Aurora Oil & Gas Limited - Jefferies

jefferies.com

Aurora Oil & Gas Limited - Jefferies

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 2011, and are derived from the reserves report of Ryder Scott Company, L.P. (“RS”) (“RS 12.31.2011 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

12.31.2011 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 2011

• 2P reserves of ~92MM boe (pre-royalties, 67MM

boe post royalties) YE 2011

• 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 2011

Well Status – end October 2012

Sugarloaf Longhorn Ipanema Excelsior Total

Farmout Wells

Producing 0 3 1 0 4

Post Farmout Wells

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


12

Financial overview

Unsaved Document / 15/08/2011 / 15:28


Quarterly Financial summary – Selected financial data

Revenue (1)

(US$ in thousands)

$57,493

$85,483

EBITDAX (2)

(US$ in thousands)

$49,916

$7,280

Q1

2011

$17,570 $23,187 $27,932 $39,567

Q2

2011

Q3

2011

Q4

2011

Q1

2012

Q2

2012

Q3

2012

$3,009

Q1

2011

$9,292 $13,241 $13,948

Q2

2011

Q3

2011

Q4

2011

$21,378

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)

$31.78

$40.85 $40.20

$35.61

LTM

average,

42.59

$48.73

$41.57 $43.29

Q1

2011

Q2

2011

Q3

2011

Q4

2011

Q1

2012

Q2

2012

Q3

2012

Q1

2011

Q2

2011

Q3

2011

Q4

2011

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


Quarterly Results Trend

US$ MM

90

80

70

60

50

40

30

20

10

0

Revenue

EBITDAX

Royalties

Production and Operating Expenses (incl Sales Taxes)

G&A

Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012

14


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

NET WELL COUNT

60

50

40

30

20

10

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

50

RBL Borrowing Base

0

Q4 2011 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


18

Appendix

Unsaved Document / 15/08/2011 / 15:28


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

More magazines by this user
Similar magazines