1. Building Shareholder Returns by
Maximizing the Potential of Currently Held Assets
NASDAQ: MPET
October 2012

2. Forward Looking Statements
Statements in this presentation which are not historical in nature are intended to be, and are hereby identified as, forward-looking statements for
purposes 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 of
uncertainties that may cause actual results to differ materially from expectations. Among these risks and uncertainties are the following: the future
outcome of the negotiations by Santos with its customers for gas sales contracts for the remaining uncontracted reserves in the Amadeus Basin; the
production 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 uncontracted
reserves at Dingo; the ability of the Company to implement a successful exploration program; pricing and production levels from the properties in
which 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, VAALCO
Energy; 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 risk
that any wells drilled may fail to encounter hydrocarbons in commercially recoverable quantities. Any forward-looking information provided in this
report should be considered with these factors in mind. Magellan assumes no obligation to update any forward-looking statements contained in this
report, 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 and
Exchange Commission (“SEC”). Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is made. The SEC also permits the disclosure of probable and possible
reserves which are additional reserves that are less certain to be recovered. Investors are urged to consider closely the disclosures in Magellan’s
periodic filings with the SEC available from us at the Company’s website, www.magellanpetroleum.com.
1

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. 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/sh
1. June 30 fiscal year end. 3

5. Turnaround Leadership
Robin 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 Energy
Antoine 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. 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. 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. 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. 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. Australian Onshore Assets
Palm 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 pipeline
Dingo
 65 km south of Alice Springs
 Material gas resource
 3 appraisal wells (’84 and ’90)
 100% owner / operator
 Marketing gas to mining industry
Mereenie
 Opportunity to earn up to A$17.5
million in bonus payments from
Santos
9

11. Bonaparte Basin
NT/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. 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. 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 FY12
Production
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. Operational Milestones
Milestone Cost FY2013 FY2014
Dec Mar Jun
Poplar
CO2-EOR – 5-well pilot ~$10 m
VAALCO/Deep Rights – test wells -
Charles formation – various testing
Australia
NT/P82 – 3D seismic ~$5 m
Palm Valley – new gas contracts -
Dingo – develop marketing strategy -
UK
Development assessment
13

15. Poised for Improved Cash Flow
12-Month revenue enhancement opportunities
 Replacement gas contracts for Palm Valley
 Increased Charles production
 Amsden potential production
 Poplar deep interval potential production
12-Month operating cost savings
 Lower Palm Valley operating costs
 Eliminated Mereenie operating costs
 Reduced G&A expenses
 Australian stock exchange listing expenses
14

16. Appendix

17. Adjusted EBITDAX Reconciliation
Adjusted 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) $ 7,368
We define Adjusted EBITDAX as net income (loss) attributable to Magellan, plus (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 on Evans Shoal, (vii) gain on sale of assets, (viii) warrant expense, (ix) net interest
income, (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 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 which 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.
16