Company Announcements Platform Australian Securities … · 29/04/2013 · 29 April 2013 Company...

29 April 2013 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 this week at investor updates in Australia. 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 20 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.

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Morgan Stanley 2013 Shale Gas & Oil Forum Sydney, Australia

April 30, 2013

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www.auroraoag.com.au | ASX: AUT | TSX: AEF

Disclaimer This document has been prepared by Aurora Oil & Gas Limited (“Aurora”) to provide an overview to interested analysts / investors 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.

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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 forward-looking 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; changes in the rate and /or location of future drilling programs on our acreage by our operator(s); 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 that any targeted well count will be achieved.

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Non-IFRS Financial Measures References are made in this presentation to certain financial measures that do not have any standardized meanings prescribed by International Financial Reporting Standards (“IFRS”). Such measures are neither required by, nor calculated in accordance with IFRS, and therefore are considered non-IFRS financial measures. Non-IFRS 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.

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Disclosure of Reserves; Defined Terms

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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 2012, and are derived from the January 30, 2013 reserves report as at December 31, 2012 as prepared by Ryder Scott Company, L.P. (“RS”) (“RS 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 Report are as follows (FY13/14/15/16/17+): Oil US$101.00/bbl, US$100.00/bbl, US$98.00/bbl, US$96.00/bbl, and US$95.00/bbl; and Natural gas US$3.60/mscf, US$4.00/mscf, US$4.20/mscf, US$4.40/mscf, and US$4.60/mscf.

Defined Reserves and Resource Terms “AMI” means Area of Mutual Interest “bbl” means barrel. “boe” means barrels of oil equivalent, and have been calculated using liquid volumes of oil, condensate and NGLs and treated volumes of gas converted using a ratio of 6 mscf

to 1 bbl liquid equivalent, unless otherwise stated. “scf” means standard cubic feet. “btu” means British thermal units “M” or “m” prefix means thousand. “MM” or “mm” prefix means million. “B” or “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. “$” or “US$” means United States (US) dollars, unless otherwise stated.

Other defined terms “CAGR” means compounded annual growth rate “CQGR” means compounded quarterly growth rate “NPBT” means net profit before tax “NPAT” means net profit after tax “Sugarkane” or “Sugarkane Field” means the Sugarkane Cretaceous Field within the Eagle Ford and includes the two contiguous fields designated by the Texas Railroad

Commission as the Sugarkane and Eagleville Fields.

Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mscf:1 bbl 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 mscf:1 bbl, utilising a conversion ratio of 6 mscf: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 before deduction of royalties.

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Pure Eagle Ford Shale producer

Rapid production, revenue and profit growth

Oil and condensate focused growth in reserves

Strong management team and experienced partner

Significant asset value

Fully funded

Key Highlights

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EBITDAX(2)

Production

EBITDAX per boe (2)

Net Profit after Tax

Funds from Operations(2)

Net Wells on Production

2012 Results at a Glance(1)

6

320%

300%

92%

274%

12%

251%

(1) Year over year increases from December 31, 2011 to December 31, 2012 (2) EBITDAX and funds from operations are supplemental measures of financial performance

that are not required by, or presented in accordance with IFRS and are considered a non-IFRS measures. See “Non-IFRS Financial Measures” above. A reconciliation of net profit after tax to EBITDAX can be found in the appendices.

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Annual Production

Exit production

Net wells on production

2013 Guidance at a Glance(1)

7

93%

45%

95%

1. 2013 guidance per ASX and TSE release dated March 28, 2013. 2. Year over year increases from December 31, 2012 to midpoint of guidance range

estimate at December 31, 2013

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Eagle Ford Focused

Developing highly contiguous ~79,700 gross (21,800 net) acres in the Sugarkane field – including recently announced acquisition

Current production: ~15,250 net boe/d ~20,000 gross boe/d

Current proved reserves (mmboe)

Strong liquidity position (cash US$177 mm as at March 31, 2013) with undrawn US$200 mm credit facility

58 net wells producing at end Q1 3013

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(1) Percentage equivalent volume from liquid hydrocarbons based on 2012 production

(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-IFRS measure. See “Non-IFRS Financial Measures” above. A reconciliation of net profit after tax to EBITDAX can be found in the appendices.

(3) Gross wells

KEY METRICS Market Cap (US$) $1.37 billion

FY2012 EBITDAX(2) (US$) $167 million

Eagle Ford Inventory (80 acre spacing) (3)

~800 proved wells

2012 Average Production (pre-royalty) 10,700 boe/d

2012 Average Production (post-royalty) 7,900 boe/d

Year on year reserve growth ~ 19%

Q1 2013 average production (pre-royalty) 18,655 boe/d

Q1 2013 average production (post-royalty) 13,763 boe/d

2013 Q1 production (pre-royalty) 1.68 mmboe

2013 Q1 production (post-royalty) 1.24 mmboe

Non Operated Operated

Pre-royalty 94.7 8.9

Post-royalty 69.9 6.7

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2013 Guidance

Spud 45 to 50 net wells

14 to 19 operated

30 to 32 non-operated

Capex budget of $430-465mm

Dec 2013 average production of 23 to 25 gross (17 to 19 net) mboe/d

2013 total production guidance of 7.2 to 8.0 gross (5.3 to 5.9 net) mmboe.

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AVGQ1 '12

AVGQ2 '12

AVGQ3 '12

AVGQ4 '12

2013EExitRate

3,506

6,148

9,266

12,474

Estimated 2013 Total Production (net mmboe)

2010 2011 2012 2013E

2.9

0.0 0.8

5.3 - 5.9

Budget Weighted to Second Half of 2013

Q1 2013 Q2 2013 Q3 2013 Q4 2013

9 4

7

11

9

10

Net Operated Spudded WellsNet Non-Operated Spudded Wells

18,000(1)

Average Net Quarterly Production 2012, Exit 2013

(1) Estimated exit rate is shown as the mid point of Dec 2013 average production of 17,000 to 19,000 net boe/d

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Operated Position

100% operated interest in ~2,700 net acres - all held by production(1)

Approximately 1,620 net boe/d from 11 wells (2)

6.7 mmboe net 1P reserves(2)

Austin Chalk (Axle Tree) & Pearsall (Heard Ranch) potential

Interests in facilities and marketing arrangements

2 to 3 rig operating program planned during 2013/14

14 to 19 net wells planned for 2013

Development plan on 40 acre spacing

Utilize knowledge from ~250 nearby wells

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ADVANTAGES OF OPERATING

Optimize developmental control

Diversify capital allocation

Increased working interest

Predictable timing of cash flows

1) Acquired effective March 1,2013. 2) Based on Aurora internal estimates as at December 31, 2012. 3) Jointly owned by Marathon except for Heard Ranch and Axel Tree properties.

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Non-Operated Position

Low risk, repeatable Eagle Ford inventory

19,100 net acre n position

~789(1) gross proved well locations on predominantly 80 acre spacing

WI% from 28% to 36% in Karnes, and 9.1% in Atascosa Counties

Q1 ’13 production stream averaged 34% oil, 30% condensate, 16% NGLs and 20% natural gas

2012 EBITDAX / boe(3) of US$42.85

30 to 32 net wells planned for 2013

8.9 net wells spudded Q1 2013.

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ADDITIONAL EVALUATIONS Testing 60 and 40 acre Eagle Ford spacing via multiple Pilot Programs

Austin Chalk Pilot Programs underway

Pearsall potential being evaluated

Wellbore orientation, fracture stimulation techniques, production optimization

1) PDP and PUD locations from RS Report. Includes 4 wells in payout under Sugarkane Farmout Agreement with Hilcorp Energy I L.P.

2) Jointly owned with Marathon Oil and others. 3) EBITDAX is a supplemental measure of financial performance that is not required by, or

presented in accordance with IFRS and is considered a non-IFRS measure. See “Non-IFRS Financial Measures” above. A reconciliation of net profit after tax to EBITDAX can be found in the appendices.

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Return Focused and Disciplined Capital Program

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Drilled Leases to HBP Status • ~ 90% leasehold HBP • 216 gross and 50 net wells

producing • Infield gathering system and

nine production facilities in service

• Acquired an additional 12.25% WI in Sugarloaf AMI for an 18% increase in net acres

Capital Beyond 2013

• Broad, low risk, scalable infill development

• Focusing on oil and condensate

• Optimize current production and enhance reservoir recovery factors

• Patiently look to expand Eagle Ford liquids rich portfolio within Aurora’s target areas

Eagle Ford Development and Efficiencies • Drill 45 -50 net wells at Sugarkane • Increase lateral length reducing

average per foot well cost • Develop operated asset on 40 acre

spacing • Determine optimised drilling and

completion practices • Pearsall Shale – recent pilot well

drilled – results after full evaluation • Shallower Austin Chalk – two 60 acre

pilot programs offsetting current Austin Chalk production

2012

2013

Beyond

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Operational Summary

13 (1) Excludes 4 gross wells in payout under Sugarkane Farmout Agreement with Hilcorp Energy I, L.P.

Gross Well Status March 31, 2013

Sugarloaf (28.1%)

Longhorn (31.9%)

Ipanema (36.4%)

Excelsior (9.1%)

Total

Producing 66 112 7 67 252

Stimulation Underway 0 2 0 0 2

Awaiting Stimulation 3 10 0 1 14

Drilling 1 8 0 1 10

Total 70 132 7 69 278

0

50

100

150

200

250

300

Q42010

Q12011

Q22011

Q32011

Q42011

Q12012

Q22012

Q32012

Q42012

Q12013

6 9 27

48 66

84

124

169

216

252

Ipanema Excelsior Longhorn Sugarloaf

Gross Producing Well count 7

66

112

67

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Reserves – Non operated Dec 31, 2012

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(1) Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will be equal to or exceed the sum of the proved plus probable plus possible reserves.

(2) Adjusted for 2012 production

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Extensive Pipeline Infrastructure Centralized processing facilities – nine

operational across the field

Scalable capacity for future production profile

Large 3rd party gas and oil lines presently under construction - considerable additional capacity installed in 2012

No current take-away bottlenecks occurring or anticipated

Major gas and oil marketing contracts in place with DCP, Kinder Morgan, Three Rivers and other

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Source: Company information.

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Acreage and resource

Aurora highly encouraged by results to date from downspacing pilot program

Additional activities include:

Production logging

Micro seismic

Tracer monitoring

Well orientation

More wells with minimal negative impact on performance adds value

Clear that < 80 acre spacing will be used – to date over 70 wells drilled on < 80 acres

Remains too early to definitively say final spacing across the non operated acreage position – further data from downspaced wells and the Austin Chalk wells need to be considered.

Aurora operated acreage in the volatile oil window to be developed on 40 acre spacing

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Eagle Ford Infill Opportunities(1)

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~ 175’

660’ between wells 80 acre

EAGLE FORD

~10,000’ – ~12,000’ vertical

60 acre 500’ between wells

Well Spacing

40 acre

330’ between wells

330’ 40 ac

660’ 80 ac

500’ 60 ac (1) For illustrative purposes only.

Not to scale.

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Austin Chalk Horizontal Potential(1)

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~ 175’

EAGLE FORD

~ 9,650’ – ~11,650’ vertical

660’ 80 ac

500’ 60 ac

~ 160’

AUSTIN CHALK

330’ 40 ac

660’ between wells 80 acre

60 acre 500’ between wells

40 acre

330’ between wells

330’ 40 ac

Well Spacing

(1) For illustrative purposes only. Not to scale.

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Aurora’s non-operated Sugarkane acreage is operated by Marathon (S&P 500 )

Since Nov ‘11 Marathon has agreed ~US$5.5b of acquisitions in the Eagle Ford

Increased its 2013 Eagle Ford capital expenditure budget from ~US$1.5 to ~US$1.9b

Operator committed to optimising drilling, completion and production processes

Aurora and Marathon have a common economic imperative for development

Marathon: An Experienced Partner

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“The Eagle Ford is the top basin we have in the world today…we love the geology.” Q4 ‘11

Marathon Oil Conference Call

“We are indeed in some of the best real estate in North America, if not the world today.” Q4 ‘12 Marathon Oil Conference Call

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Financial overview

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1) The revolving credit facility is a secured Reserve Based Lending (RBL) facility subject to borrowing base redeterminations generally proportional to production/PDP growth. On February 27, 2013, the amount available was increased from US$150 to US$275 million. Following the issue of the US$300 million unsecured notes in March 2013, the borrowing base under the RBL was reduced to US$200 million. As at December 31, 2012 US$30 million had been drawn down under this facility. Since December 31, 2012 a further US$30 million was drawn, and following the unsecured notes issue in March 2013, the RBL borrowings were repaid.

Financial Liquidity

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Funding in place exceeds forecast working capital requirements and capital forecast RBL in place at US$200 mm (undrawn) Closed on US$300 mm Notes offering at 7.5% coupon

Pro forma December 31, 2012 US$ mm

Cash on hand 68

Trade and other receivables 90

Trade and other payables (181)

Working capital as at December 31, 2012 (23)

March 2013 acquisition (cost) (115)

$300 mm notes issue – March 2013 (net of costs) 293

Repayment of borrowings (60)

Revolving credit facility (RBL) availability 200

Pro forma Financial Liquidity 295

Q1 2013 update

Cash balance at March 31, 2013 177

Revolving credit facility (RBL) availability 200

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Balance sheet - Debt Notes - unsecured

US$365 million 9.875% pa due Feb 2017

US$300 million 7.5% pa due April 2020

Fixed term & fixed coupon debt issued to

over 80 institutional bond investors

Less restrictive on Aurora business or assets

than bank facilities

Reserve Based Borrowing (Revolver) availability – secured

US$200 million available from a syndicate of US and international banks

Currently undrawn

Floating interest rate – Libor plus 1% - 3%

Flexible financing – draw and repay at any time

Borrowing base grows in line with value of producing reserves

Financial Covenants – includes cashflow and earnings to interest, and total debt

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(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” in the disclaimers . A reconciliation of net earnings after tax to EBITDAX is detailed in the appendices

Debt Metrics

A. Fixed Interest costs = US$58.6 million pa

B. Q4 2012 EBITDAX(1) annualised = $258 million

C. Total Debt = US$665 million

Total Debt to Q4 2012 EBITDAX(1) annualised C / B = 2.6X

Q4 2012 EBITDAX(1) annualised to Interest B / A = 4.4x

Debt levels are modest by US E&P standards and debt and interest coverage is strong, particularly based on continuing growth in production and EBITDAX F

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Framework for Growth

23 1) Revenue from continuing operations and before royalties

2013 average net production estimated to be 14,500 – 16,200 boepd versus 2012 average of 7,900boepd

Q1'12

Q2'12

Q3'12

Q4'12

Q1'13

$39.5

$54.3

$85.5

$112.5

$127.5

Revenue(1) (US$ mm) Revenue(1) (US$ mm)

Q1'12

Q2'12

Q3'12

Q4'12

Q1'13

3,506

6,148

9,266

12,474

13,763

Average Production (net boepd)

Q1'12

Q2'12

Q3'12

Q4'12

$8.7

$10.3

$16.0

$23.8

Net Profit After Tax (US$ mm)

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Netbacks and Commodity Mix (2012)

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Net

bac

ks

Based on gross 2012 production of 3.9 mmboe

Operating Netback US$46.72/boe

NPAT US$15.06/boe

EBITDAX US$42.85/boe

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Pure Eagle Ford Shale producer

Rapid production, revenue and profit growth

Oil and condensate focused growth in reserves

Strong management team and experienced partner

Significant asset value

Fully funded

Summary

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Appendices For

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Corporate Summary

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Key Facts millions

Fully paid ordinary shares 448

Options on issue (varied prices) 6.3

Executive Performance Rights (1) 3.1

Fully diluted capital 456

Cash Balance - March 31, 2013 US$ 177

Senior Unsecured Notes Due February 2017 US$ 365

Senior Unsecured Notes Due April 2020 US$ 300

Revolving Credit Line Borrowing Base - Facility limit US$300 mm - Borrowing Base (grows with PDP)

US$ 200

Board of Directors and Executive Staff Shareholding

(million shares)

Jon Stewart Executive Chairman Australian 19.75

Douglas E. Brooks Chief Executive Officer American 0.01

Graham Dowland Finance Director Australian 2.20

Ian Lusted Technical Director Australian 1.42

Michael Verm Chief Operating Officer American 0.01

Fiona Harris Non Executive Director Australian 0.15

Gren Schoch Non Executive Director Canadian 6.00

William Molson Non Executive Director Canadian 1.52

Alan Watson Non Executive Director British 1.05

(1) 0.9 million performance are subject to shareholder approval at 2013 AGM.

Available but not drawn

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2012 Summary Development accelerates

Spudded 160 new gross wells at the Sugarkane field during 2012

148 new gross wells producing (plus 2 farmout wells completed payout) giving a total increase of 38.5 net producing wells.

Production

Average gross production rate (pre-royalty) of approximately 10,700 boe/d (net 7,900 boe/d)

Cumulative gross production 3.91 mmboe (net 2.88 mmboe)

Accretive acquisitions – mid year 2012

Increased working interest in Sugarkane Field (12.25% WI in the Sugarloaf AMI )

Approximately 18% increase in net acres (~2,900 net acres)

Total acquisition cash costs of ~US$200 mm

Liquidity increased to fund development

US$365 mm in senior unsecured notes issued (Feb and Jul 2012)

RBL borrowing base increased from US$85 mm to US$150 mm

A$ 124mm equity issue – Q2 2012

Funding to maintain flexible and strong liquidity post Sugarloaf WI acquisitions

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Quarterly Production Growth

29

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

Q1 '1

2(n

et)

Q1 '1

2(gro

ss)

Q2 '1

2(n

et)

Q2 '1

2(gro

ss)

Q3 '1

2(n

et)

Q3 '1

2(gro

ss)

Q4 '1

2(n

et)

Q4 '1

2(gro

ss)

Q1 '1

3(n

et)

Q1 '1

3(gro

ss)

Ave

rage

Dai

ly P

rod

uct

ion

(b

oe/

d)

Average daily liquids hydrocarbons (boe/d)

Average daily gas rate (boe/d)

Aurora Quarterly Net and Gross Daily Production

2012 / 2013

5.1 7.9 10.5 14.0 9.3

Incremental net producing F

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EBITDA/EBITDAX Reconciliation(1)

30

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-IFRS measure. See “Non-IFRS Financial Measures” above.

Twelve months

endedDec-12 Dec-12 Sep-12 Jun-12 Mar-12US$'000 US$'000 US$'000 US$'000 US$'000

Net profit after tax 58,846 23,798 16,013 10,330 8,705Adjustments:

Share based payment expense 4,398 1,102 991 1,078 1,227Depletion, depreciation and amortisation expense 39,161 15,036 14,117 7,250 2,758Interest income (247) (23) (31) (152) (41)Finance costs 28,027 10,216 9,056 5,522 3,233Net foreign exchange (gain)/ loss (3,042) 13 (27) (2,972) (56)Gain on foreign currency derivatives not qualifying as hedge (1,167) 0 0 (1,167) 0Other income (29) (28) 0 (1) 0Net gain on sale of available for sale assets (770) 0 0 (770) 0Income tax expense 37,356 13,416 8,910 9,957 5,073

EBITDA 162,533 63,530 49,029 29,075 20,899Exploration and evaluation costs 4,939 1,009 887 2,564 479

EBITDAX 167,472 64,539 49,916 31,639 21,378

Three months ended

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Funds from Operations Reconciliation(1)

31

1) Funds from Operations is a supplemental measure of financial performance that is not required by, or presented in accordance with IFRS and is considered a non-IFRS measure. See “Non-IFRS Financial Measures” above.

Dec 31, 2012 Dec 31, 2011US$'000 US$'000

Net profit after tax 58,846 30,584Add/(less) non-cash items

Depletion, Depreciation and amortisation expense 39,161 4,367Amortisation of borrowing costs and discount /premium on financial instruments 2,927 66Share based payment expense 4,398 4,052Income tax expense 37,356 1,643Net Foreign exchange (gain) (3,042) (989)Employee Benefit Provision 242 92

Funds from Operations 139,888 39,815

Twelve months ended

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Company Announcements Platform Australian Securities … · 29/04/2013 · 29 April 2013 Company...

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