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Reservoir Prospect Gross

Resources CoS Mean MMbbls %

Toubkal 790 20% Zagora 47 23% Miocene Amchad 38 23% Jbel Musa 87 11% Jbel Ayachi 69 11% Albian Jbel Lakhdar 69 11%

Total: 1,100

Stock Data (Aus$) Share Price (A$/share) 0.23 Market Capitalisation (A$m) 9.3 Net Cash FY’12 forecast (A$m) 2.0 Enterprise Value FY’12 (A$m) 7.3 Fully dil. shares in issue (m) 41.4 Price Target (A$/share) 0.80 Upside (%) 248% Key Indicators WI C & P Resources (MMbbls) 825 EV/Prospective (US$/bbl) 0.01 Risked EV/Prospective (US$/bbl) 0.11 NAV Data

Core NAV (A$/share) 0.11

Total NAV (A$/share) 0.11

RNAV (A$/share) 5.61

P/RNAV (x) 0.04

Analysts

Tracy Mackenzie / Jack Allardyce

T: +44 (0) 131 529 0376 / 2067 E: first.second@nplus1brewin.com

Introductory Research 29 February 2012* 4

Pura Vida Energy Oil & Gas Explorers

BUY

Early Entry on North Atlantic Margin Acreage Pura Vida Energy (ASX: PVD) is an exploration focused companyrecently listed on the ASX. It has a 75% interest in the Mazagan Offshore Area, offshore Morocco. Whilst high risk given the frontier nature of theacreage, its rating is attractive versus its peers and could provide acheap entry point for those looking for exposure to North Africa wherelarger players are moving in (Kosmos is operator of adjacent acreage). We initiate with a Buy recommendation and a A$0.80/share PT. An Experienced Board PVD’s executives have experience at a senior level with larger industryparticipants that include; Tap Oil, Karoon Gas, BHPBP, Stirling and Woodside.An Independently verified prospective resource base of 825 MMbbls (net)An Independent Resource Assessment by RISC estimates net prospectiveresources of 825 MMbbls to PVD’s current 75% interest (although we assumea farm-down to 37.5% in our valuation). A compelling valuation versus Peer Group In our view, PVD’s closest comparator is Tangiers Petroleum, a pure exploration play with acreage in Morocco and Australia (dual listed on ASX &AIM). Tangiers currently trades at a risked EV/2P+C+P of $1.51/boe versus PVD which is trading on $0.09/boe (incorporating all resources). In aggregate, we believe there is potential for near-term high impact events, including the recognition of additional resources followingcompletion of the seismic reprocessing (currently underway), farm-outnegotiations leading to securing funding for the drilling program and acquisitions.

*Priced on closing prices on 24th February 2012. This research is based upon facts and figures at this time. It may be subject to further updates in due course, as or at a future date. N+1 Brewin is retained by Pura Vida Energy for the provision of research services. This document is a Marketing Communication and has not been prepared in accordance with legal requirements designed to promote the independence of investment research and is not subject to any prohibition on dealing ahead of the dissemination of investment research. Please refer to important disclosures at the end of this document.

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Table of contents VALUATION REVIEW 7 SWOT Analysis 13 PEER REVIEW 14 COMPANY REVIEW 19

Corporate Structure 20 Play/Asset REVIEW 21

Industry 22 Morocco in Context & The Atlantic Margin 23 Mazagan Permit (PVD: 75%) 25 Exploration History 25 Hydrocarbon Prospectivity 28

The Basics 28 The Prospects/Leads 29 Work Programme 31

FINANCIAL REVIEW 32 APPENDICES 36

Regional Specifics 38 Existing Seismic / Structural Data 40 Miocene Prospects 41

Toubkal 41 Amchad and Zagora 43 Risks 44

Lower Cretaceous Prospects 45 Jbel Musa, Jbel Ayachi and Jbel Lakhdar 45 Risks 46

SPE/WPC/AAPG/SPEE Petroleum Resources Management System 47

4

Executive Summary Synopsis Pura Vida Energy (PVD) is an independent exploration and production company headquartered in Perth, Western Australia. The Company has a 75% interest in exploration acreage known as the Mazagan Offshore Area, off the Atlantic coast of Morocco in North Africa1. The term of the permit is 8 years, comprising an initial 2 year period, after which time PVD has the option to enter further periods of 2 years and 4 years respectively. PVD’s immediate priority is to undertake geological works to de-risk its prospect inventory. At that juncture, the aim would be to utilise its high equity interest and seek a larger farm-in partner to move to the next stage (an exploration drilling programme). PVD’s executives have experience at a senior level with larger industry participants that include; Tap Oil, Karoon Gas, BHPBP and Woodside. The MD, Damon Neaves, was formerly the Business Development Manager for Tap Oil and the Technical Director, David Ormerod, has participated in several major discoveries2 throughout his career as well as being responsible for Karoon Gas’ entry into Brazil. PVD’s management team brings together a blend of technical and commercial skills with extensive industry experience and a track record in value-accretive acquisitions. The competitive terms for the acquisition of the Mazagan area demonstrate the ability of the management team to execute the company’s acquisition strategy effectively. An Independent Resource Assessment by RISC3 was concluded in September 2011 and concluded that the permit ‘offers significant frontier exploration potential at moderate to high risk’. They estimated a gross prospect inventory totalling 1.1 billion bbls on a geological CoS range of 11-23%, as detailed below. The largest feature is the Toubkal stratigraphic trap, with mean unrisked prospective resources of 790 MMbbls and an estimated CoS of 20% (1 in 5). Gross Prospect Inventory (PVD: 75%)

Reservoir Prospect/Lead Gross Unrisked Prospective Resources CoS Low Best High Mean MMbbls MMbbls MMbbls MMbbls %

Toubkal 180 560 1670 790 20.0% Zagora 13 35 95 47 23.0% Miocene Amchad 8 26 81 38 23.0% Jbel Musa 14 53 195 87 11.0% Jbel Ayachi 12 43 153 69 11.0% Albian Jbel Lakhdar 12 43 153 69 11.0%

239 760 2,347 1,100

Source: RISC report September 2011

1 The remaining 25% is held by the Moroccan NOC, Office National des Hydrocarbures et des Mines (ONHYM). ONHYM’s interest is carried throughout the exploration period. 2 Including Mad Dog, Atlantis and Neptune in the Gulf of Mexico and the Stybarrow discovery in the North West Shelf offshore Western Australia. 3 RISC was founded in 1994 and operates out of Perth, Australia and London, UK. They have completed over 1300 assignments in 68 countries for nearly 500 clients.

5

Rating The table below gives an indication of the current rating based on an Unrisked and Risked EV/prospective resources basis, current cash and other balance sheet items. The table below assumes the following:

Interest will be farmed down from 75% to 37.5% (thus net prospective resources go from 825 MMbbls to 412.5 MMbbls).

The Risked EV/Prospective resources applies a 90% risking (i.e. a chance of success of

10%). Thus the current Risked EV/Prospective resources = $4.4m/(413 MMbbls*10%) = $0.11/bbl ($0.01/bbl on an unrisked basis).

Current Rating (A$m)

Current1 Current1 Risked Unrisked Prospective Resources (MMboe) 41.3 412.5 Valuation, $m 9.3 9.3 Net debt (cash), $m -5.5 -5.5 EV, $m 3.8 3.8 EV/Prospective Res. ($/boe) 0.09 0.01

Source: N+1 Brewin Peers In our view, PVD’s closest comparator is Tangiers Petroleum, a pure exploration play with acreage in Morocco and Australia (dual listed on ASX & AIM). We would note that Pura Vida is at a more advanced stage than Tangiers, in having 3D seismic over all of its prospects. However, Tangiers has recently completed a 3D seismic survey (aimed at de-risking and delineating the areal extent of three prospects). The chart below attempts to benchmark PVD’s rating against its listed peers with an African exploration focus, the vertical axis’s shows the individual company valuations on a risked EV/(2P + Contingent + Prospective) basis ($/boe). So for example, Tangiers currently trades at a risked EV/2P+C+P of $1.51/boe versus PVD which is trading on $0.09/boe (this assumes both Tangiers and Pura Vida farm down their 75% interests in Morocco to 37.5%). Peer Ratings Comparison (Risked EV/boe)

1.731.51

1.030.86

0.53 0.60

0.24 0.29 0.16

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Source: N+1 Brewin Notes: Those with frontier exploration at an earlier stage have all been risked at 10%, Cove is risked at 50% and its actual rating is beyond the scale at $13/boe and Pancontinental’s rating is higher due to it having an existing carry (again off the scale at $12./boe). The average in the chart excludes, Cove (discovery already made/takeover), Dominion (takeover), Pancontinental (has an existing carry) and Pura Vida.

6

In Summary Whilst the company’s rating is likely to be below that of its more established peers that have more advanced programmes (funding established and drilling timings defined) we believe the discount to represent an attractive investment opportunity. The Pura Vida investment case offers investors exposure to a large prospect inventory at a significant discount to its closest listed peers (i.e. Tangiers). However, we think it is worthwhile to look at how the rating may behave under various scenarios. Whilst binary outcomes would likely prevail on the rating (our risk reward has a swing of: +554% to -87%) as first drilling commences this is unlikely to be confirmed for some time4. In the shorter-term, the valuation/rating could advance on the de-risking of prospects from technical works and the potential convergence towards peer comparator ratings. A high equity interest of 75% facilitates greater potential farm-down options/terms. Success on nearby blocks/similar plays would de-risk Pura Vida's potential from an investor’s perspective. During 2011 a number of large independents have taken acreage positions offshore Morocco (including Kosmos) so we expect activity to step-up through 2012. Thus, any share price reaction is more likely to revolve around prospect de-risking, moves towards establishing a farm-in partner and on a peer comparison basis over the next 12 months. In the longer term the rating will likely gravitate to the polar outcomes (see discussion). Upcoming newsflow/Catalysts

Event/Prospect Timing CoS (%)

Risked (A$/s)

Unrisked (A$/s)

Seismic re-processing Ongoing to Q3 2012 - - - Farm-out discussions Q1 ->Q4 2012 - - - Potential acq. of new project Q1->Q2 2012 - - - 1st Exp. Well (Toubkal) 2013 20% 4.3 21.5

Total 4.3 21.5

Source: N+1 Brewin We would note that our current fully diluted shares in issue is 41.4m and excludes restricted partly paid shares, restricted performance right shares and out of the money options. By 2014 we expect fully diluted shares in issue (all else remaining equal) to be c. 63.2m share. The table below summarises where our price target and RNAV would reside applying the shares in issue. Valuation on Fully Diluted Scenarios

Fully diluted shares in issue (m) 41.4 63.2 Price Target (A$/share) 0.8 0.5 RNAV (A$/share) 5.6 3.7

Source: N+1 Brewin

4 See page 12 for an exposition of risk-reward estimation.

7

VALUATION REVIEW

8

Investment Case & Valuation Valuation Methodology Our valuation methodology normally applies a rating based on a Price/Risked Net Asset Value (P/RNAV) basis. The P/RNAV multiple is applied based on the maturity of the portfolio and benchmarked against similar peers. However, where a company has a concentrated portfolio, all of which resides in the exploration stage, utilising a valuation based on estimated NAV could be misleading. The rationale being that the NAV is largely predicated on too few prospects, that in the exploration component of the NAV, to provide a realistic Economic Monetary Value (EMV)5 as the outcomes are likely to be binary. Thus, whilst we have undertaken typical NAV analysis, our price target is based on peer benchmarking on an Enterprise Value (EV) to resources basis ($/boe). The rationale being that the ratings of frontier explorers, with no booked reserves but with contingent and/or prospective resources, is more likely predicated on a heavily risked value of the potential resources on a $/boe basis. Valuation Range Summary The table below shows the current indicative valuation on a $/boe basis. It also attempts to indicate where the valuation may increase to over the next 18 months as the Company undertakes its work programme (as detailed in the use of funds) and should the prospects be de-risked by the market. The upside scenario detailed for the end of 2012 below anticipates the following:

Total capex of A$3.5m is deployed towards: 50 drop cores (sea bed samples), reprocessed 3000km2 of seismic to pre stack depth and detailed seismic inversions and ongoing geological studies.

Interest will, at some stage, be farmed down from 75% to 37.5% (thus net prospective

resources go from 825 MMbbls to 412.5 MMbbls). Y/E 2012 cash balances of A$2.0m.

The Risked EV/Prospective resources applies a 90% risking (i.e. a chance of success of

10%). Thus the current Risked EV/Prospective resources = $3.8m/(413 MMbbls*10%) = $0.09/bbl.

Successful indicators/works undertaken and/or positive indications on farm-in partner/s

(PVD’s or peers) lead to a re-rating on a Risked EV/prospective resources basis more in-line with its peers.

Assuming progress continues on schedule in regards to cores and seismic reprocessing,

and initial indications are positive then PVD's rating begins to converge towards listed peers. If it achieves a rating of at least 50% of its closest peer (Tangiers: EV/Pros res. = $1.51/boe) it would have a Risked EV/boe of closer to $0.75/boe which equates to a market value of A$33m or A$0.80 (versus the current price of A$0.23, suggesting almost 250% upside).

5 Given the pure exploration nature of PVD our RNAV comprises largely of an EMV of the exploration portfolio we have visibility on (generally named prospects). To estimate its EMV we look at each prospect on the basis of the potential size of the prospect and its assigned chance of success (CoS). For our success case value we will either model the individual prospects on a DCF basis to derive an asset specific potential NPV or benchmark them against an ‘in the ground NPV’ value from similar fields as a value proxy. This should enable us to capture the time-value of the capital required to develop an asset in the event of a successful discovery.

9

Potential rating evolution

2012 2012-2013 2012 Current Potential ∆ Year end Prospective Resources (MMboe) 413 0.0 413 Valuation, $m 9.3 33.1 Net debt (cash), $m -5.5 -3.5 -2.0 EV, $m 3.8 31.1 Risked EV/Prospective Res. ($/boe) 0.09 0.66 0.75

Source: N+1 Brewin Should the results of re-processing and other works further de-risk the prospects and there are positive indications of a farm-in partner PVD should trade at least in line with the likes of Tangiers on a Risked EV/Pros res. of $1.5/boe. This would equate to a share price of A$1.5/share.

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NAV Constituents Our total net asset value (TNAV) is comprised of our core NAV (CNAV) on producing 2P reserves (nothing as yet in Pura Vida’s case), balance sheet items (and appraisal projects pending development (again nothing as yet in Pura Vida’s case). We estimate Pura Vida’s risked TNAV (essentially balance sheet items) at A$0.11/share versus the current share price of A$0.23/share. Our EMV includes the prospect inventory as outlined by the Competent Persons Report (Miocene & Albian targets). However, we have assumed that Pura Vida would look to farm-down its interest to c.37.5% (from 75%) to garner a carry on any drilling programme. We would caveat that the EMV is heavily skewed by the Toubkal prospect which is the largest (net prospective resources of c. 300 MMbbls on a 37.5% interest and an estimated CoS of 20%). Our overall risk adjusted value (RNAV) is c.A$5.6/share (A$30.0/share unrisked). However, we would caveat that the volumetrics within our EMV are heavily skewed by one prospect, the Toubkal prospect which is the largest (net prospective resources of c. 300 MMbbls on a 37.5% interest and an estimated CoS of 20%). We would also caveat that our current fully diluted shares in issue is 41.4m and excludes restricted Partly paid shares, restricted performance right shares and out of the money options. By 2014 we expect fully diluted shares in issue (all else remaining equal) to be c. 63.2m share.

Net Asset Value

Country/Field 2P Unrisked Risked U/R WI CoS Reserves NAV NAV NAV NAV NAV NAV

(%) (%) (MMbbls) ($m) ($/boe) ($m) ($/boe) (A$/s) (A$/s) Morocco No currently producing 2 P reserves Net (Debt)/Cash (2011A) 5.5 5.5 0.13 0.13 Overheads -0.9 -0.9 -0.02 -0.02 Core NAV 4.6 4.6 0.11 0.11 Country/Field Net Cont Unrisked Risked U/R

WI CoS Total NAV NAV NAV NAV NAV NAV (%) (%) (MMbbls) ($m) ($/boe) ($m) ($/boe) (A$/s) (A$/s) Morocco Currently no discoveries under appraisal/development Appraisal/Development NAV - - - - - Total NAV 4.6 4.6 4.6 0.11 0.11 Drilling Programme Net Prosp. Unrisked Risked U/R

WI1 CoS2 Total NAV NAV EMV EMV EMV NAV (%) (%) (MMbbls) ($m) ($/boe) ($m) ($/boe) (A$/s) (A$/s) Morocco - Miocene reservoir targets Toubkal (stratigraphic trap) 37.5% 20% 296.3 888.8 3.0 177.8 0.6 4.29 21.47 Zagora (structural closures against salt diapirs) 37.5% 23% 17.6 52.9 3.0 12.2 0.7 0.29 1.28 Amchad (structural closures against salt diapirs) 37.5% 23% 14.3 42.8 3.0 9.8 0.7 0.24 1.03 Morocco - Albian reservoir targets Jbel Musa 37.5% 11% 32.6 97.9 3.0 10.8 0.3 0.26 2.36 Jbel Ayachi 37.5% 11% 25.9 77.6 3.0 8.5 0.3 0.21 1.88 Jbel Lakhdar 37.5% 11% 25.9 77.6 3.0 8.5 0.3 0.21 1.88 EMV 412.5 1237.5 227.6 0.6 5.50 29.89

RNAV 412.5 1240.0 232.2 0.6 5.61 30.01

Source: N+1 Brewin Whilst our target price is not predicated/benchmarked on RNAV it equates to a P/RNAV of 0.04x.

11

Pura Vida Energy

Outcome Analysis The decision tree analysis below attempts to capture the potential outcomes for Pura Vida’s rating based on the expected future drilling programme as it stands. Our Risked NAV (RNAV) is A$5.6/share, however, this encapsulates the risked values of each of its plays from its defined prospect inventory. These are yet to be defined exploration wells and are likely have binary outcomes. Thus, we have undertaken probabilistic decision tree analysis showing where our RNAV would reside under each set of available scenarios. Thus, investors can take a view of which wells/outcomes they have more/less confidence in etc. Whilst our RNAV captures the riskings associated with each of the defined drilling plays (based on applied chance of success), we also weighted the outcome analysis (applying CoS v. CoF percentages) on each of the prospects based on binary outcomes (success or failure). The key events for 2012 will likely be de-risking the prospects in order to attract a farm-in partner, however, the outcome analysis attempts to outline the potential outcomes on the commencement of a drilling campaign (targeted for 2013). The Defined Programme Pura Vida has commenced works as outlined in its work programme. It has entered into an agreement for the reprocessing, imaging and quantitative interpretation of 3,000km2 of 3D seismic data as well as engaged contractors to undertake a seepage detection study and to prepare an Environmental Impact Study for the acquisition of 50 ocean bed drop cores. Morocco– Toubkal (PVD WI: 75%) – Pura Vida currently expects the first well to be drilled on

the Toubkal prospect (targeting 2013). This is a combined structural and stratigraphic play, with a prospective reservoir made up of turbidite/debris flows, delineated by seismic amplitudes. Our pre-drill riskings are in line with the CPR and may appear high for a frontier play. We ascribe a 20% CoS versus the 10% CoS we would typically apply to a frontier play.

However, we have assumed that PVD farm-down to a 37.5% interest (from 75%) to fund a

drilling programme. The reduced barrels ascribed offsets the lower riskings.

Based on a conservative, ‘in the ground’ value of $3/bbl, we estimate an unrisked value of the Toubkal prospect alone, based on a 37.5% interest, of c.$890m (c. A$21.5/share) on the ultimate success case (100% CoS), c.A$4.3/share on a risked basis. Within our outcome analysis, indications of an initial discovery (in-line with size prognosis) would lead us to unwind our riskings from 20% to 35%. On the ultimate failure case we would remove its value and the risked value ascribed to the Zagora Miocene prospect.

Other prospects – (PVD WI: 75%) – Whilst our outcome analysis incorporates the existing

Miocene and Albian prospects, we expect that on the success case at Toubkal, the new prospects to the West, in deeper water, to be targeted. This would require additional 3D seismic. In the interim, the Lower Cretaceous targets may be targeted.

On the failure case the Amchad may be targeted ahead of Zagora.

12

Pura Vida Energy

Outcome Analysis

Source: N+1 Brewin, Company Data

13

Pura Vida Energy

Risk & Reward / Scenario Analysis The table below attempts to show where our valuation would reside under varying eventualities during 2012/2013, looking at more qualitative drivers such as rating de-risking from the evolvement of the work programme etc. The analysis suggests an attractive risk-reward with upside potential of up to c.554% downside of c.87% on the work programme/peer comparison outlined.

Scenario Events/Assumptions Implied % ∆

Bull case A$1.5

Results of re-processing and other works further de-risk the prospects and there are positive indications of a farm-in partner. Trades at least in line with the likes of Tangiers on a Risked EV/Pros res. of $1.51/boe.

554%

Base Case A$0.8

Assumes progress continues on schedule in regards to cores & seismic reprocessing. Initial indications are positive and PVD's rating begins to converge towards listed peers (Risked EV/Pros res = $0.75/boe).

248%

Bear Case A$0.3

Seisimic re-processing and drop core program yield negative results and no progress on farming down. Reversion to post activities cash.

-87%

Source: N+1 Brewin SWOT ANALYSIS

STRENGTHS WEAKNESSES Management – Good balance of disciplines, with the requisite level of experience, both in oil and gas(technically and commercially) and capital markets.

High Risk – a high risk, frontier exploration programme with ultimately a likely binary outcome for shareholders. While a successful outcome offers significant upside from current levels, the failure case is effectively cash at bank. However, ahead of any drilling the work programme and any subsequent farm-down should moderate shorter term moves in rating.

First Mover Advantage – Early entry into acreage with high % equity position (75%). This gives investors an opportunity to invest at an attractive early valuation and strong position for farm down.

Concentration of Portfolio – The company’s entire portfolio consists of the Mazagan portfolio. The lack of diversity further heightens the downside scenario.

Material Exploration Potential – Six prospects already identified with the largest, Toubkal, containing 790 MMbbls of prospective resource. A discovery of this magnitude would completely transform the industry within Morocco as well as the company.

Subsurface Challenges – Toubkal is defined completely by amplitude responses, which are theorised to indicate the presence of hydrocarbons. Stratigraphic traps are typically more difficult to target vs. structural prospects, while a lack of well analogues also increases the likelihood of variability in stratigraphy.

OPPORTUNITIES THREATS Farm Down – Strong position with regards topotential partners, which could see the companyreceive a carry on all/some costs going forward. 75% position also allows PVD to seek a strategic partnerwith deepwater/regional experience while stillmaintaining a material equity stake.

Economic Outlook – Wider macroeconomic environment and (particularly) current low appetite for risk could pose funding issues. Extended tightness in capital markets could become more significant issue as company moves into 2nd phase of exploration and requires funding for wells unless carried via farm-down.

Additional Acreage – Broad international experienceof management team can be leveraged in seeking outadditional opportunities.

Lack of Farm-in interest – Pura Vida’s forward plan is largely predicated on its ability to de-risk its prospect inventory and then farm-down for the next stage (actual drilling). If they are unable to secure a partner the rating could stagnate until visibility on funding is secured.

Source: N+1 Brewin

14

Pura Vida Energy

PEER REVIEW

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Pura Vida Energy

Peer Group Valuation Analysis In terms of peer group analysis, we have considered a number of companies listed across the ASX, AIM and TSX with exploration acreage in Africa. The table below provides a list of these comparators with some brief commentary to indicate the level of maturity of the prospective resource base in each case. The Ratings Quadrant table (see page 17) compares valuation metrics for these potential comparators. The resources estimates are taken from the last public documents for each of the companies – e.g. last annual report, prospectus, competent persons report or public announcement/presentation. The only adjustment is to incorporate any known acquisitions or disposals as the Enterprise Value should reflect this information and cash/debt changes. The charts below attempt to benchmark PVD’s rating against its listed peers with an African exploration focus, with the vertical axes shows the individual company valuations on a risked EV/(2P + Contingent + Prospective) and unrisked EV/(2P + Contingent + Prospective) resource basis ($/boe) respectively. So for example, Tangiers currently trades at a risked EV/2P+C+P of $1.51/boe. In comparison our range for PVD on a comparable basis incorporating all resources is $0.09/boe. Ratings Comparison (Risked EV/boe)

1.731.51

1.030.86

0.53 0.60

0.24 0.29 0.16

0.74

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Source: N+1 Brewin Notes: Those with frontier exploration at an earlier stage have all been risked at 10%, Cove is risked at 50% and its actual rating is beyond the scale at $13/boe and Pancontinental’s rating is higher due to it having an existing carry (again off the scale at $12/boe). The average in the chart excludes: Cove (discovery already made & subject to takeover), Dominion (takeover), Pancontinental (has an existing carry) and Pura Vida.

… valuation…sits at a significant discount

16

Pura Vida Energy

Ratings Comparison (Unrisked EV/boe)

0.15 0.150.10 0.09 0.05 0.06 0.02 0.03 0.02

0.070.01

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oe)

Source: N+1 Brewin Notes: The average in the chart excludes: Cove (discovery already made and subject to takeover), Dominion (takeover), Pancontinental (has an existing carry) and Pura Vida. In summary: ⇒ Pura Vida trades at a significant discount to its ASX, AIM and TSX listed peers. On an unrisked

EV/Resources basis the averages (exc. outliers detailed above) are PVD - $0.01/boe, ASX - $0.11, AIM - $0.03/boe and TSX $0.07/boe.

⇒ A doubling of PVD’s rating would only bring it in line with the lowest rated peer in our sample set

(Tower Resources). ⇒ Tangiers rating looks full, especially when compared to Rialto which is the only company in our

sample set with contingent and prospective resources. We therefore look to benchmark our PT at a discount to Tangiers.

⇒ Assuming progress continues on schedule in regards to cores & seismic reprocessing. Initial

indications are positive then PVD's rating should begin to converge towards listed peers. If it achieves a rating of at least 50% of its closest peer (Tangiers: EV/Pros res. = $1.51/boe) it would trade on a Risked EV/boe of closer to $0.75/boe which equates to a market value of A$33m or A$0.80 (versus the current price of A$0.23, suggesting almost 250% upside).

⇒ We therefore believe that a strong buy case exists on a peer comparison basis as Pura

Vida is the new entrant to the public markets and is relatively unknown.

…a strong buy case exists on a peer comparison basis

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Comparator Companies

Company Exchange Ticker African Portfolio Equity Exploration Phase/ Commentary Constituents interest (%) Milestones Australian Comparators Tangiers Petroleum ASX TPT Morocco (Tarfaya offshore block) 75% 2D Seismic only Seeking farm-in partners to conduct 3D and

carry out initial drilling WHL Energy ASX WHN Seychelles (offshore exploraation area) 100% 2D Seismic only Frontier exploration, v.high risk. States

potential drilling programme 2012/13 Pancontinental Oil & Gas ASX PCL Kenya (Lamu Basin Offshore)

Namibia (Offshore Northern Namibia) 15-40%

85% 2D Seismic only Frontier exploration, v.high risk. Carried on

a well in Kenya in H2 2012. In Namibia, seeking a farm-in partner conduct 3D and carry out initial drilling

Rialto Energy ASX RIA Cote d'Ivoire (Offshore) Ghana (awaiting assignment)

85% 18%

3D seismic and defined drilling programme

In Cote d'Ivoire a multi well programme is expected to commence in Feb 2012. In Ghana there is a commitment well by Oct 2012.

UK Comparators Chariot Oil & Gas AIM CHAR Namibia (8 offshore blocks) 50% 2D & 3D Seismic 3 Farm-in partners secured to date.

Remains frontier exploration. 4-5 wells targeted to be drilled through to 2013.

Cove Energy AIM COV Mozambique (Rovuma offshore & onshore) Tanzania (producing gas asset & exploration) Kenya (5 offshore blocks)

8.5-10% 16.4-20.4%

15%

3D Seismic and discovery wells Producing gas asset & new 3D expected on exploration area 2D Seismic & 3D planned

Several gas discovery wells (2010-11). Decision on an LNG solution expected by Q3 2013.

Dominion Petroleum AIM DPL Tanzania (1 offshore block & 3 onshore) Uganda (Exploration area 4B) Kenya (2 offshore blocks)

80% 2D & 3D Seismic Recommended offer by Ophir on October 2012 for an implied value of c.US$190m

Tower Resources AIM TRP Uganda Namibia (3 blocks offshore)

2D Seismic & 2 dry wells 2D & 3D Seismic

No clear visibility on a forward programme in Uganda. A well is expected do drill the first Namibian well in H1 2012.

Canadian Comparators Africa Oil TSX.V AOI Kenya (6 onshore blocks)

Ethiopia (3 blocks onshore) Mali (2 onshore blocks)

30-100% 30-55%

25%

2D seismic Large oil discovery announced (Feb 2012) Two wells stated to be planned for 2012

Energulf Resources TSX.V ENG Namibia (Offshore block) DRC (Onshore block)

10-19% 90%

3D Seismic 2D Seismic

In Namibia, further 3D acquisition expected in 2012.

Longreach Oil & Gas TSX.V LOI Morocco (2 offshore blocks) Morocco (3 onshore blocks)

10% 30-50%

Drilling Drilling/Seismic

Upcoming drilling programme across portfolio.

Source: N+1 Brewin

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Ratings Quadrant

Unrisked Net Contingent Resources Unrisked Net Prospective Resources Risked Prospective Resources Company Mkt Cap. (Debt)/Cash EV Oil Gas Equ. EV/(2P+C) Oil Gas Equ. EV/(2P+C+P) CoS Equ. EV/(2P+C+P) (US$m) (US$m) (US$m) MMbbls Bcf MMboe $/boe MMbbls Bcf MMboe $/boe % MMboe $/boe ASX Exchange Tangiers Petroleum1 83.5 7.9 75.6 0.0 0.0 0.0 - 325.1 1054.0 500.8 0.15 10% 50.1 1.51 WHL Energy 61.3 3.7 57.6 0.0 0.0 0.0 - 3500.0 - 3500.0 0.02 10% 350.0 0.16 Pancontinental Oil & Gas2 129.1 9.2 119.9 0.0 0.0 0.0 - 96.2 23.5 100.1 1.20 10% 10.0 11.98 Rialto Energy 184.5 44.4 140.1 50.0 396.0 116.0 1.21 511.0 1800.0 811.0 0.15 10% 81.1 1.73 Pura Vida 9.3 5.5 3.8 0.0 0.0 0.0 - 412.5 - 412.5 0.01 10% 41.25 0.09 ASX average 1.21 0.10 0.10 3.09 ASX average exc. Pancon. & PVD 1.21 0.11 1.13

AIM Exchange Chariot Oil & Gas 501.9 139.6 362.3 - - - - 12471.0 - 12471.0 0.03 10% 1247.1 0.29 Cove Energy 1846.1 164.8 1681.3 - 124.6 20.8 80.93 - 1561.7 260.3 5.98 50% 130.1 12.92 Dominion Petroleum3 186.3 10.7 175.6 - - - - 517.9 7163.1 1711.8 0.10 10% 171.2 1.03 Tower Resources 65.9 12.7 53.2 - - - - 2205.0 - 2205.0 0.02 10% 220.5 0.24 AIM average 80.93 1.53 3.62 AIM average exc. Cove (discovery), Dominion (take-over) & PVD - 0.03 0.27

TSX Exchange Africa Oil 438.2 119.7 318.5 - - - - 5328.0 - 5328.0 0.06 10% 532.8 0.60 Energulf Resources 46.7 3.5 43.3 - - - - 815.0 - 815.0 0.05 10% 81.5 0.53 Longreach Oil & Gas 16.0 11.8 4.2 - - - - - 292.0 48.7 0.09 10% 4.9 0.86 TSX average - 0.07 0.66

Notes: 1 Prospective oil resources assumes a farm down of its Tarfaya Block interest from 75% to 37.5%. Prospective gas resources are from its 90% interest in the Nova prospect in Australia.

2 Prospective resources only includes its net interest in the one prospect in Kenya to be drilled in H1 2012. Unable to find data on other prospects. 3Values represent the valuation at take-over by Ophir. Prices are at closing on 24th February 2012 (FX: A$/US$: 1.0)

Source: N+1 Brewin

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COMPANY REVIEW

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Company Background Pura Vida Energy is an independent exploration and production company headquartered in Perth, Western Australia, which was incorporated on 28 April 2011. The Company has a 75% interest (pending final sign-off, see below) in exploration acreage known as the Mazagan Offshore Area, off the Atlantic coast of Morocco in North Africa. It intends to develop and drill exploration wells on this acreage, while also building a diversified portfolio of additional oil and gas assets. Corporate Structure The company is led by Managing Director Damon Neaves, Technical Director David Ormerod and (Non-Executive) Chairman Bevan Tarratt. • Damon Neaves, LLB, B.Comm, A.S.I.A - Founding director and shareholder of PVD. A geologist,

Mr Neaves has previously worked in various commercial, operational and management roles within the international oil and gas industry. Latterly he headed business development at ASX-listed Tap Oil, having previously held various senior management positions. During his eight year tenure at Tap he led teams in a number of acquisitions, many of which involved entry into new countries. These included: Thailand, Ghana, Indonesia, Brunei, Philippines, Australia and New Zealand. Prior to working in oil and gas Mr Neaves practised as a lawyer and corporate advisor.

• David Ormerod, Bsc. Geology (Hons) - Founding director and shareholder of PVD. Mr Ormerod

has over 25 years’ experience in a number of senior positions in the upstream oil and gas sector and has participated in several major discoveries during this time. He was formerly the New Ventures Manager and South America Exploration Manager for Karoon Gas where he was responsible for entry into Brazil and offshore Peru, which saw a period of dramatic growth in shareholder value. Prior to that Mr Ormerod spent 14 years with BHPBP where he gained experience in the Gulf of Mexico, West Africa, South East Asia and the North West Shelf. He also led the Mexico exploration team at Woodside, was New Ventures Manager at Tap Oil and managed Sterling Oil & Gas’ assets in West Africa.

• Bevan Tarratt, SDIA - Mr Tarratt has an extensive background in the accounting industry, has

owned various medium sized retail businesses and has over 10 years’ experience in oil & gas, primarily focused on small cap resource companies. He also has previous equity markets experience with Paterson Securities Limited, and has several years’ experience in the evaluation of mineral resources acquisitions, principally in Africa. Mr Tarratt has experience in primary and secondary capital raisings and corporate strategic consulting, having managed several Initial Public and Re-compliance offerings on the ASX and having participated in the re-structuring and re-compliance of numerous ASX-listed companies. He is currently an Executive Director of ZYL Limited (ASX:ZYL); and a Non- Executive Director of Minerals Corporation Limited (ASX:MSC) and of Stonehenge Metals Ltd (ASX:SHE).

We believe the management team to present a strong balance of disciplines, with the requisite level of experience, both in oil and gas (technically and commercially) and capital markets, to provide comfort to investors. However, the current team would be expected to expand through the addition of further management/consultants as the portfolio is progressed. Additionally, we see the fact that all three directors are equity holders as a major positive, aligning the interests of management with all investors. While the subsurface experience/abilities of the team are important within any E&P company, this is typically heightened within a frontier exploration company, where the fortunes of the business are wholly based on success with the drillbit. We therefore view the extensive experience of the Technical Director, particularly during his time at BHPBP in West Africa, as invaluable.

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Pura Vida Energy

PLAY/ASSET REVIEW

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Pura Vida Energy

Morocco – An existing province with a new edge Industry In comparison to its prolific neighbour Algeria, the North African Kingdom of Morocco has a relatively modest upstream industry. While exploration began in 1929, oil production had been in slow decline since the ‘70s, however, more recently production increased from c. 400 bopd in 2001 to c.4,000 bopd in 2010. It is estimated that Morocco imported in excess of 95% of its energy requirements each year from 2002 through 2008, making it the second largest importer of energy in Africa. The government has been increasingly supportive towards International companies helping it to grow its domestic production, the number of licences granted increasing from 9 in 2000 to 115 in 2011. The chart below clearly illustrates the increase in exploration activity. Morocco Activity Evolution

Source: ONHYM However, while a variety of plays have been discovered, most sedimentary basins, including those offshore, are still largely unexplored. The country does have some infrastructure however, with two oil terminals and two refineries. The Maghreb-Europe gas (MEG) pipeline links Algeria and Spain, and runs from Algeria's Hassi R'Mel field to the Moroccan frontier town of Oujda. It then extends 545km across Morocco to the Estrecho Station near Tangiers and 42km under the sea, terminating at Cordoba 270km inland. Morocco Energy Infrastructure

Source: PVD Under Morocco’s hydrocarbon code, the government, via the state company (ONHYM), retains a 25% participation right of up to 25% in oil and gas licences. Not surprisingly, Morocco has exceptionally attractive fiscal terms with 10 year tax holidays (from first production) on any discoveries and royalties ranging from 3.5% to 10% (contingent on water depth and gas versus oil). Total government take as a percentage is approximately 30% versus a global average of c.67%.

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Pura Vida Energy

Morocco in Context & The Atlantic Margin Although hydrocarbon occurrences in Morocco are represented by a variety of liquid and gas accumulations ranging from dry gas in the Rharb Basin, condensate in Essaouira, light oil in Essaouira and Prerif, to heavy oil in Tarfaya, most sedimentary basins are still largely unexplored, especially when compared to other countries in the region. In 2011 Morocco had and estimated drilling density of 0.04 wells for every 100km2, compared to a global average of 8. Whilst a lack of existing reserves explains this, Moroccan officials argue that without sufficient exploration that would generate basic data, it is not fair to conclude that there is no oil in Moroccan soil. They bring the case of the Gulf of Guinea where estimated reserves are billions of barrels and not so long ago was deemed unattractive by the oil industry. Indeed, Africa, and the Atlantic margins in particular are at the forefront of many explorers’ priorities. The South Atlantic margin possesses multiple world-class petroleum systems along both continental margins (Brazil & West Africa) and has been in focus since the 1950’s following initial discoveries in Nigeria and Gabon. Significant successes have continued on a regular basis involving Brazil, the Congo, and Angola. The NW African Central Atlantic margin extends from the northern tip of Morocco southward to the Guinea Fracture Zone. NW Africa has seen a surge of oil exploration activity, with the Chinguetti Field discovery in Mauritania followed by discoveries by both Anadarko (Sierra Leone) and Kosmos (Ghana), and a large amount of new seismic data. The common feature which led to these discoveries was having high quality 3D seismic identify potential hydrocarbon-bearing reservoirs based on new play concepts. Pura Vida is applying the same technologies and concepts in the Mazagan Offshore Area which it believes has the potential for similar large scale discoveries. The most high profile international operators in Morocco are Anadarko, Kosmos Energy and Repsol. Junior operators include; Pura Vida Energy, Tangiers Petroleum, San Leon, Serica Energy, Circle Oil and Longreach. NW Atlantic Margin Discoveries

Source: PVD Pura Vida’s acreage lies within the Essaouira Basin offshore Morocco which is relatively under-explored. However, an unprecedented level of transactional activity has been observed in Morocco recently which should lead to increased exploration and drilling activity in the future. Historically, most of the drilling activity occurring in the Essaouira Basin has been onshore and production has existed onshore since the 1950’s. Recently, the available acreage has been taken up by large independents, in particular Kosmos has picked up acreage surrounding the Mazagan Offshore Area. Kosmos was the first to recognize the new play type in Ghana which led to a number of subsequent discoveries. It is Pura Vida’s view that the discoveries in the onshore and shallow water Essaouira Basin prove the petroleum system which provides substantial potential for large scale discoveries in the deep water areas.

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Pura Vida Energy

The entire Atlantic Margin of Morocco is under explored in terms of drilling. According to ONHYM only 34 wells have been drilled since 1968. Of which, the 29 wells drilled prior to 2003, aimed principally to test Jurassic carbonate objectives in the shallow water areas of the shelf. They resulted in the discoveries of light and heavy oils at the Cap Juby structure as well as oil and/or gas shows in most of the other wells. The remaining 5 wells were drilled as follows:

3 wells in 2004, in deep offshore to test Tertiary and Upper Cretaceous at salt related structures. Besides minor oil and/or gas shows and evidence of good source rocks intervals, these wells failed to find commercial hydrocarbon accumulations.

One well in 2008, in deep offshore, to test the Lower Cretaceous.

One well in 2009, to test Tertiary Bright spot anomalies. This well tested gas accumulation.

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Pura Vida Energy

Asset Overview Mazagan Permit (PVD: 75%) The Mazagan permit was acquired by Pura Vida (PVD) through direct negotiation of a Petroleum Agreement with the Moroccan Government. PVD holds a 75% working interest in the permit with the remaining 25% held by the Moroccan NOC, Office National des Hydrocarbures et des Mines (ONHYM). ONHYM’s interest is carried throughout the exploration period. The Mazagan Offshore Area comprises six exploration blocks off the Atlantic coast of Morocco, representing a total area of c.10,900km2 with water depth ranges from c.1000m to c.3000m. The area lies about 80km from the coast near the town of Essaouira, and was initially called Cape Tafelney. It is described as a combined block, and essentially covers the exploration areas originally defined by the Moroccan government as Essaouria Offshore IV and Essaouria Offshore V.

Location Map / General Setting & Bathymetry (water depths)

Source: PVD Exploration History The acreage was originally held in two adjacent permits by a joint venture operated by Vanco with Agip, CNOOC and ONHYM as partners. These permits covered a different area to the Mazagan licence, and included shallow water acreage closer to the coast. The Ras Tafelney permit lay to the south and covered the most prospective area of the current permit, while the Safi Haute permit lay to the north. Timeline

1998: 2D seismic 2004: Shark B-1 Well 2007: Acreage relinquished

2001: 3D seismic 2006: More 2D seismic 2011: PVD awarded permit

Source: PVD The partners initially acquired a first phase of 2D seismic in 1998, followed by 3D seismic in

2001. The first drilling on the acreage was the Shark B-1 exploration well, which was drilled in 2004 at a water depth of 2128m. The Shark prospect was a clear fourway dip-closed salt-cored anticline mapped at interpreted Top Cretaceous and Albian levels.

Reservoir targets were potential sands in the Lower Tertiary, Upper Cretaceous and Lower

Cretaceous assumed to correspond to higher amplitude events on seismic (although these are not thought to fit structure and were not seen as a direct hydrocarbon indicator at the time). Total depth was 3976m MD, close to the base Aptian, and the well was largely on prognosis (<30m), with the deepest target being 65m shallow.

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Pura Vida Energy

Shark-1 Seismic

Source: PVD Whilst post-drill reports showed that no significant reservoirs had been encountered in any of

these intervals and no oil shows were witnessed, recent geophysical work suggests that some reservoir potential does exist in the limestones.

One C1 gas show was noted, related to a limestone. The strong amplitude responses proved to

be related to density contrasts between non-reservoir lithologies of claystone, siltstone, and limestone.

The company believes that the Shark well was dry because it was located in a sand bypass zone, where the Middle Miocene Channel sands were absent. This is backed up by the lack of raised amplitudes at the Middle Miocene level. PVD is using these amplitude responses to evaluate the potential presence of hydrocarbons within the Miocene. More recently, in 2006, a second tranche of 2D seismic lines was acquired. In the southwest of the permit is Deep Sea Drilling Project (DSDP) site 415, which includes a well drilled to the Albian. A number of other DSDP wells have been drilled around the acreage (see below).

Location of Deep Sea Drilling Project (DSDP) wells

Source: PVD Outside of the Pura Vida acreage, further to the south lies the 2004 Shell-operated Amber-1 well. This well targeted Cretaceous turbidite sands in a trap against a salt ridge.

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Pura Vida Energy

No significant reservoirs were encountered, and the well was plugged and abandoned, although

minor oil and gas shows were present in Eocene and Cretaceous levels. Several minor hydrocarbon discoveries have been made close to shore, off Agadir, and onshore

to the north. Towards the Canary Islands are additional discoveries. The diagrams before illustrates the stratigraphic correlations of regional wells and the individual well correlations, including the DSDP sites to the west and north. Vanco was chasing an Upper Cretaceous play with its Shark well. However, Pura Vida’s Toubkal prospect is an amplitude anomaly in the Miocene horizon and multiple other similar traps (deeper four way closures) identified on the 2D data implies the block is more than a ‘one shot’ play.

Deepwater Morocco Stratigraphic Correlation, NW Africa

Source: RISC, Vanco

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Pura Vida Energy

Deepwater Morocco Well Correlation, NW Africa

Source: RISC, Vanco Hydrocarbon Prospectivity The Basics Deep water offshore Morocco is minimally explored, and although it clearly offers potential, it also constitutes frontier territory. Pura Vida has identified two potential plays, both of which are unproven, with both therefore carrying play risks. In addition, prospect risks are specific to the various features of each prospect, and assume that the play is proven. Play risks comprise the regional development of source (presence of a mature source interval, with generation, expulsion and migration prior to trap development), reservoir and top seal. Prospect risks comprise charge, trap (geometry), reservoir (presence and effectiveness) and seal (trap integrity including fault seal and stratigraphic pinchout where relevant). Plays Pura Vida is targeting two play types, those in the Miocene horizon and those in the Lower Cretaceous/Jurassic. The Miocene play is based on hydrocarbons stratigraphically trapped within channelised gravity flows. However, there are essentially no structural closures within the mapped acreage (e.g. faults visible on the seismic), and the recognition of this Miocene level as a play is completely dependent on the presence of raised seismic amplitudes (darker areas on the seismic maps) and their proposed association with hydrocarbon fill.

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Pura Vida Energy

These are known as direct hydrocarbon indicators (DHI) within the petroleum industry. While typically, a DHI would be utilised alongside some mapped geometry (such as a structural closure or clear updip termination of a seismic package), in the Miocene case there is no mapped updip pinchout of a seismic unit. This is partly because there is no mapping of a sediment package which is seen to thin and terminate, but also because the raised amplitudes appear to extend beyond the edge of the available 3D seismic data volume. The pinch out of the sands is defined on 2D as mapped by PVD, however, from an independent perspective, the DHIs currently provide the play solely. The Lower Cretaceous/Jurassic play involves simple structural features without DHI support, so the conventional play and prospect approach is applicable.

Source Rock & Migration:

In terms of source, the limited well data suggest that source intervals may occur regionally within the Cretaceous Albian and Aptian, and the Upper and Lower Jurassic. Within the permit, the kitchen is expected to be within the Jurassic, which is known to be a period when source development was regionally significant. For example, the Kimmeridge Clay in the North Sea, and equivalents offshore Canada, were close during this early stage of Atlantic rifting. Oil in the existing fields lends to the Jurassic.

Maturation modelling by the company calibrated to Shark-1 using a Type II kerogen suggests

that both oil and gas are expelled within the permit, with oil dominating. Were a Type III kerogen to be used, we would expect a significantly higher proportion of generated gas.

Reservoir & Trap:

Original operators Vanco undertook petrophysical and amplitude-versus-offset (AVO) studies

aimed at the Albian. These concluded that the expected depths and porosities for the Albian would not provide AVO responses (although recent work by DownUnder Geophysics concludes that a response could be expected).

Pura Vida has interpreted a number of seismic horizons across the 3D survey, including: water

bottom, Middle Miocene Channel (a key event for the primary target), Lower Tertiary, Top Cretaceous, Upper Cretaceous Maastrictian, Upper Cretaceous Campanian, Top Albian, Top autochtonous salt and a nominal Jurassic event (for deeper prospectivity).

An arbitrary seismic line through the permit shows these various features in relation to the Shark-

1 well, and illustrates the daipir province (see below). A detailed independent study has also recently been undertaken by specialist geophysical

contractors DownUnder GeoSolutions, using the Shark B-1 well, Amber-1 and nearshore well Souss-1 as inputs. Souss-1 was included specifically as it included Miocene turbidite sands that were absent in the other wells, and which represent the best available equivalent lithology to that forecast for the Mazagan prospects.

The results provided encouragement that relative seismic amplitudes could be used to guide

prospect definition, with the caveat that the work assumes high net-to-gross sands and hydrocarbon saturation, neither of which may be the case. It is also worth noting that the AVO support claimed for the Amber prospect turned out to be a lithology effect (although Pura Vida reports that amplitudes do not in any case conform to structure).

The Prospects/Leads Based on interpretation of 3D seismic data, the Mazagan Offshore Area contains a number of prospects with significant resource potential. The largest of these is the huge Toubkal prospect, which has a mean resource of 790 MMbbls. An independent resource assessment by RISC was completed in September 2011, with total mean prospective resources estimated at over a billion barrels. Six prospects have been identified and modelled by RISC, three within the Miocene play, and three within the Albian (Cretaceous). An additional two leads have been identified in the Miocene by Pura Vida (resources for the leads are company estimates).

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Pura Vida Energy

Summary of prospects and leads

Reservoir Prospect/Lead Gross Unrisked Prospective Resources CoS Low Best High Mean MMbbls MMbbls MMbbls MMbbls %

Toubkal 180 560 1670 790 20.0% Zagora 13 35 95 47 23.0% Miocene Amchad 8 26 81 38 23.0% Jbel Musa 14 53 195 87 11.0% Jbel Ayachi 12 43 153 69 11.0% Albian Jbel Lakhdar 12 43 153 69 11.0% Amtoudi* - - - 700 - Miocene Tafraoute* - - - 800 -

239.0 760.0 2347.0 2600.0

Source: RISC, PVD * Lead

The main geological play is proposed as Middle Miocene turbidite/debris flow sands within a broad stratigraphic closure (Toubkal prospect) and local structural closures of the same sands against salt diapirs (Amchad and Zagora prospects). Prospectivity is defined on good quality 3D seismic data. Raised amplitudes (DHIs) observed on the seismic data suggest sand fairways and independent rock property seismic modeling provides support for oil fill, although calibration is limited. An additional play type at Lower Cretaceous/Jurassic levels is based on turbidites within clear four-way dip closures. For a more detailed overview of the plays and prospects please see Appendix I.

Prospect/lead map

Source: PVD

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Pura Vida Energy

Work Programme The work program for the full three terms comprises the following:

• Term I (2 years) - Reprocess 3000 km2 3D seismic and acquire 50 drop cores

• Drill or drop licence, 20% relinquishment if continue into second term

• Term II (2 years) - Drill one exploration well to 3000m below mudline

• Drill or drop licence, 30% relinquishment if continue into third term

• Term III (4 years) - Drill two exploration wells to 3000m below mudline

• If commercial discovery, enter exploitation concession

The minimum work program for the first two years includes the reprocessing of 3,000km2 of the existing 3D seismic, acquiring 50 ocean bed drop cores and geological studies. The estimated cost of this work is c.US$3.7m. However, we would note that PVD is fully funded for this stage and currently expects to complete the minimum work program within the first 12 months and could subsequently expedite the programme. At the end of the first term, the company may elect to drop the licence or relinquish 20% and enter into a further period of two years, which includes a commitment to drill an exploration well. Following this there is a further drop option, or on relinquishing a further 30% a final four year period would be entered with a commitment to drill two exploration wells. In the event of a commercial discovery, PVD has the right to an exploitation concession over the relevant area for a period of up to 25 years, which may be extended by a further period of up to 10 years. Exploration wells in the deep water of the Mazagan Offshore Area are likely to cost around $45m. PVD intends to fund future drilling by farming down its interest to obtain a carry on the costs. To this end, the work program to be undertaken in the first two years has been designed to de-risk prospects for drilling. It is anticipated that this work will assist in marketing the farm-in opportunity to potential operators to fund future drilling campaigns and enhance the value of Pura Vida’s interest in any future dealings.

Cost of work programme for first two years is c.US$3.66m

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Pura Vida Energy

FINANCIAL REVIEW

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Pura Vida Energy

Use of Proceeds/Capex Programme The gross proceeds of the Placing on admission was c.$4.0m. The Group intends to use the proceeds of the placing and existing cash to pursue its growth strategy, specifically as detailed below. Whilst PVD have sufficient funds for its work programme to de-risk its acreage, as previously noted it would need to farm-down its interest and or raise more equity in the event of an actual drilling programme. Use of Proceeds Capex Timeline

A$m 2012E 2013E Admission expenses 0.5 0.0 Exploration capex 3.0 0.7 Repayment of loans 0.5 0.0 Administration costs 1.0 1.0 Project generation and working capital 0.4 0.4 Total 5.4 2.0

Source: PVD

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Pura Vida Energy

Financial Forecasts Profit & Loss

Profit & Loss (A$) 2011A 2012E 2013E Revenue 0 0 0 %∆ - 0.0% 0.0% Costs of sales 0 0 0 DD&A 0 0 0 Impairments 0 0 0 Other 0 0 0 Total cost of sales 0 0 0 % group revenues (pre-excep) - - - %∆ (pre-excep) - 0.0% 0.0% Gross profit 0 0 0 EDITDAX -506,315 -1,614,500 -1,070,000 Margin % - - - % ∆ - 218.9% -33.7% Unsuccessful efforts 0 0 0 Other operating items -429,669 -644,500 -100,000 G&A expenses -76,646 -970,000 -970,000 EBIT -506,315 -1,614,500 -1,070,000 Margin % - - - % ∆ - 218.9% -33.7% Net financial items 426 0 0 Reported PBT -505,889 -1,614,500 -1,070,000 Adjusted PBT -505,889 -1,614,500 -1,070,000 Taxation 0 0 0 Reported PAT -505,889 -1,614,500 -1,070,000 Minorites 0 0 0 Reported PAT (equity holders) -505,889 -1,614,500 -1,070,000 Adjusted PAT -505,889 -1,614,500 -1,070,000 Basic eps (p/share) 0.0 -1.7 -1.8 Adj. fdil eps (p/share) 0.0 -1.7 -1.6 Average SII (m) 40.3 40.3 40.3 Average Fdil SII (m) 0.0 41.4 43.4 Y/E SII (m) 0.0 41.4 43.4

Notes: Our Fully diluted shares in issue incorporates fully paid shares outstanding plus ‘in the money’ partly paid shares that aren’t restricted and could thus be dilutive.

Source: N+1 Brewin, PVD

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Pura Vida Energy

Cash Flow

Cash Flow (A$) 2011A 2012E 2013E EBITDA -506,315 -1,070,000 -1,070,000 Exploration write-off/other items 0 0 0 ∆ in working capital 0 -360,000 -360,737 Taxes 0 0 0 Other op. CF items 0 0 0 Net CF from operations -506,315 -1,430,000 -1,430,737 Capex 0 -3,500,000 -160,000 Acquisitions/disposals 0 0 0 Other inv. CF items 426 0 0 CF from investments 426 -3,500,000 -160,000 Incr/Decr in equity 0 4,000,000 0 Incr/Decr in debt 0 -500,000 0 Ordinary dividends 0 0 0 Pref. dividends 0 0 0 Other fin. CF items 0 0 0 CF from financing 0 3,500,000 0 Forex & disc ops 0 0 0 Incr/Decr in cash (post FX) -505,889 -1,430,000 -1,590,737 Equity FCF -506,315 -4,930,000 -1,590,737

Source: N+1 Brewin, PVD Balance Sheet

Balance Sheet (A$) 2011A 2012E 2013E PP&E 14,743 13,269 11,942 Intangibles & GW 38,100 3,538,100 3,698,100 Deferred tax 0 0 0 Other non-current assets 0 0 0 Non-current assets 52,843 3,551,369 3,710,042 Inventories 0 0 0 Debtors 15,372 62,023 15,372 Cash 3,365,257 1,935,257 344,520 Other current assets 0 0 0 Current assets 3,380,629 1,997,280 359,892 Total assets 3,433,472 5,548,649 4,069,934 ST debt 0 0 0 Creditors 224,203 224,203 224,203 Other current liabs 0 0 0 Current liabs 224,203 224,203 224,203 LT debt 567,992 67,992 0 Creditors 0 0 0 Other non-current liabs 0 0 0 Non-current liabs 567,992 67,992 0 Provisions for liabilities and charges 0 0 0 Total liabs 792,195 292,195 224,203 Net Assets 4,225,667 5,840,844 4,294,137 Minority interest 0 0 0 Shareholder funds 4,225,667 5,840,844 4,294,137 Net (debt)/cash 3,933,249 2,003,249 344,520

Source: N+1 Brewin, PVD

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APPENDICES

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Appendix 1: Wider Geological Setting Located on the northwest corner of the African craton, the Moroccan margin is similar to the rest of the north African Atlantic margin, with syn-rift (Triassic) continental clastics, carbonates, and evaporites overlain by Cretaceous and Tertiary marine clastics. Major tectonic events influencing the development of the margin include the Devonian-to-Westphalian age Hercynian orogeny, rifting of the central Atlantic, and the Late Cretaceous to Miocene aged Alpine orogeny.

Setting / Bathymetry and Tectonic History – Moroccan Margin

Source: PVD Following uplifting and eroding of Paleozoic basement on the west Moroccan margin at the end of the Hercynian orogeny, rifting began in the Triassic, creating normal listric faults striking NNE to SSW. These in turn resulted in a series of half grabens, into which syn-rift continental clastics were deposited. Extension continued during the Triassic post rifting, creating a restricted marine environment which resulted in evaporate (salt) deposition (which continued into the Early Jurassic). Ongoing extension and subsidence then created open-marine conditions, during which anoxic conditions are believed to have prevailed, leading to the development of source rocks. Ongoing Atlantic opening during the Middle Jurassic resulted in carbonate deposition, causing the deformation and diapiric rise of the underlying evaporites. This has resulted in diapirs, tongues, sheets, canopies and toe thrusts, and has influenced sediment deposition. DSDP wells drilled in the area show that thick turbidites were also deposited offshore during this time (providing potential reservoir for the deeper Mazagan prospectivity).

Depositional Setting During Jurassic and L. Cretaceous

Source: PVD Carbonate deposition was halted with a global sea level fall in the Early Cretaceous, and was followed by progradation of thick deltaic deposits (another potential reservoir), which further loaded

Jurassic L. Cretaceous

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the underlying evaporites. By the Late Cretaceous, clastic influx had decreased, and deep-water muds and marls were being deposited offshore. Several periods of erosion and non-deposition followed at the start of the Tertiary and during the Cenozoic. The Alpine orogeny (the event which created the Atlas mountains) began during the Late Cretaceous and continued into the Late Tertiary. Inversion and shear along Mesozoic rifts produced the Atlas Mountains, with the main phase occurring during the Miocene-Pliocene. Erosional products (flow of turbidites and debris) at this time are assumed to provide the reservoir for the main play of the Mazagan permit. It is thought that these flows could have occurred at any time from the Lower Cretaceous onwards (except for the Aptian). However, the failure of the Shark B-1 exploration well in 2004 (drilled to the Aptian) to encounter any hydrocarbons indicates that reservoir development is not ubiquitous.

Moroccan Margin Geology from L. Cretaceous

Source: PVD This depositional process is backed up by an equivalent one in the present-day geological setting, whereby the Agadir Canyons, which lie to the south of the Mazagan permit, are seen to channel sediment out into the deeper water. Regional Specifics The Mazagan permit forms part of the Atlantic rift succession, and locally covers part of the offshore portion of the Essaouria Basin. Prominent bathymetric features in the area include the Essaouira and Agadir Canyons and the Tafelney Plateau. The Tafelney Plateau is a high-relief accommodation zone created during the rifting stage of the central Atlantic Basin. It has a complex history but most recently has been uplifted as part of the Neogene rise of the Atlas Mountains.

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Seismic Line Across Tafelney Plateau

Source: PVD The Atlantic margin history of the permit, and more recent uplift of the Atlas Mountains, suggest that coarse clastic material should be present on the permit. These clastics are being targeted across the Miocene and Lower Cretaceous/Jurassic intervals. In terms of source, the limited well data suggest that source intervals may occur regionally within the Cretaceous Albian and Aptian, and the Upper and Lower Jurassic. Within the permit, the kitchen is expected to be within the Jurassic, which is known to be a period when source development was regionally significant. For example, the Kimmeridge Clay in the North Sea, and equivalents offshore Canada, were close during this early stage of Atlantic rifting.

Potential Source Rocks During L. Jurassic

Source: PVD Maturation modelling by the company calibrated to Shark-1 using a Type II kerogen suggests that both oil and gas are expelled within the permit, with oil dominating. Were a Type III kerogen to be used, we would expect a significantly higher proportion of generated gas.

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Existing Seismic / Structural Data The permit has a limited 2D seismic grid totalling c.5000 km, as well as two 3D seismic surveys totalling 3,659 km2 over the eastern half of the block. The larger of the two surveys is the Ras, an elongate north-south grid covering 3,025 km2. The smaller northern Vanco survey lies in the northeast of the permit, and covers 719 km2.

Existing Surveys

Source: PVD Mazagan includes permits IV &V; permit boundary has subsequently been changed in the north

Original operators Vanco undertook petrophysical and amplitude-versus-offset (AVO) studies aimed at the Albian. These concluded that the expected depths and porosities for the Albian would not provide AVO responses (although recent work by DownUnder Geophysics concludes that a response could be expected). Pura Vida has interpreted a number of seismic horizons across the 3D survey, including: water bottom, Middle Miocene Channel (a key event for the primary target), Lower Tertiary, Top Cretaceous, Upper Cretaceous Maastrictian, Upper Cretaceous Campanian, Top Albian, Top autochtonous salt and a nominal Jurassic event (for deeper prospectivity). An arbitrary seismic line through the permit shows these various features in relation to the Shark-1 well, and illustrates the daipir province (see below).

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South (left) to north (right) seismic line through Ras 3D seismic survey

Source: PVD A detailed independent study has also recently been undertaken by specialist geophysical contractors DownUnder GeoSolutions, using the Shark B-1 well, Amber-1 and nearshore well Souss-1 as inputs. Souss-1 was included specifically as it included Miocene turbidite sands that were absent in the other wells, and which represent the best available equivalent lithology to that forecast for the Mazagan prospects. The results provided encouragement that relative seismic amplitudes could be used to guide prospect definition, with the caveat that the work assumes high net-to-gross sands and hydrocarbon saturation, neither of which may be the case. It is also worth noting that the AVO support claimed for the Amber prospect turned out to be a lithology effect (although Pura Vida reports that amplitudes do not in any case conform to structure). Miocene Prospects Toubkal Toubkal is a combined structural and stratigraphic play, with a prospective reservoir made up of turbidite/debris flows, delineated by seismic amplitudes. This type of play is viewed as analogous to the Jubilee field in Ghana and other recent discoveries along the transverse margin in Africa and the deep water plays in the Campos Basin in Brazil. The amplitude appearance at Jubilee is comparable to that at Toubkal although we would note that the updip termination of high amplitudes and/or a geometrically defined unit has not yet been demonstrated in the Toubkal prospect. Recent major discoveries have resulted in this play type being actively sought after by major operators in the region.

Seismic line through Toubkal prospect

Source: PVD At the mapped Middle Miocene level, the 3D data shows a number of areas of raised amplitudes, trending east-west, the geometry of which is consistent with channels with variably constrained margins. The prospect is defined by the main central area of raised amplitudes. A distinct area close to the seismic data edge has particularly high amplitudes, while there are other areas of equivalent high amplitudes which are less clearly limited. The package of raised amplitudes varies considerably in thickness, and mapping of a realistic base has not yet been possible. Also, the updip limit of any

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raised amplitudes and/or termination of a related seismic package is not yet defined as the most updip portion lies adjacent to the seismic data boundary to the east. The prospect areas are based on selected levels of raised amplitude, with the initial play being defined by Pura Vida precisely at an interpreted Middle Miocene top channel event. This shows variably raised amplitudes across an east-west channelised zone, although raised amplitudes are clearly present locally in many other areas. The limits to the raised amplitudes appear to provide some information about changes in lithology and/or fluid content, which is supported by independent rock property modelling. On the basis that the highest reflectivity would be associated with gas, the moderately raised amplitudes could be associated with oil fill. The limit of the raised amplitudes to the northwest is broadly concordant with structure, and suggests that it may reflect a hydrocarbon-water contact (c.3000mss). In this area, a considerably thicker package than just the Middle Miocene Channel event appears to demonstrate amplitude cut-off at a consistent depth, providing encouragement for hydrocarbon fill.

Toubkal Prospect - Raised Mid Miocene Channel amplitudes

Source: PVD Amplitude limits to the southwest generally cross-cut depth contours, suggesting that the cut-off represents the sand limit in this area. In the eastern area, close to the area of very high (potentially gas) amplitudes there is also broad structural concordance, but this is at a shallower depth than that to the west. It is suggested that this also represents a sand limit, which is coincidentally aligned with the depth contours (although an association of depositional limits with pre-existing structure may exist). Alternatively, this could also represent a fluid contact, which is in a separate sand package that is not in communication with the main area to the west.

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Toubkal Prospect – Definition of P10, P50 areas

Source: PVD Red polygon – P10, Blue polygon – P50

The P10 area for Toubkal is defined on the basis of main change in amplitude, while the P50 area is a relatively arbitrary but realistic mid-case defined to capture all the main raised amplitude area. These two values were then combined in a log normal distribution to define the full distribution. The implied P90 area is c.60% of the P50 area. Both P10 and P50 areas are limited to the west at the edge of the 3D seismic data, where the raised amplitudes clearly continue beyond the mapped area. The zone of raised amplitude is more constrained in the east, and, as noted, still appear to continue updip, placing a risk on up-dip seal. The company reports that 2D lines to the east of the 3D data demonstrate that the raised amplitudes are not present, implying sealing is likely. Amchad and Zagora The Amchad and Zagora prospects are structural closures against the sides of different salt diapirs. Like Toubkal they are also supported by raised amplitudes, although these do not cover the full structural closure. Zagora displays a thicker package of raised amplitudes that a better cut-off at common depth.

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Amchad and Zagora Prospects – Mid Miocene

Source: PVD As no wells have been drilled to date, gross thicknesses are very uncertain. The vertical extent of the raised amplitudes should provide guidance, but these are highly variable. There is also a great deal of uncertainty around rock properties, although the very shallow depth means that porosities are likely to be high. In terms of hydrocarbon properties, the shallow depth could mean that the dissolved gas component is small, but the predicted type II to III kerogen typically results in a relatively significant gas proportion. Risks The Miocene play is based on hydrocarbons stratigraphically trapped within channelised gravity flows. There are no structural closures within the mapped acreage, and the recognition of this Miocene level as a play is completely dependent on the presence of raised seismic amplitudes and their proposed association with hydrocarbon fill.

Miocene Prospect Risking

Play Name Source Reservoir Seal Overall CoS Miocene 80.0% 70.0% 80.0% 45.0% Prospect Name Charge Reservoir Trap Seal Overall CoS Toubkal 85.0% 75.0% 95.0% 75.0% 40.0% Amchad/Zagora 85.0% 75.0% 95.0% 85.0% 51.0% Combined CoS Toubkal 20.0% Amchad/Zagora 23.0%

Source: PVD The risks associated with the Miocene Play are as follows:

• Source – moderate risk; no material shows in the Shark-1 well, but no reservoir at the location. Association between the near shore and onshore fields with a Toarcian source, and shows encountered in other wells, including Amber-1 to the south. Evidence of a Lower Jurassic source is very limited, and at considerable distance from the permit. Rock property

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modelling provides encouragement that the raised seismic amplitudes are hydrocarbon-related.

• Reservoir – moderate risk; despite no sands within Shark-1 the well did not penetrate the

likely sand fairways, which are supported by seismic amplitudes. Also, DSDP well 416 encountered turbidites through the Eocene to Miocene interval.

• Seal - moderate risk; top seal likely to be certain, but nature of the play as an amplitude

supported pinchout means lateral seal (and base seal), including the updip lateral seal, is unproven. Raised seismic amplitudes provide support that seal is working.

Prospect risks assume that the play is proven. The risks associated with the Miocene Prospects are as follows:

• Charge – High confidence; charge is required through the Cretaceous, where occasional faults are expected to provide a migration route. Lack of amplitude support on unfaulted four-way dip closure to the west of Zagora can be reasonably interpreted as implying that charge was in contrast possible up the diapir walls to provide the charge (and observed amplitude support) for Zagora and Amchad. However, a biodegradation risk is present for all features. Probability 0.85, applicable to all prospects.

• Reservoir – moderate confidence; no nearby wells with Miocene sands. However,

stratigraphic model implies sands are regionally present.

• Trap – high confidence; virtually certain, with trap geometry defined by 3D. Toubkal prospect involves a different trap geometry (large channelised sand fairway with updip limit undefined, albeit restricted width) to Amchad & Zagora (structural closures against salt diapirs). However, these are given the same probability.

• Seal - moderate confidence (likely – Toubkal, very likely - Amchad and Zagora); amplitudes

are defined as probably hydrocarbon-related, so seal is implied as probably working. Note however that raised amplitudes at lower levels in Shark-1, some of which appear to be crestally associated, were discovered to relate to impedance contrasts between non-reservoir lithologies.

Lower Cretaceous Prospects Jbel Musa, Jbel Ayachi and Jbel Lakhdar While the prospectivity at the Lower Cretaceous level is considered secondary to that at the Miocene, the company has identified three prospects at the Albian horizon. The Jbel Musa, Jbel Ayachi and Jbel Lakhdar prospects are prognosed to have reservoirs made up of turbidite sands, such as those seen in the DSDP wells and the Canary Islands. All three are dip-closed, salt-cored features.

Prospect map at Albian level / seismic inline and crossline through Jbel Ayachi

Source: PVD Albian is red horizon in centre of section

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Risks

Lower Cretaceous Prospect Risking

Play Name Source Reservoir Seal Overall CoS L. Cretaceous 70.0% 50.0% 100.0% 35.0% Prospect Name Charge Reservoir Trap Seal Overall CoS All 85.0% 50.0% 95.0% 75.0% 30.0% Combined CoS All 11.0%

Source: PVD Play risks at the Lower Cretaceous are as follows:

• Source – moderate risk; no material shows in nearby Shark-1, but no reservoir at the location. Small fields exist more proximal to coast, with shows in other wells. Direct evidence of Lower Jurassic source is limited, with no nearby wells. Closest is distant DSDP site 547 with some source quality Lower Jurassic. However, this proposed source would be immediately below the reservoir.

• Reservoir – moderate-high risk; very limited well data. DSDP site 416 has turbidites from the

Tithonian (at TD) to the Hauterivian.

• Seal – certain; top seal is not proven but extremely likely, given shale-dominated section, including ubiquitous mass transport zone, seen in Shark-1.

Again, prospect risks assume that the play is proven. The risks associated with the Miocene Prospects are as follows:

• Charge – high confidence; very likely to occur, given reservoir overlies proposed source.

• Reservoir – low confidence; no nearby wells deep enough to penetrate Lower Cretaceous / Jurassic. Stratigraphic model implies sands are regionally present, but material risk will still remain even if a future nearby well were to encounter reservoir.

• Trap – high confidence; trap geometry defined by 3D, and all prospects are clear four-way

dip closures.

• Seal - moderate confidence; parameter remains at moderate confidence given that it has not yet been drilled in the area.

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Appendix 2: Resource Definitions SPE/WPC/AAPG/SPEE Petroleum Resources Management System Basic Principles and Definitions The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project’s economic feasibility, its productive life, and its related cash flows. Petroleum Resources Classification Framework Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon content could be greater than 50%. The term “resources” as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.” The diagram below is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum. SPE/WPC/AAPG/SPEE Resources Classification Framework

Source: www.spe.org/industry/reserves/docs/Petroleum_Resources_Management_System_2007.pdf BD Analysis, EIA 2010

The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the “Chance of Commerciality, that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification:

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TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”). DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage. Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below. RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered. PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity. UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in- Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).

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Appendix 3: Glossary Glossary Term Definition Acreage

An area of land or sea where a company is entitled to explore for oil or gas reserves.

Appraisal Drilling or seismic activities that aim to delineate the range of reserves made after an exploration well has first encountered hydrocarbons

Basin A geological province on land or offshore where hydrocarbons are generated and trapped.

bbls Barrels of oil or condensate. bopd, bcpd Barrels of oil/condensate per day (in reference to production volumes).

boepd Barrels of oil in equivalence terms, i.e. the amount of natural gas that has the same heat content as an average barrel of oil (c. 6,000 cubic feet of gas = 1 barrel of oil).

Bcf Billion cubic feet.

Bright spot

A seismic amplitude anomaly or high amplitude that can indicate the presence of hydrocarbons. Bright spots result from large changes in acoustic impedance and tuning effects, such as when a gas sand underlies a shale, but can also be caused by phenomena other than the presence of hydrocarbons, such as a change in lithology. The term is often used synonymously with hydrocarbon indicator.

Chance of success (COS)

An estimate of the chance of all the elements within a prospect working, described as a probability. High risk prospects have a less than 10% chance of working, medium risk prospects 10-20%, low risk prospects over 20%. Typically about 40% of wells recently drilled find commercial hydrocarbons.

Cost oil The portion of oil revenues used by companies to recover capital expenditure in production sharing contracts.

Development well A well drilled in the known extent of a field. Development costs Capital expenditure required to bring oil and gas reserves on production. EMV Expected monetary value.

Exploration prospect A geological structure which may contain hydrocarbons but which has not been tested by any exploration well.

Epoch A time subdivision of periods such as Pliocene or Miocene. Era A major time division of earth history such as Paleozoic.

Farmout A lease given to another company for drilling in return for a consideration such as a royalty.

Fault A break in the rocks along which there has been movement of one side relative to the other side.

Field A surface area directly above one or more producing reservoirs on the same trap such as an anticline.

Formation A mappable rock layer. Gas-Oil ratio The amount of natural gas per barrel of oil. Horizon A surface.

Horizontal well A highly deviated well drilled along the pay zone and parallel to the bedding of a reservoir.

Initial pressure The original reservoir pressure before any production (virgin or original pressure).

Initial production The first 24 hours of production from a well. Lead A structure which may contain hydrocarbons.

Licensing rounds The allocation of exploration acreage to oil and gas companies in return for a signature bonus, or a minimum level of expenditure (minimum work programme), or an agreed price.

Log A record of rock properties in a well. mcf 1,000 cubic feet. MMcf 1,000,000 cubic feet. MMcfpd 1,000,000 cubic feet per day (in reference to production volumes). MMcfe 1,000,000 cubic feet equivalent. Oil converted into gas equivalence.

mD Millidarcy, a measurement of rock permeability, (a millidarcy is one thousandth of a darcy).

Plateau period The period in the life of an oil and gas field when production is at a peak and level (usually for a number of years).

2P Proven and Probable reserves.

Probable reserves The volume of hydrocarbon reserves that geological, geophysical and engineering data indicate to be in place, for which there is a 50% chance that it will be more or less than that amount.

Proven reserves The volume of hydrocarbon reserves that geological, geophysical and engineering data indicate to be in place, for which there is a 90% chance that it will be more or less than that amount.

Production forecast A forecast of the future levels of production that can be expected from any particular oil or gas field (often subject to frequent revisions).

Profit oil The volume of oil in a PSC which remains after the contractor has recovered its costs; the profit oil is shared between the national oil company and the contractor in agreed proportions.

PSC Production sharing contract.

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Glossary Term Definition

Pay 1) the zone producing gas and/or oil in a well or 2) the vertical thickness of the producing zone. It can be measured as either gross pay, including non-productive zones or net pay, including only productive zones.

Pay sand The vertical portion that produces gas and/or oil. Pay zone The vertical portion of a reservoir in a well that produces gas and/or oil. Period A subdivision of an era of geological time.

Permeability A measure of the ease with which a fluid flows through a rock (measured in darcies or millidarcies).

Pliocene An epoch of geological time. Part of the tertiary period.

Plugged and abandoned (P&A) A well that has had a cement plug (s) placed in it to close the well. Usually, dry holes and depleted wells are P&Aed.

Porosity The percentage volume of a rock that is pore space (Ø). Prospect A location where both geological and economic conditions favour drilling a well. Rank wildcat An exploratory well drilled at least two miles away from the nearest production.

Recoverable oil/gas The amount of oil that can be produced from a reservoir under current economic conditions (a fraction of the oil in place).

Recovery factor The percentage of oil and/or gas in place that is expected to be produced from a reservoir. This is typically 10-50% in an oil field and 50-80% in a gas field.

Reservoir Hydrocarbons are contained in a reservoir rock. This is a porous sandstone or limestone. The oil collects in the pores within the rock. The reservoir must also be permeable so that the hydrocarbons will flow to surface during production.

Saturation The percentage of different fluids such as gas, oil and water in the pore space of a rock.

Seal An impermeable rock layer that forms the cap on top of an oil or gas reservoir (caprock).

Seismic

A petroleum exploration method in which sound energy is put into the earth (for onshore) with a source. The sound energy then reflects of subsurface sedimentary rock layers and is recorded by detectors on the surface. An image of the subsurface rock layers is made with seismic data to find petroleum traps. 3D seismic shows the seismic reflectors in three dimensions.

Sidetrack (ST) A new section of wellbore drilled from an existing well.

Source rock When organic-rich rock such as oil shale or coal is subjected to high pressure and temperature over an extended period of time, hydrocarbons form.

Spud Starting to drill a well. Stratigraphic column A column showing the vertical succession of rock layers in an area.

Trap Hydrocarbons are buoyant and have to be trapped within a structural (e.g. Anticline, fault block) or stratigraphic trap.

Tcf Trillion cubic feet. Waterflood

A method used to produce more oil from a depleted reservoir. Water is pumped down injection wells into the reservoir in order to force oil through the reservoir to producing wells.

Source: N+1 Brewin

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