. The extension of PRRT to onshore projects was enacted during fiscal year 2012 and effective from July 1, 2012. As a consequence of the extension of the Australian PRRT regime to onshore petroleum products, a deferred tax benefit of $6.0 million was recorded during fiscal year 2012. On June 28, 2013, Australian Tax and Superannuation Laws Amendment (2013 Measures No. 1) Bill 2013 received Royal Assent. This new legislation clarifies that the Company is able to access 100% of the costs incurred in relation to the Palm Valley field since July 1, 2002. As a result of this legislative change, the gross deferred tax assets have been updated to reflect the additional basis available in costs incurred since July 1, 2002. Primarily as a result of additional qualifying expenditures incurred in Australia during fiscal year 2013 which are expected to be realized in future periods, the net deferred tax asset balance increased to $7.2 million during fiscal year 2013.
The US gross deferred tax assets and liabilities at June 30, 2013 consist primarily of foreign tax credits, property, plant and equipment, and stock options. The Australian deferred tax assets and liabilities at June 30, 2013 consist primarily of acquisition and development costs, asset retirement obligations, net operating and capital loss carry forwards, and other assets which will result in tax deductions when paid. Australian net operating and capital losses carry forward indefinitely.
After reviewing all positive and negative evidence, a valuation allowance is still recorded against all the net deferred tax assets related to corporate income taxes in the US, Australia and the UK. A partial valuation allowance is recorded against the deferred tax assets that relate to the Australian PRRT. As a result the Company has a net deferred tax asset of $7.2 million as of June 30, 2013.
As of June 30, 2013, the Company remains subject to examination in the following major tax jurisdictions for the tax years indicated below:
Jurisdiction
 
Tax Years Subject
 to Examination:
US Federal
 
2011 - 2012
Colorado
 
2010 - 2012
Connecticut
 
2010
Maine
 
2010 - 2012
Montana
 
2011 - 2012
Australia
 
2009 - 2012
United Kingdom
 
2009 - 2012

At June 30, 2013, the Company had net operating loss and foreign tax credit carry forwards for US Federal and State Income Tax purposes, respectively, which are scheduled to expire periodically as follows:
 
State Net Operating Losses
 
Federal Foreign Tax Credit
 
(In thousands)
Expires:
 
 
 
2017
$
301

 
$
310

2018
3,219

 

2019
1,432

 
1,411

2020
1,191

 
144

2021

 
1,006

2022

 
3,030

2023 and thereafter

 
4,050

Total
$
6,143

 
$
9,951


There are no uncertain tax positions that would meet the more-likely-than-not recognition threshold for the fiscal years ended June 30, 2013, or 2012.
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Stock Based Compensation
12 Months Ended
Jun. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock Based Compensation
Note 7 - Stock Based Compensation
The 2012 Stock Incentive Plan
On January 16, 2013, the Company's shareholders approved the Magellan Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (the "2012 Stock Incentive Plan"). The 2012 Stock Incentive Plan replaces the Company's 1998 Stock Incentive Plan (the "1998 Stock Plan"). The 2012 Stock Incentive Plan provides for the granting of stock options, stock appreciation rights, restricted stock and/or restricted stock units, performance shares and/or performance units, incentive awards, cash awards, and other stock based awards to employees, including officers, directors, and consultants of the Company (or subsidiaries of the Company) who are selected by the Compensation, Nominating and Governance Committee of the Board of Directors of the Company to receive incentive compensation awards. The stated maximum number of shares of the Company's common stock authorized for awards under the 2012 Stock Incentive Plan is 5,000,000 shares plus any remaining shares under the 1998 Stock Plan immediately before the effective date of the 2012 Stock Incentive Plan, which was 288,435 as of January 15, 2013. The maximum aggregate annual number of common shares or options that may be granted to one participant is 1,000,000, and the maximum annual number of performance shares, performance units, restricted stock or restricted stock units is 500,000. The maximum term of the 2012 Stock Incentive Plan is ten years.

Stock Option Grants
Under the 2012 Stock Incentive Plan, stock option grants may contain both time based or performance based vesting provisions. As of June 30, 2013, under the 2012 Stock Incentive Plan, all PBOs granted were fully vested and 4,776,769 shares, including forfeited shares, were available for future issuance. During the fiscal year ended June 30, 2013, 1,627,500 options were granted of which 75,000 were issued as PBOs and 882,500 options were issued outside of the 1998 Stock Plan. Options outstanding have expiration dates ranging from January 16, 2014, through January 14, 2023.
The following table summarizes the stock option activity for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
Number of
Shares
 
WAEPS (1)
 
Number of
Shares
 
WAEPS (1)
Fiscal year beginning balance
6,753,125

 
$1.44
 
5,200,000

 
$1.49
Granted
1,627,500

 
$1.23
 
1,675,000

 
$1.10
Exercised

 
$0.00
 
(21,875
)
 
$1.60
Forfeited
(591,668
)
 
$1.16
 
(100,000
)
 
$1.72
Options outstanding at end of fiscal year
7,788,957

 
$1.33
 
6,753,125

 
$1.44
 
 
 
 
 
 
 
 
Weighted average remaining contractual term
 
 
5.9 years
 
 
 
6.8 years
(1) Weighted average exercise price per share
Cash received from the exercise of stock options for the fiscal year ended June 30, 2012, was less than $0.1 million. No stock options were exercised during 2013. The following table summarizes options outstanding and exercisable as of June 30, 2013:
 
 
 
 
Options outstanding and exercisable
Range of
exercise
prices
 
Number
of
shares
 
Weighted average remaining contractual life
 
Weighted average exercise price
$0.79
-
$1.09
 
1,277,500

 
8.5 years
 
$1.04
$1.10
-
$1.13
 
1,691,666

 
8.5 years
 
$1.11
$1.14
-
$1.18
 
100,000

 
4.6 years
 
$1.16
$1.19
-
$1.40
 
3,100,000

 
2.9 years
 
$1.20
$1.41
-
$2.41
 
1,619,791

 
5.7 years
 
$2.02
 
 
 
 
7,788,957

 
5.9 years
 
$1.33
 
 
 
 
 
 
 
 
 
Aggregate intrinsic value
$
21,383

 
 
 
 

The fair value of shares issued under the 2012 Stock Incentive Plan was estimated using the following weighted-average assumptions for the fiscal years ended:
 
June 30,
 
2013
 
2012
Number of options
1,627,500
 
1,675,000
Weighted-average grant date fair value per share
$0.61
 
$0.66
Expected dividend
$0.00
 
$0.00
Forfeiture rate
 
Risk free interest rate
0.6
%
-
1.3%
 
1.0
%
-
1.3%
Expected life
5.1

-
6.0 years
 
5.3

-
6.0 years
Expected volatility (based on historical price)
60.3
%
-
63.5%
 
61.2
%
-
62.8%

Stock Compensation Expense
The Company recorded $0.8 million and $1.6 million of stock compensation expense for the fiscal years ended June 30, 2013, and 2012, respectively. Stock based compensation is included under general and administrative expense in the consolidated statements of operations. At June 30, 2013, there was a total of $0.8 million in unrecognized stock compensation expense related to stock options granted. This cost is expected to be recognized over a weighted-average period of 1.9 years. The amount of unrecognized compensation expense noted above does not necessarily represent the amount that will ultimately be realized by the Company in its consolidated statement of operations. During the fiscal year ending June 30, 2014, it is expected that an additional 1,367,500 stock options will vest.
The Company's compensation policy is designed to provide the Company's non-employee directors with a portion of their annual base Board service compensation in the form of equity. Between July 1, 2012, and June 30, 2013, the Company issued a total of 175,000 shares of its common stock to non-employee directors pursuant to this policy.
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Preferred Stock
12 Months Ended
Jun. 30, 2013
Equity [Abstract]
Preferred Stock
Note 8 - Preferred Stock
Series A Convertible Preferred Stock Financing Agreement
On May 10, 2013, the Company entered into a Series A Convertible Preferred Stock Purchase Agreement (the "Series A Purchase Agreement") with an affiliate of One Stone Energy Partners, L.P. ("One Stone"). Pursuant to the terms of the Series A Purchase Agreement, the Company issued 19,239,734 shares of Series A Convertible Preferred Stock, par value $0.01 per share (the "Series A Preferred Stock"), at a purchase price of $1.22149381 per share (the "Purchase Price"), for aggregate proceeds of approximately $23.5 million. Subject to certain conditions, each share of Series A Preferred Stock and any related unpaid accumulated dividends will be convertible into one share of the Company's Common Stock, par value $0.01 per share (the "Common Stock"), at an initial conversion price of $1.22149381 per share (the "Conversion Price").
The Series A Purchase Agreement also includes the following key terms:
Dividends. Holders of Series A Preferred Stock will be entitled to a dividend equivalent to 7.0% per annum on the face value, which will be the Purchase Price plus any accumulated unpaid dividends, payable quarterly in arrears. Dividends will generally be payable in cash or in kind (in the form of additional shares of Series A Preferred Stock), at the Company's option.
Conversion. Each share of Series A Preferred Stock will be convertible at any time, at One Stone's option, into one share of Common Stock, subject to the Conversion Cap prior to the approval of the Proposal by the Common Stock shareholders. The Series A Preferred Stock is entitled to customary anti-dilution protections.
Voting. The Series A Preferred Stock will be entitled to vote on an as-converted basis with the Common Stock, subject to the Voting Cap prior to the approval of the Proposal by the Common Stock shareholders (which approval was received on August 14, 2013).
Forced Conversion. At any time after the third anniversary of the Closing Date, the Company will have the right to cause One Stone to convert all, but not less than all, of the shares of Series A Preferred Stock into shares of Common Stock, if, among other conditions: (i) the per share price of Common Stock equals or exceeds 200% of the Conversion Price for a period of 20 out of 30 consecutive trading days, (ii) the average daily trading volume of shares of Common Stock exceeds an amount equal to the number of shares of Common Stock issuable upon the conversion of all outstanding shares of Series A Preferred Stock divided by 45, and (iii) the resale of shares of Common Stock is covered by an effective shelf registration statement, or such shares as can be sold under Rule 144 under the US Securities Act of 1933, as amended (the "Securities Act").
Redemption. At any time after the third anniversary of the Closing Date, and upon 30 days prior written notice, the Company may elect to redeem all, but not less than all, shares of Series A Preferred Stock for an amount equal to the greater of (i) the closing sale price of the Common Stock on the date the Company delivers such notice multiplied by the number of shares of Common Stock issuable upon conversion of the outstanding Series A Preferred Stock, and (ii) a cash payment that, when considering all cash dividends already paid, allows One Stone to achieve a 20% annualized internal rate of return on the then outstanding Series A Preferred Stock. One Stone will have the right to convert the Series A Preferred Stock into shares of Common Stock at any time prior to the close of business on the redemption date.
Change in Control. In the event of a Change in Control (as defined) of the Company, holders of Series A Preferred Stock will have the option to (i) convert Series A Preferred Stock into Common Stock immediately prior to the Change in Control, (ii) in certain circumstances, receive stock or securities in the acquirer of the Company having substantially identical terms as those of the Series A Preferred Stock, or (iii) receive a cash payment that, when considering all cash dividends already paid, allows One Stone to achieve a 20% annualized internal rate of return on the then outstanding Series A Preferred Stock.
The Company has determined that a Change in Control (as defined) is not solely within the Company's control and the Series A Preferred Stock is therefore presented in the consolidated balance sheets under temporary equity, outside of permanent equity.
Liquidation. Upon a liquidation event, holders of Series A Preferred Stock will be entitled to a non-participating liquidation preference per share of Series A Preferred Stock equal to (i) 115% of the Purchase Price until the second anniversary of the issuance of Series A Preferred Stock, (ii) 110% of the Purchase Price after the second anniversary of issuance until the third anniversary of issuance, (iii) 105% of the Purchase Price after the third anniversary of issuance until the fourth anniversary of issuance, and (iv) thereafter, at the Purchase Price.
Ranking. Series A Preferred Stock will rank senior to Common Stock with respect to dividend rights and rights on liquidation, winding up, and dissolution.
Board Representation. For so long as One Stone owns at least 15% or 10% of the fully diluted shares of Common Stock (assuming full conversion of the Series A Preferred Stock), One Stone will have the right to appoint two members or one member, respectively, to the Company's Board of Directors (the "Board"). These directors will not be subject to director elections by the holders of Common Stock at the Company's annual meetings of shareholders.
Minority Veto Rights. For so long as One Stone owns at least 10% of the fully diluted Common Stock (assuming full conversion of the Series A Preferred Stock), One Stone will hold veto rights with respect to (i) capital expenditures greater than $15.0 million that are not provided for in the then-current annual budget; (ii) certain related-party transactions; (iii) changes to the Company's principal line of business; and (iv) an increase in the size of the Board to a number greater than 12.
Standstill. For a period of two years following the date of the Series A Purchase Agreement, One Stone is prohibited from (i) acquiring direct or beneficial control of any additional equity securities of the Company or any rights thereto; (ii) participating in or forming any voting group or voting trust with respect to any voting securities of the Company; and (iii) seeking to influence, modify, or control management, the Board, or any business, policies, or actions of the Company. Until such time as One Stone no longer holds any Series A Preferred Stock, One Stone is prohibited from engaging, directly or indirectly, in any short selling of the Common Stock.
Registration Rights. One Stone will be entitled to resale registration rights with respect to the shares of Common Stock issuable upon conversion of the Series A Preferred Stock, pursuant to a separate Registration Rights Agreement executed on the Closing Date.
The Company has analyzed the embedded features of the issuance of the the Series A Preferred Stock and has determined that none of the embedded features meet the requirements under US GAAP to be bifurcated from the the Series A Preferred Stock contract and accounted for separately as a derivative. The Company also recorded the transaction by recognizing the fair value of the Series A Preferred Stock at the time of issuance in the amount of $23.5 million, net of offering costs of $0.5 million. The Company will accrete the Series A Preferred Stock to the liquidation or redemption value when it becomes probable that an event or events underlying the liquidation or redemption are probable.
For the fiscal year ended June 30, 2013, the Company accrued dividends in the amount of $0.2 million and recorded accretion in the amount of $0.5 million to reflect the initial estimated fair value at which the preferred stock was recorded.
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Stockholders' Equity
12 Months Ended
Jun. 30, 2013
Equity [Abstract]
Stockholders' Equity
Note 9 - Stockholders' Equity
Treasury Stock
On September 24, 2012, the Company announced that its Board of Directors had approved a stock repurchase program authorizing the Company to repurchase up to a total value of $2.0 million in shares of its common stock. The size and timing of such purchases will be based on market and business conditions as well as other factors. The Company is not obligated to purchase any shares of its common stock. The authorization will expire on August 21, 2014, and purchases under the program can be discontinued at any time. As of June 30, 2013, the Company repurchased 149,539 shares pursuant to this program.
On January 14, 2013, the Company entered into a Collateral Purchase Agreement (the "Collateral Agreement") with Sopak AG, a Swiss subsidiary of Glencore International plc ("Sopak"), pursuant to which the Company agreed to purchase: (i) 9,264,637 shares of the Company's common stock, (ii) a warrant granting Sopak the right to purchase from the Company an additional 4,347,826 shares of common stock, and (iii) a Registration Rights Agreement, dated as of June 29, 2009, and amended as of October 14, 2009, and June 23, 2010, between the Company, Young Energy Prize S.A., a Luxembourg corporation ("YEP"), and ECP Fund, SICAV-FIS, a Luxembourg corporation ("ECP"), which is a subsidiary of Yamalco Investments Limited, a Cyprus company ("Yamalco"), for a purchase price of $10.0 million. The Company accounted for the the Purchase Price of $10.0 million by allocating (i) $0.8 million to the fair value of the warrant and (ii) $9.2 million to the purchase of 9,264,637 shares of common stock, resulting in a value per share of $0.993 (refer below). The Collateral Agreement was subsequently amended on January 15, 2013, and completed on January 16, 2013. YEP, ECP, and Yamalco are entities affiliated with Nikolay V. Bogachev, a former director of the Company.
All repurchased common stock shares are currently being held in treasury at cost, including direct issuance cost. The following table summarizes the Company's treasury stock activity for the fiscal year ended June 30, 2013:
 
Number of shares
 
Average price per share
 
Amount
 
(In thousands, except share and per share amounts)
Repurchases through the stock repurchase program
149,539

 
$0.916
 
$
137

Repurchase through the Collateral Agreement (1)
9,264,637

 
$0.993
 
$
9,196

Total treasury stock
9,414,176

 
 
 
$
9,333

(1) Purchase price of $10.0 million reduced by the fair value of the warrant.
Retired Warrant
The Company formally retired the warrant purchased from Sopak pursuant to the Collateral Agreement. The fair value of the warrant was estimated using the Black-Scholes-Merton pricing model and determined to be approximately $0.8 million, which was included as a reduction of additional paid in capital in the consolidated balance sheet.
Assumptions used in estimating the fair value of the warrant included: (i) the common stock price on the repurchase date of $0.90; (ii) the exercise price of the warrant of $1.15; (iii) an expected dividend of $0; (iv) a risk free interest rate of 0.2%; (v) a remaining contractual term of 1.5 years; and (vi) an expected volatility based on historical prices of 60.8%.
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(Loss) Earnings Per Share
12 Months Ended
Jun. 30, 2013
Earnings Per Share [Abstract]
(Loss) Earnings Per Share
Note 10 - (Loss) Earnings Per Share
For the year ended June 30, 2012, outstanding stock options that had an exercise price below the average stock price would have resulted in 448,269 incremental dilutive shares. There is no dilutive effect on loss per share for the fiscal year ended June 30, 2013 as a result of net losses.
The following table summarizes the computation of basic and diluted (loss) earnings per share for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands, except share and per share amounts)
NET (LOSS) INCOME APPLICABLE TO MAGELLAN PETROLEUM CORPORATION
$
(19,767
)
 
$
26,498

Preferred stock dividend and accretion of preferred stock
(722
)
 

NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(20,489
)
 
$
26,498

 
 
 
 
 
 
 
 
Basic weighted-average shares outstanding
49,642,083

 
53,592,958

Add: dilutive effects of stock options and unvested stock grants

 
448,269

Diluted weighted-average common shares outstanding
49,642,083

 
54,041,227

 
 
 
 
Basic net loss (earnings) per common share
$(0.41)
 
$0.49
Diluted net loss (earnings) per common share
$(0.41)
 
$0.49
The following table summarizes potentially dilutive securities excluded from the calculation of diluted shares outstanding for the fiscal years ended:
 
June 30,
 
2013
 
2012
Series A convertible preferred stock
19,239,734

 

Stock options

 
100,000

Non-vested restricted stock
75,000

 

Total potentially dilutive securities
19,314,734

 
100,000

There were no other potentially dilutive items for the years ended June 30, 2013, and 2012.
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Segment Information
12 Months Ended
Jun. 30, 2013
Segment Reporting [Abstract]
Segment Information
Note 11 - Segment Information
The Company conducts its operations through three wholly owned subsidiaries: NP, which operates in the US; MPA, which is primarily active in Australia, and MPUK, which includes our operations in the UK, as well as Corporate, which is treated as a cost center. See Note 1 - Basis of Presentation, for additional information regarding the Company's realignment of its reporting segments.
The following table presents segment information for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Revenues:
 
 
 
NP
$
6,131

 
$
6,173

MPA
939

 
7,533

Corporate
329

 
646

Inter-segment eliminations
(329
)
 
(640
)
Consolidated revenues
$
7,070

 
$
13,712

 
 
 
 
Net (loss) income attributable to Magellan Petroleum Corporation:
 
 
 
NP
$
(326
)
 
$
2,154

MPA
(6,833
)
 
29,260

MPUK
(4,726
)
 
(5,068
)
Corporate (1)
27,523

 
(5,416
)
Inter-segment eliminations
(35,405
)
 
5,568

Consolidated net (loss) income attributable to Magellan Petroleum Corporation
$
(19,767
)
 
$
26,498

 
 
 
 
Assets:
 
 
 
NP
$
26,093

 
$
10,833

MPA
32,735

 
62,535

MPUK
2,021

 
5,213

Corporate
96,229

 
59,099

Inter-segment eliminations
(74,806
)
 
(45,106
)
Consolidated assets
$
82,272

 
$
92,574

 
 
 
 
Expenditures for additions to long lived assets:
 
 
 
NP
$
2,124

 
$
4,857

MPA
192

 
3,440

MPUK
350

 
1,135

Corporate
259

 
145

Consolidated expenditures for long lived assets
$
2,925

 
$
9,577

(1) During fiscal year June 30, 2013, approximately $35.9 million was included in Corporate net income represented by cash dividends received from MPA, and a deemed distribution related to the transfer of MPUK from MPA to MPC. These intercompany transactions have been eliminated in arriving at the consolidated results.
The following table summarizes other significant items for the fiscal years ended:
 
June 30,
 
2013
 
2012
 
(In thousands)
Depletion, depreciation, amortization, and accretion:
 
 
 
NP
$
988

 
$
819

MPA
413

 
695

Corporate
133

 
230

Consolidated depletion, depreciation, amortization, and accretion
$
1,534

 
$
1,744

 
 
 
 
Lease operating:
 
 
 
NP
$
4,851

 
$
5,232

MPA
2,186

 
7,665

Consolidated lease operating
$
7,037

 
$
12,897

 
 
 
 
Exploration:
 
 
 
NP
$
398

 
$
1,495

MPA
4,169

 
2,448

MPUK
3,700

 
2,348

Consolidated exploration
$
8,267

 
$
6,291

 
 
 
 
Income tax benefit (expense):
 
 
 
MPA
$
1,266

 
$
5,951

Consolidated income tax benefit (expense)
$
1,266

 
$
5,951

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Commitments
12 Months Ended
Jun. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Commitments
Note 12 - Commitments
Operating leases. The following table summarizes the Company's future minimum rental commitments under non-cancelable operating leases, net of guaranteed sublease income, as of June 30, 2013:
 
Total
 
(In thousands)
Amounts payable in fiscal year:
 
2014
$
162

2015
262

2016
268

2017
273

2018 and thereafter
90

Total
$
1,055


Rental expenses for each of the years ended June 30, 2013, and 2012, were $0.6 million and, $0.6 million, respectively.
Purchase obligations. Although the Company is committed to certain exploration and capital expenditures related to MPA, some of these expenses may be farmed out to third parties. Amounts payable under these firm commitments for fiscal year 2014 were $5.7 million as of June 30, 2013.
Contingent production payments. In September 2011, the Company entered into a Purchase and Sale Agreement (the "Nautilus PSA") among the Company and the non-controlling interest owners of NP for the Company's acquisition of the sellers' interests in NP (the "Nautilus Transaction"). The Nautilus PSA provides for potential future contingent production payments, payable by the Company in cash to the sellers, of up to a total of $5.0 million if certain increased average daily production milestones for the underlying properties are achieved. J. Thomas Wilson, a director and chief executive officer of the Company, has an approximate 52% interest in such contingent payments. See Note 5 above for information regarding the estimated discounted fair value of the future contingent consideration payable related to the Nautilus Transaction.
FINRA review. On August 28, 2012, Stratex Oil & Gas Holdings, Inc. ("Stratex"), announced an unsolicited proposal for the acquisition of the Company's common stock (the "Stratex Announcement"). On September 10, 2012, the Company announced that its Board of Directors, after carefully considering the unsolicited proposal, had determined not to pursue the Stratex proposal. On September 12, 2012, the Company received a subpoena from the SEC for the production of documents in connection with these announcements. On May 31, 2013, the Company received a letter dated May 30, 2013 from the Staff of the SEC indicating that the investigation relating to the announcements regarding an unsolicited proposal on August 28, 2012 by Stratex Oil & Gas Holdings, Inc. for the acquisition of the Company's common stock, had been completed as to the Company, against whom the Staff does not intend to recommend any enforcement action by the SEC. The Company believes that this matter is now concluded as the Company also received a letter from the Financial Industry Regulatory Authority ("FINRA") on April 30, 2013 indicating that FINRA had completed its related review regarding this matter, which letter also indicated that FINRA had referred its review to the SEC for whatever action, if any, the SEC deemed appropriate.
Sopak Collateral Agreement. The Company has estimated that there is the potential for a statutory liability of approximately $1.0 million of required US Federal tax withholdings and any applicable penalties and interest related to the Collateral Agreement as described in Note 9. As a result, as of June 30, 2013, we have recorded a total liability of $1.0 million under accrued and other liabilities in the consolidated balance sheet included in this report. The Company is in the process of addressing its US Federal tax withholdings requirements. The Company has a legally enforceable right to collect from Sopak any amounts owed to the IRS as a result of the Collateral Agreement. As a result, we have recorded a corresponding receivable under prepaid and other assets in the consolidated balance sheet of $1.0 million as of June 30, 2013.
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Related Party Transactions
12 Months Ended
Jun. 30, 2013
Related Party Transactions [Abstract]
Related Party Transactions
Note 13 - Related Party Transactions
US Federal tax withholding. During the third quarter of fiscal year 2012, the Company identified a potential liability of approximately $2.0 million related to the Company's failure to make the required US Federal tax withholding in the course of its initial acquisition 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 former Director of Magellan and a foreign national. Due to the status of YEP I as foreign entity and the members of White Bear as foreign nationals, Magellan was required to make US 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 US Federal tax withholdings. Upon the filing of US 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 US Federal tax withholdings as well as related penalties and interest except for Magellan's interest on late payment of the US Federal tax withholdings.
With regards to White Bear, Mr. Bogachev filed his US income tax return and paid taxes due on the Poplar Acquisition, and Magellan has no further related potential liability. With regards to YEP I, which is now a defunct entity, Magellan concluded that it was unlikely that one of YEP I's successor entities would file a corresponding US income tax return. As a result, the Company initiated a disclosure process with the IRS. As a result of this disclosure process the Company's total liability with respect to this matter was determined to be approximately $0.1 million, which was paid as of June 30, 2013.
As of June 30, 2012, we recorded a total liability of $1.0 million under accrued and other liabilities in the consolidated balance sheets related to this matter. That amount is comprised of the $0.3 million payment to Mr. Bogachev, $0.6 million in withholdings, penalties, and interest related to YEP I, and $0.1 million related to Magellan's interest on late payment of the US Federal tax withholdings. The effect of the disclosure process with the IRS on the consolidated statements of operations for the year ended June 30, 2012, resulted in an expense of $0.9 million recorded under general and administrative expense and an interest expense of $0.1 million. The effect of this transaction on the consolidated statements of operations for the year ended June 30, 2013, resulted in other income of $0.4 million representing the difference between the original estimate and the estimated final liability of $0.1 million related to the YEP I withholding obligation.
Office lease. The Company leased its prior Denver office space from an entity owned, in part, by J. Thomas Wilson, President and CEO of the Company and a member of the Company's Board of Directors. The total lease expense paid under this arrangement was $11 thousand and $72 thousand for the fiscal years ended June 30, 2013, and 2012, respectively. Following the relocation of the Company's headquarters to Denver, Colorado, a lease agreement for new office space was entered into with an unrelated party in August 2012. Separately, Mr. Wilson provided consulting services to the Company related to its Australian operations while a member of the Board of Directors but prior to becoming President and CEO of the Company in September 2011. As a result, consulting fees of $0 and $59 thousand for fiscal years ended June 30, 2013, and 2012, respectively, were paid to Mr. Wilson.
PFC Energy. J. Robinson West, the Chairman of the Board of Directors of the Company, is also Chairman, Founder, and CEO of PFC Energy ("PFC"). PFC has served as a consultant for the Company on various Australian projects. As of June 30, 2013 and 2012, there were no consulting arrangements between the Company and PFC in place or planned. The total consulting fees paid to PFC during the fiscal year ended June 30, 2012, was $64 thousand for work performed primarily in fiscal year 2011.
See Note 2 for information related to transactions the Company entered into with NT and ER, effective September 1, 2011.
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Employee Severance Costs
12 Months Ended
Jun. 30, 2013
Restructuring and Related Activities [Abstract]
Employee Severance Costs
Note 14 - Employee Severance Costs
The Company is required to record charges for one-time employee severance benefits and other associated costs as incurred. In July 2012, the Company incurred severance costs payable in connection with the termination of the employment of certain Corporate employees pursuant to the terms of their employment agreements. For the fiscal year ended June 30, 2013, the Company expensed total employee-related severance costs of $0.8 million, all of which were charged to general and administrative expense in the consolidated statements of operations. The Company does not expect any additional benefits or other associated costs related to these terminations. The liability related to these severance costs is included in the 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 is as follows for the fiscal year ended:
 
June 30,
2013
 
(In thousands)
Fiscal year beginning balance
$

Charges to general and administrative expense
837

Cash payments
(419
)
Fiscal year closing balance
$
418

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Subsequent Events
12 Months Ended
Jun. 30, 2013
Subsequent Events [Abstract]
Subsequent Events
Note 15 - Subsequent Events
Dingo gas supply and purchase agreement
On September 12, 2013, Magellan Petroleum Corporation (NT) Pty Ltd, a wholly owned subsidiary of MPA entered into a gas supply and purchase agreement (the "Dingo GSPA") with PWC for the long term sale of gas from the Company's Dingo gas field. Pursuant to the Dingo GSPA, the Company has contracted to supply up to 31.0 petajoules, equivalent to 30.1 Bcf, of gas to PWC on a 100% take-or-pay basis over a supply period of up to 20 years.
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Supplemental Oil and Gas Information
12 Months Ended
Jun. 30, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplementary Oil and Gas Information
Note 16 - Supplemental Oil and Gas Information (Unaudited)
Supplemental Oil and Gas Reserve Information
The Company relies upon a combination of internal technical staff and third party consulting arrangements for reserve estimation and review. The reserve information presented below is based on estimates of net proved reserves as of June 30, 2013, and 2012, and was prepared in accordance with guidelines established by the SEC.
In the US, reserve estimates were prepared by the Company's Operations Manager, Blaine Spies, for the fiscal years ended June 30, 2013, and 2012, and were audited by the Company's independent petroleum engineering firm, Allen & Crouch Petroleum Engineers ("A&C"), for the same reporting periods. A copy of the summary reserve audit report of A&C is provided as Exhibit 99.1 to this Annual Report on Form 10-K. A&C does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis.
In Australia, reserve estimates were prepared by the Ryder Scott Company ("RS"), an independent petroleum engineering firm, for the fiscal years ended June 30, 2013, and 2012. Reserve estimates were prepared in accordance with the Company's internal control procedures, which include the verification of input data used by RS, and management review and approval. A copy of the summary reserve report of RS is provided as Exhibit 99.2 to this Annual Report on Form 10-K. RS does not own an interest in any of Magellan's oil and gas properties and is not employed by Magellan on a contingent basis.
Proved reserves are the estimated quantities of oil, gas, and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. All of the Company's estimated proved reserves are located in the US and Australia.

Analysis of Changes in Proved Reserves
The following table sets forth information regarding the Company's estimated proved oil and gas reserve quantities. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
 
United States
Australia (1)
 
Total
 
Oil
(Mbbls)
 
Gas
(Bcf)
 
Oil
(Mbbls)
 
Gas
(Bcf)
Proved Reserves:
 
 
 
 
 
 
 
Fiscal year beginning balance
9,190.0

 
0.4

 
9,190.0

 
0.4

Extensions and discoveries
186.4

 

 
186.4

 

Revision of previous estimates
(1,643.8
)
 
6.0

 
(1,643.8
)
 
6.0

Purchase of minerals in place
1,246.8

 
5.5

 
1,246.8

 
5.5

Production
(74.2
)
 
(0.4
)
 
(74.2
)
 
(0.4
)
Fiscal year ended June 30, 2012
8,905.2

 
11.5

 
8,905.2

 
11.5

Revision of previous estimates
(1,215.7
)
 
0.2

 
(1,215.7
)
 
0.2

Production
(320.9
)
 
(0.3
)
 
(320.9
)
 
(0.3
)
Fiscal year ended June 30, 2013
7,368.6

 
11.4

 
7,368.6

 
11.4

 
 
 
 
 
 
 
 
Proved Developed Reserves:
 
 
 
 
 
 
 
Fiscal year ended June 30, 2012
1,646.7

 
11.5

 
1,646.7

 
11.5

Fiscal year ended June 30, 2013
1,581.5

 
11.4

 
1,581.5

 
11.4

 
 
 
 
 
 
 
 
Proved Undeveloped Reserves:
 
 
 
 
 
 
 
Fiscal year ended June 30, 2012
7,258.4

 

 
7,258.4

 

Fiscal year ended June 30, 2013
5,787.2

 

 
5,787.2

 

(1) The amount of proved reserves applicable to Australia gas reflects the amount of gas committed to specific long term supply contracts.
Extensions and discoveries. Extensions and discoveries are additions to reserve amounts either by drilling a well to extend the limits of a known reservoir or by drilling a well in a reservoir that was not included in previous reserve estimates, respectively. During the year ended June 30, 2012, in the US, there was one discovery well, EPU 117, drilled in the Amsden formation at Poplar, which added 186 Mbbls to our reserves total.
Revision of previous estimates. Revisions of estimates represent upward (downward) changes in previous estimates attributable to new information gained primarily from development activity, production history, and changes to the economic conditions present at the time of each estimate. During the year ended June 30, 2013, in the US, there was a 1,216 Mbbls downward revision of estimates related to the removal from the reserves projections of four PUD wells to be drilled during calendar year 2015. These wells were removed because the Company determined it would be beneficial to use only one as opposed to two drilling rigs for its PUD drilling program, and, as a result, it would not be feasible to drill these four wells within the projected time frame. During the year ended June 30, 2013, in Australia, there were immaterial revisions of estimates related to minor variances in projections relative to the prior year. During the year ended June 30, 2012, in the US, there was a 1,644 Mbbls downward revision of estimates as a result of modifications to projected production profiles from new wells. During the same period in Australia, there was a 6.0 Bcf upward revision of gas estimates related to the signing of a new gas sales contract with Santos in May 2012.
Purchase of minerals in place. During the year ended June 30, 2012, in the US, there were 1,247 Mbbls of purchases of minerals in place related to the Company's consolidation of its ownership in NP and Poplar in September 2011. During the same period in Australia, there were 5.5 Bcf of purchases of minerals in place related to the consolidation of Magellan's ownership in Palm Valley as part of the Santos SA in the Amadeus Basin completed in May 2012. These minerals in place have been recorded as proved reserves because they have been contracted for sale under the Palm Valley GSPA.
Sales of minerals in place. There were no adjustments to reserves quantities relating to sales of minerals in place for the years ended June 30, 2013, and 2012.

Standardized Measure of Oil and Gas
The Company computes a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.
The "standardized measure" is the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service, depreciation, depletion, and amortization, and tax, and are discounted using an annual discount rate of 10% to reflect timing of future cash flows.
The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company's expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unexpected delays in development, changes in prices, or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Prices. All prices used in calculation of our reserves are based upon a twelve month unweighted arithmetic average of the first day of the month price for the twelve months of the fiscal year, unless prices were defined by contractual arrangements. Prices are adjusted for local differentials and gravity and, as required by the SEC, held constant for the life of the projects (i.e., no escalation). The resulting prices used for proved reserves for the fiscal year ended June 30, 2013 are:
 
United States
 
Australia
Oil (per Bbl)
$82.90
 
NA
Gas (per Mcf)
NA
 
$4.92

Costs. Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Income taxes. Future income tax expenses are calculated by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
Discount. The present value of future net cash flows from the Company's proved reserves is calculated using a 10% annual discount rate. This rate is not necessarily the same as that used to calculate the current market value of our estimated oil and natural gas reserves.
The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:
 
United States
 
Australia
 
Total
 
(In thousands)
Fiscal year ended June 30, 2013
 
 
 
 
 
Future cash inflows
$
610,853

 
$
55,947

 
$
666,800

Future production costs
(244,703
)
 
(38,576
)
 
(283,279
)
Future development costs
(28,922
)
 
(4,095
)
 
(33,017
)
Future income tax expense
(112,193
)
 

 
(112,193
)
Future net cash flows
225,035

 
13,276

 
238,311

10% annual discount
(127,644
)
 
(2,991
)
 
(130,635
)
Standardized measures of discounted future net cash flows
$
97,391

 
$
10,285

 
$
107,676


 
United States
 
Australia
 
Total
 
(In thousands)
Fiscal year ended June 30, 2012
 
 
 
 
 
Future cash inflows
$
756,405

 
$
53,296

 
$
809,701

Future production costs
(291,212
)
 
(34,729
)
 
(325,941
)
Future development costs
(34,416
)
 
(4,107
)
 
(38,523
)
Future income tax expense
(152,314
)
 
(3,667
)
 
(155,981
)
Future net cash flows
278,463

 
10,793

 
289,256

10% annual discount
(156,967
)
 
(2,214
)
 
(159,181
)
Standardized measures of discounted future net cash flows
$
121,496

 
$
8,579

 
$
130,075


A summary of changes in the standardized measure of discounted future net cash flows is as follows:
 
United States
 
Australia
 
Total
 
(In thousands)
Fiscal year beginning balance
$
110,016

 
$
264

 
$
110,280

Net change in prices and production costs
18,517

 

 
18,517

Extensions and discoveries
6,785

 

 
6,785

Acquisitions of reserves
26,584

 
4,872

 
31,456

Revisions of previous quantity estimates
(37,846
)
 
6,144

 
(31,702
)
Changes in estimated future development costs
(2,275
)
 
(555
)
 
(2,830
)
Sales and transfers of oil and gas produced
(941
)
 
(264
)
 
(1,205
)
Previously estimated development cost incurred during the period
5,841

 

 
5,841

Accretion of discount (1)

 

 

Net change in income taxes
(1,657
)
 
(1,576
)
 
(3,233
)
Net change in timing and other
(3,528
)
 
(306
)
 
(3,834
)
Fiscal year ended June 30, 2012
121,496

 
8,579

 
130,075

Net change in prices and production costs
(7,955
)
 
(624
)
 
(8,579
)
Revisions of previous quantity estimates
(26,503
)
 
192

 
(26,311
)
Changes in estimated future development costs
3,473

 
5

 
3,478

Sales and transfers of oil and gas produced
(20,178
)
 
556

 
(19,622
)
Previously estimated development cost incurred during the period
3,419

 
7

 
3,426

Accretion of discount
19,269

 
1,016

 
20,285

Net change in income taxes
22,258

 
1,577

 
23,835

Net change in timing and other (2)
(17,888
)
 
(1,023
)
 
(18,911
)
Fiscal year ended June 30, 2013
$
97,391

 
$
10,285

 
$
107,676

(1) For fiscal year 2012, the Company assumed no accretion in value of proved oil reserves in the US and Australia. Accretion, with respect to measuring the changes in the standardized measure of reserves values, represents the value benefit of being closer in time, relative to the prior fiscal year's standardized measure, to future cash flows in the reserve projections. During fiscal year 2012, in the US, the Company did not develop its US proved oil reserves in accordance with the reserve plans in place at the beginning of the year, but instead postponed such plans by one year. Therefore, the benefit of accretion of the prior fiscal year's reserves should not have factored into the value of the standardized measure for fiscal year 2012. During fiscal year 2012, in Australia, the reserves at the beginning of the year had been sold entirely during the fiscal year as the long term gas sales contract in place at Palm Valley expired by its term in January 2012. As such, accretion of prior year reserves was not relevant in this case.
(2) For fiscal year 2013, in the US, there was a $17,888 downward revision in reserves value due to changes in timing and other. This revision primarily relates to the change, relative to the prior year reserves projections, in the expected timing of drilling and completing PUD wells and the attendant cash flow expected from these wells. During fiscal year 2013, the Company focused its activities at Poplar on executing water shutoff treatments due to their potential attractive economics. As a result, PUDs previously estimated to be drilled during fiscal year 2013 were postponed, resulting in a change in the annual quantity and timing of PUD wells to be drilled in the current reserves projections.
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Oil and Gas Activities
12 Months Ended
Jun. 30, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Activities
Note 17 - Oil and Gas Activities (Unaudited)
Costs Incurred in Oil and Gas Producing Activities
Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:
 
United States
 
Australia
 
United Kingdom
 
Total
 
(In thousands)
Fiscal year ended June 30, 2013
 
 
 
 
 
 
 
Proved
$
3,399

 
$

 
$

 
$
3,399

Unproved
157

 
179

 
335

 
671

Exploration Costs
398

 
4,169

 
3,700

 
8,267

Development Costs
2,045

 

 

 
2,045

Total, including asset retirement obligation
$
5,999

 
$
4,348

 
$
4,035

 
$
14,382

 
 
 
 
 
 
 
 
Fiscal year ended June 30, 2012
 
 
 
 
 
 
 
Proved
$
1,606

 
$
5,634

 
$

 
$
7,240

Unproved
945

 
3,787

 

 
4,732

Exploration Costs
2,192

 
1

 
5

 
2,198

Development Costs
2,779

 

 

 
2,779

Total, including asset retirement obligation
$
7,522

 
$
9,422

 
$
5

 
$
16,949


Net Changes in Capitalized Costs
The net changes in capitalized costs that are currently not being depleted pending the determination of proved reserves can be summarized as follows:
 
United States
 
Australia
 
United Kingdom
 
Total
 
(In thousands)
Fiscal year ended June 30, 2013
 
 
 
 
 
 
 
Fiscal year beginning balance
$
1,823

 
$
4,388

 
$
4,624

 
$
10,835

Additions to capitalized costs
1,954

 

 
335

 
2,289

Reclassified to producing properties
(3,223
)
 

 

 
(3,223
)
Charged to expense
(57
)
 

 
(3,035
)
 
(3,092
)
Exchange adjustment

 
(412
)
 
(162
)
 
(574
)
Fiscal year closing balance
$
497

 
$
3,976

 
$
1,762

 
$
6,235

 
 
 
 
 
 
 
 
Fiscal year ended June 30, 2012
 
 
 
 
 
 
 
Fiscal year beginning balance
$
2,411

 
$
415

 
$
5,259

 
$
8,085

Additions to capitalized costs
4,631

 
3,973

 
1,369

 
9,973

Assets sold or held for sale
(150
)
 

 

 
(150
)
Reclassified to producing properties
(3,772
)
 

 

 
(3,772
)
Charged to expense
(1,297
)
 

 
(2,106
)
 
(3,403
)
Exchange adjustment

 

 
102

 
102

Fiscal year closing balance
$
1,823

 
$
4,388

 
$
4,624

 
$
10,835

During the third quarter of fiscal year 2013, the Company allowed a petroleum exploration and development license in the UK to expire at the end of its term. As a result, an impairment of $0.9 million was recorded in the consolidated statements of operations. Additionally, the Company recorded a write-down related to the Markwells Wood-1 exploration well in the UK operated by Northern Petroleum. As a result, an exploration expense of $2.2 million was recorded in the consolidated statements of operations. No further write-downs were recorded during the fiscal year ended June 30, 2013.
At June 30, 2013, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling.
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Quarterly Financial Data
12 Months Ended
Jun. 30, 2013
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data
Note 18 - Quarterly Financial Data (Unaudited)
The following table summarizes the unaudited quarterly financial data, including (loss) income before income taxes, net (loss) income, and net (loss) income per common share for the fiscal years ended:
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
June 30,
2013
 
(In thousands, except per share data)
Fiscal year ended June 30, 2013
 
 
 
 
 
 
 
 
 
Total operating revenues
$
1,660

 
$
1,748

 
$
1,937

 
$
1,725

 
$
7,070

Total operating expenses
$
7,542

 
$
9,485

 
$
7,303

 
$
5,227

 
$
29,557

Loss before income taxes
$
(5,646
)
 
$
(7,606
)
 
$
(4,653
)
 
$
(3,128
)
 
$
(21,033
)
Net loss
$
(5,310
)
 
$
(7,285
)
 
$
(4,332
)
 
$
(2,840
)
 
$
(19,767
)