Kevin Gallagher - Managing Director, Chief Executive Officer Anthony Neilson - Chief Financial Officer

Thank you for standing by. And welcome to the Santos Limited 2019 Half Year Results Conference Call. [Operator Instructions]. I would now like to hand the conference over to Mr. Kevin Gallagher, Managing Director and CEO. Please go ahead.

Good morning, everyone. Thank you for joining us for Santos’ 2019 half year results. With me today is our Chief Financial Officer, Anthony Neilson. I’m delighted to note that Santos has delivered record financial results for the first half. These results demonstrate the strength of our disciplined cash generative operating model and a successful integration of the Quadrant acquisition into our business. I’m also very pleased to say we have continued to drive unit cost down and deliver efficiency gains despite cost pressures seen across our industry. Before we start, I’ll draw your attention to the usual disclaimer on slide two. I’ll start with some opening remarks about our performance, before handing over to Anthony to discuss the financial results, and after Anthony’s presentation, I’ll take you through our operations and growth opportunities before opening the call to questions. Moving to slide three; our clear and consistent strategy combined with a disciplined operating model continues to deliver strong financial results for the company. The half-year highlights are shown on the slide and include strong growth and free cash flow, Underlying NPAT, EBITDAX and sales revenue. Importantly, these results also demonstrate that the acquisition of Quadrant has delivered what we promised. The results highlights are that we generated $638 million in free cash flow, up 74%. EBITDAX is up 43% to $1.3 billion, and underlying profit is up 89% to a record $411 million after tax. Pleasingly, the Board has declared an interim dividend of $0.06 per share fully franked. This is up 71% on the previous interim dividend. The dividend is consistent with our sustainable dividend policy, which targets a range of 10% to 30% payout of free cash flow. Moving to, slide four. Our journey to become Australia’s safest operator continues. Our core value at Santos, as I always safe value, this means that every single day, every person who works at Santos is focused on safety and going home in the same condition that they came to work. Our LTIFR performance has improved back to 2014 levels, but with significantly higher activity levels. Our injury severity, as measured by the number of injuries graded moderate, harm or greater, has also declined over the past three years as shown by the gray bars on the chart. But we still have to do more. In July, we stopped our operations across all Santos field and office location to Stand Together for Safety. I personally hosted Stand Together for Safety events at Moomba and Port Bonython. I wanted to be clear that everybody at Santos has the authority to stop the job if they felt it is unsafe. It was clear from these conversations that our people are committed to care about the safety of themselves and their workmates and want to make this an area of competitive advantage for Santos. We’re also focused on Process Safety, where I’m pleased to say our focus on preventing loss of containment is delivering improved performance. Moving to, slide five. I have said before that we are running this business on a balanced portfolio basis, a portfolio that generates sustainable free cash flow through the oil price cycle. What I mean by balanced is in terms of our asset mix. It’s a balance between on-shore and off-shore, between natural gas and liquids, conventional and unconventional and of course a balance between oil and CPI linked pricing and we’re getting the balance right. The Quadrant acquisition has increased our weighting to CPI linked pricing. As you can see in the pie chart, that’s just now about 35% of our sales and gives us a nice natural hedge component in times of volatile oil prices. This underpinning cash flow is important as we begin to move into a major growth CapEx base. Our balanced portfolio delivered $638 million in free cash flow in the first half, that’s up 74% on the previous first half. We are now targeting a free cash flow breakeven oil price this year of $31 per barrel, down from the previous guidance of $35 a barrel. Importantly, every $10 increment in oil price above our free cash flow breakeven increases annual free cash flow by between $300 million and $350 million. Moving to, slide six. Today’s results are not simply about higher volumes and contracted LNG prices; they are also about lower unit costs and efficiency gains. The Santos operating model continues to drive lower cash unit production costs across our operated assets. You can see the results on the slide, compared to two years ago; we have delivered reductions of 25% in Western Australia, 13% in the Cooper Basin and 9% in Queensland. I believe this is industry leading performance, which has been achieved despite cost pressures seen across our industry. Before I hand over to Anthony, I want to briefly highlight progress on our growth projects on slide seven. Last year, we rolled out target to achieve more than 100 million barrels of annual oil equivalent production by 2025. One of the things I believe sets Santos apart is that we have growth opportunities across all of our assets. Our growth is not beholden into one project, one product market or one region, ours is also a brownfield upstream growth strategy leveraging existing infrastructure to deliver superior shareholder returns. It has been a busy first half with significant milestones achieved across growth projects in all assets. I will address some of these in greater detail later in the presentation, but highlights include the successful appraisal of Dorado, meaning we’re today announcing a significant resource upgrade; successful drilling activity, combined with the appraisal of Moomba South, means we’re targeting over 150% reserve replacement in the Cooper this year. Barossa is making excellent progress towards FID early next year. Barossa’s robust economics are based on the brownfield nature of the project and its competitive unit development costs, and we advanced PNG LNG expansion by signing a binding LOI to farm-in into P’nyang. In summary, it’s been an excellent first half for Santos, and we’re in great shape to drive our growth forward and deliver shareholder returns. I will now hand over to Anthony to provide a detailed review of our financial results.

Thank you, Kevin. Hello, to everyone. This is another strong result and clean set of numbers for the business. Our continued efforts to embed safe, low-cost efficient operations across our assets, combined with the successful integration of Quadrant energy has led to record first half earnings and free cash flow generation. The balance sheet has also been strengthened, as we look to deliver the significant growth opportunities across our portfolio. Moving to, slide nine. The three key financial priorities for the business remain unchanged as we continue to focus on driving shareholder value. These priorities are; our focus on strong free cash flow generation, continued cost out and efficiency gains, and a balance sheet supportive of our growth strategy. Underlying NPAT in the first half was up 89% to $411 million and free cash flow up 74% to $638 million. And despite higher CapEx on the back of our offshore West Australian drilling program and our increased onshore activity across the Cooper basin and GLNG, we still have been able to lower our 2019 forecast free cash flow breakeven to 2018 levels at around $31 per barrel. Our continuous focus on cost out and efficiency gains has continued to flow through to the bottom line. Excluding the impact of the PNG LNG earthquake repair costs, which are in our OpEx, our normalized production costs are down 5% to $7.27 a barrel. As Kevin has stated, our production costs across all our operated assets and PNG are lower than last year. At 30, June, our net debt was $3.35 billion, down 6% on year-end 2018, including the recognition of $359 million lease liability under the new accounting standard AASB 16. For those interested, the notes to the financial statements contain detailed tables of the P&L, balance sheet and cash flow impacts of the adoption of AASB 16. As you’ll see from these notes, this did not have a material impact on our reported P&L or cash flow. Gearing was 31% at the end of the half, and is forecast to decline to less than 30% by the end of 2019. With the balance sheet well-positioned for growth and our strong free cash flow generation, the Board declared a fully franked interim dividend of $0.06 per share, in line with our dividend policy. The dividend is 71% higher than the 2018 interim dividend. Slide 10, shows a very strong set of results for the first half and a strong improvement trend across all key metrics. Sales revenue increased 18% to approximately $2 billion, driven largely by higher LNG prices and sales volume due to the acquisition of Quadrant Energy. These high volumes, combined with cost savings and efficiencies, led to an EBITDAX of $1.26 billion, up 43%. We recorded an underlying net profit after tax of $411 million, up 89% and our free cash flow as I said before was $638 million, up 74%. Slide 11, shows strong upward trend in underlying earnings. Our focus on cost reductions and efficiency gains combined with the acquisition of Quadrant drove earnings higher, with the underlying profit turnaround in three years from the first half of 2016 being $442 million for the half year. These results include the impact of the new AASB 16 Lease standard with an immaterial $2 million expense for the first half. Slide 12, outlines the strong free cash flow generation from the business. The company achieved a 74% increase in free cash flow to $638 million, and over the three years since the first half of 2016, the turnaround in free cash flow has been $738 million for the half year. Operating cash flow increased 63% to over $1 billion, and investing cash flow, excluding asset acquisitions and divestments, major growth CapEx and lease payments increased 49% to $413 million. This higher CapEx was mainly the result of the drilling program in offshore Western Australia and higher onshore activity levels, which have all been maintained within our disciplined operating model of less than $40 per barrel free cash flow breakeven. We have strong free cash generation, we are now well placed to continue to reduce net debt, reinvest for growth and fund the dividend. Slide 13, shows the diverse nature of our portfolio, outlining the strength across our five core assets and the balanced nature of their contributions to EBITDAX and margins. PNG and Western Australia are our two highest margin assets with strong, stable cash flows, low costs and margins in excess of 72%. This slide highlights the successful impact of the Quadrant acquisition on our results. You can also see that all our segments now have an EBITDAX margin of greater than 50%. All of our assets are free cash flow positive at an oil price of less than $40 a barrel. Slide 14, shows production and sales volumes. First half 2019 production in sales volumes were higher than the prior corresponding period due to PNG LNG resuming full production, following the earthquake in 2018 as well as the successful integration of Quadrant. We expect a strongest second half for both production and sales volume. 2019’s production guidance is maintained at 73 million to 77 million barrels and our sales volume guidance at 90 million to 97 million barrels. Slide 15, shows that our focus on safe low cost efficient operations is continuing to deliver with our first half unit upstream production costs declining 8% to $7.37 a barrel. Excluding the impact of shutdowns and the PNG LNG earthquake repair cost, which is in OpEx, our normalized unit production costs fell 5% from year-end ‘18 to $7.27 a barrel. Unit upstream production costs were lower across all our operated assets, reinforcing the continued successful implementation of our low-cost disciplined operating model. 2019 production guidance is maintained at $7.25 to $7.75 a barrel, which includes all planned shutdown activity and PNG earthquake costs. Slide 16, outlines our CapEx. Our first half CapEx was $447 million due and mainly to the drilling programs in offshore Western Australia and increased drilling activity in the Cooper Basin and Queensland. The exploration and appraisal program offshore Western Australia reflected the successful appraisal of the significant Dorado discovery and Corvus-2 gas well, plus our Rock South-1 exploration well. The high equity position in these wells, were up to 100% provides flexibility to optimize our portfolio and firm down at a later date. Even with this additional CapEx spend in 2019 our forecast free cash flow breakeven of $31 a barrel is in-line with 2018. Our free cash flow breakeven guidance includes all forecast CapEx except Barossa FEED and long-leads of approximately $50 million, which we classify as major growth project expenditure. As you can see from the chart on the right-hand side of the page, improved onshore efficiencies and productivity gains have led to increased drilling activity in both the Cooper Basin and GLNG during the year at lower average drilling costs per well. All of this activity is under a self-funded operating model at less than $40 a barrel for both Cooper and GLNG. Our 2019 CapEx guidance is lowered, to approximately $950 million to $1.05 billion, mainly from movements in FX and the rescheduling of the two well drilling program in the McArthur Basin to 2020. Slide 17, shows net debt at year-end was $3.35 billion and gearing of 31% post the completion of the Quadrant acquisition. This debt and gearing includes $359 million of AASB 16 Lease liabilities. We are well on track to meet our target gearing ratio of less than 30% by the end of 2019. We have ample liquidity of $3.2 billion with cash on hand of $1.2 billion and undrawn bilateral facilities of $2 billion. S&P has reaffirmed our investment grade credit rating of BBB- on the 19 of August. The balance sheet is healthy, we have ample liquidity and we are set to deliver our growth opportunities. Slide 18, shows our debt maturity profile at 30 June. Our gross debt is $4.57 billion, including the PNG project financed debt, which is nonrecourse with the repayments coming from the cash flows of the project. Once the PNG project debt is removed, as shown on the right hand side, our senior unsecured gross debt is $2.9 billion. Following successful refinancing of the Quadrant acquisition bridge facility in the first half, there are no material near-term maturities. Our balance sheet is strong, and de-gearing is progressing to plan post the acquisition of Quadrant. Potential remains to further optimize the portfolio through strategically aligned farm-outs and disposals to enhance financial flexibility. I’d like to finish by emphasizing the company’s record first half financial performance. We’ve generated record first half cash flow, and we declared a $0.06 fully franked interim dividend. This is another good quality and clean set of numbers. Our continued focus on safe, low-cost efficient operations and the successful integration of Quadrant provides a strong platform to deliver our significant growth opportunities across our five core assets. Thank you. And I’ll now hand back to Kevin.

Thank you, Anthony. And let me start by acknowledging Anthony and his team for the excellent job they’ve done to strengthen the balance sheet and support of our growth plans. Now let’s take a look at our assets starting with Western Australia on Slide 20. The acquisition of Quadrant has transformed the scale of our business in WA. The charts tell the story: First half EBITDAX almost trebled to $314 million at a margin of more than 70%. Unit production costs were down 12% to $7.63 per BOE, and are now 25% lower than two years ago. These results demonstrate we have quickly and successfully integrated Quadrant into our business. Progress on delivering the combination synergies has also been pleasing. We have already achieved an annualized run rate of $40 million, which gives us confidence to increase our guidance today to between $50 million and $60 million in savings per annum. Another opportunity delivered by the acquisition of Quadrant, is of course Dorado, shown on Slide 21. Following excellent results from the Dorado 2 appraisal well, we are today announcing a 6% to 8% increase in gross 2C resources to 310 million barrels of oil equivalent. I would remind you that Santos net interest in Dorado is 80%. So this means our net 2C resource possession is greater than our 2P reserves in PNG, for example and importantly over 120 million barrels are oil and liquids. Dorado 2 greatly de-risked future development of the field and confirmed high-quality reservoirs and fluids. Importantly, the well confirmed an oil-water contact in the primary Caley Formation and Connectivity to Dorado 1 for all reservoirs. We are currently drilling Dorado 3, where production testing is planned in the next month. Testing will provide critical dynamic and fluid data to underpin field development planning. Concept evaluation for the Dorado development is now well underway, and we are targeting a FEED entry decision early next year. Moving to, Slide 22. Dorado has proven a world class liquid-rich petroleum system with high quality reservoirs in the Bedout sub-basin. The basin is only partially explored; it has multiple play types, some of which remain untested. We’re also in shallow water, which helps the economics. Santos has high equity interest of up to 100% across the basin, and we recently added the WA-540-P permit to our portfolio, which you can see at the top of the map. We have built a basin master position, which brings opportunities to create value through strategic partnering and ongoing portfolio optimization. Now let’s look at the Cooper Basin on Slide 23. The turnaround of the Cooper continues as we position the asset as a high value swing producer, supplying both domestic and export markets. Production is growing again and the asset is more profitable with first half EBITDAX up 27% to almost $300 million with margins above 50%. We have continued to drive cost lower and increase productivity with production cost per barrel down another 3%. We drilled 51 wells in the first half, the highest in 12 years, but this doesn’t mean we took our eye off the ball on cost and efficiencies with the average vertical gas well cost maintained at $2.3 million. We’re on track to drill around 105 wells this year, up from previous guidance of 100 for the same budget. On Slide 24, our focus on low-cost efficient drilling combined with a renewed focus on the rocks is delivering improved reserve replacement as well as higher production in the Cooper. As I said previously, we’re planning to drill around 105 wells this year. About 60% of those wells are targeting prospective and contingent resource conversion opportunities. 85 wells last year delivered 72% reserve replacement, the year before that, 60 wells delivered only 32%. This drilling activity combined with the successful appraisal of Moomba South means we are targeting over 150% 2P reserve replacement in the Cooper this year. This would be the first time since 2012 that the Cooper has more than replaced its annual production, and this will be done within the capital constraints of our disciplined operating model, which sees all assets free cash flow positive at an oil price of less than $40. All of this means we’re on track to our target of between 17 million and 19 million BOEs of production in the Cooper by 2025. Moving to, Slide 25. What really excites me about the Cooper is the hopper of growth opportunities that are emerging now we have significantly reduced the cost base of the asset. The appraisal of Moomba South is just the first of several large-scale project appraisal programs focused on resource conversion. We drilled eight appraisal wells and all intersected gas oat and the target Patchawarra Formation. Individual well test rates up to 8 mmscf per day were recorded, with higher liquids and lower CO2 contents compared to adjacent field production. Seven wells were brought online through existing infrastructure, and are providing valuable data as we progress field development planning. Planning is ongoing for further drilling towards the end of 2019 and parallel with field development planning for the Moomba South project, and we aim to take FID on the Moomba South development by year-end and expect to book a reserve upgrade. And we have the emerging opportunity in the Granite Wash Play, which flowed gas in the Moomba South appraisal wells and confirmed the productive capacity of this new play. We’re also progressing projects in our Energy Solutions business, including evaluating compression, electrification with renewables, which would free up more gas for sale and reduce emissions, gas that comes with no upstream risk and no decline curve. We’re also working on further oil beam pump conversions to solar and batteries. Our carbon capture utilization and storage project has moved into pre-FEED. Cores from two appraisal wells have been analyzed, and we have decided to drill injection test wells later in the year. And in June, we brought online a two-megawatt solar project at the Port Bonython facility at Whyalla. It’s a very exciting time for the Cooper Basin, and it’s great to see so many projects emerging as a result of our lower-cost operating model and competing for investment capital. Moving to Queensland, on Slide 26. We see a similar upstream cost discipline and efficiency story to the Cooper. First half EBITDAX was up 13% to $321 million with EBITDAX margins above 60%. We drilled a record of 189 wells in the GLNG acreage in the first half. Average well costs were maintained despite the higher level of activity. Upstream production continues to build, and the development projects at Roma East and Arcadia are progressing well. Production is building from Roma as the field dewaters, and it has exceeded 115 terajoules per day, and first gas is expected to be introduced into the New Arcadia compressors later this quarter. At New South Wales, the Narrabri Gas Project has been moved forward into the assess phase by the New South Wales Department of Planning. Gas customers are keen for Narrabri gas to come into the, market and we have announced a number of gas off-peak agreements, subject of course to project sanction. I will make a few comments on the domestic gas market later in the presentation. Moving to, Slide 27. GLNG is on track to achieve the 6 million tonne LNG sales run rate by the end of this year. This includes LNG volumes originally slated for export, but redirected to the domestic market by the GLNG partnership. We’re drilling more wells for less CapEx per well. As you can see from the middle chart, we will drill more than twice as many wells this year as two years ago for about the same level of total CapEx. This is the Santos disciplined operating model and action. Equity gas production is building, as shown on the chart on the right. I expect this positive trend to continue as well as continue to dewater and we bring online the new production from Roma East and Arcadia, I mentioned on the previous slide. I’d like to take this opportunity to thank our partners at GLNG, PETRONAS, Total and KOGAS for their support over the last couple of years, and as you know the GLNG plant has spare capacity and we are in advanced discussions with our partners to access that capacity for both Santos Gas and other partner’s gas. Moving to, Slide 28 and Northern Australia. Darwin LNG continues to perform strongly, operating at an annualized rate of 3.1 million tonnes per annum in the first half and shipping 23 cargoes. We continue to make excellent progress towards an expected FID on Barossa early next year. The Subsea Production System contract was awarded to TechnipFMC following a competitive tender. We expect to award the gas export pipeline contract shortly while evaluation of beds for other key packages, including drilling and the FPSO are progressing well. Barossa has also entered into exclusive negotiations with Darwin LNG for the supply of backfill gas, and on the marketing front Santos is in advanced discussions with a number of quality LNG buyers on firm offers for the Barossa volumes. These firm offers provide a solid foundation to take the project forward to FID. What I really like about Barossa, is it’s a low-risk brownfield project with a very competitive cost of supply into Asia. In the McArthur Basin, environmental plans were recently approved by the NT government for drilling two wells, which we now expect to drill following the upcoming wet season. On slide 29, PNG LNG continues to be a well-run, high-performing asset in our portfolio. Production has recovered well from last year’s earthquake, and the plan achieved record daily rates for over 9 million tonnes per annum in the first half. EBITDAX is up 72% to $283 million, reflecting higher volumes and LNG prices. Margins of above 80% remain strong. Our signing of an LOI to farm-in to P’nyang represented another step on the path towards expansion. Discussions are ongoing with our operator, joint venture partners and obviously the PNG government to achieve the alignment required for expansion. Discussions are ongoing, as I said and we will update you as we know more. Before I close, I’d like to make a few comments on how we see international and domestic gas markets starting with LNG on Slide 30. The first point to make is Santos has a strong contracted LNG position. More than 95% of our current LNG volumes are sold on mid and long term contracts with strong slopes to oil. This means we have minimal exposure to the LNG spot market. Some of our long-term contracts are currently in price reviews. While I cannot comment on individual contracts, I will say that the scope for change is modest and limited by contract terms. The next point, as we continue to see robust long-term demand growth out to 2030 and beyond, our portfolio is well positioned to capture some of this growth with low-risk brownfield upstream backfill and expansion projects at Darwin and PNG LNG. And as I mentioned earlier, we’re in advanced discussions with a number of quality LNG buyers on firm offers for Barossa volumes. Moving to domestic gas on, Slide 31. Santos is on track to supply more than 70 petajoules into the East Coast market in 2019, which is approximately 14% of forecast demand. This is obviously in addition to our West Coast domestic gas business, where we are the largest supplier, providing more than 35% of forecast demand. As you have seen in today’s results, we are increasing activity levels in the Cooper and in Queensland and drilling at record rates. We are increasingly meeting our export commitments with Queensland gas, thereby freeing up the Cooper to supply southern markets. GLNG is only supplying gas into our long-term contract commitments, and I’d like to acknowledge our GLNG partners, who are diverting LNG volumes previously slated for export to the domestic market. We have already committed 100% of Narrabri gas for the domestic market, should the project be approved, and we have been an active participant in recent Queensland acreage releases to develop gas for the domestic market only. Finally, I want to reiterate that Santos is open to discussion about policies to ensure the domestic gas market will be adequately supplied at competitive prices. So in summary, on slide 32 our clear and consistent strategy to focus on long-life assets that generate sustainable free cash flows through the oil price cycle is delivering consistent and clear results. Record financial performance, good cost control, resource growth at Dorado and the successful integration of Quadrant highlight a very good first half for Santos. We’re working hard to deliver on a promise to transform, build and grow the company. And on that note, I’m going to wrap up now and thank you for joining us today, and I’ll open the call to questions.

Thank you. [Operator Instructions] Our first question today will come from James Redfern with Merrill Lynch. Please go ahead.

Hi Kevin, good morning. I just had a few questions please. The first one is in relation to Dorado. I’m just wondering if you could please comment on the development concept for Dorado. My understanding, it’ll be 50,000 barrels a day of oil with the world’s top date [ph] to release FPSO. I’m just wondering how Santos plans to monetize or deal with the gas, roughly 600 Bcf of gas. Will that be transported by pipeline to Devil Creek or what’s the plan there, and I have two more. Thanks.

That’s a lot of questions wrapped up into one there James, but thanks for the question. We’ll enter FEED as I said early next year, possibly even towards the end of this year, but we’re just finalizing that concept so late. But without getting into too much details, what I would say is that we’re probably looking at a two step – two phase development with the first phase very much focused on liquids development and with the gas recycled and developed at a later stage, but we’ll provide more details on that towards the end of the year at our strategy date.

Okay, thank you. And then maybe if we switch over to Barossa and Darwin LNG, I’m just wondering if you could comment on what your expectation is in terms of plans to shutdown at Darwin LNG in relation to the timing of when they run down gas, it finishes or ceases and first gas in Barossa, like its indication, there we are thinking sort of 12, 18, 24 months?

Well, look I mean that’s our moving target at this point and the field is still continuing to perform well. We have regularly stated that we expect Bayu-Undan to come to the end of field life at the – towards the end of 2022 and starting up Barossa in 2024. I would expect that we will be able to shed more light on the scheduling of that when we take our FID decision early in the New Year.

Okay, thanks Kevin and one more if I can; last one I promise. Just in relation to the LNG marketing for Barossa, can you please remind me how much of the expected volumes from Barossa Santos plan to contract ahead of FID early 2020?

Well, I wouldn’t be able to remind you, because we’ve never stated it James, but again, a very good effort mate. Look, yes, you are – yes look, the bottom line is that we will look to contract a significant volume of those reserves before taking FID. As a company our size, I think that that will be prudent, and again, I think we’ll provide more information on that when we take that FID decision or if we contract before the FID decision, yes.

Okay, thanks Kevin. That’s great.

Cheers! Thank you.

Our next question will come from James Byrne with Citigroup. Please go ahead.

Oh! Good morning Kevin and Anthony. First question for you Anthony, just on your remarks around farm-outs and disposals, I guess it’s obvious that you’d farm down Dorado, but where else are some of those candidates reducing your equity interest? You also stated that in the context of the balance sheet rather than, say your risk management in any one given asset. So what sort of price did the farm-outs and disposals give you that an already healthy balance sheet does not?

Yes, thanks James. Look, my comments around finance and disposals were targeted specifically there around Dorado. As I said, we’ve got a 100% interest in the Dorado Field and it’s coming into development and it’s a fantastic opportunity to move forward with, and you can see that through our joint ventures partners kept market cap at the end of the day. We also got the whole Bedout Basin and the remaining acreage sites. It’s all four blocks of Bedout that we’d look at potentially farming down over time when the value equation is right, probably down towards...

Yeah, I don’t know if you realized Anthony, you said 100%. You make 100% in the Bedout and 80% in Dorado.

Thank you. On the balance sheet, yes look the proceeds James at present go to two things. One is, it goes straight into the gearing and debt to continue at the gearing profile like we said post the Quadrant acquisition, and we want to get below 30% and continue that, and we want to get ready for the growth spends that we’ve got in our portfolio, which includes as I said, Dorado, Barossa and the other great opportunities we have with PNG and potentially Narrabri coming up as well. So it’s getting ready for the growth period.

Easy, alright thanks. Secondly Kevin, you had mentioned some cost-out pressures in the industry. What are they? How does that implicate future periods to Santos? Should we be thinking cost-out is really starting to flat-line here or can you still deliver more particularly in WA?

No, I think what we’re trying to emphasize James is that as much as we’re hearing about cost inflations across our industry, not only here in Australia, but globally, we were working with our contractor, as in focusing on efficiency to drive further unit cost reductions and we’re still managing to both maintain our drilling cost performance and also see further improved production cost performance across our operations.

Got it, okay. Last question on GLNG; with Santos potentially pulling rather than selling gas to GLNG, how does that interact with the ADGSM in the instance that GLNG was made to withhold a portion of exports?

Well look, it wasn’t made to withhold a portion of exports James. There’s an HOA in place between all of the LNG facilities where they agreed to prioritize sales back into the domestic market on an agreement basis. ADGSM has never been triggered. We don’t believe it needs to be either based on our view of supply going forward.

Okay, fine. Thanks.

Thank you.

Our next question will come from Ben Wilson with the Royal Bank of Canada. Please go ahead.

Good day Kevin and Anthony. My question is in relation to the Cooper. The production increased target that you’ve outlined in this presentation deck grown from current levels up to 17 to 19 over the next five year period. Are you able to maybe tell me, is that contingent on drilling rates and success rates similar to what we see this year? The reason I ask is because it looks like you should probably be able to deliver higher production than what you’ve outlined in that number if you continue along the path that you’re on.

Well, look Ben, thanks for the question. If you look at our production over the last few years, over three years we’ve gone 14.5, 15 – wait, you can see the numbers here. 14.4 sorry, 15.5, and this year we expect that to be higher than 15.5. And it’s just a function of the self-funding operator model, allowing the asset to continually free up more cash to drill more wells year-on-year and that’s a function… You know if you look at the slide 24, that slide basically describes the Cooper operating model, showing the number of wells, the well mix. It’s very important that we continue to invest and drill wells targeting prospective and 2C conversion. We’re obviously drilling wells that are targeting our undeveloped 2P reserves and bring them straight on to production, and you can see the relationship with the number of wells and the mix of wells to the reserve replacement. And so we’ve been working hard over three years or so to get that efficiency, get those efficiency gains to get that model working to drive that reserve replacements up, and as we see this year, we’re targeting greater than 150% reserve replacement at year end. What that will come, if the number of wells keep continuing to grow, we expect to see a steady sustainable growth in production rates, as long as we can maintain reserves replacement and the historic resource conversion rates from 2C to 2P, which are around the 70% mark over – that’s a ten year running average that we see when we target 2C opportunities. And as we say, based on our forecast, that should take us somewhere in the range between 17 million and 19 million BOEs by 2025.

Okay, that’s great. Thanks Kevin.

Thanks Ben.

Our next question will come from Mark Samter with MST. Please go ahead.

Good morning guys. I’m going to resist the temptation to ask that question on inorganic opportunities and I’m going to ask a question on the Cooper Basin as well. Can you give us any kind of handle on what these incremental reserve bookings that we expect and obviously reserves not a reserve? Can you give us any feeling for what we think F&D costs are on these incremental reserve bookings with that broadly in line with the rest of the Cooper portfolio or are we talking about more expensive gas that’s still obviously very economic in the current market?

Yes. Well look, I mean I think we see the economics across the Cooper in terms of new reserves being very high-value barrels. I mean the incremental volume at the Cooper we see as high value like I said. The Cooper operates – everything is going to operate within that free cash flow breakeven model, that operating model that we described earlier Mark and so what that means is because of the lower well costs, we’re seeing better economics on all of those reserves and the resource. As long as we can maintain the 7%, 8% plus 2C to 2P conversion rate, at the current drilling cost, then that – the 2C prospects we’re targeting would all be economic within a $40 oil price world. Now in saying that, where we believe we’ll see the biggest gains across the Cooper is when we see bigger wells, and we see higher EUR wells, and so that’s why in 2020 we’ll be targeting some of those other prospects we talked about earlier and drilling some horizontal wells to see if we can get larger unit cost – sorry, larger unit development cost gains and larger production volumes per well. And again, that all goes to help the economics. And you know as that chart showed earlier, maintaining a good mix of exploration appraisal and development wells is critical to ensure it’s a balanced operating model.

Thanks. And just a quick question on Darwin as well. I obviously don’t expect you to come in on the press around Conoco, but is this when we think about the mismatch between Barossa ownership and Darwin ownership and the timelines on FID and perhaps none of your JV partners are in la-la land, but just can we kind of think about the timelines of how that will progress and the limitations that ownership in Darwin can put on the timelines?

Well, look on the contrary, I’ve got to acknowledge the joint venture partners for working really well together. Everybody is very focused on ensuring that we get a good outcome for all parties, and as we say, we got the exclusive period now where GLNG and Barossa are talking regarding the tolling arrangements. Barossa is moving forward at pace now. And what I would say from a Santos perspective, we are keen to work with all parties to ensure that we do seek and get good alignment of interest across the different sides of this relationship between GLNG and Barossa in order to facilitate good development. Barossa is a very strong project. I mean what I like about Barossa is the fact, and I said it earlier, it’s a low-risk brownfield upstream project. What I would remind everyone is that quite a lot of the CapEx blurs occurred over the last decade on many of the LNG projects, and in most cases the offshore scopes went very well. In fact, in most cases the offshore scopes were finished well ahead of the onshore scopes and I’m sure they weren’t planned that way, but that’s just a fact of life. The offshore is a much more controllable environment and when we look at Barossa, we see a very low-cost – very competitive low-cost development that we’re very excited about.

Perfect! Thank you.

Cheers! Thanks Mark.

Our next question will come from Saul Kavonic with Credit Suisse. Please go ahead.

Hi Kevin, hi Fergs [ph]. Three quick questions from me, back on Darwin and Barossa. Can you give us an indication of what abandonment costs at Bayu-Undan could look like over the next two years in scale and timing? And can you also give us an indication on Bayu-Undan tax as a percentage of revenue. Is that likely to continue the way it has now at the tail end of life or could we see some weird and funny things as we approach the ceasing of production?

Well look, I don’t think we comment on the actual abandonment cost. What I can say is that we provide for those in our accounts and as part of the PC, sorry cost recovery processes. And look – and that doesn’t start really until post-2023 polling and/or later. In terms of tax environment, no I wouldn’t expect anything squirrely there. The treaty agreement that’ll be signed in the near future or be ratified should I say, as it carves out and protects our project.

Fiscal stability clauses are in there, so also we’re protected.

Yes, so it’s secured in that sense. It’ll be more of the same. It’ll be exactly what you’ve seen to-date.

Understood! Moving to Narrabri, a couple of questions. I mean one is, we got in the press the Planning Minister, Rob Stokes saying it has big potential environmental impact and that the import terminal can help secure affordable supply to New South Wales. You’ve got some commentary on the Planning Minister’s comments?

Well, look, what I’ve heard the Planning Minister say has been very supportive of the process and as I’ve heard the Premier and the Deputy Premier say likewise recently. The project has just been progressed into the next phase and the expectation I’m hearing from government is that we’d expect a decision on the project to be first quarter of next year or early next year. And I think we’ve just got to let the government and the regulator process play out now. And we’re very confident in the project. We think it’s a great project and we can see that the development in Queensland has gone very well. We work very well with the local communities there, and we’re very welcomed in those communities and the great thing about Narrabri benefits from the learning that we’ve seen across Queensland in recent years, and the project economics are strong and I think everybody would agree that the cost of the gas that’s going to come from the Narrabri gas project is going to be far more competitively priced than any gas that can come in from any import terminal.

Just further to that, assuming that you do get the tick of approval from the government, say Q1 next year, can you step us through the timeline and key milestones for Narrabri development?

Well look, I mean once we get the EIS approval Saul, the next stage is to embark on the full appraisal of the field to optimize the development, and our guidance previously on that, that’s probably a 12 to 18 month cycle before we take FID in the project.

Understood! And one last question, if we move across to our friends in PNG, if we were to see tougher fiscal terms imposed in P’nyang, does that change your view on LOI and access agreements that you’d want to revisit or you’ll keep to the LOI and access agreement terms regardless of the fiscal terms outcome at P’nyang?

Well look, I’m not going to speculate. I don’t think it serves to speculate. I’m very confident that everything will sort itself out in PNG. I mean ultimately I think the focus is on development, and sure, there’s the government that’s taking the time to reevaluate and look to make sure that the balance between project economics and community or government contribution is something that everybody can live with for the longer term, but we’re confident that’ll play out. No doubt, it means everything is going to the right a little bit and it’s uncertain at this point of time why that is and we’re working as I said earlier with our partners and with the government to get clarity on that. But from a Santos point of view, I’ll go back to the portfolio view that we take in our business and you know those PNG expansion may be slipping to the right. We’ve got a great core business in PNG. It is performing fantastically well and will start recurring the slippage in the project at the same time with the emergence of Dorado. And Dorado as I said earlier, we’ve got more reserves in Dorado than we have in PNG. That project is coming up fast and really floating to the top in terms of value and work to Santos and to our shareholders. And I expect we’re going to see that within a year or late this year and hopefully be targeted on FID by the end of 2020.

Just one quick last one. In terms of inorganic growth opportunities generally, if you were to pursue one of those, would you contemplate doing a further equity raise or stretching your gearing materially above current levels?

Like two things I’m going to say there Saul. One is, we never speculate on M&A opportunities for a number of reasons, and two, as we have no plans, and I will emphasize, no plans to raise equity.

Thanks Kevin, I appreciate it.

Thank you.

Our next question will come from Joseph Wong with UBS Equity Research.

Hi guys. Maybe if I just turn to I guess the Northern Territory, I understand the McArthur Basin drillings are being pushed out to 2020, but can you provide some details in terms of what commercial flow rates, hereafter what the success looks like to you and where would the home be for the gas?

Well look, I’m not going to comment on commercial flow rates. Let’s wait and see what it cost to drill the wells and what the well’s flow at once we complete our exploration program. In terms of natural homes for the gas, it really depends on scale Joseph. I would think the obvious route for that gas is to come north to Darwin and support potential expansion through Darwin in the future and any domestic needs as Darwin’s domestic market develops over time. If it’s big enough, it can come East either via Moomba or over to Wallumbilla. So lots of options for McArthur Basin, but I think – let’s not get ahead of ourselves. It’s an exploration play, and we’ll go there earlier in the New Year following the end of the wet season and drill our wells. We still do plan to test a well this year in McArthur, the well that we drilled some years ago that I always have trouble pronouncing, but...

Tanumbirini 1.

Tanumbirini 1, yes. Sorry, it’s a Scottish accent and I struggle with that one. But yes, we still plan to test that before the end of this year.

Yes, yes, maybe if I kind of turn to like this LNG marketing, I guess can you provide any update in terms of your JV with ENN group. I guess what’s the intention to market the LNG from Barossa through that JV?

Well look, I mean our intention is to market to the buyer who comes in with the best terms for Santos, and that as I say, we’re in conversations, very advanced conversations with a number of potential buyers with firm offers on the table. You know one of the things we’re firm in marketing Barossa is because it’s a brownfields project, despite the volatility globally and some concerns about some projects moving to the right, there’s a lot of confidence around the Barossa project because of its brownfield low-risk nature and that’s good, yes.

Okay, and the last one for me is just on, I guess Santos’s I guess the midstream business, I guess that’s been growing. Can you provide details in terms of is there appetite to take more equity in liquefaction facilities as the press is speculating some major exit?

Look, I mean our midstream, it’s an internal division and is very focused on ensuring we have a midstream focus across our current operating assets, and so the focus is very much internal on our own assets, our own operations at this point, that’s the intent of that group.

Okay, thank you.

Thank you.

Our next question will come from Daniel Butcher with CLSA. Please go ahead.

Hi everyone. Sorry just to go back to Barossa once again, just to clarify a few more things. Can you maybe sort of outline what’s the tenor you’ll be looking for on LNG on the off take contracts. I mean are you shortening your expectations to sort of five or ten years or would you be going for sort of 15 years plus? And secondly, it’s sort of implied in your answer that you might go to FID without contracts. What makes you comfortable with doing that and contracting up after FID?

Alright Dan, like first of all I think from a tenor point of view, we’d be looking at 10 to 15 years, in that range, number one; and number two, if you picked that up from a previous answer, then I apologize, it’s certainly not what we want to be. What I said earlier was we’d be looking to contract a significant portion of our volumes pre-FID to support FID, and you know we’ve got a very strong balance sheet that supports the developments of projects. We’ve said many times before, when we look forward to the 2024 and the CapEx profile that we have today, we’re very confident in our $60 oil well. We can fund all of those projects from our free cash flow that’s coming out of the business, so we’re very confident. However, we would not be looking to FID and LNG projects without significant portions being contracted.

Sure, thanks, and can you maybe just remind us, I mean Darwin LNG is obviously not as old as Northwest shelf, but if it runs for another 20 years it might need some sort of repower or heavy sort of extra works mid-life to keep it going and efficient? Have you got some view on what that might cost?

Yes, well look I mean the costs for what we refer to it, the realizing project for DLNG are embedded in the numbers that were given previously as guidance for the overall CapEx for that project.

Oh! So you would do it upfront in the gap between Bayu-Undan running down and...

Yes, the plan is to do that work in the period where DLNG is shut down between the end of fuel life at Bayu-Undan and the start of Barossa. I mean what I can say it’s in the order of about $400 million to $500 million.

Gross?

Gross, you know for the whole joint venture.

Okay, thanks. One more on Barossa if you got a second. Just wondering how you are thinking about the high CO2 there? Will you be able to build a CO2 price into your far data decision or is there some sort of works in place where you can reinject it if necessary, if some sort of carbon price comes in which isn’t grandfathered or how you sort of deal with that?

We don’t publish it, but we do factor in. We’ve said many things we factor in, a cost of carbon into all of our project economics and all of our decisions. That’s an internal thing, but we factored that in. And our current forecast is that we’ll stay within all of our safeguard mechanism baselines going forward.

Okay, thanks. And maybe just turning to WA, just seeing some projects obviously not quite there with your oil projects there, but some projects late in life have renegotiated their FPSO leases to be partly variable showing production revenue to extend the life of the field. Are you intending on doing that with your WA oilfields when they run down to extend the production life beyond what you’ve currently budgeted and how many years of production or reserves might that add?

Well look, I mean we’ve got a – our oilfields are performing very well for us this year. We own our FPSOs and they’re not the least models, but we used to have one of those with our Mutineer-Exeter, but that field was abandoned and sort of finished last year, I think it was, yes 2018. On a go-forward basis, a few years to go before end of field life in any of these fields, with a very successful infill drilling program in the Van Gogh field late last year, early this year, and we have other drilling opportunities across that field, which will give that further injections of life going forward. So yes, we’re not quite yet at the stage where we’re thinking end of field life in any of these assets at this point in time, and we’ll continue to evaluate that as the fields mature and perform.

I’m sorry, I thought you had leased Ningaloo. Am I mistaken about that?

No, we own it, yes.

Alright, sorry, but thank you. Cheers!

No worries.

Our next question will come from Scott Ashton with Shaw Energy [ph]. Please go ahead.

Good morning Kevin and Anthony. Look, most of my questions have been answered, but just one on for you Anthony. I look at your restoration liabilities on the balance sheet and I suppose just a general comment where we are with sort of bond yields and discount rates. We’re not seeing any movement there. Can you sort of maybe throw a bit of light on what you are seeing with respect to your rehabilitation provisions?

Yes, risk-free rate has come down Scott. So there’s small movements in the risk direction provision that they’ve gone up slightly from year end and most of that’s been due to the movement in risk-free rate.

Much guided for that to sort of change again at year end?

Depends on the risk rate, but at the moment it’s hard for them to go much lower than what they are, the risk free range, but yeah. So as I said, the movement from year end to 30 June has pretty been based on the movement as the risk free rate from December to June as well. So that’s the sensitivity range for the team.

Thanks Anthony.

Cheers! You’re welcome.

Our next question will come from Adam Martin with Morgan Stanley. Please go ahead.

Hi Kevin, Anthony. Just risk around Dorado not flowing as expected. Obviously you’ve got to long flow test Dorado 3. You talk about connectivity in Dorado 1, 2 across all reservoirs, but can you just talk about the risks here. Obviously it looks really good, but can you just talk about that, please?

Well look, I think first of all, I made the point some time ago that the 50,000 barrel per day flow rate that we modeled on our 100 million barrel per day waterfall chart was a conservative estimate as the gross initial production rate at Dorado. The drilling was done year-to-date. The coring results that we’ve seen and the logs that we’ve run across the different wells, we’d indicate that that is the case, that it’s a conservative rate. Now I think I can’t see a whole lot more than that until we do our well test in a few weeks’ time and we’ll get a much better feel for it then, but we’re very excited by it. It’s a great quality reservoir. It’s got everything going for it. The connectivity between Dorado 1 and Dorado 2, you’ve seen the upgrade in volumes. There’s more oil there than we originally thought. So yes, I mean this is all looking very good. It’s more pointed towards a better outcome than a lesser outcome, but I think I can’t say any more than till we well test Adam.

Alright, no good to hear. And Anthony, just one for you; if you add back the Barossa FEED CapEx and I think there was some other long lead items, what would the free cash flow breakeven be. Obviously we can’t ship stuff out all the time, so what would the free cash flow be?

So there’s about $50 million of Barossa FEED cost as I said and Kevin gave you the sensitivity of 300 to 350 for every $10. So if you can work back from that to $1 rate and then divide it by the 50, so it would probably be about $1, $1.50.

Okay, well that’s good. Alright, that’s all for me, thank you.

Okay, that’s all the questions. So I thank everybody for the call and I look forward to catching up with many of you over the next week or so as we go on our roadshow. Thank you very much.

That does conclude our conference for today. Thank you for participating and you may now disconnect.