Kevin Gallagher - Chief Executive Officer Anthony Neilson - Chief Financial Officer

Adam Martin - Morgan Stanley James Byrne - Citi James Redfern - Bank of America Merrill Lynch Andrew Hodge - Macquarie Mark Samter - MST Marquee Joseph Wong - UBS

Good morning, everyone, and thank you for joining us for Santos' 2018 half-year results. With me today is our Chief Financial Officer, Anthony Neilson. I'm very pleased to report that the company is stronger now than it was six months ago, stronger than it was a year ago and with an even greater future. So far, 2018 had been an excellent year for Santos despite the unique challenges the year has brought: firstly, a major earthquake and ongoing seismic activity that led to an extended PNG production shut-in; and secondly, a proposal by Harbour Energy to buy Santos, which was ultimately rejected by the board. 2018 has also brought new opportunities with stronger commodity prices and the exciting strongly value-accretive proposed acquisition of Quadrant Energy announced just yesterday. I'm very pleased to say that Santos has continued to drive unit cost down and to deliver efficiency gains despite oil price increases and an extended unforeseen outage in PNG. Before we start, I draw your attention to the usual disclaimer on Slide 2. I plan to start with some opening remarks about our performance before handing over to Anthony to discuss the financial results. After Anthony's presentation, I'll take you through our operations and growth opportunities before opening the call to questions. Moving to Slide 3. After delivering our turnaround ahead of plan, we are now focused on building and growing the company. We have built a reliable, low cost, diversified natural gas portfolio that is generating strong cash flow to support our growth strategy and a return to dividends for our shareholders. We have continued to reduce costs to improve efficiency, locking in a sustainable low-cost operating model which, combined with stronger commodity prices, has increased our cash flow generation by 22%. With significant growth opportunities across our 5 core long-life natural gas assets, Santos is now in a great position to unlock significant shareholder value. We've reduced our net debt by a further 17%, strengthening our balance sheet to support growth and the return to dividends for our shareholders, which we're announcing today. And as promised, we have sold our noncore assets in Asia. Finally, we have announced a proposed acquisition of Quadrant Energy, which is aligned with our growth strategy to build on existing infrastructure positions around our core assets. Once again, we've demonstrated through the first half of this year that we're continuing to stick to our strategy to deliver on our promises. Moving to Slide 4. Half-year highlights are we generated $367 million in free cash flow, up 22% despite the $70 million impact of the PNG earthquake, which highlighted the strength and the diversity of our portfolio. Our forecast free cash flow breakeven is expected to be $35 per barrel. Net debt is down another 17% to $2.4 billion, and we have ample liquidity of $3.5 billion, with the proceeds from the sale of our Asian assets still to come in the second half of the year. Underlying profit is up 99% to $270 million after tax, and EBITDAX is up 23% at $883 million, reflecting strong asset performance and higher commodity prices. We have locked in a sustainable low-cost operating model to generate strong cash flows throughout the oil price cycle. Back in 2016, that wasn't the case. But to date, our low cash flow breakeven means our portfolio can comfortably handle the higher gearing level following the proposed Quadrant acquisition with a short-term focus to then rapidly degear. As promised, we have maintained a disciplined approach to capital management, prioritizing debt repayment, and not only position the company for growth but delivering growth through the proposed Quadrant acquisition and advancing organic growth projects such as Barossa. Accordingly, the board has decided to declare an interim dividend of US$0.035 per share. This is consistent with the sustainable dividend policy approved by the board and announced on June 28th. Moving to Slide 5. This is a great snapshot of the fantastic results of our disciplined low-cost operating model. Despite oil price rises and the unexpected PNG outage, we have continued to drive unit cost down and efficiency up. We're doing more with less, extracting more production for less money. A great example is the fourth rig we've just put into the Cooper Basin. We've been able to do this because we've driven well cost down 50% on 2015. We expect to drill around 87 wells there this year, more wells in a single year since 2014. And we're drilling them faster, hitting a record 3.1 days for a gas well earlier this year. With our GLNG partners, we're drilling a record 300 wells in Queensland this year. Queensland well costs are now down a massive 84% since 2015. The efficiency journey is not over yet, and we're going to remain focused on continuing to get even better at what we do. Turning to Slide 6. We are focused on organic growth projects across all our core assets as well as completing the Quadrant acquisition. Barossa is now firmly in the lead to backfill Darwin LNG with FEED underway on major engineering contracts awarded. We have received the proposal to farm into P'nyang, and we are working through that now with our PNG LNG foundation partners. In the Cooper Basin, we are growing production. Gas production is up 4%; and oil production, up 7%. In Queensland this year, production is up 5% due to Roma and Scotia ramp-up. Fairview production remained strong, although it has been limited by well availability in the first half of the year. Roma East development is underway, and the first wells are now online. And Arcadia development has been sanctioned with construction now underway. We continue to focus on Narrabri gas project approvals, which we expect some time next year. However, in the meantime, we have obtained the approval to connect all our existing appraisal wells to the Wilga Park power station. Moving to Slide 7. Santos has announced plans to acquire 100% of Quadrant Energy for $2.15 billion. This is a strongly value-accretive acquisition of long-life WA conventional assets. Strong and stable cash flows from these assets will provide increased certainty during an upcoming period of major growth project delivery for Santos. Our production will increase by 90 million barrels of oil equivalent, up 32%; and 2P reserves will increase by 220 million barrels of oil equivalent, up 26%. These are assets well known to Santos, and they will lower our free cash flow breakeven oil price to $32 per. There is significant portfolio overlap, which means the two companies will be stronger together with expected combination synergies of $30 million to $50 million per year going forward. Our strong balance sheet has enabled us to fully fund the transaction with existing cash resources and new committed debt facilities, with a rapid de-gearing profile expected to be less than 30% by the end of 2019. Moving to Slide 8. You can see that Quadrant provides revenue diversification for Santos and increased exposure to high-margin CPI-linked contracts. On completion of a transaction, Santos' average WA domestic sales gas price will increase with further upside from 2020. Moving to Slide 9. Our journey to become Australia's safest onshore operator continues. I'm very pleased with our process safety improvements, with our focus on learning to prevent loss of containment incidents has delivered excellent results, we're now building the same learning culture into our approach to personal safety to drive down our lost time injury frequency, which is still too high. Our top priority is to focus on those incidents with potential for significant harm to people, assets or the environment. Personal safety improvements are built into all our scorecards, and it's very important to me that we deliver them as well as continue to pursue the excellent financial and operational results that we are seeing from the business. I'll now hand over to Anthony to provide a detailed review of our financial results.

Thank you, Kevin. Hello to everyone. This is now the great underlying results, with the business performing well and underlying profit increasing to $217 million for first half 2018. This result shows that the sustainability of Santos' transformation continues, allowing us the opportunity for growth. Our cost efficiencies are continuing. We are generating strong free cash and, at a stronger balance sheet, we got debt reduction target to be met more than a year ahead of schedule. We now have the gearing well under control and our free cash flow breakeven sustainably low to be able to grow the business through the acquisition of Quadrant. Moving to Slide 11. Strong financial and operational performance continues to drive shareholder value. The key financial priorities continue to be around cost out and efficiency gains, free cash flow and a balance sheet that supports our growth strategy. Firstly, cost efficiencies have continued to flow through to the bottom line. The first half was hampered by increased planned and unplanned shutdown activity, in particular, the PNG earthquake and a major shutdown at Bayu Undan. However, excluding these shutdowns, our production costs are down 4% to $7.79 a barrel. In addition, Cooper Basin costs continued to decline, down 13% to $8.42 a barrel. Secondly, increasing free cash flow generation. We achieved $367 million in free cash flow, up 22%. Our free cash flow breakeven is forecast at $35 a barrel for 2018. Thirdly, our net debt is reduced $2.4 billion through stronger free cash flow, and gearing has reduced to 26%. Our debt reduction target will shortly be met more than a year ahead of schedule. With the balance sheet now in a strong position and our debt targets met, the board has reinstated the dividend by declaring a fully franked interim dividend of $0.035 per share in line with the dividend policy announced in June. The balance sheet is in a strong position to support the Quadrant acquisition. And post Quadrant completion at year-end 2018, our gearing is expected to be around 34%, with rapid degearing expected from the Quadrant cash flows and gearing less than 30% by the end of 2019. Slide 12 shows the key financial metrics for the first half and a strong improvement trend across all key metrics. These results show the strong platform that has been built around our disciplined operating model, allowing us to focus on our growth strategy. Sales revenue has increased 16% to $1.68 billion, driven largely by higher prices. These higher prices, combined with cost savings and efficiencies, led to an EBITDAX of $883 million, up 23% from first half 2017. We recorded an underlying net profit aftertax of $217 million, up 99% from the first half 2017. Our reported net profit result includes the impact of $76 million impairment aftertax, which is mainly from the timing of our Asian asset sales being not completed at 30 June, and these assets being recognized as held for sale. However, an overall gain on sale of these Asian assets is expected on completion in the second half 2018. Our free cash flow was also strong at $367 million, up 22%, despite a $70 million hit from the PNG earthquake. Slide 13 shows strong underlying earnings. The company's focus on cost out and efficiency gains, combined with higher realized crude oil prices of $75.37 a barrel, has driven our earnings higher. We've recorded our fourth successive period of underlying net profit, turning the business around from the first half 2016, net underlying loss. Slide 14 outlines the strong free cash flow generation from the business. The company achieved $367 million free cash flow for the period, excluding an additional $25 million cash from asset sales. Our operating cash flow increased slightly to $644 million, and investing cash flow, excluding asset sales, was down 18% to $277 million. With our strong free cash flow generation, we are now well placed to grow the portfolio through our acquisition of Quadrant and continue to reduce gearing and return funds to shareholders through sustainable dividends. Slide 15 shows production and sales volumes have decreased from prior period, mainly due to the shutdown activities, in particular, the PNG earthquake and the major shutdown at Bayu Undan. These have impacted production by approximately 2 million barrels. Production from PNG is fully restored, and the plant has operated at record rates during second quarter. Excluding these shutdown activities in the first half, our production would have increased from first half 2017. This shows the diversification and strength we are building in our portfolio, being able to absorb major shutdowns during the period and still maintaining our 2018 full year production guidance at 55 to 58 million barrels, excluding any Quadrant acquisition impact. Sales volume of 38 million barrels are lower, mainly due to the shutdowns mentioned, and also lower third-party sales due to the expiry of a large GLNG third-party gas contract at the end of 2017. 2018 guidance is maintained at 72 million to 76 million barrels, excluding any Quadrant acquisition impacts. Slide 16 shows product sales revenue was $1.68 billion, up 16% on the back of higher crude and LNG prices. Average realized crude prices were up 38%, and LNG prices were up 24% in the period. All product lines had revenue growth. But most pleasing to note was the growth in our crude oil, which was up 53% to $400 million. This is due to the improved performance of Cooper oil, which is up 7% and at full year highs and also higher third-party oil volumes. Also, we received strong premium to Brent oil prices for the sale of this crude. Slide 17. Cost efficiencies continue, and we are lowering our 2018 production cost guidance to $8 to $8.60 a barrel, excluding any impact of Quadrant acquisition. Our production costs were impacted by the PNG earthquake and major shutdown activities in the first half. Production costs, excluding shutdown activities of $10 million, dropped 2.5% down to $233 million. Other operating costs dropped 16%, down to $160 million. Upstream unit production costs were $8.69 a barrel. However, this included an impact of $0.90 a barrel due to shutdown activities. Excluding these shutdowns then, production costs on a like-for-like basis actually dropped 4% to $7.79 a barrel. This underlying cost reduction emphasizes that delivery of our low-cost disciplined operating model continues and is further reinforced by Cooper's continued cost reductions, dropping 13% to $8.42 a barrel. Slide 18 shows a summary of the P&L. Some key numbers that I've not already talked to are: high third-party product purchases reflect higher volumes mainly from higher oil, gas and ethane purchases in the Cooper and also higher prices. Foreign currency gains of $90 million relate to foreign currency on tax basis and U.S. dollar cash balances, which are held in Australian companies. An offset of $67 million loss has been recorded in a tax expense as FX on deferred tax balances. Net of this tax offset, the FX gain is actually $24 million, which arises from the Aussie-U. S. dollar exchange rate decreasing by $0.05. Fair value losses on commodity hedges of $109 million represent the mark-to-market of oil hedge contracts at 30 June. We have approximately 5 million barrels of hedging remaining for the second half '18, representing 30% of our oil exposed production. We also have 3 million barrels of hedges in 2019, plus Quadrant also have 1.5 million barrels. This total hedging represents a very low percentage of total combined production for 2019. There was impairment loss of $76 million pre and post tax, mainly arising from the sale of our Asian assets, totaling $47 million. We announced the sale of Asia for $221 million in May 2018 to Ophir Energy with completion expected in September. On completion, we expect to book a profit on the sale of the Asian assets in the second half, which is expected to more than offset the first half impairment of those assets. Total finance costs reduced significantly by $31 million, down 22%, due to lower debt levels that we now achieved. Our tax rate was impacted in the first half 2018 by foreign currency movements and the impairment discussed above. Excluding foreign currency and impairment, the effective tax rate was approximately 40% for the half. The full year effective tax rate, excluding foreign currency and impairment, is expected to be in the range of 35% to 40%, excluding any Quadrant acquisition impacts. Slide 19 outlines our capital expenditure for the period. First half CapEx was $306 million, mainly relating to increased activity in Cooper and Queensland, plus the Bayu Undan infill drilling program, with the number of onshore wells drilled in the first half '18 increasing to 151. Improved efficiencies and productivity gains have led to sustained lower drilling costs in both the Cooper Basin and GLNG. With significant sustainable cost out and efficiency gains now embedded in our onshore operations, we have added a fourth rig to the Cooper Basin, and this will increase activity in 2018 to drill 87 wells in the Cooper. Also, GLNG drilling is expected to be approximately 300 wells. We've recently lowered our 2018 CapEx guidance of $775 million to $825 million, excluding Quadrant acquisition, and this is maintained. As I mentioned earlier, we expect 2018 free cash flow breakeven to be maintained at around $35 a barrel. Slide 20 shows net debt reduction. Net debt at June 30 reduced to $2.4 billion and gearing of 26% driven from stronger free cash flows. Our debt reduction target of $2 billion will be reached shortly, more than a year ahead of schedule. We the acquisition of Quadrant, we're expecting our gearing to increase to 34% by year-end. However, rapid de-gearing occurs from strong, stable cash flows, and we are targeting a long-term gearing ratio of less than 25% excluding periods of major growth. S&P have issued a bulletin last night on the 22nd of August, reaffirming our investment-grade credit rating is unchanged and stating that Santos has the financial headroom to undertake the Quadrant acquisition. Post completion of the Quadrant acquisition, we will have liquidity of $2.5 billion with cash on hand of $0.5 billion at 30 June, plus cash flows generated since 30 June and our undrawn bilateral facilities of $2 billion. The 2019 debt maturity of $600 million relating to the ECA facility will be repaid from this cash, plus any new free cash flow generation. Slide 21 shows our debt maturity profile at 30 June, excluding the Quadrant acquisition debt. Gross debt is $3.9 billion, including the PNG project finance debt, which is nonrecourse, and the repayments come from the cash flows of the project. Once the PNG project debt is removed, as shown on the right-hand side, our non-PNG gross debt is $2.4 billion. New Quadrant acquisition debt will be $1.2 billion through a $600 million per year bridge facility and a $600 million 5.5-year term loan. We have retained enough cash and liquidity to meet our 2019 debt commitments post Quadrant without any further debt raisings required. I would like to finish by emphasizing the company's strong underlying financial performance. The balance sheet is stronger. We have generated significant free cash flow, and we have reinstated fully franked dividends. We continue to embed efficiencies to lock in our position as a low-cost, reliable, high-performing operator. We are in a good position to leverage off this platform and deliver value from the Quadrant acquisition. Thank you. I will now hand back to Kevin.

Thanks, Anthony. As you can see Anthony and his team have done a great job with the balance sheet, and my whole leadership team have continued to do an excellent job in what has been another high-paced year. Now let's take a look at some of those growth opportunities, starting with PNG on Slide 23. PNG LNG continues to be a well-run, high-performing asset in our portfolio. Despite the extended outage caused by the PNG earthquakes in February, which were, first and foremost, a humanitarian tragedy, LNG production resumed earlier than expected and have returned at record rates. Highlights have been the 400 LNG cargoes shipped in May, 4 years after startup, and 2 new midterm sales agreements with Petro China and BP, for 0.9 million tonnes per annum in total. We've just had success to the Barikewa-3 well -- appraisal well, which exceeded predrill expectations and is located just 10 kilometers from the PNG LNG gas pipeline. Moving to Slide 24. We are moving closer to realizing PNG growth through expansion of our upstream position to better align with our joint venture partners across the LNG value chain. This includes farming into P'nyang, pursuing Muruk appraisal and further exploration in the Western Fold Belt. Expansion plans involve the PNG LNG and Papua LNG joint ventures operating together with 3 additional LNG trains proposed for the PNG LNG plant stake. One train, Train 3, will process PNG LNG resources. Santos will also benefit from 2 additional Papua LNG trains to a shared facility access fee that will reflect the value of our investment in PNG LNG infrastructure. We expect unit LNG processing cost to reduce with greater volumes, including Papua LNG. Moving to Slide 25. Darwin LNG continues to perform well with 24 cargoes shipped in the first half of the year. Despite a plant shutdown of 1 month in May, reflecting higher production costs, sales revenue was inline with last year due to higher commodity prices. First gas from the Bayu Undan infill well project has been delivered, with the first well started up and the second well being drilled now. Moving to Slide 26. I'm very confident that Barossa will provide backfill for the Darwin LNG project. There is no other project cost to being advanced -- as advanced as Barossa, which is now well into FEED with major engineering contracts awarded. Barossa is a major growth project with the potential to deliver around 9 million barrel of oil equivalent per year from 2024, more than doubling Santos' production in Northern Australia. With our operator, ConocoPhillips, and partner, SK, we are making great progress towards a final investment decision at the tail end of next year. Moving to Slide 27. We now have a clear development concept for the Barossa project, with 6 phase 1 subsea wells tied back to an FPSO for gas processing and condensate export. A 260-kilometer export pipeline will transport gas to the existing Bayu Undan pipeline and to Darwin LNG. Moving to Slide 28 and the Cooper Basin. Production is growing again. EBITDAX is 46% higher because we have continued to drive costs lower and increase productivity with production cost down 13%. This means we have been able to invest in more wells, with the fourth rig starting up just two weeks ago. The Cooper Basin story is one of renewal and about the success of the Santos strategy. Turning to Slide 29, you can see we have completely transformed the Cooper business. We've arrested long-term production decline, and production is growing again. We have further reduced well costs, which are now down 30%, since 2015 to $2.4 million per well. Upstream operating costs are down 34% since 2015 to $8.42 per barrel. We are focused on building and growing the business through reserve replacement and resource conversion, including appraisal, with Moomba South commencing this year; returning to Wilga exploration with 2 wells drilled in the first half of this year, the first Wilga wells in a decade; plans to execute a CO2-enhanced oil recovery pilot program in 2019, following successful admissible lab testing trials; and freeing up fuel gas for sale by deploying more solar and batteries to power our operations. Moving to Slide 30. The Cooper story shows just how much can be achieved with a laser focus on cost and efficiency and a renewed focus on the rocks. At the same time as reducing well cost by 30% since 2015, we have drilled 30% more wells, delivering higher production. While it is early days and no commitments yet, I am very excited about the upside potential of the Cooper, and I firmly believe that the Cooper may have its best years ahead of it. Turning to Slide 31. Moomba South, a large scale 2C resource close to the Moomba hub as the first of our growth opportunities, and I have more to say about others at our Investor Day in September. Our success at Moomba 212 has provided line of sight to economic development along the flanks of the field with our infrastructure footprint. We're progressing appraisal now with an 8-well program underway to test key uncertainties around gas in place and deliverability from the main reservoirs. Moving to Queensland on Slide 32. EBITDAX is up 86% as a result of higher upstream production and higher LNG prices. Although production costs are higher, this is, in part, offset by the freeing up of more gas for sale as we install electric drive compression at the Roma Hub. Eastern Queensland sales volumes are up, reflecting the ramp-up of Combabula and banked gas withdrawals. We drilled 118 wells in the first half, and GLNG shipped 40 LNG cargoes. I'm pleased with our progress on building equity gas supply, with Fairview production remaining strong, although it has been limited by well availability in the first half of the year. Infill drilling is now underway and will extend into 2019. Additional workover activity is also underway as we replace older well designs with a new efficient low-cost designs. Roma production continues to build, and Scotia has exceeded all expectations since startup. We've commenced our 430-well Roma East development, and the new Arcadia development has been sanctioned with construction now underway. Moving to Slide 33. Just as we've maintained focus in locking in our low-cost operating model in the Cooper, we've continued to do that at GLNG. Again, doing more with less means we can accelerate our development plans and unlock more gas over time. At Roma, our well costs are now down 84% since 2015 to $850,000 per well. Our run rate for development wells is down 77% to 2.6 days. And as a result, we're aiming to drill a record 300 GLNG wells this year. Turning to Western Australia on Slide 34. I've already touched on some of the benefits the proposed Quadrant acquisition will bring, but what it will also do is catapult WA into major growth status for us on the back of the very exciting Dorado discovery. Finally, on Slide 35. We delivered a commitment to sell our noncore assets. And I'd like to take this opportunity to commend our team, which has run these assets profitably and safely during this period, and wish them all the very best for the future. In summary, on Slide 36. Our strategy to focus on 5 core long-life assets and lock in a sustainable low-cost operating model is delivering clear results. Our balance sheet is in great shape, and our cash flows are strong, putting us in an excellent position to fund sustaining capital, net debt reduction, growth projects and exploration. And very pleasingly, we can now fund a return to sustainable dividends and reward those shareholders who stuck with us as we transform the business over the last 2.5 years. We are now poised for growth, with stable production and cash flows providing a great platform. On that note, I'm going to wrap up now, and I'll open the call to questions. Thank you.

[Operator Instructions] Our first question comes from the line of Adam Martin from Morgan Stanley.

Just on Cooper oil production on Slide 30, you've got a chart there that's showing about a 12% uplift in July for crude oil. Can you just talk about really crude oil [price] in the next couple of years, clearly, with Beach being quite successful chasing some smaller fields? Can you just talk about sort of production profile you're expecting out of that sort of asset in the next couple of years?

So Adam, I'm not going to give you any production forecast this morning. What I will say, though, is it's really a function of us continuing to drive the efficiency across our drill-complete-connect operating model, so faster wells, lower-cost wells, more wells. And as a function of that, you can see the quite rapid increase in oil production over the course of the last year or so. What I will say, though, is that we do intend next month at our Investor Day to cover that in a bit more detail. But it's not only just about drilling. I did mention a few moments ago the work we're doing on enhanced oil recovery projects. And again, we'll go into that in a lot more detail at the Investor Day next month. But -- it's certainly a very encouraging story. And the results over the course of last year, this will be very, very encouraging.

No, that sounds good. The trends at Cooper, just -- we just try to understand that. And second question, just around the acquisition, just can you just talk -- and I sort of tried to ask it yesterday, but just around the 2C opportunity for the existing gas assets. My understanding is the abandonment liabilities are quite high. So I want to try to understand, is there potential to push out those abandonment liabilities by bringing in some either new 2C resource gas or finding other fields nearby? So just trying to understand that just as it relates to the.

Yes. Thanks for that, Adam. Look, there is running room around the existing assets in terms of exploration running room and, obviously, very significant running room that, we believe, in the Beetaloo Basin. And so from a kind of growth perspective, we see that as a prevailing exploration and growth running room. Perhaps, Anthony, you want to talk a wee bit about the abandonment?

Yes. Thanks, Kevin. So to answer the first part of the question around pushing out the gas abandonment, then yes, as Kevin said, that's quite possible with 2C opportunities in that Carnarvon Basin area around the existing near-field opportunities. So we've already got some discoveries in that portfolio from the JV that we're in with Quadrant. So from a gas abandonment perspective, yes, it's further out, and backfill opportunities could push that out further. With regards to the Quadrant oil assets, the main oil asset that's under abandonment is Harriet, which is low-cost onshore and shallow water abandonment activities spread over -- smoothed over a number of years. So there's no big one-off lumps of Harriet abandonment, it's sort of steady as she goes over time.

And Harriet well percentage, will that be your total abandonment liability for that acquired asset?

I don't want to give that detail here yet.

Okay, okay. And just final question, just I didn't quite understand the bit about the Queensland production cost going up a touch. Can you just explain that in a bit more detail? That's the final question.

So yes, the Queensland costs are basically really two things. One, as Kevin said, electricity uses for transformation, so the electricity in that increases the gas sales. And the other thing is driven by increased activity so, obviously, some workover activity and increased activity in the sale leads to some higher costs.

Our next question comes from the line of James Byrne from Citi. Please go ahead.

So just in the context of the Quadrant acquisition, I just wanted to understand a little bit about capital allocation across the portfolio. You've restated your capital priorities with debt repayment at the top, as we'd expect. Just wondering whether I should think about the incremental $1.2 billion of debt to fund Quadrant as being serviced entirely by the cash flows from Quadrant and essentially mutually exclusive from the rest of the portfolio. Or am I thinking about that on an entire group basis? And if it is the latter, does that take any capital away from supporting growth in the base business that you otherwise would have had?

Thanks, James. Look, it's better to say that it's driven in a portfolio level, as we've said, on yesterday's call that it brings our free cash flow breakeven down to $32 a barrel. So on a 2018 basis, that's down $3 from the new $35 target, which just set today. So that lower portfolio value gets balanced across all of the capital. Having said that, though, as Kevin said, we've committed to a [4 3] in the Cooper now, the GLNG drilling activities ramped up and set. So those two things, really, aren't going to change. So the overall portfolio will still balance the CapEx required.

I think what I would add to that, James, is that within GLNG and Cooper particularly, which is about two assets that returned, that require a high sustaining capital on an annualized basis, those are self-funding. Those are self-funding operations. And the operating discipline model that we often talk about ensures that they can spend more capital if they have more wells to drill, provided they remain cash flow-positive below our threshold breakeven levels defined within our operating model. And I mean, that's what you should think about, those 2 assets. They have continued to self-fund their growth. And as production grows and earnings grows from those assets, that will allow them on a unit cost basis to drill more wells. And then, really, that's about capital prioritization across the rest of the portfolio, and we're going to prioritize the highest rate of return projects and activities we have across the portfolio as we go forward.

Secondly, look, I don't want to steal the thunder from the Strategy Day at all, but with regards to the outlook for the Cooper Basin, you flagged there's 100 opportunities for exploration and appraisal. Just wondering how I should think about the priority between exploration and appraisal for reserves growth versus production growth, particularly in the near term. Now if I were to drill down and look at Moomba South in particular, looking at some data this morning, it looks like that Moomba 212 well that you've called out has an initial production rate of 3 million gas a day which is 50% more than your infill wells at Big Lake. So should I think about production growth really being premised on appraisal success? Or is your pipeline of opportunities in infill drilling sufficient for production growth in the near term?

Look, I don't think you or all the other callers on the line have enough time for us to answer that question in totality. However, let me just try and touch that, and we will obviously cover that in a lot of detail at our Investor Day next month. But let me just say that we didn't see 100 exploration wells. What we're saying is with the fourth rig in the Cooper in a go-forward basis, we see the drilling rig going to around 100 wells per annum going forward. We think about 87 this year because we've just brought it on 2 weeks ago. But on a go-forward basis, that should give us the ability to drill around 100 wells per annum. And so that will be a max of development wells. There'll be some appraisal wells in there, and there'll be some exploration wells. And what we've been trying to build at the Cooper is a balanced approach to our activity levels, so we are drilling exploration wells and targeting the significant prospective resources we have across the Cooper Basin and also targeting capital at our very significant 2C position across the Cooper Basin, so we keep converting that resource into reserves and, ultimately, spending capital on developing the undeveloped 2P reserves. And so it's getting a more balanced approach to how we grow the Cooper. Now you are right in one sense, I won't go into any specific well results, but we have seen some very encouraging well results this year. And some of those have been undeveloped 2P wells were drilled and completed, and they've come on and they've been encouraging. Some have been 2C wells but have converted to 2P. And some have actually been exploration wells that we've drilled with prospective resource that went straight into production because we have got good results. I think the key message here is that what -- the focus on the rocks over the last couple of years, we are identifying and building a much stronger inventory of opportunities across the Cooper Basin. And I look forward to sharing our insights on that with the larger investor community at our Investor Day next month.

I certainly look forward to hearing all about it, Kevin. And probably another one that's better suited for the Strategy Day, but I think I'll see what I can get out of it today. Just with regards to the Horizon contract where you're basically talking about focusing on growing Queensland volumes in your portfolio to satisfy that contract and essentially free up Cooper Basin production, what -- over what time frame should we think about that production growth to free up the Cooper and the magnitude of those?

I think the way -- the way I think you should think of that really, James, is more about what we're doing on the East Coast at totality. We view the markets on the East Coast as one big market -- or two markets that connect to our business. We've obviously got our LNG market, our export market, through our GLNG project and then the domestic gas market here on the East Coast serviced and the main by the Cooper Basin. And so what we are doing quite simply when we look at transportation costs that it makes more sense to supply our current GLNG commitments from Queensland resources than it does from the Cooper Basin. And so we're focused very much on freeing up and developing our Cooper -- sorry, our Queensland resources to do that, then freeze up the Cooper Basin to become a higher value swing producer that can meet the needs of the domestic market but also give us the opportunity to put excess volumes into the LNG market. That's a longer-term strategy. It's -- we've been pleased with the progress over the last year or so in that area, and that will continue to progress in the years ahead.

Our next question comes from the line of James Redfern from Merrill Lynch.

Three questions, please. The first one is just on the P'nyang farm-in. Should we expect this to occur before yearend, around the time of expected FEED entry? And also, any guidance you can give on the amount of the farm-in in terms of the dollar amount that we should be expecting? And I've got two more after that.

Look, James, I think I'll try and answer that best I can. I think all I can really say is that on timing, my hope would be -- in that time period you're talking about, we're optimistic. And then, certainly, we're in discussions with the joint venture partners, in a very positive discussions following the receipt of their proposal for the farm-in. Look, the terms of the agreement are confidential. And obviously, we'll -- once we announce it, we'll be able to communicate what we can. But at this point in time, those discussions are confidential, and I can't disclose or give you any guidance on that, sorry.

Yes, that's fine. I totally understand. A question on GLNG. Your guidance of reaching production of 6 million tonnes annualized by the end of 2019, that's 1 million tonnes higher than today, I'm just wondering how we should be think about achieving that. Is the FEED gas -- the increase in FEED gas going to come meekly from growth in the Cooper Basin and GLNG in terms of reaching that target?

No. I mean, we're drilling 300 wells this year in Queensland, at GNLG, and we expect to have a significant drilling program next year also. Our current forecast are that we're on track to achieve that target, and that includes the fact that we are -- of course, GLNG is selling some gas in the domestic market as a consequence of the hedge agreement we signed with the federal government last year. But no, we're still confident at this point in time we're going to achieve that target, and that will come from Queensland CSG reserves.

Okay. And then just last one, it's a longer-dated question. Barossa-Caldita expecting first gas late in 2023, just wondering when do you expect Darwin LNG to shut down for maintenance and how long that maintenance would take before restarting?

Well, look, I mean that really depends on the success of the current value on that infill well drilling program. And the first well that we've just brought online has come on and with better than expected performance. That has been very good news, obviously, with 2 more wells to drill and complete and tie in. Look, the plan right now is that sometime in 2022, we expect to come to the end of field life for Bayu Undan. If that's extended because we get better field performance, then that's a great outcome. But at some point in 2022, we expect that to come to end of field life. And then, as you see, we -- towards the end of '22, I should say. And then in '23, it's really about doing any work we have to do to get ready for bringing on Barossa-Caldita.

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

I've got a few questions. The first one is just you guys have changed the way that you're reporting in terms of the FX and kind of moved it back above the line just to be more comparable. I guess, the first part of that double question is who are you trying to be more comparable to? And then just on an ongoing basis, should we, therefore, be thinking that you'll continue to do that but keep commodity hedging below the line?

You're talking underlying, Andrew?

Yes.

Yes. So there's no change to any statutory reporting. Yes, so basically, with FX now pretty much just -- the volatility standard is part of that business, so we just try to simplify the underlying profit calc, and FX is now just part of the business. Yes, we will continue to normalize for commodity hedging.

Okay. The second part was just in terms of the 300-well program. I mean, obviously, it's a normal for you to do it at Roma East. Just wanted to get a sense of what the costs are at both Arcadia because, obviously, you've got to do fracturing there as well as what you're doing at Fairview and Scotia.

Well, look, I think, Andrew, rather than go through all the different fields and individual well designs and costs here this morning. That's something that we can look to provide more later on, next month at the Investor Day. And you're right, there are different programs and different types of wells with different fields, and so that's something I'd defer to the Investor Day.

Okay. And I guess -- just, I guess, tying to what a couple of people have been asking about, GLNG outage. Fairview, I think, for the last six months has had, you've been saying, about sort of lack of availability and I think mobilized an extra rig already. But volume's still continuing to decline down to sort of 425 today compared to 465 at the start of the year. And so I just wanted to get an idea about what we should be kind of expecting from Fairview in the future.

Well, look, I mean I think we can shed more light on that at Investor Day also in terms of showing you the infill drilling program that we've now commenced. And as I said earlier, that will continue into 2019. So we'd be expecting to see some production come back there at Fairview. And -- but I think what's important is -- just to point out, Fairview is still performing very, very strongly in line with our expectations. And it's a world-class ESG reservoir. Our focus primarily over the last couple of years has been on Roma and Scotia and, of course, getting through sanction on Arcadia. And we'll progress all of those things, in some cases, ahead of plan. The ramp-up at Scotia has been very pleasing. However, as I stated, we've now got that rig mobilized into Fairview to do the infill drilling program and accelerate some production there and, hopefully, we'll see some results of that early in 2019. But we can shed more light on that as we talk more specifically about GLNG and the ramp-up profile at our Investor Day.

And last one just for Darwin LNG. Your current contracts with Tokyo Gas and JERA, and they've both, even in the last 6 months, what they've had current contracts on long-term projects expire, then they've materially reduced volumes. I just wanted to get a sense about what you're thinking for Caldita-Barossa, particularly given that you're going to go FID next year. And also, will you guys be equity marketing? Or do you still expect to be sort of group marketing?

Look, I mean, at this point in time, we are working alongside our partners looking at joint marketing opportunities as well as equity market opportunities. At EMEA, they'll be a combination of the 2. But right now, there's a marketing review process going on testing the market. And I'm not really in a position right now to tell you what the outcomes of that are because it's an ongoing process. And over the course of the FEED process, throughout the course of the next year, I would hope to land on that and, obviously, determine and put in place the level of contracting to support any FID decision.

I guess I would just kind of ask you, I mean, you signed that sort of agreement with ENN earlier in the year. Just trying to get a sense about how -- if that's still ongoing and what's happening there.

Yes. Well, obviously, it went on hold during the Harbour process, and we've reinvigorated our discussions with ENN for that joint venture. At the point we announced that, we made it very clear to the market it was not exclusive, and so we can continue to do our own marketing separately. But that joint venture effectively could be a buyer also to satisfy Chinese demand.

Our next question comes from the line of Mark Samter from MST Marquee.

A couple of questions, again, I apologize if this was slightly covered earlier, I slightly drifted out during the Q&A. With Cooper reserves, you guys have been pretty clear to date that you don't expect reserve upgrades to come from 2C to 2P migration. Beach, in their reserve statement a couple of weeks ago explicitly highlighted that they were migrating 2C to 2P based off your production costs. Have things changed in Adelaide and just Santos is the conservative big brother in town now? Or did you -- your numbers were historically more aggressive than theirs, just how should we contextualize? Because I think that to you guys have been about [Indiscernible] that they migrated. How should we think about that?

Look, I think, Mark, we're going to help you -- at least we're going to try very hard to help you think about that a little differently to maybe how we historically have looked at the 2C to 2P conversion in the Cooper, at next one's Investor Day, that will be a big focus of it. We've got a very considerable 2C resource base in the Cooper. And the way that we have matured those resources to reserves over the years has meant -- has been quite a slow kind of bleed -- well, certainly, in recent years, a slow bleed and a slow conversion rate. We'll take you through the changes to that resource to reserves maturation process that we are putting in place through appraisal programs of large opportunities, like Moomba South, that we've highlighted in the pack at the Investor Day. And I'm confident that we will see more significant conversions in the future, more lumpy conversions as well as the continuous kind of slow bleed that we see from the infill near-field exploration drilling programs. But really, we need to take you through that in more detail at the Investor Day next month and also a focus on the significant 2P undeveloped reserves that we have and show you how we're allocating capital to develop those also.

Okay. And then just on GLNG. Can you just kind of shed some light on how the JV as a whole might be thinking about particularly now spending billions of dollars to have capacity, 30% empty. Obviously, those volumes are highly politicized at the moment. But how the JV is thinking about both potentially increase equity molecules but also potentially, if the market permits it, third-party molecules into that capacity.

Yes. Look, I mean I think how the JV is thinking about it really is a question for the JV partners. What I can say, though, is I've been really impressed by the way the joint venture's been working over the last 9 months or so to start focusing on the longer-term strategy for GLNG. So the partners are working together developing and putting in place the plans for the longer-term strategy for GLNG to address those issues that you're mentioning. The focus over the last couple of years and really into this year has been very much on ramp-up and getting just to steady-state production levels around the 6 million tonnes that we talked about. The partners are very complementary of the upstream operating performance and the fact that we've given the project a much brighter future by virtue of the fact that we've been able to get the drilling costs down and really improve the drill-complete-connect process which, ultimately, makes faster development -- or leads to faster development of the undeveloped reserves but, just as importantly, in fact, very importantly, improve the economics of 2C to 2P conversion for the future. And that's something that over the next few years, we want to be able to demonstrate our ability to do, which is why we're so focused on the efficiency of those upstream operations.

[Operator Instructions] We do have a question from Joseph Wong from UBS. Please go ahead.

Just three questions. And this is on last night, on the presentation slide for the Quadrant acquisition, you mentioned there's a 30% EBITDAX accretion associated with the acquisition but only a 5% EPS accretion. Can you provide any detail on that?

Yes. Thanks, Joseph. I think one of the biggest differences is, obviously, the EPS accretion is -- we equated those for 2019 post any purchase price accounting adjustments that will happen. So it's an estimate, it's a forecast. And as you know, when you guys repurchase price accounting, everything has to be fair valued. So the big difference is between items that will flow through at fair value of purchase price accounting that will be largely noncash.

That's probably it for us, I think. I think there's one more questions, yes, I think there's one more coming in.

Yes, we do have one more.

We do have a question from [Phil Cavernik] from Crédit Suisse. Please go ahead.

Maybe not. Okay, well, if there's no further questions, we can wrap up that. I just like to thank everybody again for your time this morning. And for those that we'll be meeting over the course of the next week, so on our road shows, we look forward to talking to them. So thank you very much.