28 November 2012 Company Announcements Platform Australian Securities Exchange Level 4 20 Bridge Street SYDNEY NSW 2000 By e-lodgement COMPANY PRESENTATION MATERIAL Please find attached to this document a copy of the presentation slides to be used by Aurora Oil & Gas Limited at the Jefferies 2012 Global Energy Conference held on November 29, 2012 in Houston, Texas. The presentation slides will also be used in subsequent marketing meetings in Canada the following week. For Aurora Oil & Gas Limited Julie Foster Company Secretary (Data referencing activities in adjacent acreage has been sourced from publically available information) Technical information contained in this report in relation to the Sugarkane field was compiled by Aurora from information provided by the project operator and reviewed by I L Lusted, BSc (Hons), SPE, a Director of Aurora who has had more than 19 years experience in the practice of petroleum engineering. Mr Lusted consents to the inclusion in this report of the information in the form and context in which it appears.
Aurora Oil & Gas Limited Jefferies 2012 Global Energy Conference November 29, 2012 0
Disclaimer This document has been prepared by Aurora Oil & Gas Limited ( Aurora ) in connection with providing an overview to interested analysts / investors and is being provided for the sole purpose of providing preliminary background financial and other information to enable recipients to review certain business activities of Aurora. This presentation is thus by its nature limited in scope and is not intended to provide all available information regarding Aurora. This presentation is not intended as and shall not constitute an offer, invitation, solicitation, or recommendation with respect to the purchase or sale of any securities in any jurisdiction and should not be relied upon as a representation of any matter that a potential investor should consider in evaluating Aurora. Aurora and its affiliates, subsidiaries, directors, agents, officers, advisers or employees do not make any representation or warranty, express or implied, as to or endorsement of, the accuracy or completeness of any information, statements, representations or forecasts contained in this presentation, and they do not accept any liability or responsibility for any statement made in, or omitted from, this presentation. Aurora accepts no obligation to correct or update anything in this presentation. No responsibility or liability is accepted and any and all responsibility and liability is expressly disclaimed by Aurora and its affiliates, subsidiaries, directors, agents, officers, advisers and employees for any errors, misstatements, misrepresentations in or omissions from this presentation. Users of this information should make their own independent evaluation of an investment in or provision of debt facilities to Aurora. Nothing in this presentation should be construed as financial product advice, whether personal or general, for the purposes of section 766B of the Corporations Act 2001 (Cth). This presentation does not involve or imply a recommendation or a statement of opinion in respect of whether to buy, sell or hold a financial product. This presentation does not take into account the objectives, financial situation or needs of any person, and independent personal advice should be obtained. This presentation and its contents may not be reproduced or re-distributed in any way without the express written permission of Aurora. 1
Forward-looking information Statements in this presentation which reflect management's expectations relating to, among other things, production estimates, changes in reserves, target dates, Aurora's expected drilling program and the ability to fund development are forward-looking statements, and can generally be identified by words such as "will", "expects", "intends", "believes", "estimates", "anticipates or similar expressions. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements and may contain forwardlooking information and financial outlook information, as defined by Canadian securities laws. Statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that some or all of the reserves described can be profitably produced in the future. These statements are not historical facts but instead represent management's expectations, estimates and projections regarding future events. Although management believes the expectations reflected in such forward-looking statements and financial outlook information are reasonable, forward-looking statements and financial outlook are based on the opinions, assumptions and estimates of management at the date the statements are made, and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements and financial outlook information. These factors include risks related to: exploration, development and production; oil and gas prices, markets and marketing; acquisitions and dispositions; our ability to comply with covenants under our debt facilities; competition; additional funding requirements; our ability to raise capital and access debt and equity capital markets; reserve estimates being inherently uncertain; incorrect assessments of the value of acquisitions and exploration and development programs; environmental concerns; availability of, and access to, drilling equipment; reliance on key personnel; title to assets; expiration of licences and leases; credit risk; hedging activities; litigation; government policy and legislative changes; unforeseen expenses; negative operating cash flow; contractual risk; and management of growth. In addition, if any of the assumptions or estimates made by management prove to be incorrect, actual results and developments are likely to differ, and may differ materially, from those expressed or implied by the forward-looking statements and financial outlook information contained in this document. Such assumptions include, but are not limited to, general economic, market and business conditions and corporate strategy. Accordingly, readers are cautioned not to place undue reliance on such statements. Further, the financial outlook information regarding future production and future production revenue is included to assist readers in assessing the potential impact of current drilling plans on our performance and may not be appropriate to be relied on for any other purposes. All of the forward-looking information and financial outlook in this presentation is expressly qualified by these cautionary statements. Forward-looking information and financial outlook contained herein is made as of the date of this document and Aurora disclaims any obligation to update any forward-looking information or financial outlook, whether as a result of new information, future events or results or otherwise, except as required by law. In relation to details of the forward looking drilling program, management advises that this is subject to change as conditions warrant, and we can provide no assurances that this number of rigs will be available or will be utilised or than any targeted well count will be achieved. 2
Non-GAAP Financial Measures Non-GAAP Financial Measures References are made in this presentation to certain financial measures that do not have any standardized meanings prescribed by generally accepted accounting principles ( GAAP ). Such measures are neither required by, nor calculated in accordance with, IFRS and therefore are considered non-gaap financial measures. Non- GAAP financial measures may not be comparable with the calculation of similar measures by other companies. Funds from Operations and EBITDAX are commonly used in the oil and gas industry. Funds from Operations represent funds provided by operating activities before changes in non-cash working capital. EBITDAX represents net income (loss) for the period before income tax expense or benefit, gains and losses attributable to the disposal of projects, finance costs, depletion, depreciation and amortization expense, other non-cash charges, expenses or income, one-off or non-recurring fees, expenses and charges and exploration and evaluation expenses. The Company considers Funds from Operations and EBITDAX as key measures as both assist in demonstrating the ability of the business to generate the cash flow necessary to fund future growth through capital investment. Neither should be considered as an alternative to, or more meaningful than net income or cash provided by operating activities (or any other IFRS financial measure) as an indicator of the Company s performance. Because EBITDAX excludes some, but not all, items that affect net income, the EBITDAX presented by the Company may not be comparable to similarly titled measures of other companies. Management also uses certain industry benchmarks such as net operating income and operating netback to analyse financial and operating performance. Net Operating Income represents net oil and gas revenue attributable to Aurora after distribution to royalty holders. Operating netback, as presented, represents revenue from production less royalties, state taxes, transportation and operating expenses calculated on a boe basis. Management considers operating netback an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices. 3
Disclosure of Reserves; Defined Terms The reserves shown in this presentation are estimates only and should not be construed as exact quantities. Proved reserves are those reserves which can be estimated with a high degree of certainty to be recoverable; probable reserves are those additional reserves which are less certain to be recovered than proved reserves. Possible reserves are those additional reserves which are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this presentation. Estimates of reserves may increase or decrease as a result of future operations, market conditions, or changes in regulations. Unless otherwise indicated, all estimates of reserves in this presentation have been prepared or evaluated in accordance with the COGE Handbook effective as of 31 December, and are derived from the reserves report of Ryder Scott Company, L.P. ( RS ) ( RS 12.31. Report. RS are qualified independent reserves evaluators under the Canadian Securities Administrators National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Price assumptions used in the RS 12.31. Report are as follows: FY12/13/14/15/16+: Oil US$101/bbl, US$98/bbl, US$95/bbl, US$92/bbl, and US$91/bbl; and Gas US$3.3/mcf, US$3.9/mcf, US$3.9/mcf, US$3.9/mcf, and US$3.9/mcf. Defined Reserves and Resource Terms bbl means barrel. boe means barrels of oil equivalent, determined using a ratio of 6 Mcf of raw natural gas to 1 bbl of condensate or crude oil, unless otherwise stated. There are now allowances for NGLs within quoted boe figures in this presentation. scf means standard cubic feet. btu means British thermal units m prefix means thousand. mm prefix means million. b prefix means billion. pd or /d suffix means per day. NGL means Natural Gas Liquids, including condensate these products are stripped from the gas stream at 3rd party facilities remote to the field. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf : 1 bbl utilising a conversion ratio of 6 Mcf : 1 bbl may be misleading. Given the value ratio based on the current share price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl may be misleading. Unless stated otherwise all per boe references, are a reference to Aurora s per boe production on a working interest basis i.e. before royalties. 4
Overview of Aurora Oil & Gas Perth, Australia headquartered E&P company CEO, COO and most operational staff based in Houston, Texas Founded in 2005 - listed on both the ASX and TSX (now in the ASX 100 index) Stock symbols AUT.AU and AEF.TO Eagle Ford Shale - Sugarkane field operated by Marathon Oil Company First mover status on highly contiguous ~77,000 gross and 19,300 net acres in the Sugarkane field, Karnes County, TX. Significant inventory of PUD well locations based on 80 acre spacing with 40 net producing wells by end Q3 2012 Downspacing pilot program underway to investigate 40 and 60 acre spacing within Eagle Ford and additional horizons. Financially conservative Sept 30 - $143MM Cash with $173MM pro-forma liquidity - including $150MM undrawn revolver Q3 2012 revenue $85 MM, EBITDAX $50MM (1). Key Metrics Market Cap $1.6 Billion Fully Paid Ordinary Shares 448 Million Enterprise Value $1.9 Billion Net Proved Reserves (PDP & PUD) 59 MMBOE 2012 Exit Rate (net after Royalty) 13,450 BOEPD Directors own approx. 7% of the outstanding shares (1) EBITDAX is a supplemental measure of financial performance that is not required by, or presented in accordance with IFRS and is considered a non-gaap measure. See Non-GAAP Financial Measures above. A reconciliation of net earnings after tax to EBITDAX can be found on page 25. 5
Pure Play Eagle Ford Producer Sugarkane field Working Interests range from 28% 36% in Karnes County and 9.1% in Atascosa. Concentrated and contiguous 77,000 gross and 19,300 net acres principally in Karnes County, TX. 2012 exit rate projected to be 13,450 boepd (net to working interest and after royalty) being 96% liquids on a revenue basis 1P reserves of ~80MM boe (pre-royalties, 59MM boe post royalties) YE 2P reserves of ~92MM boe (pre-royalties, 67MM boe post royalties) YE 166 gross wells drilled in 2012 (YE est.) Major infrastructure installed in 2012 Activity focused on condensate and volatile oil windows Low risk, repeatable and scalable Eagle Ford inventory including over 800 gross wells on 80 acre spacing with pilot program investigating 60 and 40 acre spacing. Additional targets in Austin Chalk and Pearsall. 6
Sugarkane Infrastructure Centralized processing facilities nine now operational across the field. Scalable capacity for future production profile Large 3rd party gas and oil lines presently under construction - considerable additional capacity in area installed so far in 2012 No current take-away bottlenecks anticipated Major gas and oil marketing contracts in place with DCP, Kinder Morgan and others Oil Pipeline 60,000 bpd capacity Gas Gathering Pipeline Gas Pipeline approx 100 mmbtu capacity Central Facilities 7
Oil and Condensate Driven Capital Program Sugarkane Field 2012 Upstream capital focused on drilling the leases to held by production status HBP 85% of leasehold now HBP End Q3 there were 173 gross and 40 net wells on production (205 total gross wells drilled) Over 300 miles of gathering system and nine production facilities installed and in service Aurora acquired an additional 12.5% working interest ( via asset and corporate transactions) in Sugarloaf AMI, resulting in an 18% increase in net acres 2013 Capital Program Plans (Marathon Forecast) 40 net wells (planned) with Marathon as Operator oil and condensate focus Continue 40 and 60 acre spacing, and drilling and completion practices evaluation Continue evaluation of additional opportunities within existing leasehold Deeper Pearsall currently drilling results due after full evaluation Shallower Austin Chalk 60 acre pilot program offsetting current Austin Chalk production Capital Beyond 2013 Broad, low risk, scalable infill development focusing on oil and condensate regions Programs to optimize current production and to enhance reservoir recovery factors Patiently look to expand Eagle Ford liquids rich portfolio within Aurora s target areas 8
Marathon: Experienced partner committed to development The Eagle Ford is the top basin we have in the world today we love the geology. Q4 11 Marathon Oil Conference Call Aurora s Sugarkane acreage is operated by Marathon, a S&P 500 energy company Since Nov 11 Marathon agreed ~US$5.5 billion of acquisitions in the Eagle Ford Marathon has allocated ~US$1.5 billion of its annual capital expenditure budget to its Eagle Ford acreage for the next 5 years. Operator committed to optimising drilling, completion and production processes Aurora and Marathon have a common economic imperative for development "Our investment in the Eagle Ford shale a little more than a year ago, and our bolt-on acquisitions since then, continue to deliver value beyond original expectations. Not only have we improved the speed and efficiency of our drilling and completions there, we also continue to optimize well spacing which could significantly increase drillable locations and recoverable reserves. Marathon Oil CEO Clarence Cazalot 06.11.12 9
2012 Operational Summary Operational activity during 3 rd quarter 56 gross wells spudded 45 gross wells commenced production Production performance during 3 rd quarter Average gross production rate for Q3 2012 of approximately 12,500 boe/d and approximately 14,000 boe/d for September 2012 Increase on Q2 of 50% & 250% on Q3 Well Status end October 2012 Farmout Wells Post Farmout Wells Sugarloaf Longhorn Ipanema Excelsior Total Producing 0 3 1 0 4 Producing 46 82 6 49 183 Stimulation Underway 1 2 0 4 7 Awaiting Stimulation 8.5 8.5 0 10 27 Drilling 3 4 0 1 8 Total 58.5 99.5 7 64 229 10
Pilot Program status Q4 activity Additional activities include: Production Logging Micro Seismic Tracer monitoring Well orientation Four wells at 40 acre spacing - producing High rate well test planned Four wells at 40 acre spacing drilling or permitted Four wells at 60 acre spacing with variations in stimulation design - producing Pilot well drilling deeper horizons Two wells at 60 acre spacing with variations in stimulation placement - producing High rate well test planned Six wells at 60 acre spacing with vertical offset within Eagle Ford horizon - producing 11
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Quarterly Financial summary Selected financial data Revenue (1) EBITDAX (2) (US$ in thousands) (US$ in thousands) $85,483 $57,493 $49,916 $7,280 Q1 $39,567 $27,932 $23,187 $17,570 Q2 Q3 Q4 Q1 2012 Q2 2012 Q3 2012 $3,009 Q1 $21,378 $9,292 $13,241 $13,948 Q2 Q3 Q4 Q1 2012 $31,639 Q2 2012 Q3 2012 Revenue per unit of production (US$/boe) LTM average, 76.57 $77.04 $76.57 $70.20$71.03 $90.09$75.34$74.11 EBITDAX per unit of production (US$/boe) LTM average, 42.59 $48.73 $40.85 $40.20 $41.57 $43.29 $31.78 $35.61 Q1 Q2 Q3 Q4 Q1 2012 Q2 2012 Q3 2012 Q1 Q2 Q3 Q4 Q1 2012 Q2 2012 Q3 2012 (1) Revenue from continuing operations (2) EBITDAX is a supplemental measure of financial performance that is not required by, or presented in accordance with IFRS and is considered a non-gaap measure. See Non-GAAP Financial Measures above. A reconciliation of net earnings after tax to EBITDAX can be found on page 25. 13
US$ MM Quarterly Results Trend 90 80 70 60 50 40 30 20 10 0 Revenue EBITDAX Royalties Production and Operating Expenses (incl Sales Taxes) G&A Q1 Q2 Q3 Q4 Q1 2012 Q2 2012 Q3 2012 14
NET WELL COUNT RBL Borrowing Base Financial Liquidity US$million Cash on hand 30 September 2012 143 Trade and other receivables 73 Trade and other payables (193) Pro forma 30 September 2012 net cash 23 Undrawn Revolver Facility 150 Financial Liquidity 30 September 2012 173 60 50 40 30 20 Current Facility Limit US$ 85 MM Reduction due to initial senior high yield notes issuance Redetermination 11 May (based on YE 11 Reserves) US$ 85 MM Redetermination 16 August (based on increase in PDP) US$ 150 MM Next Redetermination Q1 2013 (based on YE 2012 reserves ) 350 300 250 200 150 100 10 50 0 Q4 Q1 2012 Q2 2012 Q3 2012 Q4 2012 (est) Net Well Count Borrowing Base RBL Current Facility Limit 0 Balance Sheet flexibility established for accelerated development and/or additional Eagle Ford opportunities RBL Borrowing base maturation generally proportional to production / PDP growth 15
Hedging Profile Swaps Zero Cost Collars Total Volume Hedged WTI (1) LLS (2) WTI (1) BBL/D oil bbls hedged gross oil bbls hedged gross oil bbls Floor Cap gross hedged price value hedged price value hedged price Price value (mbbls) $/bbl US$mm (mbbls) $/bbl US$mm (mbbls) $/bbl $/bbl US$mm Q4 2012 60 $94.5 $6 21 98.2 2 - - - - 880 2013 102 $92 $9 108 95.4 10 90 75 107 7 820 2014 78 $91 $7 - - - - - - - 210 240 $22 129 $12 90 $7 Hedge position designed to protect fixed interest costs (1) WTI refers to West Texas Intermediate crude oil (2) LLS refers to Louisiana Light Sweet crude oil 16
Key highlights 1 Pure Eagle Ford shale producer 2 Strong management team and experienced partner 3 Rapid production and reserve growth 4 Oil and condensate focused 5 Significant asset value with potential for accretive A&D and M&A 6 Fully funded 17
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Corporate summary Key Facts millions Fully Paid Ordinary Shares 448 Options on issue (varied prices) 5.5 Executive Performance Shares 1.2 Fully diluted Capital 455 September 30, 2012 pro forma working capital $23 Senior Unsecured Notes Due February 2017 $365 Revolving Credit Line Borrowing Base undrawn at September 30, 2012 - Facility limit $300mm - Borrowing Base grows with PDP $150 Board of Directors and Executive Staff Shareholding (million shares) Jon Stewart Executive Chairman Australian 19.8 Doug Brooks Chief Executive Officer American Graham Dowland Finance Director Australian 2.2 Ian Lusted Technical Director Australian 1.4 Michael Verm Chief Operating Officer American Fiona Harris Non Executive Director Australian 0.1 Gren Schoch Non Executive Director Canadian 5.9 William Molson Non Executive Director Canadian 1.5 Alan Watson Non Executive Director British 1.1 19
2012 to end Q3 Development accelerates drilling of 123 new wells at the Sugarkane field during 2012 104 new gross wells producing year to date Production Average gross production rate YTD of approximately 8,600 boe/d (90% liquids) Cumulative gross production 2.35 MMboe Accretive acquisitions mid year 2012 Increased working interest in Sugarkane Field (12.25% WI in the Sugarloaf AMI ) Approx 18% increase in net acres (~2900 net acres) Total acquisition cash costs of ~US$200 million Liquidity increased to fund development US$365 million in senior unsecured notes issued (Feb and Jul 2012) RBL borrowing base increased mid year from US$85 million to US$150 million A$124 million equity issue 2 nd Qtr 2012 Funding to maintain flexible and strong liquidity post Sugarloaf WI acquisitions 20
2012 to date continued Financial performance to Q3 2012: Q3 US$mm Increase from Q2 Year to Date US$mm Increase from corresponding period Revenue 85 50% 182 280% EBITDAX (1) (2) 50 60% 103 300% NPAT (1) (2) 16 60% 35 35% Drilling and field Capex for 9 months to September 30, 2012 of US$310 million Acreage 86% held by production as at end Q3 2012 Inclusion in ASX 100 index YE11 Reserves - Proved reserves 80.4 MMboe before royalties (3) 1. EBITDAX is a supplemental measure of financial performance that is not required by, or presented in accordance with IFRS and is considered a non-gaap measure. See Non-GAAP Financial Measures above. 2. A reconciliation of net earnings after tax to EBITDAX can be found on page 25. 3. Does not include reserves attributable to 2012 acquisitions 21
2012 Full Year Guidance Production Range (1) Estimated annual production (MMboe) of 3.7 4.1 gross, 2.8 3.0 net Estimated December month average production rate (boe/d) 17,300 19,100 gross, 12,800 14,100 net 2012 Guidance: PRIOR GUIDANCE (net) UPDATED GUIDANCE (net) (2) Exit Cumulative Average Dec 12 Month Average Cumulative Average Oil & Condensate 7800 bbl/d 2 MMbbl 5,500 bbl/d 8650 bbl/d 2 MMbbl 5,400 bbl/d NGL 2100 bbl/d 0.40 MMbbl 1,100 bbl/d 2100 bbl/d 0.4 MMbbl 1,100 bbl/d Gas 22.2 MMscf/d 4300 MMscf 11.7 MMscf/d 16.4 MMscf/d 3200 MMscf 8.8 MMscf/d BOE 13,500 boe/d 3.1 MMboe 8,600 boe/d 13,450 boe/d 2.9 MMboe 8,000 boe/d Capex $320 million for drilling and completions in line with budget $80 million for facilities (in field infrastructure and gathering system capital spend accelerated into current year) EBITDAX guidance of US$143-158 million Effective Tax Rate (P&L) of 36-38% - no company income taxes paid on cash basis 1 Based on assumption of 11.7 new net wells on production during Q4 2012 2 Values in table represent mid point within above stated production ranges 22
2013 Provisional Plans (1) Pilot Program Continue spacing and completion evaluation with further wells likely Continue evaluation of deeper horizons Carry out Austin Chalk pilot program on 60 acre spacing Drilling Schedule Marathon has indicated a plan to spud 139 gross (39.4 net) wells during 2013 on Aurora s acreage This compares to 158 gross (35 net) wells initially planned for 2012 AMI WI 2013 Drilling Schedule Gross Wells Net Wells Sugarloaf 28.1% 64 18.0 Longhorn 31.9% 46 14.7 Excelsior 9.1% 14 1.3 Ipanema 36.4% 15 5.4 Total 139 39.4 1 Please refer to Forward -looking information above 23
Financial summary Selected financial data Selected financial data (US$ in Thousands) Qtr Dec-11 Qtr Mar-12 Qtr Jun-12 Qtr Sep-12 12 Months to Sep-12 PRODUCTION: Total net production (boe) - pre-royalty 391,645 438,726 761,124 1,152,944 2,744,439 Total net production (boe) - post-royalty 288,400 319,044 559,468 852,840 2,019,752 Daily production (boe/d) - pre-royalty 4,257 4,821 8,364 12,532 7,519 Daily production (boe/d) - post-royalty 3,135 3,506 6,148 9,270 5,534 REVENUES: $/boe $/boe Oil and gas revenues 27,820 39,523 57,341 85,452 $74.12 $76.57 Royalties (7,277) (10,392) (15,403) (22,528) ($19.54) ($20.26) Net Operating Income (1) 20,543 29,131 41,938 62,924 $54.58 $56.31 EXPENSES: Operating expenses (1,989) (3,569) (4,999) (7,417) ($6.43) ($6.55) Production taxes (1,060) (1,382) (1,907) (2,925) ($2.54) ($2.65) Operating Netback (1) 17,494 24,180 35,032 52,582 $45.61 $47.11 Administrative expenses (3,546) (2,802) (3,393) (2,666) ($2.31) ($4.52) EBITDAX (1) (2) 13,948 21,378 31,639 49,916 $43.29 $42.59 Depreciation and depletion (non cash) (2,051) (2,758) (7,250) (14,117) ($12.24) ($9.54) Other Income 336 97 5,063 58 $0.05 $2.02 Interest expense (70) (2,873) (4,910) (7,637) ($6.62) ($5.64) Amortisation of Borrowing Costs (non cash) (66) (360) (612) (1,419) ($1.23) ($0.90) Share based payments expense (non cash) (1,398) (1,227) (1,078) (991) ($0.86) ($1.71) Evaluation and exploration costs (637) (479) (2,564) (887) ($0.77) ($1.66) Net Earnings Before Tax 10,062 13,778 20,288 24,923 $21.62 $25.16 Tax Expense Accrual (3) (5,529) (5,073) (9,958) (8,910) ($7.73) ($10.74) Net Earnings After Tax 4,533 8,705 10,330 16,013 $13.89 $14.42 (1) EBITDAX, operating netback and net operating income are supplemental measure of financial performance that are not required by, or presented in accordance with IFRS and are considered non-gaap measures. See Non-GAAP Financial Measures above. (2) A reconciliation of net earnings after tax to EBITDAX can be found on page 26. 24 (3) This represents a movement in the deferred tax provision for future taxes payable. No income tax is expected to be due/paid in 2012 or 2013 based on the current forecast plans for 2013.
EBITDA/EBITDAX reconciliation (1) Nine months ended Three months ended Sep-12 Sep-12 Jun-12 Mar-12 Dec-11 US$'000 US$'000 US$'000 US$'000 US$'000 Net earnings after tax 35,048 16,013 10,330 8,705 4,533 Adjustments: Share based payments expense 3,296 991 1,078 1,227 1,398 Depreciation and amortization expense 24,125 14,117 7,250 2,758 2,051 Interest income (224) (31) (152) (41) (112) Finance costs 17,811 9,056 5,522 3,233 136 Foreign exchange loss/(gain) (3,056) (27) (2,973) (56) (161) Gain on foreign currency derivatives not qualifying as hedge (1,167) 0 (1,167) 0 0 Other Income 0 0 0 0 (63) Net gain on sale of available for sale assets (770) 0 (770) 0 0 Income tax expense/(benefit) 23,940 8,910 9,957 5,073 5,529 EBITDA 99,003 49,029 29,075 20,899 13,311 Exploration and Evaluation costs 3,930 887 2,564 479 637 EBITDAX 102,932 49,916 31,639 21,378 13,948 (1) EBITDAX is a supplemental measure of financial performance that is not required by, or presented in accordance with IFRS and is considered a non-gaap measure. See Non-GAAP Financial Measures above. 25