MPET 2013-09-30 10Q

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

FORM 10-Q

(MARK ONE)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 November 6, 2013 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)
 
September 30,
2013
 
June 30,
2013
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
27,003

 
$
32,469

Accounts receivable — trade
1,098

 
794

Accounts receivable — working interest partners
78

 
58

Inventories
550

 
555

Prepaid and other assets
1,335

 
1,422

Total current assets
30,064

 
35,298

 
 
 
 
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
 
 
 
Proved oil and gas properties
36,256

 
35,377

Less accumulated depletion, depreciation, and amortization
(5,955
)
 
(5,814
)
Unproved oil and gas properties
5,119

 
5,312

Wells in progress
7,929

 
923

Land, buildings, and equipment (net of accumulated depreciation of $1,879 and $1,810 as of September 30, 2013, and June 30, 2013, respectively)
1,277

 
1,382

Net property and equipment
44,626

 
37,180

 
 
 
 
OTHER NON-CURRENT ASSETS:
 
 
 
Goodwill
2,174

 
2,174

Deferred income taxes
7,217

 
7,217

Other long term assets
267

 
403

Total other non-current assets
9,658

 
9,794

Total assets
$
84,348

 
$
82,272

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Short term line of credit
$
551

 
$
51

Current portion of note payable
282

 
390

Current portion of asset retirement obligations
483

 
476

Accounts payable
7,390

 
1,948

Accrued and other liabilities
2,721

 
2,757

Accrued dividends
—

 
202

Total current liabilities
11,427

 
5,824

 
 
 
 
LONG TERM LIABILITIES:
 
 
 
Asset retirement obligations
6,604

 
6,403

Contingent consideration payable
4,017

 
3,940

Other long term liabilities
151

 
163

Total long term liabilities
10,772

 
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 19,743,917 and 19,239,734 as of September 30, 2013, and June 30, 2013, respectively; liquidation preference of $27,735 and $27,227, respectively
24,119

 
23,502

Total preferred stock
24,119

 
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 September 30, 2013, and June 30, 2013, respectively
540

 
540

Treasury stock (at cost): 9,425,114 and 9,414,176 shares as of September 30, 2013, and June 30, 2013, respectively
(9,344
)
 
(9,333
)
Capital in excess of par value
91,443

 
90,786

Accumulated deficit
(55,329
)
 
(50,079
)
Accumulated other comprehensive income
10,720

 
10,526

Total equity attributable to Magellan Petroleum Corporation
38,030

 
42,440

Total liabilities, preferred stock and equity
$
84,348

 
$
82,272

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

1
Table of Contents

MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands, except share and per share amounts)
 
THREE MONTHS ENDED
 
September 30,
 
2013
 
2012
REVENUES:
 
 
 
Oil production
$
2,134

 
$
1,460

Gas production
221

 
200

Total revenues
2,355

 
1,660

 
 
 
 
OPERATING EXPENSES:
 
 
 
Lease operating
2,756

 
2,051

Depletion, depreciation, amortization, and accretion
309

 
316

Exploration
929

 
622

General and administrative
3,095

 
3,663

Impairment
—

 
890

Loss on sale of assets
61

 
—

Total operating expenses
7,150

 
7,542

 
 
 
 
LOSS FROM OPERATIONS
(4,795
)
 
(5,882
)
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
Net interest income
20

 
221

Other (expense) income
(60
)
 
15

Total other (expense) income
(40
)
 
236

 
 
 
 
LOSS BEFORE INCOME TAX
(4,835
)
 
(5,646
)
Income tax benefit
—

 
336

LOSS AFTER INCOME TAX
(4,835
)
 
(5,310
)
Preferred stock dividend
(415
)
 
—

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(5,250
)
 
$
(5,310
)
 
 
 
 
Earnings per common share (Note 9):
 
 
 
Weighted average number of basic and diluted shares outstanding
45,348,840

 
53,849,181

Net loss per basic and diluted share outstanding
$(0.12)
 
$(0.10)
The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

2
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MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
(In thousands)
 
THREE MONTHS ENDED
 
September 30,
 
2013
 
2012
LOSS AFTER INCOME TAX
$
(4,835
)
 
$
(5,310
)
Foreign currency translation adjustments
171

 
941

Unrealized holding gain (loss) on securities available for sale, net of deferred tax of $0
23

 
(22
)
Comprehensive loss attributable to Magellan Petroleum Corporation
$
(4,641
)
 
$
(4,391
)
The notes to the condensed consolidated financial statements (unaudited) are an integral part of these financial statements.

3
Table of Contents

MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED)
(In thousands, 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
—

 
—

 
—

 
(4,835
)
 
—

 
$
(4,835
)
Foreign currency translation adjustments
—

 
—

 
—

 
—

 
171

 
$
171

Unrealized holding gain on securities available for sale, net of taxes
—

 
—

 
—

 
—

 
23

 
$
23

Stock and stock based compensation
—

 
—

 
657

 
—

 
—

 
$
657

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

 
(11
)
 
—

 
—

 
—

 
$
(11
)
Preferred stock dividend
—

 
—

 
—

 
(415
)
 
—

 
$
(415
)
September 30, 2013
$
540

 
$
(9,344
)
 
$
91,443

 
$
(55,329
)
 
$
10,720

 
$
38,030

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

4
Table of Contents

MAGELLAN PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
 
THREE MONTHS ENDED
 
September 30,
 
2013
 
2012
OPERATING ACTIVITIES:
 
 
 
LOSS AFTER INCOME TAX
$
(4,835
)
 
$
(5,310
)
Adjustments to reconcile net loss to net cash used in operating activities:
 
 
 
Foreign transaction gain
(21
)
 
—

Depletion, depreciation, amortization, and accretion
309

 
316

Fair value increase of contingent consideration payable
77

 
80

Deferred income taxes
—

 
(336
)
Loss on disposal of assets
61

 
—

Stock based compensation
657

 
346

Impairment loss
—

 
890

Severance benefit costs
—

 
780

Net changes in operating assets and liabilities:
 
 
 
Accounts receivable
(169
)
 
143

Inventories
6

 
57

Prepayments and other current assets
89

 
255

Accounts payable and accrued liabilities
1,005

 
(871
)
Other long term liabilities
(13
)
 
—

Net cash used in operating activities
(2,834
)
 
(3,650
)
 
 
 
 
INVESTING ACTIVITIES:
 
 
 
Additions to property and equipment
(3,139
)
 
(385
)
Proceeds from sale of assets
29

 
—

Net cash used in investing activities
(3,110
)
 
(385
)
 
 
 
 
FINANCING ACTIVITIES:
 
 
 
Short term debt issuances
500

 
550

Short term debt repayments
(108
)
 
(500
)
Long term debt repayments
—

 
(132
)
Net cash provided by (used in) financing activities
392

 
(82
)
Effect of exchange rate changes on cash and cash equivalents
86

 
841

Net decrease in cash and cash equivalents
(5,466
)
 
(3,276
)
Cash and cash equivalents at beginning of period
32,469

 
41,215

CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
27,003

 
$
37,939

 
 
 
 
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
4,590

 
236

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

5
Table of Contents

ITEM 1 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 - Basis of Presentation
Description of Operations
Magellan Petroleum Corporation (the "Company" or "Magellan" or "we" or "us") is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. The Company conducts its operations through three wholly owned subsidiaries: Nautilus Poplar LLC ("NP"), which owns and operates an oil field covering the Poplar Dome ("Poplar") located in the Williston Basin in eastern Montana; Magellan Petroleum Australia Pty Ltd ("MPA"), which owns and operates gas fields in Australia; and Magellan Petroleum (UK) Limited ("MPUK"), which owns a large acreage position in the Weald and Wessex Basins in southern England for prospective conventional and unconventional oil and gas production.

Basis of Presentation
The accompanying unaudited condensed consolidated financial statements include the accounts of Magellan and its wholly owned subsidiaries, NP, MPA and MPUK, and have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim financial information and in accordance with the instructions to Form 10-Q and Rule 8-03 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete 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 three months ended September 30, 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.

Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. GAAP requires goodwill to be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. We perform an annual assessment of qualitative factors for our impairment test. The qualitative factors used in our assessment include macroeconomic conditions, industry and market conditions, cost factors, and overall financial performance. Management performs interim assessments of goodwill if impairment indicators are present. For the three months ended September 30, 2013, no events or circumstances were identified that would indicate that a goodwill impairment has occurred.


6
Table of Contents

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

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, MPA, and MPUK, 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, MPA, and MPUK. 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 September 30, 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 September 30, 2013, and June 30, 2013, consisted of the following:
 
September 30,
2013
 
June 30,
2013
 
(In thousands)
Note Payable
$
282

 
$
390

Less current portion of Note Payable
(282
)
 
(390
)
Long term Note Payable
$
—

 
$
—


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Table of Contents

As of September 30, 2013, the minimum future principal maturities of the Note Payable were as follows:
 
Total
 
(In thousands)
One year
$
282

Total
$
282

The variable 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 September 30, 2013, resulting in an interest rate of 6.25% per annum as of September 30, 2013. Under the Note Payable, NP is subject to certain customary financial and restrictive covenants. As of September 30, 2013, NP was in compliance with all financial and restrictive covenants.
In addition, the Company has a $1.0 million working capital line of credit classified as short term debt (the "Line of Credit"). The amount due on the Line of Credit was $0.6 million and $51 thousand as of September 30, 2013, and June 30, 2013, respectively. The Line of Credit bears interest at a variable rate, which was 6.25% as of September 30, 2013. This Line of Credit also secures a letter of credit in the amount of $25 thousand in favor of the Bureau of Land Management. As of September 30, 2013, $0.4 million was available under this Line of Credit.
The Note Payable and Line of Credit are collateralized by a first mortgage and an assignment of production from Poplar and are guaranteed by Magellan up to $6.0 million, not to exceed the amount of the principal owed. The carrying amount of the Company's long term debt approximates its fair value, due to its variable interest rate, which resets based on the market rates.

Note 3 - Asset Retirement Obligations
The estimated valuation of asset retirement obligations ("AROs") is based on management's historical experience and best estimate of plugging and abandonment costs by field. Assumptions and judgments made by management when assessing an ARO include: (i) the existence of a legal obligation; (ii) estimated probabilities, amounts, and timing of settlements; (iii) the credit-adjusted risk-free rate to be used; and (iv) inflation rates. Accretion expense is recorded under depletion, depreciation, amortization, and accretion in the unaudited condensed consolidated statements of operations. If the fair value of a recorded ARO changes, a revision is recorded to both the ARO and the asset retirement capitalized cost.
The following table summarizes the ARO activity for the three months ended September 30, 2013:
 
Total
 
(In thousands)
Fiscal year opening balance

$
6,879

Liabilities incurred
7

Accretion expense
110

Effect of exchange rate changes
91

September 30, 2013
7,087

Less current asset retirement obligation
483

Long term asset retirement obligation
$
6,604


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. A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:
•
Level 1: Quoted prices in active markets for identical assets.
•
Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•
Level 3: Significant inputs to the valuation model are unobservable inputs.

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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 for all periods presented. During the three months ended September 30, 2013, and 2012, there have been no transfers in and/or out of Level 1, Level 2, or Level 3.

Assets and liabilities measured on a recurring basis
The Company's financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable, are carried at cost, which approximates fair value due to the short term maturity of these instruments. The recorded value of the Line of Credit and Note Payable (see Note 2 - Debt) approximates fair value due to their variable rate structure. The Company's other financial and non-financial assets and liabilities measured on a recurring basis are measured and reported at fair value.

The following table presents items required to be measured at fair value on a recurring basis by the level in which they are classified within the valuation hierarchy as follows:
 
September 30, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Cash equivalents (1)
$
25,647

 
$
—

 
$
—

 
$
25,647

Securities available for sale (2)
67

 
—

 
—

 
67

 
$
25,714

 
$
—

 
$
—

 
$
25,714

Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable (3)
$
—

 
$
—

 
$
4,017

 
$
4,017

 
 
 
 
 
 
 
 
 
June 30, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(In thousands)
Assets:
 
 
 
 
 
 
 
Cash equivalents (1)
$
26,270

 
$
—

 
$
—

 
$
26,270

Securities available for sale (2)
44

 
—

 
—

 
44

 
$
26,314

 
$
—

 
$
—

 
$
26,314

Liabilities:
 
 
 
 
 
 
 
Contingent consideration payable (3)
$
—

 
$
—

 
$
3,940

 
$
3,940

(1) Cash equivalents have maturities of 90 days or less. In the, US cash equivalents were held in US Treasury notes, and in Australia ,cash equivalents were held in several time deposit accounts.
(2) Included in the unaudited condensed consolidated balance sheets under prepaid and other assets.
(3) 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.

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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
 
September 30,
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
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 three months ended September 30, 2013:
 
Total
 
(In thousands)
Fiscal year beginning balance
$
3,940

Accretion of contingent consideration payable
77

September 30, 2013
$
4,017

Assets and liabilities measured on a nonrecurring basis
The Company also utilizes fair value to perform impairment tests as required on its oil and gas properties. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are also classified within Level 3.

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 three months ended September 30, 2013, and 2012, is 0% and 0%, 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 relates to the Australian Petroleum Resource Rent Tax as of September 30, 2013, until such time as we are able to determine it is "more-likely-than-not" those 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 replaces the Company's 1998 Stock Incentive Plan (the "1998 Stock Plan"). The 2012 Stock Incentive Plan provides for the granting of stock options, stock appreciation rights, restricted stock and/or restricted stock units, performance shares and/or performance units, incentive awards, cash awards, and other stock based awards to employees, including officers, directors, and consultants of the Company (or subsidiaries of the Company) who are selected 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 any remaining shares under the 1998 Stock Plan immediately before the effective date of the 2012 Stock Incentive Plan, which was 288,435 as of January 15, 2013. The maximum aggregate annual number of 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 is 500,000. The maximum term of the 2012 Stock Incentive Plan is ten years.


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Stock Option Grants
Under the 2012 Stock Incentive Plan, stock option grants may contain time based, performance based, or market based vesting provisions. As of September 30, 2013, all PBOs granted were fully vested and 3,335,107 shares, including forfeited shares, were available for future issuance. During the three months ended September 30, 2013, there were no stock options granted. Stock options outstanding have expiration dates ranging from January 16, 2014, to January 15, 2023. See Note 15 - Subsequent Events, for information about stock option grants made after September 30, 2013.
The following table summarizes the stock option activity for the three months ended September 30, 2013:
 
Number of
Shares
 
WAEPS (1)
Fiscal year opening balance
7,788,957

 
$1.33
Granted
—

 
$0.00
September 30, 2013
7,788,957

 
$1.33
 
 
 
 
Weighted average remaining contractual term
5.6

years
(1) Weighted average exercise price per share
The fair value of shares issued under the 2012 Stock Incentive Plan was estimated using the following weighted-average assumptions for the three months ended:
 
September 30,
 
2013
 
2012
Number of options
—
 
925,000
Weighted average grant date fair value per share
$0.00
 
$1.31
Expected dividend
0
 
0
Forfeiture rate
0
 
0
Risk free interest rate
—
%
-
—%
 
0.6
%
-
0.8%
Expected life (years)
0.00

-
0.00
 
5.13

-
6.00
Expected volatility (based on historical price)
—
%
-
—%
 
60.7
%
-
63.5%
Stock Compensation Expense
The Company recorded $0.7 million of related stock compensation expense for the three months ended September 30, 2013, and $0.3 million of related stock compensation expense for the three months ended September 30, 2012. Stock based compensation is included in general and administrative expense in the unaudited condensed consolidated statements of operations. As of September 30, 2013, the unrecorded expected future compensation expense related to stock option awards was $1.0 million. 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 September 30, 2013, the Company issued a total of 266,664 shares of its common stock to non-employee directors pursuant to this policy.

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 conversion price of $1.22149381 per share (the "Conversion Price").

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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. 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 as can be sold under Rule 144 under the US Securities Act of 1933, as amended (the "Securities Act").
•
Redemption. At any time after the third anniversary of the Closing Date, and upon 30 days prior written notice, the Company may elect to redeem all, but not less than all, shares of Series A Preferred Stock for an amount equal to the greater of (i) the closing sale price of the Common Stock on the date the Company delivers such notice multiplied by the number of shares of Common Stock issuable upon conversion of the outstanding Series A Preferred Stock, and (ii) a cash payment that, when considering all cash dividends already paid, allows 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 the Series A Preferred Stock is therefore 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.
•
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.

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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 issuance of the Series A Preferred Stock and has determined that none of the embedded features meets the requirements under US GAAP to be bifurcated from the Series A Preferred Stock contract and accounted for separately as a derivative. The Company also recorded the transaction by recognizing the fair value of the Series A Preferred Stock at the time of issuance in the amount of $23.5 million. The Company will accrete the Series A Preferred Stock to the redemption value when it becomes probable that an event or events underlying the redemption is probable.
For the three months ended September 30, 2013, the Company recorded $0.4 million in dividend expense related to the Series A Preferred Stock. The activity related to the Series A Preferred Stock for the three months ended September 30, 2013, is as follows:
 
Number of shares
 
Amount
 
(In thousands, except share amounts)
Fiscal year opening balance
19,239,734

 
$
23,502

PIK dividends issued for Series A Preferred Stock
504,183

 
617

Total Series A Preferred Stock
19,743,917

 
$
24,119


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 will be based on market and business conditions as well as other factors. The Company is not obligated to purchase any shares of its common stock. The authorization will expire on August 21, 2014, and purchases under the program can be discontinued at any time. During November 2012, the Company repurchased 149,539 shares pursuant to this program. As of September 30, 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 shares of common stock, and (iii) a Registration Rights Agreement, dated as of June 29, 2009, and amended as of October 14, 2009, and June 23, 2010, between the Company, Young Energy Prize S.A., a Luxembourg corporation ("YEP"), and ECP Fund, SICAV-FIS, a Luxembourg corporation ("ECP"), which is a subsidiary of Yamalco Investments Limited, a Cyprus company ("Yamalco"), for a purchase price of $10.0 million. The Company accounted for the 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 (refer below) for the shares of common stock purchased. The Collateral Agreement was subsequently amended on January 15, 2013, and completed on January 16, 2013. YEP, ECP, and Yamalco are entities affiliated with Nikolay V. Bogachev, a former director of the Company.

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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:
 
THREE MONTHS ENDED
 
FISCAL YEAR ENDED
 
September 30, 2013
 
June 30, 2013
 
Number of shares
 
Amount
 
Number of shares
 
Amount
 
(In thousands, except share and per 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; (ii) the exercise price of the warrant 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
 
September 30,
 
2013
 
2012
 
(In thousands, except share and per share amounts)
NET LOSS AFTER INCOME TAX
$
(4,835
)
 
$
(5,310
)
Preferred stock dividend
(415
)
 
—

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS
$
(5,250
)
 
$
(5,310
)
 
 
 
 
Basic weighted average shares outstanding
45,348,840

 
53,849,181

Net loss per basic and diluted share outstanding (1)
$(0.12)
 
$(0.10)
(1) There is no dilutive effect on earnings per share in periods with net losses.
Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following:
 
THREE MONTHS ENDED
 
September 30,
 
2013
 
2012
Stock options
157,500

 
75,000



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Note 10 - Segment Information
The Company conducts its operations through three wholly owned subsidiaries: NP, which operates in the US; MPA, which is primarily active in Australia, and MPUK, which includes our operations in the UK, as well as Corporate, which is treated as a cost center. The following table presents segment information as follows:
 
THREE MONTHS ENDED
 
September 30
 
2013
 
2012
 
(In thousands)
REVENUES:
 
 
 
NP
$
2,134

 
$
1,460

MPA
221

 
200

Consolidated revenues
$
2,355

 
$
1,660

 
 
 
 
CONSOLIDATED NET LOSS:
 
 
 
NP
$
(562
)
 
$
(272
)
MPA
(1,091
)
 
(437
)
MPUK
(632
)
 
(1,387
)
Corporate
(2,546
)
 
(3,043
)
Inter-segment elimination
(4
)
 
(171
)
Consolidated net loss
$
(4,835
)
 
$
(5,310
)

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:
 
September 30,
2013
 
June 30,
2013
 
(In thousands)
Proved oil and gas properties:
 
 
 
United States
$
28,039

 
$
27,606

Australia
8,217

 
7,771

Less accumulated depletion, depreciation, and amortization
(5,955
)
 
(5,814
)
Total net proved oil and gas properties
$
30,301

 
$
29,563

 
 
 
 
Unproved oil and gas properties:
 
 
 
United Kingdom
$
1,095

 
$
1,075

United States
269

 
261

Australia
3,755

 
3,976

Total unproved oil and gas properties
$
5,119

 
$
5,312

 
 
 
 
Wells in Progress:
 
 
 
United Kingdom
$
739

 
$
688

United States (1)
7,190

 
235

Total wells in progress
$
7,929

 
$
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.

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Table of Contents

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 $1.0 million of required US Federal tax withholdings related to the Collateral Agreement as described in Note 8 - Stockholders' Equity. As a result, as of both June 30, 2013, and September 30, 2013, we have recorded a total liability of $1.0 million 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 under prepaid and other assets in the unaudited condensed consolidated balance sheets of $1.0 million.

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.

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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 three months ended September 30, 2013.
See Note 8 - Stockholders' Equity above for discussions of other transactions in which Mr. Bogachev had an interest.

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 three months ended September 30, 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 three months ended September 30, 2013, is as follows:
 
Total
 
(In thousands)
June 30, 2013
$
418

Cash payments
(87
)
September 30, 2013
$
331


Note 15 - Subsequent Events
On October 15, 2013, the Company granted a total of 3,000,000 stock options under the 2012 Stock Incentive Plan, with the granted stock options containing both operational performance goal based and market price based vesting provisions. The exercise price for these options is $1.03 per share. The number of shares available for future issuance under the 2012 Stock Incentive Plan was consequently reduced to 335,107.


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Table of Contents

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, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the 2013 Form 10-K. Any 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 with assets in the US, Australia, and the UK. The Company is primarily focused on the development of a CO2-enhanced oil recovery ("CO2-EOR") program at Poplar Dome ("Poplar") in eastern Montana. Historically active in Australia, Magellan operates two gas fields in onshore Northern Territory, the Palm Valley and Dingo gas fields, and an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory. Magellan also owns a large acreage position onshore UK in the Weald and Wessex Basins prospective for unconventional shale oil and gas production.
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 Australia Pty Ltd ("MPA"), and Magellan Petroleum (UK) Limited ("MPUK").
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 September 30, 2013, totaled $2.4 million, compared to $1.7 million for the prior year period, an increase of 42%. This increase was primarily due to increased production at Poplar as a result of successful water shut-off treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014. We reduced our operating loss for the three months ended September 30, 2013, to $4.8 million, compared to an operating loss of $5.9 million for the prior year period. We also reduced our net loss for the three months ended September 30, 2013, to $4.8 million ($(0.12)/basic share), compared to a net loss of $5.3 million ($(0.10)/basic share) for the prior year period. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation below) was negative $2.9 million for the three months ended September 30, 2013, compared to negative $3.7 million in the prior year period, a positive change of 22.9%. For further information, please refer to the discussion below in this section under Comparison of Results between the Three Months Ended September 30, 2013, and 2012.

CORPORATE EVENTS
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,

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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 September 30, 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 reserve potential of this 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 drilling five wells 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 oil recoverable.
In July 2013, the Company signed an approximately two-year CO2 supply contract with Air Liquide for the CO2 necessary to complete the CO2-EOR pilot project. In August 2013, the Company obtained permits from the US Bureau of Land Management to drill the five wells necessary for the pilot project. Drilling began in August 2013 immediately following the receipt of the required permits and is expected to continue through November of this year. Currently, all five vertical wells have been spud with surface casing set, and four wells have been drilled to total depth of approximately 5,900 feet, including the CO2-injection well. CO2 injection is expected to commence toward the end of December 2013. The currently estimated cash cost of the pilot project, including capital and certain operating expenditures, including the cost of the supply of CO2 over two years, totals approximately $20.0 million, with most of these expenditures expected to be incurred by March 2014.
Shallow Intervals. During the three months ended September 30, 2013, Magellan sold 23 Mbbls (336 bopd) of oil attributable to its net revenue interests in Poplar, compared to 18 Mbbls (261 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 shut-off treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014, which mitigated the natural production decline of the field.
During the period, Magellan remained focused on evaluating the potential of water shut-off and other treatments on Poplar's existing producing wells, which treatments, in the cases of the EPU 42, EPU 55, and EPU 104 wells, have proven to increase oil production from a single well while significantly reducing water production, thereby reducing total and per barrel operating costs. The EPU 55, which currently produces on a 7/64ths choke to manage reservoir production and ultimate recovery from the field, is currently producing approximately 25 bopd with a 10% oil cut. The EPU 104 and EPU 42 wells currently produce approximately 30 bopd and 40 bopd with oil cuts of 8% and 5%, respectively. Each of these wells were uneconomic prior to the water shut-off treatments but are now considered economic and are reflected as such in our proved reserves as of June 30, 2013. The average payback period for these treatments ranges from 10 to 12 months. The effectiveness of water shut-off treatments on the EPU 34-11H and EPU 119 wells is still under evaluation. Based on the successful track record to date of these treatments, Magellan intends to continue its program of water shut-off treatments on additional wells at Poplar.
Deep Intervals. During the three months ended September 30, 2013, the Company progressed plans for a water shut-off treatment in the Nisku formation at Poplar via the EPU 125 well. This well, which the Company operates and in which the Company owns a 35% working interest, had been previously drilled by VAALCO Energy (USA), Inc. ("VAALCO") pursuant to the terms of a farm-out agreement executed in September 2011. Pursuant to the operating agreement with Magellan, VAALCO did not consent to the expenditure on the water shut-off treatment, VAALCO not participate in the revenue from this well until Magellan has recovered the costs of the water shut-of treatment and applicable penalty. Preparations for the well treatment have been initiated and completion is scheduled to occur in the fourth quarter of fiscal year 2014.

Australia
Palm Valley. The Palm Valley gas field, which is operated by MPA, produced a gross average of approximately 0.5 MMcf/d of natural gas for sale for the three months ended September 30, 2013, compared to 0.4 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

19
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selling at its full deliverability capacity and generating revenues of approximately AUD $8.0 million per year. Based on recent discussions, we expect that the sales ramp up will commence in early calendar year 2014.
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 has 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, and which is expected to take approximately six months to complete. Based on engineering and design work already done, 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.
Concurrently with the FEED work, the Company will be applying for various regulatory permits and licenses to allow for the commercial production and sale of gas from Dingo, including (i) the grant of a production license over the area of the current Dingo retention license, (ii) the grant of a pipeline license over the approximately 30-mile pipeline route connecting the Dingo field to Brewer Estate, and (iii) the grant of planning approval for the use of land at Brewer Estate for the installation and operation of gas processing facilities. The Company expects that it will take approximately twelve months to receive all required permits and licenses to be able to start the construction phase of the surface facilities and pipeline necessary to commission the production of gas from Dingo. We began preliminary permitting work in July 2013 and expect the construction phase of the project to commence in early fiscal year 2015.
The Company is currently exploring a number of alternatives related to the development of Dingo. We may fund the development of Dingo through the issuance of new project finance debt facilities, which would be serviced with cash flow generated by the Dingo GSPA once production commences; we may seek to find a third party to build and own the pipeline, which third party would in turn charge the Company a tariff for the use of the pipeline over the life of the Dingo GSPA; we may seek to find a strategic partner to finance a portion or all of the development costs of Dingo in exchange for a working interest in Dingo; or we may sell the Amadeus Basin assets consisting of the Palm Valley and Dingo gas fields and forgo any related development costs.
NT/P82. During the first quarter of fiscal year 2014, 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. 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. The Company expects to engage in a farmout process in late November 2013 to identify a partner experienced in offshore drilling and to close such a transaction before the end of fiscal year 2014. 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 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, the Company believes it is well positioned to successfully complete a farmout.

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 realities; 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 expect will be spud in or around the third 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 prospect for unconventional hydrocarbon resources and are subject to "drill or drop" rules by the end of June 2014 and a 50% relinquishment requirement to the extent that drilling obligations have been met by the term of the PEDLs. During the quarter ended September 30, 2013, Magellan, in conjunction with Celtique, completed extensive geological analysis of the Weald Basin and focused on securing and permitting various potential well site locations.
We and our partner, Celtique, expect that the drilling of one well located in PEDL 234 may qualify to meet our work commitments for both PEDLs 234 and 243. We expect this well will be spud in the third quarter of fiscal year 2014. In addition, we

20
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are in the process of permitting a well in PEDL 231 to fulfill our commitments for drilling in PEDL 231 and have applied for a 12-month extension to our current PEDL to allow additional time to receive planning approval. In PEDL 234, we are also awaiting final planning approval to drill a well in the center of the Weald Basin. The purpose of these wells is to test and evaluate the Kimmeridge Clay and Liassic formations in order to substantiate the unconventional oil production potential of our acreage and to test and evaluate the conventional potential of the Triassic formations. Under the terms of our joint operating agreement with Celtique, we are required to participate in certain commitment wells to maintain our working interest in the PEDLs.
On September 23, 2013, Cuadrilla Resources ("Cuadrilla"), a privately owned exploration and development company focused on unconventional oil and gas projects onshore UK, announced that it had successfully completed its first test well in the Weald Basin. This well, located in the village of Balcombe, offsets immediately to the east the acreage that the Company co-owns with Celtique. Cuadrilla drilled a 1,700 foot horizontal leg through the Kimmeridge Micrite, which is contained in the Kimmeridge Clay formation. We believe Cuadrilla is currently applying for regulatory approval to conduct a production test on this well. Magellan believes that Cuadrilla's success in permitting and drilling a well, as well as the results of their analyses and production testing, could serve to substantiate the value of the Company's acreage in the Weald Basin.
Northern Petroleum Operated Licenses. In the Weald and Wessex Basins, Magellan owns working interests of between 23% and 40% in five licenses operated by Northern Petroleum (PEDL 126, 155, 240,256, and P1916), which expire between June 2014 and January 2016. During the quarter ended September 30, 2013, the Company continued to evaluate the exploration options for its most recently acquired license, P1916, which lies offshore, west of the Isle of Wight, and PEDL 240, which is onshore and contiguous to P1916 and could provide a potential drilling site for the offshore prospect. P1916 is prospective for a Wytch Farm extension play.
Magellan Operated Licenses. In the Weald Basin, Magellan owns a 100% interest in two licenses (PEDL 137 and 246), both of which, following an extension to PEDL 137 and PEDL 246, expire in September 2014 and June 2015, respectively. During the quarter ended September 30, 2013, the Company actively pursued a farm-in partner for the drilling of an exploration well on the Horse Hill prospect in PEDL 137, for which the Company has obtained planning approval from the Surrey County Council. The Horse Hill well would be a vertical well and the planning approval does not allow the operator to use hydraulic fracturing technology in this well. This well would target conventional oil plays in the Portland Sandstone and Corrallian Limestone, which are productive in nearby oil fields, and 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 core and log the Kimmeridge Clay and Liassic formations, which will contribute to the assessment of the potential of these formations in the Weald Basin.

CONSOLIDATED LIQUIDITY AND CAPITAL RESOURCES
Historically, we have funded our activities from cash from operations and our existing cash balance. The Company has limited capital expenditure obligations pertaining to its leases and licenses, which allow for significant flexibility in the use of its capital resources. Based on its existing cash position, the Company believes it has sufficient financial resources to fund its ongoing operations and to finance its core project at Poplar, the CO2-EOR pilot project, which we believe will further establish the full value of this asset. Furthermore, offshore Australia and in the UK, the Company owns interests in large potential projects, which will require significant additional capital to reduce their inherent operational risk and increase their potential value. A possible funding strategy for these assets is to seek farm-in partners that will bear most of the costs of future operational milestones in exchange for working interests in these assets alongside Magellan. The Company may also seek to raise debt facilities to fund some of its projects, including the construction of surface facilities and a pipeline to tie the Dingo gas field to Brewer Estate in Northern Territory, Australia. Finally, Magellan intends to explore the potential sale of certain non-core assets that are more mature by the nature of their long term contracts and redeploy these proceeds in the Company's core assets, such as Poplar, which offer the potential to further increase the Company's net asset value per share.

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 shut-off treatments. In the first half of fiscal year 2014, the Company intends to evaluate the potential of CO2-EOR in the Charles formation at Poplar by drilling a five-well pilot, including one CO2 injector well and four producing wells. Magellan expects to incur most of the approximately $20.0 million in estimated capital and certain operating expenditures by March 2014. 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.
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

21
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resources and other strategic considerations, the Company may invest in re-completing a well in the Nisku formation.
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 subject to renewal for an additional 5 years). 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 the construction of the pipeline to a third party, entering into a joint-venture or farmout agreement, or selling the asset.
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 expects 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.
In the UK, the Company's interests are governed by various PEDLs and one Seaward Production License. The majority of these licenses expire in 2014, and all are subject to "drill-or-drop" obligations. In fiscal year 2014, the Company will focus on evaluating the potential of its unconventional prospects in the Weald Basin in southern England, which are contained within the license areas of PEDLs 231, 234, and 243, which the Company co-owns equally with Celtique. The Company expects to fund its share of the cost for an evaluation well expected to be spud within PEDL 234 during the third quarter of fiscal year 2014, of which the net cost to Magellan is estimated to be approximately $4.0 million. Pending the results of this well, the Company may participate in a second such evaluation well within these PEDLs toward the end of fiscal year 2014 or early in fiscal year 2015. The Company may seek a farmout partner to partially fund these expenditures or use the proceeds from other non-core asset sales. The Company does not expect to incur further significant capital or exploratory expenditures on its other UK licenses in fiscal year 2014.
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 September 30, 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 $27.0 million of cash and cash equivalents as of September 30, 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 $1.4 million as of September 30, 2013, with the remaining $25.6 million held in cash equivalents with maturities of 90 days or less. In the US cash equivalents were held in US Treasury notes and totaled $22.0 million, and in Australia cash equivalents were held in several time deposit accounts totaling $3.6 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 September 30, 2013, $3.9 million, or 15% 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 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:
 
September 30,
2013
 
June 30,
2013
 
(In thousands)
Outstanding borrowings:
 
 
 
Term loan
$
282

 
$
390

Line of credit
551

 
51

Total
$
833

 
$
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 September 30, 2013, $0.6 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, and $0.4 million remained available to borrow. As of September 30, 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 $0.8 million as of September 30, 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 three months ended:
 
September 30,
 
2013
 
2012
 
(In thousands)
Cash (used in) provided by:
 
 
 
Operating activities
$
(2,834
)
 
$
(3,650
)
Investing activities
(3,110
)
 
(385
)
Financing activities
392

 
(82
)
Effect of exchange rate changes on cash and cash equivalents
86

 
841

Net decrease in cash and cash equivalents
$
(5,466
)
 
$
(3,276
)
Cash used in operating activities during the three months ended September 30, 2013, was $2.8 million, compared to $3.7 million for the same period in 2012. The decrease in cash used in operating activities was primarily due to an increase in revenues of $0.7 million, partially offset by an increase in cash outflows related to our operating assets and liabilities.
Cash used in investing activities during the three months ended September 30, 2013, was $3.1 million, compared to $0.4 million for the same period in 2012. The increase in cash used in investing activities was primarily due to the expenditures related to the CO2-EOR pilot project at Poplar. For the three months ended September 30, 2013, the $3.1 million used in investing activities was primarily spent on the development of our assets, of which $2.7 million related to the CO2-EOR pilot project and $0.4 million related to water shut-off treatments at Poplar.
Cash provided by financing activities during the three months ended September 30, 2013, was $0.4 million, compared to $0.1 million of cash used in financing activities for the same period in 2012. The increase in cash provided by financing activities for the three months ended September 30, 2013, related to short term debt issuances and repayments.
During the three months ended September 30, 2013, the effect of changes in foreign currency exchange rates positively impacted the translation of our AUD denominated cash and cash equivalent balances into USD and resulted in an increase of $0.1 million in cash and cash equivalents, compared to an increase of $0.8 million for the same period in 2012.


23
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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, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure and to assess the financial performance of our assets and our company without regard to historical cost basis and items affecting the comparability of period to period operating results.
The following table provides a reconciliation of net loss to Adjusted EBITDAX for the periods ended:
 
THREE MONTHS ENDED
 
September 30,
 
2013
 
2012
 
(In thousands)
LOSS AFTER INCOME TAX
$
(4,835
)
 
$
(5,310
)
Depletion, depreciation, amortization, and accretion expense
309

 
316

Exploration expense
929

 
622

Stock based compensation expense
657

 
346

Foreign transaction gain
(21
)
 
—

Impairment expense
—

 
890

Loss on sale of assets
61

 
—

Net interest income
(20
)
 
(221
)
Other expense (income)
60

 
(15
)
Income tax benefit
—

 
(336
)
Adjusted EBITDAX
$
(2,860
)
 
$
(3,708
)
For clarification purposes, the below tables 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.

24
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The following table provides the alternative method for calculating Adjusted EBITDAX for the periods ended:
 
THREE MONTHS ENDED
 
September 30,
 
2013
 
2012
 
(In thousands)
Total revenues
$
2,355

 
$
1,660

Less:
 
 
 
Lease operating
(2,756
)
 
(2,051
)
General and administrative
(3,095
)
 
(3,663
)
Plus:
 
 
 
Stock based compensation expense
657

 
346

Foreign transaction gain
(21
)
 
—

Adjusted EBITDAX
$
(2,860
)
 
$
(3,708
)

COMPARISON OF RESULTS BETWEEN THE THREE MONTHS ENDED SEPTEMBER 30, 2013, AND 2012
Oil and Gas Sales Volume
The following table presents oil and gas sales volumes for the three months ended:
 
September 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Net sales by field:
 
 
 
 
 
 
 
Poplar (Mbbls)
23

 
18

 
5

 
28
%
Palm Valley (MMcf)
50

 
34

 
16

 
47
%
 
 
 
 
 
 
 
 
Net sales by product:
 
 
 
 
 
 
 
Oil (Mbbls)
23

 
18

 
5

 
28
%
Gas (MMcf)
50

 
34

 
16

 
47
%
 
 
 
 
 
 
 
 
Consolidated sales (Mboe)
31

 
24

 
7

 
29
%
Consolidated sales (boepd)
336

 
261

 
75

 
29
%
Sales volume for the three months ended September 30, 2013, totaled 31 Mboe (336 boepd), compared to 24 Mboe (261 boepd) sold in the prior year period, an increase of 29%. Sales volume by product for the three months ended September 30, 2013, was 73% oil and 27% gas, compared to 77% oil and 23% gas in the prior year period. At Poplar, increased production was attributable to successful water shut-off 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 selling at its full deliverability capacity.


25
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Oil and Gas Prices
The following table presents the average realized oil and gas prices for the three months ended:
 
September 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
Average realized price (1):
 
 
 
 
 
 
 
Poplar (USD/bbl)
$94.76
 
$79.19
 
$15.57
 
20
%
Palm Valley (AUD/Mcf)
$4.78
 
$4.76
 
$0.02
 
*

Consolidated (USD/boe)
$76.12
 
$69.11
 
$7.01
 
10
%
* Not meaningful
(1) Prices per bbl or per Mcf are reported net of royalties.
The average realized price for the three months ended September 30, 2013, was $76/boe compared to $69/boe in the prior year period, an increase of 10%. 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 20% 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.

Revenues
The following table presents revenues for the three months ended:
 
September 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Consolidated net revenue by source (USD):
 
 
 
 
 
 
 
Poplar
$
2,134

 
$
1,460

 
$
674

 
46
%
Palm Valley
221

 
200

 
21

 
11
%
Total
$
2,355

 
$
1,660

 
$
695

 
42
%
 
 
 
 
 
 
 
 
MPA net revenue by source (AUD):
 
 
 
 
 
 
 
Palm Valley
$
241

 
$
193

 
$
48

 
25
%
Total
$
241

 
$
193

 
$
48

 
25
%
 
 
 
 
 
 
 
 
Consolidated net revenues by type (USD):
 
 
 
 
 
 
 
Oil
$
2,134

 
$
1,460

 
$
674

 
46
%
Gas
221

 
200

 
21

 
11
%
Total
$
2,355

 
$
1,660

 
$
695

 
42
%
Revenues for the three months ended September 30, 2013, totaled $2.4 million, compared to $1.7 million in the prior year period, an increase of 42%. The $0.7 million increase in revenue was primarily due to the increased production from the Poplar field coupled with a favorable increase in realized pricing per barrel.


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Operating and Other Expenses
The following table presents operating expenses for the three months ended:
 
September 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Selected operating expenses (USD):
 
 
 
 
 
 
 
Lease operating
$
2,756

 
$
2,051

 
$
705

 
34
 %
Depletion, depreciation, amortization, and accretion
$
309

 
$
316

 
$
(7
)
 
(2
)%
Exploration
$
929

 
$
622

 
$
307

 
49
 %
General and administrative
$
3,095

 
$
3,663

 
$
(568
)
 
(16
)%
 
 
 
 
 
 
 
 
Selected operating expenses (USD/boe):
 
 
 
 
 
 
 
Lease operating
$89
 
$85
 
$4
 
5
 %
Depletion, depreciation, amortization, and accretion
$10
 
$13
 
$(3)
 
(23
)%
Exploration
$30
 
$26
 
$4
 
15
 %
General and administrative
$100
 
$152
 
$(52)
 
(34
)%
Lease Operating Expenses. Lease operating expenses increased $0.7 million to $2.8 million, or $89/boe, during the three months ended September 30, 2013, relative to the prior year period. At Poplar, lease operating expenses increased by approximately $0.8 million due to increased workovers and field maintenance activity compared to the same period in the prior year. At MPA, lease operating expenses decreased by $0.1 million primarily due to a decrease in Palm Valley field maintenance expenditures.
Depletion, Depreciation, Amortization, and Accretion. The following table presents depletion, depreciation, amortization, and accretion for the three months ended:
 
September 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
Depreciation and amortization
$
115

 
$
76

 
$
39

 
51
 %
Depletion
84

 
129

 
(45
)
 
(35
)%
ARO accretion
110

 
111

 
(1
)
 
(1
)%
Total
$
309

 
$
316

 
$
(7
)
 
(2
)%
Depletion, depreciation, amortization, and accretion expenses decreased $7 thousand to $309 thousand, or $10/boe, during the three months ended September 30, 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 increased by $0.3 million to $0.9 million, or $30/boe, during the three months ended September 30, 2013. The $0.3 million increase primarily related to expenditures for processing and interpretation of MPA's 2-D and 3-D seismic data acquired over NT/P82 in the Bonaparte Basin, offshore Australia.
General and Administrative Expenses. The following table presents general and administrative expenses for the three months ended:
 
September 30,
 
 
 
 
 
2013
 
2012
 
Difference
 
Percent change
 
(In thousands)
 
 
 
 
General and administrative (excluding stock based compensation and foreign transaction gain)
$
2,459

 
$
3,317

 
$
(858
)
 
(26
)%
Stock based compensation
657

 
346

 
311

 
90
 %
Foreign transaction gain
(21
)
 
—

 
(21
)
 
(100
)%
Total
$
3,095

 
$
3,663

 
$
(568
)
 
(16
)%
General and administrative expenses decreased $0.6 million to $3.1 million, or $100/boe, during the three months ended September 30, 2013. General and administrative expenses, excluding stock based compensation and foreign transaction gain, decreased by $0.9 million to $2.5 million, or $79/boe. This decrease is primarily due to prior year period employee severance costs of

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$0.8 million paid to former employees pursuant to the terms of their employment agreements and a decrease of approximately $0.1 million in accounting and consulting fees. The increase in non-cash stock based compensation of $0.3 million is primarily related to the issuance of equity based compensation to employees and to non-employee directors pursuant to the terms of the Company's compensation policy related to their annual base compensation for Board service.

OFF-BALANCE SHEET ARRANGEMENTS
The Company does not use off-balance sheet arrangements, such as securitization of receivables, with any unconsolidated entities or other parties.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Information regarding critical accounting policies and estimates is contained in Item 7 of our 2013 Form 10-K. There are no new significant accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of September 30, 2013.

FORWARD LOOKING STATEMENTS
This report contains forward looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than the statements of historical facts, included in this report that addresses activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward looking statements. The words "anticipate," "assume," "believe," "budget," "estimate," "expect," "forecast," "initial," "plan," "project," "will," and similar expressions are intended to identify forward looking statements. These forward looking statements about the Company and its subsidiaries appear in a number of places in this report and may relate to statements about our businesses and prospects, planned capital expenditures, availability of liquidity and capital resources, increases or decreases in oil and gas production, the ability to enter into acceptable farmout arrangements, revenues, expenses, operating cash flows, borrowings, and other matters that involve a number of risks and uncertainties that may cause actual results to differ materially from results expressed or implied in the forward looking statements. Additionally, there are risks and uncertainties such as the following: the uncertainties associated with our planned CO2-EOR program at Poplar, including uncertainties about drilling results from the recently initiated pilot project and our ability to acquire a long term CO2 supply for the program; uncertainties related to whether we will be able to realize expected gas sales volumes in Australia under the Dingo GSPA and Palm Valley GSPA, including uncertainties about the ultimate level of demand under the agreements and the timing and cost of implementing a pipeline and gas treatment facilities for the Dingo GSPA; our ability to attract and retain key personnel; the likelihood of success of a water shut-off program at Poplar; our limited amount of control over activities on our operational properties; our reliance on the skill and expertise of third party service providers; the ability of our vendors to meet their contractual obligations; government regulation and oversight of drilling and completion activity in the UK; the uncertain nature of oil and gas prices in the US, Australia, and the UK; uncertainties inherent in projecting future rates of production from drilling activities; the uncertainty of drilling and completion conditions and results; the availability of drilling, completion, and operating equipment and services; the results of 2-D and 3-D seismic data related to our NT/P82 interest in offshore Australia; and other matters discussed in the Risk Factors section of the 2013 Form 10-K and this report. For a more complete discussion of the risk factors that may apply to any forward looking statements, you are directed to the discussion presented in Item 1A ("Risk Factors") of the Company's 2013 Form 10-K. Any forward looking statements in this report should be considered with these factors in mind. Any forward looking statements in this report speak as of the filing date of this report. The Company assumes no obligation to update any forward looking statements contained in this report, whether as a result of new information, future events or otherwise, except as required by securities laws.
For a more complete discussion of the risk factors that may apply to any forward looking statements, you are directed to the discussion presented in Item 1A ("Risk Factors") of the Company's Form 10-K for the fiscal year ended June 30, 2013. Any forward looking statements provided in this report should be considered with these factors in mind. The Company assumes no obligation to update any forward looking statements contained in this report, whether as a result of new information, future events, or otherwise, except as required by securities laws.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's exposure to market risk relates to fluctuations in foreign currency and world prices for crude oil, as well as market risk related to investments in marketable securities. The exchange rates between the Australian dollar and the US dollar and the exchange rates between the US dollar and the British pound have changed in recent periods, and may fluctuate substantially in the future. Any appreciation of the US dollar against the Australian dollar is likely to result in decreased revenue, operating income, and net income. Because of our UK development program, a portion of our expenses, including exploration costs and capital and operating

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expenditures, will continue to be denominated in British pounds. Accordingly, any material appreciation of the British pound against the Australian and US dollars could have a negative impact on our business, operating results, and financial condition.
For the three months ended September 30, 2013, oil sales represented approximately 91% of total oil and gas revenues. Based on the current three months' sales volume and revenues, a 10% change in oil price would increase or decrease oil revenues by $0.2 million. Gas sales, which represented approximately 9% of total oil and gas revenues in the current three month period, are derived primarily from the Palm Valley field in the Northern Territory of Australia, where the gas prices are set according to long term contracts that are subject to changes in the Australian Consumer Price Index for the three months ended September 30, 2013.
At September 30, 2013, the fair value of our investments in securities available for sale was $0.1 million.

ITEM 4 CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Under the supervision and with the participation of certain members of the Company's management, including the Chief Executive Officer and the Chief Financial Officer, the Company completed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in SEC Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report. Based on this evaluation, the Company's Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report to provide reasonable assurance that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and is accumulated and communicated to the Company's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2013, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART II - OTHER INFORMATION
ITEM 1A RISK FACTORS
Item 1A ("Risk Factors") of our 2013 Form 10-K, sets forth information relating to important risks and uncertainties that could materially affect our business, financial condition, operating results, or cash flows. There have been no material changes in the Risk Factors described in such Form 10-K, and those Risk Factors continue to be relevant to an understanding of our business, financial condition, operating results, and cash flows. Accordingly, you should review and consider such Risk Factors in making any investment decision with respect to our securities. An investment in our securities continues to involve a high degree of risk.

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
As of September 30, 2013, the Company issued a total of 504,183 shares of its Series A Preferred Stock to One Stone as PIK dividends, pursuant to the terms and conditions of the Certificate of Designations of Series A Preferred Stock dated May 17, 2013, as amended, which 504,183 shares represented payment of quarterly dividends for the period from May 17, 2013 through September 30, 2013 of approximately $617,000 on the 19,239,734 shares of Series A Preferred Stock issued to One Stone on May 17, 2013. The shares of Series A Preferred Stock were issued pursuant to the private placement exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (the "Securities Act"). The facts relied upon to make such exemption available include that the private placement was with a single person that has represented that it is an "accredited investor" within the meaning of Rule 501 under the Securities Act, and the securities are restricted from transfer except pursuant to an effective registration statement under the Securities Act or an available exemption from such registration. Each share of Series A Preferred Stock is convertible at any time, at the holder's option, into one share of the Company's Common Stock, subject to customary anti-dilution provisions. For additional information regarding the Series A Preferred Stock, see Note 7 of the Notes to unaudited condensed consolidated financial statements included under Part I, Item 1 of this report.

ISSUER PURCHASES OF EQUITY SECURITIES
The table below provides information about purchases of the Company's common stock by the Company during the periods indicated.
Period
 
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Program
 
Maximum Number or Dollar Value of Shares that May Yet be Purchased Under the Program (1)
July 1, 2013 - July 31, 2013
 
—

 
$
—

 
—

 
$
1,863,022

August 1, 2013 - August 31, 2013
 
—

 
$
—

 
—

 
$
1,863,022

September 1, 2013 - September 30, 2013
 
10,938

(2) 
$
1.02

 
—

 
$
1,863,022

Total
 
—

 
$
—

 
—

 
 
(1) On September 24, 2012, the Company announced that its Board of Directors had approved a stock repurchase program whereby the Company is authorized to repurchase up to a total of $2.0 million in shares of its common stock. This authorization will expire on August 21, 2014. The shares may be repurchased from time to time in open market or privately negotiated transactions, subject to market conditions and other factors, including compliance with securities laws. Stock repurchases may be funded with existing cash balances or internal cash flow. The stock repurchase program may be suspended or discontinued at any time.
(2) These shares were purchased to allow employees who held the shares to satisfy tax withholding obligations that occurred in connection with the vesting of restricted shares of common stock, pursuant to the terms of their restricted stock award agreements.
The payment of dividends on our Common Stock is subject to the rights of holders of our Series A Preferred Stock, which ranks senior to the Common Stock with respect to dividend rights. For additional information, see Note 7 of the Notes to Condensed Consolidated Financial Statements (Unaudited) included under Part I, Item 1 of this report.

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ITEM 6 EXHIBITS
The following exhibits are filed or furnished with or incorporated by reference into this report:
3.1
Restated Certificate of Incorporation as filed on May 4, 1987 with the State of Delaware, as amended by an Amendment of Article Twelfth as filed on February 12, 1988 with the State of Delaware (filed as Exhibit 4.B. to the registrant's Registration Statement on Form S-8 filed on January 14, 1999 (Registration No. 333-70567) and incorporated herein by reference).
3.2
Certificate of Amendment of Restated Certificate of Incorporation as filed on December 26, 2000 with the State of Delaware (filed as Exhibit 3(a) to the registrant's Quarterly Report on Form 10-Q filed on February 13, 2001 and incorporated herein by reference).
3.3
Certificate of Amendment of Restated Certificate of Incorporation related to Articles Twelfth and Fourteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.3 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference).
3.4
Certificate of Amendment of Restated Certificate of Incorporation related to Article Thirteenth as filed on October 15, 2009 with the State of Delaware (filed as Exhibit 3.4 to the registrant's Quarterly Report on Form 10-Q filed on February 16, 2010 and incorporated herein by reference).
3.5
Certificate of Amendment of Restated Certificate of Incorporation related to Article Fourth as filed on December 10, 2010 with the State of Delaware (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on December 13, 2010 and incorporated herein by reference).
3.6
Certificate of Designations of Series A Convertible Preferred Stock as filed on May 17, 2013 with the State of Delaware (filed as Exhibit 3.6 to the registrant's Current Report on Form 8-K filed on June 26, 2013 and incorporated herein by reference).
3.7
Certificate of Amendment to Certificate of Designations of Series A Convertible Preferred Stock as filed on August 19, 2013 with the State of Delaware (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on August 19, 2013 and incorporated herein by reference).
3.8
By-Laws, as amended on June 13, 2013 (filed as Exhibit 3.1 to the registrant's Current Report on Form 8-K filed on June 18, 2013 and incorporated herein by reference).
4.1 +
Registration Rights Agreement dated May 17, 2013 between Magellan Petroleum Corporation and One Stone Holdings II LP (filed as Exhibit 4.1 to the registrant's Current Report on Form 8-K filed on June 26, 2013 and incorporated herein by reference).
10.1
Gas Supply and Purchase Agreement dated September 12, 2013, between Magellan Petroleum (NT) Pty Ltd and Power and Water Corporation (filed as Exhibit 10.1 to the registrant's Current Report on Form 8-K filed on September 12, 2013 and incorporated herein by reference) (portions of this Exhibit have been omitted pursuant to a request for confidential treatment filed with the Securities and Exchange Commission).
10.2 +
Form of Restricted Stock Award Agreement under the 2012 Omnibus Incentive Compensation Plan (filed as Exhibit 10.75 to the registrant's Annual Report on Form 10-K filed on September 16, 2013 and incorporated herein by reference).
10.3 +
Form of Nonqualified Stock Option Award Agreement under the 2012 Omnibus Incentive Compensation Plan (filed as Exhibit 10.76 to the registrant's Annual Report on Form 10-K filed on September 16, 2013 and incorporated herein by reference).
10.4 * +
Form of Performance-Based Nonqualified Stock Option Award Agreement under the 2012 Omnibus Incentive Compensation Plan.
31.1 *
Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2 *
Certification of Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer, pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1 **
Certification of John Thomas Wilson, President and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 **
Certification of Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS ***
XBRL Instance Document
101.SCH ***
XBRL Taxonomy Extension Schema Document
101.CAL ***
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF ***
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB ***
XBRL Taxonomy Extension Label Linkbase Document
101.PRE ***
XBRL Taxonomy Extension Presentation Linkbase Document
*
Filed herewith.
**
Furnished herewith.
***
Furnished herewith. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
+
Management contract or compensatory plan or arrangement.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
MAGELLAN PETROLEUM CORPORATION
 
 
(Registrant)
 
 
 
 
 
 
By:
/s/ J. Thomas Wilson
 
 
 
John Thomas Wilson, President and Chief Executive Officer
 
 
 
(as Principal Executive Officer)
 
 
 
 
 
 
By:
/s/ Antoine J. Lafargue
 
 
 
Antoine J. Lafargue, Vice President - Chief Financial Officer and Treasurer
 
 
 
(as Principal Financial and Accounting Officer)
 
 
 
 
Date:
November 12, 2013
 
 

32