Aurora Oil & Gas - Credit Suisse

DISCLOSURE APPENDIX CONTAINS ANALYST CERTIFICATIONS AND THE STATUS OF NON-US ANALYSTS. U.S. Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

23 May 2011Asia Pacific/Australia

Equity ResearchOil & Gas Exploration & Production

Aurora Oil & Gas (AUT.AX / AUT AU) INITIATION

In the Eagle Ford Sweet Spot ■ Initiate on AUT with A$3.60 Target Price, OUTPERFORM rating: In our

view Aurora’s 15,760 net acres is in the sweet spot of the Eagle Ford Shale in Texas, USA. The acreage contains a high proportion of liquids (oil and condensate), which is proving to be highly economic despite current US gas prices. Well paybacks range from five to14 months.

■ Paying full price for base value, but considerable upside remains: After a substantial re-rating in the company’s share price in 2010 (up over 1,000% since 1 Jan 2010), we see the current share price factors in full value for the company’s base valuation. But upside should come through the increase in production rates and total oil and gas recovery over time. 900 development wells are to be drilled as a minimum, with plenty more if closer spaced wells prove economic. Current 3P reserves (representing less than 5% of oil and 10% of gas in place) will largely be reclassified as 2P by the end of 2011.

■ 60 wells to be drilled in 2011 and HiWAY fracs trialled: Aurora’s production profile and revenues will ramp-up aggressively over 2011 as 60 development wells are drilled, primarily to hold acreage through production. A trial will commence shortly on the use of HiWAY fracture stimulation technology, which could result in increased production rates and reserves. AUT should exit 2011 with net production of 5,000 BOEPD and increasing.

■ Our A$3.60/share target price is based on a risked SOTP valuation of $3.58/share: Our DCF valuation is prepared in USD and is converted to AUD at an exchange rate of 1.05 to generate our target price. Our base valuation is A$2.84/share with a risked valuation of $3.58/share and unrisked valuation of A$5.39/share. We initiate our coverage with a target price of $3.60/share and an OUTPERFORM rating.

Share price performance

0246

May-09 Sep-09 Jan-10 May-10 Sep-10 Jan-110

1000

2000Price (LHS) Rebased Rel (RHS)

The price relative chart measures performance against the S&P AUST INDEX ASX 200 INDEX which closed at 4732.19 on 20/05/11 On 20/05/11 the spot exchange rate was A$.94/US$1

Performance Over 1M 3M 12M Absolute (%) -3.1 -8.1 293.1 Relative (%) 0.6 -4.6 283.2

Financial and valuation metrics

Year 12/10A 12/11E 12/12E 12/13EProduction (mmboe) — 1.1 4.1 6.3Revenue (US$mn) 0.6 76.6 293.2 535.7EBITDAX (US$mn) -6.0 50.5 195.6 291.3EBIT (US$mn) -6.5 48.2 188.5 344.5Net income (US$mn) -5.9 49.8 180.5 258.9EPS (CS adj.) (USc) -2.02 12.26 44.06 63.21Change from previous EPS (%) n.a. — — —Consensus EPS (USc) n.a. 13.15 27.72 38.28EPS growth (%) n.a. 708.0 259.3 43.5P/E (x) NM 24.8 6.9 4.8Dividend (USc) — — — —Dividend yield (%) — — — —EV/EBITDAX -196.7 23.3 5.8 3.1Net debt/equity (%) net cash net cash 0.73 net cash

Source: Company data, ASX, Credit Suisse estimates, * Adj. for goodwill, notional interest and unusual items. Relative P/E against ASX/S&P200 based on pre GW in AUD. Company PE calculation is based on displayed EPS Currency

Rating OUTPERFORM* [V] Price (20 May 11, A$) 2.85 Target price (A$) 3.60¹ Market cap. (A$mn) 1,150.51 Yr avg. mthly trading (A$mn) 4 Last month's trading (A$mn) 2 Projected return: Capital gain (%) 26.3 Dividend yield (net %) — Total return (%) 26.3 52-week price range 0.69-3.32 * Stock ratings are relative to the relevant country benchmark. ¹Target price is for 12 months. [V] = Stock considered volatile (see Disclosure Appendix).

Research Analysts Nik Burns

Joint Lead Analyst 61 3 9280 1641

[email protected]

Sandra McCullagh Joint Lead Analyst

61 2 8205 4729 [email protected]

23 May 2011

Aurora Oil & Gas (AUT.AX / AUT AU) 2

Table of contents Executive summary 4 Investment thesis 5

Base case reserves 5 Upside 1 – Higher EURs should be achievable… 8 …as production is already running above base case 9 Upside 2 – ready to trial closer spaced drilling 9 Upside 3: Trialling new fraccing technology 10 Further upside exists – not included in our valuation 11 Acquisitions to diversify and increase production 12 Funding in place 12

Valuation, catalysts and risks 13 Valuation methodology and assumptions 13 Catalysts 15 Risks 15

Financials and key drivers 17 Appendix 1 – Valuation detail 18

Valuation Assumptions 18 Valuation Scenarios 20 Valuation Outputs 20

Appendix 2 – Shale 25 What is shale? 25 Shale development 26 Shale production characteristics 26 Shale plays in the USA 27 Eagle Ford Shale 28 Sugarkane area Eagle Ford shale characteristics 31 ASX-listed companies operating in the Eagle Ford 31 How are reserves determined? 32

Appendix 3 – Aurora Oil & Gas 33 Hilcorp Energy 34 Acquisitions 34

23 May 2011


Figure 1: Financial summary Aurora Oil & Gas AUT.AXIn USDmn, unless otherwise stated Year ending 31 Dec Share Price: 2.85

Profit & Loss 2010A 2011F 2012F 2013F 2014F Financial Summary 2010A 2011F 2012F 2013F 2014FSales revenue 0.6 76.6 293.2 535.7 717.3 c_I_REPReported NPAT mn -5.9 48.6 180.5 258.9 331.8EBITDA -6.0 50.5 202.9 376.4 506.2 c_I_NPACredit Suisse NPAT mn -5.9 49.8 180.5 258.9 331.8Depr. & Amort. 0.5 2.4 14.4 31.8 53.8 c_EPS* Credit Suisse EPS c -2.0 12.3 44.1 63.2 81.0Goodwill amort. 0.0 0.0 0.0 0.0 0.0 EPS growth % 708.0 259.3 43.5 28.1EBIT -6.5 48.2 188.5 344.5 452.4 c_PE P/E x -150.6 24.8 6.9 4.8 3.7Associates 0.0 0.0 0.0 0.0 0.0 0 P/Earnings Growth x 0.0 0.0 0.1 0.1Net interest -0.5 -1.6 0.7 0.6 -4.9Reported PBT -5.9 49.8 187.8 344.0 457.3 (c_DPS/Dividend payout ratio % 0.0 0.0 0.0 0.0 0.0Income tax 0.0 0.0 7.4 85.0 125.5 c_DPS* DPS c 0.0 0.0 0.0 0.0 0.0Profit after tax -5.9 49.8 180.5 258.9 331.8 c_DPS/SYield % 0.0 0.0 0.0 0.0 0.0Minorities 0.0 0.0 0.0 0.0 0.0 ALT(c_FFranking % 0.0 0.0 0.0 0.0 0.0Preferred dividends 0.0 0.0 0.0 0.0 0.0Normalized NPAT -5.9 49.8 180.5 258.9 331.8 c_CPS* Operating CFPS c -0.3 10.3 37.6 61.7 87.3Analyst adjustments 0.0 0.0 0.0 0.0 0.0 SHARE_P/OCF x -1,183.2 29.5 8.1 4.9 3.5Unusual item after tax 0.0 -1.2 0.0 0.0 0.0 EV/EBITEV/EBITDA x -196.7 23.3 5.8 3.1 2.3Reported NPAT -5.9 48.6 180.5 258.9 331.8 c_FCF_ FCF yield % -15.1 -6.3 -0.9 7.1 14.7

Balance Sheet Financial RatiosCash & equivalents 46.0 38.2 46.5 84.7 268.0 Profitability RatiosInventories 0.0 1.1 3.5 5.8 7.5 EBITDAEBITDA margin % -956.6 66.0 69.2 70.3 70.6Receivables 0.6 23.1 63.7 101.5 126.2 EBIT_MEBIT margin % -1,028.9 62.9 64.3 64.3 63.1Other current assets 0.0 0.0 0.0 0.0 0.0 c_ROE*Return on equity % -2.9 17.1 38.2 35.4 31.2Current assets 46.6 62.4 113.7 192.0 401.7 c_ROA*Return on assets % -2.9 14.8 33.5 34.5 30.7Property, plant & equip. 155.7 272.4 423.5 556.2 676.6 c_ROIC ROIC % -4.1 17.0 38.0 40.1 41.3Intangibles 0.0 0.0 0.0 0.0 0.0 c_TAX_ Effective tax rate % 0.0 0.0 3.9 24.7 27.4Other non-current assets 2.2 2.2 2.2 2.2 2.2Non-current assets 157.9 274.5 425.7 558.4 678.8 Balance Sheet RatiosTotal assets 204.5 337.0 539.3 750.4 1,080.5 c_NET_Net debt mn -46.0 -8.2 3.5 -84.7 -268.0Payables 1.7 14.8 16.7 18.8 17.1 (c_NET_Net debt/Equity % -22.7 -2.8 0.7 -11.6 -25.2Interest bearing debt 0.0 30.0 50.0 0.0 0.0 (c_NET_Net debt/Capital % -29.3 -2.9 0.7 -13.1 -33.7Other liabilities 0.0 0.0 0.0 0.0 0.0 I_EBIT/cInterest cover x 12.3 -29.2 278.8 601.0 -92.2Total liabilities 1.7 44.8 66.7 18.8 17.1 (c_C_CACapex/Sales % 21,383.4 155.3 56.5 30.7 24.3Net assets 202.9 292.2 472.6 731.6 1,063.4 (c_C_CACapex/Depn % 343,779.5Ordinary equity 202.9 292.2 472.6 731.6 1,063.4 ALT(c_CWorking capital/Sales % 769.2 -13.6 -14.0 -7.1 -3.9Minority interests 0.0 0.0 0.0 0.0 0.0Preferred capital 0.0 0.0 0.0 0.0 0.0 Share ItemsTotal shareholder funds 202.9 292.2 472.6 731.6 1,063.4 c_EPS_Equiv. FPO (period avg.) mn 293.8 406.3 409.6 409.6 409.6

Cashflow Share Price Performance 52wk range: 0.69-3.32EBIT -6.5 48.2 188.5 344.5 452.4Net interest 0.4 1.6 -0.7 -0.6 4.9Depr & Amort 0.5 2.4 14.4 31.8 53.8Tax paid 0.0 0.0 -7.4 -85.0 -125.5Working capital 4.8 -10.4 -41.1 -38.1 -28.0Other 0.0 0.0 0.0 0.0 0.0Operating cashflow -0.8 41.8 153.8 252.7 357.6Capex -134.1 -119.0 -165.5 -164.5 -174.3Acquisitions & InvestAsset sale proceeds 0.0 0.0 0.0 0.0 0.0Other 0.0 0.0 0.0 0.0 0.0Investing cashflow -134.1 -119.0 -165.5 -164.5 -174.3Dividends paid 0.0 0.0 0.0 0.0 0.0Equity raised 156.4 40.7 0.0 0.0 0.0Net borrowings 0.0 30.0 20.0 -50.0 0.0Other -8.2 -1.2 0.0 0.0 0.0Financing cashflow 148.2 69.5 20.0 -50.0 0.0Total cashflow 13.4 -7.8 8.3 38.1 183.3 Source: Reuters Share price as of 22-May-11, 17:18Adjustments 8.3 0.0 0.0 0.0 0.0Net Change in Cash 21.7 -7.8 8.3 38.1 183.3

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May-10 Aug-10 Nov-10 Feb-11 May-11AUT.AX XJO

Source: Company data, Credit Suisse estimates

23 May 2011


Executive summary ■ Pure play Eagle Ford shale in sweet spots: AUT is a pure play on some of the best

liquids rich shale gas in the Eagle Ford Shale (EFS) area of Texas, USA. AUT has 15,760 net acres (74,800 gross acres) in the Sugarkane field with four contiguous Areas of Mutual Interest (AMI): Sugarloaf, Longhorn, Ipanema and Excelsior. The areas sit across Live Oak, Karnes and Dewitt counties. Hilcorp Energy is the operator of the AMIs. AUT is listed on the ASX and TSX (AEF) with a market cap of A$1.1bn. Net 3P reserves of 82.9mmboe imply ~US$14.80/boe of 3P reserves. We estimate a well payback period of five to 14 months, and an estimated well life of more than 20 years.

Figure 2: Summary of AUT holdings AUT Acres

AMI Interest Gross NetSugarloaf 15.70% 23,500 3,700Longhorn 31.90% 27,000 8,600Ipanema 36.40% 4,600 1,700Excelsior 9.10% 19,700 1,760Total 21.1% 74,800 15,760


■ Farmed out to bring in experienced and funded operator, Hilcorp: AUT has taken a different path from some of the other smaller Eagle Ford players, by deciding that it needed an experienced, well funded operator. In hindsight it may look as though AUT and its partners farmed out to Hilcorp too cheaply. However Hilcorp has demonstrated itself to be a low cost operator that has helped unlock the acreage value. As larger operators have moved into Eagle Ford, we believe this was the right path.

■ Stage 1, hold all acreage by production: AUT and its partners are focussed on getting “held by production” status over all acreage before lease expiry, leading to 140 wells to be drilled by the end of 2012, ahead of the potential relinquishment timetable. This work is expected to convert 3P reserves into the 2P category.

■ Stage 2, realise the upside: AUT estimates that only 5% of the oil in place and 10% of the gas in place will be recovered under the current development plan, based on independent reserves certifier Netherland Sewell & Associate Inc’s (“NSAI”) estimated 3P reserves. The operator Hilcorp is looking at ways to increase production rates and Estimated Ultimate Recovery via new drilling and fracture stimulation techniques.

■ Phenomenal share price performance in 2010 was justified: AUT was the best performing stock in the S&P/ASX200 in 2010, up 730% for the year. The current share price infers a valuation of ~US$78,000/net acre, which looks expensive to the recent transactions in the sector (typically in the US$10-20,000/net acre range). However we believe we have moved beyond the simple $/acre valuation methodology, as it fails to account for areas (such at these four AMIs) that generate very high rates of return – our DCF analysis of AUT’s acreage position more than justifies this value.

■ Funding: Cash at 31 March was US$74.9mn, which is forecast to shrink to US$14.2mn by end 2011. We understand AUT is looking at a $50mn–$100mn debt facility to tide it over until after mid 2012, when operations should become self funding.

■ Initiate coverage at A$3.60 target price, Outperform rating: This is an early stage growth story with significant upside potential remaining, in our view. Whilst the company is trading close to our base valuation of A$2.84/share, the current share price does not factor in any upside achievable through the application of new technology. With rapidly increasing production and revenues and at least 900 new wells to drill we initiate coverage on AUT with a A$3.60/share target price and OUTPERFORM rating.

23 May 2011


Investment thesis Base case reserves ■ Material position in prime Eagle Ford Shale Acreage. AUT has 15,760 net acres

(74,800 gross acres) in the Sugarkane field with four contiguous Areas of Mutual Interest (AMI): Sugarloaf, Longhorn, Ipanema and Excelsior. The areas sit across Live Oak, Karnes and Dewitt counties. AUT increased its stake in the four AMIs in late 2010, acquiring 5,100 net acres from another participant in the AMIs for US$120mn. Two other ASX-listed companies have an interest in the Sugarloaf AMI: AWE Limited (10%) and Eureka Limited (6.25%).

■ Factoring a higher base valuation than NSAI. On our numbers the current share price reflects the value of the current NSAI scenario, including extraction of NGLs, and not any upside achievable through increased production and Estimated Ultimate Recovery (‘EUR’). Figure 3 compares the NSAI base case assumptions with Credit Suisse assumptions. We note the NSAI assumptions for oil and gas prices used the Nymex forward strip for WTI Intermediate and Henry Hub as at 31 December 2010). Since then the WTI forward curve has moved up, although we note it is still trading below our Credit Suisse FY13 and FY14 WTI assumptions. We assume higher oil prices in FY13 and FY14, based on tighter inventory levels. We assume higher gas prices over the period but note only 13% of our revenue is driven from sales gas. We use a lower discount rate (8.9% real) and assume that NGLs are extracted, on our A$2.84/share base case.

Figure 3: Comparison of NSAI and Credit Suisse “base” valuation scenarios Valuation NSAI Credit SuisseReserves Developed 83 MMBOE 80 MMBOEOil Price FY11 $93.61 FY11 $94.48

FY12 $93.95 FY12 $92.50FY13 $92.95 FY13 $106.25FY14 $92.40 FY14 $110.00FY15 $92.55 FY15 $90.00FY15+ $93.11 FY15+ $90.00

Gas Price FY11 $4.59 FY11 $4.91FY12 $5.08 FY12 $6.00FY13 $5.33 FY13 $6.50FY14 $5.49 FY14 $6.50FY15 $5.64 FY15 $6.50

FY15+ $5.79 FY15+ $6.50Discount Rate 10% real 8.9% realNGL's extracted No YesNPV (before tax) 1384 1954NPV (after tax) 885 1230shares on issue 410 410value/share (US$/share) 2.16 3.00value/share (A$/share) 2.06 2.86


■ Minimal geological risk. The Eagle Ford Shale formation is present across all of AUT’s acreage in the Sugarkane Field. The major variability in the geological and reservoir properties comes from the thickness of the shale intersected, shale depth and hydrocarbon composition. Unlike conventional oil and gas traps where the target reservoir may fail to contain oil or gas, we expect all wells drilled in the four AMIs will intersect the Eagle Ford Shale.

23 May 2011


■ High liquids content and high initial production rates – economic at low US gas prices. The Eagle Ford Shale contains a high proportion of liquids (light oil), which can comprise up to 70% of the hydrocarbons produced. The ratio of liquids to gas (condensate-gas ratio or ‘CGR’) produced increases from the South East to the North West parts of the Sugarkane field. In addition, the overpressured nature of the shale (pressure gradient of 0.76–0.80 psi/ft in AUT’s acreage) improves the initial production rates and EUR per well. The combination of the high liquids contents and the high production rates results in development wells which are economic even in the current US gas price environment. In full field development, only 13% of all revenue is generated from sales gas. We estimate that new wells will achieve a payback in five to 14 months from the commencement of production.

Figure 4: Eagle Ford Shale hydrocarbon “windows” and some CGR’s achieved to date

Source: Company presentation

■ Extraction of Natural Gas Liquids (NGLs) is adding value. The gas produced from these wells contains a high level of ethane, propane and butane. Currently gas sold with such high liquids content attracts a significant premium to Henry Hub, but going forward the company will be extracting these components from the gas stream and selling them as a separate product. The end result will be less gas sold (approximately 20% lower gas volumes) but approximately 80 bbls/mmscf of NGLs will be produced and sold, leading to a better overall revenue stream (refer to Figure 5). Propane is currently selling for over 55% of WTI oil price at Mont Belvieu in Texas (see Figure 12). We assume a price of 50% of WTI in our DCF valuation.

23 May 2011


Figure 5: Incremental value achieved from extracting and selling NGLs


■ AUT is not alone in seeing the value of the Eagle Ford Shale. The high liquids content of the EFS has attracted a number of majors energy companies over the past two years (refer to Figure 39 in Appendix 2). In terms of activity, there are currently 171 rigs in operation in the EFS, which is the second most active shale play after the Bakken shale in the north of the USA (with 174 rigs – refer Figure 36) and represents a 122% increase in activity from one year ago (when there were 79 rigs in operation).

■ A solid (and growing) reserves base. Independent reserves certifiers Netherland Sewell and Associates (‘NSAI’) has certified 22 mmboe of 2P reserves and 83 mmboe of 3P reserves net to AUT (refer Figure 6). The methodology NSAI employs in certifying shale reserves means that most of the current 3P reserves will be reclassified as 2P reserves at the end of CY11, once the 60 new development wells are drilled this year. NSAI valued AUT’s share of EFS 2P reserves at US$441.5mn and 3P reserves at US$1,384.2mn (before corporate tax).

Figure 6: Certified AUT reserves (net of royalties) as at 31 December 2010 Light/Med Oil NGL/Cond Gas BOE

bbls bbls mcf bblsProved Developed Producing 0 634,195 2,422,833 1,038,001Proved Undeveloped 271,070 5,381,291 24,101,427 9,669,266Total Proved (1P) 271,070 6,015,486 26,524,260 10,707,266Probable 289,535 5,903,066 31,170,818 11,387,737Proved + Probable (2P) 560,605 11,918,552 57,695,078 22,095,003Possible 18,392,324 22,442,489 119,780,026 60,798,151Proved + Probable + Possible (3P) 18,952,929 34,361,041 177,475,104 82,893,154

Source: Company data

■ Aggressive drilling campaign will lead to a rapid expansion in production and revenues. The current focus for drilling is to hold all acreage by production before the end of 2012. Current production was 1,660 BOEPD net to AUT at the end of April, with AUT predicting its net production will increase to 5,000 BOEPD by the end of 2011. 60 wells are expected to be drilled in the 4 AMIs this CY, bringing the total wells drilled by the JV to 80 by the end of 2011. Beyond 2011 oil and gas production is expected to escalate, with NSAI predicting production will reach 29,000 BOEPD by 2019 after drilling 903 development wells.

23 May 2011


■ Sufficient capital to reach self funding stage. AUT raised A$120mn in late 2010 to fund its acquisition of an additional stake in the four Sugarkane AMIs and to help fund its share of development costs. AUT has flagged it may set up a US$50mn–$100mn debt facility to ensure it has sufficient funding in place to reach the point where the company is self-funding (we estimate this point will be reached in 1Q2012).

■ Hilcorp as operator. A key aspect of developing an unconventional resource is a focus on optimising recovery and reducing costs. Since Hilcorp was brought in as operator we have seen a reduction in drilling times and an increase in production rates. Hilcorp has also demonstrated a willingness to optimise its drilling and fracture stimulation techniques ahead of full field development. Hilcorp’s transaction with private equity firm KKR in 2010 brought in US$400mn via the sale of a 40% stake in its 100,000 net acre position in the EFS, so we believe it has sufficient funding in place to accelerate development.

■ Infrastructure now in place to handle production growth. A new wet gas pipeline (initial capacity 50 mmscfd) was recently commissioned to take wet gas via Kinder Morgan line to Copano for NGL stripping. An existing Hilcorp oil pipeline that crosses the Sugarkane field was recommissioned and filled in February 2011. It has an initial capacity of 40,000 bbl/day, but can be twinned to expand future production growth. A number of other third-party pipelines also cross or run near the 4 AMIs, so the JV has multiple paths to sell its product and stay ahead of infrastructure requirements.

Upside 1 – Higher EURs should be achievable… ■ Significant upside potential in EUR versus nearby company estimates. NSAI has

divided the four AMIs into five production type curve areas, with areas to the south expected to be in the mid-high condensate “window” and areas to the north to be in the oil “window”. These areas are shown in Figure 7 below. The estimated EUR for each type curve region is summarised in Figure 8 below. Other companies with operations near to Sugarkane field in the oil window assume higher estimated EURs: EOG at 575mmboe, Murphy at 500–700mmboe, Chesapeake at 595 mmboe and Plains at 483mmboe. Current EURs for gas-condensate wells for other nearby companies: Petrohawk at Blackhawk of 1,070mmboe and at Hawkville of 867mmboe.

Figure 7: NSAI-defined decline curve allocation areas


23 May 2011


Figure 8: NSAI estimated EUR for areas of the Sugarkane field NSAI-defined area Oil NGL/Cond Gas Total BOEin Sugarkane Field bbls bbls mmscf bblsGas Condensate Type Curve #1 240,000 3,050 748,000Gas Condensate Type Curve #2 464,950 1,700 748,000Oil Type Curve #1 300,000 300 350,000Oil Type Curve #2 230,000 230 268,000Oil Type Curve #3 400,000 400 467,000


…as production is already running above base case ■ Already outperforming NSAI predictions. Immediate upside to NSAI’s reserves and

valuation estimates is the fact that wells drilled to date have, on average, outperformed the average well production performance expected by NSAI. The following chart plots the average well performance to date versus the NSAI condensate decline curve. The incremental recovery of the wells versus NSAI is also shown, with a cumulative outperformance of 27,000 BOE after 10 months. It should be noted that the decline curves include some earlier wells which have a short horizontal section; newer wells (online for four months or less) have a longer horizontal length and have outperformed the NSAI decline curve to a greater extent.

Figure 9: Upside in deliverability – current production running ahead of NSAI forecasts


■ Increasing the type curves adds A$0.86/share. On our calculations a 20% increase to our type curves adds A$0.86/share (derisked) to our valuation. We currently apply a 75% risk-weighting to this scenario in our risked SOTP valuation, giving A$0.64/share.

Upside 2 – ready to trial closer spaced drilling ■ 80-acre well spacing may be leaving a lot of oil and gas behind. NSAI has

assumed a single well will drain an area of 80 acres, however AUT and other AMI participants believe that a well may be draining much less than this. Estimated Ultimate Recovery (‘EUR’) for the current development plan is 5% of oil in place and 10% of gas in place. Drilling wells closer together may increase the total EUR across the four AMIs

■ Drilling vertically offset wells in the Austin Chalk above the Eagle Ford Shale could also increase EUR. The Austin Chalk is a known productive reservoir immediately overlaying the EFS. Similar extraction techniques can be employed in the Austin Chalk to the EFS (e.g. horizontal drilling and multi-stage fracture stimulation).

23 May 2011


The horizontal laminations present in the shales means that fractures are more likely to propagate horizontally rather than vertically.

■ Could we eventually see 20-acre well spacing? In other shale plays in the US there has been a definite trend towards reduced well spacing to improve overall recovery. As Figure 10 shows, a possible end game here could be four horizontal wells contained in the same 80-acre block, equalling an average 20-acre drainage area per well. At some stage there will be an optimal economic outcome, where a reduction in well spacing no longer adds value. Hilcorp will commence trialling closer well spacing in 2Q 2011 to ascertain whether closer well spacing could improve the total recovery and economics of developing the acreage. The project participants plan to make a decision on the optimal way in which to exploit the oil and gas in the acreage prior to commencing full field development in late 2012.

Figure 10: Closer well spacing


■ Closer spaced wells could be worth A$0.36–$0.56/share, but is not factored in to our Target Price. We have generated a 60-acre and a 40-acre development scenario, with wells drilled on 60-acre spacing producing at 95% of the 80-acre spacing wells with 90% of the EUR. 40-acre well spacing is assumed to produce initially at 90% of the 80-acre well spacing with 80% of the EUR.

Upside 3: Trialling new fraccing technology ■ HiWAY fracs: The Operator is trialling ‘HiWAY Fracs’ in 2Q 2011. Using

Schlumberger (SLB) technology, the fraccing proppant is pumped in pulses and creates better flow channels for the hydrocarbons. This technology also extends the reach of the fraccing. Petrohawk (HK) has trialled this technology on two wells in Eagle Ford and reported 37% higher initial gas production than the best comparable offset well for a well in the gas zone, and 32% higher initial oil production rate than the best comparable offset for a condensate well (see Figure 11). Based on these results, HK is using this technology for more wells. HK is now forecasting a preliminary 25%–90% rise in per well EURs for no increase in well costs.

■ Four HiWAY frac wells underway: In the AUT acreage, four wells have been selected for HiWAY fraccing in 2Q2011. The plan is for two wells in the oilier Excelsior AMI, one in the high condensate Longhorn AMI and one in Sugarloaf. The locations have been selected adjacent to existing wells to achieve the best comparison between the two fraccing methods.

■ Cost angle: Management has commented that costs for HiWay frac are currently 5%–10% higher than other fraccing, however this may be offset by the lower level of proppant used. Over time we anticipate the cost of this technology (if successful) may be competitive with current traditional fracture stimulation techniques.

23 May 2011


Figure 11: HK results from using HiWAY frac


■ Value upside of A$1.03 not factored into Target Price: We have not factored any upside into our valuation yet for improved Estimated Ultimate Recovery(EUR)/well. If we assume that HiWAY fracs increase the average initial production rates by 20% and EUR by 20% it would add US$1.08 /share (AUD$1.03/share) to our valuation.

Further upside exists – not included in our valuation ■ Choking back well production to increase well EUR. AUT has reported that a few of the

wells put on production have been placed on a restricted choke setting. This reduces the flow rates achieved in the early stages of well production. The operator is working on the theory that restricting initial production may result in a lower decline in oil and gas production and eventually lead to higher EUR per well. The trade-off is that it may extend the payback period of each well given the lower levels of revenues generated. The project participants in the AMIs are still determining whether this practice is an optimal path to take going forward, and it may be too early in the wells’ lives to accurately judge the impact on well EUR.

■ NGL recovery may increase to 100 bbl/mmscf. AUT has estimated that 80 bbl/mmscf of NGLs will be extracted; however it may be possible to extract closer to 100 bbl/mmscf. We do note that there is a trade-off in terms of liquids recovery: Incremental NGL recovery comes at a higher price and reduces the level of sales gas produced and the heating value of that gas (potentially lowering its price).

■ Excelsior production rates and EURs may improve with new well data. We understand the Excelsior EURs estimated by NSAI are based on existing well data, however the well data used was from wells with short horizontal lengths. There is a definite relationship between horizontal well length and early production rates. We anticipate that future wells drilled in the Excelsior AMI will achieve higher production rates, potentially leading to an increase in EURs.

■ Improvement in Natural Gas Liquids pricing relative to WTI Oil Price. We understand the NGLs extracted from the raw gas stream will attract a price linked to the Mont Belvieu propane price. Figure 12 shows the ratio of Mont Belvieu propane price to the spot WTI oil price. We have conservatively assumed NGLs will trade at 50% of WTI, however the price over the past two years has been in the 55%–65% range. We will wait to see the type of pricing AUT attracts for its NGLs, with the final price likely to be related to the ratio of ethane produced versus propane and butane.

23 May 2011


Figure 12: Historic ratio of Mont Belvieu propane price to WTI oil price

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Acquisitions to diversify and increase production ■ AUT on the hunt for value-adding acquisitions. AUT has stated publicly that it is

continually reviewing acreage acquisition opportunities. We believe AUT is in a good position to acquire additional acreage, as the company is well-backed, it understands the value of its acreage and should be self funding by early 2012. We expect that any acquisition would probably be in the EFS and most likely close to its existing acreage position.

Funding in place ■ AUT expects to rely on bank debt for year end cash gap: AUT had US$74.7mn in

net cash at 31 March 2011. AUT has signalled that it may set up a US$50mn–$100mn debt facility this year to provide additional funding capacity to get the company to the point of being self funding (expected in early 2012). On our numbers we believe AUT may not need to utilise this facility, however having it in place would free up some cash for acquisition of additional acreage. Further equity raisings would be dilutive, and AUT believes it is at a point where bank debt makes sense. Our modelling assumes the company maintains a bank balance of US$50mn for potential acquisitions, which requires the maximum drawdown of US$50mn debt in 2011/12. The company would be able to repay this level of debt before the end of CY13.

23 May 2011


Valuation, catalysts and risks Valuation methodology and assumptions ■ DCF valuation of production profile: We value AUT using a discounted cash flow

valuation of the NSAI expected drilling and production profile (plus NGL extraction) out to 2030. We risk-weight our upside scenarios to generate a risked SOTP valuation. Our cash flows are generated in USD and convert to an AUD target price. We use the Credit Suisse WTI oil price and US gas price assumptions (see Figure 15) and a WACC of 11.6 % nominal (8.9% real).

■ A$3.60 Target price, Outperform on solid base value with considerable upside potential. We value the base NSAI reserves case at US$2.99/share. We then add in risked upside (75%) from production above the base case (~20% higher production) at US$0.67/share. Finally we assume higher density drilling and risk weight (25%) our outcome worth US$0.10/share. Our risked SOTP valuation is US$3.75/share or AUD$3.58/share at the Credit Suisse forecast CY11 AUDUSD exchange rate of 1.05. We set our Target price at $3.60/share leading to an OUTPERFORM rating.

Figure 13: SOTP valuation Risked Valuation Probability Unrisked Valuation US$/BOE US$/BOE US$/acre

NPV US$mn US$/share Weighting NPV US$mn US$/share 2P reserves 3P reservesSugarkane Field - NSAI assumptions 1,157 2.82 1,157 2.82 52.36 13.96 73,400 NGL Extraction 73 0.18 73 0.18 3.30 0.88 4,600 Total production 1,230 3.00 1,230 3.00 55.66 14.84 78,000

Cash 38 0.09 38 0.09Debt -30 -0.07 -30 -0.07Elixir Shares 1 0.00 1 0.00Corporate Overheads -16 -0.04 -16 -0.04Net cash and other -6 -0.02 -6 -0.02

BASE VALUATION - USD 1,224 2.99 1,224 2.99 55.38 14.76 77,600

BASE VALUATION - AUD 1,165 2.84 1,165 2.84

Upside ScenariosIncrease type curves to match prod'n 276 0.67 75% 368 0.90 16.66 4.44 23,400 60 acre spacing 39 0.10 25% 156 0.38 7.07 1.88 9,900 40 acre spacing 0 0.00 0% 85 0.21 3.83 1.02 5,400 HiWAY fracture stimulation 0 0.00 0% 442 1.08 19.99 5.33 28,000 NGL recovery 100bbl/mmscf 0 0.00 0% 45 0.11 2.02 0.54 2,800 Total potential upside 315 0.77 1,095 2.67 49.56 13.21 69,500

TOTAL VALUATION - USD 1,539 3.75 2,319 5.66 104.94 27.97 147,100

TOTAL VALUATION - AUD 1,465 3.58 2,208 5.39

Target Price - AUD 3.60

Shares on issue 409.9 mn

AUDUSD Assumption 1.05


23 May 2011


■ Unrisked valuation of A$5.39: Figure 14 shows the value added through each scenario on an unrisked basis in A$/share. Note we have added HiWAY frac success and increased NGL extraction to the top of our waterfall for illustration purposes.

Figure 14: Unrisked valuation waterfall

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Figure 15: WTI oil price and HH gas price assumptions (2011 real) 2011 2012 2013 2014 2015

WTI Oil Price US$/bbl 94.48 92.50 106.25 110.00 90.00HH Gas Price US$/mcf 4.91 6.00 6.50 6.50 6.50 Source: Company data, Credit Suisse estimates

■ Oil and Gas pricing assumptions. We have assumed oil is sold at a 2% discount to WTI, and gas sold at Henry Hub price once NGLs are extracted, or at a 25% premium to Henry Hub if the NGLs are left in the gas stream.

■ Type curves used for production profiles. Our valuation model is based on the use of type curves to predict future oil/condensate and gas production. In total we use five type curves, based on the five separate areas defined by NSAI. A drilling schedule was then generated to match NSAI’s forecast production profile. Cash flow forecasts were generated out to 2030.

■ Taking a conservative approach to risked valuation. Figure 16 summarises the key outputs from the six scenarios developed. Our SOTP valuation incorporates a base value, which is unrisked, and risked upside scenarios. Our base value is Scenario 2, based on the current NSAI type curve assumptions and including the value added through NGL extraction and sale. Of the other scenarios, we have applied the following probability weighting:

• Type curves increased by 20% 75%

• 60-acre well spacing 25%

• 40-acre well spacing 0%

• HiWAY fracture stimulation success 0%

• Increased NGL extraction to 100 bbl/mmscf 0%

23 May 2011


■ Detailed DCF valuation assumptions, scenarios and outputs can be found in Appendix 1. This includes the individual type curves used in our valuation and the economics of each type curve and the input assumptions and outputs from each valuation scenario.

Figure 16: Summary of valuation scenarios generated Scenario Description NPV (A.T.) Wells NGL Peak Prod Recovery

US$mn Drilled Extraction BOE/day MMBOE1 NSAI match 1,157 900 None 29,000 80.02 NSAI match + NGL extraction 1,230 900 80 bbl/mmscf 29,000 80.03 Type curves match production + NGL extraction 1,598 890 80 bbl/mmscf 38,000 106.34 Scenario 3 + 60 acre well spacing 1,754 1,244 80 bbl/mmscf 52,000 132.15 Scenario 3 + 40 acre well spacing 1,839 1,868 80 bbl/mmscf 56,000 169.56 Scenario 3 + HiWAY frac success 2,039 900 80 bbl/mmscf 46,000 127.57 Scenario 3 + Increased NGL extraction 1,642 900 100 bbl/mmscf 29,000 80.0


Catalysts ■ Increasing production from drilling activity. Approximately 60 new wells are

planned to be drilled in 2011, leading to higher production and revenues for AUT. AUT’s share of production was 1,660 BOEPD by late April and is expected to reach 5,000 BOEPD by the end of 2011. Whilst variability is expected in the initial production rates between each well, overall we expect to see new wells outperform the NSAI production type curves, leading to higher reserves at the end of 2011. A new reserves report is not expected until early 2012, at which time most of the current 3P reserves should be reclassified as 2P reserves.

■ HiWAY fracture stimulation trials. AUT has stated that it will commence the use of Schlumberger’s HiWAY fracture stimulation technology before the middle of 2011. Petrohawk has seen positive production results to date; similar result here could signal a significant re-rating of the stock. On our numbers a 20% increase to the average production rate and 20% increase to the EUR adds A$1.03/share to our valuation.

■ Impact of closer well spacing. The project participants will also trial wells drilled on a 60-acre spacing to gauge the impact and interference on production. The plan is to optimise the well spacing ahead of the full field development phase, expected to commence in late 2012.

■ Potential acquisitions. AUT has signalled it plans to undertake value-adding acquisitions. We will judge each on its merit, but to date AUT has demonstrated that it can add shareholder value through acquisitions and this could be a further positive catalyst for the stock.

Risks ■ Non-operator: Private company Hilcorp is operator across the four AMIs in which

AUT is a participant. Whilst the other participants have a say in the pace and location of drilling activity, this process is largely driven by Hilcorp. This can be a sub optimal position if there is disagreement in the pace and focus of investment between AUT and the operator, but from our observations to date Hilcorp’s ambitions for the development of the four AMIs is closely aligned to that of AUT. Hilcorp has proven to be a low cost operator with a focus on optimising drilling, completion and fracture stimulation practices ahead of full field development. Hilcorp sold a 40% stake in its 100,000 net acres of EFS to private equity firm Kohlberg Kravis Roberts & Co (‘KKR’).

23 May 2011


KKR is investing up to US$400mn in the acreage to earn its 40% interest. Hilcorp now has the funding required to accelerate development before reaching a positive cash flow position. The pace of drilling and fracture stimulation activity continues to step up, with the number of rigs in operation increased from two to four in January and a second frac crew commenced operations in March.

■ Environmental concerns over shale gas drilling. There has been considerable negative press surrounding the environmental impact of shale gas drilling, including the pollution of overlying aquifers with frac fluids and methane and the improper disposal of produced fluids post fracture stimulation. Most of the major environmental issues that have occurred in shale drilling have happened in the Marcellus shale on the east coast of the US. The Marcellus shale is a relatively shallow shale, which is in close proximity to an aquifer containing potable water. This water is used by some local towns for drinking water, and in a few select cases improper cementing, fracture stimulation and completion practices has resulted in the contamination of these aquifers. In contrast to the Marcellus shale, the EFS is at a depth of approximately 10,000+ft, with the nearest potable water aquifer more than 5,000ft shallower. Water for fracture stimulation is drawn from saline aquifers deeper than the potable water aquifer. Casing is run over the shallower aquifers to protect them from drilling and fracture fluid contamination. In short, we downplay the chances of major environmental issues in AUT’s acreage.

■ Infrastructure bottlenecks. A new wet gas pipeline (initial capacity 50 mmscfd with expansion options) was recently commissioned to take wet gas via Kinder Morgan line to Copano for NGL stripping. An existing Hilcorp oil pipeline that crosses the Sugarkane field was recommissioned and filled in February 2011. It has an initial capacity of 40,000 bbl/day, but can be twinned to expand future production growth. A number of other third-party pipelines also cross or run near the four AMIs, so the JV has multiple paths to sell its product and stay ahead of infrastructure requirements.

■ Oil Price: With 87% of the revenues generated from AUT’s acreage linked to the prevailing price of oil, AUT’s future revenues are highly correlated to the movement in WTI oil price. A summary of the WTI oil price assumptions used in our analysis can be found in Figure 15. A US$10/bbl change in oil price across the valuation period results in a 12% change to our DCF valuation.

■ Drilling costs: We are cautious on drilling cost escalation, especially given the focus on shale plays in Texas. Whilst there has been some upward pressure on drilling and fracture stimulation costs in the EFS over the past 12 months, we expect that this will eventually dissipate as service providers bring in rigs from other parts of the country. We have seen a real shift in drilling away from dry shale gas plays such as the Barnett and Haynesville towards the liquids rich Eagle Ford and Bakken shales. We also note that drilling to hold acreage by production means wells are being deliberately spread out to hold as much acreage as quickly as possible. Once all acreage is held by production and full field development commences we expect developers will move to batch drilling, where as many as six wells may be drilled from a single location,. This eliminates the need to move the rig between each new well and saves considerable time and mobilisation/demobilisation costs.

■ Acquisition risk and future use of cash flow generated. AUT has stated that it is actively seeking value-adding acquisitions, however there is a risk that future investments are not profitable. New acreage may carry the opportunity for AUT to operate, and we note that AUT is currently lacking deep shale drilling operational skills. These skills can be hired or contracted out, but we flag it as a potential risk factor for AUT. At this stage the company has no dividend policy in place, but we expect that to be revisited in the next two years as the company starts to generate significant positive cash flow from its Sugarkane Field operations.

23 May 2011


Financials and key drivers ■ Substantial investment leads to rapid escalation in revenue and earnings

growth. We anticipated this growth in earnings to continue until at least 2019, however the pace of this growth will be largely dictated by the pace of drilling activity and prevailing oil price. However even with an escalation in drilling (from four wells a month currently to eight a month by FY13) we still anticipate positive free cash flow from FY13 onwards. Note the drop in total revenue in FY15 in Figure 17 is due to a US$20.00/bbl reduction in our WTI oil price in that year. We assume no dividends over the forecast periods.

■ Changed reporting to USD and 31 December reporting date: AUT changed its reporting date from 30 June to 31 December on 1 July 2010. It also changed its reporting currency to USD from AUD at that date. Our FY10 numbers therefore reflect a six-month period from 1 July 2010 to 31 December 2010.

Figure 17: Summary of key financial forecasts for AUT – based on NSAI type curves Profit and Loss (US$mn) FY10A FY11F FY12F FY13F FY14F FY15FTotal revenue 0.6 78.3 304.8 558.0 746.5 670.7Revenue growth n/a 12392% 289% 83% 34% -10%

Expenses 6.6 26.6 93.9 166.1 219.7 203.8EBITDA -6.0 51.7 210.8 391.9 526.7 466.9DD&A 0.5 2.3 14.6 31.9 53.4 70.0EBIT -6.5 49.4 196.2 360.0 473.4 396.8Less: Net interest -0.5 -1.6 0.6 0.4 -5.5 -14.3Profit before tax -5.9 51.0 195.6 359.6 478.9 411.2Tax expense 0.0 0.0 10.5 90.4 132.7 116.2NPAT -5.9 51.0 185.1 269.2 346.1 294.9Significant items 0.0 -1.2 0.0 0.0 0.0 0.0Reported NPAT -5.9 49.8 185.1 269.2 346.1 294.9

EPS -2.0 12.3 45.2 65.7 84.5 72.0DPS 0.0 0.0 0.0 0.0 0.0 0.0Shares (m) 293.8 406.3 409.6 409.6 409.6 409.6Cash flow FY10A FY11F FY12F FY13F FY14F FY15FNet cash flow from operations -0.8 41.9 156.8 261.4 370.7 382.7Net cash flow from investing activities -134.1 -119.0 -165.5 -164.5 -174.3 -151.7Cash flow from financing activities 148.2 69.5 20.0 -50.0 0.0 0.0

Net Increase (decrease in cash flow) 13.4 -7.6 11.2 46.9 196.3 231.0Balance Sheet FY10A FY11F FY12F FY13F FY14F FY15FNet cash (debt) 46.0 8.4 -0.4 96.5 292.9 523.8Gearing -29% -3% 0% -15% -37% -61%


23 May 2011


Appendix 1 – Valuation detail Valuation Assumptions ■ Low condensate type curve: The following figures show the type curves used and

the cumulative NCFAT using WTI oil price of US$100/bbl and Henry Hub gas price of US$4.50/mcf. We have simulated a 20-year well life for each well drilled.

Figure 18: Low condensate type curve used and NCFAT chart (CCGR = 79 bbl/mmscf)

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■ Payback of nine months on low condensate: Key outputs are: NPV US$9.6mn (after tax), IRR of 105% and payback period of nine months from start of production.

Figure 19: High condensate type curve used and NCFAT chart (CCGR = 274 bbl/mmscf)

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■ Payback of six months on high condensate: Key outputs are: NPV US$14.4mn (after tax), IRR of 188% and payback period of six months from start of production.

Figure 20: Longhorn Oil type curve used and NCFAT chart (CCGR = 1,000 bbl/mmscf

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■ Payback of five months on Longhorn oil: Key outputs are: NPV US$9.7mn (after tax), IRR of 80% and payback period of five months from start of production.

Figure 21: Excelsior #1 type curve used and NCFAT chart (CCGR = 1,000 bbl/mmscf))

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■ Payback of eight months on Excelsior type 1: Key outputs are: NPV US$5.7mn (after tax), IRR of 95% and payback period of eight months from start of production.

Figure 22: Excelsior #2 type curve used and NCFAT chart (CCGR = 1,000 bbl/mmscf)

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■ Payback of 14 months on Excelsior type 2: Key outputs are: NPV US$2.9mn (after tax), IRR of 49% and payback period of 14 months from start of production.

■ NSAI drilling and production profile. Figure 23 shows the drilling profile generated to match NSAI’s forecast production profile and the resultant production forecast.

Figure 23: Well drilling profile used and production profile generated from valuation model Well Drilling Profile

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23 May 2011


■ Cost assumptions. We have adopted the following cost assumptions in our valuation model:

• Drilling and Completion Cost: US$8mn per well until CY13 when it reduces to US$6.8mn. Drilling cost reduction is due to anticipated increased competition for drilling services and reduction in costs associated with the construction of central processing facilities.

• Central Processing Facilities: US$15mn each. Assuming each CPF can handle 50 wells each, with six constructed this year and additional units added as required.

• Operating Costs: US$15,000/well/month.

• Transportation and processing costs: US$0.50/mmbtu.

• Abandonment costs: These have been excluded from our valuation as: a) the wells are expected to produce for at least a 20-year period; and b) the eventual abandonment liability (estimated to be 5% of the well cost or US$350mn) is exceeded by the cash flows that are expected to be generated beyond 2030 (the end of our DCF valuation).

■ NGL extraction: 80 bbl/mmscf of NGLs are extracted and sold at 50% of WTI, with a corresponding reduction of 20% in the volume of gas sold.

Valuation Scenarios The following valuation scenarios were developed:

(1) NSAI match: NSAI type curves and development well timing, no NGL extraction.

(2) NSAI + NGL extraction: NSAI type curves and development well timing, NGL extraction at a rate of 80 bbl/mmscf.

(3) Type Curves Match Production: Type curves increased by 20% to match recent well results, NSAI well timing and NGL extraction.

(4) 60 acre well spacing: As per scenario 3, but assume 60-acre well spacing, with wells producing at 95% of 80-acre well spacing and an EUR 90% of 80-acre well spacing. A more aggressive development drilling campaign is assumed to drill all well locations.

(5) 40 acre well spacing: As per scenario 3, but assume 40-acre well spacing, with wells producing at 90% of 80-acre well spacing and an EUR 80% of 80-acre well spacing. A more aggressive development drilling campaign is assumed to drill all well locations.

(6) HiWAY fracs: As per scenario 3, but assume HiWAY fracture stimulations are successful and increase initial production rates and EUR by 20%.

(7) NGL extraction increased: As per scenario 3 but NGL extraction increases to 100 bbl/mmscf.

Valuation Outputs ■ Scenario 1: NSAI Match, no NGL extraction

• Total wells drilled: 900

• Positive cash flow position reached: Q2 2012

• Peak production achieved: 2019 (29,000 BOEPD)

• NPV (after tax): US$1,157mn

23 May 2011


Figure 24: Scenario 1 short-term production profile and annual NCFAT AUT Production Profile

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■ Scenario 2: NSAI Match, NGLs extracted at 80 bbl/mmscf





Figure 25: Scenario 2 short-term production profile and annual NCFAT

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■ Scenario 3: Increase type curves to match recent well performance (increase NSAI curves by 20%)







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■ Scenario 4: 60-acre well spacing, with initial rate per well 95% of 80-acre spacing and EUR per well of 90% of 80-acre well spacing.

• Total wells drilled: 1,244






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■ Scenario 5: 40-acre well spacing, with initial rate per well 90% of 80-acre spacing and EUR per well of 80% of 80-acre well spacing.

• Total wells drilled: 1,868




23 May 2011




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■ Scenario 6: 80-acre well spacing, with HiWAY fracture stimulations generating a 20% higher initial production rate and 20% higher recovery.






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1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13


-100

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■ Scenario 7: 80-acre well spacing, with type curves matching current production profiles plus NGL extraction at 100 bbl/mmscf (and 25% gas shrinkage).





23 May 2011



Quarterly Average

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■ Revenue composition mainly oil-price linked. Figure 31 and Figure 32 shows the breakdown of production and revenue generated by product over the life of the project. Whilst 28% of the production on a BOE basis is sales gas, it represents just 13% of forecast revenue gas, with the remaining 87% of revenues attracting an oil-linked price.

Figure 31: Production split by product Figure 32: Revenue split by product

28%

17%

21%

34%

Sales Gas NGL Condensate Oil

13%

11%

29%

47%

Sales Gas NGL Condensate Oil

Source: Company data, Credit Suisse estimates Source: Company data, Credit Suisse estimates

23 May 2011


Appendix 2 – Shale What is shale? ■ Shale is a dense, low porosity and low permeability sedimentary rock. Shales can

have a high organic content which under the right conditions can generate hydrocarbons. This makes shale a source rock, and the lack of intrinsic permeability means that most of the hydrocarbons are still trapped inside the shale. Permeability of shale is measured in the nanodarcys (nD), compared to CSG and conventional oil and gas reservoirs in milli-darcys (mD).

Figure 33: Eagle Ford shale core section


23 May 2011


Shale development ■ The hydrocarbon potential of shales is not a new phenomenon. This has been

known for many years, but the issue has been the inability to extract the trapped hydrocarbons at an economic rate. Early wells focussed on single stage fracture stimulation in a vertical well, which did not achieve flows that generated an economic rate of return.

■ Horizontal fracced wells: The secret to the success of shale has been the combination of long horizontal wells (enabled though improvements in drilling technology) and fracture stimulation (‘fraccing’), that opens up a fissure system in the shale to allow the hydrocarbons to flow. These techniques were first trialled around 10 years ago, and it has been the further improvement in drilling technology combined with increasing the number of fracture stimulations performed in each well (called multi-staged fraccing) that has led to commercial gas flow rates. It is now not uncommon for wells to have a 10,000ft horizontal section, bringing the total well length to over 20,000ft, and for wells to have up to 32 fracture stimulation stages.

Figure 34: Horizontal well drilling and fraccing


Shale production characteristics ■ High initial production rates but a rapid decline. Shale gas and oil production

profiles have three distinct characteristics. High initial production rates, due to “flush” production as the gas and oil close to the fractures are produced quickly. Rapid early decline, as the shale closest to the fractures are depleted, and long tail production, as hydrocarbons away from the fractures slowly migrate to the fractures and into the wellbore. Early decline rates can be as high as 80% in the first year (and are typically higher in oil wells than gas-condensate wells), so achieving a fast payback is critical for economic shale gas and oil extraction. Wells can produce oil and gas for 20+ years, with the well life typically dictated by an economic cutoff.

23 May 2011


Figure 35: Typical well production profiles – gas-condensate and oil type curves

0

200

400

600

800

1,000

1,200

1,400

1 3 5 7 9 11 13 15 17 19 21 23Time (months)

Prod

uctio

n ra

te (B

OEP

D) Gas-condensate Type Curve

Oil Type Curve


Shale plays in the USA ■ USA has led the way in economic shale gas and oil extraction. Figure 36 shows

the location of the current and prospective shale plays in the Lower 48 states, with the Eagle Ford shale situated in West Texas. The shale gas industry has turned the US gas market on its head within the space of five years. At one stage midway through the last decade the US was on track to become a major LNG importer. This was to keep up with growing domestic demand against a backdrop of declining conventional supplies. Shale gas now accounts for more than 10% of all US gas production, and is causing a number of companies to consider exporting gas as LNG, either directly from the US or using Canadian gas which is no longer required further south.

■ The shale gas resource is huge and is impacting domestic prices. The US Energy Information Administration (EIA) recently increased its estimate of technically recoverable shale gas resources by 134%, from 368 Tcf to 862 Tcf. Shale gas production has increased from 1.3 Tcf in 2007 to 3.3 Tcf in 2009, and EIA expects it to reach 12.3 Tcf by 2035, or 47% market share. Growth in the shale gas production (combined with the global financial crisis) has led to a drop in US gas prices, from a high of over US$10/mcf in mid 2008 to around US$4.20/mcf currently.

23 May 2011


Figure 36: Location map of the current and prospective shale plays in the Lower 48 states, USA

Source: Energy Information Administration website

Eagle Ford Shale ■ Newest of the shale areas: The Eagle Ford Shale in southern Texas is one of the

more recent shale areas, with activity only really kicking off in earnest in 2008. Since mid-2010, the major international oil companies have entered the Eagle Ford area, including Apache, Anadarko, Chesapeake, Talisman, Statoil, ConocoPhillips, CNOOC. Transaction multiples have risen from US$10k/acre to over US$20/acre in more recent times (refer to Figure 38). Estimated gross reserve potential of the EFS is 25 billion boe (150 TCF).

■ Drilling activity has ramped-up quickly. A year ago there were 79 rigs in operation in the EFS, this has now increased to 171 rigs and companies are racing to hold their leases by production. Wells drilled during this period are typically spread out across the leases in order to maximise the acreage held (refer Figure 43). Once all leases are held by production, companies can move into full field development mode, which can see multiple wells drilled from a single location, leading to a reduction in drilling costs.

23 May 2011


Figure 37: Eagle Ford Shale players


Figure 38: Some recent Eagle Ford shale transactions Date Buyer Seller Acres Sold Transaction Value

US$mn US$/acre14-Jun-10 KKR Hilcorp Energy 40,000 400 10,00024-Jun-10 Reliance Industries Pioneer Natural Resources 95,300 1,025 10,756

5-Oct-10 Plans Exploration and Production Dan Hughes 60,000 578 9,63310-Oct-10 CNOOC Chesapeake Energy 199,800 2,008 10,05010-Oct-10 Talisman & Statoil Enduring Resources 97,000 1,325 13,66024-Dec-10 Aurora Oil & Gas Undisclosed 5,100 120 23,52921-Mar-11 KNOC Anardarko Petroleum 80,000 1,600 20,000

Total 577,200 7,056 12,225Source: Company data, Credit Suisse estimates

■ Aurora is a small Eagle Ford Shale player compared to many others. Figure 39 Summarises the net acreage positions in the EFS as compiled by NGI Shale Daily website. AUT appears as number 38 on the list with its 15,760 net acres, compared to some of the major players like EOG Resources (595,000 net acres) and Apache Energy and Chesapeake Energy (both with 450,000 net acres).

23 May 2011


Figure 39: Eagle Ford holdings

Source: NGI Shale Daily website

■ Geology delivers oil, liquids and dry gas: The Eagle Ford shale play deepens as it approaches the Gulf of Mexico. At the deeper points, it is hotter, leading to a drier gas. At the shallower northern part of the Sugarkane Field the EFS is oil-bearing. In between, the gas is “wet”, contacting condensates and LPG (see Figure 40). Yields of liquids in the condensate window at ~400bbl/mcf, dropping to 60bbl/mmcf. The plays are at depths of 10,000 feet to 12,000 feet and average thickness is 250 feet.

23 May 2011


Figure 40: Eagle Ford shale areas

Source: US Energy Information Administration website

Sugarkane area Eagle Ford shale characteristics ■ Liquids rich and high pressure gradient. Figure 41 summarises the key technical

properties of AUT’s acreage versus those of the regional EFS. The key properties that differentiate AUT’s acreage from other parts of the EFS are the pressure gradient and high condensate-gas ratio. The high pressure gradient enhances both the initial production rate and EUR per well.

Figure 41: Summary of technical characteristics of AUT’s acreage versus regional EFS Property AUT Acreage Regional Eagle FordDepth (ft) 12,000 - 13,000 6,000 - 14,000Porosity (%) 6 - 10% 2 - 12%Pressure (psi/ft) 0.76 - 0.80 0.43 - 0.80Condensate-Gas Ratio (bbls/mmscf) 50 - 400 0 - 400+Total Organic Content (%) 2 - 6.6% 2 - 6.6%GIIP/640 acres (Bcfe) 120-250 100-300Source: Company data

ASX-listed companies operating in the Eagle Ford ■ Only two pure EFS plays on the ASX. AUT and EKA are the only pure EFS plays on

the ASX. Eureka Energy has 1,500 net acres in the Sugarloaf AMI, but has recently acquired approximately 4,000 net acres in the Brioche Project within the EFS and also has approximately 700 net acres in the Pan de Azucar project area. TXN has almost 6,000 net acres in the EFS, but further to the west of AUT’s position and looks to be more in the oil window, and also has conventional oil and gas production. AWE looks expensive on a $/acre basis but the company has considerable conventional oil and gas production and reserves in Australia and New Zealand.

23 May 2011


Figure 42: ASX-listed companies with acreage in the Eagle Ford Shale Company Code Net acres Shares SP market cap Net cash EV EV/acre

A$mn A$mn A$mn A$/acreAurora Oil & Gas AUT 15,760 410 2.84 1164 71 1093 69,339AWE Ltd AWE 2,400 723 1.38 997 75 922 384,360Eureka Energy EKA 6,200 237 0.28 66 16 51 8,187Texon Petroleum TXN 5,914 243 0.71 172 13 159 26,949


How are reserves determined? ■ Reserves delineation on an acreage grid pattern: Reserves are based on 80-acre

development blocks. 2P reserves are based on the estimated reserves in blocks surrounding a drilled well (two blocks each to the left and right and one block above and below). 3P reserves are in blocks surrounding the 2P reserves locations. This process is not dissimilar to the reserves certification process for CSG. Conversion from 3P reserves to 2P is initially a matter of drilling more wells to get full coverage by 2P. Reserves upside then comes from comfort on upside in well deliverability, and from closer well drilling.

Figure 43: Reserves delineation process Figure 44: Conversion of reserves underway

Source: Company presentation Source: Company presentation

23 May 2011


Appendix 3 – Aurora Oil & Gas ■ Formed in 2005: AUT was formed in 2005, post a reorganisation of the suspended

company, Tony Barlow Menswear, a publicly listed company on the ASX. Head office of AUT is Perth, Australia. The company’s founders reside in Perth and found Australia a suitable place to raise the necessary capital for a small cap exploration company.

■ Board includes combined CEO/Chairman: The board comprises seven members including a combined CEO/Chairman role. While we prefer these roles to be separate, we note that AUT acknowledges the benefits of an independent chair and we expect this will change in the next few years as AUT matures. Both the Finance director, Graham Dowland and the Technical director, Ian Lusted, are members of the board. Four of the directors are independent. A summary of director experience follows:

■ Jonathan Stewart (BComm, ACA) – Executive Chairman, CEO

• Appointed director on 22 Feb 2005

• 20 years’ experience in executive management positions in various industries including oil and gas

• Former director of Gawler Resources and current chairman of Elixir Petroleum (ASX listed)

■ Ian Lusted (BSc(Hons)) – Director, Technical Director • Appointed Technical director on 14 Apr 2008 • 15 years experience in petroleum engineering • No other current or former directorships within the past three years

■ Graham Dowland (BComm, ACA) – Director, Finance Director • Appointed Finance director on October 2010, director of AUT since 22

Feb 2005 • 20 years’ experience as director/consultant to various public companies

listed on Australia, Canadian and UK exchanges • Includes former directorships at Mint Wireless and Eureka Energy.

Currently a director of Imugene Ltd

■ Fiona Harris – (B Comm, FCA, FAICD) Non-Executive independent Director • Appointed director on 1 Oct 2010 • 15 years’ experience as NED • Current directorships include Altona Mining Ltd, Territory Resources Ltd

and Sundance Resources Ltd. Former director of Alinta Limited

■ Gren Schoch (BSc, MSc, P Eng) – Non-Executive Independent Director • Appointed director on 4 April 2005 • Extensive oil and gas experience, mainly in Canada

• No other current or former directorships within the past three years

■ Alan Watson –(BSc Hons) Non-executive Independent Director

• Appointed director on 17 Nov 2010

• 30 years’ experience in investment banking

• Currently an independent director of TSX-listed AirBoss of America Ltd

23 May 2011


■ Bill Molson (BA (Econ)) Non-executive Independent Director

• Canadian, appointed April 2011

• Former Managing Director at UBS Securities, with expertise in capital raising, capital structuring, M&A and Investor Relations

• Currently involved in private equity

Figure 45: Board shareholdings


■ Board composition well balanced: The board skill set (see Figure 47) appears well balanced for a company of this size, with extensive commercial skills to assist AUT with its growth.

Figure 46: Board composition c Position Tenure Financial Oil & Gas Technical Commercial CEO Top 200 NEDJonathan Stewart Executive Chairman, CEO 6 x x xIan Lusted Technical Director 3 xGraham Dowland Finance Director 6 x x Fiona Harris NED, Independent Director 0.6 x x xGren Schoch NED, Independent Director 6 x xAlan Watson NED, Independent Director 0.3 x xBill Molson NED, Independent Director 0.1 x

Average Tenure (years) 3.1Source: Company data

■ The Top 20 shareholders own ~65% of the company as at 31 March 2011.

Figure 47: Substantial shareholders Rank Shareholder Total Units % of Issued Capital

1 Harbour Investments 35,300,000 8.7%2 J P Morgan Chase and Co 35,089,783 8.6%


Hilcorp Energy ■ Hilcorp farmed in to the four Areas of Mutual Interest 2009: In 2009, AUT and its

partners entered into a farmout agreement with Hilcorp Energy, a private E&P company. Hilcorp was required to drill seven new wells and fracture stimulate three additional wells across three of the AMIs. Hilcorp received priority return of capital costs and a 12% IRR through production. Hilcorp continues as the operator.

Acquisitions ■ 2010 further acquisition in same area: In 2010, AUT acquired a further 5,100 net

undeveloped acres in the Sugarkane field for US$120mn (US$23,500/acre). Net 3P reserves for the acquisition were 28mmboe (US$4.65/boe).

23 May 2011


Companies Mentioned (Price as of 20 May 11) Abraxas Energy (AXAS, $4.09) Anadarko Petroleum Corp. (APC, $74.58, OUTPERFORM, TP $100.00) ANTARES ENERGY LTD (AZZ.AX, A$0.41) Apache Corp. (APA, $123.00, OUTPERFORM, TP $148.00) Aurora Oil & Gas (AUT.AX, A$2.85, OUTPERFORM, TP A$3.60) AWE Limited (AWE.AX, A$1.41, NEUTRAL, TP A$1.70) BP (BP.N, $45.00, OUTPERFORM, TP $59.00, MARKET WEIGHT) Cabot Oil & Gas Corp (COG, $54.66) Carrizo Oil & Gas Inc. (CRZO, $35.67, NEUTRAL [V], TP $43.00) Chesapeake Energy Corp. (CHK, $30.62, UNDERPERFORM, TP $34.00) Clayton Williams Energy, Inc. (CWEI, $72.12) CNOOC Ltd (0883.HK, HK$18.14, UNDERPERFORM, TP HK$15.90) Comstock Resources, Inc. (CRK, $28.62, OUTPERFORM [V], TP $34.00) ConocoPhillips (COP, $72.61, OUTPERFORM, TP $93.00) Crimsom Exploration (CXPO, $3.97) Doxa Energy (DXA.TO, C$0.36) Eagle Ford Oil & Gas (ECCE, $0.36) El Paso Corp. (EP, $19.38) EOG Resources (EOG, $106.95, NEUTRAL, TP $108.00) Eureka Energy Limited (EKA.AX, A$0.28) ExxonMobil Corporation (XOM, $81.57, NEUTRAL, TP $95.00) FieldPoint Petroleum Corp (FPP, $3.12) Forest Oil (FST, $31.38, RESTRICTED [V]) Gastar Exploration (GST, $3.51) GeoResources (GEOI, $23.21) Goodrich Petroleum Corp. (GDP, $19.20) Hess Corporation (HES, $77.92, OUTPERFORM, TP $115.00) Lucas Energy (LEI, $2.70) Marathon Oil Corp (MRO, $51.20, OUTPERFORM, TP $65.00) Murphy Oil Corp. (MUR, $66.88, UNDERPERFORM, TP $73.00) Newfield Exploration Co. (NFX, $74.90, OUTPERFORM, TP $92.00) Occidental Petroleum (OXY, $100.40, NEUTRAL, TP $128.00) Penn Virginia Resource L.P. (PVR, $25.65) PetroHawk Energy Corp. (HK, $25.64, OUTPERFORM, TP $35.00) Pioneer Natural Resources (PXD, $90.94, OUTPERFORM, TP $136.00) Plains Exploration & Production Co. (PXP, $34.41, NEUTRAL [V], TP $48.00) Reliance Industries (RELI.BO, Rs921.40, OUTPERFORM, TP Rs1,142.00) ReoStar Energy Corp (REOS, C$0.04) Rosetta Resources Inc. (ROSE, $46.14, OUTPERFORM [V], TP $62.00) Royal Dutch Shell plc (RDSa.L, 2145 p, OUTPERFORM, TP 2780 p, MARKET WEIGHT) Savoy Energy (SNVP, $0.01) Saxon Oil (SXN) Schlumberger (SLB, $83.50, OUTPERFORM, TP $110.00) St. Mary Land (SM, $65.28) Statoil (STL.OL, NKr137.20, NEUTRAL, TP NKr164.00, MARKET WEIGHT) Swift Energy Co. (SFY, $38.29, OUTPERFORM, TP $54.00) Talisman Energy Inc. (TLM.TO, C$20.32, OUTPERFORM, TP C$28.00) Texon Petroleum Limited (TXN.AX, 0.76) Whiting Petroleum Corp. (WLL, $65.04, OUTPERFORM, TP $81.00)

Disclosure Appendix Important Global Disclosures Nik Burns & Sandra McCullagh each certify, with respect to the companies or securities that he or she analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report. See the Companies Mentioned section for full company names.

23 May 2011


3-Year Price, Target Price and Rating Change History Chart for AUT.AX AUT.AX Closing

Price Target Price

Initiation/

Date (A$) (A$) Rating Assumption

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Closing Price Target Price Initiation/Assumption Rating

A$

O=Outperform; N=Neutral; U=Underperform; R=Restricted; NR=Not Rated; NC=Not Covered

The analyst(s) responsible for preparing this research report received compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities. Analysts’ stock ratings are defined as follows: Outperform (O): The stock’s total return is expected to outperform the relevant benchmark* by at least 10-15% (or more, depending on perceived risk) over the next 12 months. Neutral (N): The stock’s total return is expected to be in line with the relevant benchmark* (range of ±10-15%) over the next 12 months. Underperform (U): The stock’s total return is expected to underperform the relevant benchmark* by 10-15% or more over the next 12 months. *Relevant benchmark by region: As of 29th May 2009, Australia, New Zealand, U.S. and Canadian ratings are based on (1) a stock’s absolute total return potential to its current share price and (2) the relative attractiveness of a stock’s total return potential within an analyst’s coverage universe**, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. Some U.S. and Canadian ratings may fall outside the absolute total return ranges defined above, depending on market conditions and industry factors. For Latin American, Japanese, and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant country or regional benchmark; for European stocks, ratings are based on a stock’s total return relative to the analyst's coverage universe**. For Australian and New Zealand stocks a 22% and a 12% threshold replace the 10-15% level in the Outperform and Underperform stock rating definitions, respectively, subject to analysts’ perceived risk. The 22% and 12% thresholds replace the +10-15% and -10-15% levels in the Neutral stock rating definition, respectively, subject to analysts’ perceived risk. **An analyst's coverage universe consists of all companies covered by the analyst within the relevant sector. Restricted (R): In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain other circumstances. Volatility Indicator [V]: A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24 months or the analyst expects significant volatility going forward.

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23 May 2011


Credit Suisse's policy is only to publish investment research that is impartial, independent, clear, fair and not misleading. For more detail please refer to Credit Suisse's Policies for Managing Conflicts of Interest in connection with Investment Research: http://www.csfb.com/research-and-analytics/disclaimer/managing_conflicts_disclaimer.html Credit Suisse does not provide any tax advice. Any statement herein regarding any US federal tax is not intended or written to be used, and cannot be used, by any taxpayer for the purposes of avoiding any penalties. See the Companies Mentioned section for full company names. Price Target: (12 months) for (AUT.AX) Method: Our target price of $3.60 for Auroral Oil & Gas is based on a a risked sum-of-the-parts discounted cash flow valuation using Credit Suisse oil price, gas price and FX assumptions. We probability-weight our "base valuation" at 100%, which assumes full field development proceeds as outlined by Netherland Sewell & Associates Inc (NSAI). We also include 75% probability of achieving a 20% increase in higher production rates, with well outerperforming NSAI assumptions. We also include 25% risk-weighting on moving from 80 acre well spacing to 60 acre spacing, which is being trialled in the months ahead. Risks: The critical risks associated with our $3.60 AUT target price, forecasts and valuation, relate to commodity price assumptions, the pace of future drilling activity and production rates from future wells. To a lesser extent, the sector is experiencing some short term upside pressure to operating costs and capex estimates as drilling and fracture stimulation activities ramp up in the Eagle Ford Shale. Longer-term risk in our opinion relates to the company's use of free cash flow, with the company stating that it intends to also grow through the acquisitions of new acreage positions. Please refer to the firm's disclosure website at www.credit-suisse.com/researchdisclosures for the definitions of abbreviations typically used in the target price method and risk sections.

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Aurora Oil & Gas - Credit Suisse

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