Company: Oil Search Limited Title: Oil Search Half Year Results Date: 19 August 2014 Time: 11:00AM AEST Conference ID: Start of Transcript

Transcription

1 DISCLAIMER: Orient Capital Pty Ltd has taken all reasonable care in publishing the information contained in this document; furthermore, the entirety of this document has been approved for release to the market by the participating company. It does not purport to be complete. The information contained is not intended to be used as the basis for making any investment decision and you are solely responsible for any use you choose to make of the information. We strongly advise that you seek independent professional advice before making any investment decisions. Orient Capital Pty Ltd is not responsible for any consequences of the use you make of the information, including any loss or damage you or a third party might suffer as a result of that use. Company: Oil Search Limited Title: Oil Search Half Year Results Date: 19 August 2014 Time: 11:00AM AEST Conference ID: Start of Transcript Rick Lee: 2014 half year results. My name's Rick Lee, I'm Chairman of Oil Search. I have up here with me Peter Botten, our CEO; Stephen Gardiner, on my left, our CFO; Paul Cholakos, EGM Production and Julian Fowles, EGM Exploration and Development. So between us we hope to inform you about what's happened over the last half year, which you've seen on the releases, and also give you our thoughts on the periods ahead. Also obviously open the floor to questions and to questions coming from those who are listening in on the webcast. So over to you, Peter. Peter Botten: Well ladies and gentlemen, thank you very much for attending the Oil Search 2014 half year results. What I'm going to do today is obviously a disclaimer and I'm going to give the introduction. Following that, Steve Gardiner will give the financial overview. Paul Cholakos will give you an update on PNG production oil and LNG. Julian Fowles will then give an update on gas growth and exploration and I'll round out with a summary and outlook, including some comments on the status of the strategic review. So that's what we have and following the presentations we'll open up to people from the floor for questions and people over the phone as well for questions. So thank you, as I say, for coming along. Obviously undoubtedly the highlights of the last few months and the first half as a whole has been the successful commissioning of the well scale PNG LNG project. It's now at full production from both LNG trains. A remarkable achievement in smooth commissioning coming in ahead of schedule and potentially marginally below its revised budget. This project obviously will change - indeed already has changed - PNG and Oil Search forever. It represents a huge opportunity for the country to lift the living standards of the people of PNG and for Oil Search it provides the platform to further build our business, commercialise our significant further gas resources and reward our shareholders through further capital appreciation and higher dividends. It is a landmark for us, it's been many years in the making, but it actually happened with production starting in March of condensate and then LNG in April and May and a very rapid commissioning process of around three months to where it now sits at full production. Total production for the half year then was impacted by condensate and LNG and production was around 5.4 million BOE, up 68%, driven by obviously LNG and continued solid performance from our oil business in Papua New Guinea. That drove a net profit after tax up 34% to US$152.5 million and the dividend announced by the Board this time is unchanged from the previous corresponding period at US$0.02 per share. I'll discuss that a little later on. A major acquisition took place by Oil Search in the first half and that involved the acquisition of interest in the Elk/Antelope gas fields, representing what we believe to be the largest undeveloped resource presenting in

2 Papua New Guinea. The appraisal program on Elk/Antelope is due to start in the second half of 2014 and preparations for that drilling program are already well underway. As well as that, given the present situation and our upside, we have very substantial further growth potential in gas in Papua New Guinea and we did spend some time in positioning ourselves for the next phase of gas development, and I'll describe that a little later on in the strategic section later in my discussion. We've also seen very encouraging results from the Taza appraisal program in Kurdistan with substantial shows. It is an appraisal well on the Taza field, Taza 2, and it confirmed the northern extent of the field as being oil bearing, with a substantive potential oil column identified in Taza 2. Unfortunately the testing program has been temporarily suspended due to the fact that we actually are struggling to get some of our supplies into that area, although security in the area is actually pretty good. Some of the supply chain areas need some work and to get the relevant testing material on site is a challenge for us right now, but we're confident that we can overcome those challenges in the coming weeks. We also have done a lot of work on the strategic review. The strategic review in the past has provided a template for us to look at and drive our business and drive our value. This strategic review is probably the most comprehensive we've carried out and looks at the next five to seven years of potential growth and how we can optimise our assets in Papua New Guinea and elsewhere, how we can use the transformational cash flows that come from PNG LNG in high returning projects, but also to reward our shareholders through higher dividends. It is a substantial piece of work which we will roll out to the market sometime in late October and does highlight the potential to continue to provide our shareholders with superior top quartile returns and higher rates of dividend, as well as supporting the substantial growth projects into the future. If I look at our total shareholder return over a one year, three year, five year and 10 year period, it I suppose demonstrates the platform that our strategic reviews in the past have given us, has given superior returns. On a one year basis our TSR was 25.7% versus a 16.2% TSR in the overall median on the ASX200. If you look at a 10 year view to 30 June, a 752% TSR, well above obviously the overall market average. Safety remains an absolute key prerequisite of our business and measured in one measure the total recordable injury rate of 1.86 for the first half of 2014 is substantially lower than the 2.5 we recorded on average for 2013, and moves us back towards the international standard from offshore oil and gas companies in OGP and substantially better in terms of our Australian colleagues who perform, I think, well below that level in terms of injuring people. Clearly anybody injured on site is not acceptable to us and we work towards incident free operations, both for our physical safety of our individuals but also in process safety and maintaining competency within our plant. Given the diversity of our workforce, the type of activities we're doing in particularly high strain, that safety result we think is a good one, but we can do better. Coming back to the importance of long-term strategy, predictable open and transparent strategy, you can see that the performance in share price growth over many years, the 10 years or so, has delivered substantial long-term performance and value-adds to our business. We believe we can now continue that trend for another five to seven years with substantial identifiable projects in our portfolio right now, and I'll 2

3 come back to that a bit later. Again, just against some of our peer groups we've not done badly and this is an August to August number. Let me throw it over to Stephen Gardiner, who will now provide you with the financial results and overview. I'm sure he can answer your questions at the end. Stephen Gardiner: Good morning ladies and gentlemen, pleasure to be here, particularly being able to speak to these numbers. Looking at the first slide you'll see the number of green arrows in the upwards direction, that's always a good sign to start these sorts of presentations. With the first half headlines clearly we're already showing the transformational impact of the PNG LNG project on our financial performance. The early start-up of the project in late August helped deliver a 34% increase, not only in our net profit after tax but the revenues that underpin that profit. We delivered a net profit after tax of US$152.5 million, supported by the delivery of five LNG cargos and 390,000 barrels of LNG kind of late sales. The bottom line LNG impact was muted though by the timing of LNG cargo deliveries, with two cargos on the water at the end of June and the fact that our LNG borrowing costs and our operating costs were fully expensed from late April, while production was still in the ramp-up phase until July. The result also benefited from a strong contribution from our oil business that Paul will address in a minute, with oil production up 8% on the prior period, reflecting excellent results from recently drilled production wells. Operating cash flow grew by 90%, again lagging earnings growth due to the timing of payments from our LNG customers. Despite the slower pace of PNG LNG capital spend, our total investment spend increased by over $550 million on the prior half, due to over $900 million being outlaid for the PRL 15 licence interest. Cash earnings performance was boosted by higher realised oil prices and strong initial LNG margins. The average realised oil price for oil in condensate sales was $ per barrel, or $3.25 higher than the prior period. The average realised LNG and Hides gas-to-electricity gas price of $14.20 per million Btu was pleasing in the context of the softening trend in regional spot LNG prices and again confirms the appeal PNG LNG has as a product for our Asian buyers. The strong PNG LNG cash margin at 83% includes shipping costs for the spot LNG cargos delivered to date. Assuming stable oil prices, the PNG LNG margin will improve from this level in the second half. As mentioned, we're now at full capacity, we'll get the full benefit of spreading those operating costs against that full capacity. In addition, you'll see the long-term sales contracts coming into effect in the fourth quarter of this year, which also will improve the overall margin contribution. Looking at the P&L in a little more detail, costs of production increased by 9% on the prior period and noncash charges more than doubled, both due to the commencement of PNG LNG production. Exploration costs fell by more than 50% on the prior half, down to $15.4 million, largely consisting of seismic, G&G and admin costs. No exploration wells were written off during the first half, given the greater focus on appraisal drilling. The large increase in financing costs in the first half was due to PNG LNG borrowing costs no longer being capitalised from late April, when first LNG production commenced. Tax expense for the first half of $125 million equated to an effective tax rate of 45%, below the 50% statutory rate for oil operations in PNG, mainly due to the taxation of PNG LNG income at 30%. The effective tax rate will define further in the second half as we increase proportion of PNG LNG income in our total income mix 3

4 and also due to the conversion of the Kutubu complex oil field to a gas field for tax purposes from 1 July this year, meaning that oil production from this field will be taxed at 30% going forward. Overall total costs of production increased by 9% due to higher oil field costs and expensing of LNG operating costs as I mentioned for the final 10 weeks of the recording period. Compared to the first half of 2013, PNG oil and gas field costs increased both in absolute terms and to a lesser extent on a BOE basis, reflecting additional labour costs to support reliable production of associated gas as well as oil and ongoing work to ensure the long-term operability and safety of our mature oil and gas field facilities. As previously noted, PNG LNG unit production costs were inflated by a relatively fixed operating cost base being spread over production volumes that had yet to reach full tank capacity. LNG unit costs were reduced in the second half, now that full production has been achieved. The negative inventory adjustment captured the production costs for LNG in the plant storage tanks and in the two cargos that were in transit to customers at the end of June. Those costs will be released to the P&L in the second half as the LNG is delivered to buyers. Turning to cash flows, our PNG oil and gas operations continue to deliver material cash to the business, which in the first half was supplemented by $51 million of receipts from LNG payments from both our LNG and condensate customers. Financing investing cash flows in the first half were dominated by the $900 million invested in the PRL 15 licence. To fund this and associated CapEx programs $1.1 billion of shares were issued to the PNG Government, with a further $171 million raised through a share purchase plan in the second quarter of the year. Surplus funds from the share issues enabled us to pay down $150 million of corporate debt, offset by further drawings under the PNG LNG project finance facility of $260 million, which included $77 million to fund interest payments. Our share of cash in the secured LNG proceeds accounts totalled $51 million at end June. By the time the project reaches its financial completion, now expected to be in the first quarter of next year when sales proceeds net of operating costs and debt service income start to be released to the project participants, our share is forecast to be in excess of $700 million. The share issues, the early start-up of the project and increased committed undrawn funding lines delivered a substantial improvement in our liquidity position. During the first half we established an additional $250 million of low cost revolving credit lines. When added to the undrawn $450 million available under our corporate facility and cash at $368 million, our total liquidity currently sits in excess of $1 billion. We've now drawn just over $4 billion under the LNG project finance facility to fund project construction costs and capitalise interest. Our remaining 30% equity contribution for capital costs is now less than $160 million. As Peter mentioned, the Board has approved a 2014 interim dividend of $0.02 per share and the dividend again will be funded by an underwriting of our dividend reinvesting plan. On the investment front, our full year capital expenditure is forecast to be around the $2 billion mark, including the PRL 15 licence costs. We are forecasting a lower 2014 spend than previous guidance on the PNG LNG project. That's due to the early production start-up, exchange savings and foreign exchange movements, reduced utilisation of contingency funds and some spend phasing issues, with spend flowing 4

5 into 2015 as the project continues to spend money on the Angore and Hides Deep pooling campaign and construction of some office facilities in Port Moresby. The exploration forecast includes expenditure on PRL 15, appraisal wells and ongoing appraisal drilling and 3D seismic acquisition in the Taza block in Kurdistan. As Peter has mentioned and Julian will cover in a bit more detail, the Taza spend could be impacted by security developments in the region. Finally turning to the full year guidance, the guidance does incorporate the impact of the early achievement of LNG production at full capacity. The production outlook for the full year has been tightened to 18 million to 20 million barrels of oil equivalent, given the largely trouble free LNG production performance to date, with the caveat of course the project continues to remain in that state. The contribution from our oil field is also likely to exceed original expectations. The operating cost guidance ranges are unchanged from the mid-year guidance, although for clarity we've confirmed the guidance to the way we now present cost information in our financial reports. So it's a very positive outlook and on that note I'll hand over to Paul to cover the operations side. Thank you. Paul Cholakos: Thanks Stephen. Look obviously the most significant event for us on the first half has been the start-up of PNG LNG. Commissioning of the pipeline facilities had commenced last year using Kutubu gas. That continued until the start-up of the Hides gas conditioning plant in March of this year. With the startup of the Hides plant, condensate production was delivered and blended at Kutubu and export of that Kutubu Blend has commenced through our PL to export system and has been ongoing since April. Production of gas from Kutubu also commenced in April and I'd like to take the opportunity today to thank everyone who has been involved and helped Oil Search in successfully delivering that gas safely and ahead of schedule. The first LNG shipment, as you know, was loaded in late May, both trains at the LNG plant are now running at full capacity after a three month ramp-up and as previously advised, the project is expected to come in within the revised $19 billion budget. There is some ongoing development work, but it's minor. It's principally around drilling and development drilling. Six of the eight Hides production wells are now complete and operational. Flow rates from those wells have been very pleasing, just confirming the quality of the reservoir and productivity at Hides. We've previously advised that the first of G wells in the north west of the Hides structure has encountered gas bearing reservoir as expected. The second G well is nearing completion, as is the produced water well and data from those two wells will provide greater certainty around the Hides structure and volume. The results to date have been brought in line with preview models. There are two wells remaining to drill on the Angore structure and the first of those will spud in the second half of the year. There's also the Hides Deep well which will spud in the fourth quarter, and Julian will talk about that shortly. As we've already said many times, PNG LNG has been delivered ahead of schedule. Given the pressures on projects in this region over the last several years, it's quite a remarkable achievement and in fact unique in the region, and once again we'd like to congratulate the project team on that achievement. Some of the key things in delivering that were the commitment to early works to make sure that supply chains were opened 5

6 up and that work fronts became available. The other key was the ability to pipe clean gas from Kutubu to commission the new build facilities, the pipeline, the LNG plant and the Hides gas conditioning plant. I think I've hit the wrong button here, apologies. Thank you. A photo many of you will have seen, this is the Spirit of Hela taking the first LNG cargo to TEPCO and that departed in May this year. As Stephen said, in the first half seven cargos were shipped and five were delivered. Sales under the long-term contracts will commence through the second half of the year. So all of PNG LNG facilities are now complete. This slide just shows some of those facilities, from the upstream Hides gas conditioning plant, the associated gas facilities at Kutubu, the LNG plant and a tanker at the jetty. Production in the first half obviously benefited from the early start-up of PNG LNG, which contributed just under 1.9 million BOEs to our production. Obviously the production in the second half from PNG LNG will be materially higher, with the project now having reached plateau production levels. Stephen also mentioned that our operating production performance has been strong. In the first half operated oil production was 2.8 million barrels, 8% higher than the corresponding period last year. As we expected, the start of our gas deliveries from Kutubu to the PNG LNG project has not impacted oil production and we continue to see strong contributions from the Kutubu and Moran fields in particular and from some of the wells that we have drilled recently. One of those wells is the Agogo 7 well. It's the third well on the Agogo forelimb structure. As you can see from the section, a very structurally complex opportunity to model and it was a challenging well to drill, but very pleasing to be able to say that that well did encounter oil in both the Toro and Digimu reservoirs. Initial flow rates during commissioning of that well have been above 1000 barrels of oil per day. This just demonstrates again that we continue to see upside around our existing operations and those opportunities are highly value accretive. Our focus in the second half of the year remains on safe, reliable production of oil and gas. The ongoing supply of gas from Kutubu and Gobe and the export of Kutubu Blend via PL2 will continue to be key contributors to the success of PNG LNG. We have ongoing drilling programs, with two wells being drilled at Usano through the second half of the year. Julian will talk about one of those later. Finally to our production outlook, as Stephen mentioned we've narrowed our full year production guidance to between 18 million and 20 million BOEs, reflecting the de-risking of PNG LNG start-up. Included in that is a slightly increase in our operating production guidance to between 6.5 million and 6.9 million barrels, following the strong first half performance will be the first year of full year contribution from PNG LNG and that will contribute approximately 21 million BOEs to our production base. I'll now hand over to Julian to cover the gas growth and exploration. Julian Fowles: Thanks very much Paul and good morning ladies and gentlemen. As Peter has outlined, I'll talk about gas growth and also about our exploration and appraisal activities across both PNG and internationally. So first of all looking at gas growth, strategically what Oil Search is doing here is looking to 6

7 focus on aggregating gas resources, really with the objective so that we can underwrite additional LNG. We've got LNG obviously that's coming from PNG LNG project already started and we'll be looking too in areas that we can expand that and potentially enter new LNG projects. I'll talk a little bit about some of these areas, so first of all in the North West Highlands I'm going to talk a little bit about P'nyang. I'll also talk - give a brief update on where we are with the Deep well at Hides. I also want to cover what we're doing with the gas resources that we see in this gulf area, where as Peter mentioned we've entered the Elk and Antelope resource. Fundamentally Oil Search is really well positioned in these areas. We're really well positioned because of our operating experience, because of our ownership of gas resources, as well as our ownership of existing infrastructure. So we're really well positioned to add value through resources and additional projects for future development. So first of all, a brief update on P'nyang. You've seen some of this before. P'nyang in PRL 3, it sits about 120 kilometres to the west of Hides. It's a resource that we appraised in 2012 with the P'nyang south well, that was very successful. What we're looking forward to with this project is that this will be a key underpinning resource for expansion of our PNG LNG project. The concept select work with the operator, Esso is already well advanced, both in engineering work and on the environmental and social side of things and we're looking to submit a development application early in Eventually you can see it sits here and Oil Search holds a substantial proportion of the P'nyang resource. Some of the acreage around this I'm going to touch on a little later on in the presentation, acreage that we've entered to - again as part of this aggregation strategy to develop more resources. If I touch on Hides now, the Hides Deep exploration well, we've talked before about the potential of the Koi- Iange reservoir, this is a reservoir that sits some 700 metres below the Toro reservoir at the Hides field and you can see in the cross section here it's outlined in the deeper part here. The Hides Deep exploration well will be a deepening of the Hides F1 development well. The site is already complete, we're looking forward to spud this well in the fourth quarter of this year. The actual location of the well pad itself, it sits up here towards the top end of the structure between Hides 1 and the G pad well, which is where we currently have some ongoing drilling. Hides Deep has significant resource potential. The Koi-Iange reservoir is one that hasn't been penetrated before at the Hides field. We see significant potential there for expansion of the resource base that we have at Hides itself. I said I would talk about the expansion that we're looking at in terms of our gas acreage holdings in the North West Highlands and this really touches on three areas. So around the P'nyang area we've picked up a licence PPL 464 in conjunction with Esso. We've also entered a conditional agreement to enter PPL 402. We'll take 100% of that. We've also entered an agreement with Mitsubishi to enter with a small interest in PPL 269. So these are subject to ongoing and also future work that we plan to do there in terms of seismic. PPL 269, for example, already has a seismic program going on there with the operator, Talisman and we plan further seismic in the other acreage that we have around 402 and I'll show you a more close-up picture of that in a minute. Drilling is possible in these areas in late 2015, so potentially this is a resource that we will be able to see what it really contains in a relatively short timeframe. So we're already third quarter of 2014, there's more 7

8 seismic to acquire, that'll be interpreted and move on to potential for drilling. So this is really seeking to identify additional resources in this area that'll support further expansion of LNG, further production of LNG. I said I'd look in a little bit more detail at that PPL 402 in Greater Juha area. So Juha sits to the west of Hides, about 30 kilometres west of Hides or so, where the Juha discovery or resource already that sits within PNG LNG. There's the Juha North discovery that was through Juha 4 and you can see that in this cross section here. The Juha field itself sits here and just to the north east of that we have Juha 4, which discovered the Juha North resource. Gas is proven in these areas but there's a significant potential upside, both at Juha North and in the related areas that we see continuous with this. So up into the 402 area and we have a seismic program that is planned for later this year that will address the potential resource and potential drilling candidates in that area. We've already undertaken some seismic in that area and that'll be going through a second phase as we go into the fourth quarter this year. So moving away from the Highlands now, we come down into the Papuan gulf area and as Peter has mentioned, we acquired a 22.8% interest in PRL 15 earlier in the year. That contains the Elk and Antelope fields here that you can see. This is the largest undeveloped gas resource currently in PNG and it's got great potential for significant exploration upside within the licence itself and will clearly be the underpinning of a new LNG project. The acquisition is really in line, as I've said before, with our overall strategy to acquire additional gas resources. As you're all aware, we're currently in an arbitration setting with Total over the sale of the interest from InterOil, the operator to Total. That's scheduled to go to the arbitrators in November this year and probably in the first quarter of next year we'd anticipate seeing a result from that. If we're successful there we do anticipate that that would add substantial additional potential to our own aspirations as gas owners and LNG producers in PNG. The appraisal program that we have around PRL 15 at the moment, that's still continuing. So if you like, the arbitration is to one side and with the operator, we're pursuing quite aggressively an appraisal program on PRL 15. We're looking at up to three additional appraisal wells to be drilled. These are really being drilled in order to determine whether we're looking at a one train or a two train development. So it's really around seeking the confirmation of upside at the Antelope field. Antelope 4 and Antelope 5 are both currently very well defined and we're expecting those to spud in the third quarter this year and those will undergo very comprehensive data and testing programs. It's possible that we'll also look at an Antelope 6 well and Antelope 6 would be situated to the east of the field. So Antelope 4 is to the south and Antelope 5 to the west and that'll really start to triangulate the sort of resource that we have at the field itself and allow it to be very well constrained. So that's the idea with that. We're also looking to the south of Antelope at this prospect here, Antelope Deep and that's a potentially large resource. It's deeper, as you can see from the name, it's deeper than Antelope itself. It's potentially very exciting and we're already well advanced in the planning for that well and we'd hope to see that being drilled in 2015, in the first half of We're also working with the operator on scoping out Concept Select studies 8

9 and what those studies will include, and that's currently being considered and there's a number of different options that we're looking at around there. I'll move on now to the exploration side of things. What I intend to cover here is a little bit of exploration, some updates around PNG itself, what we're doing there with oil and then I'll look at the international side of exploration and that'll focus on Kurdistan and on our operations at Taza. So I think Paul showed you earlier on an Agogo well. This is equally complicated, the Usano-4 well. This is a well that's currently being drilled into a prospect that sits below the Usano accumulation. There's a forelimb prospect here and there's a footwall prospect in here. Some of the work our guys do is pretty amazing to be able to deconvolve really what the geology looks like in the subsurface. It's complicated work, it's highly technical, it takes quite a bit of time, but the results that we've seen to date, there's been some 40 wells that we've drilled since taking over operatorship from Chevron back in 2003, 40 development wells, and about 80% to 90% of those wells have been highly successful. So I've got to say these types of diagrams look extremely complex, but to some of our geoscientists this is what they work with every day and they have a very successful track record with it. So we're currently drilling this well, as I said, it's an exploration well, it'll tackle a couple of different plays in the forelimb and in the footwall. We see an additional prospect beyond Usano as well that looks further to the east of the field itself and that's something that'll be ready for drilling by the end of this year and we'll look to be drilled after the Usano footwall penetration. Mananda 7, just a brief update on Mananda 7. We spudded this well at the end of last year. It was designed to appraise the Mananda 6 discovery which lies to the south east of Mananda 5, Mananda 5 discovered up here. Mananda 7 defines the structural configuration of the Mananda 6 area. That was a little more complicated than previously interpreted, we're currently working through that to see what it means in terms of resources. What we have done though is the results of that well have enabled us to look more deeply at some of the other prospectivity in the area, a little better constrained now. What we're looking at is below this main structural combination at Mananda 6 and Mananda 7, we're looking down in this area here at what could be potentially quite a large and interesting prospect at what we're calling Mananda Deep, and that's something that we're getting after with a bit more work to evaluate that prospect and some other shallower prospects that also exist along that trend. We're looking potentially to be drilling a well there in 2015 to further appraise that overall Mananda structure. What's happening on the development side is we're working the results of the Mananda 7 back into the development options and what that looks like and that work is currently moving forward with some concepts and legwork. So I'll move away from PNG now and touch on where we are with our international exploration and appraisal work. This is just a map of the Middle East and North Africa, where we currently have our assets. So we have Yemen down here in the south, where we hold Black 7. We operate a block in Tunisia called the Tajerouine Block and also we have a block at Taza in Kurdistan in Northern Iraq. The international strategy that we have is primarily focused on operated oil opportunities, where those can add materiality and substantial potential to Oil Search. What we're looking to do is to leverage the long-term and existing 9

10 relationships we have in those regions in order to further develop that portfolio and to really build, if you like, a new hub in these areas in the oil arena for Oil Search. We're obviously using our existing skills base that we developed in Kurdistan and that's across both the community side of things, government regulation side of things, as well as our technical skills base that I've touched on earlier. The pace of any work here, of course, is dependent on opportunities and on the valueadd and materiality of those opportunities and that's something that's being addressed very closely in the strategic review, I think as Peter has mentioned. I'll talk mostly, as I said, about Kurdistan, but just to update you on Tunisia, we have a program of seismic that's planned to start there this quarter, about 300 kilometres of 2D seismic to further delineate an interesting prospect that we've identified, with potential that we would go forward and drill on that prospect. In Yemen things are a little frustrated, we're still in force majeure, we've got an extension on the licence again for a further 12 months and we're looking there again at fulfilling a seismic commitment. But we're also looking now in a little bit more detail at the existing wells at the Al Meashar discovery and what they may be able to do if we put those on a longer term test. Access to Yemen though continues to be difficult. So briefly on Kurdistan, our appraisal program here is a fairly comprehensive appraisal program. Taza 1, to date, the discovery well, we've set 10 kilometres to the north west of Taza 1 to Taza 2 and I'll talk in a bit more detail about Taza 2 in a second. We have drilled that to TD now at 4200 metres. We're preparing for Taza 3, which will be a further appraisal well that sits around six kilometres south of Taza 1. Then we have two other proposed wells to the east and west, Taza 4 and Taza 5 and those will be targeting specific elements of the Taza structure and some of those will be specifically targeting fractured intervals that we're able to identify currently on the Taza data that we've got, and that the 3D that we're requiring will better enhance. Our plan is also to install on one of these wells an early production facility to see how the reservoirs that we've penetrated, how they can produce and what they might look like in the longer term. We have an additional prospect in the Taza Block called South East Jambur. It's an extension or a continuation of the Jambur field that sits to the west of the main Taza reservoir. Taza 2 results, I've touched on some of this already. We observed in Taza 1 Jeribe, Dhiban and Euphrates oil. We've now extended that down into the Kirkuk, Jadalla and Shiranish formations, so it's around about 700 metres deeper than we got to in Taza 1. We've seen hydrocarbon shows and good oil indications through all of those at the moment and we have been moving forward to prepare for testing of up to five different intervals at Taza 2. Our current interpretations suggest that the reservoir intervals that we've penetrated are not particularly permeable. That's not that surprising in the Kurdistan context, these are limestone and a lot of the time the wells in Kurdistan depend on a good fracture network for their productivity, and that's what we anticipate that we will need to see at these wells, the appraisal wells that I've talked about already. We have seen fracturing - some fractures occurring in set in the Taza 2 well. We've seen that both through elevated gas readings and oil shows, but also some indications on logs as well and obviously those will be targets for any testing that we plan to do. 10

11 As Peter has already touched on, the security in Northern Iraq is at a fairly precarious level at the moment. We've taken the decision on Taza 2 that we'll suspend activities rather than mobilise a whole load of new staff requiring new things to be set up around the supply chain and key technical staff. Rather than mobilise those into the field for that, we've decided to suspend the activities prior to actually starting the testing work. We certainly hope that once we see a little more stability in the security situation and our supply chain is more secure, then we'd look at restarting those operations. So just a last slide to show you that there's also additional potential at Taza. So currently Taza 1 was drilled down here, just into the top of the Kirkuk. Taza 2 has extended that down through a number of different intervals, the Jadalla and the Shiranish formation, and we've seen, as we said, we've seen hydrocarbon shows in those. There's another potential reservoir that sits beneath that called the Qamchuka and a future well will be targeting that additional potential at Taza with a view to seeing if that contains hydrocarbons and if so, could that be produced. So it's a pretty exciting time for a number of reasons in Kurdistan, but certainly focused on the technical side of things we see great potential there and great upside. So if I can, I'd just like to hand back now to Peter, if I can move this on. There we go. Peter Botten: Thanks Julian. I'm now going to talk about the strategic review, summarise and look at some of the outlook issues for us. The strategic reviews that's going on right now involves a dedicated team of about 18 people who are looking at the future of the organisation. It will set the objectives and programs for Oil Search over the next five to seven years and it really does focus on how to maintain our top quartile returns to shareholders. It is a root and branch analysis of what we're doing and how we can do it with the existing asset set that we've got; the assets that remain in PNG to look at, as well as some international assets. So it is looking at the totality of our business, the way we can access value in those assets and the organisation to capture that value over the next five to seven years. The first emphasis, I should say, is how to optimise our PNG assets and the way to capture the full value of those assets and really that does come down to understanding the substantial gas reserves and resources that are in play in PNG, and how to capture the value in a capital and time efficient way. There is very substantial potential value identified with certainly multiple trains possible out of the assets that we have, and standing back and you look at Papua New Guinea at the moment, it is commercialised in terms of 2P resources, about nine TCF of gas. Total discovered 2P resource in PNG at the moment is about 14 TCF, of which just under 12 TCF sits within our portfolio. That's a substantial about of gas remaining to be commercialised and really it does represent an unprecedented platform for further growth. The next 18 months - 12 to 18 months, is really critical in how we can optimise bringing that gas together. We can see viable high returning projects, multiple LNG trains potentially being identified and underwritten by the discovered resource today. However how those trains come together, who owns them and how they are built is part of the analysis that is ongoing as our strategic review evolves and I think Julian said earlier on that the resource base that we have is significant. How we bring this together in an optimal way is part of the [brain] and the analysis that's being applied to the strategic review. 11

12 We're very comfortable that we see at least two more trains which have the capacity to more than double our production again from 2015 through over the next five to seven years. How we bring it together though in terms of optimise what is a good value proposition to a very good value proposition is part of our analysis that's taking place now. With that obviously comes ways to optimise our PNG portfolio and you've seen already a number of moves that we've made and will continue to make to further make sure that Oil Search is in a pivotal position to bring this resource to market, to commercialise in an optimal way. You'll also see a focus on managing the operating risk in PNG and I'll touch on that with a slide later on and also how we can optimise our non PNG assets and our various new venture activities balancing the investment in the high returning pieces of business that we can see right now with the various capital management initiatives that we obviously want to deliver to our shareholders in terms of dividends, potential buy-backs, capital management in a general way et cetera. All of that is part of a core large piece of business that I suppose the strategic review right now is probably about 60% 65% complete and we will be looking at rolling that out to the market in the last quarter with the strategy day planned for 23 October this year. It also will review the organisation succession plan and the right skills and people to drive this business to potentially as I say more than double our production base over that five to seven year period. A very substantial piece of work going on which will be the platform for our future programs and growth and transparency with our shareholders about how we can achieve further value creation. A key issue for PNG at the moment is obviously how it can manage this huge transition and impact of PNG LNG with the revenues that are coming to it and also to address itself to multiple developments potentially down the track in terms of further LNG expansion, further LNG growth and further LNG projects overall. It's vital that obviously that the revenues that are coming into PNG at the moment from the resources projects are well used and better used than in the past. Obviously that we wish to play a role in doing what we can to ensure that those revenues are used wisely. Certainly the establishment of the Sovereign Wealth Funds and the various governances processes that PNG Government are putting in place now it's very encouraging but there's still substantial work to do and we would wish to use our skills and resources and experience in helping Government through various private public partnerships. Assisting them in delivery and assisting them in terms of capital capacity building in making sure that these resources are used wisely and in a transparent way with all society seeing the benefits. It's certainly a key part of our future activities and one that is very complimentary to the growth targets that we've set for commercialising further LNG and our other resources in country. We see a very comprehensive program to manage and mitigate the operating risks probably more so than we've done in the past and that involves various initiatives including tax credit, infrastructure projects, our whole foundation and potentially further initiatives in education and capacity building as I've mentioned. The depths of programs that are on the table from this are subject to the strategic review as an ongoing piece of business. We have a very, very stable share register with strong support from IPIC as a new 13% shareholder and very strong support from the PNG Government with whom we work very closely especially on issues of sustainability within the country. This piece of business is an essential part and you'll see 12

13 greater emphasis of this into the future especially as we see such great potential value creation going on in our business over the next five to seven years. In summary the transformation of Oil Search and Papua New Guinea as a whole has begun. PNG project was delivered ahead of schedule and was certainly within the revised budget. It will see our total production increase over four times from 2013 to It does and needs delivering material cash flows to underwrite further growth but also provide a higher level of dividends and capital management for our shareholders. We see our existing assets having the potential to underwrite at least two further trains in terms of expansion and potential additional projects. How that comes together is a focus for us over the coming 12 months or so. The Taza discovery has a significant upside potential and we will move to testing Taza 2 and drilling Taza 3 as soon we can possibly do it. Our oil business as we've described remains extremely strong albeit less material than it has been in the past and with over US$1 billion of liquidity our balance sheet is strengthening very rapidly and thirdly can manage both continued strong investment in high returning growth projects as well as returning capital to our shareholders. I say the platform - the strategic review provides the programs and the platform for us to deliver and continue to deliver superior returns over the next five to seven years. In reality we have an unprecedented platform to further build value for our shareholders and provide continuing high returns to them and the strategic review will enunciate how we're going to do that and the organisation structure that we think can continue to deliver these sorts of returns. So with that thank you very much, that ends the formal part of the presentation now perhaps we could throw it open to questions from the floor initially around any questions you have on the results. John Hirjee: (Deutsche Bank, Analyst) Good morning. John Hirjee from Deutsche Bank. A question to Stephen if I may. In terms of the project completion for PNG LNG is there any chance of that being brought forward given the amount of cargos that you're now delivering and the operation performance of the project? Stephen Gardiner: John the key driver of the timings and completion and operability test where the plant has to run for 120 days with fairly limited interruption during that time period we understand at the moment they're probably just getting ready to commence that test. Probably it's likely to commence in September so that takes us through to the early part of next year just to complete that test and we understand at that point various other elements of the completion process will also be completed. So we're hopeful that we will achieve that financial completion sometime early in John Hirjee: (Deutsche Bank, Analyst) Okay thank you. Another question if I may. In terms of the current spot cargos that are being sold into the market could you elaborate on the pricing that you're achieving for those? Is it a spot price or is it a better than spot price that you're currently achieving? Stephen Gardiner: Sure it's a spot price but obviously we're selling most of the cargos to our customers who are very keen to - our long term customers that have the long term off take agreements. They're very keen to access these cargos so I think they've paid probably what you're seeing is a better price than the average trend for spot price in the region. Peter Botten: I think you can see that in our quarterly report which highlighted that pricing. 13

14 John Hirjee: (Deutsche Bank, Analyst) Thank you. Dale Koenders: (Citigroup, Analyst) Hi. Dale Koenders from Citigroup. Peter, you've previously spoken about a targeted payout ratio for dividends of 30% to 50% but given the focus of today's presentation on growth of LNG is that still a target or is maybe growth more of a focus? Peter Botten: No look I think obviously the final payout ratio and prices is subject to the strategic review and the Board's review of the strategic review. But at the present time we see that our payout ratio in that 30% to 50% can be absolutely managed with our growth objectives and we see no change to that. In fact it can be very well managed based on present forecasting of cash flows and expenditures. Dale Koenders: (Citigroup, Analyst) In terms of sort of the go forward covering the costs for these growth assets do you have a target for gearing or perhaps targeting investment grade credit rating going forward? Peter Botten: Look I think that those questions are probably better answered after we've got through the strategic review and you can see the total picture and although we have some preliminary analysis around that I think it's better to put the whole picture out there rather than cherry pick any individual. But we're very comfortable at present with our gearing direction. These things throw off cash extremely quickly and are able - we are able to pay down debt extremely quickly. Obviously we're making assumptions into the future about gearing for future LNG projects but frankly especially as there's a number of financiers in this room hopefully they're experienced both in terms of construction and now where deliverability has been strong and I think we maintain very strong support from the financial institutions for what we're doing. Bearing in mind these projects we see are being - are high returning projects certainly in comparison to other LNG projects in our region. These things are pretty robust with a robust resource project structure around them and some good operators involved. So I think we're very comfortable with where we go but more information at the strategic review. Dale Koenders: (Citigroup, Analyst) Okay and one other quick question, could you elaborate on the comment that substantial value add is successful through the arbitration of the Antelope process? Is this just in terms of synergies between the projects or perhaps greater participation? Peter Botten: Look I think reality of life is that firstly the arbitration process is underway and we'll see that I think to its conclusion. The reality is we have good outcomes from the development of LNG projects in PNG and we have extremely good outcomes and I suppose it's - we're very much focused on ensuring that we get the best possible outcomes for the development of future LNG in PNG and shall we say we have avoid some of the pitfalls that other project areas have had in developing multi LNG projects in similar areas. There is a very substantial prize for all parties to get that right. That doesn't mean to say that they will - we will get it right but at the end of the day we'll do what we can to try and get it as right as possible because we have a significant interest in many parts of this chain. Scott Ashton: (BBY, Analyst) Good afternoon Peter, Scott Ashton from BBY. An exploration question for you or Julian. Can I just get a bit of an understanding on what's going with PPL 269 given you've picked up a 14