HARTSHEAD RESOURCES NL — Capital/Financing Update 2017

May 30, 2017

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ASX Code: PVD

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31 May 2017
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NKEMBE PSC, GABON UPDATE INCLUDING INCREASE TO RESOURCE FOR LOBA OIL DISCOVERY

HIGHLIGHTS

• Pura Vida is actively seeking to transact on it’s Nkembe Project and is considering all opportunities to create shareholder value

• While the Company continues discussions with various parties regarding funding and provision of a suitable drilling rig to progress Nkembe, Pura Vida has decided to cease expenditure on the asset until such time as a funding solution has been secured. The first phase of the PSC ends in January 2018 and an outline for a further extension to progress the PSC is provided in this release

• Loba confirmed as a viable field and an appraisal opportunity that lends itself to fast track development and production within a year, following a successful appraisal well and drill stem test

• Following the completion of the reprocessing of the Mandaros 3D, the Loba oil discovery has become more robust technically and commercially, with contingent gross un-risked recoverable resources ranging from a 1C of 10.8 mmbo, a 2C of 16.5 mmbo and a 3C of 25.3 mmbo and a mean of 17.5 mmbo. This is an update to those volumes reported 13 September 2016 and the differences are described later in this release

• As a result of a larger low side 1C resource case, Loba has become economically robust with an NPV10 of US$77 million, an ROI of 155% and an IRR of 82%. This scenario is capable of carrying two further dry hole costs, reducing the NPV10 to US$64 million with an ROI of 105% and an IRR of 57%

• Loba base case (gross, mean resource size) carrying two further dry wells, has an NPV10 of US$125 million and an ROI of 155% with an IRR of 81%

• Pay back from a fast track development described in the release of 13 September 2017 is less than a year in all cases and the breakeven oil price, in the low side (1C) case is US$33.65 per barrel. If Loba were to carry two additional dry holes this would be US$38.58 per barrel

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Note 1: Hydrocarbon volumes are expressed in gross unrisked mean recoverable resources and differentiated as contingent (being discovered) from prospective (being un-discovered). Note 2 : Net present value (NPV) is based upon an assumed cost of capital of 10% (NPV10) Note 3 : NPV10 is net to Pura Vida’s 80% net interest after; corporate income tax, assuming Government takes up its entitled 20% share of the development, plus operating costs, licence costs and relevant production bonus Note 4 : World bank oil price forecast 10[th] April 2017 used by Pura Vida in its economic analysis and reporting.

Current funding discussions and future work

Pura Vida continues to seek funding partners for the Nkembe asset and is in discussions with a number of parties considering acquiring an interest in the asset. These parties include private equity groups, international and Australian oil and gas companies and rig contractors. While these discussions are encouraging, no formal offers have been received at this stage.

In these circumstances, Pura Vida has elected to cease all expenditure on Nkembe. Accordingly, the previously foreshadowed resource updates for Lepidote Deep and Pompano will not be finalised at this time. Should the Company secure funding on acceptable terms, it is expected that the work required to finalise updates on these prospects should not take long to complete.

Loba resource update

The company has been progressing the shallow water oil prone prospects for drilling and is pleased to provide a resource update of the existing Loba oil discovery in light of recent technical work, based upon favourable results from the reprocessed legacy Mandaros 3D survey. The aim of the reprocessing is to mature prospects for drilling and the survey covers the south eastern part of the block, including the Loba Field.

The Mandaros 3D “Legacy data” was originally acquired in 1993 as part of a larger survey at that time and the data became available to Pura Vida last year as holder of the Nkembe PSC. The data is of sufficient quality and coverage for the shallow water oil prone prospects. Pura Vida has undertaken a reprocessing of the data to apply modern processing techniques aimed specifically at improving seismic imaging, utilising pre-stack depth migration with RTM-TTi technology. RTM allows for more accurate imaging in and below areas with both structural and velocity complexities. As a result of this work, data quality and thus imaging have greatly improved, which enables superior structural and stratigraphic interpretation to be made whilst reducing uncertainty and risk.

Figure 1 Imaging comparison between the new reprocessed depth migrate data and old “legacy” data

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A B
C D
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Figure 1A, is a seismic profile from the legacy Mandaros 3D data through the Loba oil discovery and field which is located on map Figure 1C & D. The benefit of seismic tomography and RTM technology is evident in the better seismic imaging seen in the reprocessed Mandaros data (Figure 1B) compared to the legacy data. Mapping of the near top reservoir level has always been possible with a characteristic seismic marker however with the benefit of the reprocessed data, it has become more robust. It is now possible to tie the well directly at these levels to the seismic, thus mapping the base of the reservoir interval for the first time (Figure 1B pink event). This reduces uncertainty of reservoir thickness across the field which aids volumetric assessment.

With better imaging it has been possible to resolve the top of the salt, now confirmed to be deeper than anticipated (compare Figure 1A & 1B blue Top Salt pick). As a consequence of a deeper salt and better reservoir imaging, the Batanga reservoir interval can be seen to extend across the structural four way dip closed trap without any truncation to salt. Faulting is also better imaged on the new data and although still affecting the domal closure, faults do not offset the reservoir enough to effectively compartmentalise the field as previously thought (see Figure 1C “old view” map of Loba discovery / western panel and Loba East / eastern panel compared to Figure 1D “new view” map which is a more simple faulted anticlinal trap). The oil water contact identified from petrophysical analysis, shown on both maps, controls the extent of the hydrocarbons within the trap.

As a consequence of the new interpretation, the removal of compartmentalisation also removes the potential for a deeper contact and this constrains the overall upside. As the reservoir interval can now be mapped with confidence across the 3D, the distribution of amplitudes within the reservoir interval can be investigated to aid in reservoir identification from seismic (Figure 2). Striking sedimentary channel fairways are evident and extend east to west across the block with a major system just to the north of the field (see zoomed area). The Loba well information can be better tied to seismic allowing important calibration of reservoir characteristics from non -reservoir rock and we can now interpret the local reservoir system to be most likely a crevasse splay. Reservoir extent and distribution have now been integrated accordingly with the well results to better determine reservoir parameters across the field and have re-defined the volumetric inputs (1C, 2C & 3C cases).

Figure 2 Amplitude distributions within the Batanga reservoir interval based on reprocessed 3D data

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The Loba oil discovery, originally drilled in 1976, encountered an oil column over 140 metres, within the Upper Cretaceous Batanga formation level. A drill stem test (DST) was performed at the time and under a 24 hour period failed to flow oil to surface. The operator at that time attempted to acidize the well prior to abandonment. During reverse circulation, to pull the test string from the wellbore, there was a recorded flow of 25.1 barrels of oil which on analysis, confirmed the oil has a density of 0.894 at 15[o] C (equivalent to 27[o] API gravity), a viscosity of 50 centistokes at 80[ o] C and a flowing point of 20[ o] C (No H2S was recorded and Sulphur content is 0.98).

Subsequent work by, and on behalf of, Pura Vida has confirmed the presence of good quality reservoir rock. As part of the more recent concept and feasibility study (announced 13 September 2016), independent assessment of the drilling and testing of the well concluded that there had been significant formation damage induced by the drilling and testing practices of the time. Furthermore, by using good oil field practices today, a vertical well could be capable of flowing oil under natural reservoir conditions. The study recommended optimizing drilling methods and practices, coupled with a well design that includes drilling a horizontal reservoir section with a multi-stage fracture completion and utilising electrical submersible pumps (ESP’s) in order to achieve commercial flow rates. Such a well combination has formed the basis of design for the development of the field, of which the costs have been included in our economics. This philosophy for well design also impacts positively on recovery factors and this along with the new mapping and reservoir identification from seismic, have all been integrated into the latest volumetric assessment for the field. These results are shown in Figure 3, along with a comparison to the previous assessment.

Figure 3 Loba contingent gross un-risked recoverable resources – comparison with the old view

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With higher certainty, due to reprocessing results, the removal of salt and fault separation has increased the Loba field as a direct consequence of combining the two panels, effectively increasing the proven area. The presence and recovery of oil in the discovery well proves the oil is moveable within the faulted anticlinal trap. The occurrence of an oil water contact in the well, which is located in a down dip structural location also proves and defines the overall trap extent, constraining the upside area compared to the “old view”. For comparative reasons the “old view” needs to arithmetically combine the contingent and prospective resources to compare with the contingent resources of the current view. Loba 1C has increased from gross un-risked contingent recoverable resource of 7.7 to 10.8 mmbo (risked 6.2 increasing to 8.3 mmbo). The overall upside of the combined contingent and prospective gross un-risked resources was 34.6 mmbo which has decreased when compared to the current 3C of 25.3 mmbo gross contingent recoverable resources.

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Updated Economics for Loba

Adopting the changes in resource size does not change the previous fast track development philosophy that could still utilise a four slot well tower with a mobile offshore production unit (MOPU), tied back to existing nearby infra-structure in all resource cases. Therefore the same cost structure, well cost, CAPEX and OPEX have been used as per the last reported economics. What does change is the number of development wells required to drain and recover oil for each case (Table 1).

Table 1 Assumptions for development drilling of each volumetric case for the Loba Field

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For oil price assumptions, Pura Vida has adopted the World Bank forecast (that is itself an average between Brent, WTI and Dubai benchmark crudes). With this approach the full field economics for the resource range remain attractive even in the low side or 1C case (Table 2). The economic modelled assumptions are predicated on drilling in 2018 and a development within the subsequent year seeing first oil in 2019. In light of the current low oil price, it is worth noting that Loba remains economically viable even in the low side 1C case, down to a breakeven price of US$33.65 per barrel. With the range in resources, the field remains viable and attractive for a farm out partner to fund the forward drilling or to directly acquire the asset. Pura Vida’s main focus is to secure a partner for this project to progress towards commercialising the Loba discovery and accelerate first production and cash flow.

Table 2 Economics for the Loba Field contingent resource cases (Batanga reservoir)

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Key Risks for the Nkembe PSC

Farm-out - Securing funding for the drilling program through a farm-out deal or sale of the asset is the critical next step in realising the value of the Nkembe block. Pura Vida is in discussions with potential partners to fund the drilling program, including appraisal and testing of the Loba Oil Field. As the Operator and holder of a 100% interest in the block, the Company believes it is well placed to achieve a farm-out or sell down.

► Production Sharing Contract (PSC) - The first phase of the Nkembe PSC ends in January 2018. Depending on the timing of funding Pura Vida may require an extension of this phase. The Company believes there are mitigating factors that the government of Gabon may consider should the Company request a further extension to this phase. However, and assuming title in the PSC is sound, an extension to the current phase is also permissible within the terms of the Nkembe PSC, subject to government approval, at a cost of US$100,000 per month.

► Work commitments - Pura Vida’s ability to perform the work commitments in the current exploration phase of the Nkembe block, which includes acquisition of new 3D seismic data and a well, remains dependent on securing a farm-in partner and the finalisation of an extension, or an agreement with the Government to vary those commitments.

► Development funding - In the success case, Pura Vida will need additional funding to proceed with any development of the Loba Oil Field or other discovery. Pura Vida would look to industry partners for funding and/or consider debt or equity funding alternatives.

► Geological risk - Exploration risk is evaluated by interpretation of geological and geophysical data and the accuracy of those interpretations can be influenced by a number of factors. A key risk in the commercialisation of the Loba Oil Field is establishing a commercial flow rate by carrying out a production test of that reservoir.

► Oil price – Economic factors, and oil price will have an impact on the viability of the project. The price of oil fell sharply in late 2014 and a sustained period of relatively low oil prices has been experienced since then. The oil price has recovered from the lows experienced in early 2016 however the oil price still remains volatile.

► General risks - There are number of other risks commonly associated with the business of oil exploration, development and production. By its nature, oil exploration contains elements of significant risk with no certainty of the discovery and commercialisation of hydrocarbons. A broad range of factors may impact results such as operational and environmental risks, failure to obtain consents, necessary approvals for the conduct of operations, regulatory or sovereign risk and political instability.

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Resource estimates cautionary statement

The estimated quantities of prospective resources relate to undiscovered accumulations and contingent resources relate to discovered accumulations. These estimates have an associated risk of discovery or appraisal (as the case may be), as well as a risk of development. Further exploration, appraisal and/or evaluation is required to determine the existence of a commercial quantity of moveable hydrocarbons.

Contingent resource estimates in this market release are prepared as at 24[th] May 2017. The resource estimates have been prepared using the Society of Petroleum Engineers’ Petroleum Resources Management System (SPE-PRMS) to define resource classification, methodology and volumes see www.spe.org . All reported volumes have been prepared using probabilistic methods expressed in millions of barrels of recoverable oil (mmbo), gross 100% equity basis.

Gas to liquid conversion factor of 6 has been used in the resource estimates to deal with volumes of associated gas. Analysis of Loba crude oil indicates that it is very similar to nearby neighbouring fields which have low amounts of associated gas and therefore Loba is expected to have small amounts of this gas. As gas can be either flared or produced through the nearby existing infra-structure, there is no impediment to production but that any economic gain from the gas is regarded as negligible and for clarity purposes reported volumes in this release do not include any volumes from associated gas.

Pura Vida is not aware of any new information or data that materially affects the assumptions and technical parameters underpinning the estimates of the contingent and prospective resources presented.

Persons compiling information about hydrocarbons

The resource estimates contained in this presentation have been prepared by Mr Andrew Morrison BSc. Geology (Hons) a Geologist who has over 30 years of experience in petroleum geology, geophysics, prospect generation and evaluations, prospect and project level resource and risk estimations and is a member of the Society of Petroleum Engineers. Mr Morrison is a full time employee of the Company and has consented to inclusion of the resource estimates in the form and context in which they are included. Mr Morrison meets the requirements of qualified petroleum reserve and resource evaluator as defined in Chapter 19 of the ASX Listing Rules and consents to the inclusion of this information in this document.

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CONTACT Simon Eley, w: +61 8 9226 2011 e: info@puravidaenergy.com.au

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