Thank you Chris ... Good morning and welcome to you all. It is pleasing to see such a good turn-out to our annual meeting.

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Before we get into today’s presentation, the first two slides contain our usual disclaimers. Today’s presentation will be posted on our website and you can refer to it at your leisure.

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Before we get into today’s presentation, the first two slides contain our usual disclaimers. Today’s presentation will be posted on our website and you can refer to it at your leisure.

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So let’s move onto the presentation itself. On Slide 4, you will see that today’s presentation focuses on progress with the Elk-Antelope LNG development. We will also consider the potential volume upside for the field. Beyond Elk-Antelope we believe there is additional value in the prospects and leads within our acreage. It is all about enhancing shareholder value and we will return to these themes during the presentation. However, for now I simply want to say that we are making significant headway on Elk-Antelope appraisal and development. We also have an exciting story about the sub-surface work we have accomplished over the past year and the potential upside we see for Elk-Antelope resources. Today we will also reveal results of the work we have done across our acreage in Papua New Guinea. Our assessment lends even more weight to our belief that this acreage could add multi-Tcfe outside of Elk-Antelope.

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Finally, in building long-term value for our shareholders, our repeatable strategy is clear and concise. It is about finding hydrocarbons, enabling their development through having the right partners and funding, and maintaining a material interest in the resources we develop. Now – before I came to New York this week, I was in Paris meeting with Total. While I was there I also met Papua New Guinea’s Minister for Petroleum and Energy, Nixon Duban. I came away even more confident than when I arrived. Total – the Government of Papua New Guinea – indeed, the whole Elk-Antelope joint venture – are fully committed to this project. Total have a large team at work and the venture expect to make the concept select decision for the LNG project mid-year. They are committed – as we all are – to ensuring plant design matches gas reserves and – like us – are pushing forward on the appraisal program. We all want to maximize volumes because that will maximize value. We have almost finalized the transition of operatorship to Total and they could be operating PRL-15 from early next quarter. As Total assumes operatorship they will be ramping up their presence in Papua New Guinea. Soon, we will have a world-class LNG operator – operating a world-class gas field. For InterOil – and for our shareholders – this is how we are going to unlock the significant value in Elk-Antelope.

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Slide 5 outlines the key speakers for today’s presentation. I am pleased to be joined by our Chief Operating Officer Jon Ozturgut, our Chief Financial Officer Don Spector and our new Senior Vice President of Exploration, Saxon Palmer. Saxon’s appointment follows the transition of Laurie Brown to an advisory role following Laurie’s treatment for a back condition that has restricted his mobility and capacity to travel. Fortunately for us, Laurie and Saxon have worked together at InterOil since August 2013. Together they have delivered great focus and clarity to our exploration strategy. Saxon is a former executive with BP and BHP Billiton with more than 25 years of international oil and gas experience. Today, Saxon will give more detail on our exploration portfolio. Our CFO, Don Spector, will outline our financial position and provide an overview of the impact Elk-Antelope could have on our value as a company. And Jon will present on the Elk-Antelope appraisal program and the LNG development. He will also discuss findings at Antelope-4 and -5, and the potential upside in the west of the field.

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Other key members of our team are also present today, including Dave Holland, a geological pioneer of the Eastern Papuan Basin who holds a special place in the InterOil story. They will be happy to speak with you after the meeting. To start, I will hand over to Jon …

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Thank you, Michael. Good morning everyone. I will start by providing an update on the Elk-Antelope appraisal program where very encouraging data from Antelope-4 and Antelope-5 strongly supports a multi-train development. I will talk you through how we arrive at this conclusion. I will also give you an update on the LNG development in PRL 15, for which Total has been appointed operator, and on concept select, which will be announced shortly. Let’s turn to slide 7.

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Before we go into the appraisal program, I want to step back and look at why the Elk-Antelope LNG project remains so attractive, not just for PNG and the joint venture, but also for the shareholders, the financiers, the contractors, and most importantly, the customers. In one sentence – it is shaping up to be one of the world’s lowest-cost, new-build LNG projects. Don will go through the metrics in more detail later. Elk-Antelope gas has significant advantages over other molecules looking for a market. First, as a general rule – lowest-cost molecules get monetized first. Second – Elk-Antelope sits in the middle of a highly prospective gas province. Third – we believe Elk-Antelope is not alone, which means significant expansion potential for the LNG plant. These are all outstanding attributes. Let’s turn to slide 8.

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So why do we need to appraise Elk-Antelope? Let me start by saying our focus is on monetizing Elk-Antelope, as quickly, efficiently and as safely as possible. While reasonably well defined, the subsurface requires additional appraisal to further reduce uncertainties and maximize shareholder value. As with any large-scale LNG development, it is critical to size the capacity of the LNG plant to match the size of the resource. Failing to properly assess field size can lead to costly inefficiencies. The results of the appraisal program will drive • project off-take rates • the number of production wells and of course, • the number and size of the LNG trains. Based on our work to date, we remain confident of a multi-train outcome. In addition to right-sizing the development, there’s another significant monetary incentive to properly appraising Elk-Antelope. The diagram on the right from an analysis by UBS illustrates two key points.

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First – proving up additional volumes increases the net present value of the project to InterOil – we are simply selling more hydrocarbons. Second – proving up additional volumes increases the size of the payments from Total. Therefore, a more rigorous appraisal now is more likely to prove up additional value and generate near-term cash payments to InterOil. For example, at 7 Tcfe this analysis shows the net present value to InterOil is nearly $3 billion. At 9 Tcfe, the net present value would be over $4 billion. This is why our near-term focus remains on the best possible appraisal of Elk-Antelope. But, of course, we will have to wait for reserves certification to know the final outcome.

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Slide 9 gives an idea of the actual geology of this giant field. Here we have a modern and an ancient example of the Elk-Antelope depositional environment. The picture on the bottom left shows a modern example of an atoll carbonate build-up. The numbers relate to One, the slope; Two, the reefal rim; and Three, the lagoonal rock. The picture at the top of the slide is an example of a Devonian carbonate build-up exposed at surface. This also shows the relationship between the slope, the reef and the lagoonal rock types. For scale, this is Windjana Gorge in north-western Australia. It is only 100 meters high, or about 330 feet, while the gas column in Elk-Antelope is about 700 meters high, or nearly 2,300 feet. Both these examples are similar to what we have in Elk-Antelope – with the slope on the west, the reefal rim where we drilled the appraisal wells, and the lagoon to the east. With this in mind, let’s turn to Slide 10 for an update on the appraisal wells.

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On the Q1 call, we provided an update on the positive reservoir results we encountered at Antelope-4. The map on the right was drawn before the current appraisal program. It shows the structural contours in meters with the gas water contact as a dotted line. Superimposed on the map are colors representing different rock types consistent with an atoll reef. We know from the Antelope wells that we have the best quality reservoir in the reefal rim, which is shaded in yellow. This reefal rim contains the best rock type for gas storage capacity. At Antelope-4, which is shown on the southern flank of the rim, we expected to intersect the reef slope where the rock is generally of poorer quality with lower gas storage capacity. However, this was not the case. Let’s take a look at what we actually found.

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Slide 11 shows the reservoir rock types we expected before drilling Antelope-4 – a good quality upper limestone followed by an excellent quality dolomite and then a lesser quality lower limestone. But this well actually intersected dolomite from the top of the reservoir and throughout the cored interval. Generally, the average porosity for carbonates is less than 15%. However, we encountered dolomite with porosity as high as 25%. The insert picture shows a thin-section about the size of a small coin taken from the Antelope-4 core, and is an excellent example of how we examine reservoir quality. Petrologists saturated this section with a viscous blue resin that filled the holes in the rock, which allows us to measure the porosity. The positive contribution to gas volumes from this dolomite could be considerable. The Joint Venture has now agreed to a side-track to determine the total dolomite section in the southern flank. Now let’s move to Slide 12 and Antelope-5.

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As discussed on our Q1 call, we have new interpretations of seismic, airborne gravity and well data that suggest positive outcomes to Elk-Antelope volumes. The location of Antelope-5 can be seen on the map of the pre-drill expectation for the top reservoir. The well actually came in 230 meters, or 750 feet, above our reference case. As such, a post-drill top reservoir map would now have the structural high encompassing Antelope-5. Let’s turn to slide 13.

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Technology is providing significantly better resolution of gravity and seismic data and recent reprocessing data has shown that the bounding fault of the Antelope field may extend even further west than previously mapped. This can be seen in the post-drill map on the left, which was drawn after Antelope-4 and -5 were drilled. This interpretation has significant positive implications for our view of the field. As illustrated in the cross-section on the right, a fault that lies further to the west will increase the amount of reservoir above the gas-water contact. The map in the center indicates the higher quality resolution of the recently acquired aerial gravity data. The areas of interest are the red and yellow colors. The yellow circle denotes where we can see potential upside. We have also highlighted three different scenarios for the fault. What is exciting is that our previous mid-case has now become our new low case. We are now evaluating all options, including an appraisal well, to test the extent of the

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fault, the top of structure and the extension of the high quality reservoir to the west. Also, while we are on this slide it is hard not to notice the Raptor trend and Antelope South prospect. Let’s move on to Slide 14 …

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Antelope-5 uncovered some of the best reservoir in the field. It has also extended the margins of the reefal rim further to the west than previously interpreted, as indicated by the yellow arrows on the right and the cross sections on the left. The map, which was drawn after Antelope-4 and -5 were drilled, shows that the reservoir crest extends further to the south-west towards Antelope-5. This new data has increased our understanding of both the container size and reservoir quality in the western flank. Both imply significant positive outcomes and we are currently reviewing the best options to quantify the new data, which could include another appraisal well, to the west of Antelope-5. The significance of this potential lies in gas volume, which, of course, can be translated into value. Now let’s put that into context. Every three Tcfe roughly equates to an extra LNG train. Based on Wood Mackenzie data, each LNG train in the Exxon-led PNG LNG Project

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generates about $2 billion a year in gross cash flow. Let’s turn to slide 15.

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Antelope-6 is a test of the eastern flank of the field and will provide important structural control over the eastern side. As we have seen in Antelope-4 and -5, the reefal rim may actually extend to the Antelope-6 location, as indicated by the yellow arrows. This would represent a further resource upside. Site preparation for Antelope-6 is well advanced and we expect to spud in the second half of 2015. Let’s turn to slide 16.

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On slide 16, we consider the extensive data that we have acquired over the Antelope field. To date, we believe these results support - a single gas column - with field-wide communication - and no evidence of compartmentalization. In particular, if you take a look at the chart on the right, the pressure data is plotted against depth. It defines a single gas gradient in red and single water gradient in blue. This supports the view that Antelope is one giant field without compartmentalization. These are great attributes and give Elk-Antelope a significant competitive advantage for development and production.

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After starting flow testing at Antelope-5, we have now collected over 115 hours of flow data. In April, we did an initial clean up test where we flowed 74 million standard cubic feet a day. Recently, we concluded a four-rate flow test where the results can be seen on the chart on the right. The red line shows the gas flow rate at four different choke sizes over different flow periods. The black line shows minimal drawdown in well head tubing pressure, over the same periods. These results further demonstrate the well’s deliverability and capacity to be a prolific producer. A pressure gauge has already been successfully set in Antelope-1 to monitor the pressure responses during the four-rate flow test. Following venture approval of an Antelope-4 side track, a full high-rate interference test is planned between Antelope-5, Antelope-1 and Antelope-4.

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Let’s turn to slide 18.

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And finally, Slide 18. Back in February, we announced that Total would be operator and we have since been working through the transition which is well advanced. We are on track for Total to assume operatorship from early next quarter and they will be operating future wells in PRL15. In addition, the multiple work streams that will make this LNG project a reality are being run in parallel and much has been accomplished. It is not just about appraisal drilling. Total has been leading on the conceptual studies since 2014. This includes the initial screening phase, which was completed last September. Sensitivity analysis and definition of the three development options was concluded in January 2015. The venture is now finalizing the detailed study phase, which is the comprehensive analysis and quantitative evaluation that led to concept select. The concept select will include the LNG site selection, location of the central processing

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facility, the gas export scheme and acid gas treatment. We met Total last week and they confirmed that we remain on track. I am looking forward to the announcement of the development concept, which we expect shortly. This will be followed by detailed design work and front-end engineering for Elk-Antelope. The venture is discussing project financing and gas marketing and environmental work and social mapping is underway. We are very appreciative of Total’s technical expertise and the depth of experience that has been brought to the project. We also appreciate Total’s strong commitment to PNG. After spending last week with Total and the PNG government in Paris, it is pleasing to see how committed everyone is to this project. This WILL BE a world-class project. And with that, I will hand over to Saxon.

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Thank you, Jon. Let me begin by saying how privileged I am to have the opportunity to work with InterOil in the Eastern Papuan Basin. As Michael mentioned, our strategy is about adding value. My role is to deliver on the first element: To find hydrocarbons, safely and competitively. First, we will take a look at the history of our success in the Eastern Papuan Basin and how we got to where we are. Then, I will take you through our portfolio and plans to advance exploration and appraisal. And then we will take a closer look at some of these targets.

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We first showed Slide 20 in our fourth quarter results call in March. Our high-graded exploration targets are Wahoo and Antelope South. And our appraisal targets are Triceratops, Raptor and Bobcat. Together, we currently believe that these can hold about 8 Tcfe of gross unrisked contingent resource and 9 Tcfe of gross unrisked prospective resource on a P50 basis. The P50 numbers for each of our five targets outside of Elk-Antelope are marked on the slide. Together with the 35 additional leads, we see this as an extraordinary basin opportunity which provides a world-class growth opportunity for InterOil.

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Slide 21 explains InterOil’s history of exploration success in the Eastern Papuan Basin. Our first discovery was at Elk-1 in 2006, which was the first indication of the basin’s enormous potential. This was followed in 2007 by Elk-4, which was actually the discovery well for the Antelope field. After further appraisal of Antelope, we discovered Triceratops in 2012, our third discovery in the basin. In 2014, we followed these successes with the Raptor and Bobcat discoveries. In short, we have had five discoveries in succession. This is an enviable position that also shows we are working with tremendous resource potential.

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Slide 22 shows one of the two tools that we use to advance our portfolio. It also shows how technology has significantly improved. To that end, I will talk to you about an exciting new technology that we are applying to the Eastern Papuan Basin – aerial gravity gradiometry that increases resolution by up to 20 times. To the left, you can see an example of the conventional gravity survey that was used when we discovered Elk-Antelope. In this map, we can make out the shapes of Antelope, Antelope South and the large Raptor trend to the west of Antelope. On the right is a corresponding example of our new gravity gradiometry data showing far higher resolution. With this data set, you can actually make out individual faults. InterOil is currently acquiring aerial gravity over its entire 16,000sqkm of acreage in the Eastern Papuan Basin. This is providing a step-change in our ability to image our portfolio and will allow us to become far more effective in defining our opportunities.

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A key component of our ability to explore and appraise in the basin is the use of seismic data, as shown on Slide 23. Seismic is a very valuable tool in pre-drill risk reduction. The left chart shows the original data over Elk-Antelope where you can faintly see the field, as well as the White Tail prospect. This seismic line was actually used in the Elk-Antelope discovery. The right chart is a reprocessed version of the same seismic line using modern technology. The difference is profound. We can clearly see how modern computers using modern algorithms can improve the data set significantly. This allows us to be more effective in appraising and exploring our acreage. For example, other structures such as Mule Deer – which we could not see before – are now obvious. While this slide is about reprocessing of previous surveys, let’s not forget that we are

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also continuing to apply modern technology as we acquire new seismic to high-grade our prospects, leads and appraisal.

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Slide 24 is about one of our opportunities – Triceratops-3 in PRL39. This well is targeting a significant carbonate build-up near Triceratops-2. In the original work by GLJ Petroleum Consultants, Triceratops was given a contingent P50 resource volume of around 400 bcfe, or less than half a Tcf equivalent. Triceratops-3 will further appraise the field and based on our latest estimates, has the potential to more than double that contingent resource volume. This is important because the field could tie-back to an LNG development. And – as a side note – you can see in the photo on the right that we are also using a new rig to drill this well. We expect the well to begin drilling this month.

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Slide 25 explains Wahoo. We suspended Wahoo last year due to pressures that were up to 50% more than what we encountered at Antelope. Since then, we have re-designed a side-track to handle these pressures and are preparing to re-enter the well this month. We know Wahoo has a hydrocarbon kitchen that is capable of producing thermogenic gases. We also know that the regional seal – the Orubadi formation is present. Now, we need to test if the reservoir is present within the structure. Wahoo is attractive geologically and commercially. From a geological perspective, success at Wahoo will prove up the extension of our known trend, which we have identified in Elk-Antelope, 170km to the north-west. Based on our latest internal estimates, we believe Wahoo has a mid-case potential of around 3.5 Tcfe. That is enough gas for one train.

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Success at Wahoo will also de-risk other leads that have been identified, such as Mako to the south. Wahoo is also relatively close to the coast and has road access to Port Moresby. A successful Wahoo would therefore be one of the closest gas discoveries to Port Moresby with potentially lower development and production costs than other discoveries in Papua New Guinea.

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The seismic section on Slide 26 shows Raptor to the left and Antelope to the right. In between are two other features known as White Tail and Mule Deer. The seismic and well data are extremely encouraging. When we first entered the Raptor reservoir late last year, we flared gas at surface. We also found high concentrations of condensate. Raptor is a deep penetration of the limestone and later this year, we plan to do a side-track and flow test. Based on our internal estimates, Raptor has the potential to be another giant, with a mid-case of 5.5 Tcfe.

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Now let’s have a look at Antelope South on Slide 27. We like that Antelope South partially underlies the Antelope field. Seismically, it looks a lot like the Antelope field. As you can see from the top insert this is an area where we have acquired substantial seismic data. Based on our internal estimates, Antelope-South also has a mid-case estimate of 5.5 Tcfe. The joint venture has now agreed on a site location for the well and will determine a spud date, pending venture approval. This well will be drilled by Total as operator.

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And now to Bobcat, on Slide 28. Bobcat was drilled around the same time as Raptor and also flowed gas to surface. The well penetrated the reservoir in a transition zone between an up-dip gas field and a down-dip water leg. We are now acquiring seismic to better delineate the field. Based on current data, our internal estimate is a mid-case of 1.5 Tcfe. Based on the interpretation of this data, we will determine how we will further appraise it.

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And finally I will quickly recap on the potential of the Eastern Papuan Basin. We have found one giant already – and our success rate is currently five out of five. Through a rigorous process, we have been filtering our 35 leads to find those that offer the best chance of commercial success. And – as Jon said earlier – we believe Elk-Antelope is not alone. With that, I will hand over to Don.

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Thank you Saxon, and welcome to everyone at our annual meeting here today. For my part of our presentation today, I would like to start with: A quick overview of our financial position, including having a look at the cash flow we will receive from the deal we did with Total, as well as the timing of when we expect to receive the initial certification payment. I will also touch on the savings we have negotiated on the unit costs for our drilling and seismic activities. Then I will finish with a more detailed discussion on the economic attractiveness of the Elk-Antelope LNG Project.

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Starting with the slide we presented at our first quarter update last month, we had $628 million of liquidity at the end of March, consisting of $328 million of cash and receivables and the fully undrawn Credit Suisse-led facility of $300 million. This is a very healthy position for us to be in as we move towards the development of the Elk-Antelope LNG Project. Turning to our costs for this year, we have seen our seismic and drilling unit costs come down as the fall in the oil price has dampened global activity. The day rates for our new rigs have come down by as much as 25 per cent. With logistics, the cost of barging equipment back and forth to our sites has also reduced by nearly 25 per cent. And on seismic, rates have dropped by nearly 20 per cent. Notwithstanding the extensive level of activity this year, it is pleasing to see the unit costs for these activities continue to fall.

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Slide 32 sets out the payments we can expect to receive from the deal we completed with Total last year. If we focus on the dark blue bar, we can see the certification payment we will receive from Total at the completion of the appraisal program. As we have mentioned before, on a base volume of 7.1 Tcfe, the certification payment we will receive will be nearly $600 million, plus an additional $517 million at final investment decision. For every Tcfe above 7.1, we receive an additional $400 million. The main theme for the structure of the deal we did with Total was to ensure we get paid for every molecule we find in the Antelope field. This includes a potential second certification payment after production has commenced. In addition to the certification payments: We also have the exploration bonus, where Total provides a carry on one exploration well of up to 75% for the first $60 million, plus they will pay $65 million for every Tcfe above the first Tcfe we find in the Antelope South prospect. We should also note here that with the drilling of Antelope-6 due to commence during

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the third quarter this year, the timing for receipt of the certification payment will likely move into the first quarter of 2016. Our focus right now, is to define the right volume for Elk-Antelope so we can correctly size the development and achieve the best long-term value outcome. The volume we certify at Antelope is, therefore, far more important than the timing of the certification payment as we remain well funded following the recent extension of the Credit Suisse facility.

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Now let’s take a look at slide 33 and the cost competitiveness of the Elk-Antelope LNG Project. The ExxonMobil-led PNG LNG Project has proved to be one of the lowest cost LNG projects globally. At a total cost of approximately $19 billion, this equates to about $2,300 a tonne. Our project at Elk-Antelope, according to research by various analysts, will be even lower cost than the ExxonMobil project, and is forecast to come in around $2,050. So why is our project forecast to be lower cost? Firstly, Antelope is one big field, whereas the ExxonMobil project had to aggregate from seven different fields Secondly, the Antelope field is much closer to the coast, hence will require a shorter pipeline, and And finally, because our project has direct river access, it will substantially reduce our transportation costs. These all add up to substantial costs savings for our project, and as I mentioned earlier, lead to a forecast construction cost of approximately $2,050 per tonne.

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So how do LNG projects in PNG compare with other LNG projects in Australasia? Let’s turn to slide 34. This cost profile shows Elk-Antelope as being the lowest cost LNG project in the region. What it also shows is that PNG – when you look at the actual cost for the ExxonMobil project and the forecast cost for Elk-Antelope – is one of the lowest-cost countries to build LNG projects. And in this lower oil price environment, lowest cost always goes first. This is very encouraging for not only the initial development at Elk-Antelope, but also the prospects for long-term expansion.

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So how strong will that market be when we look for those future buyers of our gas? Turning to slide 35. Wood Mackenzie has done a lot of work on how much additional supply will enter the market to meet the ever growing need for energy supply. The main chart on the left of the slide shows contracted supply keeping pace with demand until the end of this decade. But what happens from early 2020 onwards is that demand continues to increase well in excess of the contracted supply. This normally leads to a higher pricing environment. So why do they believe that demand will exceed supply? Firstly, as you can see from this slide, existing contracted supply will start to taper off from 2021. Secondly, if we look at the chart on the bottom right of this slide, demand from China is expected to double between now and 2020 and then continues to grow over the next decade.

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And then thirdly, in this lower oil price environment, only a small number of new greenfield projects will be built. Only projects with lower cost profiles will be developed in the current low oil price environment. And as we have already seen, Elk-Antelope is forecast to be one of the lowest cost new build projects to be developed. To reinforce the cost benefits that LNG projects have in PNG – if we look at the chart in the top right hand corner – PNG sits right on the doorstep of the world’s largest LNG markets. With sailing times of less than 10 days to most of Asia’s import terminals, PNG has a large advantage over nearly all other competing suppliers.

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Having established that PNG is one of the lowest cost countries in the world in which to develop LNG, what is the cash flow profile for an LNG development, and most importantly, what does that profile look like post start-up of the project? Slide 36 shows an indicative cash flow for a two-train LNG development. According to Wood Mackenzie, the ExxonMobil LNG project in PNG will be generating an average of about $4 billion of gross cash flow per year in the coming years. Using these metrics, a similar two-train project at Elk-Antelope could generate about $1 billion of cash-flow per year for InterOil. And as this profile shows, depending on oil price, cash flow remains relatively constant throughout the life of the project. Once an LNG project ramps up to full capacity, subject to operational reliability, it normally maintains that level of production throughout its life. Another important issue is the impact an LNG project can have on your share price. In this regard, the share price performance of Oil Search, which has 29 per cent of the PNG LNG Project, may be instructive. Oil Search was trading at just above $3 a share when engineering design work began on

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the PNG LNG Project in 2007. When the project was completed in 2014, the Oil Search share price had risen to more than $9, a 180 per cent increase over the development and construction period of the project. Not a bad return for shareholders. In wrapping up my section of the presentation, our company is well funded today and along with the continued strong support we are receiving from our banking group, we are looking forward to the payments we are about to receive from Total under the deal we completed last year. We have another busy year ahead of us as we continue to make material savings in the unit costs associated with our core business activities. And finally, Elk-Antelope is well placed as Papua New Guinea’s next LNG project with attractive economics and a robust market to sell our gas into. On that note, I will hand you back to Michael.

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Thanks Don, and also Jon and Saxon. In summary, we are making great progress on Elk-Antelope appraisal and project development. In particular, we are hugely encouraged by what our sub-surface team is seeing within Elk-Antelope. LNG project planning continues with pace and we expect concept select soon. This will then lead into basis of design and front-end engineering. Flow testing at Antelope-5 is progressing well and initial results demonstrate the well’s deliverability and capacity to be a prolific producer. Furthermore, we have identified multi-Tcfe in our prospects and discoveries outside of Elk-Antelope that we will drive towards monetization. This is all about our strategy of building long-term value for shareholders through: • finding hydrocarbons • enabling their development through having the right partners and funding • and maintaining a material interest in the resources we develop. We thank you for your continued support and now look forward to your questions.

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Thank you.

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