David John Wissler Knox – Managing Director and Chief Executive Officer Andrew Seaton – Chief Financial Officer

Dale Koenders – Citigroup Global Markets Australia Pty Ltd. Adrian Wood – Macquarie Securities Ltd. Mark Samter – Credit Suisse Ltd. Ben Wilson – JPMorgan Securities Ltd. John Hirjee – Deutsche Bank AG Nik Burns – UBS Securities Australia Ltd. Stuart Baker – Morgan Stanley Ltd. Scott Ashton – BBY Ltd.

: I would now like to hand the conference over to your first speaker today, Mr. David Knox, Managing Director and Chief Executive Officer for Santos Limited. Thank you. Please go ahead.

Thank you very much, Vince. Good morning and welcome to Santos's 2014 Half-Year Results Conference Call. Joining me on the line today is my CFO, Andrew Seaton. In addressing the results, we'll refer to the presentation which has been released this morning and is available on our website. Now, turning to the cover of the deck, you can see the first cargo from PNG LNG being loaded on the Spirit of Hela. The first cargo was not only a significant milestone for Santos, but also for our operator ExxonMobil, and of course, for the people and government of Papua New Guinea. I had the pleasure of being in PNG last week to watch the loading of the 19th LNG cargo on to the same ship. As it is a clear confirmation of how well the commissioning and ramp-up of the plant is gone and this is something, of course, that we are going to do aspire to as we do the same when we bring on GLNG next year. I'm now going to jump straight to Slide 3. In presenting the results to you today, we will focus on four important highlights in the first-half. First, strong project delivery. PNG LNG is already producing at full capacity and GLNG is on track to start up next year. In fact, GLNG is now better than 85% complete. These two projects will deliver materially higher revenues and cash flow for the company. We've also delivered first production from Peluang in Indonesia and also Dua in Vietnam. Secondly, Andrew will talk to the sound operational performance in the first-half that delivered growth and revenue, EBITDAX, underlying profit, and operating cash flow. Thirdly, the start-up of PNG has enabled the company to increase returns to shareholders. We are announcing today 33% increase in the interim dividend. During the construction of the LNG projects we've had seven halves at $0.15 dividends. With the early start-up at PNG, we've received the first cash flow from the project in July. This has been the key to enabling us to increase the dividend now. And finally, we've announced another significant exploration discovery in the Browse Basin with Lasseter well this morning. Turning to Slide 4, operational and financial performance are dependent on our attitude towards an execution of safe operations in every sense of the word. I think these safety performance results underscore the Santos leadership teams' commitment to continual improvement in the safety of our people and also of our operations. To put these statistics into perspective, Santos and its contractors have worked some 32 million man hours so far this year. Achieving this sort of safety performance at a time of very high activity is especially important. It’s important for the safety of our people, and also for the successful delivery of the projects. I'm very pleased to report that drilling completions across the entire company achieved six months without the lost time injury. On safety critical maintenance for direct operating assets, our score was better than a 98%, which is our target. We paid very strong attention to learning from the high potential incidence, and this is driving further improvement, the core safety processes, and also the culture. Now, with that very brief overview, I'm going to ask Andrew to take you through the financials into more detail. So over to you, Andrew.

Thanks, David, and good morning to all. You can see the summary financials for the half on Slide 6. These numbers underscore our sound financial performance, but more importantly, they point to our improving outlook. We saw the beginnings of the improved production during the first-half, and the second half production outlook is clearly stronger, margins are growing as well, as our portfolio is increasingly linked to the oil price. We remain well funded to execute our strategy and the business is generating strong cash flow. If you turn to Slide 7, I would like to talk more about the dividend. The Santos Board and Management are aware that returns are a key priority for shareholders. Underwriting is to strike an ongoing balance between higher dividends, debt repayment, and the continued investment necessary for growth. As you know, we reduced our dividend payout in December 2010, given the funding that was required for our two major LNG projects. With PNG LNG successfully starting up ahead of schedule in April, and with GLNG now progressing well towards completion, we have the capacity to now increase the dividend. As David said, we received our first cash flow from PNG LNG in July. To enable this, we put a letter of credit in place, so that we can get early access to fund from the project finance distribution account. This is highly efficient for us as we have a positive carry on the results in cost of funding. The letter of credit was underpinned by our strong investment grade credit rating and our robust balance sheet. We intend to continue to access our share of PNG LNG cash in this way. Looking forward, we plan to maintain or increase each dividend as earnings and cash flow increase. And we expected the level of dividend will next be reviewed around the time of GLNG start-up. The growth story is evident when you look at our production on Slide 8. The start-up of PNG LNG contributed to the increase in first-half production, but the real benefit of this project is clearer when you look at our July production of 164,000 barrels a day, which is some 20% above the first-half average. PNG LNG is now fully ramped up with both trends producing at full capacity, and this will drive a stronger second-half of production. However, offsetting this to some extent is the impact of a planned 35-day to 40-day statutory shutdown of Bayu-Undan, as well as the 45-day shutdown of the Fletcher-Finucane FPSO for repairs and maintenance. Now full-year guidance of 52 million to 57 million barrels oil equivalent is unchanged. So, overall, the production snapshot is that we've had a sound first-half and that we do have a stronger second-half to come. And that's also the case with sales revenue and EBITDAX on Slide 9. EBITDAX was 13% higher, which reflects higher revenues and also the sound operating performance across the business. Now, third-party business continues to perform well, as we leverage our infrastructure position. We make a margin from all third-party oil producing at Cooper plus we sell third-party gas and liquids in Eastern Australia. We expect stronger revenue and EBITDAX in the second-half as our production continues to grow. Moving to production cost on Slide 10, was both production cost and DD&A have increased during the first half. It’s important to remember that one of the main drivers has been the new assets sort of come online. Production from these new assets both PNG LNG and to a lesser extent Peluang is sold at higher prices. And overall, this is resulting in margin growth for the company. Of the $48 million increase in production costs, $15 million can be attributed to these new assets coming online and also our full-half of production from Fletcher-Finucane. There is also $21 million for workovers and other costs and $12 million in relation to currency movement as the Australian dollar weakened against the U.S. dollar. And it's a similar story with DD&A, new assets online contributed half of the increase in DD&A from the first-half of 2013. The remainder has been due to foreign exchange impact and a higher dollar per barrel rate. On the next slide, you can see the higher underlying net profit after-tax for the first-half of $258 million. Higher prices and higher volumes contributed strongly. This was partially offset by higher exploration and the valuation expense, higher production costs, and also higher net finance costs. On the latter with PNG LNG now in production, we've ceased capitalizing interest on net asset, but you will see a higher interest expense going forward. The reported net profit after-tax figure of $206 million is primarily due to the impairment of the Indonesian CSG assets that we flagged in the second quarter report. Turning now to operating cash flow on Slide 12, as this chart that really highlights the growing strength of the company, we recorded our highest ever first-half operating cash flow of $744 million. And this will be higher again in the second-half. As I said before, we expect operating cash flow to more than double from 2013 levels by 2016. On the next slide, Slide 13, you can see the breakdown of capital expenditure of $1.9 million. As you would expect, GLNG was the largest item expenditures at $795 million. This represents all of the Santos' spend in relation to GLNG and includes $65 million for domestic stay-in-business CapEx, exploration appraisal, and also Santos corporate costs. We spent $440 million in the Cooper and over $170 million in other Eastern Australian assets, which includes our share of the Combabula and Spring Gully developments and also Narrabri, Mereenie, and some other assets in Eastern Australia. Capitalized interest for the first-half was $124 million. Our full-year CapEx guidance of $3.5 billion, which excludes capitalized interest is maintained. So to summarize, I'm confident that we have the momentum for a stronger second-half. Our major projects are now clearly proving to be the foundation for further growth and increase shareholders returns as we said they would be when we committed to them some years ago. We are confident of acquisition. We remain committed to strong financial discipline across our operations, also capital management and continued investment for growth. And with that, I'll hand back to David.

Thank you very much, Andrew. Now, our financial performance is, of course, underpinned by the project. And I want to review the key projects over the next few slides, and I'm now on Slide 16. I'm going to start in Asia. Last week in Vietnam, Chim Sao surpassed the milestone of $25 million barrels of oil production. And this is to improve the reliability of the Chim Sao facilities was successfully undertaken in the first-half. Further works are planned for later this year to ensure the improved performance of the FPSO. The field is currently producing around 28,000 barrels per day, which is an improvement on what we saw in the first-half, also pleased to say that the first of the Dua development wells have now been brought into production. In Indonesia, our team delivered the first gas in Peluang ahead of schedule in March. Importantly, this project was delivered with an impeccable safety record. Peluang is our fourth operated vessel in East Java and it underscores our ability to deliver new projects in Indonesia. Also pleased to say that the team is making good progress on Ande Ande Lumut. The fleet studies are well underway on the wellhead platform and also the FPSO. And we expect to be in a position to take a final investment decision late next year. We've also made our first entry into East Malaysia, to an agreement to acquire participating interest in exploration acreage located in the Sabah Basin. Santos has acquired up to 25% participating interest in the deep water Block S, production sharing contract from INPEX. The participants in the PSC will be INPEX, who's the operator with 50%, and Santos and PETRONAS Carigali each with 25%. Block S lies in the heart of a prolific Sabah Basin. It's surrounded by large commercial oil and gas discoveries, and significant existing infrastructure and production from the area. 3D seismic is resulted in two significant drilling opportunities. The first of these, the Telus is expected to start in the fourth quarter of this year. I'm now going to move much closer to home and to onshore. We drilled nine appraisal wells in Narrabri. These wells are being hooked up to our new water handling facility at Leewood, which is just north of the Pilliga forest, where the first two of our 150 mega-liter pumps have been commissioned. The test results from these wells will be added to the data from the stock of existing wells, the 15 existing wells, to inform the design of the 2015 work program for the Narrabri gas project. We also continue to transfer water from the legacy ponds at Bibblewindi to our new facilities at Leewood and we expect this work to be completed very soon. Now, we're going to turn to PNG LNG on Slide 17. Last Friday night, I had the great privilege to join Exxon and the government of Papua New Guinea to celebrate effectively the start of this project, of course, it started up as Andrew said, in April. It was an extraordinary evening and there is a celebration of both the success of Exxon, but also of all parties that have been involved in this project. I think the thing that you would take away if you're fortunate enough to be there that night, was above all the transformation the importance of this project is for the people of Papua New Guinea and the country of Papua New Guinea. And it was a real pleasure to sit on the Prime Minister's table, and hear him stand up and say in the first line of his speech, that this is one of the speeches that he was proudest ever to make. And it's rare in the oil and gas industry that we can make such a contribution that firmly believes that Santos, along with our operator Exxon, we've made a massive contribution to PNG. And this is, of course, borne out by the fact that today more than 20 cargoes have been shipped to our customers in Asia and the remaining activity on the project is of course drilling and that's going to bring me on to Slide 18, if I could go to 18. All eight Hides development wells have been drilled. Six of these are on production and the final two wells in the G-pad are being completed. The developments in produced water well results will be used to redefine the Hides reservoir model. We believe that there is significant scope for upsides in the Hides reservoir volumes. At the same time, Exxon will commence the drilling of the exciting Hides what's now called F1 well. Previously known as Hides Deep, this well is designed as both the Hides producer and also to penetrate the deeper exploration target directly below the existing Hides field. Now, the important thing is that Santos has a 24% interest in this prospect to our ownership of PRL 1. We are well placed the benefits from the expansion of PNG LNG, however, we are confident expansion will happen, however, it's still a little early to predict exactly how and when this will occur. The important point is that as an existing infrastructure owner and the holder of prospective acreage, whatever the source of that expansion gas, Santos is very well placed to benefit. Now, outside of the PNG LNG project, we've also had exploration success in the first-half with gas discoveries at Manta and also at Northwest Koko. And we're now working with our partner Talisman to determine the next steps in our evaluation program. With that, I'm now going to turn to GLNG on Slide 19. GLNG is on schedule and on budget to deliver its first cargo next year. I have to say, we are really pleased with progress from the drilling through the pipeline and also the progress on Curtis Island. As I've said already, the project is now moved past the 85% complete mark. Let's start with the upstream works on Slide 20. We've drilled almost 600 wells – 600 wells have been drilled since FID, 77 were spotted during in the first-half and we continue to see good performance on drilling and time and cost. Our guidance on drilling is unchanged. We expect to drill around 300 wells over this year and next combined. Fairview production capacity continues to build ahead of expectations and our own plan. The wells are now averaging 2.2 terajoules per day per well, that up from 1.8 terajoules at our last update to you in February. This performance underlines the confidence we have in this field, and support our ramp-up production profile. In Roma, we're also building a strong base of dynamic data and there is real potential for upside here as well. Currently, we have over 50 wells flowing. Even more encouragingly is the fact that we've also now have our first well that's producing more than 1 terajoule per day. This is a good basis for the confidence that future production capacity of the field, we'll comfortably achieve our planning basis. Construction of the upstream surface facility is basically complete. Two of the three hubs to be handed over for commissioning with construction of the third now very well advanced. Our upstream facilities will be ready to supply gas when it is needed. Turning to the pipeline and the LNG plants in Curtis Island, I'm now on Slide 21. Some of you would have seen the significant progress made during your visit in June. The 420 kilometer gas transmission pipeline is in the ground. It's been hydro-tested and it's been de-watered. Commissioning of the pipeline is underway and we expect to commence gassing up the pipeline in the coming weeks. At the end of June, including the work being done at Bechtel's Module Yard in Batangas, Train 1 was 84% complete, and Train 2 was 77% complete. All the Train 1 modules are set on their places and work continues with piping hook-up and cabling pulling. All but two of the Train 2 modules have also left the module yard. That's 109 of the 111 modules required for the project. We expect to receive the final Train 2 modules on Curtis Island in September. I'm particularly pleased with the progress that's been made on the tanks and on the jetty, both which are well clear of the critical paths. The first LNG tank has been successfully hydrotested and final installation work is now underway. Construction on both the second tank and the LNG jetty is progressing very well. Bechtel is responsible for plant commissioning and we now have 85 of our own Santos operational staff embedded into the Bechtel project team at the plant. We're well prepared to initiate commissioning work, once gas is introduced into the plant in the fourth quarter of this year. It's also important for me to say that we're pleased that Bechtel's Curtis Island workforce has accepted the new labor agreement. All 3,500 staffs are at work. It's business as usual on our site and we're on track to deliver first LNG next year. Now, let me take a look on our promising exploration program and I'm going to start in the Browse Basin on Slide 22. Today, I was delighted to be able to announce some big news to you on the significant gas-condensate discovery with the latter the one well. This is an exciting discovery that builds on the current success we had in 2012. What we've done, we've intersected the gas-condensate section of 405 meters, and the logging has indicated that we have 78 meters of net pay over the Lower Vulcan and Plover intervals. We've taken hydrocarbon samples and these have confirmed our gas-condensate ratios are between 10 and 25 barrels per million standard cubic feet. We've done multiple pressure testing and lots of log evaluation and the indications are that the gas would flow at a high rate. So this marks a very important progress in our exploration program in the Browse basin, of course, comes on the back of our current success in 2012. Now, we're going to move on to the Cooper Basin unconventional program on Slide 23. As I said before, our team's focus here is on cracking the code in the unconventional basin. This code cracking is both characterizing the reservoir quality and then matching each reservoir with the most compatible completion time. The shale gas potential in the Cooper Basin has been enhanced with the successful execution of 1,000 meter, 10 fracture stage horizontal well Moomba-193. This well has extended our learning curve from the recently drilled 500 meter Roswell-2 horizontal well. Now, in the 193 horizontal, down hole micro-seismic has showed that the full length of the horizontal lateral section was stimulated and that the fractures were contained within the target REM shale interval. Following stimulation, a 28-day flow test was commenced in Moomba-193, and the well flowed at an average of 1.5 million standard cubic feet per day. This is an improved rate over Roswell-2 and is a positive indication that flow rates can be increased through fracture design, placement, and, of course, the increased horizontal length. In April, Moomba-194 was successfully connected via a short tieback into Santos’ existing production infrastructure. It was brought online with a flow rate of 0.9 million standard cubic feet per day. This is the second successful unconventional well to be connected after Moomba-191, which is currently flowing at a very good 1.7 standard cubic feet per day. This well has already produced 1.3 bcf of gas. Drilling commenced in the Nappamerri Trough region with the spudding of Gaschnitz-4, and this is the first of three planned new wells in the Gaschnitz area. Now, all these exciting work will continue as we evaluate the full potential of the unconventional resource base in the Cooper Basin. So in conclusion, everyone, I'm exceptionally pleased with the company's achievement and the progress made during the first-half of 2014. The start-up of PNG LNG and the receipt of the first cash from the project has enabled the company to increase our returns to shareholders. This increase in dividend delivered on what we said was half of the time of GLNG FID. It’s consistent with our commitment regarding capital management initiatives now that PNG LNG is fully operational. We've also delivered a sound operational performance in the first-half. We have seen the growth in the revenue and EBITDAX underlying profit and operating cash flow. GLNG is clearly on track to start-up and deliver its first cargo next year. Lasseter is a significant exploration discovery. We have today outlined many proof points to support our positive outlook for the company. Our strategy to transform the scale and the diversity of our business is now becoming a reality. With that, I would like to hand over back to Vincent and take any questions which you have. Thank you very much. Can I have the first question?

Yes. (Operator Instructions) Your first question today comes from the line of Dale Koenders from Citigroup. Dale, please go ahead. Dale Koenders – Citigroup Global Markets Australia Pty Ltd.: Hi, David and Andrew. First question just on the discovery of Lasseter, you previously spoken about the potential of WIT some full payers more than 10 tcf of resource accumulation. Just wondering is that still the target longer-term for the block and how far do you think you’ve got so far with Crown and Lasseter?

Well, I think – thank you very much, Dale. Now, this is very exciting to be able to announce this, this morning. The 5,000 meter deep well, we found a very significant hydrocarbon column. We've got 78 meters in that pay, the top sands in the Lower Vulcan are of extremely high quality. We know the well will flow and flow very well. So clearly this is a big step in evaluating this resource. We now have Crown discovery, we have the Lasseter discovery and clearly working with others in the area of Poseidon and the wells in that area Procheas [ph], et cetera. This is now becoming a very, very hot place to hold exploration acreage. As you can see on the map, we hold very significant Santos – very significant exploration acreage, right the way around both Crown and Lasseter. So, I think, if you look forward for the company, this is one of the big future options that is available to us. But I had said, there's nothing much more exciting than doing a well of this nature, this depth and this complexity, and coming out with 400 meters of hydrocarbon. It is very significant for us. Dale Koenders – Citigroup Global Markets Australia Pty Ltd.: 400 meters gross, so the net pay is 78 meters and net to gross is quite a lot. But where do you think you go in terms of the gas ratios between Crown and Lasseter, do you think you’ve got enough for a standalone development or you may be looking unitization?

I think, ultimately the gas resources is very significant. I think at the end of the day, however, probably we'll be working with others to develop this total resource and obviously there are a number of fields around about particularly Poseidon and Ichthys further to the East. So we've got plenty of good products. We also have good partners in our venture in Chevron and INPEX. So I think we are very well set-up here to combine this resource with others around us to have a really significant future development. I'm hesitant in saying the exact size of the resource. Clearly the 10 tcf number has been supported by this well. But we have to continue to evaluate that, but this is a very, very significant discovery for us and goes from the back of what we found at Crown. Dale Koenders – Citigroup Global Markets Australia Pty Ltd.: What's the expected forward work program, you're still planning to drill, I think is at Grand?

We haven’t committed to a forward work program. After you made a discovery of this nature, obviously you're going to spend a bit of time updating the seismic, making sure you fully understand all the reservoir models and then deciding, what's the best well to drill, what is the next best well to drill. So we are not going to do that. So we will decide once we've really had a good look and evaluated these results. These are very good results. These are the type of results that really shift thinking and shift understanding of the whole area. And it’s the best development of Lower Vulcan sands that we've seen in this area. So we need to really understand the extent of these sands. Dale Koenders – Citigroup Global Markets Australia Pty Ltd.: Okay. And then on the Hides produced water disposal well, and I think the results are done. Are you able to find any contrast and how much upside there might be or how much more gas column you found? My understanding is that ensuring the gas-water contact is with the prices of measuring pressure and gas gradients and water gradients is a very quick calculation.

Yes, we don’t have all the data in from that well yet, as we are today. So I can't give you any detailed comment on it, but we do believe that the Hides field is likely to get bigger at the end of the day, yes. Dale Koenders – Citigroup Global Markets Australia Pty Ltd.: Is it a – the prices getting an update, is that weeks away or maybe is it end of the year?

Well, I think we – I'm not going to expect that in how long it will take, but it will certainly be done in the fullness of time and it will be done to the highest amount of rigor and quality. There's quite a lot of sense involved in this and what Exxon will be doing as operator is incorporating those results in the Hides model. But overall, I think we believe that the Hides field is getting bigger, not – certainly bigger than it currently is. So we see an upside here; not anything else. Dale Koenders – Citigroup Global Markets Australia Pty Ltd.: Okay. Thanks, guys. That's great.

Your next question today comes from the line of Adrian Wood from Macquarie. Adrian, please go ahead. Adrian Wood – Macquarie Securities Ltd.: Yes, David, just a couple of questions. First of all on the dividend, obviously that jump has come a little bit earlier than I think perhaps we were expecting. Just wondering how we should think about the next jump in the dividend when GLNG starts up. Obviously, you talked about greater than doubling in operating cash flow from 2013 to 2016. Would it be reasonable to think of a greater than doubling in the dividend from $0.15 to something over $0.30 or is that too aggressive or not aggressive enough. Can you just talk through the thoughts there, I appreciate it's ultimately a board decision, and…?

It is, Adrian. Let me answer that question and I'm going to bring Andrew in here and then allow you to do a second question. This is a very important issue. We're very clear that Santos intends to maintain or increase each dividend as earnings and cash flow increase. And we're also very clear that the next time we will really think about this as a board, all other things being equal is at the time of GLNG start-up. So that's the board's position, that's where we are. And Adrian, we are very pleased to announce it today. It's done because we are at a good start-up with PNG. We are getting the cash into the firm, so we're able to do that today and I'm very pleased to be able to do so. I'll ask Andrew to add any further color he'd like.

Adrian, I think that's really is consistent with our intentions when we cut the dividend back at the end of 2010 and we're embarking on two projects, one of which is now online, so we've taken first step. And I think as David said, our intentions moving forward are quite clear. I'm sorry as I can't quantify the increase in the dividend in the future other than to say we're going to find the right balance. We will remain a growth company. We will continue to reinvest in growth. We have been able to maintain our BBB+ credit rating right through this high CapEx phase and so we will remain committed to our strong investment credit rating and obviously shareholder returns are also very much friend of mine. Adrian Wood – Macquarie Securities Ltd.: Okay, great. Thanks. And just a second question, I noticed that you spent $65 million of Non-LNG CapEx in the GLNG CapEx budget for the first-half of the year. I'm just wondering if this rate is spent, so let's call it a $130 million a year, will continue following the start-up of GLNG and if indeed it does can you confirm that it is included in the $500 million of sustaining CapEx guidance that's out there? And if it isn't going to continue after start-ups then can we explain why it's not included in the overall LNG development budget of $18.5 billion given the sort of feels like in that case it's probably going in to the export market rather than the domestic market?

Yes, sure, thanks, Adrian. I can confirm a couple of things. Firstly, the $1 billion guidance we've given for CapEx beyond the end of 2015 is everything. So that includes Santos's share of the domestic stay-in business, appraisal, exploration, so forth. That's the whole lot. Remember, that our domestic contracts would tail-off after 2016, but it's definitely all included. There's nothing more to see here. Adrian Wood – Macquarie Securities Ltd.: Right, thanks.

Your next question today comes from the line of Mark Samter from Credit Suisse. Mark, please go ahead. Mark Samter – Credit Suisse Ltd.: Yes, morning, guys. Couple of questions, if I can, the first one is on the Cooper Basin. The round numbers, you said you spent $450 million in the first-half. You told us over December investor day, you were going to spend $650 million in the year, leaving residual of $200 million. Now, if we look at the release Beach made a couple of weeks ago and their guidance for CapEx from July 14 to June 15. I'll keep this numbers and we can scrabble over rounding errors. The net Santos level, the implied net Santos level from the Beach guidance is about $880 million over the next 12 months. If your $650 million is right for FY 2014, that leaves $200 million in the half, that would leave $675 million left in first-half 2015. That doesn't look like your usual CapEx profile when the infrastructure-build should be largely down to hit that target of increased production. Can you just talk us through what we're seeing there?

Yes, Mark, this is a pivotal time for the Cooper Basin and we are spending over and above the normal amount in the Cooper. We've described previously the market, the project called the Cooper Infrastructure Expansion Project. And what that is, is improving some satellite facilities and also installing another CO2 Train at Moomba Train number 8 at Moomba. Those will greatly increase the processing capacity through Moomba and also support the ramp-up in production. The important thing is we've already seen the inflection in the Cooper. We've seen the gas production bottom out last year and start to increase. We've got more drilling rigs operating in the Cooper now than we have had for a very long time. The CapEx guidance that we've given still holds. I think there's a bit of a timing difference there between Beach's fiscal year and our calendar year. But there is this discrete one-off project which will be prosecuted through the remainder of this year and into next. Mark Samter – Credit Suisse Ltd.: Do you think, we can expect – just if we take Beach's guidance and your guidance, and were you showing they're both correct then? That's a huge step-up in CapEx in the first-half 2015. It implies net to you $850 million spent in the first-half. Do you feel comfortable with both sets of numbers?

Yes, Mark, I've not studied Beach's numbers. In fact, I've not seen Beach's numbers at all. What I can say is, is our numbers, we're going to run a six rig program in the Cooper. We're going to maintain our Cooper oil spend at roughly the same levels as we have for the last couple of years. Our Cooper gas-spend will be a little higher as we spend, I got around $400 million our share on the Cooper Infrastructure Expansion project and as we build the capacity. We're right in the middle of setting our budgets at the moment. We take those to the board in October for our own internal, but directionally that's where we're heading. Mark Samter – Credit Suisse Ltd.: Okay. Thanks. And my question I guess for David probably. With the EBAs Curtis Island, it's quite interesting to note between the first vote in May and the third vote, there were $474 more workers employed. I mean, Bechtel looks like at the start of the year that the workforce had peaked and was going to start to tail-off. What you think we should be reading into that? Was there issues with productivity and they brought more staff on? Was it anything else that we could be thinking about, now, just your take on why the staff numbers were increasing at a time you should see them decreasing?

Well, I think it's very clear that certainly on our side Bechtel has made excellent progress. We're probably as well on the site today at peaking manning levels. They will start to fall off fairly soon, but currently we're probably at about peak levels. I have to say that today the productivity on our site is very good. We've had some very good productivity results actually this week. And we're fully at work. We've got all the Train 1 modules on the site. We've only got two Train 2 modules still in the module yard and it's going to come out in September. So overall, I have to say, Mark, however you look at this, we've made extremely good progress on Curtis Island and if you look at the upstream the hubs are basically done. We just did commissioning. The pipeline is done. We've got the wells in place and the field is performing better than we expected. So now it is a matter of finishing off on Curtis Island and I'd say, we have a workforce now that it is fully committed to doing that. The issues with the agreement are now all behind us. We now have a three year agreement in place. And I have every expectation that we will go forward and we'll be delivering our first cargoes, I've said for long time in 2015, and Train 2 will be ready to start up at the end of 2015. Nobody should have any doubt about that. Mark Samter – Credit Suisse Ltd.: Okay. I mean, I'm interested with that comment that and you obviously are drawing people on the one project that's delivered LNG early. You look at the last seven LNG project to start production, one was early PNG LNG; one was on time Peru, that's probably a slightly different kettle of fish. The other five will materially lay, I mean, ex-Skikner [ph] which was – it a unit disaster, the average of the other ones was 12 months late.

Mark, I have no intention of being the average, none at all. PNG was not average. GLNG will not be average. Mark Samter – Credit Suisse Ltd.: Okay. Okay. Brilliant. Thank you.

Your next question today comes from the line of Ben Wilson from JPMorgan. Ben, please go ahead. Ben Wilson – JPMorgan Securities Ltd.: Good morning, David and Andrew. I just had one question about the Cooper Basin drilling program. The specifically, I guess, you described it as a down-spacing or an infill program, and what your expectations are around reserve development when you do report. Is the nature of the program to develop the roughly half of your 2P net reserves of – I think it's 1.1 tcf or so you got there? Would you anticipate with this infill program that you'll be adding tier 2P reserve base?

Probably the former, we're basically down-spacing infilling and developing the remaining 2P reserves in our core fields. Of course, that's not true for the unconventional program, but for the conventional program that's what we're doing. And as Andrew said, we've increased the number of rigs, we've turned the corner of – we're starting to build capacity in the field. I've been very pleased over the last effectively couple of months with the performance of the Cooper basin and the gas business. I've also been very pleased that the op-performance has been very good recently as well and sometimes that's bit of an unsung hero. But the op-performance is really going very well right now. So, the Cooper Basin, it isn't an easy place to operate, a challenging place to work, but I think that certainly the last few months have gone very well for us. And as Andrew said, we're also increasing the infrastructure there. We're modernizing some of it. We're adding some more compression. We're putting a new CO2 Train in. That project is also probably slightly below the radar screen. I'm pleased to say that that's going extremely. It's back on its schedule and it's probably coming in slightly under the budget. This is all very good for Santos, very good for our shareholders and very good for the future of the basin. Ben Wilson – JPMorgan Securities Ltd.: Okay. Very good. And just a question on Cooper, just maybe you can provide an update on your expected timing of that gas and then when…?

2016. Ben Wilson – JPMorgan Securities Ltd.: 2016 and when you would anticipate the signing commercial agreements around your share of the gas because it is a big chunk for the first couple of years?

Yes, this is a best fortune it is, almost because this project was unfortunately delayed and that we're now obviously coming into a different gas market situation; hadn't come on when it was first envisaged. In 2016, we know the gas market is going to be very strong. So we will obviously sign agreements as that date approaches. But we're in no massive rush to do so at this stage. The field will come on 2016, as you say we've got a substantive volume of gas available to us at that stage. It's coming at a perfect time for us in 2016 when we believe the gas market is going to be very good in Victoria. Ben Wilson – JPMorgan Securities Ltd.: Excellent, thanks very much, guys.

Your next question today comes from the line of John Hirjee from Deutsche Bank. John, please go ahead. John Hirjee – Deutsche Bank AG: Thank you. Good morning, everyone. A question on the dividend if you don’t mind; could you give us some further color or granularity on how you're thinking about the payout ratio that you want to employ when the LNG projects are at plateau. And on that, will there be any seasonality at plateau, in other words what I'm trying to decide for is with the interim and the final dividend there will be sort of material differences or is there a plan to sort of keep it equal as you have been doing at least in the last couple of years.

Yes, thanks, John. Good questions. To take the second one first, we're not looking at seasonality. So, the statement we've made this morning is that we'll look to maintain or increase each dividend and that's so rather than each year of payments we'll look to maintain or increase each dividend. In terms of the payout ratio the important thing here is that the first-half of 2014, the half just gone, we only had a couple of months of PNG LNG ramping up. So as I said, the second-half is going to be stronger. The payout ratio in the first-half is about 78% of underlying profit. Now, that is higher than we would envisage moving forward. We're more comfortable balancing our growth with our dividend. We're probably more comfortable at around a 40% to maybe 50% dividend payout ratio notionally through the cycle, but again, reiterating that progressive nature of our dividend. John Hirjee – Deutsche Bank AG: Thank you, Andrew. Another question if I may. And, David, you mentioned Roma, and about the one well that’s achieving over 1 PJ a day. What's the prognosis in terms of how many further additional wells do you expect to give you further confidence that as you mentioned that half of PJ a day planning assumption can be made?

Well, I think, I do quite right, John. The issue in Roma is, we've now got the wells hooked up in the dewatering. We have 50 wells hooked up in the dewatering, this is a big step for us. And what we've seen in that dewatering phase was, we've seen these wells started to come on, and we've seen that, they're not a model type curve, but they're real production performance. I'm always saying is that wells or the average well is performing exactly as we expected. But there are some wells that are performing quite a bit, but better than we expected. And by that, we mean that either they are producing a lot more water than perhaps we originate plan, which indicates, it will produce a lot more gas, or that, in fact, they're going to gas much earlier and I think that we're producing at higher gas rates. So when you talk to the – all the geoscientists up in the project, I think they will all to a person say that, the Roma field is looking very encouraging. Now, but obviously, we are not alone, and this is an offset field, which origins develop Combabula, which is very large and significant, and they’ve had it on stream for a lot longer. And we knew that their average well is performing better than our model, the average of 0.5. : John Hirjee – Deutsche Bank AG: Good. Thank you, David. Thanks, Andrew.

John, thank you very much.

Your next question today comes from the line of Nik Burns from UBS. Nick, please go ahead. Nik Burns – UBS Securities Australia Ltd.: Thank you. Just a couple of question for me. The first one just on the current set of plan at East Coast gas markets, we're all expecting gas prices to go up quite significantly from here, but I guess, we're in a situation now wherein Queensland in particular, we've got a very large gas prices. Just wondering, if there is any way that you're able to take advantage of this low gas price environment maybe potentially buying some of this gas and putting into storage in Moomba?

Nik, we are aware right now, of course, that there is a lot of gas available at present that will, of course, change us as the first train with the QCLNG starts up and then subsequently up in April and June. The – there are opportunities for companies such as us who do have storage available to do what you are suggesting. Our key, however, is really to focus as we discussed just now with John Hirjee is to really get the Roma wells dewatered and make sure that that's how we focus and get all of our wells online and ready to fill the train and the second train as well. So if we do, do any processing of gas it will be very much on the margin. Our real focus is developing our own fields at this stage. But we do have storage available. We have it both in the GLNG assets, but we also have it, of course, in the Cooper Basin, and we're one of the few companies who does. Nik Burns – UBS Securities Australia Ltd.: Right, so you wouldn’t be looking to maybe buy gas in Queensland and taking it back to Moomba for storage?

Well, I think the storage is going to be, just as a general theme, storage is going to be an important thing to have. It’s important for a number of operational reasons, but it’s also important, because it does allow you to time shift gas if you choose to do so. So we do have it available, I'm just signaling there, I think, that will be very much on the margin for us. Our focus will be on getting our own fields up and running. Nik Burns – UBS Securities Australia Ltd.: :

No, I don’t – I think, it’s far too early to read anything into it other than that we are producing reasonable quantities of gas from shale, and we are learning as we go forward. This isn’t a journey we are on. Today, I'm as confidence, however, being about the future of Cooper shale. But we recognize, we also have major tight gas columns, and that’s why we're doing the free-gas [ph] in these wells, because we have the huge column of gas in very tight rock. And we also have which they call basin-centered gas, and we also have as we know deep coals, which are producing as you rightly say. So, we have quite a few options and choices, and we are evaluating all of those and then at some stage we'll probably decide on which is the front runner. But I think, we're in the early stage, this is the second horizontal well we've done. It was probably one of the largest fracs we've ever done, but we are still very much learning. And the fact that we've got gas coming from shales and we've got it in improving rate is a good thing. In North America, typical horizontal well is actually 3,000 meters. So, we've got a fair way to go. We're at 1,000 right now, we can go out further if we choose to do so. Typically, they can even put 30 or 40 frac stages into these wells. So you can see how even if you just model these numbers forward, you start to get quite significant flow rates even if you just take these numbers forward. But I think, we're still in early stage, we're still learning. But if you ask me, am I – do I believe that Cooper shale or the basin-centered gas for the deep coal will be a success in the next 10 to 15 years, I'd say probably, yes, yes, I think there is a good chance of it. Nik Burns – UBS Securities Australia Ltd.: That’s great.

We just keep an eye on things and keep watching. Next year, we're going to continue to develop this program. We're going to continue to evaluate. We're going to continue to drill wells and continue to get good results, I think, and we'll just build the model. Nik Burns – UBS Securities Australia Ltd.: Excellent. Thanks, David.

Your next question today comes from the line of Stuart Baker from Morgan Stanley. Stuart, please go ahead. Stuart Baker – Morgan Stanley Ltd.: Good morning, gentlemen. Just another question on the Cooper Basin, I appreciate, some of these have been asked already. But the second biggest spend in the half year for $440 million, I'm trying to get an answer and I'll take it a couple of ways, which is, can you split the investing in the infrastructure in that figure away from the stay-in business spend for the gas development? That’s the first question. The second question is, how should I think about how much money you're going to need to spend every year over the next several years in developing the 2P that's in the undeveloped bucket? It looks like about 550 PJs in a region where a TJ, they seems to grab a headline now. And I assume you get about a PJ a well, it looks like to me you need about another 500 wells to deliver that reserve, and then try to think about what that’s going to cost, I can see couple of billion dollars pretty easily spread over as I said quite a few years. And therefore I'm figuring a stay-in business gas development drilling cost will be about $400 million per annum, does that sound about reasonable?

Stuart, few questions here, the first one that the breakdown of the infrastructure versus the drilling, I don’t have those numbers at my finger tip, but I'm sure that Andrew then will be able to do some work and get them to you during the day. Secondly, just on the flow rates, you sort of implied one PJ a day is now the norm. We're still seeing flow rates from individual wells a lot higher than 1 PJ a day. And, remember, the Cooper economics are also driven by the liquids content. So we're still seeing good areas with high condensate gas ratios and strong LPG components as well. The number that you put forward about $400 million, isn't that probably sounds about right depending on the number of rigs that we choose to run? As I said, we are up to about six weeks now in the Cooper and that’s good business for us. The incremental rates of return from operating those rigs are all strong. So, I guess, this is something that we will keep an eye on the gas market and the results that we are getting. But at the moment, the Cooper as an asset, has turned the corner and is performing well. Stuart Baker – Morgan Stanley Ltd.: Okay, thanks, Andrew. I appreciate it. Few maybe parts of question here, but fair enough. Thank you.

Your next question today comes from the line of Scott Ashton from BBY. Scott, please go ahead. Scott Ashton – BBY Ltd.: :

Yes, thank you, Scott, and obviously, there is a lot of excitement around what's happening in PNG right now. And we ourselves know that we are going to be in PNG for 30, 40, 50 years. So what we have been doing strategically and quite quietly is picking up exploration acreage. We've picked up some good acreage in the Forelands and as I said today, we've had two reasonable well-tests on those two wells that are operated by Talisman, the 269 acreage, I haven’t actually got a map in front me, it’s exactly where it is. But we've been very interested in this Forelands area. The Peluang as you rightly say, also an interesting field, which could potentially brought into the project into the main PNG project. So our strategy is to work in the Forelands, get access to good quality exploration place and then work with the PNG operator Exxon to basically grow the resources of the main project. And recognizing that we are going to be in country for a long time, and recognizing it’s a very good hydrocarbon province. Scott Ashton – BBY Ltd.: Thanks, Dave, and just sort of time it back to one of the earlier questions on payout ratios and DV's [ph] obviously want to keep their powder dry to sort of play a part in sort of consolidating some of that acreage up there. So, I mean, would this be one of the more strategic acreage positions you’ve got?

What we're doing here doesn’t affect any of the dividend conversation. We've got in the reasonably inexpensive access cost. Scott Ashton – BBY Ltd.: Correct.

And that’s been – our strategy is to get in reasonably early with the exploration drill a bit over the last couple of years. And we've also Block S in Malaysia which I've announced today. We've got these two discoveries in the Forelands. So you will see us continuing to gain access to exploration place where we believe there's real potential. Within a fairly tight region, we are keeping ourselves confined to the Asian region and we believe there is some really good opportunities there and what we've done in Malaysia, and what we've done in PNG are fine examples of that.

Hey, Scott, maybe, if I can also elaborate. We do have a number of significant great opportunities that are coming through, whether it’s PNG LNG Train 3, whether it's the Browse region, whether it’s Darwin, backfill Darwin expansion, that Cooper continued grow and the shale that we've talked about and also projects in Asia. I think the key thing is our growing operating cash flow and our reducing investing cash flow at the moment. : Scott Ashton – BBY Ltd.: That’s great. I appreciate your time and patience on that. Cheers.

Thanks, Scott.

(Operator Instructions) Your next question comes from the line of Michael Doug [ph] from Citigroup. Michael, please go ahead.

Hi, there. I just wondered a bit more color on the flexibility in your gas sales contracts, given kind of the expectation in the market of on a lot of gas supply in the short term. To what extent will customer nominations impact your production in the coming year? And I guess a follow-on from that is, on what should that gas has you already banked from those contracts that you need to supply going forward?

Thanks, Michael. I mean the gas market is in transition right now, as an earlier question pointed to. The sport market price is quite low in Queensland but remember that very little gas trades through the spot market. Our contracts are really long-term contracts, some of them have a degree of flex in them and so perhaps they will be nominated down. But that's factored into our thinking in the guidance that we've given on production. But as David said, once the first LNG project QCLNG starts up then that opens up a whole new market for gas molecules in Eastern Australia. And our strong expectation is that, you will see that the market supply-demand coming back into balance at that time.

Okay. Thanks for that.

Ultimately, strategically here the bigger thing is we are going from a sort of $4 gas well in Eastern Australia up to $6 to $9 gas well as we said for a number of years and that’s happening and that’s the big strategic win for us. It’s repriced all our resources in Eastern Australia.

Yes, and your production forecast for next year kind of includes the conservative assessment of how customers will make their volumes?

It will include the assessment, yes.

Yes, we haven’t given guidance for next year. We've given guidance for this year, and that's been taking into account. We'll give guidance for next year at our Investor Day in November.

Great. Thanks, guys.

Can I have one last question and then we need to wrap.

(Operator Instructions)

If there are no more questions then I – there are no more questions just…

No, there are no questions on…

Well – I just like to thank everyone for joining us this morning. And thank you very much and I look forward to seeing you over the next 10 days. Thank you.