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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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)
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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)
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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
28
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www.auroraoag.com.au | ASX: AUT | TSX: AEF
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
or p
erso
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se o
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www.auroraoag.com.au | ASX: AUT | TSX: AEF
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$'000
Net profit after tax 58,846 23,798 16,013 10,330 8,705Adjustments:
Share based payment expense 4,398 1,102 991 1,078 1,227Depletion, depreciation and amortisation expense 39,161 15,036 14,117 7,250 2,758Interest income (247) (23) (31) (152) (41)Finance costs 28,027 10,216 9,056 5,522 3,233Net foreign exchange (gain)/ loss (3,042) 13 (27) (2,972) (56)Gain on foreign currency derivatives not qualifying as hedge (1,167) 0 0 (1,167) 0Other income (29) (28) 0 (1) 0Net gain on sale of available for sale assets (770) 0 0 (770) 0Income tax expense 37,356 13,416 8,910 9,957 5,073
EBITDA 162,533 63,530 49,029 29,075 20,899Exploration and evaluation costs 4,939 1,009 887 2,564 479
EBITDAX 167,472 64,539 49,916 31,639 21,378
Three months ended
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www.auroraoag.com.au | ASX: AUT | TSX: AEF
Funds from Operations Reconciliation(1)
31
1) Funds from Operations is a supplemental measure of financial performance that is not required by, or presented in accordance with IFRS and is considered a non-IFRS measure. See “Non-IFRS Financial Measures” above.
Dec 31, 2012 Dec 31, 2011US$'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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