Company: Title: Oil Search Limited Half Year Results. Start of Transcript

Transcription

1 Company: Title: Oil Search Limited Half Year Results Start of Transcript Rick Lee: Good morning all. My name's Rick Lee and I'm the Chairman of Oil Search and I'd like to thank you for your interest and support of the company. For most of the last six months, I had thought that I might be standing here at this meeting welcoming IOL's shareholders to the Oil Search register. We had been making pretty good progress as I think you would be aware in convincing Oil Search - InterOil shareholders of the merits and prospects of a merger with Oil Search. The vote would have been a few weeks ago. All changed obviously when the InterOil Board advised in July that an Exxon proposal had been judged by their Board to be superior to the one that Oil Search had made and changed their recommendation to their shareholders. So that's where we are. We as a Board, decided not to match Exxon which was our right and a similar position was adopted by Total. So in many ways, there was a great deal of disappointment in the Oil Search camp to surrender the position of what you might say some control over the integration and our own destiny. But I think and you will hear later today that we see very clear benefits still from integration being available and arguably more certain for Oil Search shareholders. At all times, shareholder value was our primary dimension in our thinking. So Oil Search resumes the position of facilitator and influencer of its destiny in PNG with our partners in PNG LNG and Papua LNG. You might say, our customary position. We're not in the driver's seat, but we're certainly on the same bus. We have also maintained our commitment to PNG and while all of this was going on, I think you'll see in the results today that our engagement with InterOil did not distract us through the half year from our focus on costs, on efficiencies, on productivity and on liquidity management in the face of very weak oil and LNG markets and uncertainties going forward in terms of outlook. So we did keep our eyes squarely on the main game of operating and financial performance and you'll see in the presentation I think from Peter and his team that the outcomes for that have been, I think, creditable in a very difficult market. So I'll hand over to Peter. He will go through those results and discuss to some extent the outlook as we see it today, obviously more work to be done, before moving to Q&A. So thank you very much for your interest. Peter Botten: Thank you, Chairman. Thanks very much, ladies and gentlemen who are present here in the room, but also the many I know who are out there on the Internet and various linkages, telecommunication linkages that we have. It's a real pleasure to be here today to present the 2016 half year results and go through what I think to be a platform really for growth which frankly I've not seen much stronger at any time in my time at Oil Search. The first half results for 2016 I think can be characterised as showing strong operational performance in both PNG LNG and our oilfields along with very tight cost control. Total production was 14.9 million barrels of oil equivalent, marginally below our record for last year. I should say that our presentation is going to have normal disclaimer, highlights and that's where we're at. This morning we're going to go through the highlights that I'll describe, the financial overview, the gas development potential that we see in our portfolio, the exploration potential and the strategy post InterOil and I'll summarise. Stephen Gardiner, our DISCLAIMER: This transcript has been prepared by a third party for Orient Capital Pty Ltd. It may not be accurate or complete and should be verified directly with the issuer. Orient Capital Pty Ltd is not responsible for any consequences of the use you make of the information contained in this transcript, including any loss or damage you or a third party might suffer as a result of that use.

2 CFO will be up next to discuss in detail the financial overview with Julian Fowles describing production, Keiran Wulff, doing both gas and exploration and myself returning for strategy and summary. As I say, it's been a pretty good first half, we believe despite the low commodity price environment that we're presently living in. Total production was 14.9 million barrels of oil equivalent, marginally below our record set last year. Performance from the PNG LNG project was very strong, averaging 7.7 million tonnes per annum during the first half. Production rates have been much higher than this on a daily basis, but it really is a tribute to the way the operator, Exxon Mobil has operated these facilities and they continue to deliver rates well above the 6.9 million tonne nameplate capacity originally thought as the build for this project. Pleasingly, our mature oilfields also performed well in the first half with production at 3.52 million barrels of oil equivalent, some 4% higher than the previous corresponding period. Julian will talk about this later, but it really is an outstanding performance from our oilfields and a real tribute to the considerable efforts to improve the efficiency and uptime in these operations. Given this strong production performance we reiterate our 2016 guidance of between 28 and 30 million barrels of oil equivalent, with the most likely outcome in the upper part of the range as enunciated. Strong production led to record sales of 15.2 million barrels of oil equivalent. However, revenues were impacted by a major decline in oil and LNG prices down 30% and 40% respectively on the previous corresponding period. Stephen will go through those, that information in more detail later in his presentation. The business continues to focus on tight cost control. In the first half - in the first half, our unit production growth declined by 8% to a very competitive US$8.21 a barrel, at the lower end of our full year guidance. A net profit of US$25.6 million was clearly driven by lower commodity prices and a higher effective tax rate driven by a number of oneoff items. Again Stephen will describe these. We maintained a very strong operating cash flow and despite the lower oil price environment the balance sheet and liquidity remains very solid. With confidence in our production performance and the strength of our balance sheet, our Board did announce a dividend of US$0.01 per share for the first half performance. Obviously as our Chairman said, much of the early part of 2016 was focused on the agreed bid that we had with InterOil and the associated agreement with Total to on-sell equity and various discussions and agreements on a range of initiatives to promote development of a cooperation between Papua LNG and PNG LNG. In July, the InterOil Board changed its recommendations to support a higher value offer made by Exxon Mobil and following our analysis and discussions with Total we elected not to increase our offer for InterOil. We did this for a number of reasons. We did not believe it was in our shareholders' interests to increase our bid. What we had offered we believe represented fair value to all parties and any higher value required cooperation between PNG LNG and Papua LNG to really be attractive to us and we did not want to give away this value. We also considered the entry of Exxon Mobil into Papua LNG delivered to us a significant proportion of our regional objectives in promoting likely cooperation between the projects, making us more efficient, more competitive, delivering value enhancement in the next phase of LNG expansion without shareholder dilution or acquisition risk. The Exxon Mobil bid underscores our view of the value of potential cooperation and the size and quality of the Elk-Antelope 2

3 resource. As part of the termination of our proposal to InterOil, we've been paid a break fee which will be shared with Total and our agreement with them will subsequently be terminated. Obviously, Exxon entering Papua LNG changes the game in Papua New Guinea. Our objective of being a catalyst to promote cooperation between the projects has been achieved with them entering the project and we now have a huge opportunity to optimise future developments in terms of resource usage, capital efficiency and value optimisation. Such cooperation has the potential to improve our competitiveness in so many ways in a challenging LNG market. It's pleasing to note statements by Exxon Mobil and Total regarding cooperation, synergies, cost reductions and maximising value, all of which have been made by our partners since the announcement. We are in no doubt about the considerable work that remains to take full advantage of the platform that this transaction brings for value creation during the next phase of LNG growth in PNG. It will be a hard and complicated road, but I do believe the potential size of the prize in the challenging environment will help drive constructive dialogue on all sides, after the transaction concludes likely in late September. As part of our own prioritising for the LNG cooperative agenda, we have commenced a strategy refresh concentrating primarily on the options of how cooperation can be achieved and the associated values reflecting the Exxon Mobil- InterOil transaction. We've done a lot of work already, but we now need to fine tune this analysis with the changing circumstances. More of that later. As we move, obviously a key part of our business is keeping our people safe and safety improvement across our organisation remains very strongly a focus for the second half of Our results in the first half of 2016 have not been what we want to achieve and although we have made progress in key areas such as process safety, the development of processes and systems and understanding and training, further training of our staff, we are really focused in the second half to deliver what we believe to be a much better performance in safety across the board and are already seeing the focus of our staff across the company in delivering better performance over the last few months. Safety remains a key focus as I say for the company and it's something that we take seriously right from the top. We remain very competitive in an Australian context in our safety performance, but that's not good enough and we really will be concentrating on the small stuff, focusing on various initiatives to drive safety performance into a better space towards the end of the year. With that in mind, I'll now hand over to Stephen Gardiner, our CFO, who will discuss the financial overview of the company and the numbers in more detail. Stephen Gardiner: Thanks very much, Peter and good morning, ladies and gentlemen. As Peter said, I'll drill down in a little more detail into our financial performance for the half year. Unfortunately, as Peter has already highlighted we had a record sales volume for the first half of this year, but that wasn't enough to prevent the impact of the further slide in oil and gas prices during the period. That resulted in a 33% decline in our revenue compared to the prior first half. Even with higher production and sales volumes though which obviously create costs themselves, our operating and other costs were down by 7% in absolute terms. If we exclude the InterOil acquisition related costs, the decline was actually 13%. That really reflects the capture of costs savings from our business optimisation program that we identified last year and we've been implementing since then through the first half of Our exploration cost expensed in the first half were much lower than last year, with only the Strickland 2 exploration well written off during the period. We only had a modest 10% equity interest in that well. 3

4 Our tax expense of US$22 million equated to an effective tax rate of 47%. Although our LNG earnings and about 60% of our oil income is taxed at the 60% gas field rate in PNG, we had a number of one-off deductibles in the period against a lower underlying tax profit which drove up that rate. They included costs such as the InterOil acquisition-related costs, some costs we spent on power, moving our power project forward which are non-deductible, our business development costs and also an adjustment to our rehabilitation provision due to a decline in discount rates. We expect our full year tax rate though to move closer to the 30% statutory rate over the second half of the year. Turning to our operating margin performance, our realised oil and gas condensate price averaged just under US$42 in the first half of That was down 27% on the same period last year. Our LNG - the LNG and gas price declined even further by 40% to US$6.09 per million BTU with the larger fall due to - in part due to the three-month lag in LNG pricing and also the impact of soft spot crude price, LNG prices during the period. But despite these lower prices, the cash earnings performance was supported by very resilient cash margins for both the PNG LNG project and our operated assets with the combined margin at 55%, affirming the quality of our producing assets. The PNG LNG cash margin at 77% was particularly robust, given that it includes shipping costs for LNG cargoes that are delivered ex-ship with about 70% of the cargoes during the period sold on that basis. More importantly, our margins were also defended by a very strong focus on cost management and I'll turn to that now. Our unit production costs reduced from US$8.90 per barrel of oil equivalent in the first half to US$ first half of 2015 to US$8.21 in the half just completed. That's down 8% reflecting higher overall production of course and more importantly the benefits from the cost reduction initiatives we've introduced. They range from renegotiation of materials and services contracts with unit rate reductions of up to 30% achieved. We've also reduced our labour pool and shifted our workforce to those locations where we have lower operating costs. We've also importantly prioritised the work programs that we do and introduced better planning around those programs to save costs and clearly focused on work that delivers value in a lower oil price environment. Our PNG LNG production - PNG oil and gas production costs more importantly where we have direct operating control decreased by 11% compared to the first half of last year. Our focus now is very much on making sure that we sustain these cost savings into 2017 and beyond. Healthy cash margins delivered healthy, very healthy operating cash flows. Our operating cash flow for the half was US$239 million, very pleasing given the state of oil and gas markets currently. It included borrowing costs of US$95 million, almost all of which related to interest payments for the PNG LNG project. Almost US$16 of operating cash was generated for each barrel of oil equivalent we sold in the first half of the year and our operating cash flow covered our investment spend by 1.5 times. Our investment was primarily on exploration and operator activities to further build our growth platform. Our financing outflows included US$61 million to fund the 2015 final dividend and also the first full principal repayment under the PNG LNG project financing of US$145 million. That was made in June. It's worth noting that since the financial completion in February 2015, we've received US$1.26 billion from the project. That's after the project funding itself, all operating and CapEx during the period and all scheduled debt servicing. So even with lower oil prices, the project is throwing off a tremendous amount of cash. Again cash flow, helps our balance sheet as well, so we're in a very strong position from a balance sheet and liquidity perspective at the moment which is where you exactly want to be in this environment. As the liquidity chart at the top shows, we've managed to maintain our strong liquidity position over the last 18 months despite the decline in oil and gas prices. We currently hold US$780 million in cash and I'm keeping a very tight hold on that and have access to US$750 million of committed undrawn bank loans. 4

5 In the first half, our operating cash flow breakeven including interest costs was less than US$17 a barrel of oil equivalent and if you add in sustaining CapEx and the scheduled LNG debt repayment, it was under US$28. So the business very much washes its face at all prices well below those we experienced in the first half of the year. We had US$4.1 billion of debt outstanding at the end of June all drawn under the PNG LNG project facilities. That debt's non-recourse and it's repaid semi-annually on a mortgage style basis and it's spread out over the next 10.5 years. So there's no financial stress in our scheduled debt repayments. Also our overall gearing at a comfortable 42% at the moment and a level that we're very comfortable to manage going forward. So in summary we've certainly got sufficient balance sheet strength to fund our LNG growth projects assuming a continued recovery in the oil and gas prices over the next few years. Turning to our investment spend, there's no change to our full year investment spend guidance that was revised downwards in the quarter report issued in July. We're still in the range of US$270 million to US$315 million. Our second half investment spend will be very much focused on exploration and appraisal activities with the drilling of the Muruk and Strickland 1 wells and the final Antelope appraisal well and Keiran will give more details on that program. Finally, other elements of our full year outlook are also unchanged from the revised guidance we issued in July. Peter has already mentioned the production outlook for the full year which is very positive. Our production cost guidance is also unchanged, but we expect to be in the bottom half of that guidance range of US$8 to US$10 per barrel of oil equivalent due to the embedding of cost savings and the higher production forecast that we recently announced. Although $13 million of cost related to the InterOil acquisition were booked in the first half results, our full year guidance for other costs excludes those InterOil costs. As we've already announced we'll be receiving about US$48 million net to us in break fees from InterOil that will more than cover the full costs of undertaking that exercise. So in summary, our full year outlook for Oil Search confirms our operational and our financial resilience in the face of an oil price that appears to have at least bottomed, but may take some time still to recover to more comfortable levels. On that note I'll hand over to Keiran - Julian. Thank you. Julian Fowles: Thanks very much, Stephen. Good morning, ladies and gentlemen. I'd like to spend a little bit of time just looking at our performance in production and the operations area through the first half of this year, with some comparisons back to what we were doing in Looking at both the LNG project and the performance there, the production and cost performance, but as well as of course our own operated production where we've got primary control. So to the first slide, really we've seen an excellent performance in the first half of 2016 as Peter already emphasised. We've had total production of 14.9 million barrels of oil equivalent. That's only very slightly lower than we saw in the second half of last year and if you look on this curve you'll see - on this graph you'll see the light blue bars which are the PNG LG contribution to that production. You'll see how that has stepped up through the last four quarters. Since we began production in the first half of '14 we've seen that step up gradually as the operator of PNG LNG has become much more used to the facilities, really looking to get the best out of those facilities, focusing on reliability and that's really starting to pay dividends as you can see. Our own operated production has also been excellent. It's been higher than we achieved in the first half of 2015 and don't forget this is in a series of fields which are in many cases, more than 20 years old. These are mature fields and we're still managing to get the best out of those fields. We've retained that production for many, many halves now at a level which is 3.5 or so million barrels of oil equivalent. So combined you can see that graph stepping up through time and as I said, at the moment we're at 14.9 million barrels for the first half and that's looking good through to the end of the year. 5

6 If we look specifically now at the PNG LNG project, its performance for the first half, it's been producing at an annualised rate of 7.7 million tonnes per annum and if you remember the nameplate capacity on the project is 6.9 million tonnes per annum. So we're achieving significantly better rates. This is despite planned maintenance that we've seen during the year. So in April we had a partial rate reduction for maintenance of the compressor system and an unplanned shutdown, the first unplanned shutdown we've experienced in May for a number of days due to some electrical faults that have since been rectified. It was very pleasing in that shutdown to see the response of the operator. They brought the plant back on line, they brought it back online very, very efficiently, very safely and very smoothly and since then the project has been going great guns. I have to say in June and July we've seen rates that are up around 8.2 or more million tonnes per annum on an annualised basis. So an excellent performance there from the plant and from the operator of course. We've delivered 205 cargoes as of the mid-year in total, since we started up in 2014 and 53 of those in the first half of this year. There's also been of course a strong performance in the upstream from Oil Search. We've got our own operated contribution to make not only through handling of the liquids which has gone again without fault, but also through the contribution of the Associated Gas fields. So we contribute quite a bit of gas, between 10% and 15% of the gas into the project. We've also delivered gas through Southeast Gobe through third party gas effectively and the sales there. OpEx and CapEx, operator's OpEx and CapEx are both below what the operator put forward as budgets. So again that's giving us improved performance on a dollar per boe basis and we believe these are sustainable changes that we're seeing, sustainable differences. Also I have to compliment PNG LNG on the safety performance. They've had an excellent safety performance though the first half of this year and that also reflects previous halves as well. The performance has been excellent. You can see on the picture there the locations where we have sent our cargoes and I'll talk a little bit about that at the moment. Obviously, we've got the contracted cargoes and we've been up at full rates on contract cargoes for some time now. But of course additional to that we've got a number of spot volumes that we have to place in the market and those spot volumes are - there's a very strong demand for those. Of course, our gas, our LNG has a very high heating value, that's very attractive to a number of markets in the region. We have a very reliable project and we have a very close proximity of our project to many of the markets in the Southeast Asian region. So if you see the first two quarters of this year we had eight spot cargoes and of those eight spot cargoes, six of those have gone to Japanese customers. That reflects the desire of that premium customer for our high heating value gas. So it's very encouraging. We've also been selling spot cargoes to other customers beyond just our long-term contract customers. They've traditionally been our primary buyers for spot cargoes. But we're expanding that beyond that area now, so we've got other customers becoming used to PNG LNG product and that's also very good for future marketing of longer term spot cargos. If I turn now to our operated oilfields and of course this is the major focus for us. We've had an excellent first half of production in oil, but also gas coming from Southeast Gobe and also from the Hides gas to electricity project. The gas there, the production has been excellent. I'd emphasise the field's maturity. We went through a process last year of optimising our business, really focused on our operated business and a number of initiatives were implemented about that. I covered that last year and I covered it in the early part of this year. But just to emphasize the dividends that that is paying, we're seeing significantly better reliability and uptime performance across all of our facilities. 6

7 A really good measure of that is looking at our compressor uptimes. A number of our facilities have major compressor units installed. Those compressors are a bit of a proxy for uptime at our facilities. We've traditionally seen uptime at our compressors of roundabout the 90% to 92%, 93% mark and in July and in June, we were seeing compressor uptimes of 100%. Not across everywhere, but across some of our facilities. That's the first time we've seen that for many years and it really reflects the reliability, but the focus also of our staff in the field, our operators in the field on improving and maintaining that higher level of performance and on prioritising the key issues for that. So that's been an excellent result and it's pleasing to see that happen and that's reflected in the production. It's also reflected in costs and I'll touch on that in a second. We've upgraded our 2016 operated production guidance up from 6.3 to 6.7 million boe and obviously that's reflected in the full year guidance that you've seen. Peter has touched on our safety performance. Safety performance in the first half of this year has not been as good as we had hoped. If I reflect back on last year we saw TRIR, total recordable incident rate of around about 1.9. First half of this year we saw 2.3. That's really not good enough. It's pleasingly to see we - as soon as we observed that trend, we stepped into the field, we stepped into all of our operations and really looked across the board at the areas that we were potentially having those incidents, having difficulties. There were a few hot spots that we've identified. Some of them are around the construction area, some of them are around our marine operations in the offshore. With a real focus on those, we've seen our July numbers now start to come back down. So we're now down just over 2, about 2.04 in terms of total recordable incidents. What we're seeing there I believe is something that we will be able to sustain through to the end of the year and I think that we'll see that much better performance through to the end of the year. Safety of course is something of - it's a key focus for everyone in the oil and gas industry. It's absolutely fundamental to what we do and it reflects also on reliability and how good our long-term performance is. So we're really focused on getting that right. I talked a little bit about our operating cost base and through 2015 of course we made a lot of changes to what we do. We changed the structure of the way we operate in the field. We brought a number of staff down from the field into our Port Moresby office. We moved some staff - we closed down our Brisbane office of course. All of the initiatives have had a flow-on effect into 2016 and we're starting to reap the benefit of a lot of that. So you'll see our unit production cost for our operated assets has come down by around 11%. On top of what we already did last year, we believe that's actually an excellent performance and we were already a relatively low cost operators despite the conditions, the harsh area that we operate in the highlands of PNG. So this is really an excellent performance from our operators in the field and it's great to see. A number of initiatives we've done there of course. Continuing to look at getting the right level of staffing, getting the right skills in place in the field. We've gone through multiple rounds now of renegotiating contracts and we continue to see reductions there in long-term major contracts on the orders of 15% to 30%. So again that has a very measurable and strong and immediate impact on our bottom line. We've focused on the efficiency of all of our support services in the field, making our camps more efficient. We've closed down a number of areas that we have camps, simply because we've managed to operate to optimise our staff numbers. We've also improved our utilisation of aviation. Aviation is a major cost in operations in the highlands of PNG. We've taken out a number of aircraft. We've replaced some with cheaper aircraft. We've got a very strong handle on exactly 7

8 our operating hours with aircraft and we're very focused on that. That is paying off in millions of dollar per year in terms of our operated cost. So a very, very tangible benefit. One of the other things of course we've looked at in 2016, given the very low oil price coming into this year was what projects could we defer, capital projects specifically. Some are around well work and we've deferred a number of those. Probably some of them into 2017, but some of them we're also looking at how we can reconfigure that work in a different way that would lead to long-term savings. So pending an oil price recovery, we will get back into some of that well work and of course that's important for sustaining again our long-term production. Looking at that, looking at the 2016 production outlook, as I said before we've increased our guidance there for the year on the back of what we see as an excellent performance in our operated fields and that now sits at 28 to 30 million boe. The numbers are up there for you, so I'll not go through those in a lot of detail. The midpoint there is talking about some very recent landowner issues. So we've had some landowner issues around the Hides area for PNG LNG and it seems those have been I think widely broadcast. Landowners have come into some parts of our areas, in what's effectively a peaceful protest. They're protesting that they haven't yet got resolution from the government on the distribution of a number of different landowner benefits. That - it's very pleasing to see now that that has developed into a very strong and positive dialogue and a dialogue that's very open with the government. So they're now publishing numbers very openly for all to see and that's been very pleasing. The impact on our production, our production at PNG LNG has actually, to be honest, been insignificant. It's been very minor. The operator prudently shut down or curtailed production from a couple of wells. Now remember that we've got eight wells on the Hides field and those can all produce at very high rates. So the curtailment of that production really only had a very minor impact on what we're seeing from PNG LNG. I'm very pleased to say that at the weekend all of that came back up with the landowners seeing a very positive response from government and seeing a future path of dialogue. I think that's really important to note that because that is really reducing what we've seen as a long-term risk in PNG LNG which is the risk of having landowner disputes about the distribution of benefits. So seeing progress in that I think is actually a real positive for us. There's a number of focus areas for us in the second half of this year. Clearly, an improved safety performance is really important and that will continue. So we're - actually we're pulling out all the stops to make sure that we improve that area. Obviously, ongoing optimisation of our production, focused on a number of things. Process safety of course is a big area for us, but also reliability. The reliability we've seen in the first half of this year, we're anticipating that that will continue into the second half and there's a significant amount of management effort going into the field to ensure that we see that. Well integrity continues with our relatively old well stock which is something we keep a very close eye on as well. Delivery of our third party gas - sorry, of Associated Gas and third party gas to PNG LNG of course is important and continued operations of the export system via our offshore terminal, those are really key to the project. We support the PNG LNG operator where we can in optimising our production operations. We're very flexible according to their needs and we have a very good dialogue with them around the integration of our operated areas with theirs. Integrated planning through to the end of this year and into 2017 is something we're really focusing on now as we come into the budget phase. We're looking at 2017, very early days on that yet. Of course the project that we've talked about previously which is looking at accelerating our gas from our Associated Gas fields, that continues to be a focus for us in terms of a new project. That has taken some excellent steps forward in getting joint ventures, both on the oil side and on the PNG LNG side on board with it. We've now gone through a first phase of contracting to get some of that work 8

9 underway to understand what the concept is really going to look like and that will obviously be something that we bring through in future presentations. That's it from me. I want to hand over to Keiran now who'll talk about gas developments and exploration. Keiran Wulff: Okay, good morning everyone. I'm Keiran Wulff. I'm the EGM for exploration and new business. Ian Munro sends his apologies, he's currently on holidays. I'm sure he'd probably prefer to be here talking to you, but he'll have to bear with me giving his presentation. Look, the first slide is without doubt highlighting that our strategy internally is to develop quite quickly the two new LNG trains in PNG, but importantly, have a line of sight to further expansion outside. Our commercialisation strategy to achieve that is really built on four pillars and they're all interlinked. It's about understanding and optimising our discovered resources properly and you'll see an evaluation appraisal program that we're undertaking over the course of the next six months. It's also about driving maximum cooperation and capturing all the synergies between the projects, driving costs as low as possible and also maximising the certainty of long-term growth and I'll cover that a little bit later. As already discussed by Peter and Rick, the focus of our IOC bid was to facilitate an integration between the projects and with Exxon now likely to acquire InterOil, one big step and probably the most challenging risk of integration has now been taken out. So the likelihood of integration is now very, very high. When you combine that with the recent certification program over at Elk-Antelope with our P'nyang resources, we now have two gas fields with over 10 tcf of 2P or 2C and over 6 tcf of 1C which is sufficient volume to support two new trains in PNG. That's equivalent or consistent to the level of resource certification that occurred in 2009 at the time we committed to the first foundation volume. So we really are there with a degree of certainty on two new trains in PNG with a clear line of sight to additional. What's also happening in PNG is in Julian's area is that we're also going through a recertification process of the resources in our foundation volumes. Whilst the results of that won't be known until the end of the year, the preliminary results are very promising with a strong likelihood of a significant increase in the 1P resource number - reserve number in the foundation fields. The other pillar is obviously driving our costs as low as possible and Oil Search already -- in our fields in PNG already starts from a very good base with our costs being in the lowest quartile globally. Importantly, our expansion of our gas fields aren't Greenfields development, they are brownfields expansions especially with greater integration. So PNG's competitiveness is even going to be greater going forward and I'll talk about the importance of that with respect to global markets. I'll also cover the strategy linked to our exploration and just how in Oil Search over the last 18 months, we've really consolidated exploration and our gas strategy into one uniform strategy. As everyone is aware, we had an obligation in the first half of 2016 to undertake a certification process on the Antelope field as part of our PAC acquisition and a key driver for us is not only costs, but how we optimise PNG's resources. So getting the certification process was very important for Oil Search to undertake. We did actually offer to delay the certification process to the PAC, certify - to the PAC group of companies so that we could incorporate the Antelope 7 results. The results that you see up on the screen are totally independent of any upside that we may actually see in the Antelope 7 well and I'll talk about that in the next slide. 9

10 The results of the certification process were not surprising, but they were also very pleasing in the sense that they strongly supported where Oil Search was at with their own internal expectations. I suppose some points to note which I'll highlight on the screen is that the 1C resource ranged from 4.8 for Netherland Sewell to 5.53 with Gaffney Cline, averaging The 2C ranged from 6.06 for Netherland Sewell to 6.8 with Gaffney Cline, averaging The 3C ranged from 7.57 for Gaffney Cline to 8.11 for Netherland Sewell, averaging 7.8. It's interesting to note that the significant timing of the reserve range for the Gaffney Cline who have really been involved since 2011 and so the confidence between us is really reflecting the additional six wells and the long-term production test that was conducted earlier this year. All the information was incorporated by the certifiers in those results. Importantly, as I've said previously we now have over 6 tcf of 1C and 2 tcf of 2C between Elk-Antelope and P'nyang, which is sufficient to underpin the financing and the LNG marketing for two additional LNG trains. The additional near term addition - additional near term gas potential will also occur in the next few months with the drilling of the Antelope 7 well, not only Antelope 7 [unclear] the field to the west, but also Antelope Deep, which will be a new prospect we've identified underneath the Antelope field. We're also planning on drilling Antelope South and I'll talk about that in the next slide. So what you see is the potential to significantly increase above what we already have in the table shown on the slide. What I thought I'd do here is really a lot of people talk about why haven't we included Antelope 7 previously and I think it's probably [unclear]. So this is the seismic line over the Antelope field and you'll see a number of wells drilling on the back limb of Antelope. Antelope 7 is going to be drilled right in this diffused area so what we have here is quite a range of potential fault margins extending to the west. So depending on where the fault lies, really it will be predicated on the - the results of Antelope 7 will be predicated on where the Antelope 7 lies. So importantly, our resource estimate does not consider the field extending as far as Antelope 7 and Antelope 7 represents upsides in the resource estimate. Antelope Deep will be drilled in this structure here which sort of underlies and to the south of the Antelope field and you can see the concentration of the Antelope wells on the eastern limb of the Antelope structure. So as I've said Antelope 7 will really constrain the western extent of the field and we've already identified some additional upside for the field going forward. This slide here, it's an interesting one. There's been a lot said and probably the greatest number of questions by investors and analysts are exactly what are the savings in an integrated project. What I'll go through here is where we currently see it. But importantly all the parties, like ourselves, Exxon and Total have all undertaken independent studies and during the course of the relationship we had with Total during the IOC bid, we were privy to what we saw from Total. Importantly what we saw from Total was very consistent with our expectations, hence the alignment of our proposal to InterOil. Importantly, the integration will result in material cost savings not only in CapEx where we see somewhere between US$2 and US$3 billion of potential savings alone at the downstream LNG facilities by the removing of the need of duplication and sharing of the site space, existing infrastructure, storage, jetty utilisations, basic utilities and power and metering options and control centres. That's really shown on the slide here which is the duplication that you don't need to do when you have a brownfield expansion compared to two separate independent greenfield developments. In addition to the basic CapEx reductions, basic is probably the wrong word for US$2 to US$3 billion, but savings will also be achieved in annual OpEx of over US$100 million a year, the removal of duplications, the total amount of owner's cost, improved financing, third party contract optimisation amongst others. 10

11 So we've also - to validate our estimates and also prepare ourselves for negotiations with both InterOil - with InterOil, but with Total and Exxon, we also got an independent expert to go through and look at all of the regional fields, Queensland Northwest Shelf and other regions to understand where synergies weren't captured so that we could actually guide our discussions to ensure that we're being realistic. It's also important to note that third parties risk were also estimated for project synergy savings in the order of US$5 billion for the PNG project over the life of the field. So we're very comfortable for where we currently sit with our CapEx estimates, but also where we're preparing ourselves as part of our strategic refresh for the negotiations with both Exxon and Total coming ahead. Our estimates are currently being fine-tuned as part of the strategic refresh and we'll be able to provide more detail on that in the next presentation. A lot has also been asked about what commercial models will be used to deliver the project integration and frankly it's just too early to give you a definitive answer. But there are a number of potential models that will occur and some of these are highlighted on the slide above. But the intention is that immediately post the finalisation of the InterOil transaction with Exxon is that all the parties will get together in October to begin those discussions and negotiations on how we best integrate the projects and also what commercial models may be used to support integration. Based on the currently defined resource we will be looking at two firm additional trains, now just to PNG LNG underpinned by Antelope and P'nyang and to achieve this the commercialisation options range from full unitisation of the upstream fields, new downstream infrastructure with a tariff paid to the host facility. The second option may be completely separate upstream projects, a new downstream infrastructure with a tariff paid to the host facility. Or the third option may be separate upstream projects with host facilities investing in new downstream infrastructure and receiving a material tariff or a combination of those. But all of those options are proven - have proven analogues globally. Importantly, all of them given Oil Search's position in both projects will have a very strong role in facilitating an optimal outcome for ourselves and for the PNG government. Importantly, there are a number of successful analogues as I've said to this and some where Total and Exxon actually work together in Qatar for example. Other examples being Trinidad and Egypt. When you combine the commonality of the ownership, the CapEx and OpEx structures with the financing and potential for expediting development, there are a large number of common drivers that align the LNG developments in PNG. This is a very indicative and I'll express again a very indicative and preliminary timetable for integrated development, but again it's a very common question raised by people in meetings. What we're looking at here is that a very strong focus for the joint ventures is really confirming the upside in and around both P'nyang and the Antelope areas through the drilling of Antelope 7, Antelope Deep, Antelope South and Muruk and potential appraisal drilling in the P'nyang area to confirm the final design. Following discussions on integration between the parties we believe that FEED will commence in early 2017, targeting and FID decision in late 2018, which will lead to first gas in late 2022, early Given the confidence on the underpinning resource base which as I've said on the previous slide we now have over 10 tcf of 2C and 6 tcf of 1C, we believe that there's enough confidence to actually commence early and quite material early works in PNG and that actually may lead to an expediting of the schedule. The other important point here for everyone to remember is that through the integration of PNG LNG with Papua LNG, it really is a brownfield expansion of an existing facility rather than a completely new greenfield project, so again we see the potential for shortening construction periods. 11

12 We've put up a very general supply/demand curve for global LNG. You've got the bears in the market and you've got the bulls in the market, but what we talk about there, that there are very clear, some commonalities between all of them. I'll just go through the commonalities and why PNG LNG is so well placed to position itself to meet the, what we see as a significant demand shortfall or a supply shortfall, early to mid in the next decade. All of the forecasters quite clearly predict that LNG demand will increase by 2 times, by double by Exxon in a recent investor conference were also quoted as saying that there's doubling of the LNG demand by Post 2018 there are also a number of LNG projects and long-term legacy projects that will be coming off plateau to the tune of about 80 million tonnes per annum that will need to be replaced as those older fields mature. What we also see is there's an additional 150 million tonne shortfall to be acquired to meet the 2030 shortfall. So what we see is whilst there are a number of new and material gas provinces, there are few, if any, as low cost or as mature for developments as PNG's brownfield expansion. Accordingly, PNG is really well placed to capture this market share to underpin expansion in PNG in the next decade. This is the final slide I'll show in relation to Ian's pack on gas. This is a demand growth slide for our quality Asian markets where PNG's product primarily goes. What we're doing, we're very confident that with the new LNG projects and expansion projects in PNG, that they're coming on to the market at exactly at the right time in the mid to early - early to mid-part of the next decade, to meet the clear increase in demand in the region. In addition, as I said before, more than 80 million tonnes of existing Northeast Asian LNG contracts expire beginning, as you are aware, on the Northwest Shelf, later this decade and there are a number of also maturing projects in the Southeast Asian region. With PNG's close proximity to the quality markets, our quality product, its quality JV, with Total and Exxon being Tier 1 companies, the supply of our product over the last two years, and the quality and its penetration into the market and, most importantly, our existing lowest-quartile position, plus the ability to drive it lower, it makes PNG's expansion very, very globally competitive with other potential new supply. With Exxon Mobil's acquisition of InterOil, it significantly enhances our likelihood of material integration with PNG's competitiveness so, which combined with our resource appraisal program, it provides a strong - solid growth for Oil Search's PNG LNG program going forward. So I'll now hand over to Keiran and exploration. The exploration program, frankly, since we began in 2015, with the lower oil price environment, has really been about rebuilding our position in PNG to support our long-term growth. What we did last year, as you've seen in our presentation, is that we undertook a country-wide study where we identified that there's significant remaining potential in the country, with the view that there's somewhere between 5 and 7 billion barrels of oil equivalent remaining to be found in PNG. We estimate, of that 5 to 7 billion barrels, probably 90% is gas. What we've done then is that over the course of the last 12 months, we've systematically gone about picking up and making acreage applications with the government. We've done a number of farm-ins and I'll talk about those. We've really targeted a program around how do we actually support the PNG LNG and Papua LNG expansion projects, not only four trains but well and truly growth beyond that. Our 2016/'17 programs are now firm and we'll be targeting somewhere about 6.4 tcf of unrisked mean prospective resource. That'll be spread over three geographic areas in the Gulf, the Foreland and the northwest part of the foldbelt. 12

13 You've seen these slides before so I'll go through these quite quickly, but Muruk is now looking to spud in the first week of November. Now we're fully - the rig's fully moved to the site, we're about 98% stocked and so the rig is literally ready to drill and it's just waiting for the drilling crew to come off Strickland to actually spud that well. That well is operated by Oil Search and we're currently 50/50 with ExxonMobil in that location. What we're also looking at doing is that in 2016 we undertook a lot of seismic in and around the prospective areas near Hides, near P'nyang as well, and we've identified three new potential structures, all of them potentially multi tcf fields. That's actually straight off the press and we'll present that towards the end of the year. That has a big impact in regard to the remaining prospectivity in and around the existing fields. P'nyang we have a drilling program and a well-planning process for next year. That well is designed to reclassify 2C to 1C. As everyone's aware, Exxon markets 1C resource rather than 2C and so that's really just confirming that with a possible second well. The second well is about firming up at 2C volume. The next slide just shows you the quality of the potential upside opportunities in and around the Antelope field. This is the high resolution gravity map, Antelope fields here. These gravity highs, and what you see is this is the Antelope feature here: Antelope Deep, Antelope South coming down. This is the Kalangar well. So what we're doing is it's really following along trendology from Antelope. All three of those wells will be drilled within the next 12 months. So we'll be testing somewhere between 2 to 3 tcf of mean prospective resources in that area. So my final slide really is what we've done about systematically enhancing our portfolio in PNG to support gas growth. We've pulled back on all of our international activity during the low-cost environment. Really PNG is where we've really brought back to farm and re-build our portfolio for the future. So we've made 15 new license applications. We've identified additional new areas that have significant upside potential. We're currently in the process of having discussions with all parties with regard to potential farmings. What we've also done is we've found out our high-risk areas and areas where we've had over - too large a commitment. So we've brought in Total, Exxon is currently expressing interest and there are a number of other parties who are talking to us as well. We've also upgraded the potential in Kimu, Urama and Barikewa quite substantially. In one of the fields we've had to upgrade the potential resource sales about five times. So our program is all about supporting PNG LNG. It's about supporting the pathway to the additional trains and actually drilling that activity in a timeframe that can be considered for an FID decision. So our plan is subject to oil prices, looking at high-quality wells, somewhere in the order of four to six over the next few years. So I'll finish there and hand it over to Peter. Peter Botten: Thanks Keiran. I'll just finalize my piece by touching on the strategic review, the refresh post InterOil and then follow it by a summary. As most of you are aware, the Company undertook a major review of our forward strategy in 2014, following the successful commissioning of PNG LNG and the significant downturn in oil and gas prices, along with a re-calibration of capital and development costs. This review reiterated the potential to more than double our production base, highlyefficient, high-returning production base, through the expansion of LNG in PNG over the next five to seven years. All of that had the potential to deliver and continue to deliver top quartile returns to our shareholders. Given recent trends in energy pricing, the near-term increase in LNG supply, the deferral of various LNG projects, FIDs around the world, other PNG related issues and, of course, now the InterOil ExxonMobil transaction, we thought it was very appropriate to refresh our strategic outlook and associated initiatives, focusing on the details of how a possible 13