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

FORM 10-Q

(MARK ONE)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2013
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from    to
Commission File Number 001-5507
MAGELLAN PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
06-0842255
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
1775 Sherman Street, Suite 1950, Denver, CO

80203
(Address of principal executive offices)
(Zip Code)
(720) 484-2400
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
o
Accelerated filer
o
Non-accelerated filer
o (Do not check if a smaller reporting company)
Smaller reporting company
þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes þ No
The number of shares outstanding of the issuer's single class of common stock as of February 12, 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)
 
December 31,
2013
 
June 30,
2013
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
12,159

 
$
32,469

Accounts receivable — trade
842

 
794

Accounts receivable — working interest partners
35

 
58

Inventories
561

 
555

Prepaid and other assets
2,065

 
1,422

Total current assets
15,662

 
35,298

 
 
 
 
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
 
 
 
Proved oil and gas properties
35,872

 
35,377

Less accumulated depletion, depreciation, amortization, and accretion
(6,216
)
 
(5,814
)
Unproved oil and gas properties
5,238

 
5,312

Wells in progress
14,459

 
923

Land, buildings, and equipment (net of accumulated depreciation of $1,611 and $1,810 as of December 31, 2013, and June 30, 2013, respectively)
1,142

 
1,382

Net property and equipment
50,495

 
37,180

 
 
 
 
OTHER NON-CURRENT ASSETS:
 
 
 
Goodwill
2,174

 
2,174

Deferred income taxes
7,217

 
7,217

Other long term assets
250

 
403

Total other non-current assets
9,641

 
9,794

Total assets
$
75,798

 
$
82,272

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Short term line of credit
$
51

 
$
51

Current portion of note payable
174

 
390

Current portion of asset retirement obligations
384

 
476

Accounts payable
2,756

 
1,948

Accrued and other liabilities
3,363

 
2,757

Accrued dividends

 
202

Total current liabilities
6,728

 
5,824

 
 
 
 
LONG TERM LIABILITIES:
 
 
 
Asset retirement obligations
6,628

 
6,403

Contingent consideration payable
4,096

 
3,940

Other long term liabilities
165

 
163

Total long term liabilities
10,889

 
10,506

COMMITMENTS AND CONTINGENCIES (Note 12)


 


 
 
 
 
PREFERRED STOCK (Note 7):
 
 
 
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 December 31, 2013, 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 December 31, 2013, and June 30, 2013, respectively
548

 
540

Treasury stock (at cost): 9,425,114 and 9,414,176 shares as of December 31, 2013, and June 30, 2013, respectively
(9,344
)
 
(9,333
)
Capital in excess of par value
91,844

 
90,786

Accumulated deficit
(59,862
)
 
(50,079
)
Accumulated other comprehensive income
10,455

 
10,526

Total equity attributable to Magellan Petroleum Corporation
33,641

 
42,440

Total liabilities, preferred stock and equity
$
75,798

 
$
82,272

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

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MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except share and per share amounts)
 
THREE MONTHS ENDED
 
SIX MONTHS ENDED
 
December 31,
 
December 31,
 
2013
 
2012
 
2013
 
2012
REVENUES:
 
 
 
 
 
 
 
Oil production
$
1,632

 
$
1,442

 
$
3,767

 
$
2,902

Gas production
237

 
306

 
458

 
507

Total revenues
1,869

 
1,748

 
4,225

 
3,409

 
 
 
 
 
 
 
 
OPERATING EXPENSES:
 
 
 
 
 
 
 
Lease operating
1,718

 
1,665

 
4,474

 
3,716

Depletion, depreciation, amortization, and accretion
598

 
332

 
907

 
649

Exploration
728

 
4,094

 
1,657

 
4,716

General and administrative
2,882

 
3,394

 
5,977

 
7,057

Impairment

 

 

 
890

Loss on sale of assets
33

 

 
95

 

Total operating expenses
5,959

 
9,485

 
13,110

 
17,028

 
 
 
 
 
 
 
 
LOSS FROM OPERATIONS
(4,090
)
 
(7,737
)
 
(8,885
)
 
(13,619
)
 
 
 
 
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Net interest income
23

 
258

 
43

 
479

Other expense
(45
)
 
(127
)
 
(105
)
 
(112
)
Total other (expense) income
(22
)
 
131

 
(62
)
 
367

 
 
 
 
 
 
 
 
LOSS BEFORE INCOME TAX
(4,112
)
 
(7,606
)
 
(8,947
)
 
(13,252
)
Income tax benefit

 
321

 

 
658

LOSS AFTER INCOME TAX
(4,112
)
 
(7,285
)
 
(8,947
)
 
(12,594
)
Preferred stock dividend
(421
)
 

 
(836
)
 

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(4,533
)
 
$
(7,285
)
 
$
(9,783
)
 
$
(12,594
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per common share (Note 9):
 
 
 
 
 
 
 
Weighted average number of basic and diluted shares outstanding
45,348,709

 
53,860,337

 
45,348,774

 
53,854,759

Net loss per basic and diluted share outstanding
$
(0.10
)
 
$
(0.14
)
 
$(0.22)
 
$(0.23)
The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

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MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
(In thousands)
 
THREE MONTHS ENDED
 
SIX MONTHS ENDED
 
December 31,
 
December 31,
 
2013
 
2012
 
2013
 
2012
LOSS AFTER INCOME TAX
$
(4,112
)
 
$
(7,285
)
 
$
(8,947
)
 
$
(12,594
)
Foreign currency translation adjustments
(248
)
 
22

 
(77
)
 
963

Unrealized holding gain (loss) on securities available for sale, net of deferred tax of $0
(17
)
 

 
6

 
(22
)
Comprehensive loss attributable to Magellan Petroleum Corporation
$
(4,377
)
 
$
(7,263
)
 
$
(9,018
)
 
$
(11,653
)
The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

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MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)
(In thousands, except share amounts)
 
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 loss

 

 

 
(8,947
)
 

 
$
(8,947
)
Foreign currency translation adjustments

 

 

 

 
(77
)
 
$
(77
)
Unrealized holding gain on securities available for sale, net of taxes

 

 

 

 
6

 
$
6

Stock and stock compensation expense
8

 

 
1,058

 

 

 
$
1,066

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

 
(11
)
 

 

 

 
$
(11
)
Preferred stock dividend

 

 

 
(836
)
 

 
$
(836
)
December 31, 2013
$
548

 
$
(9,344
)
 
$
91,844

 
$
(59,862
)
 
$
10,455

 
$
33,641

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

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MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
 
SIX MONTHS ENDED
 
December 31,
 
2013
 
2012
OPERATING ACTIVITIES:
 
 
 
LOSS AFTER INCOME TAX
$
(8,947
)
 
$
(12,594
)
Adjustments to reconcile net loss to net cash used in operating activities:
 
 
 
Foreign transaction (gain) loss
(26
)
 
36

Depletion, depreciation, amortization, and accretion
907

 
649

Fair value increase of contingent consideration payable
156

 
161

Deferred income taxes

 
(658
)
Loss on disposal of assets
95

 

Stock compensation expense
1,066

 
606

Impairment loss

 
890

Severance benefit costs

 
755

Net changes in operating assets and liabilities:
 
 
 
Accounts receivable
129

 
305

Inventories
(6
)
 
(42
)
Prepayments and other current assets
(647
)
 
6

Accounts payable and accrued liabilities
1,118

 
886

Other long term liabilities
3

 
(14
)
Net cash used in operating activities
(6,152
)
 
(9,014
)
 
 
 
 
INVESTING ACTIVITIES:
 
 
 
Additions to property and equipment
(13,943
)
 
(1,070
)
Proceeds from sale of assets
29

 

Net cash used in investing activities
(13,914
)
 
(1,070
)
 
 
 
 
FINANCING ACTIVITIES:
 
 
 
Repurchase of common stock

 
(137
)
Short term debt issuances
1,000

 
1,450

Short term debt repayments
(1,216
)
 
(1,315
)
Long term debt repayments

 
(264
)
Net cash used in financing activities
(216
)
 
(266
)
Effect of exchange rate changes on cash and cash equivalents
(28
)
 
839

Net decrease in cash and cash equivalents
(20,310
)
 
(9,511
)
Cash and cash equivalents at beginning of period
32,469

 
41,215

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
12,159

 
$
31,704

 
 
 
 
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
557

 
109

Preferred stock dividend
836

 

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

5

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Basis of Presentation
Description of Operations
Magellan Petroleum Corporation is an independent oil and gas exploration and development company primarily focused on the development of a CO2-enhanced oil recovery ("CO2-EOR") program at Poplar Dome ("Poplar") in eastern Montana. Historically active internationally, Magellan also maintains exposure to the UK and Australian oil and gas markets through the following assets: (i) a large, mostly non-operated acreage position onshore UK in the Weald and Wessex Basins for prospective unconventional shale oil and gas production; (ii) an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory, Australia; and (iii) two gas fields, Palm Valley and Dingo, onshore Northern Territory, 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"), and Magellan Petroleum Australia Pty Ltd ("MPA").

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 six months ended December 31, 2013, 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 period. Actual results could differ from those estimates.

Foreign Currency Translation
The functional currency of our foreign subsidiaries is their local currency. Assets and liabilities of foreign subsidiaries are translated to US dollars at period-end exchange rates, and our unaudited condensed consolidated statements of operations and cash flows are translated at average exchange rates during the reporting period. Resulting translation adjustments are recorded in accumulated other comprehensive income, a separate component of stockholders' equity.
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.

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 on a graded amortized method and 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

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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 to estimate the expected term of stock options due to a lack of related historical data regarding exercise, cancellation, and forfeiture rates. 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 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
During the quarter ended June 30, 2013, the Company completed a corporate restructuring of its wholly owned subsidiary in the UK whereby the equity interest in MPUK was transferred from MPA to Magellan. The Company benefits from this improved structure through (i) simplified accounting and the elimination of administrative redundancies, (ii) enhanced communication and clarity for investors, and (iii) increased flexibility in the structuring of investment and operating decisions. This realignment in corporate structure required the Company to re-evaluate its reportable segments under Financial Accounting Standards Board Accounting Standards Codification ("ASC") Topic 280, Segment Reporting. 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, and MPA. The presentation of all historical segment information herein has been changed 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 10 - Segment Information.

Recently Issued Accounting Standards
There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2013.

Note 2 - Debt
Long term debt relates to a $1.7 million note payable by NP, re-issued in January 2011 (the "Note Payable"). The Note Payable will be fully amortized in June 2014. The outstanding principal of the Note Payable as of December 31, 2013, and June 30, 2013, consisted of the following:
 
December 31,
2013
 
June 30,
2013
 
(In thousands)
Note Payable
$
174

 
$
390

Less current portion of Note Payable
(174
)
 
(390
)
Long term Note Payable
$

 
$

As of December 31, 2013, the minimum future principal maturities of the Note Payable were as follows:
 
Total
 
(In thousands)
One year
$
174

Total
$
174


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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 December 31, 2013, resulting in an interest rate of 6.25% per annum as of December 31, 2013. Under the Note Payable, NP is subject to certain customary financial and restrictive covenants. As of December 31, 2013, NP was in compliance with all financial and restrictive covenants.
In addition, the Company has a $1.0 million working capital line of credit classified as short term debt (the "Line of Credit"). The amount outstanding on the Line of Credit was $51 thousand as of December 31, 2013, and June 30, 2013, respectively. The Line of Credit bears interest at a variable rate, which was 6.25% as of December 31, 2013. This Line of Credit also secures both a letter of credit in the amount of $25 thousand in favor of the Bureau of Land Management and business credit cards in the amount of $25 thousand. As of December 31, 2013, $0.9 million was available under this Line of Credit.
The Note Payable and Line of Credit are collateralized by a first mortgage and an assignment of production from Poplar and are guaranteed by Magellan up to $6.0 million, not to exceed the amount of the principal owed. The carrying amount of the Company's long term debt approximates its fair value, due to its variable interest rate, which resets based on market rates.

Note 3 - Asset Retirement Obligations
The estimated valuation of asset retirement obligations ("AROs") is based on the Company's historical experience and management's best estimate of plugging and abandonment costs by field. Assumptions and judgments made by management when assessing an ARO include: (i) the existence of a legal obligation; (ii) estimated probabilities, amounts, and timing of settlements; (iii) the credit-adjusted risk-free rate to be used; and (iv) inflation rates. Accretion expense is recorded under depletion, depreciation, amortization, and accretion in the unaudited condensed consolidated statements of operations. If the recorded value of ARO requires revision, the revision is recorded to both the ARO and the asset retirement capitalized cost.
The following table summarizes the ARO activity for the six months ended December 31, 2013:
 
Total
 
(In thousands)
Fiscal year opening balance

$
6,879

Liabilities incurred
7

Accretion expense
220

Effect of exchange rate changes
(94
)
December 31, 2013
7,012

Less current asset retirement obligation
384

Long term asset retirement obligation
$
6,628


Note 4 - 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 and/or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed above for all periods presented. During the six months ended December 31, 2013, and 2012, there have been no transfers in and/or out of Level 1, Level 2, or Level 3.


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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 value of the Line of Credit and Note Payable (see Note 2 - Debt) approximates fair value due to their variable interest rate structure.

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:
 
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Securities available for sale (1)
50

 

 

 
50

 
$
50

 
$

 
$

 
$
50

Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable (2)
$

 
$

 
$
4,096

 
$
4,096

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

 

 

 
44

 
$
44

 
$

 
$

 
$
44

Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable (2)
$

 
$

 
$
3,940

 
$
3,940

(1) Included in the unaudited condensed consolidated balance sheets under prepaid and other assets.
(2) See Note 12 - 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
 
December 31,
2013
 
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

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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 six months ended December 31, 2013:
 
Total
 
(In thousands)
Fiscal year beginning balance
$
3,940

Accretion of contingent consideration payable
156

December 31, 2013
$
4,096

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 six months ended December 31, 2013, no events or circumstances were identified that would indicate that an impairment of our oil and gas properties has occurred.

Note 5 - Income Taxes
The Company has estimated the applicable effective tax rate expected for the full fiscal year. The Company's effective tax rate used to estimate income taxes on a current year-to-date basis for the six months ended December 31, 2013, and 2012, is 0% and 4.96%, 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 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. Consistent with the position at June 30, 2013, the Company maintains the partial valuation allowance recorded against the DTAs that relate to the Australian Petroleum Resource Rent Tax as of December 31, 2013, until such time as we are able to determine it is "more-likely-than-not" those reserved DTAs will be realized.

Note 6 - 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 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 six months ended December 31, 2013, the Company granted a total of 3,000,000 stock options under the 2012 Stock Incentive Plan, of the 3,000,000 stock options granted, 1,500,000 were issued as PBOs, and 1,500,000 were issued with market based vesting provisions. The performance metrics used to measure the potential vesting of the PBOs consisted of completing the

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CO2-EOR pilot program at Poplar (weighted 10%), approval of a full field CO2-EOR development project at Poplar (weighted 40%), sale of substantially all of the Amadeus Basin assets (weighted 20%), approval of a farmout agreement or participation in drilling a well in the Weald Basin (weighted 20%), approval of a farmout agreement 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 and average stock price as defined.
As of December 31, 2013, zero stock options with market based vesting provisions or PBOs were vested, and 335,107 shares, including forfeited shares, were available for future issuance. Stock options outstanding have expiration dates ranging from January 16, 2014, to June 15, 2023.
The following table summarizes the stock option activity for the six months ended December 31, 2013:
 
Number of
Shares
 
WAEPS (1)
Fiscal year opening balance
7,788,957

 
$1.33
Granted
3,000,000

 
$1.03
December 31, 2013
10,788,957

 
$1.25
 
 
 
 
Weighted average remaining contractual term
6.6

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 six months ended:
 
December 31,
 
2013
 
2012
 
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 $1.1 million of related stock compensation expense for the six months ended December 31, 2013, and $0.6 million of related stock compensation expense for the six months ended December 31, 2012. Stock compensation expense is included in general and administrative expense in the unaudited condensed consolidated statements of operations. As of December 31, 2013, the unrecorded expected future compensation expense related to stock option awards was $1.9 million.

Stock Awards
On July 1, 2013, 450,000 restricted shares of 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. Between July 1, 2013, and December 31, 2013, the Company issued a total of 266,664 shares of its common stock to non-employee directors pursuant to this policy under the 2012 Stock Incentive Plan.


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Note 7 - 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 (the "Common Stock"), 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.

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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 six months ended December 31, 2013, the Company recorded a preferred stock dividend of $0.8 million related to the Series A Preferred Stock. The activity related to the Series A Preferred Stock for the six months ended December 31, 2013, is as follows:
 
SIX MONTHS ENDED
 
FISCAL YEAR ENDED
 
December 31, 2013
 
June 30, 2013
 
Number of shares
 
Amount
 
Number of shares
 
Amount
 
(In thousands, except share amounts)
Opening balance
19,239,734

 
$
23,502

 

 
$

Issuance of Series A Preferred Stock

 

 
19,239,734

 
23,502

PIK dividends issued, previously accrued and payable in cash
164,607

 
202

 

 

Current year PIK dividends issued
685,095

 
836

 

 

Total Series A Preferred Stock
20,089,436

 
$
24,540

 
19,239,734

 
$
23,502


Note 8 - 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 December 31, 2013, $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

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Table of Contents

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:
 
SIX MONTHS ENDED
 
FISCAL YEAR ENDED
 
December 31, 2013
 
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

 

 

Total
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%.

Note 9 - Earnings Per Common Share
The following table summarizes the computation of basic and diluted earnings per share:
 
THREE MONTHS ENDED
 
SIX MONTHS ENDED
 
December 31,
 
December 31,
 
2013
 
2012
 
2013
 
2012
 
(In thousands, except share and per share amounts)
NET LOSS AFTER INCOME TAX
$
(4,112
)
 
$
(7,285
)
 
$
(8,947
)
 
$
(12,594
)
Preferred stock dividend
(421
)


 
(836
)
 

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(4,533
)
 
$
(7,285
)
 
$
(9,783
)
 
$
(12,594
)
 
 
 
 
 
 
 
 
Basic and diluted weighted average shares outstanding (1)
45,348,709

 
53,860,337

 
45,348,774

 
53,854,759

Net loss per basic and diluted share outstanding (1)
$(0.10)
 
$(0.14)
 
$(0.22)
 
$(0.23)
(1) There is no dilutive effect on earnings per share in periods with net losses.

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Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following:
 
THREE MONTHS ENDED
 
SIX MONTHS ENDED
 
December 31,
 
December 31,
 
2013
 
2012
 
2013
 
2012
In-the-money stock options
157,500

 

 
157,500

 

Non-vested restricted stock
900,000

 

 
900,000

 

Total
1,057,500

 

 
1,057,500

 


Note 10 - 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, MPA, which is primarily active in Australia, as well as Corporate, which is treated as a cost center. The following table presents segment information as follows:
 
THREE MONTHS ENDED
 
SIX MONTHS ENDED
 
December 31,
 
December 31,
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
REVENUES:
 
 
 
 
 
 
 
NP
$
1,632

 
$
1,442

 
$
3,767

 
$
2,902

MPA
237

 
306

 
458

 
507

Consolidated revenues
$
1,869

 
$
1,748

 
$
4,225

 
$
3,409

 
 
 
 
 
 
 
 
CONSOLIDATED NET LOSS:
 
 
 
 
 
 
 
NP
$
(14
)
 
$
(194
)
 
$
(576
)
 
$
(466
)
MPA
(1,626
)
 
(5,073
)
 
(2,717
)
 
(5,510
)
MPUK
(514
)
 
(621
)
 
(1,146
)
 
(2,007
)
Corporate
(2,143
)
 
(1,393
)
 
(4,689
)
 
(4,436
)
Inter-segment elimination
185

 
(4
)
 
181

 
(175
)
Consolidated net loss
$
(4,112
)
 
$
(7,285
)
 
$
(8,947
)
 
$
(12,594
)


15

Table of Contents

Note 11 - Oil and Gas Activities
The following table presents the capitalized costs under the successful efforts method for oil and gas properties as of:
 
December 31,
2013
 
June 30,
2013
 
(In thousands)
Proved oil and gas properties:
 
 
 
United States
$
28,039

 
$
27,606

Australia
7,833

 
7,771

Less accumulated depletion, depreciation, and amortization
(6,216
)
 
(5,814
)
Total net proved oil and gas properties
$
29,656

 
$
29,563

 
 
 
 
Unproved oil and gas properties:
 
 
 
United Kingdom
$
1,103

 
$
1,075

United States
269

 
261

Australia
3,866

 
3,976

Total unproved oil and gas properties
$
5,238

 
$
5,312

 
 
 
 
Wells in Progress:
 
 
 
United Kingdom
$
956

 
$
688

United States (1)
13,503

 
235

Total wells in progress
$
14,459

 
$
923

(1) The Company began implementing a CO2-enhanced oil recovery pilot project at NP in the first quarter of fiscal year 2014.

Note 12 - 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 4 - 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 8 - Stockholders' Equity. As a result, we have recorded a total liability of $1.5 million and $1.0 million as of December 31, 2013, 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 December 31, 2013, and June 30, 2013, respectively, under prepaid and other assets in the unaudited condensed consolidated balance sheets.

Note 13 - 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 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.

16

Table of Contents

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 has been completed. This transaction had no effect on the Company for the six months ended December 31, 2013.
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 six months ended December 31, 2013, was $2.2 million. As of December 31, 2013, there were no unpaid contract fees related to KES.
See Note 8 - Stockholders' Equity above for discussions of other transactions in which Mr. Bogachev had an interest and which was finalized as of January 2013.

Note 14 - Employee Severance Costs
The Company is required to record charges for one-time employee severance benefits and other associated costs as incurred. In July 2012, the Company incurred severance costs payable in connection with the termination of the employment of certain employees pursuant to the terms of their employment agreements. There were no employee related severance costs for the six months ended December 31, 2013. The Company does not expect any additional benefits or other associated costs related to these terminations. The liability related to these severance costs is included in the 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 six months ended December 31, 2013, is as follows:
 
Total
 
(In thousands)
June 30, 2013
$
418

Cash payments
(174
)
December 31, 2013
$
244



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

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto contained herein and in our 2013 Form 10-K and notes thereto, 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 development company primarily focused on the development of a CO2-enhanced oil recovery ("CO2-EOR") program at Poplar Dome ("Poplar") in eastern Montana. Historically active internationally, Magellan also maintains exposure to the UK and Australian oil and gas markets through the following assets: (i) a large, mostly non-operated acreage position onshore UK in the Weald and Wessex Basins prospective for unconventional shale oil and gas production; (ii) an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory, Australia, which the Company currently plans to farmout; and (iii) two gas fields, Palm Valley and Dingo, onshore Northern Territory, 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"), and Magellan Petroleum Australia Pty Ltd ("MPA").
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 December 31, 2013, totaled $1.9 million, compared to $1.7 million for the prior year period, an increase of 7%. This increase was primarily due to increased production at Poplar as a result of successful water shutoff treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014. We reduced our operating loss for the three months ended December 31, 2013, to $4.1 million, compared to an operating loss of $7.7 million for the prior year period. We also reduced our net loss for the three months ended December 31, 2013, to $4.1 million ($(0.10)/basic and diluted share), compared to a net loss of $7.3 million ($(0.14)/basic and diluted share) for the prior year period. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation below) was negative $2.3 million for the three months ended December 31, 2013, compared to negative $3.0 million in the prior year period, a positive change of 22.7%. For further information, please refer to the discussion below in this section under Comparison of Results between the Three and the Six Months Ended December 31, 2013, and 2012.

CORPORATE EVENTS
Marketing Process for Potential Sale of Palm Valley and Dingo Gas Fields
Following the signing of the previously reported Dingo gas supply and purchase agreement in September 2013 with Northern Territory Power and Water Corporation for the supply of up to 31 PJ (30 Bcf) of gas over a 20-year period, management believed that both Palm Valley's and Dingo's existing long-term gas sales contracts could provide a basis to fairly assess their value, and, as a result, management undertook an evaluation of strategic alternatives of these assets during the second quarter of fiscal year 2014. As part of

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this evaluation, the Company commenced a process to market and sell Palm Valley and Dingo. As a result of this process, the Company has been negotiating with a party for the potential sale of Palm Valley and Dingo, and the Company currently believes that it may be close to reaching an agreement for such sale. However, as of the date of this report, no definitive agreement has been reached, the process is still ongoing, and the process may or may not result in a sale of these two gas fields.

Stock Option Program
On October 15, 2013, the Company adopted a new stock option program (the "Program") under the 2012 Stock Incentive Plan and granted options to certain key employees of the Company to purchase up to a total of 3,000,000 shares of the Company's Common Stock at an exercise price of $1.03 per share, which was the NASDAQ closing price for the Common Stock on the grant date. The vesting of all grants under the Program is contingent upon the Company achieving certain performance milestones: fifty percent will vest and become exercisable if the Company achieves certain strategic objectives; and the remaining fifty percent will vest and become exercisable if the Company's Common Stock share price achieves $2.35 per share for a specified period of time, which price represents an increase of approximately 130% over the exercise price. These vesting targets are intended to align management with shareholders in driving net asset value and market price per share and preclude dilution from exercise in the event the objectives are not met. Pursuant to the Program, the Company granted options to Messrs. J. Thomas Wilson, the Company's President and Chief Executive Officer, Antoine J. Lafargue, the Company's Vice President - Chief Financial Officer and Treasurer, and C. Mark Brannum, the Company's Vice President - General Counsel & Secretary to purchase up to a total of 1,000,000 shares, 825,000 shares, and 825,000 shares, respectively, of Common Stock. Options to purchase up to an additional 350,000 shares of Common Stock were granted to certain other key employees.

HIGHLIGHTS OF OPERATIONAL ACTIVITIES
During the three months ended December 31, 2013, the Company progressed a number of initiatives for its operational assets to evaluate and determine the potential of its oil and gas 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 for significantly enhanced oil recovery through CO2-EOR techniques. 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 at Poplar in the first quarter of fiscal year 2014, which program will consist of five wells, including the CO2-injection well, and injecting CO2 over a two year period. Over the course of calendar year 2014, we will be monitoring the performance of the wells and the volumes of injected CO2 and regularly re-calibrating our reservoir model. We expect it will take approximately 12 months from the time of first injection to further ascertain the effectiveness of CO2-EOR techniques on a full field basis and the incremental volume of recoverable oil.
During the quarter ended December 31, 2013, the Company drilled to total depth the five CO2-EOR pilot wells, including the CO2 injector well. The four producing wells are designed to yield primary oil production from the Charles formation in addition to enhanced production as a result of the CO2-EOR. These wells are currently undergoing water shutoff treatments in preparation for the first CO2 injection, which is scheduled to occur in February 2014. As of December 31, 2013, the total cost of the pilot project, including capital and certain operating expenditures, which includes CO2 supply cost scheduled to occur over the next two years, is currently estimated at approximately $20.0 million.
Shallow Intervals. During the three months ended December 31, 2013, Magellan sold 21 Mbbls (228 bopd) of oil attributable to its net revenue interests in Poplar, compared to 17 Mbbls (185 bopd) of oil during the same period in 2012. This increase was primarily due to increased production at Poplar as a result of successful water shutoff treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014, which mitigated the natural production decline of the field.
During the period, Magellan remained focused on evaluating the potential of water shutoff and other treatments on Poplar's existing producing wells, which treatments are intended to increase oil production and reduce water production from wells with paybacks of less than 12 months. Most recently, the Company successfully completed a treatment on the EPU 6 well, which was producing marginal quantities of oil from the Charles C intervals prior to the treatment and is currently flowing at a rate of 45 bopd and 550 bwpd. Magellan has now concluded that water shut off treatments are more effective in the C intervals of the Charles formation than in the B intervals. As such, Magellan will continue these treatments on wells producing from the Charles C intervals at Poplar.

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Deep Intervals. During the three months ended December 31, 2013, there was minimal activity in the Deep Intervals at Poplar. However, the Company may elect to perform a water shutoff treatment at the EPU 125 well in the Nisku formation in the coming months.

United Kingdom
Going forward, the Company's primary objectives in the UK are to (i) receive drilling approval for a number of different sites in order to demonstrate that, assuming the prospect for producing commercial quantities of hydrocarbons is geologically and technically viable, access to drill sites is achievable within the existing regulatory framework and current social and environmental conditions; and (ii) establish the potential of its unconventional prospects, most of which lie within the licenses co-owned 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 we currently expect will be spud in or around the fourth quarter of fiscal year 2014.
Celtique Operated Licenses. Magellan co-owns equally with Celtique Petroleum Exploration and Development Licenses ("PEDLs") 231, 234, and 243, which overlay the center portion of the Weald Basin. The Weald Basin is prospective for unconventional oil and gas resources. During the three months ended December 31, 2013, Celtique and Magellan received a two-year extension of the drilling conditions of licenses from the UK Department of Energy and Climate Change ("DECC"), extending the "drill or drop" deadline to June 2016. Management believes this extension is a very valuable development, as it allows additional time for (i) the Company to drill and test the play, (ii) the applicable regulatory system to continue its favorable trajectory in allowing for responsible unconventional onshore development, and (iii) more companies to enter the play. During the period, Magellan and Celtique also advanced plans to drill a first exploratory well to be spud in the fourth quarter of fiscal year 2014 or the first quarter of fiscal year 2015, which will most likely be within the PEDL 234 license area. This well will primarily focus on a conventional Triassic prospect, and the expected net cost to the Company is estimated at approximately $5.0 million.
Magellan Operated Licenses. In the Weald Basin, Magellan owns a 100% interest in two licenses (PEDLs 137 and 246). These licenses expire in September 2014 and June 2015, respectively. During the quarter ended December 31, 2013, the Company executed a farmout of the Horse Hill prospect on PEDL 137 to Horse Hill Development Ltd ("HHDL"), a wholly owned subsidiary of Angus Energy ("Angus"), a privately-owned UK based exploration and development company. Pursuant to the terms of the farmout, HHDL is obligated to fund 100% of the cost of drilling a vertical exploratory well in order to earn a 65% working interest in the license. Drilling of this well is subject to obtaining final planning permission, and the well will target conventional oil plays in the Portland Sandstone and Corallian Limestone. Both of these plays are productive in nearby oil fields. The well will also target a new Triassic gas play identified on 2-D seismic data, which was reprocessed by the Company. In addition, the Company will have the opportunity to evaluate the Kimmeridge Clay and Liassic formations, which will contribute to the assessment of the potential of these formations in the Weald Basin. No hydraulic fracturing will be used in the completion of this well.
In February 2014, Angus entered into binding heads of agreement to sell 10% and 7.5% interests in HHDL to two separate third parties. These sales implied an equity valuation of HHDL of GBP £6.0 million, which, based on HHDL's right to earn a 65% working interest in PEDL 137, in turn imply a 100% equity valuation of PEDL 137 of GBP £9.2 million (approximately $15.0 million), or approximately $600 per acre. This valuation also implies a valuation of Magellan's 35% pro forma interest in the license of GBP £3.2 million (approximately $5.0 million).
This farmout is in line with the Company's UK strategy, which is to remain focused on its acreage in the center of the Weald Basin, which is contained in PEDLs 231, 234, and 243, while maintaining a non-operating interest to these more peripheral licenses at little or no incremental cost.
Northern Petroleum Operated Licenses. In the Weald and Wessex Basins, Magellan owns working interests of between 23% and 40% in five licenses operated by Northern Petroleum (PEDLs 126, 155, 240, 256, and P1916), which expire between June 2014 and January 2016. During the quarter ended December 31, 2013, the Company committed to fund in 2014 its share of a pre-drill study of a proposal to sidetrack the Markwells Wood-1 well in order to evaluate unconventional production prospects in the Oxford Clay and Liassic formations. The study will be carried out by Schlumberger, and, if the results are found to be encouraging, Magellan may participate in the sidetrack exploration/appraisal well. Magellan expects to incur up to approximately £80 thousand on this pre-drill study. Currently, there is no major work or expenditure scheduled on the other licenses Magellan co-owns with Northern.

Australia
Palm Valley. The Palm Valley gas field, which is operated by MPA, produced a gross average of approximately 0.6 MMcf/d of natural gas for sale for the three months ended December 31, 2013, compared to 0.7 MMcf/d during the same period in 2012. Gas volumes during the period were sold under the Palm Valley gas supply and purchase agreements ("GSPA") to Santos. Gas sales volumes under this contract are expected to ramp up based on currently scheduled contracts to approximately 3.3 MMcf/d by the third quarter of fiscal year 2014 and to approximately 4.1 MMcf/d by the fourth quarter of fiscal year 2015, at which point the field will be

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selling at its full deliverability capacity and generating revenues of approximately AUD $8.0 million per year.
Dingo. During September 2013, the Company signed the Dingo GSPA with Northern Territory Power and Water Corporation ("PWC") for the supply of up to 31 PJ (30 Bcf) of gas over a 20-year period, which supply is expected to commence early in calendar year 2015. With a long term contract now in place, the Company will use the intervening time period to design, construct, and commission the surface facilities and tie-in pipeline necessary for the production and delivery of Dingo's gas. Gas volumes are expected to be produced from three wells drilled at Dingo in the 1980s and 1990s, of which two wells have since been temporarily shut-in but are expected to be capable of producing gas volumes sufficient to meet the initial delivery requirements under the Dingo GSPA. The Company appointed GPA Engineering ("GPA") to undertake the front-end engineering and design ("FEED") of the facilities and pipeline, which is a continuation of work performed by GPA during the pre-FEED stage in fiscal year 2013. The FEED study was completed in January 2014. Based on the FEED study, the Company is planning to run Dingo as a remote operation, with only wellheads and gathering lines to be located at the field itself. Production from the wells will flow through a pipeline approximately 30 miles in length to a processing facility to be located at Brewer Estate, an industrial facility located just south of Alice Springs, where the gas will be processed and where PWC will take delivery of the gas.
Following the signing of the Dingo GSPA, management believed that both Palm Valley's and Dingo's long-term gas sales contracts could provide a basis to fairly assess their value, and, as a result, management undertook an evaluation of strategic alternatives of these assets during the second quarter of fiscal year 2014. As part of this evaluation, the Company commenced a process to market and sell Palm Valley and Dingo. As a result of this process, the Company has been negotiating with a party for the potential sale of Palm Valley and Dingo, and the Company currently believes that it may be close to reaching an agreement for such sale. However, as of the date of this report, no definitive agreement has been reached, the process is still ongoing, and the process may or may not result in a sale of these two gas fields.
NT/P82. During the three months ended December 31, 2013, the Company worked toward completing 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. In November 2013, the Company elected to run the seismic data through additional testing and review, at minor additional cost, in order to confirm the validity and integrity of the data and analysis. Although this has extended the expected date of finalization of interpretation to the third quarter of fiscal year 2014, the Company believes this additional analysis will allow it to successfully complete a farmout process on favorable terms before the end of fiscal year 2014. Based on the preliminary results of the interpretation of the 2-D and 3-D seismic surveys, the Company believes that two large prospects are present within our block.
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 by the fourth quarter of fiscal year 2015 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.

CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES
Historically, we funded our activities from cash from operations, assets sales, an issuance of preferred equity, and our existing cash balance. In the future the Company intends to fund the implementation of its strategy through existing cash balances and through a prioritization of assets, which may include farmouts and partial or total divestitures of some of the Company's international assets. Based on its existing cash position and the various alternative sources of funds generally available to the Company, including partial or complete sale of certain assets, farmout transactions, and issuance of debt or equity financings, the Company believes it has sufficient financial resources to fund its ongoing operations.

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 by the results of the CO2-EOR pilot project and results of water shutoff treatments. Until approximately December 2015, the Company intends to evaluate the potential of CO2-EOR in the Charles formation at Poplar. As of December 30, 2013, a five-well pilot, including one CO2 injector well and four producing wells has been drilled. Magellan expects to have incurred most of the approximately $20.0 million in estimated capital and certain operating expenditures by March 2014. As of December 2013, approximately 60% of the estimated costs of the CO2-EOR pilot project have been incurred, while approximately 20% of the estimated costs of the CO2-EOR pilot project are related to the injection of CO2, which is scheduled to occur over the next two years.

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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 and which represent 125 thousand out of the Company’s total of approximately 200 thousand net acres in the UK, have been extended to June 2016 and are subject to "drill-or-drop" obligations. In fiscal year 2014, the Company will focus on evaluating the potential of its unconventional prospects in these licenses. The Company expects to fund its share of the cost for an evaluation well expected to be spud within PEDL 234 during the fourth quarter of fiscal year 2014 or the first quarter of fiscal year 2015, of which the net cost to Magellan is estimated to be approximately $5.0 million, and which will meet the license obligations for both PEDLs 231 and 243. Pending the results of this well, the Company may participate in a second such evaluation well within these PEDLs in fiscal year 2015. The Company expects to fund these expenditures from either its cash balances, a farmout, the proceeds from non-core asset sales, or a combination thereof. The Company does not expect to incur further significant capital or exploratory expenditures on its other UK licenses 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 2015. Following the successful completion of seismic surveys over two prospects in the license area and the associated processing and interpretation, the Company currently plans to commence a farmout process in order 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.
At Palm Valley, the Company's interest in the field is governed by Petroleum Lease No. 3, which expires in November 2024 (and is subject to automatic renewal for another 21 years). The Company is not obligated to undertake significant mandatory capital expenditures in order to maintain its position in the lease. The Company's discretionary capital expenditure plans are primarily focused on maintaining gas production from the existing facilities in order to meet delivery obligations under its GSPA with Santos while maintaining a safe and efficient operation, conducted in accordance with good oil field practice.
At Dingo, the Company's interest in the field is governed by Retention License No. 2, which expires in February 2014 and is currently under application both for renewal as a retention license and conversion to a production license. Following the signing of the Dingo GSPA in September 2013, the Company has estimated that the cost to install surface facilities for production and processing of gas and to build a 30 mile pipeline connecting Dingo to existing pipeline infrastructure at Brewer Estate, south of Alice Springs, would total approximately $20.0 million. The Company is currently reviewing a number of alternatives related to the development of Dingo, including issuing project finance debt facilities, contracting out the construction of the pipeline to a third party on a build/own/operate ("BOO") basis, entering into a joint-venture or farmout agreement, selling the asset, or a combination thereof. If the Company is successful in its attempt to sell Palm Valley and Dingo, the Company will not incur the approximately $20.0 million in development costs for Dingo.

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.
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 December 31, 2013, $1.9 million remained authorized for stock repurchases under this program. See Issuer Purchases of Equity Securities under Part II, Item 2 of this report for additional information.

Sources of Funds
Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $12.2 million of cash and cash equivalents as of December 31, 2013, compared to $32.5 million as of June 30, 2013.
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 $1.0 million as of December 31, 2013, with the remaining $11.1 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 $8.8 million, and in Australia, cash equivalents were held in several time deposit accounts totaling $2.3 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 December 31, 2013, $2.5 million, or 21% 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 loss and foreign tax credit carry forwards available to the Company at that time.

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Existing Credit Facilities. A summary of the Company's existing credit facilities and borrowing base is as follows:
 
December 31,
2013
 
June 30,
2013
 
(In thousands)
Outstanding borrowings:
 
 
 
Term loan
$
174

 
$
390

Line of credit
51

 
51

Total
$
225

 
$
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 December 31, 2013, $0.1 million of the $1.0 million Line of Credit was drawn, $25 thousand secured a Line of Credit in favor of the Bureau of Land Management, $25 thousand secured business credit cards, and $0.9 million remained available to borrow. As of December 31, 2013, NP was in compliance with its financial covenants as set forth in 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 $0.2 million as of December 31, 2013.
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 of some of the Company's assets.

Cash Flows
The following table presents the Company's cash flow information for the six months ended:
 
December 31,
 
2013
 
2012
 
(In thousands)
Cash (used in) provided by:
 
 
 
Operating activities
$
(6,152
)
 
$
(9,014
)
Investing activities
(13,914
)
 
(1,070
)
Financing activities
(216
)
 
(266
)
Effect of exchange rate changes on cash and cash equivalents
(28
)
 
839

Net decrease in cash and cash equivalents
$
(20,310
)
 
$
(9,511
)
Cash used in operating activities during the six months ended December 31, 2013, was $6.2 million, compared to $9.0 million for the same period in 2012. The decrease in cash used in operating activities was primarily due to an increase in revenues of $0.8 million, and a decrease in general and administrative expenses of $1.1 million related to prior year employee severance costs, and accounting and consulting fees related to the prior year period. This decrease was partially offset by an increase in cash outflows related to our operating assets and liabilities.
Cash used in investing activities during the six months ended December 31, 2013, was $13.9 million, compared to $1.1 million for the same period in 2012. The increase in cash used in investing activities was primarily due to the capital expenditures related to the CO2-EOR pilot project at Poplar. For the six months ended December 31, 2013, the $13.9 million used in investing activities was primarily spent on the development of our assets, of which $11.9 million related to the CO2-EOR pilot project and $0.8 million related to water shutoff treatments at Poplar.
Cash used in financing activities during the six months ended December 31, 2013, was $0.2 million, compared to $0.3 million of cash used in financing activities for the same period in 2012. The decrease in cash used in financing activities for the six months ended December 31, 2013, related to the repurchase of common stock and long term debt repayments in the prior year period.
During the six months ended December 31, 2013, the effect of changes in foreign currency exchange rates negatively impacted the translation of our AUD denominated cash and cash equivalent balances into USD and resulted in a decrease of $28 thousand in cash and cash equivalents, compared to an increase of $0.8 million for the same period in 2012, 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) foreign transaction loss (gain), (v) impairment expense, (vi) loss (gain) on sale of assets, (vii) net interest expense (income), (viii) other expense (income), and (ix) income tax provision (benefit). Adjusted EBITDAX is not a measure of net income or cash flow as determined by accounting principles generally accepted in the United States ("GAAP") and excludes certain items that we believe affect the comparability of operating results.
Our Adjusted EBITDAX measure provides additional information 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,

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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.
The following table provides a reconciliation of net loss to Adjusted EBITDAX for the periods ended:
 
THREE MONTHS ENDED
 
SIX MONTHS ENDED
 
December 31,
 
December 31,
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
LOSS AFTER INCOME TAX
$
(4,112
)
 
$
(7,285
)
 
$
(8,947
)
 
$
(12,594
)
Depletion, depreciation, amortization, and accretion expense
598

 
332

 
907

 
649

Exploration expense
728

 
4,094

 
1,657

 
4,716

Stock based compensation expense
406

 
261

 
1,066

 
606

Foreign transaction (gain) loss
(5
)
 
36

 
(26
)
 
36

Impairment expense

 

 

 
890

Loss on sale of assets
33

 

 
95

 

Net interest income
(23
)
 
(258
)
 
(43
)
 
(479
)
Other expense (income)
45

 
127

 
105

 
112

Income tax benefit

 
(321
)
 

 
(658
)
Adjusted EBITDAX
$
(2,330
)
 
$
(3,014
)
 
$
(5,186
)
 
$
(6,722
)
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 (i) stock based compensation expense and (ii) foreign transaction (gain) loss.
The following table provides the alternative method for calculating Adjusted EBITDAX for the periods ended:
 
THREE MONTHS ENDED
 
SIX MONTHS ENDED
 
December 31,
 
December 31,
 
2013
 
2012
 
2013
 
2012
 
(In thousands)
Total revenues
$
1,869

 
$
1,748

 
$
4,225

 
$
3,409

Less:
 
 
 
 
 
 
 
Lease operating
(1,718
)
 
(1,665
)
 
(4,474
)
 
(3,716
)
General and administrative
(2,882
)
 
(3,394
)
 
(5,977
)
 
(7,057
)
Plus:
 
 
 
 
 
 
 
Stock based compensation expense
406

 
261

 
1,066

 
606

Foreign transaction (gain) loss
(5
)
 
36

 
(26
)
 
36

Adjusted EBITDAX
$
(2,330
)
 
$
(3,014
)
 
$
(5,186
)
 
$
(6,722
)


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COMPARISON OF RESULTS BETWEEN THE THREE MONTHS ENDED DECEMBER 31, 2013, AND 2012
Oil and Gas Sales Volume
The following table presents oil and gas sales volumes for the three months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Net sales by field:
 
 
 
 
 
 
 
Poplar (Mbbls)
21

 
17

 
4

 
24
 %
Palm Valley gas (MMcf)
53

 
62

 
(9
)
 
(15
)%
 
 
 
 
 
 
 
 
Net sales by product:
 
 
 
 
 
 
 
Oil (Mbbls)
21

 
17

 
4

 
24
 %
Gas (MMcf)
53

 
62

 
(9
)
 
(15
)%
 
 
 
 
 
 
 
 
Consolidated sales (Mboe)
30

 
28

 
2

 
7
 %
Consolidated sales (boepd)
322

 
302

 
20

 
7
 %
Sales volume for the three months ended December 31, 2013, totaled 30 Mboe (322 boepd), compared to 28 Mboe (302 boepd) sold in same period in the prior year, an increase of 7%. Sales volume by product for the three months ended December 31, 2013, was 70% oil and 30% gas, compared to 63% oil and 37% gas in same period in the prior year. At Poplar, the increase in production was primarily the result of increased production from water shutoff treatments and workovers on EPU 55, EPU 42, and EPU 104. At Palm Valley, the decrease in gas volumes produced was attributable to reduced customer demand. Gas sales volumes are now being sold pursuant to the Palm Valley GSPA and are expected to ramp up based on currently scheduled nominations to approximately 3.3 MMcf/d by the third quarter of fiscal year 2014 and to approximately 4.1 MMcf/d by the fourth quarter of fiscal year 2015, at which point the field will be producing at its full deliverability capacity.

Oil and Gas Prices
The following table presents the average realized oil and gas prices for the three months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Average realized price:
 
 
 
 
 
 
 
Poplar (USD/bbl)
$79.27
 
$82.53
 
$(3.26)
 
(4
)%
Palm Valley (AUD/Mcf)
$4.86
 
$4.78
 
$0.08
 
2
 %
Consolidated (USD/boe)
$63.54
 
$62.99
 
$0.55
 
1
 %
The average realized price for the three months ended December 31, 2013, was $64/boe compared to $63/boe in the same period in the prior year, an increase of 1%. At present, the Company does not engage in any oil and gas hedging activities. Relative to the same period in the prior year, the average realized price from oil sales at Poplar decreased by 4% primarily as a result of declining differentials relative to the benchmark pricing (WTI) realized at that field. The average realized gas price from Palm Valley increased by 2% primarily as a result of CPI escalation allowed under the Palm Valley Gas Sales Agreement with Santos and the related concession gas sales agreements.


24

Table of Contents

Revenues
The following table presents revenues for the three months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Consolidated net revenue by source (USD):
 
 
 
 
 
 
 
Poplar
$
1,632

 
$
1,442

 
$
190

 
13
 %
Palm Valley
237

 
306

 
(69
)
 
(23
)%
Total
$
1,869

 
$
1,748

 
$
121

 
7
 %
 
 
 
 
 
 
 
 
MPA net revenue by source (AUD):
 
 
 
 
 
 
 
Palm Valley
$
257

 
$
295

 
$
(38
)
 
(13
)%
Total
$
257

 
$
295

 
$
(38
)
 
(13
)%
 
 
 
 
 
 
 
 
Consolidated net revenues by type (USD):
 
 
 
 
 
 
 
Oil
$
1,632

 
$
1,442

 
$
190

 
13
 %
Gas
237

 
306

 
(69
)
 
(23
)%
Total
$
1,869

 
$
1,748

 
$
121

 
7
 %
Revenues for the three months ended December 31, 2013, totaled $1.9 million, compared to $1.7 million in the prior year period, an increase of 7%. The $0.1 million increase in revenue was primarily due to the increased production from the Poplar field.

Operating and Other Expenses
The following table presents operating expenses for the three months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Selected operating expenses (USD):
 
 
 
 
 
 
 
Lease operating
$
1,718

 
$
1,665

 
$
53

 
3
 %
Depletion, depreciation, amortization, and accretion
$
598

 
$
332

 
$
266

 
80
 %
Exploration
$
728

 
$
4,094

 
$
(3,366
)
 
(82
)%
General and administrative
$
2,882

 
$
3,394

 
$
(512
)
 
(15
)%
 
 
 
 
 
 
 
 
Selected operating expenses (USD/boe):
 
 
 
 
 
 
 
Lease operating
$56
 
$60
 
$(4)
 
(7
)%
Depletion, depreciation, amortization, and accretion
$20
 
$12
 
$8
 
67
 %
Exploration
$24
 
$148
 
$(124)
 
(84
)%
General and administrative
$95
 
$122
 
$(27)
 
(22
)%
Lease Operating Expenses. Lease operating expenses remained relatively constant between the periods and increased $0.1 million to $1.7 million, or $56/boe, during the three months ended December 31, 2013.

25

Table of Contents

Depletion, Depreciation, Amortization, and Accretion. The following table presents depletion, depreciation, amortization, and accretion for the three months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Depreciation and amortization
$
64

 
$
168

 
$
(104
)
 
(62
)%
Depletion
425

 
124

 
301

 
243
 %
ARO accretion
109

 
40

 
69

 
173
 %
Total
$
598

 
$
332

 
$
266

 
80
 %
Depletion, depreciation, amortization, and accretion expenses increased $266 thousand to $598 thousand, or $20/boe, during the three months ended December 31, 2013. 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 $3.4 million to $0.7 million, or $24/boe, during the three months ended December 31, 2013. The $3.4 million decrease primarily related to expenditures for acquiring and interpreting MPA's 2-D and 3-D seismic data acquired over NT/P82 in the Bonaparte Basin, offshore Australia during the three months ended December 31, 2012.
General and Administrative Expenses. The following table presents general and administrative expenses for the three months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
General and administrative (excluding stock based compensation and foreign transaction (gain) loss)
$
2,481

 
$
3,097

 
$
(616
)
 
(20
)%
Stock compensation expense
406

 
261

 
145

 
56
 %
Foreign transaction (gain) loss
(5
)
 
36

 
(41
)
 
(114
)%
Total
$
2,882

 
$
3,394

 
$
(512
)
 
(15
)%
General and administrative expenses for the three months ended December 31, 2013, decreased by $0.5 million relative to the prior year period. General and administrative expenses, excluding stock based compensation and foreign transaction (gain)/loss, decreased by $0.6 million to $2.5 million, or $82/boe during the three months ended December 31, 2013. This decrease is primarily the result of a decrease in IRS penalties, travel and entertainment, legal expenses and general office expenses relative to the same period in the prior year. The increase in non-cash stock based compensation is primarily related to the recent issuance of equity based compensation awards to officers and employees pursuant to the Company's 2012 Stock Incentive Plan.


26

Table of Contents

COMPARISON OF RESULTS BETWEEN THE SIX MONTHS ENDED DECEMBER 31, 2013, AND 2012
Oil and Gas Sales Volume
The following table presents oil and gas sales volumes for the six months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Net sales by field:
 
 
 
 
 
 
 
Poplar (Mbbls)
43

 
36

 
7

 
19
%
Palm Valley (MMcf)
103

 
102

 
1

 
1
%
 
 
 
 
 
 
 
 
Net sales by product:
 
 
 
 
 
 
 
Oil (Mbbls)
43

 
36

 
7

 
19
%
Gas (MMcf)
103

 
102

 
1

 
1
%
 
 
 
 
 
 
 
 
Consolidated sales (Mboe)
61

 
53

 
8

 
15
%
Consolidated sales (boepd)
330

 
288

 
42

 
15
%
Sales volume for the six months ended December 31, 2013, totaled 61 Mboe (330 boepd), compared to 53 Mboe (288 boepd) sold in the prior year period, an increase of 15%. Sales volume by product for the six months ended December 31, 2013, was 71% oil and 29% gas, compared to 68% oil and 32% gas for the same period in the prior year. At Poplar, increased production was attributable to successful water shutoff treatments on the EPU 42, EPU 55, and EPU 104 wells. At Palm Valley, the increase in gas volumes produced is attributable to volumes sold under the Palm Valley GSPA, which was in effect in both the current and prior year periods. Gas sales volumes pursuant to this contract are expected to ramp up based on currently scheduled nominations to approximately 3.3 MMcf/d by the third quarter of fiscal year 2014 and to approximately 4.1 MMcf/d by the fourth quarter of fiscal year 2015, at which point the field will be producing at its full deliverability capacity.

Oil and Gas Prices
The following table presents the average realized oil and gas prices for the six months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Average realized price (1):
 
 
 
 
 
 
 
Poplar (USD/bbl)
$87.36
 
$80.82
 
$6.54
 
8
%
Palm Valley (AUD/Mcf)
$4.80
 
$4.77
 
$0.03
 
1
%
Consolidated (USD/boe)
$69.99
 
$64.37
 
$5.62
 
9
%
(1) Prices per bbl or per Mcf are reported net of royalties.
The average realized price for the six months ended December 31, 2013, was $70/boe compared to $64/boe in the prior year period, an increase of 9%. At present, the Company does not engage in any oil and gas hedging activities. Relative to the prior year period, the average realized price from oil sales at Poplar increased by 8% as a result of increased benchmark pricing (WTI) and slightly improved differentials relative to the benchmark pricing (WTI) realized at the field.The average realized gas price from Palm Valley remained relatively constant between the periods.


27

Table of Contents

Revenues
The following table presents revenues for the six months ended:
 
December 31,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Consolidated net revenue by source (USD):
 
 
 
 
 
 
 
Poplar
$
3,767

 
$
2,902

 
$
865

 
30
 %
Palm Valley
458

 
507

 
(49
)
 
(10
)%
Total
$
4,225

 
$
3,409