Good morning, everyone. It’s Matt Kay here. And welcome to the call. I’m joined on the call today by Morné Engelbrecht, our Chief Financial Officer. I’m also joined in the room by a number of our executives who’ll be available to also answer questions, later. The format of today’s presentation is that Morné and I will run you through the presentation pack, which includes a summary of our FY19 results, as well as our plans for FY20. And at the end of that, we’ll be open for Q&A. So, let’s move to the presentation. On Slide 2, that includes our disclaimer, which seems to be getting larger as we get larger as a company. And you’ll see it includes oil price assumptions and FX assumptions that are used in our five-year outlook and our FY20 guidance, as well as a reserves disclosure. So I’ll let you read that at your leisure. Let’s go to Slide 3. Put simply, Beach enjoyed a record year in FY19, a year in which we delivered, and in most cases, outperformed on all of our promises. This success has put Beach in excellent shape to launch an expanded investment program, commencing this year FY20. Our results in FY19 were driven by record production of 29.4 million barrels of oil equivalent, 65% higher than the prior year. Record production was achieved by a combination of a full 12-months contribution from the latest energy assets, improved facility reliability, exceptional oil production in our Western Flank acreage and strong customer nominations for our gas business. In FY19, we achieved a drilling success rate of 85% in our operated Western Flank acreage as well as an overall success rate of 84% across the 134 wells drilled. This is strong evidence that there is significant remaining undeveloped oil and gas potential left in the Cooper Basin. Pleasingly, the combination of positive appraisal results in the Cooper, combined with the reassessment of our asset reserves, has led to a 204% organic 2P reserves replacement, extending our 2P reserves life from 11 years to 12.4 years. Record production, combined with our continued focus on margins and costs, helped Beach deliver a record underlying net profit after tax of $560 million, up 86% on the prior year. Our return on capital employed of 27% was well above both the prior year of 19% and our five-year target range of 17% to 20%. This has meant that Beach has fortified its financial position with $172 million of net cash at the end of June, more than 2 years ahead of our initial expectations. This was helped by delivering on our synergy and cost reduction targets during the year, with more to come. And we are pleased today to report a final dividend of $0.01 per share fully franked. So while we’ve enjoyed great success over the past year, this is just the first step in Beach’s growth story. Our focus remains on delivering best-in-class returns, and we’re excited by the capability of our expanded portfolio and our team to deliver that agenda. What you will hear from us today is our plans to increase our five-year investment program by up to $1.5 billion versus our previous five-year outlook. This investment acceleration starts now. Today, you’ll hear details about our plans to invest between $750 million and $850 million in FY20. The enhanced investment program is expected to lead to an increase in production to between 34 million and 40 million barrels of oil equivalent by FY24. In FY20, we plan to participate in up to 194 wells utilizing 10 rigs, up from 5 rigs at the start of FY19. This includes doubling the number of wells in the Western Flank in FY20, going from 42 up to 84. So whilst we increased our reinvestment in the business, it was quite simple, because 90% of our projects commencing in FY20 are expected to generate rates of return greater than 50%. So the question across the business has been, why would we not increase the investment? We have the balance sheet. We have the assets. We have the people. And we’ll provide more details around the work program that reinforces that thinking. Our investment will see Beach generate in the order of $2.7 billion of free cash flow over the next 5 years, including more than $1 billion of free cash flow in FY24. Our target of averaging 100% 2P reserves replacement over this five-year period remains. Let’s go to Slide 4. At our Investor Day in September last year, we outlined a detailed view of our growth plans for the next 5 years. And you can see here a summary of what we said we would deliver this year and what we’ve now achieved. I’m proud to say that we’ve delivered on a range of metrics, including production, free cash flow, EBITDA and reserves replacement. I’m proud of these results because I believe Beach is a company that delivers on promises. Our FY19 performance is clear evidence of this. Let’s go to Slide 5. This outlines our safety performance. As you know, safety is always our primary focus and drives our behaviors at all levels across the company. Continuing the theme for FY19, this year was our safest on record, our best environmental performance on record and our best of process safety performance on record. And that’s an outstanding result in a year where we integrated the major acquisition and become a genuine onshore, offshore and gas processing operator. Our goal, of course, isn’t just be better every year, our goal in safety is to achieve 0 HSE issues. So our drive for excellence has not stopped and we will not stop. Let’s go to Slide 6. This outlines our revised five-year outlook for production, free cash flow and CapEx. As you can see, our production outlook has increased and accelerated compared to the outlook we released to the market at the Investor Day in September last year. As I’ve stated, this is expected to generate over $2.7 billion in free cash flow over the period, including more than $1 billion in FY24. We will achieve this improved production and free cash flow through the acceleration of our organic growth investment. With Beach’s balance sheet already in a strong net cash position, now is the time to deploy our capital and exploit our valuable asset base. And I want to make it clear, this five-year outlook to production and free cash flow is based on organic investment only and includes no blue-sky. The path we’re taking is quite a simple one. We’re investing more to grow faster and increase total shareholder returns. Slide 7 outlines the rationale for higher investment expenditure in some more detail, specifically, the new information developed since our Investor Day last year. I won’t go through the entire list, but there are some things worth highlighting, such as the successful appraisal drilling results at Bella and other Western Flank fields, leading to higher reserves and warranting further appraisal activity ahead. You’ll hear today about our plans to double the number of Western Flank wells in FY20 and significantly increase oil production. On Slide 8, you’ll recall that our target has been to achieve 100% organic 2P reserves replacement. Well, we did better than that in FY19, achieving 2P reserves replacement of 204%. This in turn led to an increase in 2P reserves life from 11 years to 12.4 years, yet another example of Beach delivering on what we say we will do. Slide 9 covers our FY20 guidance. What we’ve done here is to show our FY19 guidance metrics as we reported them on the column to the left. This, of course, included 11 months of Victorian Otway Basin assets at 100% interest and 1 month at 60% interest. With our working interest now down to 60%, the central column shows what FY19 would have looked like if we own 60% of Victorian Otway assets through the whole of FY19. We feel this is a better comparison point to FY20 guidance shown here today. FY20 guidance shows a forecast lift in production versus pro forma FY19 levels, moving to between 27 million to 29 million barrels of oil equivalent. CapEx guidance. We’ve already talked about the $750 million to $850 million, and we’ll talk more about later. EBITDA guidance is $1.25 billion to $1.4 billion. In relation to DD&A guidance, we release this on $1 per barrel basis going forward as obviously a key variable for DD&A is production. For FY20, we expect DD&A to be in the range of $17 to $18 per barrel. Both EBITDA and DD&A guidance will be explained in more detail shortly by Morné. Slide 10 outlines a little bit more granularity on FY20 production. The really pleasing thing here is a significant increase in oil production we expect to achieve. Oil output from our Cooper Basin assets increases from 6.8 million barrels in FY19 to between 8.7 million and 9.2 million barrels in FY20. The increase is driven by Beach’s participation in up to 97 wells, oil wells that is including up to 16 horizontal wells. Gas production is expected to be in the range of 14.8 million to 15.8 million barrels of oil equivalent. Higher gas output from the Cooper Basin is expected to offset the impact of statutory shutdowns this year at Kupe and Otway assets, with facility reliability and customer nominations remaining the key variables, of course, to guidance ranges. On Slide 11, we provide more granularity on the FY20 CapEx. Here, we show you a split by expenditure, by part, by assets and by the end target. The size of the investment pie is larger, of course, than FY19, but the splits for FY20 are broadly similar to the prior year. More than 80% of our investment in FY20 is targeting growth, either development, appraisal or exploration. Almost 2/3 of our investment is targeted to bring gas supplies into the East Coast gas market and then just under 1/3 targeting oil. You’ll also note that more than half of our investment spend will occur in our Cooper Basin assets. Of course, with an increase in expenditure in the Victorian Otway as we kick off our drilling campaign there this year. It’s worth pointing out that more than half of our FY20 expenditure will not contribute to FY20 production. It’s about creating a sustainable growth business. What that meant is that much of the investment is directed at gas assets, such as the Victorian Otway that will contribute production over the medium to longer-term as well as finding additional reserves. And again, I’d note that this is higher returning investments, with more than 90% of our projects commencing in FY20, generating rates of return above 50% and 25% of those projects actually generating returns of more than 100%. Let’s move to Slide 12, which I think is an important slide. This helps kind of picture of where with -- the difference was between FY19 and FY20 CapEx. And what the chart shows is that FY20 CapEx is driven by three things: one, the commencement of our extensive drilling campaign in the Otway Basin; two, some minor rephasing of capital from FY19; and three, and importantly, a 40% increase in the number of Cooper Basin wells in FY20 compared to FY19. If we go to Slide 13. This is a chart that I’m sure many of you have already seen and was released by AEMO earlier this year. And what it shows is that forecast Southeastern Australian gas supply versus Southeastern Australian gas demand. And the conclusion here is that Southeastern Australia is not producing enough gas to meet its own demand, meaning the states of South Australia and New South Wales and Victoria are reliant on gas diverted from LNG projects in Queensland or elsewhere to meet demand. And going forward, the picture doesn’t get much better, with the reliance on LNG or future suppliers to increase over time, unless, of course, there is a significant increase in supply. And we at Beach recognize the challenge and the opportunity. And we’re doing all that we can to bring on as much new supply as we can as quickly as possible, with almost 2/3 of our investment in FY20 designed to increase gas supplies. I won’t go through Slide 14 in too much detail, as we’ve shown it a number of times to you before, but it highlights the percentage of our future East Coast gas supply that’s expected to be sold at market prices versus legacy prices. It’s important to note that the tailwind is now a year closer. By FY ‘22, more than 70% of our supplies are expected to be sold at market prices. Before I hand over to Morné to run through the financials, I want to highlight Slide 15 which outlines the progress we’ve made to bring down operating costs. The three columns on the left show annual average operating cost per BOE over the past 3 years, with the impact of the Lattice acquisition increasing our average operating cost from $9.10 to $9.70 per BOE in FY18. Over the past 12 months, the impact of our operational excellence program has reduced our annual operating cost per BOE to $9.30. The 3 columns on the right show operating cost per BOE to the 3 most recent half periods since we acquired Lattice, with operating cost declining from $9.90 to $9.20 per BOE. So to date, we’ve taken $21 million out of our direct controllable operating costs, meaning we’re well on track to achieve our $30 million cost-out target by the end of FY20. And we’ve done all of this while improving our safety performance and increasing our facility reliability to above 97%, again, on track to achieve 98% by the end of FY20. I’ll hand over to Morné now to run through some financials and come back to you a bit later. Morné? Morné Engelbrecht: Thanks, Matt. Good morning, everyone, and thank you for joining us today. As Matt rightfully noted, Beach enjoyed a record year in FY19, a year in which we delivered and outperformed in many cases. This is reflected in what you will see from today’s results. To start off with, Beach generated just over $1 billion in operating cash flow in FY19 from our diversified portfolio of oil and gas assets operating at our 5 different basins. This was driven by record production, which was a combination of an exceptional 16% increase in Western Flank production, a full 12-months contribution from our expanded diversified portfolio of assets and a combination of high gas customer nominations and higher reliability. This mostly underpinned an 86% increase in underlying impact of $560 million. Our underlying EBITDA also increased by 80% to $1.375 billion in FY19. EBITDA was positively impacted by the Lattice GSA revaluations as part of the purchase price accounting, as tracked previously. The impact going forward will be much lower, with an estimated $50 million to flow through in FY20 and included from the EBITDA guidance range of $1.25 billion to $1.4 billion. It should also be noted that the impact of the new leasing standard will also positively impact future EBITDA as lease expenses are shifted from operating expenditure to depreciation and interest expense. In total, we expect all our leases will have a positive impact of $30 million on EBITDA and a broadly equal but offsetting impact on DD&A for FY20. There will also be some mining interest charges running to these leases. Our leases rate mining to draw rigs, property leases and helicopters. A lot of these assets amounted to $97 million with an equal offsetting lease liability will be recorded on the balance sheet on July 2019 when we adopt the new standard. This is an accounting change only and has no impact on cash. Our return on capital employed was also exceptional at 27%, well above our 17% to 20% target range. Turning to Slide 18. This is a summary of FY19 financial highlights compared to FY18. We have touched on a number of these items already, so I won’t dwell on this too much. The strong performance of the group, combined with the proceeds from the sale of 40% interest in our Victorian Otway assets, saw Beach exit FY19 in a very healthy net cash position. I also wanted to make note of our FY20 cash tax obligations, which is expected to be around $170 million higher than our tax expense. This is a function of the deferral of some cash tax from the FY19 year into FY20 and our significant increase in size and profitability. Furthermore, the board has approved the payment of a $0.01 per share fully franked dividend, bringing total dividends paid in FY19 to $0.02 per share. Turning to Slide 19. This is a bridge from FY18 underlying impact of $302 million to FY19 underlying impact of $560 million. The key drivers in higher profits are the increase in production volume and production mix, other revenue associated with the unwinding of liabilities associated with the GSAs, a low Australian dollar, and this was offset by higher taxes due to higher profitability and earnings and higher depreciation and gross costs associated with our expanded asset base and higher production volumes. Turning to slide 20. This shows the movement in our net cash position in FY19, with our operating cash flows of over $1 billion and proceeds from the Otway sale helping to drive Beach to a very healthy net cash position at the end of FY19. A healthy and very robust balance sheet is further supported by the fact that our gas revenues cover all of our operating costs. This, together with high margins and low costs, operations generates substantial cash flows for Beach. At the end of the year, Beach had access to $622 million in liquidity, with all outstanding debt repaid and our $450 million revolver facility undrawn. This very healthy and robust funding position, together with the forecast positive free cash flow in FY20, will help fund the execution of our growth plans. To summarize. Beach ended FY19 in excellent shape, with a strong balance sheet and a net cash position and over $600 million in liquidity. Our net cash position, combined with our gas business, provides Beach with the natural hedge against oil price volatility, with our FY20 gas revenues covering all of our forecast operating costs. We expect gas revenues will increase in the coming years as we target higher production and benefits from increased exposure to market prices. Beach prides itself on our low-cost operator model, and our operational excellence program continues to deliver outstanding results. The operating cost per BOE stands at $9.30 in FY19, and we see there is room to reduce this even further over the coming years. This will be driven by achieving our target of sustainable 20% reduction in direct controllable operating costs or around $30 million per annum. As you heard today, we have already reached $21 million by the end of FY19. Beach is a growth company, and our priority for capital allocation remains growing total shareholder returns via value accretive growth investments. I would like to hand back to Matt to run you through the assets. Matt?

Thanks, Morné. We spent a lot of time today updating you on our plans for accelerated growth, so I won’t go through our asset slides in too much detail. But it’s worth highlighting a few items. Turning to Slide 23. We’ve had an outstanding year in the Western Flank. Increased drilling led to reserves replacement ratio of over 300%, an increase in Western Flank reserves life to over 8 years and a 15% increase in production. The 6 horizontal wells we drilled delivered results well ahead of our initial expectations. And moving ahead, we plan to double that drilling activity in the Western Flank, with 84 wells planned in FY20, increasing operated production from 15,000 barrels per day to more than 20,000 barrels per day. We’ll make a modest investment in infrastructure to ensure we can handle higher oil volumes over the coming years. That’s the definition of a good problem to have. Skipping ahead to slide 25. We talk about Bauer apps, and why not, it’s a great asset. We’re often asked to provide more information about Bauer to the market. And what you see here is a map on the left, which shows our 2p top reservoir map from last year. Since then, as you know, we’ve drilled 4 appraisal wells to try and understand the extent of the field better. And what we’ve done is discovered an easterly extension to the field. So the map on the right demonstrates how the field limit has been increased, which has underpinned the increase in reserves for Western Flank for FY19. In FY20, we plan to drill 23 wells in Bauer, including a further 8 appraisal wells to potentially increase the field limit even further. We also plan on drilling 7 additional horizontal wells to exploit the existing reserves and increase our production. Let’s go to slide 26 which is a broader slide showing the Western Flank oil fairway and our plans for FY20. So Beach plans to invest around $200 million during the year, participating in a total of 77 oil wells, including 41 exploration and appraisal wells and up to 17 horizontal wells. Around 15% of FY20 Western Flank CapEx will be invested in ensuring the right level of surface infrastructure being in place to accommodate the higher forecast forward volumes. Our drilling program will see us continue to roll out the Bauer appraisal strategy across other fields. Slide 27 outlines our Western Flank gas business. Again, it was a great year here, with production up 35% and a doubling of our 2P reserves after successful appraisal at the Lowry and Udacha South fields. In FY20, we plan to drill 3 to 5 prospects that were unearthed through the Spondylus 3D seismic survey, and if successful, consider whether we need to expand our gas processing capacity. Slide 28. The Cooper Basin joint venture had another good year, with 92 wells drilled at an 87% success rate. Over half the wells drilled were exploration and appraisal wells, which enjoyed a success rate of 80%. Let’s go to slide 29. You heard during the year that seven of the eight appraisal wells drilled at Moomba South were completed and put on production. The results there, combined with other successes, saw Beach replaced 98% of our production. The operator, Santos, has indicated they will target drilling around 100 wells a year, with further focus on refilling the hopper through exploration and appraisal, including follow-up drilling in Southwest Queensland and horizontal pilot programs. Let’s go to slide 30. We enjoyed another really good year for the Victorian Otway assets as well, thanks to facility reliability above 97% and strong customer demand for our gas. We completed, as you know, the sale of a 40% interest in our assets to O.G. Energy and also acquired the undeveloped La Bella gas field. A comprehensive program to integrate, reprocess and analyze all 3D seismic has now led to a better understanding of our existing gas fields and also the identification of new prospects and leads. FY20 will bring the drilling activity back to those Victorian assets, the first drilling year since 2014, and that was a key reason, you’ll recall, for our Lattice acquisition. So Slide 31 shows our exploration and development program is designed to fill the Otway gas plant back to its capacity of 205 PJs a day or beyond and keep it full for many years. Our updated outlook for the OGP shows that combined with our development wells, achieving one exploration success out of the 2 upcoming wells, will allow Beach to keep the OGP full until at least FY ‘26. As you know, drilling will get underway later this half with the extended reach well Black Watch-1. Can also advise the Ocean Onyx rig for our offshore campaign remains on track for delivery between December and February. And I again highlight that out of our 10-well program for the next 3 years, 8 of those are development wells. Let’s go to Slide 32. Production performance at Bass gas remains a key priority for us and we’ve continued our development studies on the Trefoil gas field. Our initial assessment points to the likelihood of an economic development and a JV, joint venture that is, plans to enter concept select phase during FY20. Let’s go to Slide 33. Let’s move across the test and then go to Kupe, and this is a cracking asset for us. The asset and our New Zealand team delivered a strong result in FY19. Facility reliability was above 99%, combined with strong customer nominations, which saw production increased to 3.2 million barrels of oil equivalent. The Kupe joint venture is targeting FID for the Kupe compression project shortly, with first gas by late FY ‘21, and that will keep the field on plateauing until FY24. Slide 34. Let’s go west. We’ve made great progress in FY19 in relation to commercializing gas at Waitsia. With our operator, Mitsui, the joint venture has completed all FEED activities on Stage 2 development, with EPC tenders in progress. As we’ve announced for Stage 1, we signed a 4.5-year contract with Alinta Energy for the delivery of 20 TJs a day from FY ‘21. Importantly, our investment in capacity expansion includes a large diameter connection to the Dampier to Bunbury Natural Gas Pipeline, clearly, increasing the flexibility of our future gas sales. We also aligned our interest with Mitsui via the sale of a 17% stake in our other payments. In the first half of FY20, we will drill the exciting Beharra Springs deep well and commence construction of Waitsia Stage 1 expansion to support the Alinta contract. We’ve made good progress in commercial discussions with a range of parties to support Stage 2 expansion. And the joint venture is targeting a final investment decision in FY20. We also plan on recording the Trieste 3D seismic survey this year to work from Kingia and Highcliff plays to the Southeast of Waitsia. Very briefly on Slide 35, we’ve completed the Haselgrove-4 well after encountering thicker sands than Haselgrove-3 in both our primary and secondary targets. Whole conditions didn’t allow us to run the full suite of logs, but we’re encouraged enough by the data we have -- 2 production tests designs of interest, and that will happen over the coming weeks. Slide 36, we’ve also made good progress on three of our key frontier exploration plays. The Bonaparte isn’t shown here, but you’re all aware that we aligned our interest with Santos around six months ago. In the Carnarvon Basin, our farm-in agreement with Cue Energy was completed in late FY19, with operator BP securing a rig to drill the large Ironbark prospect in FY ‘21. Beach is also committed to stage 3 of our work program in our Canterbury Basin permit off the coast of New Zealand. The newly formed or reformed joint venture is planning to drill the large gas liquids Wherry prospect in FY ‘21, subject to rig availability. Slide 37 is a summary of our current planned rig activity for FY20, showing Beach contracting 10 rigs throughout the year at various stages. Slide 38 supports our drilling campaign in FY20, which summarizes the number of oil and gas wells that we plan to drill this year. 196 wells means we’ve got a very busy year ahead of us. On Slide 39, I know that we’ve bombarded you with a lot of information today and a fair amount of new information as well. So let’s just take a step back and maybe highlight 8 areas as key summary and takeaway. One, we’ve had an outstanding FY19 with high filling success rates, more than 200% reserves replacement and with net cash at bank. Two, we have a portfolio that presents us with exceptional growth opportunities, with 90% of those for FY20 presenting greater than 50% rates of return and surrounding our own infrastructure. Three, that puts us in a position, a great position, in fact, to accelerate our growth. Four, we’re ready to go right now. We’ve outlined our plans to fully exploit our existing asset base through the drilling about 196 wells and investing $750 million to $850 million. Five, the main change from a year ago is that we’re going to be pushing even harder on the Western Flank. In fact, you will recall 3 years ago, many were predicting the decline of the Western Flank oil play when it had a 2p reserves life of just 3.5 years. Today, following a very successful 12 months, Beach’s share of western flank oil production has reached its highest ever level, and our 2P reserves life for Western Flank oil has now increased to 8 years. Six, our investment in FY20 is just the beginning. Overall, we have identified up to $1.5 billion of new growth projects for the next five years, covering a mix of high returning, short-cycle oil wells to longer-term gas exploration and development opportunities. Seven, the end result is an increase in our production and free cash flow targets over the next five years, all while targeting a return on capital employed of between 17% and 20%. And lastly, the portfolio represents an outstanding opportunity to Beach and its shareholders. Now is the time to hit the accelerator, and that’s what we’re doing. So, thank you for listening to that. That marks the end of today’s presentation. We’ll open up the lines now for Q&A.

[Operator Instructions] Your first question comes from the line of James Redfern from Merrill Lynch.

A word on a very impressive outlook. Just one -- look, two questions, please. The first one, given the increasing focus on growth, we had increase in five-year production and free cash flow target. Just wondering how we should think about capital management. And should we assume a fairly flat dividend going forward given Beach’s strong focus on growth? And then I’ve got 2 more after that.

Look, I think, as you can see, what we’ve outlined here is an acceleration of capital investment. And I think we’ve presented ourselves in the last few years of a clear growth company, not as a dividend stock. So I think that’s consistent with the way we’ve messaged to market. Obviously, we routinely, and by routinely, I mean at least every 6 months, assess our capital management programs, including dividends, and that’s discussed obviously at board level. So for now, when you look at the outlook that we have for the next 12 months in terms of how much we’re reinvesting into higher growth and high-returning opportunities, we’ve decided to keep the dividend stable. We’ll obviously reassess that as we move forward depending on outcomes and cash flows going forward.

And then, in terms of the $1.5 billion of value-accretive opportunities that you’ve identified, that is all organic, so it doesn’t include any inorganic opportunities. Is that right?

That’s correct. So there is nothing at all in any of this pack in terms of acquisitions or anything else. It’s all organic opportunities, which, as you know, is predominantly surrounding our existing infrastructure which obviously leads to the very high rates of return.

And just one last quick one. Just a best guess. Your reserve increased by 11 million BOEs, which doubles the reserve of Bass gas. Does that include Trefoil? And then in ISO, should we assume FID in Trefoil in the 2021?

It does include Trefoil, so that’s in the main change and one of the key changes that you would have seen come through the reserve statement. We’ve been doing a lot of development study work around that. So we’re going to do concept select with the joint venture this year. And obviously, once we’ve been through that cycle, we’ll give more information to the market around FID intentions.

Your next question comes from the line of James Byrne from Citi.

Look, clearly, a pretty impressive five-year outlook at the headline. I guess what I wanted to ask about is how we, on the public side, can look to risk adjust that headline guidance. In particular, I was hoping you could confirm whether the guidance for production and cash flow has an assumption of exploration and appraisal success or not noting just how much you’re drilling, exploration and appraisal in Cooper and high-value targets in the Otway. And I guess, beyond just exploration and appraisal, which assets that are yet to take FID are also included in guidance such as Waitsia, La Bella and Trefoil just mentioned?

What we do is we do assume, particularly in the Cooper given the amount of wells we’re drilling, the success rate for exploration and appraisal, and it’s not dissimilar to historic success rates given how well FY19 has gone for us. But what I’d also flag is, if you look at our capital program, the vast majority of it is in the development space. And certainly, if you look at the Otway program, which is a big ticket item, as I said, out of those 10 wells that we’ll drill over the next 3 years, only 2 of those are exploration. And as we all know, that exploration historically in the Otway basin has been highly successful when you have ample to support on seismic, which is what we have for our 2 exploration plays as well. So, not [indiscernible] to lift, normal exploration risking. So I think this is a relatively low risk for oil and gas portfolio, very low risk portfolio. And what we’re doing is extrapolating reserves and resources in areas where we have facilities. So again, that’s why you’re seeing very strong returns. In relation to that five-year outlook, yes, it includes Trefoil and it includes Waitsia.

Okay. I don’t suppose sort off the top of your head, the proportion of volume growth associated with what you can immediately see as low risk development versus something like taking FID on projects and exploration success.

Well, it depends on which year you’re looking at. Obviously, if you look at FY20, that’s not reliant on any major FIDs. That’s all basically the current portfolio.

Let’s consider FY24 then, like the exit rate, where you are getting $1 billion of free cash flow?

Yes. So that’s clearly assuming that you’ve got Waitsia online and you’ve got Trefoil as well.

Okay. Yes. And then the second question I have is, you’ve clearly got excellent returns for the CapEx that you’re spending in FY20. And I applaud you for that. But I want to understand, how do you think those IRRs are going to change over the five-year outlook? For example, La Bella might concentrate a reasonable amount to CapEx, but I’d be surprised if it was achieving very high IRRs, for example. I guess, like on slide 39, I noticed that while the free cash flow steps up materially, you kind of have a -- you have a ROCE that is flat on your prior guidance, which kind of, I guess reflects the capital intensity and maybe the deterioration returns over time. Is that a fair statement do you think?

It’s a bit mix. Obviously, in the Cooper, you’ve got incredibly high rates of return, both on oil and gas, particularly given most of our Western Flank gas has extremely high liquids content. And well obviously, we own all the infrastructure there. It’s not dissimilar, frankly, in the outline, where we’ve got the ownership in existing infrastructure, and we’re drilling in the fields around there. So the rates of return high for offshore domestic gas, very high. Clearly, as you develop further with more CapEx in around opportunities like Trefoil, the rates of return are different to the old opportunities and the onshore opportunities. But what I would say is they’re still highly maturely above our cost of capital. So they’re still screening incredibly well, which is part of the reason why we’re progressing on them and part of the reason why they’re included in the reserves booking.

Just one last quick one. At the 2018 Strategy Day, you might have to jog my memory here, but I think you’d said that the sort of breakeven oil price for that $500 million of spend was $16 a barrel. And I’m wondering what sort of oil price breakeven is it going to be where you start to pull back away from that $800 million of spend.

Yes. I think if you look at our business now, it’s in a position where we have a natural hedge in the business across gas business. So all of our operating costs as a business is covered by our gas revenues. So you haven’t seen us hedge any time in the last six months and I doubt that you’ll see us hedge much going forward. So we’re highly robust. Frankly, I think even if you’re at a $40 or a $50 oil world, you still see us pushing forward with this program. A lot of it is targeting gas, as you know. So almost 2/3 of it’s targeting East Coast gas. So this is a company that’s in incredibly robust shape from a balance sheet perspective and from a cash flow perspective. So I think you’ll see us push forward with this program. And it have to be a world that we can’t currently see for us to pull back.

Your next question comes from the line of Mark Samter from MST.

I have a few questions if I -- just following what James is saying about the Perth basin. I’ve got a few questions on the Perth basin. I mean, how much of this increased FY24 production guidance as you’re now talking about essentially Waitsia stage 2 being 100 to 250 TJs a day. And obviously, that delta is 4 million, 5 million barrels a year net to you. Is a lot of the step-up just the wider range? And what’s your expectations?

You’ll see when we go out to FY24. In fact, when you look at our five-year outlook, Mark, we’ve got a range. So that obviously takes into account various outcomes, not only on Waitsia, but all of our portfolio.

Yes. I’m just comparing previous guidance to new guidance. How much of that step-up is increased by Waitsia?

No, it’s not Waitsia-driven.

So, you’ve not changed Waitsia assumptions?

No, not on the range. So this is more driven by, obviously, the exceptional outcomes on the Western Flank we’ve had in the last 12 months, and obviously, Trefoil included as well.

Okay. And then I mean so Waitsia’s still pretty much 25% of your reserve? But if you use ACCC gas price of $4ish, so is still economic?

Yes. Waitsia is highly economic, highly economic. As we’ve said, it’s highly -- it could be highly economic today. It could have been highly economic last year, but we’re going to get to sell the gas once. So what we’re doing is making sure we’re engaging with all the right customers and right parties to make sure that we can get the highest return possible for shareholders, and we haven’t been pace-driven, we’re value-driven on this one.

Okay. And then just focusing on the FY20 gas production of Western Flank. It’s a great outcome. I’m certainly not trying to hide away from that fact. I mean take the midpoint of the gas production range, you’re talking about a 0.4 million barrel BOE decline in gas production year-on-year. I mean you guided yourself Otway’s down almost 20%, which is over 1 million barrels net to Bass gas looks like it had a pretty shocking start to the year following to the bulletin board, you might be losing 0.2, 0.3 there. Again, you’re guiding, Kupe but there’s a decline this year because of the maintenance, we get a bit back from Western Flank, obviously. Am I interpreting that right that you’re assuming an absolutely [indiscernible] SACB JV, I guess?

No, we’re not. No, there’s nothing in any of the slide deck, including the five-year outlook, that is changes open Andes.

FY20. Sorry, FY20. I understand on your guidance, you’ve guided a pretty material decline, obviously, in Otway?

Yes.

Bass gas, we can say is might a very weak start for the year. Kupe, again, you’ve guided to. I mean there’s no other asset left other than SACB JV, some pretty meaningful year-on-year growth in FY20?

Well, you’ve got Black Watch coming in as well. So I think one of the issues that we’ve said in the notes is we do have statutory shutdowns this year on both Kupe and Otway, and we believe most of that will be offset by the Cooper Basin the way the Cooper basin is performing that you need to bring in Black Watch as well in terms of the growth story.

Right. Okay. All right. Okay. And then there’s another question, there’s -- despite that sale of the Otway, the Otway stake has been a pretty chunky increase in provisions for restoration. Can you talk through where that’s coming from? Morné Engelbrecht: Yes, Mark. It’s Morné here. So on the restoration provision, that’s obviously highly driven by discount rates. And you will have noted, obviously, the bonds, the rates have decreased, which have obviously pushed up the overall amount that we then provide for in terms of the rehabilitation. So that’s the main driver there.

Okay. So I’m going to sneak in one more quick question, if I can. And I realize some of this is in fairly going to incremental gross CapEx. I mean you talked about an increase in the five-year free cash flow profile, but it’s a different 5 years do you gave us. Last year, actually, the free cash flow, you back out the numbers, free cash flow for FY20 to FY24 has dropped to about $0.5 billion from what you gave before. And that’s despite, obviously, a fantastic outcome in the Western Flank oil, which is very high margin product. Is it fair to say your assumptions have got slightly worse for offshore Victoria over the next 3, 4 years and just Western Flank is obviously been fantastic, but not offset that, or?

No. I think what you’re seeing the differential there is, as we’ve mentioned in the core markets, we’re reinvesting $1.5 billion over the next 5 years of capital that we didn’t see in terms of opportunities a year ago. So that’s the main changes. We’re reinvesting more. And as we said, with 50% rates of return, why wouldn’t you?

Yes. I guess that doesn’t quite correlated what you guided, the 20 million BOEs reserves for an extra, or [indiscernible] reduction in free cash flow.

So I think the 20, we’re investing for growth beyond just the 5 years, right? So actually, you got an exit rate of $1 billion of free cash flow in FY24. And what we’re investing for is -- and more than 2/3 of it’s going into a gas business, which is clearly going to last beyond the five-year outlook window.

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

Just slide 6, that free cash build up. Just a few questions around that. Firstly, that sort of cash tax is higher than P&L tax. Is that a one-off, 1-year impact? Second question. The ‘22 uplift, is that effectively Otway CapEx coming down and Otway production going up in this ‘23, ‘24, is that WA? Just trying to understand how that builds up, please. Morné Engelbrecht: Yes. I’ll answer the first one, Adam. On the cash tax, obviously, we’ve had a significant step change in the business in FY19 and our installment0 have lagged behind that. So if you look at the balance sheet in FY18, we had $100 million tax liability there for -- at the end of FY19, we’ve got a $200 million tax liability there. So you would see that the installment payments as we go into FY20 is going to increase, which is driving that sort of increase in cash tax. I suppose beyond FY20, we would expect that to sort of normalize and be aligned with the tax expense going forward.

In relation to the question, Adam, on capital. Say, obviously, there’s actually quite a good slide on slide 12 where you can see what we’d assumed for FY20 at the time of last year’s investor briefing and what’s changed. And the change, as you can see, is really the fact we’ve had such a good year on the Western Flank in FY19 that we’re reinvesting more there. That’s the key. And then for the next couple of years, obviously, we are investing heavily in the Otways. We’ve said we’re drilling a 10-well program there over the next 3 years, and obviously, that will come off. And we’ll then basically have the free cash flow streaming in from Otway.

Okay. That’s good. And just back on Bass gas, we’re also going to try and value that. You’ve got an uplift of reserves, approximate doubling. We’re talking $100 million to $200 million gross, something in that order, the CapEx for that Trefoil in a time?

We haven’t released a number yet on Trefoil. Obviously, we are still working through concept select as a JV. So it’s too early at the moment to release a CapEx number for Trefoil.

Your next question comes from the line of Daniel Butcher from CLSA.

The first question is just on your five-year production target growth. It seems like you’re assuming similar success rate for the Cooper Basin for the whole next 5 years, yet you’re more than doubling the rate of wells you drilled business last year and even higher versus the previous years. What make -- what gives you the confidence that either from 3D seismic wells something you see that you can have that sort of run rate continue with that success rate as well for another 5 years, or 4 or 5?

I’ll let Jeff Schrull chip in here as well. So we’re actually assuming a lower success rate going forward than we have had in FY19. So we’re certainly not assuming that we replicate an outstanding year in FY19 year-on-year for the next 5, but we don’t obviously release our exact assumptions on risking going forward. But I’ll let Jeff talk to how the outlook looks for?

Yes. So, we definitely are assuming a lower success rate because, going forward, we’re going to be aggressively appraising all of our fields to find out how big they are once and for all so that we can put together final FDPs, talk about optimal well spacing, optimizing infrastructure, et cetera. So the more aggressive the appraisal, obviously the higher the risk. In about 2 years, we’re planning an exploration campaign. And we have a fairly modest assumption that’s gone into these forecasts for success there. Like Matt said about all of the numbers, the way the exploration is and appraisal is represented in all these assets, there’s no blue-sky. There’s no crazy high success rates or anything like that. We’ve been very conservative about it. And bear in mind, the beauty of the Western Flank is the portfolio of approach, so many wells to drill, some are going to work, some aren’t. But in the end, I think we’ll probably end up pretty close to what we modeled.

And just as a follow-up on that. I mean you sort of mentioned I think that you’re approach horizontal wells has got to even further than maybe you communicated last time. Do you have any updates you can give us on decline rates and overall EURs for those wells versus verticals?

Yes. It’s Geoff Barker here. Look, I think the -- what we’re saying is better performance than we anticipated. And off the back of that, we’ve actually had some reserves growth. So the decline rates, it’s really too early to tell where the decline rates are. We’ve had less than 1 year’s production for a number of these wells, so -- but we’re not seeing any adverse performance at all. Performance is really holding up.

Yes. So the first well we drilled was Bauer-26, that’s the only well that we’ve got longer-term production information from and it’s exceeded our expectations.

Okay. And maybe one more if I can on Trefoil. I know as you booked 2p reserves there, but you haven’t even gone to concept slit yet. That seems kind of aggressive, doesn’t it? I mean, normally, you wait for FID to book that oil and gas project, I would have thought. And maybe if you could just highlight when the [indiscernible] take was underway, we still a free, wouldn’t say [indiscernible] but pre down beta assessment of the processes for Trefoil. I’m just wondering where your current assumptions to that report. Is it on the gas price front or is so CapEx? If you can just talk or what’s sort of?

Well, firstly, we comply with the PRMS. So our reserves are independently audited. We make our own assessment, but they’re also independently audited. And they comply with the justified for development classification under the PRMS. So we are complying with the PRMS, there’s no requirement under PRMS rules that you actually have FID before you book a reserve. And in terms of the development concept itself, what we have is very much a swing down concept. So the previous concept involved quite a significant number of wells. I think it was 6 to 8 wells with associated infrastructure, and the costs were very high. What we’ve done is we’ve high-graded the objective reservoirs here and targeted the objective reservoirs that have got most of the gas reserves in them, which we can drain with 2 wells. So we’ve got a significantly swing down development costs as a result of that for a relatively modest impact in terms of reserves. So the overall recovery has dropped slightly, but the costs have dropped dramatically.

Great. Is it much with those 2 wells? Or is it?

No. We have a wellhead jacket, so there’s a dry [indiscernible], the only subsea infrastructure would be a subsea pipeline back to Yala.

Next question comes from the line of Saul Kavonic from Credit Suisse.

Just a few quick questions. Firstly, just I see in your long-term CapEx guidance there, you’re now indicating that you would own your share of the Waitsia processing facility for the expansion. Could you give some color as to why you opted for that option versus lease?

Yes. So, we just really keeping the market informed in terms of where we’re hitting there. I think previous operator was thinking more so around third-parties on any infrastructure. I think from a current joint venture standpoint, both Mitsui and Beach, we prefer to have more control over that infrastructure and where we can take it. So at the moment, our view is that we would own the infrastructure. So that’s why we’ve replicated that now in our numbers.

Also on -- again, the five-year targets, the 100% reserves replacement ratio, is that still being refreshed going forward. So in other words, you had over 200% for the last year, is that going to be factoring in over the next 4 years? So on average, you’re looking 100%? Are we looking at it even from now, 5 years ahead, it’s still going to be 100%?

Well, we are starting the clock again. So, we’ve just set the bar high for us.

Great. And just a couple other ones. Price discussion, on the price reset discussions, the one you’ve obviously already done regarding the contract. In the press review discussions you’ve had to date, have you found that prices have reset all the way to the same price levels you get from uncontracted gas, or is there still a bit of a gap to get all the way to the current pricing levels?

Thanks. So look, obviously, negotiations in discussions within a gas customer. And in relation to price resets with [indiscernible] highly confidential, so unfortunately, I’m not in a position to give you more on that one.

Right. Lastly, on Black Watch. The field looks -- appears to carry over into the neighboring permit with Cooper and [indiscernible]. Is there a unitization arrangement in place for its development?

No. There’s no unitization arrangements in place. And at the moment, we’re progressing ahead on the basis of what we’ve already announced for the market. So we’re moving ahead to drill.

Understood. If I may, just one more. Just -- actually, I guess, the previous question, just for clarity. That the 4 million barrel increase in the range of -- on the five-year outlook, just to be clear, that is predominantly coming from Western Flank and Trefoil and not elsewhere?

Look, it’s a combination, obviously, of the entire portfolio. But yes, a lot of it relative to what we saw last year is the improvement in Western Flank, and then obviously, also including Trefoil.

Your next question comes from the line of James Bullen from Canaccord.

Congratulations. Thanks for providing a bunch of details around the assumptions for the five-year outlook. But as you mentioned, you are coming more and more of a gas company. You’ve given us the oil price assumptions and the ForEx assumptions. Can you provide us with any color around the gas price assumptions?

Now look, we obviously can’t provide detail around gas price assumptions, particularly when we’re in negotiations with customers and also in discussions around price resets in our contracts. But I think, look, we’re all fortunate at the moment that we’ve got ACCC numbers out in the open market, so I suggest you look towards the ACCC numbers. And as we’ve said throughout, we don’t think lease gone, we don’t think topsides. So that will guide you to way you should be thinking about right.

Right. Just around La Bella. I mean how material is it? It provides you with a bit of a boost on reserves. When do you think you can actually have that in production?

Yes. So on La Bella, that was obviously an important move by us during the year, a $4 million cash to get access to La Bella through the gazettal process. The way we think of Labella is it’s really a bit of an insurance policy. We’ve got a retention lease over La Bella. We intend to move forward at it. But the timing of when we move forward, it really depends on how the other wells perform and how the exploration wells perform as well. It’s a very nice insurance policy for us to have.

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

Thank you everyone for your time, greatly appreciate it. I appreciate all your questions. And obviously, please feel free to check in with our Investor Relations team and hopefully see a number of you on our road show over the next couple of days. Take care.