Mpet investor presentation 2012 10 01

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Mpet investor presentation 2012 10 01

  1. 1. Building Shareholder Returns byMaximizing the Potential of Currently Held Assets NASDAQ: MPET October 2012
  2. 2. Forward Looking StatementsStatements in this presentation which are not historical in nature are intended to be, and are hereby identified as, forward-looking statements forpurposes of the Private Securities Litigation Reform Act of 1995. These statements about Magellan and Magellan Petroleum Australia Limited(“MPAL”) may relate to their businesses and prospects, revenues, expenses, operating cash flows, and other matters that involve a number ofuncertainties that may cause actual results to differ materially from expectations. Among these risks and uncertainties are the following: the futureoutcome of the negotiations by Santos with its customers for gas sales contracts for the remaining uncontracted reserves in the Amadeus Basin; theproduction volume at Mereenie and whether it will be sufficient to trigger the bonus amounts provided for in the Santos asset swap/sales agreement;the ability of the Company to successfully develop its existing assets; the ability of the Company to secure gas sales contracts for the uncontractedreserves at Dingo; the ability of the Company to implement a successful exploration program; pricing and production levels from the properties inwhich Magellan and MPAL have interests; the extent of the recoverable reserves at those properties; the profitable integration of acquired businesses,including Nautilus Poplar LLC; the likelihood of success of the drilling program at the Poplar Fields by the Company’s new farm-in partner, VAALCOEnergy; and the results of the ongoing production well tests in the U.K. In addition, MPAL has a large number of exploration permits and faces the riskthat any wells drilled may fail to encounter hydrocarbons in commercially recoverable quantities. Any forward-looking information provided in thisreport should be considered with these factors in mind. Magellan assumes no obligation to update any forward-looking statements contained in thisreport, whether as a result of new information, future events, or otherwise.Oil and gas issuers are required to include disclosures regarding proved oil and gas reserves in certain filings made with the U.S. Securities andExchange Commission (“SEC”). Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological andengineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic andoperating conditions, i.e., prices and costs as of the date the estimate is made. The SEC also permits the disclosure of probable and possiblereserves which are additional reserves that are less certain to be recovered. Investors are urged to consider closely the disclosures in Magellan’speriodic filings with the SEC available from us at the Company’s website, www.magellanpetroleum.com. 1
  3. 3. Magellan is……executing a turnaround strategy focused on maximizing the value of existing oil and gas assets in the United States, Australia, and the United Kingdom 2
  4. 4. Investment Considerations Cash and equivalents of approximately $40 million dollars $ 73 m 10.8 MMBoe net proved reserves Several near-term opportunities to $ 55 m significantly increase reserves 22,000 net unitized acres covering Poplar Dome, the largest geologic structure in the $ 41 m western Williston Basin, Montana Australian natural gas assets generating long- term stable revenue with potential upside Long-term potential from onshore UK and off- shore Australia projects Lower fixed operating costs in FY131; most capex discretionary Experienced management team Market cap Cash Book value 3 Oct 30 Jun 30 Jun $1.02/sh $0.76/sh $1.35/sh1. June 30 fiscal year end. 3
  5. 5. Turnaround LeadershipRobin West (66) – Chairman Tom Wilson (60) – CEO Founder, CEO of PFC Energy  Former President of KMOC and Anderman Former Reagan Administration Assistant International Secretary of the Interior (1981-83),  Former First Vice President and director of responsible for U.S. offshore oil policy Young Energy Prize Member of National Petroleum Council and  Previously, led new international strategy Council on Foreign Relations for Apache and served as a Project Director of Key Energy Services and Manager for Shell Oil formerly of Cheniere EnergyAntoine Lafargue (38) – CFO Mark Brannum (46) – General Counsel & Former CFO of Falcon Gas Storage based Secretary in Houston, TX  Former Deputy General Counsel of SM Previously, a principal with Arcapita, a Energy Company private equity fund focused on the energy  Previously, a shareholder with Winstead and infrastructure sectors P.C., a large business law firm based in Previously held investment banking Dallas, TX positions with DLJ/Credit Suisse and Bank  Over 17 years of in-house and outside of America counsel legal experience 4
  6. 6. Poplar  22,000 net unitized acres covering largest geologic structure in western Williston Basin  Substantially all acreage held by production, and capex is mainly discretionary  Bakken Play is moving west to Poplar 5
  7. 7. Poplar Judith River  Shallow gas opportunity Greenhorn  Oil potential – similar to Eagleford play Amsden  New oil pool discovery Jan 12  1 producing well; currently planning development strategy Tyler  4 current wells  Additional potential Charles  Approximately 250 bbls/day  CO2-EOR: pilot project in FY13 Several reserve development opportunities 6
  8. 8. Poplar – VAALCO Farm-Out VAALCO farm-out in Sep 2011 to explore and develop deeper formations at Poplar – 100% carry for 3 wells in calendar 2012 – 35% interest in all wells to Magellan Objective and rationale: – Prove up reserves and value of deeper formations of Poplar, with limited capital exposure through the exploration phase – Remain focused on Charles and shallower formations – Benefit from VAALCO’s horizontal well drilling expertise Timing: – First well drilled in Q1; no commercial quantities of hydrocarbons below the Bakken/Three Forks formation; well temporarily suspended – Second well completed in Q3 as a horizontal well to test Bakken/Three Forks; found to be water-bearing; well temporarily suspended to evaluate options 7
  9. 9. Poplar – CO2 Enhanced Oil Recovery Evidence points to Charles formation being a prime candidate for a CO2 enhanced oil recovery program Offers the potential to increase reserves from current 10 MMbbls to 40 to 60 MMbbls Laboratory tests confirm oil from Charles formation has requisite miscibility for successful CO2 enhancement Project assessment milestones: – Laboratory tests complete; all results positive – 5 well pilot project to start in FY13 Potential additional proved reserves of 30 to 50 MMbbls 8
  10. 10. Australian Onshore AssetsPalm Valley 145 km SW of Alice Springs 11 Bcf of proved gas reserves and 14 Bcf of probable gas reserves ~$100 m revenue contract over 17 years with price upside 100% owner / operator Connected to Darwin pipelineDingo 65 km south of Alice Springs Material gas resource 3 appraisal wells (’84 and ’90) 100% owner / operator Marketing gas to mining industryMereenie Opportunity to earn up to A$17.5 million in bonus payments from Santos 9
  11. 11. Bonaparte BasinNT/P82 Long term development opportunity Potential reserves of approximately 1 to 3 Tcf 100% held exploration block 3D seismic survey to be conducted in Q2 FY13 1 exploration well required by 2015 10
  12. 12. UK Shale 200,000 net acres – 11 licenses Celtique operated (50%)  Acquired 175 km 2D seismic in July 2011  Conventional plays: shallow oil and deep gas  Unconventional plays: Shale oil and gas potential in Liassic and Kimmeridge shales Northern operated (22.5% – 40%)  Markwells Wood – production test suspended  PEDL 240 (Isle of Wight) – Wytch Farm extension play Magellan operated (100%)  Deep gas potential at Horse Hill Magellan operated : 2 licenses, 100% WI Celtique operated : 4 licenses, 50% WI Northern operated : 5 licenses, 22.5%-40% WI 11
  13. 13. Historical Financials1 Revenue Net income (loss) EBITDAX (2) 28.5 26.5 18.2 13.7 7.4 $m (1.4) (4.8) (11.2) (32.4) FY10 FY11 FY12Production Oil (Mbbls) 139 123 122 Gas (Bcf) 3.4 0.7 0.4 Total (Mboe) 711 241 196 boepd 1,947 661 537 1. June 30 fiscal year end. 2. See Appendix: EBITDAX Reconciliation for reconciliation to net income and for further information on EBITDAX. 12
  14. 14. Operational MilestonesMilestone Cost FY2013 FY2014 Dec Mar JunPoplar CO2-EOR – 5-well pilot ~$10 m VAALCO/Deep Rights – test wells - Charles formation – various testingAustralia NT/P82 – 3D seismic ~$5 m Palm Valley – new gas contracts - Dingo – develop marketing strategy -UK Development assessment 13
  15. 15. Poised for Improved Cash Flow12-Month revenue enhancement opportunities Replacement gas contracts for Palm Valley Increased Charles production Amsden potential production Poplar deep interval potential production12-Month operating cost savings Lower Palm Valley operating costs Eliminated Mereenie operating costs Reduced G&A expenses Australian stock exchange listing expenses 14
  16. 16. Appendix
  17. 17. Adjusted EBITDAX ReconciliationAdjusted EBITDAX: Non-GAAP financial measure reconciliation to net income (loss) Fiscal Years Ended June 30, 2012 2011 2010 (In thousands) Net (loss) attributable to Magellan $ 26,498 $ (32,432) $ (1,446) Depletion, depreciation, amortization, and accretion expense 1,744 2,890 5,428 Exploration expense 6,291 2,854 1,273 Stock-based compensation expense 1,560 1,670 2,305 Foreign transaction (gain) loss (475) 951 677 Impairment expense 328 173 2,050 Loss on Evans Shoal - 15,893 - (Gain) on sale of assets (40,413) (969) (6,817) Warrant expense - - 4,276 Net interest (income) (749) (923) (1,038) Other (income) (9) - (1,975) Income tax (benefit) provision (5,951) 5,141 2,646 Net (loss) income attributable to non-controlling interest in subsidiaries (15) (5) (11) Adjusted EBITDAX $ (11,191) $ (4,757) $ 7,368We define Adjusted EBITDAX as net income (loss) attributable to Magellan, plus (i) depletion, depreciation, amortization, and accretion expense, (ii) exploration expense, (iii) stockbased compensation expense, (iv) foreign transaction loss (gain), (v) impairment expense, (vi) loss on Evans Shoal, (vii) gain on sale of assets, (viii) warrant expense, (ix) net interestincome, (x) other income, (xi) income tax benefit (provision), and net (loss) income attributable to non-controlling interest in subsidiaries. Adjusted EBITDAX is not a measure of netincome 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 ofoperating results.Our Adjusted EBITDAX measure provides additional information which may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use asa 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 indicatorof our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a companys financial performance, suchas 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. Webelieve 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 ourconsolidated financial statements. For example, Adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independentexploration and production companies without regard to financial or capital structure, and to assess the financial performance of our assets and our company without regard tohistorical cost basis and items affecting the comparability of period to period operating results. 16

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