UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

(MARK ONE)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2014
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from    to
Commission File Number 001-5507
MAGELLAN PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
06-0842255
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
1775 Sherman Street, Suite 1950, Denver, CO

80203
(Address of principal executive offices)
(Zip Code)
(720) 484-2400
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
o
Accelerated filer
o
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting company
þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No
The number of shares outstanding of the issuer's single class of common stock as of May 9, 2014 was 45,348,709.





TABLE OF CONTENTS
ITEM
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



Table of Contents

PART I - FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS (UNAUDITED)
MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands, except share amounts)
 
March 31,
2014
 
June 30,
2013
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
19,014

 
$
32,469

Securities available-for-sale
20,113

 
44

Accounts receivable — trade
2,613

 
794

Accounts receivable — working interest partners
89

 
58

Accounts receivable — sale of Amadeus Basin assets
4,624

 

Inventories
391

 
555

Prepaid and other assets
1,754

 
1,378

Total current assets
48,598

 
35,298

 
 
 
 
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
 
 
 
Proved oil and gas properties
28,957

 
35,377

Less accumulated depletion, depreciation, amortization, and accretion
(3,499
)
 
(5,814
)
Unproved oil and gas properties
899

 
5,312

Wells in progress
17,303

 
923

Land, buildings, and equipment (net of accumulated depreciation of $434 and $1,810 as of March 31, 2014, and June 30, 2013, respectively)
401

 
1,382

Net property and equipment
44,061

 
37,180

 
 
 
 
OTHER NON-CURRENT ASSETS:
 
 
 
Goodwill
1,174

 
2,174

Deferred income taxes

 
7,217

Other long term assets
200

 
403

Total other non-current assets
1,374

 
9,794

Total assets
$
94,033

 
$
82,272

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Short term line of credit
$

 
$
51

Current portion of note payable
138

 
390

Current portion of asset retirement obligations
388

 
476

Accounts payable
3,078

 
1,948

Accrued and other liabilities
4,623

 
2,757

Accrued dividends
431

 
202

Total current liabilities
8,658

 
5,824

 
 
 
 
LONG TERM LIABILITIES:
 
 
 
Asset retirement obligations
2,434

 
6,403

Contingent consideration payable
4,174

 
3,940

Other long term liabilities
118

 
163

Total long term liabilities
6,726

 
10,506

COMMITMENTS AND CONTINGENCIES (Note 15)


 


 
 
 
 
PREFERRED STOCK (Note 10):
 
 
 
Series A convertible preferred stock (par value $0.01 per share): Authorized 50,000,000 shares, issued 20,089,436 and 19,239,734 as of March 31, 2014, and June 30, 2013, respectively; liquidation preference of $28,220 and $27,227, respectively
24,540

 
23,502

Total preferred stock
24,540

 
23,502

 
 
 
 
EQUITY:
 
 
 
Common stock (par value $0.01 per share): Authorized 300,000,000 shares, issued, 54,773,823 and 54,057,159 as of March 31, 2014, and June 30, 2013, respectively
548

 
540

Treasury stock (at cost): 9,425,114 and 9,414,176 shares as of March 31, 2014, and June 30, 2013, respectively
(9,344
)
 
(9,333
)
Capital in excess of par value
92,445

 
90,786

Accumulated deficit
(35,773
)
 
(50,079
)
Accumulated other comprehensive income
6,233

 
10,526

Total equity attributable to Magellan Petroleum Corporation
54,109

 
42,440

Total liabilities, preferred stock and equity
$
94,033

 
$
82,272

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

1

Table of Contents

MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except share and per share amounts)
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
REVENUE FROM OIL PRODUCTION
$
1,907

 
$
1,706

 
$
5,674

 
$
4,608

 
 
 
 
 
 
 
 
OPERATING EXPENSES:
 
 
 
 
 
 
 
Lease operating
1,397

 
1,032

 
4,714

 
3,515

Depletion, depreciation, amortization, and accretion
337

 
230

 
956

 
645

Exploration
1,605

 
2,395

 
2,776

 
3,523

General and administrative
1,588

 
2,204

 
6,411

 
7,685

Impairment

 

 

 
890

Total operating expenses
4,927

 
5,861

 
14,857

 
16,258

 
 
 
 
 
 
 
 
Loss from operations
(3,020
)
 
(4,155
)
 
(9,183
)
 
(11,650
)
 
 
 
 
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Net interest expense
(80
)
 
(20
)
 
(103
)
 
(51
)
Other income (expense)
27

 
449

 
(78
)
 
337

Total other (expense) income
(53
)
 
429

 
(181
)
 
286

 
 
 
 
 
 
 
 
Loss from continuing operations
(3,073
)
 
(3,726
)
 
(9,364
)
 
(11,364
)
 
 
 
 
 
 
 
 
DISCONTINUED OPERATIONS:
 
 
 
 
 
 
 
Loss from discontinued operations, net of tax
(2,589
)
 
(606
)
 
(5,245
)
 
(5,564
)
Gain on disposal of discontinued operations, net of tax
30,182

 

 
30,182

 

Net income (loss) from discontinued operations
27,593

 
(606
)
 
24,937

 
(5,564
)
 
 
 
 
 
 
 
 
Net income (loss) attributable to Magellan Petroleum Corporation
24,520

 
(4,332
)
 
15,573

 
(16,928
)
Preferred stock dividends
(431
)
 

 
(1,267
)
 

Net income (loss) attributable to common stockholders
$
24,089

 
$
(4,332
)
 
$
14,306

 
$
(16,928
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per common share (Note 12):
 
 
 
 
 
 
 
Weighted average number of basic shares outstanding
45,348,709

 
46,084,149

 
45,348,753

 
51,302,369

Weighted average number of diluted shares outstanding
45,348,709

 
46,084,149

 
45,348,753

 
51,302,369

 
 
 
 
 
 
 
 
Basic earnings (loss) per common share:
 
 
 
 
 
 
 
Loss from continuing operations
$(0.07)
 
$(0.08)
 
$(0.21)
 
$(0.22)
Net income (loss) from discontinued operations
$0.61
 
$(0.01)
 
$0.55
 
$(0.11)
Net income (loss) attributable to common stockholders
$0.53
 
$(0.09)
 
$0.32
 
$(0.33)
 
 
 
 
 
 
 
 
Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
Loss from continuing operations
$(0.07)
 
$(0.08)
 
$(0.21)
 
$(0.22)
Net income (loss) from discontinued operations
$0.61
 
$(0.01)
 
$0.55
 
$(0.11)
Net income (loss) attributable to common stockholders
$0.53
 
$(0.09)
 
$0.32
 
$(0.33)
The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

2

Table of Contents

MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(In thousands)
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
Net income (loss) attributable to Magellan Petroleum Corporation
$
24,520

 
$
(4,332
)
 
$
15,573

 
$
(16,928
)
 
 
 
 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Foreign currency translation gain (loss) during the period
911

 
(190
)
 
834

 
773

Reclassification of foreign currency translation gain to earnings upon sale of subsidiary
(6,049
)
 

 
(6,049
)
 

Unrealized holding gain (loss) on securities available-for-sale
916

 
(8
)
 
922

 
(30
)
Other comprehensive (loss) income, net of tax
(4,222
)
 
(198
)
 
(4,293
)
 
743

 
 
 
 
 
 
 
 
Comprehensive income (loss) attributable to Magellan Petroleum Corporation
$
20,298

 
$
(4,530
)
 
$
11,280

 
$
(16,185
)
The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

3

Table of Contents

MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)
(In thousands)
 
Common
Stock
 
Treasury
Stock
 
Capital in Excess of Par Value
 
Accumulated Deficit
 
Accumulated Other Comprehensive Income
 
Total Stockholders' Equity
June 30, 2013
$
540

 
$
(9,333
)
 
$
90,786

 
$
(50,079
)
 
$
10,526

 
$
42,440

Net income

 

 

 
15,573

 

 
$
15,573

Other comprehensive loss, net of tax

 

 

 

 
(4,293
)
 
$
(4,293
)
Stock and stock compensation expense
8

 

 
1,659

 

 

 
$
1,667

Net shares repurchased for employee tax costs upon vesting of restricted stock

 
(11
)
 

 

 

 
$
(11
)
Preferred stock dividends

 

 

 
(1,267
)
 

 
$
(1,267
)
March 31, 2014
$
548

 
$
(9,344
)
 
$
92,445

 
$
(35,773
)
 
$
6,233

 
$
54,109

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

4

Table of Contents

MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
 
NINE MONTHS ENDED
 
March 31,
 
2014
 
2013
OPERATING ACTIVITIES:
 
 
 
Net income (loss) attributable to Magellan Petroleum Corporation
$
15,573

 
$
(16,928
)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
 
 
 
Depletion, depreciation, amortization, and accretion
956

 
645

Increase in fair value of contingent consideration payable
234

 
172

Gain on disposal of Amadeus Basin assets
(30,182
)
 

Exploration costs previously capitalized
733

 
2,233

Stock compensation expense
1,667

 
753

Impairment loss

 
890

Severance benefit costs

 
535

Net changes in operating assets and liabilities:
 
 
 
Accounts receivable
(64
)
 
(148
)
Inventories
165

 
(42
)
Prepayments and other current assets
(410
)
 
195

Accounts payable and accrued liabilities
697

 
(2,563
)
Net cash used in operating activities of continuing operations
(10,631
)
 
(14,258
)
 
 
 
 
INVESTING ACTIVITIES:
 
 
 
Additions to property and equipment
(16,934
)
 
(2,233
)
Proceeds from first cash installment for the sale of Amadeus Basin assets
13,859

 

Net cash used in investing activities of continuing operations
(3,075
)
 
(2,233
)
 
 
 
 
FINANCING ACTIVITIES:
 
 
 
Repurchase of common stock
(11
)
 
(9,333
)
Repurchase of warrant

 
(813
)
Short term debt issuances
1,000

 
2,000

Short term debt repayments
(1,303
)
 
(1,413
)
Long term debt repayments

 
(372
)
Net cash used in financing activities of continuing operations
(314
)
 
(9,931
)
 
 
 
 
CASH FLOWS FROM DISCONTINUED OPERATIONS:
 
 
 
Net cash provided by (used in) operating activities of discontinued operations
1,366

 
(922
)
Net cash used in investing activities of discontinued operations
(1,265
)
 
(83
)
Net cash provided by (used in) discontinued operations
101

 
(1,005
)
 
 
 
 
Effect of exchange rate changes on cash and cash equivalents
464

 
728

Net decrease in cash and cash equivalents
(13,455
)
 
(26,699
)
Cash and cash equivalents at beginning of period
32,469

 
41,215

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
19,014

 
$
14,516

Supplemental schedule of non-cash activities:
 
 
 
Revision to estimate of asset retirement obligations

 
(306
)
Amounts in accounts payable and accrued liabilities related to property and equipment
846

 
109

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

5

Table of Contents


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Basis of Presentation
Description of Operations
Magellan Petroleum Corporation (the "Company" or "Magellan") is an independent oil and gas exploration and production company focused on the development of a CO2-enhanced oil recovery ("CO2-EOR") program at Poplar Dome ("Poplar") in eastern Montana and the exploration of conventional and unconventional hydrocarbon resources in the Weald Basin, located in Sussex County England onshore United Kingdom ("UK"). Magellan also owns an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory, Australia, which the Company currently plans to farmout; and an 11% ownership stake in Central Petroleum Limited (ASX: CTP), a Brisbane based exploration and production company that operates one of the largest holdings of prospective onshore acreage in Australia. The Company conducts its operations through three wholly owned subsidiaries corresponding to the geographic areas in which the Company operates: Nautilus Poplar LLC ("NP") in the US, Magellan Petroleum (UK) Limited ("MPUK") in the UK, and Magellan Petroleum Australia Pty Ltd ("MPA") in Australia.

Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP, MPUK, and MPA, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information, and in accordance with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. Accordingly, these interim unaudited condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete annual period financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature. All intercompany transactions have been eliminated. Operating results for the nine months ended March 31, 2014, are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2014. This report should be read in conjunction with the consolidated financial statements and footnotes thereto included in the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 2013 (the "2013 Form 10-K"). 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 the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Foreign Currency Translation
The functional currency of our foreign subsidiaries is their local currency. Assets and liabilities of foreign subsidiaries are translated to US dollars at period-end exchange rates, and our unaudited condensed consolidated statements of operations and cash flows are translated at average exchange rates during the reporting periods. Resulting translation adjustments are recorded in accumulated other comprehensive income, a separate component of stockholders' equity. A component of accumulated other comprehensive income will be released into income when the Company executes a partial or complete sale of an investment in a foreign subsidiary or a group of assets of a foreign subsidiary considered a business and/or when the Company no longer holds a controlling financial interest in a foreign subsidiary or group of assets of a foreign subsidiary considered a business.
Transactions denominated in currencies other than the local currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in foreign currency transaction gains and losses that are reflected in results of operations as unrealized (based on period end translation) or realized (upon settlement of the transactions) and reported under general and administrative expenses in the consolidated statements of operations.


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Table of Contents

Securities available-for-sale
Securities available-for-sale are comprised of investments in publicly traded securities and are carried at quoted market prices. Unrealized gains and losses are excluded from earnings and recorded as a component of accumulated other comprehensive income in stockholders' equity, net of deferred income taxes. The Company recognizes gains or losses when securities are sold. On a quarterly basis, we perform an assessment to determine whether there have been any events or economic circumstances to indicate that a security with an unrealized loss has suffered other-than-temporary impairment. As a result of this review, no impairment was recorded during the nine months ended March 31, 2014, or 2013, respectively.

Stock Based Compensation
Stock option grants may contain time based, market based, or performance based vesting provisions. Time based options are expensed on a straight-line basis over the vesting period. Market based options are expensed based on a graded amortized method, the expense is recognized if the derived service period is satisfied, even if the market condition is not achieved. Performance based options ("PBOs") are recognized when the achievement of the performance conditions is considered probable. Accordingly, PBOs are expensed 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 fair value of the stock options is determined on the grant date and is affected by our stock price and other assumptions regarding a number of complex and subjective variables. These variables include our expected stock price volatility over the term of the awards, risk free interest rates, expected dividends, and the expected option exercise term. The Company estimates the fair value of PBOs and time based stock options using the Black-Scholes-Merton pricing model. The simplified method is used to estimate the expected term of stock options due to a lack of related historical data regarding exercise, cancellation, and forfeiture. For market based stock options, the fair value is estimated using Monte Carlo simulation techniques.

Exploration
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed to be noncommercial. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole costs. Exploration expenses include dry hole costs and geological and geophysical expenses.

Segment Information
As of June 30, 2013, the Company determined, based on the criteria of ASC Topic 280, that it operates in three segments, NP, MPUK, and MPA, as well as a head office, Magellan ("Corporate"), which is treated as a cost center.
The Company's chief operating decision maker is J. Thomas Wilson (President and CEO of the Company), who reviews the results and manages operations of the Company in the three reporting segments of NP, MPUK, MPA, and Corporate. The presentation of all historical segment information herein has been reclassified to conform to the current 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 13 - Segment Information, and Part II, Item 8 of our 2013 Form 10-K.

Recently Issued Accounting Standards
In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-02 which requires additional disclosures regarding the reporting of reclassifications out of accumulated other comprehensive income. ASU No. 2013-02 requires an entity to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. This guidance is effective for reporting periods beginning after December 15, 2012. The Company adopted this guidance effective July 1, 2013. The Company's adoption of this standard did not have a significant impact on its unaudited condensed consolidated financial statements.
In March 2013, the FASB issued ASU No. 2013-05, which permits an entity to release cumulative translation adjustments into net income when a reporting entity (parent) ceases to have a controlling financial interest in a subsidiary or group of assets that is a business within a foreign entity. Accordingly, the cumulative translation adjustment should be released into net income only if the sale or transfer results in the complete or substantially complete liquidation of a foreign subsidiary or foreign group of assets comprising a business. The Company's adoption of this standard did not have a significant impact on its unaudited condensed consolidated financial statements.

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Note 2 - Sale of Amadeus Basin Assets
On March 31, 2014 (the "Central Closing Date"), pursuant to the Share Sale and Purchase Deed dated February 17, 2014 (the "Sale Deed"), the Company sold its Amadeus Basin assets, the Palm Valley and Dingo gas fields ("Palm Valley" and "Dingo," respectively), to Central Petroleum Limited ("Central") through the sale of the Company's wholly owned subsidiary, Magellan Petroleum (N.T.) Pty. Ltd, to Central's wholly owned subsidiary Central Petroleum PV Pty. Ltd ("Central PV"). In exchange for the assets, on March 31, 2014, Central paid to Magellan (i) AUD $15.0 million, and (ii) 39.5 million newly issued shares of Central stock (ASX: CTP), equivalent to an ownership interest in Central of approximately 11%. Central also committed to the payment of AUD $5.0 million to Magellan on April 15, 2014. The Sale Deed provides for certain customary purchase price adjustments, including the payment by Central of capital expenditures incurred by Magellan during the period from October 1, 2013, and March 31, 2014, less AUD $485 thousand, which is estimated at approximately AUD $743 thousand. The Sale Deed also provides that the Company is entitled to receive 25% of the revenues generated at the Palm Valley gas field from gas sales when the volume-weighted gas price realized at Palm Valley exceeds AUD $5.00/Gigajoule ("GJ") and AUD $6.00/GJ for the first 10 years following the Central Closing Date and for the following 5 years, respectively, with such prices to be escalated in accordance with the Australian CPI. Between the third and fifth anniversaries of the Central Closing Date, inclusive, the Company may seek from Central a one-time payment (the "Bonus Discharge Amount") corresponding to the present value, assuming an annual discount rate of 10%, of any expected remaining bonus payments in exchange for foregoing future bonus payments. If the Company receives the Bonus Discharge Amount, bonus payments and the Bonus Discharge Amount together may not exceed AUD $7.0 million. The Company also retained its rights to receive any and all bonuses (the "Mereenie Bonus") payable by Santos Ltd ("Santos") and contingent upon production at the Mereenie oil and gas field achieving certain threshold levels. The Mereenie Bonus was established in 2011 pursuant to the terms of the asset swap agreement between the Company and Santos for the sale of the Company's interest in Mereenie to Santos and the Company's purchase of the interests of Santos in the Palm Valley and Dingo gas fields. For additional information, see Note 3 - Discontinued Operations.

Note 3 - Discontinued Operations
As discussed in detail in Note 2, on March 31, 2014, pursuant to the Sale Deed, the Company completed the sale of Palm Valley and Dingo to Central PV. The assets of Palm Valley and Dingo were previously reported under the MPA segment, accordingly, MPA's results of operations associated with this sale were reclassified to discontinued operations in the third quarter of fiscal year 2014. Prior period amounts related to discontinued operations in the unaudited condensed consolidated statement of operations and statement of clash flows have also been reclassified to conform to the current period presentation. Summarized results of the Company's discontinued operations are as follows:
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Revenue
$
356

 
$
231

 
$
814

 
$
738

Net income (loss) from discontinued operations
$
27,593

 
$
(606
)
 
$
24,937

 
$
(5,564
)

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The Company reasonably estimated potential purchase price adjustments pursuant to the Sale Deed relating to the reimbursement of Dingo development costs and post completion costs. As of March 31, 2014, the gain related to the Company's discontinued operations is summarized as follows:
 
March 31,
2014
 
June 30,
2013
 
(In thousands)
Assets and liabilities sold
 
 
 
Property and equipment, net
$
(10,100
)
 
$
(9,627
)
Deferred income taxes
(7,217
)
 
(7,217
)
Goodwill allocated to disposal group
(1,000
)
 
(1,000
)
Asset retirement obligations
4,457

 
4,575

Other assets and liabilities, net (1)
1,178

 

Total assets and liabilities of discontinued operations
(12,682
)
 
(13,269
)
 

 
 
Consideration
 
 
 
First cash installment - received at Central Closing Date
13,859

 
 
Second cash installment - received on April 15, 2014
4,624

 
 
Stock of Central
19,147

 
 
Total consideration
37,630

 
 
 
 
 
 
Reclassification of foreign currency translation gains to earnings upon sale of foreign subsidiary
6,049

 
 
Transaction costs
(815
)
 

Gain on disposal of discontinued operations, net of tax
$
30,182

 
 
(1) Includes preliminary purchase price adjustments that have not been finalized.
For additional information about the sale of the Amadeus Basin assets and the Sale Deed, see Note 2 - Sale of Amadeus Basin Assets.

Note 4 - Securities Available-for-Sale
The following table presents the amortized cost, gross unrealized gains, gross unrealized losses and fair market value of available-for-sale equity securities as follows:
 
March 31, 2014
 
Amortized
cost
 
Gross unrealized gains
 
Gross unrealized losses
 
Fair
value
 
(In thousands)
Equity securities
$
19,339

 
$
929

 
$
(155
)
 
$
20,113

 
 
 
 
 
 
 
 
 
June 30, 2013
 
Amortized
cost
 
Gross unrealized gains
 
Gross unrealized losses
 
Fair
value
 
(In thousands)
Equity securities
$
192

 
$

 
$
(148
)
 
$
44



9

Table of Contents

Note 5 - Debt
The outstanding principal of a $1.7 million note payable by NP, re-issued in January 2011 (the "Note Payable"), will be fully amortized in June 2014. As of March 31, 2014, the minimum future principal maturities of the Note Payable, totaling $138 thousand, were considered a current liability.
The variable interest rate of the Note Payable 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 March 31, 2014, resulting in an interest rate of 6.25% per annum as of March 31, 2014. Under the Note Payable, NP is subject to certain customary financial and restrictive covenants. As of March 31, 2014, NP was in compliance with all financial and restrictive covenants.
The Note Payable is collateralized by a first mortgage and an assignment of production from Poplar and is guaranteed by Magellan up to $6.0 million, not to exceed the amount of the principal owed. The carrying amount of the Note Payable approximates its fair value, due to its variable interest rate, which resets based on market rates.

Note 6 - Asset Retirement Obligations
The estimated valuation of asset retirement obligations ("AROs") is based on the Company's historical experience and management's best estimate of plugging and abandonment costs by field. Assumptions and judgments made by management when assessing an ARO include: (i) the existence of a legal obligation; (ii) estimated probabilities, amounts, and timing of settlements; (iii) the credit-adjusted risk-free rate to be used; and (iv) inflation rates. Accretion expense is recorded under depletion, depreciation, amortization, and accretion in the unaudited condensed consolidated statements of operations. If the recorded value of ARO requires revision, the revision is recorded to both the ARO and the asset retirement capitalized cost. As a result of the sale of the Amadeus Basin assets on March 31, 2014, AROs were reduced by approximately $4.5 million.
The following table summarizes the ARO activity for the nine months ended March 31, 2014:
 
Total
 
(In thousands)
Fiscal year opening balance

$
6,879

Liabilities incurred
7

Liabilities sold
(4,457
)
Accretion expense
325

Effect of exchange rate changes
68

Balance at March 31, 2014
2,822

Less current asset retirement obligation
388

Long term asset retirement obligation
$
2,434


Note 7 - Fair Value Measurements
The Company follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:
Level 1: Quoted prices in active markets for identical assets.
Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3: Significant unobservable inputs.
The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Company's policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed above for all periods presented. During the nine months ended March 31, 2014, and 2013, there have been no transfers in or out of Level 1, Level 2, or Level 3.


10

Table of Contents

Assets and liabilities measured on a recurring basis
The Company's financial instruments, including cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities, are carried at cost, which approximates fair value due to the short term maturity of these instruments. The recorded values of the line of credit and Note Payable (see Note 5 - Debt) approximate fair value due to their variable interest rate structures.
The following table presents items required to be measured at fair value on a recurring basis by the level in which they are classified within the valuation hierarchy as follows:
 
March 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Securities available-for-sale
$
20,113

 
$

 
$

 
$
20,113

 


 


 


 


Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable (1)
$

 
$

 
$
4,174

 
$
4,174

 
 
 
 
 
 
 
 
 
June 30, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Securities available-for-sale
$
44

 
$

 
$

 
$
44

 


 


 


 


Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable (1)
$

 
$

 
$
3,940

 
$
3,940

(1) See Note 15 - Commitments and Contingencies, below for additional information about this item.
The contingent consideration payable is a standalone liability that is measured at fair value on a recurring basis for which there is no available quoted market price, principal market, or market participants. The inputs for this instrument are unobservable and therefore classified as Level 3 inputs. The calculation of this liability is a significant management estimate and uses drilling and production projections, 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. Payments of future production bonuses are sensitive to Poplar's 60 days rolling gross production average. The contingent consideration payable would increase with significant production increases and/or a reduction in the discount rate.
The following table presents information about significant unobservable inputs to the Company's Level 3 financial liability measured at fair value on a recurring basis as follows:
Description
 
Valuation technique
 
Significant unobservable inputs
 
March 31,
2014
 
June 30,
2013
Contingent consideration payable
 
Discounted cash flow model
 
Discount rate
 
8.0%
 
8.0%
 
 
 
 
First production payout
 
December 31, 2015
 
December 31, 2015
 
 
 
 
Second production payout
 
December 31, 2016
 
December 31, 2016
Adjustments to the fair value of the contingent consideration payable are recorded in the unaudited condensed consolidated statements of operations under net interest income. The following table presents a roll forward of the contingent consideration payable for the nine months ended March 31, 2014:
 
Total
 
(In thousands)
Fiscal year opening balance
$
3,940

Accretion of contingent consideration payable
234

Balance at March 31, 2014
$
4,174


11

Table of Contents

Assets and liabilities measured on a nonrecurring basis
The Company also utilizes fair value to perform an annual impairment test on its oil and gas properties, or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Fair value is estimated using expected undiscounted future cash flows from oil and gas properties. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are also classified within Level 3. For the nine months ended March 31, 2014, no events or circumstances were identified that would indicate that an impairment of our oil and gas properties has occurred.

Note 8 - Income Taxes
The Company has estimated the applicable effective tax rate expected for the full fiscal year. The Company's effective tax rate used to estimate income taxes on a current year-to-date basis for the nine months ended March 31, 2014, and 2013, is 0% and 5.46%, respectively. Deferred tax assets ("DTAs") are recognized for the expected future tax consequences of temporary differences between the financial reporting and tax basis of assets and liabilities and for operating losses and foreign tax credit carry forwards. A valuation allowance reduces DTAs to the estimated realizable value, which is the amount of DTAs management believes is "more-likely-than-not" to be realized in future periods.
We review our DTAs and valuation allowance on a quarterly basis. As part of our review, we consider positive and negative evidence, including cumulative results in recent years. We anticipate that we will continue to record a valuation allowance against our DTAs in all jurisdictions of the Company, until such time as we are able to determine that it is "more-likely-than-not" that those DTAs will be realized. Following the sale of MPNT, the deferred tax asset related to the Petroleum Resource Rent Tax was realized as part of the sale transaction. Consistent with the position at June 30, 2013, the Company maintains a full valuation allowance recorded against all DTAs, until such time as we are able to determine it is "more-likely-than-not" those reserved DTAs will be realized. The Company therefore had no recorded DTAs as of March 31, 2014.

Note 9 - Stock Based Compensation
The 2012 Stock Incentive Plan
On January 16, 2013, the Company's shareholders approved the Magellan Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (the "2012 Stock Incentive Plan"). The 2012 Stock Incentive Plan replaced the Company's 1998 Stock Incentive Plan (the "1998 Stock Plan"). The 2012 Stock Incentive Plan provides for the granting of stock options, stock appreciation rights, restricted stock and/or restricted stock units, performance shares and/or performance units, incentive awards, cash awards, and other stock based awards to employees, including officers, directors, and consultants of the Company (or subsidiaries of the Company) who are selected to receive incentive compensation awards by the Compensation, Nominating and Governance Committee (the "CNG Committee") of the Board of Directors of the Company (the "Board"), which is the plan administrator for the 2012 Stock Incentive Plan. The stated maximum number of shares of the Company's common stock authorized for awards under the 2012 Stock Incentive Plan is 5,000,000 shares plus the remaining number of shares under the 1998 Stock Plan immediately before the effective date of the 2012 Stock Incentive Plan, which was 288,435 as of January 15, 2013. The maximum aggregate annual number of options or stock appreciation rights that may be granted to one participant is 1,000,000, and the maximum annual number of performance shares, performance units, restricted stock, or restricted stock units that may be granted to any one participant is 500,000. The maximum term of the 2012 Stock Incentive Plan is ten years.

Stock Option Grants
Under the 2012 Stock Incentive Plan, stock option grants may contain time based, performance based, or market based vesting provisions. During the nine months ended March 31, 2014, the Company granted a total of 3,000,000 stock options under the 2012 Stock Incentive Plan, of which 1,500,000 were granted as PBOs, and 1,500,000 were granted with market based vesting provisions. Performance metrics used to measure the potential vesting of the PBOs consist of: (i) completing the drilling of the CO2-EOR pilot program at Poplar (weighted 10%); (ii) board approval of a full field CO2-EOR development project at Poplar (weighted 40%); (iii) sale of substantially all of the Amadeus Basin assets (weighted 20%); (iv) approval of a farmout agreement or the ability to participate in drilling one well in the Weald Basin with internally developed funding, including proceeds from a sale of assets (weighted 20%); and (v) approval and execution of a farmout agreement for drilling one well in the Bonaparte Basin (weighted 10%). Potential vesting of the market based stock options are subject to the Company maintaining a $2.35 per share closing price for 10 consecutive trading days and median stock price of $2.35 over a period of 90 days. As of March 31, 2014, performance metrics (i), (iii) and (iv) were met.
As of March 31, 2014, 2,250,000 stock options with market based vesting provisions or PBOs had not vested, and 560,107 shares, including forfeited shares, which remain available for future issuance. Stock options outstanding have expiration dates ranging from November 18, 2015, to October 15, 2023.

12

Table of Contents

The following table summarizes the stock option activity for the nine months ended March 31, 2014:
 
Number of
Shares
 
WAEPS (1)
Fiscal year opening balance
7,788,957

 
$1.33
Granted
3,000,000

 
$1.03
Forfeited
(41,666
)
 
$1.05
Balance at March 31, 2014
10,747,291

 
$1.25
Weighted average remaining contractual term
6.4

years
(1) Weighted average exercise price per share.
The fair value of stock options granted under the 2012 Stock Incentive Plan or the 1998 Stock Plan was estimated using the following weighted-average assumptions for the nine months ended:
 
March 31,
 
2014
 
2013
 
PBOs (1)
 
Market Based (2)
 
PBOs
Number of options
1,500,000
 
 
1,500,000
 
 
1,007,500
 
Weighted average grant date fair value per share
$0.57
 
 
$0.69
 
 
$0.61
 
Expected dividend
0
 
 
0
 
 
0
 
Forfeiture rate
0
 
 
0
 
 
0
 
Risk free interest rate
1.5
%
-
1.7
%
 
 
 
2.8
%
 
0.6
%
-
0.8
%
Expected life (years)
0.4

-
1.6

 
 
 
2.6

 
5.1

-
6.0

Expected volatility (based on historical price)
61.7
%
-
61.9
%
 
 
 
66.6
%
 
60.3
%
-
63.5
%
(1) The term related to these PBOs were estimated using an average probabilistic weighted method.
(2) The Company assumed market based options will be voluntarily exercised at the midpoint of vesting, and the contractual term.
Stock Compensation Expense
The Company recorded $0.6 million and $1.7 million of related stock compensation expense for the three and nine months ended March 31, 2014, respectively, and $0.1 million and $0.8 million of related stock compensation expense for the three and nine months ended March 31, 2013. Stock compensation expense is included in general and administrative expense in the unaudited condensed consolidated statements of operations. As of March 31, 2014, the unrecorded expected future compensation expense related to stock option awards was $1.5 million.

Stock Awards
On July 1, 2013, 450,000 restricted shares of the Company's Common Stock (the "Common Stock") were awarded to executive officers pursuant to the 2012 Stock Incentive Plan. The restricted shares are subject to a three year vesting term. 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. On July 1, 2013, the Company issued a total of 266,664 shares of its Common Stock to non-employee directors pursuant to this policy and the 2012 Stock Incentive Plan.


13

Table of Contents

Note 10 - Preferred Stock
Series A Convertible Preferred Stock Financing
On May 10, 2013, the Company entered into a Series A Convertible Preferred Stock Purchase Agreement (the "Series A Purchase Agreement") with One Stone Holdings II LP ("One Stone"), an affiliate of One Stone Energy Partners, L.P. Pursuant to the terms of the Series A Purchase Agreement, on May 17, 2013 (the "Closing Date"), the Company issued to One Stone 19,239,734 shares of Series A Convertible Preferred Stock, par value $0.01 per share (the "Series A Preferred Stock"), at a purchase price of $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 are convertible into one share of the Company's Common Stock, par value $0.01 per share, at an initial face amount and conversion price of $1.22149381 per share (the "Conversion Price").
The Certificate of Designations, as amended (the "Certificate of Designations"), governing the Series A Preferred Stock also includes the following key terms:
Dividends. Holders of Series A Preferred Stock are entitled to a dividend equivalent to 7.0% per annum on the face value, which is the Purchase Price plus any accumulated unpaid dividends, payable quarterly in arrears. Dividends are generally payable in kind ("PIK") (in the form of additional shares of Series A Preferred Stock) or in cash, at the Company's option.
Conversion. Each share of Series A Preferred Stock is convertible at any time, at the holder's option, into one share of Common Stock, based on an initial face amount and conversion price of $1.22149381 per share. The Series A Preferred Stock is entitled to customary anti-dilution protections.
Voting. The Series A Preferred Stock is entitled to vote on an as-converted basis with the Common Stock.
Forced Conversion. At any time after the third anniversary of the Closing Date, the Company will have the right to cause the holders 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 average per share price of Common Stock equals or exceeds 200% of the Purchase 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 into which such shares are converted is covered by an effective shelf registration statement, or such shares of Common Stock 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 the holders of Series A Preferred Stock to achieve a 20% annualized internal rate of return on the then outstanding Series A Preferred Stock. The holders of Series A Preferred Stock 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 in the Certificate of Designations) 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 the holders of Series A Preferred Stock 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 in the Certificate of Designations) is not solely within the Company's control, and therefore the Series A Preferred Stock is presented in the unaudited condensed consolidated balance sheets under temporary equity, outside of permanent equity.
Liquidation. Upon a liquidation event, holders of Series A Preferred Stock are 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 Closing Date, (ii) 110% of the Purchase Price after the second anniversary of the Closing Date until the third anniversary of the Closing Date, (iii) 105% of the Purchase Price after the third anniversary of the Closing Date until the fourth anniversary of the Closing Date, and (iv) thereafter, at the Purchase Price, plus, in each case, any accrued and accumulated dividends on such share.
Ranking. Series A Preferred Stock ranks senior to Common Stock with respect to dividend rights and rights on liquidation, winding up, and dissolution.

14

Table of Contents

Board Representation. For so long as the holders of Series A Preferred Stock own at least 15% or 10% of the fully diluted shares of Common Stock (assuming full conversion of the Series A Preferred Stock), the holders of a majority of the then outstanding shares of Series A Preferred Stock have the right to appoint two members or one member, respectively, to the Company's Board. These directors are not 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 the holders of Series A Preferred Stock own at least 10% of the fully diluted Common Stock (assuming full conversion of the Series A Preferred Stock), the holders of a majority of the then outstanding shares of Series A Preferred Stock 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.
The Series A Purchase Agreement and a related separate Registration Rights Agreement also include the following key terms:
Standstill. For a period of two years following the date of the Series A Purchase Agreement, One Stone is generally prohibited from (i) acquiring direct or beneficial control of any additional equity securities of the Company or any rights thereto; (ii) making, or in any way participating in, directly or indirectly, any solicitation of proxies to vote in any election contest or initiate, propose or otherwise solicit stockholders of the Company for approval of any stockholder proposals; (iii) participating in or forming any voting group or voting trust with respect to any voting securities of the Company; and (iv) 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. Holders of Series A Preferred Stock are entitled to resale registration rights with respect to the shares of Common Stock issuable upon conversion of the Series A Preferred Stock.
The Company has analyzed the embedded features of the Series A Preferred Stock and has determined that none of the embedded features is required under US GAAP to be bifurcated from the Series A Preferred Stock and accounted for separately as a derivative. The Company recorded the transaction by recognizing the fair value of the Series A Preferred Stock at the time of issuance in the amount of $23.5 million. The Company will accrete the Series A Preferred Stock to the redemption value if events or circumstances indicate that redemption is probable.
For the nine months ended March 31, 2014, the Company recorded preferred stock dividends of $1.3 million related to the Series A Preferred Stock. The preferred stock dividend for the three months ended March 31, 2014, will be paid in cash, and accordingly an accrual of $431 thousand was recorded for unpaid cash dividends as of March 31, 2014.

The activity related to the Series A Preferred Stock for the nine months ended March 31, 2014, and the fiscal year ended June 30, 2013, is as follows:
 
NINE MONTHS ENDED
 
FISCAL YEAR ENDED
 
March 31, 2014
 
June 30, 2013
 
Number of shares
 
Amount
 
Number of shares
 
Amount
 
(In thousands, except share amounts)
Fiscal year opening balance
19,239,734

 
$
23,502

 

 
$

Issuance of Series A Preferred Stock

 

 
19,239,734

 
23,502

PIK dividend shares issued, for previously accrued dividend
164,607

 
202

 

 

Current year PIK dividends shares issued
685,095

 
836

 

 

Balance at March 31, 2014
20,089,436

 
$
24,540

 
19,239,734

 
$
23,502



15

Table of Contents

Note 11 - Stockholders' Equity
Treasury Stock
On September 24, 2012, the Company announced that its Board 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 is to 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. During November 2012, the Company repurchased 149,539 shares pursuant to this program. As of March 31, 2014, $1.9 million in shares of Common Stock remained authorized for repurchase under 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 Collateral Agreement was subsequently amended on January 15, 2013, and completed on January 16, 2013. The Company accounted for the Collateral Agreement by allocating the purchase price of $10.0 million to the fair value of the warrant, which was estimated at $0.8 million, and the remaining $9.2 million to the purchase of the 9,264,637 shares of Common Stock, resulting in a value per share of $0.993 for the shares of Common Stock purchased. YEP, ECP, and Yamalco are entities affiliated with Nikolay V. Bogachev, a former director of the Company.
All repurchased shares of Common Stock are currently being held in treasury at cost, including direct issuance cost. The following table summarizes the Company's treasury stock activity as follows:
 
NINE MONTHS ENDED
 
FISCAL YEAR ENDED
 
March 31, 2014
 
June 30, 2013
 
Number of shares
 
Amount
 
Number of shares
 
Amount
 
(In thousands, except share amounts)
Fiscal year opening balance
9,414,176

 
$
9,333

 

 
$

Repurchases through the stock repurchase program

 

 
149,539

 
137

Repurchase through the Collateral Agreement (1)

 

 
9,264,637

 
9,196

Net shares repurchased for employee tax costs upon vesting of restricted stock
10,938

 
11

 

 

Balance at March 31, 2014
9,425,114

 
$
9,344

 
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 described above. 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 unaudited condensed consolidated balance sheet.
Assumptions used in estimating the fair value of the warrant included: (i) the Common Stock market price on the repurchase date of $0.90 per share; (ii) the warrant exercise price of $1.15 per share; (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%.


16

Table of Contents

Note 12 - Earnings Per Common Share
The following table summarizes the computation of basic and diluted earnings per share:
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
 
(In thousands, except share and per share amounts)
Loss from continuing operations
$
(3,073
)
 
$
(3,726
)
 
$
(9,364
)
 
$
(11,364
)
Preferred stock dividend
(431
)
 

 
(1,267
)
 

Net loss
(3,504
)
 
(3,726
)
 
(10,631
)
 
(11,364
)
Net income (loss) from discontinued operations
27,593

 
(606
)
 
24,937

 
(5,564
)
Net income (loss) attributable to common stockholders
$
24,089

 
$
(4,332
)
 
$
14,306

 
$
(16,928
)
 
 
 
 
 
 
 
 
Basic weighted average shares outstanding
45,348,709

 
46,084,149

 
45,348,753

 
51,302,369

Add: dilutive effects of in-the-money stock options and non-vested restricted stock grants (1)

 

 

 

Diluted weighted average common shares outstanding
45,348,709

 
46,084,149

 
45,348,753

 
51,302,369

 
 
 
 
 
 
 
 
Basic earnings (loss) per common share:
 
 
 
 
 
 
 
Loss from continuing operations
$(0.07)
 
$(0.08)
 
$(0.21)
 
$(0.22)
Net income (loss) from discontinued operations
$0.61
 
$(0.01)
 
$0.55
 
$(0.11)
Net income (loss) attributable to common stockholders
$0.53
 
$(0.09)
 
$0.32
 
$(0.33)
 
 
 
 
 
 
 
 
Diluted earnings (loss) per common share:
 
 
 
 
 
 
 
Loss from continuing operations
$(0.07)
 
$(0.08)
 
$(0.21)
 
$(0.22)
Net income (loss) from discontinued operations
$0.61
 
$(0.01)
 
$0.55
 
$(0.11)
Net income (loss) attributable to common stockholders
$0.53
 
$(0.09)
 
$0.32
 
$(0.33)
(1) All diluted earnings per share calculations are dictated by the results from continuing operations, accordingly there were no dilutive effect on earnings per share in the periods presented.
There is no dilutive effect on earnings per share in periods with net losses. Stock options or shares of Common Stock issuable upon the conversion of the Series A Preferred Stock were not considered in the calculation of diluted weighted average common shares outstanding, as they would be antidilutive. Potentially dilutive securities excluded from the calculation of diluted shares outstanding in periods with net losses are as follows:
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
In-the-money stock options
5,143,666

 
75,000

 
907,500

 
82,500

Non-vested restricted stock
850,000

 

 
900,000

 

Total
5,993,666

 
75,000

 
1,807,500

 
82,500



17

Table of Contents

Note 13 - Segment Information
The Company conducts its operations through three wholly owned subsidiaries: NP, which operates in the US; MPUK, which includes our operations in the UK; and MPA, which is primarily active in Australia. Oversight for these subsidiaries is provided by Corporate which is treated as a cost center. Due to the sale of the Amadeus Basin assets held by MPA, results of operations related to MPA are included in results of operations from discontinued operations.
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Revenue from oil production:
 
 
 
 
 
 
 
NP
$
1,907

 
$
1,706

 
$
5,674

 
$
4,608

 
 
 
 
 
 
 
 
Net income (loss) from continuing operations:
 
 
 
 
 
 
 
NP
$
40

 
$
333

 
$
(536
)
 
$
(133
)
MPUK
(1,349
)
 
(2,417
)
 
(2,495
)
 
(4,424
)
Corporate
(2,011
)
 
(1,673
)
 
(6,700
)
 
(6,661
)
Inter-segment elimination
247

 
31

 
367

 
(146
)
Consolidated net loss from continuing operations
$
(3,073
)
 
$
(3,726
)
 
$
(9,364
)
 
$
(11,364
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
March 31,
2014
 
June 30,
2013
 
 
 
 
 
(In thousands)
Total assets:
 
 
 
 
 
 
 
NP
 
 
 
 
$
26,831

 
$
26,093

MPUK
 
 
 
 
174

 
2,021

MPA
 
 
 
 
39,821

 
33,418

Corporate
 
 
 
 
102,403

 
96,558

Inter-segment elimination (1)
 
 
 
 
(75,196
)
 
(75,818
)
Consolidated total assets


 


 
94,033

 
82,272

Assets of discontinued operations
 
 
 
 

 
(18,199
)
Total assets of continuing operations


 


 
$
94,033

 
$
64,073

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


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Note 14 - Oil and Gas Activities
The following table presents the capitalized costs under the successful efforts method for oil and gas properties as of:
 
March 31,
2014
 
June 30,
2013
 
(In thousands)
Proved oil and gas properties:
 
 
 
United States
$
28,957

 
$
27,606

Australia

 
7,771

Less accumulated depletion, depreciation, and amortization
(3,499
)
 
(5,814
)
Total net proved oil and gas properties
$
25,458

 
$
29,563

 
 
 
 
Unproved oil and gas properties:
 
 
 
United Kingdom
$
630

 
$
1,075

United States
269

 
261

Australia

 
3,976

Total unproved oil and gas properties
$
899

 
$
5,312

 
 
 
 
Wells in Progress:
 
 
 
United Kingdom
$
728

 
$
688

United States (1)
16,575

 
235

Total wells in progress
$
17,303

 
$
923

(1) The Company began implementing a CO2-enhanced oil recovery pilot project at NP in the first quarter of fiscal year 2014.
During the nine months ended March 31, 2014, the Company allowed petroleum exploration and development licenses in the UK to expire at the end of their term. As a result, $0.7 million of exploration expense was recorded in the unaudited condensed consolidated statement of operations.

Note 15 - Commitments and Contingencies
Refer to Note 12 - Commitments, of the Notes to the Consolidated Financial Statements in our 2013 Form 10-K for information on all commitments.
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 executive officer of the Company, has an approximately 52% interest in such contingent payments. See Note 7 - Fair Value Measurements, above for information regarding the estimated discounted fair value of the future contingent consideration payable related to the Nautilus Transaction.
The Company has estimated that there is the potential for a statutory liability of approximately $1.5 million of required US Federal tax withholdings, and related penalties and interest, related to the Collateral Agreement as described in Note 11 - Stockholders' Equity. As a result, we have recorded a total liability of $1.5 million and $1.0 million as of March 31, 2014, and June 30, 2013, respectively, under accrued and other liabilities in the unaudited condensed consolidated balance sheets included in this report. The Company has a legally enforceable right to collect from Sopak any amounts owed to the IRS as a result of the Collateral Agreement. As a result, we have recorded a corresponding receivable of $1.5 million and $1.0 million as of March 31, 2014, and June 30, 2013, respectively, under prepaid and other assets in the unaudited condensed consolidated balance sheets.

Note 16 - Related Party Transactions
During the third quarter of fiscal year 2012, the Company identified a potential liability of approximately $2.0 million related to the Company's non-payment of required US Federal tax withholdings in the course of its initial acquisition of a part of NP. In October 2009, Magellan acquired 83.5% of the membership interests in NP (the "Poplar Acquisition") from the two majority owners of NP, White Bear LLC ("White Bear"), and YEP I, SICAV-FES ("YEP I"). Both of these entities are affiliated with Nikolay V. Bogachev, a foreign national who was a director of Magellan at the time of the Poplar Acquisition but has since resigned. Because YEP I was a foreign entity and the members of White Bear were foreign nationals, Magellan was required to make US Federal tax withholdings

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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 the 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 be filing the corresponding US income tax return. As a result, the Company initiated a disclosure process with the IRS. During October 2013, the Company received a letter from the IRS stating that the disclosure process was completed. This transaction had no effect on the Company for the nine months ended March 31, 2014.
J. Robinson West, the Chairman of the Board of Directors of the Company, also serves as a non-employee director on the board of directors for Key Energy Services Inc. ("KES"). KES performed contract drilling rig services for the Company in Poplar during the second quarter of fiscal year 2014. The total contract fees paid to KES during the nine months ended March 31, 2014, was $2.2 million. As of March 31, 2014, there were no unpaid contract fees related to KES.
See Note 11 - Stockholders' Equity above for discussions of other transactions in which Mr. Bogachev had an interest and which were finalized as of January 16, 2013.

Note 17 - Employee Severance Costs
The Company is required to record charges for one-time employee severance benefits and other associated costs as incurred. In July 2012, the Company incurred severance costs payable in connection with the termination of the employment of certain employees pursuant to the terms of their employment agreements. On March 31, 2014, the Company sold its interests in Palm Valley and Dingo to Central. Pursuant to the Sale Deed, the Company incurred severance costs payable in connection with the termination of certain MPA employees. For the nine months ended March 31, 2014, the Company expensed total employee-related severance costs of $1.5 million, all of which were charged to loss from discontinued operations, net of tax, in the unaudited condensed consolidated statement of operations. The Company does not expect any additional benefits or other associated costs related to the terminations of employment as discussed above.
The liability related to these severance costs is included in the unaudited condensed consolidated balance sheets under accrued and other liabilities. A reconciliation of the beginning and ending liability balance for charges to general and administrative expense and cash payments for the nine months ended March 31, 2014, is as follows:
 
Severance - Termination Benefits
 
Severance - Discontinued Operations
 
Total Severance Liability
 
(In thousands)
Fiscal year opening balance
$
418

 
$

 
$
418

Charges to loss from discontinued operations, net of tax

 
1,475

 
1,475

Cash payments
(250
)
 

 
(250
)
Balance at March 31, 2014
$
168

 
$
1,475

 
$
1,643


Note 18 - Subsequent Events
On April 15, 2014 the Company received approximately $4.6 million, the second cash installment pursuant to the Sale Deed related to the sale of the Amadeus Basin assets.


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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our 2013 Form 10-K, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the 2013 Form 10-K. Any capitalized terms used but not defined in the following discussion have the same meaning given to them in the 2013 Form 10-K. Unless otherwise indicated, all references in this discussion to Notes are to the Notes to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report. Our discussion and analysis includes forward looking statements that involve risks and uncertainties and should be read in conjunction with the Risk Factors under Item 1A of Part II of this report and under Item 1A of the 2013 Form 10-K, along with the cautionary discussion about forward looking statements at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than the results expressed or implied in our forward looking statements.

OVERVIEW OF THE COMPANY
Magellan Petroleum Corporation is an independent oil and gas exploration and production company focused on the development of a CO2-EOR program at Poplar in eastern Montana and the exploration of conventional and unconventional hydrocarbon resources in the Weald Basin, onshore UK. Magellan also owns an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory, Australia, which the Company currently plans to farmout; and an 11% ownership stake in Central, a Brisbane based exploration and production company that operates one of the largest holdings of prospective onshore acreage in Australia.
The Company conducts its operations through three wholly owned subsidiaries corresponding to the geographic areas in which the Company operates or has assets: NP in the US, MPUK in the UK, and MPA in Australia. The Company owns, indirectly through a wholly owned subsidiary of MPA, a 100% interest in the exploration block NT/P82.
Our strategy is to enhance shareholder value by maximizing the value of our existing assets. Our portfolio of operations includes several early stage oil and gas exploration and development projects, the successful development of which requires significant capital, as well as significant engineering and management resources. We are committed to investing in these projects to establish their technical and economic viability. In turn, we are focused on determining the most efficient way to create the greatest value and highest returns for our shareholders.

SUMMARY RESULTS OF OPERATIONS
Revenues for the three months ended March 31, 2014, totaled $1.9 million, compared to $1.7 million for the prior year period, an increase of 12%. This increase was primarily due to increased production at Poplar as a result of successful water shut-off treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014. We reduced our operating loss for the three months ended March 31, 2014, to $3.0 million, compared to an operating loss of $4.2 million for the prior year period. We also recorded net income for the three months ended March 31, 2014, of $24.1 million ($0.53/basic share), compared to a net loss of $4.3 million ($(0.09)/basic share) for the prior year period. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation below) was negative $477 thousand for the three months ended March 31, 2014, compared to negative $1.4 million for the prior year period. For further information, please refer to the separate discussions below in this section under Comparison of Results between the Three Months Ended March 31, 2014, and 2013, and the Nine Months Ended March 31, 2014, and 2013.

CORPORATE EVENTS
Sale of Amadeus Basin Assets and Restructuring of Australian Interests
On March 31, 2014, the Company sold its Amadeus Basin assets, the Palm Valley and Dingo gas fields, to Central PV, a wholly owned subsidiary of Central, through the sale of its wholly owned subsidiary Magellan Petroleum (N.T.) Pty. Ltd (the "Transaction") pursuant to the Sale Deed. In exchange for the assets, Central paid to Magellan cash in the total amount of AUD $20.0 million, in two installments of AUD $15.0 million and AUD $5.0 million on March 31, 2014, and April 15, 2014, respectively, and 39.5 million newly issued shares of Central stock, equivalent to an approximate 11% ownership interest in Central. Magellan is currently Central's single largest shareholder. Based on the Central closing price on May 8, 2014, these shares of stock represent a total value of AUD $16.8 million, or an AUD $1.8 million increase over the issuance value of AUD $15.0 million as determined on the Execution Date. In addition, Magellan is entitled to receive bonus payments from Central in the event that future gas sales revenues from Palm Valley exceed certain levels. The Company also maintained its right to the Mereenie Bonus, which it received as part of the asset swap

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agreement with Santos in September 2011, and which entitles the Company to potential total cash payments ranging from AUD $5.0 million to AUD $17.0 million based on certain gas sales thresholds at Mereenie.
Management believes this transaction represents a major milestone in the execution of the Company's strategy, both establishing greater financial security and simplifying the Company's operations and focus. We believe that the cash consideration from the transaction combined with the Company's previous cash balances provide the Company with sufficient funds to complete the CO2-EOR Pilot Project at Poplar, to participate in the drilling of its first exploratory wells in the UK, and to finance its ongoing operations. By selling Dingo, the Company avoided the need to finance an AUD $20.0 million development, including necessary gas transportation facilities, which would have rendered the Australian operations cash flow negative over the next five years. The Company has also been able to close its Brisbane, Australia office, which is expected to reduce consolidated general and administrative expenses by approximately $2.0 million to $3.0 million per year and bring the Company closer to operating cash flow break-even levels. In addition, management believes that the 11% ownership stake in Central allows the Company to maintain broader exposure to the Amadeus Basin through a player who controls most of the basin's acreage through farmouts to significant operators, and represents an attractive investment opportunity with significant value appreciation potential. Based on the Company's current balance sheet position and the expected costs of its current projects, the Company currently intends to continue holding its position in Central's stock. Finally, the Company is in the process of implementing a reorganization of its subsidiaries, whereby the Company's wholly owned subsidiary, MPUK, will hold a 30% interest in MPA, which will allow the Company to fund its future operations in the UK from the proceeds of the Transaction. The Company also expects that it will be able to repatriate the proceeds from the Transaction without incurring tax liabilities.
For a summary of the key terms of the Sale Deed and further information on the Amadeus Basin Sale, please see the Company's Current Reports on Form 8-K filed with the SEC on February 18, 2014, and March 31, 2014.

Series A Preferred Stock Dividend
Following the recent increase in the Company's share price to levels significantly above the Purchase Price of $1.22149381, at which each share of Series A Convertible Preferred Stock may be converted into one share of the Company's Common Stock, the Company has elected to pay the dividend to which the holders of Series A Convertible Preferred Stock are entitled to in cash.

HIGHLIGHTS OF OPERATIONAL ACTIVITIES
During the three months ended March 31, 2014, the Company progressed a number of initiatives for its operational assets to evaluate and determine the potential of its exploration and production properties.

Poplar (Montana, USA)
CO2-EOR pilot project. Based on the Company's technical analysis, the production history of the field to date, and reference to analogous CO2-EOR projects in the Williston Basin, management believes that the Charles formation at Poplar is an attractive candidate to use CO2-EOR technique in order to significantly increase the ultimate oil recovery of the field, resulting in increased reserves and oil production. To reduce the operational risk of implementing a full-field CO2-EOR program at Poplar, and to further validate the tertiary recovery technique on a full-field basis, the Company began to implement a CO2-EOR pilot project in the Charles formation in the first quarter of fiscal year 2014. The program consists of injecting CO2 in an injection well for a period ranging between one and two years and assessing its impact on the oil production out of four production wells surrounding the injection well.
As of the filing date of this report, all five wells have been drilled to total depth of approximately 5,800 feet, and all wells have been perforated. The Company has performed water shut-off treatments on the CO2 injection well, EPU 202-IW, and is planning to apply water shut-off treatments to the other four production wells during the fourth quarter of fiscal year 2014, which we believe will contribute to a better understanding of the impact of the CO2 to the reservoir at Poplar and improve the overall estimate of the oil recovery factor from the CO2-EOR technique. On March 25, 2014, the Company began injecting CO2 through the injection well, marking the beginning of the injection phase of the pilot. The Company is still in the testing phase of the CO2 injection facility, and considering the additional time required to perform water shut-off treatments to the four production wells, the Company projects that production from the four production wells of the CO2-EOR pilot will start to ramp up towards the end of the first quarter or the beginning of the second quarter of fiscal year 2015. Over the twelve months following the beginning of CO2 injection, the Company will be monitoring the performance of the pilot wells in response to the volumes of injected CO2, and will regularly re-calibrate our reservoir model. We currently expect to have preliminary findings of the pilot on or around September 2014, with more complete results expected by March 2015. With these results, the Company should be in a position to quantify the effectiveness of CO2-EOR technique on a full field basis at Poplar and the incremental volume of oil recoverable from a full-field CO2-EOR development.
Shallow Intervals. During the three months ended March 31, 2014, Magellan sold 23 Mbbls (254 bopd) of oil attributable to its net revenue interests in Poplar, compared to 19 Mbbls (216 bopd) of oil during the same period in 2013. This increase was primarily

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due to increased production at Poplar primarily as a result of successful water shut-off treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014, which mitigated the natural production decline of the field.
Deep Intervals. During the three months ended March 31, 2014, there was no activity in the Deep Intervals at Poplar. However, the Company may elect to perform a water shut-off treatment at the EPU 125 well or EPU 120 well in the Nisku formation in the coming months. Since the discovery of Poplar in the 1950s by Murphy Oil, the Nisku formation has produced a cumulative total of approximately 200 Mboe.

United Kingdom
Magellan's onshore UK acreage position is located in the Weald Basin, which is southwest of London and which contains multiple unconventional and conventional oil and gas prospects. The Company's primary objective in the UK is to establish the potential of our unconventional prospects, most of which lie within the licenses co-owned equally with Celtique Energie Holdings Ltd ("Celtique"), by drilling exploratory wells and collecting cores and logs. As part of this effort, the Company plans to participate in up to three evaluation wells with Celtique, the first of which is expected to spud between the summer of 2014 and the end of calendar year 2014, depending on the timing of the finalization of the planning and regulatory approval.
Central Weald Licenses. In the central Weald Basin, Magellan co-owns equally with Celtique three licenses, PEDLs 231, 234, and 243, representing 124 thousand net acres that may be prospective for unconventional oil and gas resources from the Kimmeridge Clay and Liassic formations and may be prospective for conventional development in other formations. These licenses are subject to drill-or-drop obligations and will now expire in June 2016 unless such obligations are met. The Company believes that the extension of the term of these licenses from June 2014 to June 2016, which was received during the third quarter of fiscal year 2014, was critical to grant sufficient time to further establish the potential of the unconventional prospects of these licenses and to allow the surrounding political process and social environment to unfold. During the quarter ended March 31, 2014, Magellan and Celtique advanced plans to drill a first exploratory well to be spud at Broadford Bridge, located within the license area of PEDL 234. A drilling permit for a well at Broadford Bridge has not yet been issued by the UK Department of Energy and Climate Change, but the process for obtaining the permit was materially advanced during this quarter. Timing of spudding this well will depend on the timing of finalization of the permit and availability of a drilling rig. The drilling permit that we are applying for at Broadford Bridge consists of a vertical well to be completed in the Triassic formation at a depth of approximately 10,000 feet, where we are seeking to test a conventional target identified as Willow, which is mainly prospective for gas. This well is intended to be completed in a conventional prospect in the Triassic formation. A complete suite of logs and cores is planned to be collected from the Kimmeridge Clay and Liassic formations, which we believe will provide certain technical data, including thickness, oil maturity, formation pressure, and rock brittleness, to be able to assess the potential for unconventional development of these formations and in turn possibly attract partners to continue the development of theses licenses. This well will satisfy the drill-or-drop obligations for both PEDL 234 and PEDL 243. The expected net cost to the Company is currently estimated at approximately $5.0 million. In addition, Celtique and Magellan have continued to advance the permit planning process to drill at the Wisborough Green and Fernhurst locations, as well as certain other potential locations.
Peripheral Weald Licenses. On the periphery of the Weald Basin, Magellan maintains non-operated interests in five additional exploration licenses representing an additional 39 thousand net acres that may be prospective for conventional oil and gas targets. In December 2013, Magellan executed a farmout of PEDLs 137 and 246, which contain the Horse Hill prospect, to Angus Energy ("Angus"), a privately owned UK based exploration and development company. Pursuant to the terms of the farmout, Angus is obligated to fund 100% of the cost of drilling a vertical exploratory well in order to earn a 65% working interest in, and operatorship of, the license. The Horse Hill prospect was identified on 2-D seismic data, which was reprocessed by the Company. It is located in the Triassic formation, which is approximately 10,000 ft. deep and is expected to primarily contain gas.
During the quarter ended March 31, 2014, the Company, together with its partners in the respective licenses, relinquished PEDLs 155 and 256 due to a determination of limited development prospectivity within the license areas, and PEDL 240, which was located on the Isle of Wight, due to inability to secure a suitable drill site. Relinquishment of these three licenses was effective in March 2014, and as a result, $0.7 million of exploration expense was recorded. The Company does not face abandonment or restoration liabilities with respect to these licenses. The Company did not believe these licenses contained material hydrocarbon resources and did not consider them core to its UK strategy.

Australia
NT/P82. During the three months ended March 31, 2014, the Company completed the processing and interpretation of 2-D and 3-D seismic surveys that the Company shot over part of NT/P82 in the Bonaparte Basin in December 2012. Based on these seismic studies, the Company believes that two large prospects are present within our block, and the Company began a farmout process of this license in April 2014.

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In completing a farmout, the Company expects to relinquish a portion of its working interest in, and operatorship of, NT/P82, in exchange for a commitment from the partner to drill exploration wells over the large gas prospects identified in the block to meet our requirements under the terms of the license. Given the estimated size of the prospects, the high level of offshore drilling activity in the Bonaparte Basin, the network of installed gas infrastructure in the relative vicinity of our block, and the relatively shallow depths of water in the license area, the Company believes it is well positioned to successfully complete a farmout during calendar year 2014.
In April 2014, the Company received from the Northern Territory government a one-year extension of the deadline for the drilling of an exploration well in NT/P82 until May 2016. This extension will allow the Company greater flexibility in identifying partner(s) for, and executing a farmout of, this exploration block.

CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES
Historically, we have funded our activities from cash from operations, asset sales, farmout agreements, an issuance of preferred equity, and our existing cash balance. Based on our existing cash position, including the cash of the Amadeus Basin sale, the Company believes it has sufficient financial resources to fund its ongoing operations and its exploration projects, including the remainder of the CO2-EOR pilot project and the drilling of exploratory wells in the UK.

Uses of Funds
Capital Expenditure Plans. At Poplar, the Company does not face significant mandatory capital expenditure requirements to maintain its acreage position. Substantially all of the leases are held by production and contain producing wells with reserves adequate to sustain multi-year production. Approximately 80% of the acreage has been unitized as a federal exploratory unit, which is held by economic production from any one well in the unit. Currently, Poplar contains 40 productive wells. In the Shallow Intervals, which are 100% owned and operated by the Company, discretionary capital expenditure plans over the next two years will be determined primarily by the results of the CO2-EOR pilot project, which is expected to continue through approximately December 2015. The total cost of the CO2-EOR pilot, including capital expenditures and certain operating expenses, was initially estimated at approximately $20.0 million, which included approximately $4.0 million related to the cost of purchasing certain volumes of CO2 over a two year period. As of April 30, 2014, the Company has incurred approximately $17.0 in relation to the CO2-EOR pilot and expects that another $8.5 million will be required to both complete all the wells, as well as to inject certain volumes of CO2 estimated to cost approximately $4.0 million. The cost increases primarily reflect changes in the scope of the project, in particular water shut-off treatments, which we believe will ultimately result in improved performance of the project. The final cost of the injected volumes of CO2 will depend on the total amount effectively injected.
In the Deep Intervals, which are operated by the Company and in which the Company has a working interest of 50% in the majority of the leases, the Company does not intend to incur material capital expenditures in fiscal year 2014. Based on its cash resources and other strategic considerations, the Company may invest in re-completing a well in the Nisku formation.
In the UK, the Company's interests are governed by various PEDLs and one Seaward Production License. PEDLs 231, 234, and 243, which the Company co-owns equally with Celtique, are subject to "drill-or-drop" obligations with a deadline of June 2016. The Company is currently focused on securing potential drilling locations, applying for drilling permits, preparing to drill the Broadford Bridge well, and evaluating the potential of its unconventional prospects in these licenses. The Company expects to fund its share of the cost the Broadford Bridge well, currently estimated to be approximately $5.0 million. This well will meet the drill-or-drop obligations for both PEDLs 234 and 243. Pending the results of this well, the Company may participate in a second exploratory well within these PEDLs towards the end of calendar year 2015. The Company is also in the process of applying for drilling permit approvals for potential wells located at Wisborough Green and Fernhurst. The Company expects to fund these expenditures from its existing cash balances. The Company does not expect to incur further significant capital or exploratory expenditures on PEDLs 231, 234 and 243 in fiscal year 2014.
In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in NT/P82. Under the terms of the permit, the Company is required to drill one exploratory well on the license by May 2016. Following the successful completion of seismic surveys in the license area and the associated processing and interpretation, the Company is actively engaged in a farmout process to identify a partner experienced in offshore exploratory drilling to drill the exploratory well on our behalf. The Company does not expect to incur further significant capital expenditures of its own until the first exploration well has been drilled.
Discontinued Operations. As a result of the sale of the Amadeus Basin Assets, the Company will be able to avoid development costs at Dingo of approximately AUD $20.0 million, including necessary gas transportation facilities, which would have rendered the Australian operations cash flow negative over the next five years. The closing of the Brisbane, Australia office will also result in reduced consolidated general and administrative expenditures of approximately $2.0 million to $3.0 million per year.
Contractual Obligations. Please refer to the contractual obligations table in Part II, Item 7 of our 2013 Form 10-K for information on all material contractual obligations as of June 30, 2013. There were no material changes to that information during the quarter ended March 31, 2014, except that, as a result of the sale of the Amadeus Basin assets on March 31, 2014, (i) purchase

24

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obligations attributable to certain exploration and capital expenditures related to MPA were reduced by approximately $0.7 million (with the entire amount originally scheduled to occur in less than one year); (ii) asset retirement obligations were reduced by approximately $4.5 million (with the substantial majority of that amount originally scheduled to occur in more than five years); and (iii) operating lease obligations were reduced by approximately $1.1 million (with $0.2 million, $0.3 million, and $0.6 million of that amount originally scheduled to occur in less than one year, from one to three years, and from three to five years, respectively).
Share Repurchase Program. On September 24, 2012, the Company announced that its Board had approved a stock repurchase program whereby the Company is authorized to repurchase up to a total of $2.0 million in shares of its Common Stock. As of March 31, 2014, $1.9 million remained authorized for stock repurchases under this program. This authorization will expire on August 21, 2014.

Sources of Funds
Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $19.0 million of cash and cash equivalents as of March 31, 2014, compared to $32.5 million as of June 30, 2013. In addition to the first cash installment of $13.9 million received on March 31, 2014, for the sale of the Amadeus Basin assets pursuant to the Sale Deed, the Company also received the second cash installment of $4.7 million on April 15, 2014.
The Company considers cash equivalents to be short term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates. Cash balances totaled $16.4 million as of March 31, 2014, with the remaining $2.6 million held in cash equivalents with maturities of 90 days or less. In the US, cash equivalents were held in US Treasury notes and totaled $2.5 million, and in Australia, cash equivalents were held in several time deposit accounts totaling $0.1 million.
Due to the international nature of its operations, the Company is exposed to certain legal and tax constraints in matching the capital needs of its assets and its cash resources. As of March 31, 2014, $14.1 million, or 74% of the Company's consolidated cash and cash equivalents, was deposited in accounts held by MPA. To the extent that the Company repatriates cash amounts from MPA to the US, the Company will potentially be liable for any incremental US Federal and state income tax, which may be reduced by the US Federal and state net operating losses and foreign tax credit carry forwards available to the Company at that time.
Existing Credit Facilities. A summary of the Company's existing credit facilities is as follows:
 
March 31,
2014
 
June 30,
2013
 
(In thousands)
Outstanding borrowings:
 
 
 
Term loan
$
138

 
$
390

Line of credit

 
51

Total
$
138

 
$
441

The Company, through its wholly owned subsidiary NP, maintains its only credit facility (the "Line of Credit") with Jonah Bank of Wyoming. As of March 31, 2014, $0 of the $2.0 million Line of Credit was drawn, $25 thousand secured a Line of Credit in favor of the Bureau of Land Management, and $1.95 million remained available to borrow. As of March 31, 2014, NP was in compliance with its financial covenants under the term loan agreement. The credit facility is collateralized by a first mortgage and an assignment of production from Poplar, and guaranteed by the Company up to $6.0 million, but not to exceed the amount of the principal owed, which was $138 thousand as of March 31, 2014. The Company believes that by the end of fiscal year 2014, the Line of Credit with Jonah Bank of Wyoming will be fully amortized. The Company may seek to enter into a new credit facility.
Central Shares. Based on the Company's current balance sheet position, the expected costs of its current projects, and the potential value appreciation of Central's shares, the Company currently intends to continue holding its position in Central's stock. The Company is not constrained in its ability to sell its shares in Central by contractual arrangements with Central. In the future, Magellan may decide to dispose of part or all of its position in Central's stock to fund some of the Company's activities.
Other Sources of Financing. In addition to its existing liquid capital resources as discussed above, the Company has various alternatives to fund the development of its assets. These alternatives could potentially include conventional bank debt, a reserve-based loan facility, mezzanine financing, issuances of new common shares or hybrid equity securities to potential investors via a PIPE or secondary offering, and a partial or complete divestiture or farmout of a portion of the development program with respect to some of the Company's assets.


25

Table of Contents

Cash Flows
The following table presents the Company's cash flow information for the nine months ended:
 
March 31,
 
2014
 
2013
 
(In thousands)
Cash (used in) provided by:
 
 
 
Operating activities
$
(10,631
)
 
$
(14,258
)
Investing activities
(3,075
)
 
(2,233
)
Financing activities
(314
)
 
(9,931
)
Discontinued operations
101

 
(1,005
)
Effect of exchange rate changes on cash and cash equivalents
464

 
728

Net decrease in cash and cash equivalents
$
(13,455
)
 
$
(26,699
)
Cash used in operating activities during the nine months ended March 31, 2014, was $10.6 million, compared to cash used in operating activities of $14.3 million for the same period in 2013. The decrease in cash used in operating activities was primarily due to an increase in revenues of $1.1 million, and timing differences related to the payment of accounts payable and accrued liabilities.
Cash used in investing activities during the nine months ended March 31, 2014, was $3.1 million, compared to $2.2 million for the same period in 2013. During the nine months ended March 31, 2014, $13.9 million was received from Central as the first installment pursuant to the Sale Deed for the sale of Palm Valley and Dingo. This amount was offset by $16.9 million of capital expenditures spent on the development of our assets. The increase in cash used in investing activities due to the capital expenditures related primarily to the CO2-EOR pilot project at Poplar.
Cash used in financing activities during the nine months ended March 31, 2014, was $0.3 million, compared to $9.9 million of cash used in financing activities for the same period in 2013. The decrease in cash used in financing activities for the nine months ended March 31, 2014, related to the repurchase of Common Stock from Sopak and long term debt repayments in the prior year period.
Cash used in discontinued operations is related to the activities of Palm Valley and Dingo, and no continuing impact on cash flows is expected from discontinued operations.
During the nine months ended March 31, 2014, the effect of changes in foreign currency exchange rates positively impacted the translation of our AUD denominated cash and cash equivalent balances into USD and resulted in an increase of $464 thousand in cash and cash equivalents, compared to an increase of $0.7 million for the same period in 2013, primarily as a result of the combined impact of the weakening AUD and the significant decrease in cash and cash equivalent balances denominated in AUD compared to the prior year period.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATION
Adjusted EBITDAX
We define Adjusted EBITDAX as net income (loss) attributable to Magellan, plus (minus): (i) depletion, depreciation, amortization, and accretion expense, (ii) exploration expense, (iii) stock based compensation expense, (iv) impairment expense, (v) net (income) loss from discontinued operations, (vi) net interest expense (income), and (vii) other (income) expense. Adjusted EBITDAX is not a measure of net income or cash flow as determined by GAAP and excludes certain items that we believe affect the comparability of operating results.
Our Adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income (loss) as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure and to assess the financial performance of our assets and our company without regard to historical cost basis and certain items that affect the comparability of period to period operating results.

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Table of Contents

The following table provides a reconciliation of net income (loss) to Adjusted EBITDAX for the periods ended:
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Net income (loss) attributable to Magellan Petroleum Corporation
$
24,520

 
$
(4,332
)
 
$
15,573

 
$
(16,928
)
Depletion, depreciation, amortization, and accretion expense
337

 
230

 
956

 
645

Exploration expense
1,605

 
2,395

 
2,776

 
3,523

Stock based compensation expense
601

 
147

 
1,667

 
753

Impairment expense

 

 

 
890

Net interest expense
80

 
20

 
103

 
51

Other (income) expense
(27
)
 
(449
)
 
78

 
(337
)
Net (income) loss from discontinued operations
(27,593
)
 
606


(24,937
)
 
5,564

Adjusted EBITDAX
$
(477
)
 
$
(1,383
)
 
$
(3,784
)
 
$
(5,839
)
For clarification purposes, the table below provides an alternative method for calculating Adjusted EBITDAX, which can also be calculated as revenue less (i) lease operating expense and (ii) general and administrative expense; plus stock based compensation expense.
The following table provides the alternative method for calculating Adjusted EBITDAX for the periods ended:
 
THREE MONTHS ENDED
 
NINE MONTHS ENDED
 
March 31,
 
March 31,
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
REVENUE FROM OIL PRODUCTION
$
1,907

 
$
1,706

 
$
5,674

 
$
4,608

Less:
 
 
 
 
 
 
 
Lease operating
(1,397
)
 
(1,032
)
 
(4,714
)
 
(3,515
)
General and administrative
(1,588
)
 
(2,204
)
 
(6,411
)
 
(7,685
)
Plus:
 
 
 
 
 
 
 
Stock based compensation expense
601

 
147

 
1,667

 
753

Adjusted EBITDAX
$
(477
)
 
$
(1,383
)
 
$
(3,784
)
 
$
(5,839
)

COMPARISON OF RESULTS BETWEEN THE THREE MONTHS ENDED MARCH 31, 2014, AND 2013
The following table presents results of operations for the three months ended:
 
March 31,
 
 
 
 
 
2014
 
2013
 
Difference
 
Percent change
Poplar:
 
 
 
 
 
 
 
Oil revenue (In thousands)
$
1,907

 
$
1,706

 
$
201

 
12
 %
Oil sales volume (Mbbls)
23

 
19

 
4

 
21
 %
Oil sales volume (boepd)
254

 
216

 
38

 
18
 %
Average realized oil price ($/bbl)
$82.90
 
$89.78
 
$(6.88)
 
(8
)%
Oil Revenue
Revenues for the three months ended March 31, 2014, totaled $1.9 million, compared to $1.7 million in the prior year period, an increase of 12%. The $201 thousand increase in revenue over the prior year was primarily due to the increased production volume, which was offset by a 8% decrease in realized prices.


27

Table of Contents

Oil Sales Volume
Sales volume for the three months ended March 31, 2014, totaled 23 Mboe (254 boepd), compared to 19 Mboe (216 boepd) sold in the same period in the prior year, an increase of 21%. The increase was primarily the result of increased production from water shut-off treatments and workovers.

Average Realized Oil Price
The average realized price for the three months ended March 31, 2014, was $82.90/boe, compared to $89.78/boe the same period in the prior year, a decrease of 8%. The decrease was primarily the result of increasing differentials relative to the benchmark pricing (WTI) realized at the Poplar field. The Company does not currently engage in any oil and gas hedging activities.

Operating and Other Expenses
The following table presents operating expenses for the three months ended:
 
March 31,
 
 
 
 
 
2014
 
2013
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Selected operating expenses:
 
 
 
 
 
 
 
Lease operating
$
1,397

 
$
1,032

 
$
365

 
35
 %
Depletion, depreciation, amortization, and accretion
$
337

 
$
230

 
$
107

 
47
 %
Exploration
$
1,605

 
$
2,395

 
$
(790
)
 
(33
)%
General and administrative
$
1,588

 
$
2,204

 
$
(616
)
 
(28
)%
 
 
 
 
 
 
 
 
Selected operating expenses ($/boe):
 
 
 
 
 
 
 
Lease operating
$61
 
$53
 
$8
 
15
 %
Depletion, depreciation, amortization, and accretion
$15
 
$12
 
$3
 
25
 %
Exploration
$70
 
$123
 
$(53)
 
(43
)%
General and administrative
$69
 
$114
 
$(45)
 
(39
)%
Lease Operating Expenses. Lease operating expenses increased $0.4 million to $1.4 million, or $61/boe, during the three months ended March 31, 2014. The increase is related to workover activity and maintenance on wells.
Depletion, Depreciation, Amortization, and Accretion. The following table presents depletion, depreciation, amortization, and accretion for the three months ended:
 
March 31,
 
 
 
 
 
2014
 
2013
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Depreciation and amortization
$
75

 
$
81

 
$
(6
)
 
(7
)%
Depletion
221

 
111

 
110

 
99
 %
ARO accretion
41

 
38

 
3

 
8
 %
Total
$
337

 
$
230

 
$
107

 
47
 %
Depletion, depreciation, amortization, and accretion expenses increased $107 thousand to $337 thousand, or $15/boe, during the three months ended March 31, 2014, compared to the prior year period. The change in depletion was primarily due to the impact of the change in reserve quantities as of June 30, 2013, relative to the prior fiscal year end and the impact of increased production from the Charles formation in the Poplar field.
Exploration Expenses. Exploration expenses decreased by $0.8 million to $1.6 million, or $70/boe, during the three months ended March 31, 2014. The Company allowed petroleum exploration and development licenses in the amount of $0.7 million in the UK to expire at the end of their term, compared to $2.2 million write off of the Company's interest in the Markwells Wood-1 well in the UK, which resulted from the Company's determination that it had no further development plans with respect to this well.

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Table of Contents

General and Administrative Expenses. The following table presents general and administrative expenses for the three months ended:
 
March 31,
 
 
 
 
 
2014
 
2013
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
General and administrative (excluding stock based compensation expense)
$
987

 
$
2,057

 
$
(1,070
)
 
(52
)%
Stock compensation expense
601

 
147

 
454

 
309
 %
Total
$
1,588

 
$
2,204

 
$
(616
)
 
(28
)%
General and administrative expenses for the three months ended March 31, 2014, decreased by $0.6 million relative to the prior year period. General and administrative expenses, excluding stock based compensation, decreased by $1.1 million to $1.0 million, or $43/boe during the three months ended March 31, 2014