Kevin Gallagher – Managing Director and Chief Executive Officer Anthony Neilson – Chief Financial Officer

Dale Koenders – Citigroup Ben Wilson – Royal Bank of Canada Mark Samter – Credit Suisse Nik Burns – UBS James Redfern – Merrill Lynch Adam Martin – Morgan Stanley John Hirjee – Deutsche Bank Andrew Hodge – Macquarie

Ladies and gentlemen, thank you for standing by, and welcome to the Santos 2017 Half-Year Results Conference Call. [Operator Instructions] I must advise you that this conference is being recorded today, 24 of August, 2017. I would now like to hand the conference over to our first speaker today, Mr. Kevin Gallagher, Managing Director and Chief Executive Officer of Santos Limited. Thank you, sir, please go ahead.

Good morning, everyone, and thank you for joining us for our 2017 half-year results. Joining me here today is our Chief Financial Officer, Anthony Nielsen. I’m going to start with some opening remarks before handing over to Anthony to discuss the financial results. Following that, I will take you through our operations before opening the call to questions. Before we start, please note the disclaimer on Slide 2. Moving to Slide 3, I am pleased to announce a significant turnaround in the underlying performance of Santos. First half highlights include; forecast pre-cash flow breakeven was $33 per barrel, down 24%. $302 million of free cash flow was generated before asset sales. That’s an increase of over 400%. Net debt was $2.9 billion at the end of June, down 36% following the repayment of $368 million of debt in the first half. This is in line with our target to reduce net debt to $2 billion by the end of 2019. Accordingly, and consistent with our focus on debt reduction, the board has decided not to declare an interim dividend. Underlying profit was $156 million after tax compared to a loss in the previous half, and upstream unit production costs are $8.08 per barrel, an 8% improvement. I am also particularly proud of the improvements that the team has made across our drilling operations. The average well cost in the Cooper is $2.8 million, down 33% from last year. And Queensland, we’re now delivering Roma wells for $900,000, more than 80% lower cost than Phase I wells. The Santos drill complete connect process is delivering real sustainable cost savings which have provided real value to the Cooper Basin and GLNG. This will change the way we look at new developments going forward, including new Queensland CSG developments and, of course, Narrabri. These are strong results that reflect the transformation of Santos into a low-cost, reliable and high-performance business. This operational performance reflects increased productivity, the benefits of a lower-cost structure and the importance of a stronger balance sheet. Strong performance from our core assets and higher forecast domestic sales in the second half have resulted in an upgrade to one – to our full year sales volumes guidance today to between 77 million and 82 million barrels of oil equivalent. Our asset portfolio is now set up to deliver long-term production with key expansion and growth opportunities in PNG, Northern Australia and Narrabri. Moving to Slide 4. Safety is an important indicator of our operational performance. In fact, to be a high-performing and sustainable business, we need to ensure we are not hurting people. Following record-low injury levels in 2016, I am disappointed to report that our injury rate increased in the first half. While these injuries were of low severity, you can rest assured we are working tirelessly to improve our safety performance. As the CEO of Santos, I am absolutely committed to ensuring all our employees return home safely. One encouraging highlight of the first half was the environmental performance across our Queensland operations. Santos is performing well with the lowest frequency of reportable environmental incidents in the industry. Moving to Slide 5. Santos continues to focus on natural gas because we believe it has a critical role to play in delivering clean and reliable energy in both Australia and Asia. Our Transform, Build and Grow strategy announced in December 2016 was developed in response to lower and more volatile oil prices over the medium term. The concepts of discipline and focus underpin this strategy and the value proposition for Santos’ shareholders going forward. The Transform phase is about turning Santos into a low-cost, reliable and high-performance business with a portfolio of five core long-life gas assets. The Build phase aims to establish a portfolio of exploration and development opportunities around our core assets and drill more wells to maximize production and increase gas supply. And finally, the Growth phase will see us focused on opportunities to increase production and develop new high-value opportunities within the core portfolio as well as develop new opportunities to expand our core assets. On Slide 6, Santos’ core asset portfolio will deliver stable base production and cash flow for the next decade at a free cash flow breakeven of between $35 to $40 per barrel before any expansion or backfill opportunities are considered. Our onshore upstream operations at GLNG and Cooper Basin are lean and efficient, and we are confident we are now Australia’s lowest-cost onshore operator. By driving cost and efficiencies, we are increasing indigenous gas supply at GLNG while maintaining production levels in the Cooper. We are now focused on the next phase of growth with significant progress made on our opportunities across Northern Australia, PNG and Narrabri. The successful completion of the appraisal drilling campaign in the Barossa field in Northern Australia is encouraging and has strengthened the position of Barossa as a lead candidate to supply gas to Darwin LNG. And PNG, the exploration activities around Muruk have produced positive news and have confirmed the discovery of a potentially exciting new gas field. And, of course, on Narrabri, we have commenced the environmental approvals process. Importantly, Santos is not a single-asset company. The diversity of our core assets offers investors a strong portfolio of production and growth opportunities that are capable of delivering sustainable shareholder value over the longer term. Like all portfolios, some assets will be at different stages of the life cycle, however, all offer significant upside potential. Moving to Slide 7, I want to spend a few moments to talk about how Santos is working to deliver more gas to the domestic market. Since the ADGSM was announced, Santos has been working constructively with the federal government and our partners to achieve the desired outcome of affordable and reliable energy for Australian households and manufacturers that can coexist alongside a thriving gas export industry. We recently announced new gas supply arrangements with Engie to deliver 15 petajoules of gas to support the Pelican Power Station in South Australia. We expect to announce further domestic supply contracts of approximately 30 petajoules in the near term, and we are also in discussions to utilize our transport capacity positions to enable more gas to flow to the southern markets. Santos continues to believe that the best way to bring more gas to market is to remove moratoriums, encourage new gas development and limit export restrictions to uncontracted LNG and therefore protect contract sanctity and Australia’s international reputation. I’ll now hand over to Anthony to run through the first half results.

Thank you, Kevin. Applause to all of you. This is a good underlying result and the business is performing well. The first half shows a continuation of the Santos turnaround which began in 2016. These financial results also show a continued discipline in increasing free cash flow and prudent capital management. Moving to Slide 9. This shows the key financial metrics. Santos had a good start to 2017. We recorded an underlying net profit after tax of $156 million, an increase of $161 million on first half 2016. Our half year results include the impact of the $689 million impairment announced on the 15 of August. As a result, we reported a net loss of $506 million. Our financial focus continues to be on the four key areas of reducing cost, increasing free cash flow, debt reduction and disciplined capital management. Firstly, reducing costs. Unit production costs have decreased $8.08 a barrel. And although CapEx increased to $321 million from first half 2016, improved efficiencies and productivity gains have led to increased drilling activity in both the Cooper Basin and GLNG within existing CapEx guidance for 2017. Secondly, positive free cash flow generation. We achieved $302 million in free cash flow, excluding $116 million from asset sales. Our operating cash flow was $662 million for the half, and our forecast free cash flow breakeven is $33 a barrel, down $3.50 a barrel in 2017. Thirdly, net debt reduced to $2.9 billion through free cash flow, asset sales and the share purchase plan. Fourthly, capital management. Hedging has been undertaken for 2018 and, as already stated, no interim dividend was declared, with the focus remaining firmly on debt reduction at this time. On Slide 10, production and sales have decreased from prior period due to sale of non-core assets. Pleasingly though, our core assets have shown increases in both production and sales for the period. First half production was 29.5 million barrels of oil equivalent, a decrease primarily due to asset sales of 1.2 million barrels of oil equivalent. Production from the five core assets increased by 2% to 25.3 million barrels. 2017 full year production guidance is maintained at 57 million to 60 million barrels. And as Kevin mentioned, we are upgrading full year sales volume guidance today to between 77 million and 82 million barrels of oil equivalent based on strong sales in our first half 2017 from our core assets. On Slide 11, Santos’ turnaround strategy to deliver low-cost, reliable and a high-performance business is now taking effect. The company’s focus on cost out and efficiency gains, combined with higher crude oil prices of $54.79 a barrel, up 28% from first half 2016, drove earnings higher. Product sales revenue were $1.5 billion, up 22%. EBITDAX was up 46% to $718 million, and underlying net profit after tax up from a $5 million loss to a $156 million profit. Moving to Slide 12, with our free cash flow breakeven now at $33 a barrel, we are now well placed to continue to reduce net debt as well as reinvest for growth. The turnaround in free cash is quite evident on Slide 12, with first half 2017 consistent with second half 2016 and over $400 million better than first half 2016. Operating cash flow increased 127% to $662 million, and the business generated $302 million in free cash flow. On Slide 13, first half CapEx was up 13% to $321 million, and this includes the Muruk acquisition and exploration drilling costs as well as the Barossa appraisal campaign. Improved efficiencies and productivity gains have resulted in increased drilling activity in both the Cooper Basin and GLNG within existing 2017 CapEx guidance, which is maintained at $700 million to $750 million. With significant sustainable cost out and efficiencies now embedded in our onshore operations, we will look to increase activity in 2018 and now expect to drill between 70 to 80 wells in the Cooper Basin and approximately 250 wells in GLNG. Moving to the net impairment on Slide 14. Since the last carrying value assessment at 31 December 2016, there’s been a change in a number of relevant assumptions, but principally lower forecast to oil prices. These factors resulted in a $689 million after-tax impairment, which was previously flagged to the market on the 15 of August. On Slide 15, our debt reduction objectives are being achieved. Net debt reduced to $2.9 billion through a combination of free cash flow, previously announced asset sales and proceeds from the share purchase plan. In the first half, we also made an early $250 million repayment to the 2019 export credit agency debt and extended $860 million of undrawn bilateral bank loan facilities that were due to mature in 2018 to 2022. Slide 16 addresses our debt maturity profile. As today’s results clearly demonstrate, Santos has improved operational performance, cut cost, generated strong free cash flow and reduced our free cash flow breakeven. From this position of strength, we have notified the euro hybrid subordinated note holders of our intention to redeem at the first call date on the 22 of September 2017. The redemption is in line with the company’s strategic focus on debt reduction, cost reduction and prudent capital management. The hybrid is our most expensive debt facility. Refinancing this with lower-cost debt is expected to lower Santos’ free cash flow breakeven further and generate annual interest cost savings of approximately $40 million per annum going forward. We have ample liquidity of $4.2 billion to redeem the hybrid, including $2.2 billion in cash and $2 billion of undrawn bilateral facilities. These bilaterals can be used to provide bridging finance if required until a new debt instrument has been executed. Debt markets remain buoyant and open to Santos, and we are confident of refinancing with lower-cost, medium-term debt in the near future. We will use some cash to redeem the hybrid, but retain sufficient flexibility to fund our 2019 debt maturities and growth projects across the portfolio. Slide 17 sets out oil price hedging. Using zero-cost three-way collars, we are 4.6 million barrels hedged for the remainder of 2017 and 9.7 million barrels in 2018. The graphs on the slide shows how the pricing of these hedges works. We are continuing to review opportunities for further hedging in 2018 and beyond. In summary, today’s results demonstrate good underlying business performance and continuation of the turnaround which has begun in 2016. Our financial focus will continue to be on four key areas of reducing costs, increasing free cash flow, debt reduction and disciplined capital management. I’ll now hand back to Kevin.

Thank you, Anthony. Before I get you through a review of our asset portfolio, I’d like to acknowledge the great work Anthony and his team are doing in strengthening our financial position. An excellent example is our ability to redeem the hybrid from a position of strength. This decision allows us to achieve cost savings of around $40 million per annum and will reduce our free cash flow breakeven position further while leaving sufficient cash in the balance sheet to manage debt repayments and fund growth. This is something Santos would not have been able to do a year ago. I want to thank Anthony and his team for the important role they’re playing in our business turnaround. Let’s start our operations review with PNG on Slide 19. PNG LNG continues to demonstrate that it’s a world-class LNG project with significant upside. The project continues to operate significantly above nameplate, reaching an annualized rate of 8.6 million tons in June, the highest monthly rate since startup. EBITDAX increased by 23% to $203 million due to the strong operating performance and higher LNG prices. The Muruk gas discovery is an exciting opportunity which I will talk more about on the next slide. Our aim is to be a partner of choice in PNG. Santos will seek to participate in opportunities, including Muruk, and also other opportunities such as P’nyang. We will collaborate with the foundation project partners to facilitate the potential expansion of PNG LNG to include further trains. I would like to acknowledge the outstanding contribution of ExxonMobil as operator and Oil Search as our key partner in the PNG LNG project and thank them for their continued support. On Slide 20, Muruk is a potentially significant new gas field located 21 kilometers northwest of the Hides production facilities. As you know, Santos farmed-in to Muruk late last year, and we were pleased to announce a discovery only a few months later. Data from the drilling program, including three sidetracks, is currently being evaluated to assess a potential gas resource. But I can tell you that our Head of Exploration, Bill Ovenden, is pretty excited at what he sees in Muruk and in the adjacent Karoma prospect. Both have the potential to be significant gas fields that will provide PNG LNG with flexibility regarding future expansion options. Muruk represents a significant addition to Santos’ PNG resource base and can provide PNG LNG with further expansion options. We’re excited to increase our exploration and appraisal activity levels in PNG next year. With our partners, Exxon and Oil Search, we are planning for an appraisal program, including seismic and more drilling on Muruk and Karoma. Positive discussions are ongoing with partners in respect of Santos’ future alignment in both exploration and discovered resources outside the PNG LNG project, and we will continue to invest in PNG and look to participate and support our joint venture partners in the expansion of the PNG LNG project over time. Turning to Northern Australia on Slide 21. Darwin LNG and Bayu Undan continue to produce strong results. Total production in the first half was 2.1 million barrels of oil equivalent. Darwin LNG continues to be an important and strategic infrastructure project for the development of onshore and offshore resources. On Slide 22, the successful completion of the two-well appraisal program for Barossa have significantly reduced resource uncertainty and confirmed the high deliverability potential of the reservoir. Barossa has strengthened its position as a lead candidate to supply backfill gas for Darwin LNG. Along with the operator, ConocoPhillips, we are reviewing the results of these wells and will provide an update on any positive impact to our resource position at year-end. Good progress is also being made on the proposed development and we expect to be in a position to approve FEED in early 2018. I would also like to take this opportunity to thank and congratulate ConocoPhillips on their continued outstanding operatorship of our Darwin LNG facilities and the good progress we are making with the Barossa opportunity. We are also increasing our exploration and appraisal activity in Northern Australia. We recently completed a seismic survey over permit WA-459P in the offshore Bonaparte nearby our Petrel, Tern and Frigate fields. And in the onshore McArthur Basin, Santos has resolved the dispute with Tamboran in relation to its 75% interest in the joint venture. We look forward to progressing our activity plans on this potentially large resource pending a successful outcome with the fracking moratorium. On Slide 23, the Cooper Basin is a shining example of the transformation of Santos to a lean, low-cost producer. Total production in the first half was 7.1 million barrels of oil equivalent, which was lower than the previous year, reflecting natural fuel decline, however, at a much reduced decline rate compared to previous years. Efficiency and productivity gains continue to be made by delivering improvements to well and plant availability. Production costs were down 12% to $9.70 per barrel. And importantly, the asset delivered significant free cash flow. Slide 24 provides more granularity on the significant improvements in cost and efficiency in the Cooper. Drill costs have been reduced significantly. Brett’s team is now delivering completed gas wells at an average cost of $2.8 million per well. That’s almost 60% less than three years ago. Drilling efficiencies continue to be realized enabling us to drill more wells with the same rig count. In 2015, we drilled 31 wells, but in 2017, plan to drill 52 wells with the same two rigs. Vince has continued to drive down production costs. We are targeting to achieve $9.40 per BOE this year, more than 40% lower than three years ago. Since establishing a standalone onshore upstream development division in the second half of 2016, the efficiency gains being delivered by our drill, complete, connect process has provided us with the confidence to drill more wells to build on these impressive results and provide a stable platform of Cooper production for the next decade. We are planning to bring a third rig into the basin towards the end of this year. These improvements in development and production cost highlight why we’re confident to write-up the Cooper Basin value at these results. I am also confident that with planned activity levels, we will be able to increase Cooper Basin production over time and deliver more gas from the Cooper to the southern domestic gas markets. GLNG continues to ramp up production. First half LNG production was 2.4 million tons with 42 LNG cargo shipped. Upstream equity gas production continues to build with strong performances from Fairview, Roma and Scotia. At Roma, production is up 66% this year and has now exceeded 50 terajoules per day. Importantly, the first row is bought online and the Phase 3A development have produced immediate gas with higher rates than expected. Drilling and completion cost continue to fall and cycle times have improved significantly. This allows GLNG to increase drill, complete and connect activities in order to unlock more near-term gas supply. I want to take this opportunity to provide clear guidance as to how we think GLNG will perform over the medium-term. We expect the LNG sales will continue to ramp up to around 6 million tons per annum by 2020 and maintain that level. This outlook is based on our current production expectations of indigenous supply and our current contracted third-party gas, the majority of which is export-compatible. Any additional third-party gas or indigenous production will offer future upside. GLNG is a long-life gas asset with significant potential. I believe in the longer term, GLNG will deliver significant value to our shareholders. In Eastern Queensland, Santos has significant volumes of uncommitted gas across the Combabula, Ramyard, Spring Gully and Denison fields. Working with our partners, plans are underway for further development of these fields. Santos is actively managing our gas portfolio in Queensland to free up gas from the Cooper Basin for the domestic market. This will drive value from our portfolio and enable greater participation in the domestic market going forward. On Slide 26, and similar to the cost-out story we see in the Cooper, we are also making significant progress in Queensland. Current Roma wells are being delivered for less than $1 million per well. That’s drilled, completed and connected. Cycle times are down to 3.6 days, rig release to rig release. This proven cost performance now allows GLNG to increase development activity and unlock more near-term gas supply. We recently upgraded our drilling target for this year to 170 wells and expect to increase this again next year to 250 wells. On Slide 27, the Western Australian gas business continues to be strongly cash flow-positive. Total production in the first half was 4.3 million barrels of oil equivalent, slightly lower than last year due to lower customer nominations. Santos will continue to seek to grow production and market share in the Western Australian domestic gas market. We have a good relationship with our operator, Quadrant, and I’d like to take this opportunity to thank Brett Darley and his team for the great job they’re doing operating our WA domestic gas assets. In 2016, we decided to run the Asian assets under a separate management team to allow Santos to focus on its core assets without distraction. These assets are performing well and are being run for value. The Narrabri gas project has the potential to supply significant volumes of gas into the East Coast market. We are currently working on plans to bring Narrabri back into our core portfolio where we will look to apply a low-cost drill, complete, connect framework developed in the Cooper Basin and GLNG upstream operations to increase the value of this project. The project is currently seeking environmental approvals before moving into the appraisal phase. A final investment decision will then be made regarding the development. However, any significant capital expenditure will only occur when the project has the necessary approvals in place. To conclude, the Santos turnaround strategy is on track and is delivering strong results. Whilst we continue to focus on cash and operational efficiencies, we will also increase the capital investment in the business to maintain and grow production. Santos will continue to maintain a disciplined and focused approach to capital management. Our priority is debt reduction, whilst retaining the flexibility to invest in development and growth opportunities that are aligned with our core assets. I remain confident that Santos will deliver significant value to shareholders over time. The business is turning around and there is more to come on our cost out program. With our stronger balance sheet, we are now well-positioned to deliver value in the current oil price environment. I continue to be excited by the opportunities before us and I look forward to reporting on our progress and success. We are now happy to take your questions.

Thank you very much. Ladies and gentlemen, we’ll now begin the question-and-answer session. [Operator Instructions] Your first question today comes from the line of Dale Koenders from Citigroup. Please go ahead.

Good morning, gentlemen. Just firstly, I was hoping to better understand the balance between the desire to grow activity and growing free cash flow, given this has been sort of where the wheels have fallen off in the past. With an increase in rig activity in the Cooper and GLNG, what does this mean for the group CapEx versus production? Do you think that the reduced well cost will absorb the increased activity and CapEx to remain flat all else equal?

Yes. Good morning, Dale. Look, that’s a really good question. I think the – as you heard me say this morning, Dale, we’re very focused on our operating model being a very disciplined and focused operating model. We have got free cash flow imperatives as part of that model to ensure that we have the discipline across our operations. And so our focus over the last 1.5 years has been very much on reducing our cost and cost out of the operations to allow us to increase activities so that across the two assets we operate in particular, we can drill more wells or less or for the same CapEx. We’ll obviously give guidance at our Strategy Day, our Investor Day later this year on those CapEx and activity levels for 2018 and going forward. But I think you have summed it up perfectly in that going – to be able to drill 52 wells versus 32 that we’re drilling with the same two rigs two years ago shows the improvement that we’ve been able to drive through the business. And it has been very much the focus, is get the cost right, get the discipline right, and then increase the activity levels in a disciplined and measured manner.

So should we think that the mandate that’s really being given to the business unit VPs is a focus on delivering growth in free cash flow rather than shackles are off and it’s time for production growth?

You can assume that’s a very disciplined message that’s been given through the business, yes.

Okay. And then in terms of the 70 to 80 wells in the Cooper, what does that deliver given the 50 wells per annum was a sustained case. Is this growth in gas to fill equity requirements for the 30 petajoules per annum domestic contract?

Well, no, don’t relate that to that one contract. We think of our contracts as being serviced from our broader gas portfolio. In terms of the activity levels and what does that mean, it means, as I’ve been saying repeatedly for the last 12 months, we’re very focused on, first of all, arresting the decline in the Cooper and then turning that back around and growing production to a stable base. And as I said today, we see that stable base being a base we can maintain with a very disciplined operating model at the Cooper Basin for the next decade.

Okay. And then finally, maybe a question for Anthony. Can you provide some thoughts around the plan for your hybrid refinancing in terms of the new debt cost maturities call in and the need for liquidity for Santos given you almost got a very large lazy cash position at the moment?

Yes, thanks Dale. So as I said, we will use some cash as we don’t need to refinance the full $1.15 billion as debt. We’ll reduce the gross debt size with any refinancing that we do. Our focus though is clearly on 2019 debt maturity, and that’s the prudent way that we’ll manage our cash balance. So while using some of the cash in reducing the debt size, we’ll basically achieve those interest savings of up to $40 million per annum that I spoke about. And until the 2019 debt is repaid and refinanced, we’ll hold enough cash in liquidity to make sure that we can meet those commitments along with the business commitments that Kevin is talking about.

And what does that mean for dividend sort of going forward?

Well, as you heard this morning, at this point in time, our focus is very much on debt reduction. We’ve got a debt reduction target through to the end of 2019. And the decision for the board results are half year – sorry, decision on dividends results for the half-year period is a decision for the board. But we have absolute focus on debt reduction and meeting those debt reduction targets.

Okay. Thanks, guys. Good result.

Thank you, Dale.

Your next question comes from the line of Ben Wilson from Royal Bank of Canada. Please go ahead.

Good day, Kevin and Anthony. I had two questions, one on PNG, specifically around the Muruk discoveries and how you potentially foresee your ability to be able to somehow get those volumes into what may well be a unitization of some sort of framework towards the end of the year and when that’s possible? And secondly, I just wanted, hopefully, to get a sense of the additional volumes you’re looking to contract in the East Coast, whether we should take that as an indication or a leading indication of the magnitude of any potential reserve upgrades that we may see out of the Cooper or in the partly broader East Coast portfolio heading into February of next year.

Thank you, Ben. And like all good questions, those were about 10 questions wrapped up in that one question. So let me try and let me try and dissect that and answer each part of it. So here we go, right? Let me start with PNG. First of all, let me just say we are really excited to be part of the picture in PNG going forward. And the Muruk discovery at the end of the year and through the first quarter of this year has opened up potentially a very significant new field. And there’s quite a bit of prospectivity around that. So we look forward to working with Exxon and Oil Search in 2018 with additional seismic programs that we want to be part of or we’re supportive of and the additional drilling programs for both Muruk and the Karoma prospects. The reality is that I can’t sit here right now and tell you what the development program is going to be for expansion, but undoubtedly, there’s going to be expansion and backfill development in the future at PNG. We want to be part of that and being part of the resource joint ventures, that positions us to be part of that. And so we’re supportive of those development programs. And as I said there, later on, we’re continuing discussions with the foundation partners for alignment and farm-ins to other opportunities – other upstream opportunities to position us to be part of the future expansion programs. And that’s really all I can say at this point in time, other than to say that we’re supportive and we’re involved in those conversations with the partners. In terms of domestic gas contracts, first of all, I’d just like to say that we have, over recent months, been part of what I would call really collaborative efforts by our joint venture partners at GLNG. And you saw the Engie announcement the other week where we have managed to agree with our partners to release some gas, and some of that gas is coming through the Santos portfolio, to be able to supply gas to the Pelican Point Power Station next year and the following year. And so that – to me, that was a very significant step in the right direction. We’re continuing those discussions with our GLNG partners to look at more opportunities. We’re also looking at opportunities to take more gas out of the Santos portfolio. We have quite significant uncommitted gas volumes in Queensland that are part of our broader portfolio that we’re looking at developing plans to unlock some of those reserves. And that would feed into our portfolio to enable us to have more flexibility in how we meet future domestic gas demand. And in the longer term, yes, we’re looking to develop more reserves over time. But in terms of reserves positions, I wouldn’t want to give any guidance today. We have an annual reserves process, and at full year results each year we give updates on our reserves position. But what I can say, Ben, and I think we’ve said this all along, is that there’s plenty of resource, both in the Cooper Basin and across the East Coast generally. And the way we unlock that resource is to take our development cost down. We’ve seen how that’s worked in the U.S., and we’re committed to that journey by breaking out our upstream onshore development division in 2016. We’ve already seen very significant strides in reducing those well costs and those development costs and we’ll continue to do that, and I’m very confident if we can do that, we can turn more of those – more of that resource across the East Coast into economic reserves.

Okay. That’s great. Thanks, Kevin.

Thank you, Ben.

Your next question comes from the line of Mark Samter from Credit Suisse. Please go ahead.

Yes. Good morning, guys. A couple of questions, if I can. Cooper Basin, we’re thinking about obviously the well count going up and with, obviously, production. In terms of a decent chunk of cost in the Cooper are going to be pretty fixed costs. I mean, I don’t know, I guess it’s why you’ve been talking taking cost out as well. But how should we think about unit cost production in the Cooper as we start to ramp up production?

Yes. Look, Mark, it takes a certain cost to operate a plant, and I think that’s what you’re referring to. So some of that is just as you suspect and you’re spot on. We do see more scope for cost reduction there going is about size in the Cooper Basin for its new future versus it being sized for its past. And so we see over the course of the next couple of years, continued cost reduction across the operations in the Cooper. It should also be pointed out, Mark, that, of course, we get a return to the non-Cooper Basin upstream – non-Cooper Basin infrastructure owners who are upstream developers around the Cooper Basin when their production comes through our facilities. So as I’m sure you can see from other sets of results that our plan’s for others to increase their production over the course of the next few years, and that increase is additional processing revenue for the SA joint venture partners. And so that helps us, of course, with our own unit cost picture there. And I think the big one for us though, Mark, is the upstream development cost. You can see those Cooper Basin costs have come down, drilling – drill, complete, connect costs have come down quite considerably over the course of the last couple of years. And we still think there’s more to go in that journey as well.

Okay. I’m sure – I don’t know if you guys even have this. I’m obviously been doing internal working numbers, but when we think about the well count for 2018, is this about getting back up to a level and then that number should drop in 2019? Or are we thinking about we should be thinking about that level being sustained for a couple of years? I mean, just give us a feel for how much gas could be sold in Cooper.

Well, look – yes, look, Mark, I think, as I said – well, I don’t think – I said earlier that we’re moving to – looking to bring a third rig in before the end of this year, and we’d be looking to sustain the three-rig level of activities going forward for quite a few years to come.

So there slightly to bend the question and without foreshadowing reserves and what they might do, I mean, clearly, you, as a business, have got an awful lot of confidence that you’re going to be able to develop material volumes from the Cooper outside of the Horizon contract, which you wouldn’t do with a pretty firm underpinning internally on that bid?

Yes, look, we’re obviously confident if we’re increasing the rig count. And I’ll look forward to giving you more clarity and guidance on that at our Investor Day later in the year.

But just a quick question on the debt reduction target just so we can confirm, reconcile our numbers on that. Should we assume that’s being done on your old deck you used to test impairments and that the income doesn’t assume any divestments in that as well?

Well, the debt reduction target’s independent of the oil price curve that we’re using. The debt reduction target, that’s our target. Now of course, if the oil price was to go to $20 per barrel, we may struggle to achieve that target and that could be the reason why. But as the debt reduction target is a target we’ve set for the business, so when we are setting our CapEx plans, our OpEx plans and our activity plans, we’re doing it with that in mind. And we test our economic assumptions and our budget planning against different price tags to the impairment price that you’re referring to.

Perfect. Thanks very much.

Your next question comes from the line of the Nik Burns from UBS. Please go ahead.

Thanks everyone. Just a question on the implications of the ADGSM on GLNG. You flagged the 6 million tonnes flat output. Should that have an asterisk next to it basically depending on what the minister determines is a shortfall that GLNG will need to make available for the domestic market?

Sorry, I missed who was asking the question?

Nik. Nik Burns here.

Sorry, Nik, I should have recognized your accent there. Look, no, the – I wouldn’t tie it to the ADGSM. Yes, we’ve taken a long-term view in GLNG. And our view here simply is that we believe in this project. We think it’s a 30-year plus project. We think the market needs some solid guidance because there’s been a lot of fluctuations over the last few years and the forward kind of forecast for GLNG. But the reality is that we are not counting any new third-party gas, and we’re not – we’re only really counting the indigenous gas and resources that we have today and the third-party gas that we currently have contracted today. Any additional gas that we’re able to access in the future, whether that be new third-party gas in the future or additional resource conversion or additional indigenous gas that we’re able to acquire, would be further upside on the project. And we want to stabilize the look-forward, if you like, the forecasting for GLNG and give some clarity around that by doing that. Now you could accuse us of being a little bit conservative in that, but I don’t apologize for that. I think the stability for the project and the new forward plan is the right way to go and plan our activity levels accordingly.

No, that’s fair. Look, just our other question is around future CapEx for GLNG. First of all, well done on getting those well costs down, that’s a fantastic result. You flagged 350 wells circa next year. Just thinking beyond just well CapEx, as you are developing new areas, how much surface infrastructure will be required to support the new wells over the next few years?

Well, depending on where we’re building. There’s been quite a bit of infrastructure already laid down around our GLNG upstream acreage. But obviously, there will be more and we’ll look at each of those projects and the economics of those projects as they come forward. But I can tell you, we’re already in the process of approving projects for next year, and the forward economics for those upstream projects have improved dramatically as a consequence of the cost out that you referred to earlier on. It’s not just drilling cost. This is drill, complete and connect cost. And the connect cost includes the connect gathering infrastructure – gathering system infrastructure that goes with these wells. And it’s also the cycle times. So connecting these wells faster after they’re drilled to get the gas to market faster is a big part of the transformation – the successful transformation we’ve seen in our GLNG upstream operations.

That’s great. Thanks, Kevin.

Thank you.

The next question comes from the line of James Redfern from Merrill Lynch. Please go ahead.

Kevin, good morning. Just a couple of questions, please. The first one, I don’t want to belabor the point on dividends, but just want to understand, so your target of reducing that debt below $2 billion by the end of 2019, should we assume that no dividends will be paid until that point? Just obviously, to give us a bit more guidance on that. And I’ve got two more after that.

Look, James, I can’t answer that question. Dividend decisions are a decision for the board, and we will review that obviously each time we go to announce half-year and full year results, yes?

Okay. Okay, I got it. And just in terms of the non-core assets that are being run separately for value and potentially divested. Can you update on whether there’s a formal sale process being started for any of those assets and whether you’ve received strong interest from other parties in any particular assets?

Yes, look, I mean what I can tell you is that they’re being run separately, as we said previously, and run for value. And really, I think the way to think of the difference between core and non-core in our portfolio is the core assets are the assets in which we prioritize investment going forward, yes? It’s not a case of the not loved assets. We still love some of those assets. We are currently not running a formal sales process, although, of course, we have received interest in these assets because some of these assets are really good assets. But there’s no formal sales process at this time. There will be complexities about selling a lot of these assets, but the reality is if we were to get an offer that represented a positive value outcome for Santos, then, obviously, we would consider that given that they’re non-core. In the absence of a value-positive offer, the focus would be running them as hard as we can to maximize the value. And I can tell you, already in the short time since we brought them out and run them separately, we have seen significant cost out in those operations and indeed, the production from those assets this year is ahead of budget. So they’re performing very strongly. You saw recently the announcement of impairing AAL, and the reality is that we have development projects in that portfolio of assets like AAL and Bestari that we wouldn’t be prioritizing in the near- to medium-term for development. So if offers came in for those projects, of course, we would be interested in selling those assets.

Okay, good. And just one last quick one. The 15 petajoules gas supply going to Engie over two years seems about 13% of your Cooper Basin gas production. Just wanted to understand the – obviously, the price is confidential, but can you tell us whether the sales to Engie are based on the gas price X Moomba or some other location? Because I’m guessing that the price is a lot higher than the realized gas price under the Horizon gas contract, so just want to understand that a little bit better.

Look, James, we wouldn’t discuss the contract prices publicly. They’re confidential. I can confirm your very last point though.

Which one was that?

They’re better than Horizon pricing.

You can’t?

I can.

You can. You can. You can. Okay. All right, very good.

My accent must have confused you there, James. It’s – I do apologize for that. As you can tell, from the Game of Thrones fans, I come from north of the wall.

Very good, very good. Okay, thanks, Kevin.

Thank you.

Your next question comes from the line of Adam Martin from Morgan Stanley. Please go ahead.

Good morning. Just back on the Cooper Basin, obviously done very well on the drilling side of the equation, operation costs, et cetera. Can you just give us a bit more color around production performance per well, type curves, et cetera? I mean, clearly, one of the dynamics in sale in the U.S. has been improved type curve performance. Cooper Basin not shale, but just trying to get a sense of what you’re seeing there. Are different completion techniques improving things, making things worse, just give us a bit of a color there?

Well, look, I mean – look, a few questions. I’m not going to go into individual well takers. What I can tell you both in GLNG and in the Cooper Basin, we have been trialing a number of things over the last 18 months or so, not only new completion technologies or techniques, but also new fracking technologies, particularly in the Cooper Basin. And what we have seen is we’ve seen an improved well performance in the Cooper Basin. I think there’s more to go in that journey though, frankly, but we have seen improved performance – well performance in the Cooper Basin. And as I said earlier on, in the Phase 3A wells in GLNG, those wells have come on strongly and stronger than anticipated. I think, however, it’s not just about the drilling and completions, our understanding of the reservoir and how to manage the reservoir and the coal seam reservoirs in Queensland has improved dramatically since we put that subsurface focus in place. And Fairview field is a prime example of that, where it’s completely outperforming our expectations year-to-date and it’s giving us a lot of optimism as to – in terms of our understanding how to manage that reservoir and get more from it.

Okay. And just on the cost at Roma, it obviously looks pretty good. Are there sort of comparables in the well dips, fracs, et cetera? And what’s driven that $600,000 or $700,000 increase – sorry, decrease from Roma 2B to Roma 3A, can you just give us a bit more detail what’s driving that result?

Yes, okay. Well, look, I mean, we – first of all, I’ll just emphasize in case anybody picked that up wrongly, it’s a decrease in cost, yes. But what’s driven it is good process, very high-performance team planning and execution and being focused. Over the course of the last 18 months, our upstream teams have had four trips to the U.S. and met with the – some of the high-performing shale operators in the U.S. and looked at their entire work processing, from planning all the way through to production operations, and looked at their fast-learning cycle times to try and understand what we could do better here in Australia. And we’ve implemented many of the things that we’ve seen over there very quickly. There’s a large focus on our upstream onshore division on learning cycle time and fast learning. And I think Roma is a prime example of how quickly they’ve been able to do that. And so it’s not just about drilling faster, although that is part of it, it’s about technologies we’re applying and it’s also about processes, logistics, the full life cycle of operations.

And so on the drilling CapEx of both GLNG and Cooper, should we expect the trend can continue a little bit or you’re near the bottom?

Look, I mean, I think there’s more to go. But I don’t think you ever say a bottom. I mean, any continual improvement process has to always strive to get better. And it’s not just about well costs. It goes back to the previous question, it’s also about better well performance and better well design, and so we’ll continually strive to improve from wherever we are at any point in time.

Okay. Thanks for that.

Thank you.

Your next question comes from the line of John Hirjee from Deutsche Bank. Please go ahead.

Good morning, everyone. Kevin, can I just ask, given the very good cost out performance in both Cooper and GLNG in terms of drilling in particular, and particularly given your background, how much of that do you think is sustainable going forward given you can only ask so much from the contractors and squeeze them so much because they’ve – they’ll hurt that they’ve got to get something back in return. So how do you think about sustainability of these costs going forward, particularly as the oil price starts to move up a little bit and inflation comes back into the cost base?

Yes. Look, I think that’s a great question, John. Thank you for that. One of the things that we’re very focused on is understanding the split between cyclical cost reduction and structural cost reduction. And what we would say today is that 70% of the cost that we have taken out are structural. And we obviously want to increase the sustainability of the cost out. But Apache in Cooper Basin, to give you an example of what I’m talking about, is not just contractor rates. Indeed, some of those contractor rate reductions we had have only just recently kicked in because they were longer-term contracts, so they were still on old rates – old higher rates before the oil price dropped at the end of 2014. But an example in the Cooper Basin would be that wells that were taking 28 days are currently being drilled around 12 days on average. And so that 16-day reduction has got nothing to do with oil price, that’s purely performance. And that’s better technologies, that’s better practices and obviously leading to time-related cost that we can lock in. And so we would refer to that as structural cost. And as we said, at least 70% of the costs we’ve seen across GLNG cost out, so we’ve seen across GLNG and the Cooper Basin, we would categorize as structural cost that we would lock in through the cycle.

Very good. Okay. And just referring to GLNG in particular, with the map you’ve given of 250 wells in 2018, how should we think about that in the context of half-on-half? Do you expect to be fairly even? Or will there be sort of a bulk drilling campaign and then towards the second half, it will be less? I’m just trying to work out cash flows versus half-on-half.

Look, at this point in time, John, I would be thinking sort of an even spread throughout the year. Obviously – hopefully, we’ll be able to give you a bit more guidance on that at the Investor Day later in the year. But I’d be thinking of that as fairly evenly spread throughout the year at this point.

And one last question, if I may, to Anthony. In terms of – I see in your free cash flow there’s not a lot of cash tax being paid. When do you expect to be in a position to go back to sort of normal cash tax? Or in other words, when do your sort of tax losses sort of exhaust themselves?

Yes, thanks John. So from an Australian tax position, we’ve got a large tax loss base, obviously, from the impairments and practice that we’ve done over the last few years. In a sense of payer IT and international taxes, they’ll be paid when profits are made, and they’re very heavily dependent in those jurisdictions on oil price.

Okay, thank you very much.

Thanks, John.

The next question comes from the line of Andrew Hodge from Macquarie. Please go ahead.

Thanks guys. First question I have is really kind of a two-parter on the project side. I noticed that your joint venture project, Premier, in Vietnam have done a pretty substantial upgrade. And I guess what looks like an increased reserve cut cost. I sort of noticed you guys didn’t kind of comment on it but touched on Narrabri for a few times. I just wanted to see how you guys kind of think about that. And then also about for Darwin LNG for the infill drilling, what that should start to mean for production and whether that’s already kind of factored into your overall decline curves and whether we should be thinking about a delay for the overall pullback in volume.

Look, I mean, first of all, with the reserves, yes, we’re aware of Premiere’s upgrade, but it – we upgrade our reserves annually with our full year results, Andrew, and so we’d expect to – any change in our reserves position to come through at that point in time. With Narrabri, as you know, Narrabri was heavily impaired prior to my time, and we’re really looking at that project now in developing a project plan for if and when we get the environmental approvals, the approvals that we’re – the process that we’re currently going through for those approvals. Narrabri is a very significant resource, but we don’t have any reserves for that because of the state of play of our project. I think from memory, that’s around 1.7 Ts of resource that we had at Narrabri at one point in time. So look, I mean, we’ve got a lot of potential stuff there, but we just have to wait until we develop those plans, and we’d update that through the annual reserves process. As far as Darwin’s concerned, the wells were successful, the strength in Barossa as the backfill opportunity for Darwin, and we just have to wait and see how that project develops. We’re pushing hard for FEED in 2018.

I meant for the backfill for Bayu Undan for the first gas there.

Oh, the Bayu Undan backfill, sorry. We are still assuming a fairly steady production through to end of field life.

Okay. And then second question was just for Anthony around hedging. I noticed you guys had done a pretty substantial increase for 2018 hedging compared to where you were at the quarterly. I just want to get an idea about now that given you’re at sort of low-teens percentage for overall forecast for next year for sales hedged, do you have a target for what you’d be kind of happy with for overall hedging numbers?

Yes, look, we’re still evaluating 2018 hedging and beyond. For now, we’re okay. We will still look at it over the coming months and obviously, that plays an important part as we’re developing our budget and plans for next year. For now, we’re okay, but we will still evaluate further.

Okay. And then I guess the last question I just want to ask is always just on the cost side. I think it, kind of, second onerous pipeline contract, but just kind of thinking about cost for the second half, are we going to be continuing to see sort of a – I know you guys have been talking about at the Investor Day last year targeting sort of $0.8 that you do upstream, 130 for midstream at GLNG, but just trying to think about how costs are going to be going forward for the rest of this year if we’re going to be seeing sort of a even pullback in terms of a closer tightening towards that $8 number.

So, yes, look, from the onerous contract perspective, that basically relates to unutilized pipeline capacity and it changes with our assumptions relating to price and capacity. So ignoring the onerous contract part of the pipeline tariffs, I think that you can see the run rate for pipeline tariffs processing, et cetera, and tolls is consistent – is starting to get to a consistent level, and so you can use that as a flat line proxy going forward.

Okay. And just in terms of, I guess, cost for the rest of the year and, I guess, Kevin touched on it a couple of times some of the questions, but just in terms of, given that you guys have tightened the guidance a little bit more but everything seems to be performing pretty well in terms of targets, just whether or not you – you’re thinking about – might be sort of how much scope there is to be able to try and pull back to get that number even closer towards the overall $8 number or beat it?

Well, I think at this stage, Andrew, there’s no change to guidance. And if there is any change, we’ll update that at a future point.

Okay. Thanks, guys.

Thank you.

There are no further questions at this time. I would like to hand the conference back to today’s presenters. Please continue.

Okay. Well, look, just to summarize, I think it’s been a fairly strong first half. We’re going to stay very focused on the things that we talked about in this morning’s call. I’d just like to thank you all for your time this morning, and I look forward to talking to many of you over the course of the next few weeks on our various roadshows. So thank you, at this point, I’ll end the call. Thanks very much.

Ladies and gentlemen, that does conclude our conference for today. Thank you for participating. You may now disconnect.