News Column

MAGELLAN PETROLEUM CORP /DE/ - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

February 14, 2014

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

OVERVIEW OF THE COMPANY Magellan Petroleum Corporation is an independent oil and gas exploration and development company primarily focused on the development of a CO2-enhanced oil recovery ("CO2-EOR") program at Poplar Dome ("Poplar") in eastern Montana. Historically active internationally, Magellan also maintains exposure to the UK and Australian oil and gas markets through the following assets: (i) a large, mostly non-operated acreage position onshore UK in the Weald and Wessex Basins prospective for unconventional shale oil and gas production; (ii) an exploration block, NT/P82, in the Bonaparte Basin, offshore Northern Territory, Australia, which the Company currently plans to farmout; and (iii) two gas fields, Palm Valley and Dingo, onshore Northern Territory, Australia. The Company conducts its operations through three wholly owned subsidiaries corresponding to the geographic areas in which the Company operates: Nautilus Poplar LLC ("NP") in the US, Magellan Petroleum (UK) Limited ("MPUK"), and Magellan Petroleum Australia Pty Ltd ("MPA"). Our strategy is to enhance shareholder value by maximizing the value of our existing assets. Our portfolio of operations includes several early stage oil and gas exploration and development projects, the successful development of which requires significant capital, as well as significant engineering and management resources. We are committed to investing in these projects to establish their technical and economic viability. In turn, we are focused on determining the most efficient way to create the greatest value and highest returns for our shareholders.



SUMMARY RESULTS OF OPERATIONS Revenues for the three months ended December 31, 2013, totaled $1.9 million, compared to $1.7 million for the prior year period, an increase of 7%. This increase was primarily due to increased production at Poplar as a result of successful water shutoff treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014. We reduced our operating loss for the three months ended December 31, 2013, to $4.1 million, compared to an operating loss of $7.7 million for the prior year period. We also reduced our net loss for the three months ended December 31, 2013, to $4.1 million ($(0.10)/basic and diluted share), compared to a net loss of $7.3 million ($(0.14)/basic and diluted share) for the prior year period. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation below) was negative $2.3 million for the three months ended December 31, 2013, compared to negative $3.0 million in the prior year period, a positive change of 22.7%. For further information, please refer to the discussion below in this section under Comparison of Results between the Three and the Six Months Ended December 31, 2013, and 2012.

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

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

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

HIGHLIGHTS OF OPERATIONAL ACTIVITIES During the three months ended December 31, 2013, the Company progressed a number of initiatives for its operational assets to evaluate and determine the potential of its oil and gas properties.

Poplar (Montana, USA) CO2-EOR pilot project. Based on the Company's technical analysis, the production history of the field to date, and reference to analogous CO2-EOR projects in the Williston Basin, management believes that the Charles formation at Poplar is an attractive candidate for significantly enhanced oil recovery through CO2-EOR techniques. To reduce the operational risk of implementing a full-field CO2-EOR program at Poplar and to further validate the tertiary recovery technique on a full-field basis, the Company began to implement a CO2-EOR pilot project in the Charles formation at Poplar in the first quarter of fiscal year 2014, which program will consist of five wells, including the CO2-injection well, and injecting CO2 over a two year period. Over the course of calendar year 2014, we will be monitoring the performance of the wells and the volumes of injected CO2 and regularly re-calibrating our reservoir model. We expect it will take approximately 12 months from the time of first injection to further ascertain the effectiveness of CO2-EOR techniques on a full field basis and the incremental volume of recoverable oil. During the quarter ended December 31, 2013, the Company drilled to total depth the five CO2-EOR pilot wells, including the CO2 injector well. The four producing wells are designed to yield primary oil production from the Charles formation in addition to enhanced production as a result of the CO2-EOR. These wells are currently undergoing water shutoff treatments in preparation for the first CO2 injection, which is scheduled to occur in February 2014. As of December 31, 2013, the total cost of the pilot project, including capital and certain operating expenditures, which includes CO2 supply cost scheduled to occur over the next two years, is currently estimated at approximately $20.0 million. Shallow Intervals. During the three months ended December 31, 2013, Magellan sold 21 Mbbls (228 bopd) of oil attributable to its net revenue interests in Poplar, compared to 17 Mbbls (185 bopd) of oil during the same period in 2012. This increase was primarily due to increased production at Poplar as a result of successful water shutoff treatments on certain wells completed during fiscal year 2013 and early fiscal year 2014, which mitigated the natural production decline of the field. During the period, Magellan remained focused on evaluating the potential of water shutoff and other treatments on Poplar's existing producing wells, which treatments are intended to increase oil production and reduce water production from wells with paybacks of less than 12 months. Most recently, the Company successfully completed a treatment on the EPU 6 well, which was producing marginal quantities of oil from the Charles C intervals prior to the treatment and is currently flowing at a rate of 45 bopd and 550 bwpd. Magellan has now concluded that water shut off treatments are more effective in the C intervals of the Charles formation than in the B intervals. As such, Magellan will continue these treatments on wells producing from the Charles C intervals at Poplar. 18



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

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



Australia

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

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selling at its full deliverability capacity and generating revenues of approximately AUD $8.0 million per year. Dingo. During September 2013, the Company signed the Dingo GSPA with Northern Territory Power and Water Corporation ("PWC") for the supply of up to 31 PJ (30 Bcf) of gas over a 20-year period, which supply is expected to commence early in calendar year 2015. With a long term contract now in place, the Company will use the intervening time period to design, construct, and commission the surface facilities and tie-in pipeline necessary for the production and delivery of Dingo's gas. Gas volumes are expected to be produced from three wells drilled at Dingo in the 1980s and 1990s, of which two wells have since been temporarily shut-in but are expected to be capable of producing gas volumes sufficient to meet the initial delivery requirements under the Dingo GSPA. The Company appointed GPA Engineering ("GPA") to undertake the front-end engineering and design ("FEED") of the facilities and pipeline, which is a continuation of work performed by GPA during the pre-FEED stage in fiscal year 2013. The FEED study was completed in January 2014. Based on the FEED study, the Company is planning to run Dingo as a remote operation, with only wellheads and gathering lines to be located at the field itself. Production from the wells will flow through a pipeline approximately 30 miles in length to a processing facility to be located at Brewer Estate, an industrial facility located just south of Alice Springs, where the gas will be processed and where PWC will take delivery of the gas. Following the signing of the Dingo GSPA, management believed that both Palm Valley's and Dingo's long-term gas sales contracts could provide a basis to fairly assess their value, and, as a result, management undertook an evaluation of strategic alternatives of these assets during the second quarter of fiscal year 2014. As part of this evaluation, the Company commenced a process to market and sell Palm Valley and Dingo. As a result of this process, the Company has been negotiating with a party for the potential sale of Palm Valley and Dingo, and the Company currently believes that it may be close to reaching an agreement for such sale. However, as of the date of this report, no definitive agreement has been reached, the process is still ongoing, and the process may or may not result in a sale of these two gas fields. NT/P82. During the three months ended December 31, 2013, the Company worked toward completing the processing and interpretation of 2-D and 3-D seismic surveys that the Company shot over part of NT/P82 in the Bonaparte Basin in December 2012. In November 2013, the Company elected to run the seismic data through additional testing and review, at minor additional cost, in order to confirm the validity and integrity of the data and analysis. Although this has extended the expected date of finalization of interpretation to the third quarter of fiscal year 2014, the Company believes this additional analysis will allow it to successfully complete a farmout process on favorable terms before the end of fiscal year 2014. Based on the preliminary results of the interpretation of the 2-D and 3-D seismic surveys, the Company believes that two large prospects are present within our block. In completing a farmout, the Company expects to relinquish a portion of its working interest in, and operatorship of, NT/P82, in exchange for a commitment from the partner to drill exploration wells over the large gas prospects identified in the block by the fourth quarter of fiscal year 2015 to meet our requirements under the terms of the license. Given the estimated size of the prospects, the high level of offshore drilling activity in the Bonaparte Basin, the network of installed gas infrastructure in the relative vicinity of our block, and the relatively shallow depths of water in the license area, the Company believes it is well positioned to successfully complete a farmout.



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

Uses of Funds Capital Expenditure Plans. At Poplar, the Company does not face significant mandatory capital expenditure requirements to maintain its acreage position. Substantially all of the leases are held by production and contain producing wells with reserves adequate to sustain multi-year production. Approximately 80% of the acreage has been unitized as a federal exploratory unit, which is held by economic production from any one well in the unit. Currently, Poplar contains 40 productive wells. In the Shallow Intervals, which are 100% owned and operated by the Company, discretionary capital expenditure plans over the next two years will be determined by the results of the CO2-EOR pilot project and results of water shutoff treatments. Until approximately December 2015, the Company intends to evaluate the potential of CO2-EOR in the Charles formation at Poplar. As of December 30, 2013, a five-well pilot, including one CO2 injector well and four producing wells has been drilled. Magellan expects to have incurred most of the approximately $20.0 million in estimated capital and certain operating expenditures by March 2014. As of December 2013, approximately 60% of the estimated costs of the CO2-EOR pilot project have been incurred, while approximately 20% of the estimated costs of the CO2-EOR pilot project are related to the injection of CO2, which is scheduled to occur over the next two years.

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In the Deep Intervals, which are operated by the Company and in which the Company has a working interest of 50% in the majority of the leases, the Company does not intend to incur material capital expenditures in fiscal year 2014. Based on its cash resources and other strategic considerations, the Company may invest in re-completing a well in the Nisku formation. In the UK, the Company's interests are governed by various PEDLs and one Seaward Production License. PEDLs 231, 234, and 243, which the Company co-owns equally with Celtique and which represent 125 thousand out of the Company's total of approximately 200 thousand net acres in the UK, have been extended to June 2016 and are subject to "drill-or-drop" obligations. In fiscal year 2014, the Company will focus on evaluating the potential of its unconventional prospects in these licenses. The Company expects to fund its share of the cost for an evaluation well expected to be spud within PEDL 234 during the fourth quarter of fiscal year 2014 or the first quarter of fiscal year 2015, of which the net cost to Magellan is estimated to be approximately $5.0 million, and which will meet the license obligations for both PEDLs 231 and 243. Pending the results of this well, the Company may participate in a second such evaluation well within these PEDLs in fiscal year 2015. The Company expects to fund these expenditures from either its cash balances, a farmout, the proceeds from non-core asset sales, or a combination thereof. The Company does not expect to incur further significant capital or exploratory expenditures on its other UK licenses in fiscal year 2014. In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in NT/P82. Under the terms of the permit, the Company is required to drill one exploratory well on the license by May 2015. Following the successful completion of seismic surveys over two prospects in the license area and the associated processing and interpretation, the Company currently plans to commence a farmout process in order to identify a partner experienced in offshore exploratory drilling to drill the exploratory well on our behalf. The Company does not expect to incur further significant capital expenditures of its own until the first exploration well has been drilled. At Palm Valley, the Company's interest in the field is governed by Petroleum Lease No. 3, which expires in November 2024 (and is subject to automatic renewal for another 21 years). The Company is not obligated to undertake significant mandatory capital expenditures in order to maintain its position in the lease. The Company's discretionary capital expenditure plans are primarily focused on maintaining gas production from the existing facilities in order to meet delivery obligations under its GSPA with Santos while maintaining a safe and efficient operation, conducted in accordance with good oil field practice. At Dingo, the Company's interest in the field is governed by Retention License No. 2, which expires in February 2014 and is currently under application both for renewal as a retention license and conversion to a production license. Following the signing of the Dingo GSPA in September 2013, the Company has estimated that the cost to install surface facilities for production and processing of gas and to build a 30 mile pipeline connecting Dingo to existing pipeline infrastructure at Brewer Estate, south of Alice Springs, would total approximately $20.0 million. The Company is currently reviewing a number of alternatives related to the development of Dingo, including issuing project finance debt facilities, contracting out the construction of the pipeline to a third party on a build/own/operate ("BOO") basis, entering into a joint-venture or farmout agreement, selling the asset, or a combination thereof. If the Company is successful in its attempt to sell Palm Valley and Dingo, the Company will not incur the approximately $20.0 million in development costs for Dingo.



Contractual Obligations. Please refer to the contractual obligations table in Part II, Item 7 of our 2013 Form 10-K for information on all material contractual obligations. Share Repurchase Program. On September 24, 2012, the Company announced that its Board had approved a stock repurchase program whereby the Company is authorized to repurchase up to a total of $2.0 million in shares of its Common Stock. As of December 31, 2013, $1.9 million remained authorized for stock repurchases under this program. See Issuer Purchases of Equity Securities under Part II, Item 2 of this report for additional information.

Sources of Funds Cash and Cash Equivalents. On a consolidated basis, the Company had approximately $12.2 million of cash and cash equivalents as of December 31, 2013, compared to $32.5 million as of June 30, 2013. The Company considers cash equivalents to be short term, highly liquid investments that are both readily convertible to known amounts of cash and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates. Cash balances totaled $1.0 million as of December 31, 2013, with the remaining $11.1 million held in cash equivalents with maturities of 90 days or less. In the US, cash equivalents were held in US Treasury notes and totaled $8.8 million, and in Australia, cash equivalents were held in several time deposit accounts totaling $2.3 million. Due to the international nature of its operations, the Company is exposed to certain legal and tax constraints in matching the capital needs of its assets and its cash resources. As of December 31, 2013, $2.5 million, or 21% of the Company's consolidated cash and cash equivalents, was deposited in accounts held by MPA. To the extent that the Company repatriates cash amounts from MPA to the US, the Company will potentially be liable for any incremental US Federal and state income tax, which may be reduced by the US Federal and state net operating loss and foreign tax credit carry forwards available to the Company at that time.

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

December 31, June 30, 2013 2013 (In thousands) Outstanding borrowings: Term loan $ 174 $ 390 Line of credit 51 51 Total $ 225 $ 441



The Company, through its wholly owned subsidiary NP, maintains its only credit facility (the "Line of Credit") with Jonah Bank of Wyoming. As of December 31, 2013, $0.1 million of the $1.0 million Line of Credit was drawn, $25 thousand secured a Line of Credit in favor of the Bureau of Land Management, $25 thousand secured business credit cards, and $0.9 million remained available to borrow. As of December 31, 2013, NP was in compliance with its financial covenants as set forth in the term loan agreement. The credit facility is collateralized by a first mortgage and an assignment of production from Poplar, and guaranteed by the Company up to $6.0 million, but not to exceed the amount of the principal owed, which was $0.2 million as of December 31, 2013. Other Sources of Financing. In addition to its existing liquid capital resources as discussed above, the Company has various alternatives to fund the development of its assets. These alternatives could potentially include conventional bank debt, a reserve-based loan facility, mezzanine financing, issuances of new common shares or hybrid equity securities to potential investors via a PIPE or secondary offering, and a partial or complete divestiture or farmout of a portion of the development program of some of the Company's assets.

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



Effect of exchange rate changes on cash and cash equivalents (28 ) 839 Net decrease in cash and cash equivalents

$ (20,310 )$ (9,511 ) Cash used in operating activities during the six months ended December 31, 2013, was $6.2 million, compared to $9.0 million for the same period in 2012. The decrease in cash used in operating activities was primarily due to an increase in revenues of $0.8 million, and a decrease in general and administrative expenses of $1.1 million related to prior year employee severance costs, and accounting and consulting fees related to the prior year period. This decrease was partially offset by an increase in cash outflows related to our operating assets and liabilities. Cash used in investing activities during the six months ended December 31, 2013, was $13.9 million, compared to $1.1 million for the same period in 2012. The increase in cash used in investing activities was primarily due to the capital expenditures related to the CO2-EOR pilot project at Poplar. For the six months ended December 31, 2013, the $13.9 million used in investing activities was primarily spent on the development of our assets, of which $11.9 million related to the CO2-EOR pilot project and $0.8 million related to water shutoff treatments at Poplar. Cash used in financing activities during the six months ended December 31, 2013, was $0.2 million, compared to $0.3 million of cash used in financing activities for the same period in 2012. The decrease in cash used in financing activities for the six months ended December 31, 2013, related to the repurchase of common stock and long term debt repayments in the prior year period. During the six months ended December 31, 2013, the effect of changes in foreign currency exchange rates negatively impacted the translation of our AUD denominated cash and cash equivalent balances into USD and resulted in a decrease of $28 thousand in cash and cash equivalents, compared to an increase of $0.8 million for the same period in 2012, primarily as a result of the combined impact of the weakening AUD and the significant decrease in cash and cash equivalent balances denominated in AUD compared to the prior year period. NON-GAAP FINANCIAL MEASURES AND RECONCILIATION Adjusted EBITDAX We define Adjusted EBITDAX as net income (loss) attributable to Magellan, plus (minus): (i) depletion, depreciation, amortization, and accretion expense, (ii) exploration expense, (iii) stock based compensation expense, (iv) foreign transaction loss (gain), (v) impairment expense, (vi) loss (gain) on sale of assets, (vii) net interest expense (income), (viii) other expense (income), and (ix) income tax provision (benefit). Adjusted EBITDAX is not a measure of net income or cash flow as determined by accounting principles generally accepted in the United States ("GAAP") and excludes certain items that we believe affect the comparability of operating results. Our Adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income (loss) as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, 22



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as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure and to assess the financial performance of our assets and our company without regard to historical cost basis and certain items that affect the comparability of period to period operating results. The following table provides a reconciliation of net loss to Adjusted EBITDAX for the periods ended:

THREE MONTHS ENDED SIX MONTHS ENDED December 31, December 31, 2013 2012 2013 2012 (In thousands) LOSS AFTER INCOME TAX $ (4,112 )$ (7,285 )$ (8,947 )$ (12,594 ) Depletion, depreciation, amortization, and accretion expense 598 332 907 649 Exploration expense 728 4,094 1,657 4,716 Stock based compensation expense 406 261 1,066 606 Foreign transaction (gain) loss (5 ) 36 (26 ) 36 Impairment expense - - - 890 Loss on sale of assets 33 - 95 - Net interest income (23 ) (258 ) (43 ) (479 ) Other expense (income) 45 127 105 112 Income tax benefit - (321 ) - (658 ) Adjusted EBITDAX $ (2,330 )$ (3,014 )$ (5,186 )$ (6,722 )



For clarification purposes, the table below provides an alternative method for calculating Adjusted EBITDAX, which can also be calculated as revenue less (i) lease operating expense and (ii) general and administrative expense; plus (i) stock based compensation expense and (ii) foreign transaction (gain) loss. The following table provides the alternative method for calculating Adjusted EBITDAX for the periods ended:

THREE MONTHS ENDED SIX MONTHS ENDED December 31, December 31, 2013 2012 2013 2012 (In thousands) Total revenues $ 1,869$ 1,748$ 4,225$ 3,409 Less: Lease operating (1,718 ) (1,665 ) (4,474 ) (3,716 )



General and administrative (2,882 ) (3,394 ) (5,977 ) (7,057 ) Plus: Stock based compensation expense 406 261 1,066 606 Foreign transaction (gain) loss (5 ) 36 (26 ) 36 Adjusted EBITDAX

$ (2,330 )$ (3,014 )$ (5,186 )$ (6,722 ) 23



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COMPARISON OF RESULTS BETWEEN THE THREE MONTHS ENDED DECEMBER 31, 2013, AND 2012 Oil and Gas Sales Volume The following table presents oil and gas sales volumes for the three months ended: December 31, 2013 2012 Difference Percent change Net sales by field: Poplar (Mbbls) 21 17 4 24 % Palm Valley gas (MMcf) 53 62 (9 ) (15 )% Net sales by product: Oil (Mbbls) 21 17 4 24 % Gas (MMcf) 53 62 (9 ) (15 )% Consolidated sales (Mboe) 30 28 2 7 % Consolidated sales (boepd) 322 302 20 7 %



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

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

December 31, 2013 2012 Difference Percent change



Average realized price: Poplar (USD/bbl) $79.27$82.53$(3.26) (4 )% Palm Valley (AUD/Mcf) $4.86$4.78$0.08 2 % Consolidated (USD/boe) $63.54$62.99$0.55 1 %

The average realized price for the three months ended December 31, 2013, was $64/boe compared to $63/boe in the same period in the prior year, an increase of 1%. At present, the Company does not engage in any oil and gas hedging activities. Relative to the same period in the prior year, the average realized price from oil sales at Poplar decreased by 4% primarily as a result of declining differentials relative to the benchmark pricing (WTI) realized at that field. The average realized gas price from Palm Valley increased by 2% primarily as a result of CPI escalation allowed under the Palm Valley Gas Sales Agreement with Santos and the related concession gas sales agreements.

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Source: Edgar Glimpses


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