Thank you. Hello, and welcome to the FY '20 full year results presentation for Beach Energy. My name is Matt Kay. I'm the Managing Director and Chief Executive Officer of Beach. Joining me on the call today is Morné Engelbrecht, our Chief Financial Officer. We're also joined by a number of Beach executives who are available to answer questions later. The format today is we'll run through the results presentation and the revised 5-year outlook before opening the lines for Q&A. Let's move straight into the presentation. Slide 2 presents our disclaimer and includes oil price and ForEx assumptions used in our 5-year outlook and FY '21 guidance as well as reserves disclosure. I'll let you have a read of that at your leisure. Before we move on to the main presentation, I wanted to point out Slide 3 highlights an important decision we reached in FY '20. During the financial year, Beach rewrote its purpose statement to more accurately reflect what we strive to do each day. This resulted in the rollout of our updated business purpose: the sustainability -- sustainably deliver energy for communities. This updated purpose highlights we are making a positive contribution to the communities in which we operate that have great importance to everyone at Beach, take pride in being an active and leading member in our communities while delivering the critical energy and society needs. Moving to Slide 4. To say that FY '20 was a tale of 2 halves would be an understatement. The first half of FY '20, Beach was tracking extremely well, its most ambitious and exciting year of organic growth in the company's history. At the half year mark, we have drilled 105 wells with an 83% success rate. That included exploration success at Beharra Springs Deep-1 in the Perth Basin, a positive appraisal drilling at Bauer in the Cooper Basin, which identified a field extension. We spudded Black Watch-1, which has subsequently been connected to the Otway Gas Plant, delivering its first new gas supply in more than 4 years. And importantly, we are on track to deliver full year production and EBITDA within the guidance range. And of course, during February and March, the full impact of COVID-19 began to hit the global economy, and of course, Beach is not immune. From a demand perspective, there was a significant reduction in global oil and LNG demand as behavior has changed rapidly to combat the spread of the virus. You will recall the Brent oil price fell to USD 18 a barrel during March. Furthermore, there were significant supply chain disruptions from global sources, creating issues in obtaining timely components for major equipment. Additionally, travel restrictions resulting from COVID-19 have added challenges from a workforce perspective as flying in and out of interstate and overseas locations became problematic. Fortunately for Beach, the combination of a strong underlying business and swift response to COVID-19 put the company in an extremely robust position to combat the challenges presented for the second half of FY '20. As at 30 June 2020, Beach's balance sheet sits in a position of strength, $50 million net cash and $500 million of liquidity. The swift market downturn has also highlighted the strength of our assets. Despite the challenging environment, Beach still delivered high returns with return on capital employed of 19% in FY '20. Further evidence of this is the fact there were no material impairments across our portfolio, and our reserves remain robust at even lower commodity prices. It's important to again point out to the revenue certainty provided by our gas business, which exceeds total operating expenditure and our stay-in-business capital expenditure. Despite the relative strength of our business, Beach took a prudent approach to costs in response to the swift market decline and COVID challenges. In the second half of FY '20, Beach made targeted staff and contractor reductions, renegotiated most supply contracts and ensured FY '20 field operating expenditure per barrel to 3% lower than FY '19. As you're aware, we also reduced planned FY '21 capital expenditure by more than 30%. Go to Slide 5. I won't dwell too much on this slide. Our response to the pandemic was swift and decisive. I'm extremely proud of the manner in which everyone at Beach responded. We enacted our crisis management team in February and have had and will continue to have a dedicated team focused on our business continuity plans. As a result, we're extremely confident in our ability to work with governments, regulators and our communities to ensure we can deliver the work program in FY '21. Slide 6 helps summarize where Beach currently stands in light of what has transpired over the last 12 months. Despite the global shock waves, Beach drilled 178 wells at an 81% overall success rate. Beach recorded production of 26.7 million barrels of oil equivalent in FY '20. That's about 2% higher than pro forma FY '19 production and was within 1% of guidance. Our EBITDA of $1.108 billion was within 6% of guidance despite the material decline in oil prices in the second half. As a result, our underlying NPAT was $461 million FY '20. Our final dividend of $0.01 per share is unchanged on the prior period as we continue to prioritize total shareholder returns through value-accretive investments. We now enter FY '21 in an extremely strong position to pursue value-accretive growth, albeit at a more measured pace in response to the current economic climate. We believe the greater than 30% reduction in capital expenditure in FY '21 is also prudent management of investment activity given the risks and uncertainty created by COVID-19. Despite this reduction in investment expenditure, there is still plenty of exciting activity to look forward to in FY '21. The offshore Otway campaign will now commence drilling between December 2020 and March 2021 following the signing of a new rig contract with Diamond Offshore for the Ocean Onyx. Now West, we and our operator Mitsui have made great progress with Waitsia Stage 2 final investment decision, which is expected in coming months based on exporting up to 1.5 million tonnes per annum of LNG by the North West Shelf infrastructure. More on that later. Additionally, the significant Ironbark 1 exploration well in the Carnarvon Basin is expected to spud with operator BP in Q2 of FY '21. As you can see, these investments make absolute sense with Beach's ability to invest through the cycle. I'll provide more detail later during the presentation. And we forecast to generate $2.1 billion of free cash flow over the next 5 years even with a reduced commodity price outlook. The stress test forecast peak net gearing to less than 10% even at USD 30 a barrel oil price over the next 5 years. Because of these world-class financial metrics, we have the full confidence in continuing our growth trajectory. Slide 7 provides an important insight into the Beach journey since FY '19. Given all that has occurred over the past 6 months, it's easy to forget where this journey started along the Lattice acquisition and how well Beach has performed over the past 2 years. As you can see via the table, Beach has met its stated cumulative FY '19 and FY '20 objectives across production and CapEx. In addition to this, we've exceeded expectations when it comes to free cash flow generation, reserves replacement and return on capital employed. Moving to Slide 8, a slide that we're extremely proud of as it again displayed our ability to achieve over 200% organic 2P reserves replacement for the third year running. In fact, we actually beat our FY '19 results in FY '20, achieving a 2P reserves replacement of 214%. This in turn led to an increase in 2P reserves life from 12.4 years to 13.2 years. As I mentioned earlier, we've taken no material impairments across producing assets. As mentioned in the slide, given a further 20% reduction in oil and gas prices, we only reduced our 2P reserves by less than 3%. That's a robust set of assets. Slide 9 outlines our safety performance. Despite this being slightly further down the pack than previous years, I can assure you safety remains the highest priority of Beach. From a safety perspective, our total recordable injury frequency rate or TRIFR remained below 4 for the third year in a row. Given COVID distractions, that's a solid result. Our environmental performance and process safety performance were both strong, maintaining the improvement levels that we've achieved over the past 4 years. Turning to Slide 10 and before I hand over to Morné, I wanted to take a moment to mention Beach's commitment to sustainability. For the past 2 years, Beach has had an emphasis on improving our focus, disclosure and capability in the sustainability space, in particular around emissions reductions. Beach is committed to playing a key role in a lower carbon future. And over the past year, we've conducted emissions benchmarking at all of our sites. This benchmarking fed into a body of work, which ultimately led to the Board committing to an emissions reduction target of 25% CO2 equivalent by FY '25 relative to FY '18 benchmark levels. Those benchmark levels were set based on the timing of the acquisition of the Lattice assets. We look forward to investigating and implementing projects in the coming years to help Beach achieve these ambitions. You will note we've also disclosed our carbon price assumptions we apply to regularly test our portfolio. I'd now like to hand over to Morné to run you through our financial results in more detail. Morné?

Thank you, Matt. Good morning, everybody, and thank you for joining us today. As Matt's already noted, the second half of FY '20 presented significant headwinds for the business. Notwithstanding this, I'm very pleased with how we've weathered the storm and how well we are currently placed. As you can see on Slide 12, we have performed extremely well on the financial front in FY '20, particularly proud of how we continue to retain a rock-solid balance sheet. We have $50 million in net cash and have access to more than $500 million in liquidity. As previously stated, we have not had any impairments across our producing assets. Our reserves remain economic to lower long-term commodity prices. On that point, Beach has a high level of revenue certainty based on our stable natural gas business. Over 99% of our gas was sold under contract, which was fixed price and present a natural hedge and downside protection. In FY '20, Beach generated more than $600 million in sales gas and ethane revenues. Importantly, these revenues cover all of our operating costs and stay-in-business costs. FY '20, we achieved our goal to reduce our direct controllable operating costs by $30 million per annum. Despite this, we continue to remain disciplined on costs. As such, we are targeting further reductions in field operating costs per barrel, which is incorporated into our dollars per BOE guidance for FY '21. We are reviewing all of our contracts to identify areas of further cost savings, and we have optimized our workforce to match the modified work programs going forward. On Slide 13, you can see our financial highlights for FY '20. Beach reported an underlying EBITDA of $1.108 billion for FY '20. This outcome was a result of 21% decrease in realized oil prices, partly offset by a 7% increase in realized gas and ethane prices and the inclusion of $21 million with the Tawhaki 1 exploration dry-hole well cost. Otway sale also impacted production and sales volumes, and it is important to note that production was 2% higher on a pro forma basis. On Slide 14, you can see our cash movements. Operating cash flow of $874 million was down 16% on the prior year. This was driven by a 14% reduction in sales revenue and $134 million increase in cash tax payments. As Matt stated earlier, Beach has announced a final dividend of $0.01 per share fully franked. Turning to Slide 15. You can see our underlying NPAT movements over FY '20, which recorded an underlying NPAT of $461 million in FY '20. This represented an 18% decline on the previous year and was mainly caused by the sale of the 40% interest in Victorian Otway assets, a 24% reduction on realized U.S. dollar liquids prices, which was partially offset by a lower Australian dollar and higher Australian dollar gas prices. Slide 16 is an important slide as I think it best illustrates our balance sheet strength. As you can see, saying Beach is in a robust position at low oil prices is an understatement. Current projections have Beach remaining in a net cash position through a peak investment year at USD 40 per barrel. Even in a scenario where oil remained flat at USD 30 per barrel to the 5-year outlook, net gearing is forecast not to surpass 10%. Can I repeat that? Less than 10% net gearing while fully funding all of our identified growth projects even at a low oil price scenario of USD 30 per barrel. It's the balance sheet strength that gives Beach the flexibility to pursue our growth opportunity set. We have a substantial portfolio of high value-accretive organic growth opportunities, which we'll pursue in a prudent and responsible manner. Furthermore, Beach can remain selective and disciplined in relation to M&A opportunities. Last point I want to make on this slide is that our balance sheet means we will focus our free cash flow generation priorities towards growth and reinvestment. However, we will consider capital returns for surplus capital if we believe it's appropriate and makes sense. Our current balance sheet strength means we can weather periods of heightened oil price volatility and economic uncertainty. Our net position -- cash position, combined with our robust gas business, means Beach has a natural hedge against any volatility. This remains a growth company, and our priority for capital allocation remains growing total shareholder returns via value-accretive growth investments. I'd now like to hand back to Matt.

Thank you, Morné. If we move to Slide '18, you can see Beach is well placed at 3 gas markets we service: the Australian East Coast and West Coast gas markets and the New Zealand domestic market. While a large amount of our focus remains on the East Coast gas market in Australia, we believe all 3 markets represent attractive value to our portfolio. Note that we maintain a relatively even split in gas and liquids production across the portfolio, of course, with the benefit of a diversified spread of 6 production hubs. On Slide 19, you can see AEMO information released earlier this year. It shows the forecast Eastern Australian gas supply versus demand. Despite the short-term impacts of COVID-19, the fundamental story remains the same: Southeastern Australia is not producing enough gas to meet its own demand. As such, states of South Australia, New South Wales and Victoria are reliant on gas diverted from LNG projects in Queensland to meet demand. Going forward, the picture doesn't get much better. This reliance on LNG diversions is set to increase over time unless there is a significant increase in supply. We at Beach recognize the challenge, and our investment thesis to support East Coast gas supply remains, albeit at a more conservative pace. Slide 20. While we've seen declines in regional spot LNG prices and therefore in spot pipeline gas prices, especially in Queensland, Slide 20 helps reinforce the point of Beach's minimal exposure at lower spot prices. Indeed, in FY '21 to FY '22, only about 2% of our East Coast gas sales are exposed to spot pricing. They remain under long-term contracts. As I move to Slide 21, I wish to highlight that in the interest of time, we'll only dive into the Victorian Otway, Cooper Basin and Perth Basin assets. There's a bunch of information in here we provide for your benefit when you have the time. Detailed information about the other assets can be found in the appendices, and we're more than willing to answer any questions you may have. Moving to Slide 22, we turn our focus especially to the West. FY '20 was a very successful year in the Perth Basin, and we are confident we can carry this momentum over into FY '21. On the exploration front, Beach had success at the Beharra Springs Deep exploration well with flow rates comparable to that at Waitsia. We also completed the acquisition of the Trieste 3D seismic survey, which confirmed multi-TCF exploration potential in EP 320. Beach also moved to Waitsia Stage 1. With final investment decision and execution, I can advise that we introduced first gas into this facility in the past few days. Move to Slide 23, which I guess you could call our big reveal of the day: Waitsia Stage 2. We're on the cusp of taking final investment decision development of about half of Waitsia gas to LNG via the North West Shelf facilities. It's required a lot of work over the past 2 years with our operator Mitsui. And we are providing as much detail as we reasonably can today on final agreements, and approvals are well in progress. Now what's been happening on North West Shelf, we've now signed a detailed nonbinding gas processing term sheet for the North West Shelf venture. That means that key terms are done. We are now progressing gas processing and gas time agreements. We expect to begin exporting LNG via the North West Shelf by late 2023. We'll be marketing our own offtake, and we've had an experienced and senior LNG marketing team in place at Beach for more than a year. Two, gas pipeline access. If you haven't noticed, this year with Stage 1 expansion of Waitsia, joint venture has already created a 280 terajoule a day connection to the Dampier to Bunbury Natural Gas Pipeline. We're well advanced in technical and commercial discussions with AGIG on transportation arrangements through the North West Shelf. Three, WA government and regulators. I'm very pleased to say that the Waitsia joint venture and indeed our Beharra Springs joint venture will be providing about 40 terajoules a day of domestic gas into WA this year. We also intend to expand that domestic gas supply. And that is helped by the Western Australian government supporting Waitsia exporting up to 50% of its reserves at LNG through the North West Shelf. The Waitsia Stage 2 development will be a significant contributor to the Western Australian economy. I can also advise that we're well advanced in submissions and the approval processes with regulators, including the EPA. Four, construction agreement. We're now at the final bid stage of what has been a multiple-stage process: the engineering, procurement and commissioning of our 250 terajoule a day gas processing facility at Waitsia. That provides enough feed gas to allow us to produce in the order of 1.5 million tonnes per annum of LNG at North West Shelf. As you can see, Beach and our operator Mitsui have been very busy at Waitsia, and all the jigsaw pieces are now coming together. We're in excellent shape to reach final investment decision in the next couple of months. Now you want to know a lot more detail about this. But given the confidentiality obligations, these various arrangements and many stakeholders, I can't share much more with you today. Go to Slide 24. Move back to Eastern Australia. You can see our offshore Otway drilling program is back on track with the execution of a new rig contract with Diamond Offshore on the Ocean Onyx. The agreement provides for the drilling of up to 9 wells with drilling operations expected to commence in December 2020 and March 2021. The agreement, which is at globally competitive rig rates for deepwater semi-sub rigs, includes provisions for COVID-19-related costs and delays. This agreement means Beach can move forward with our plans to develop more natural gas supplies in the East Coast gas market. You should be aware, Beach successfully drilled the onshore-to-offshore Black Watch 1 extended reach well, which is now producing into the Otway Gas Plant. We expect to spud the onshore-to-offshore Enterprise 1 exploration well towards the end of September. Slide 25 provides some additional context around the delay of the Otway drilling program and COVID-related challenges faced by the broader Otway development project. The supply chain for this project extends across multiple countries. Travel restrictions had an adverse impact on logistics and the supply chain, most notably around Christmas trees and subsea control modules. This challenge was mitigated by shifting the final stage of construction from Batam, Indonesia to Perth. The recent months, our contracts and procurement team has worked diligently with suppliers to mitigate additional issues and ensure supplies and services are ready for commencement of the offshore program. Importantly, delays have only reduced the present value of the Otway program at well below 5%. Go to Slide 26. We're moving back to South Australia and turning our attention to Western Flank. And wow, what a story it continues to be with more great results in FY '20. Operated production surpassed 23,000 barrels per day in the second half of FY '20, and drilling success stirred a 159% 2P reserves replacement ratio. Western Flank continues to be a high-returning asset with most development wells having IRRs of greater than 100%. However, given the commodity price environment, FY '21 capital expenditure will be reduced by 50% to $110 million, and we're going into a partial harvest mode. Our aim is to maintain output above 20,000 barrels per day as we seek to high-grade our prospect and lead portfolio for drilling program in FY '22. On this point, it should be noted that at least 4 oil fields have yet to be fully appraised. And we have 7 drilled and uncompleted wells waiting in the Western Flank oil portfolio. Slide 27. I won't spend too much time on this slide. I think it speaks for itself. Expected ultimate recovery of oil in our Western Flank acreage has more than doubled in the past 4 years. And as most of you know, we've doubled production in the last 2 years. 2P expected ultimate recovery is now approaching 100 million barrels net to Beach, a truly outstanding result. Go to Slide 28, give you a quick overview of the Cooper Basin joint venture operated by Santos. It's very pleasing to see FY '20 production reach 8.7 million barrels of oil equivalent, 6% higher than the prior year. JV also recorded a 111% 2P reserves replacement. Beach remains highly supportive of the joint venture's efforts to high-grade drilling opportunities in FY '21. Beach expects to participate in 40 to 50 wells with a focus also on infrastructure opportunities to support improved reliability and capacity. Excitingly, Beach plans to work with Santos to explore the potential of carbon capture and storage in the basin, this work being evaluated in the first half of FY '21. As we move through Slide 29, we're now about to change gears to turn our attention to the updated 5-year outlook. On Slide 30, you can see FY '21 is scheduled to be Beach's biggest investment year with the full year of offshore Victorian Otway program, the full year of Waitsia Stage 2 construction and the continued aggressive Cooper Basin drilling program. However, given macro issues, more than 30% of planned FY '21 expenditure will be deferred in capital expenditure at a range of between $650 million to $750 million. This will mean the capital expenditure forecast for FY '22 and beyond will be higher and spending is deferred into those years. Additionally, FY '20 to '24 cumulative CapEx increased by around $200 million to $4.2 billion as new growth opportunities have been identified. These include follow-up drilling and development in the Perth Basin following exploration success at Beharra Springs Deep, increased Western Flank investment following the FY '20 successes and Kupe joint venture considering a new well to extend plateau beyond FY '24. Slide 31. It should be no surprise that a deferral of FY '21 activities delay a potential production contribution from some of the assets. Despite this, production remains on track to deliver between 37 million to 43 million barrels of oil equivalent in FY '25. In essence, the destination hasn't changed, only the timing and the profile to reach it. In the current environment, we believe this is the prudent approach to ensure Beach maintains financial strength through a period of volatility. Importantly, a significant increase in production over the next 5 years comes from known sources within our existing portfolio. Slide 32. You can see that we've taken a conservative approach to forecasting production of 37 million barrels of oil equivalent by FY '25. In the interest of being prudent, our key assumptions in the low case are things that are virtually certain as opposed to further upside. Even in the 43 million barrel of oil equivalent scenario, you can see outcomes that are likely given our previous track record of delivery especially in the Western Flank and the Perth Basin. The high case does not rely on material exploration success. Slide 33. Here, you can see our revised free cash flow outlook to reflect the revised work program, and of course, most importantly, the updated commodity price assumptions. Our updated assumptions forecast Brent oil price at USD 41.25 per barrel in FY '21, USD 53.50 a barrel in FY '22 and USD 60 a barrel from FY '23 with an underlying exchange rate of $0.70. Under these assumptions and the updated production and CapEx assumptions, Beach is forecast to generate $2.1 billion in cumulative free cash flow FY '21 through to FY '25. That demonstrates some exciting times ahead for us at Beach. Flipping through to Slide 35, we cover our FY '21 guidance. FY '21 production is expected to be between 26 million and 28.5 million barrels of oil equivalent, reflecting an optimized approach to capital expenditure as we seek to lower capital while maintaining production. On that front, CapEx is forecast between $650 million and $750 million while underlying EBITDA is forecast between $900 million and $1 billion. Beach will continue to be vigilant around reducing field operating costs, guidance ranging from $8.25 to $8.75 per barrel. Slide 36 outlines some more granularity on our FY '21 production. Really pleasing thing to see here is the significant increase in oil production we expect to achieve. Oil output from our Cooper Basin assets increases from 8.8 million barrels in FY '20 to between 9.2 million and 10.2 million barrels in FY '21. Forecast increase is driven through maintaining operated Western Flank output of 20,000 barrels per day through FY '21. Gas production is expected to be in the range of 13.7 million to 14.7 million barrels of oil equivalent. Gas production is impacted by natural field decline at both Kupe and the Victorian Otway Basin. However, this was expected to decline ahead of the compression project completion at Kupe, the start-up of the offshore drilling program in Victoria. Victorian Otway is also impacted by a 23-day planned shutdown in November 2020. At the same time, production is expected to increase in the Perth Basin, the start-up of Waitsia Stage 1 and also the connection of Beharra Springs Deep-1 well around mid-FY '21. Meanwhile, Cooper Basin gas production is expected to stay steady. Slide 37 provides more granularity on FY '21 CapEx. Here, we show you a split in expenditure by type, by asset, by the end target. Top-left chart highlights our focus on development CapEx in FY '21 as we look to temporarily reduce our exploration and appraisal spend. Consistent with our thematic outlined earlier, 65% of our investment in FY '21 is targeting East Coast gas suppliers. Looking at this granular spend, it's critical I'll point out, approximately 40% of FY '21 capital expenditure to generate production volumes in FY '21. The remaining 60% is targeting production growth in future years. What we've said previously still rings true: this is about creating sustainable growth business. Slide 38 highlights how we've continuously delivered on reducing our cost base. In FY '21, we maintain this focus to target a further 3% to 7% reduction in field operating cost per barrel compared to FY '20. As a reminder, those are Australian dollar figures. I think it's fair to say our track record of delivery and continued desire for improvement in this space has helped position Beach as a low-cost operator. Now let's move to Slide 40. As a reminder, today's key takeaways. First, we had a very solid FY '20 result despite challenging conditions. I don't think anyone on the call would have predicted the manner and the ferocity in which COVID-19 hit the global economy, not to mention our way of life including at work. Beach acted swiftly, and we were able to protect our people, our assets and ensure the continuity of our operations. As a result, underlying business continued to perform extremely well through FY '20 whilst able to navigate many challenges that are presented to us. Second, we now enter FY '21 with an incredibly strong foundation. The balance sheet is in excellent shape. We have a high-margin business, highlighted by no material impairments. We enjoy a resilient and growing 2P reserves base. On top of this, we have got an extremely robust gas business that provides a strong level of revenue certainty. In fear of being a broken record, I'll say it again: our gas revenues exceed our total operating expenditure and our stay-in-business capital expenditure. Third, Beach growth plans are unchanged but at a more conservative pace. We believe a 30% reduction in capital expenditure is prudent in the current environment to reflect the risk COVID creates and a greater economic uncertainty. The growth program is still well and truly underway. There's some clear evidence. We secured a new rig contract signed with Diamond Offshore to commence the Otway offshore drilling program. Waitsia Stage 2 FID is expected in coming months, with the ability to unlock an export opportunity. The Ironbark 1 exploration well is expected to spud in Q2 FY '20. We are confident not only in our growth portfolio but also on the fact we can invest through the cycle. We are forecast to generate $2.1 billion in cumulative free cash flow over the next 5 years even taking into account a reduced commodity price outlook. We're stress-testing at a conservative USD 30 a barrel oil price over the next 5 years. And net gearing is forecast to peak at less than 10%, and committing to all of our currently identified growth opportunities. If you put those things together, it shows how well placed Beach is to succeed in the current environment. Beach came out of the mid-2015 oil price downturn as a bigger, better and stronger company. Now I have no doubt we're on the path to do the same again this time around. This marks the end of today's presentation. Would love to turn this over now to Q&A.

[Operator Instructions] Your first question comes from James Byrne with Citi.

First question is just on the cumulative free cash flow guidance. Just trying to reconcile why the FY '21 to '25 period results in the same $2.7 billion in free cash flow as the old FY '20 to '24 outlook at constant commodity prices. Now I note that when I read up your charts, the production is a little bit higher for the new guidance. And I think that it's hard to see why that higher production would be completely offset by the $200 million higher CapEx guidance because at the end of the day, that CapEx is going into very high-margin opportunities like Western Flank oil. So the inference I have is that the margin expectation for the business is lower than it had been previously. And I wanted to understand whether that line of thinking was fair or whether I'd missed the mark. Just trying to reconcile there the old and new guidance, please.

Thanks for the question. Look, it's, frankly, pure coincidence that the $2.7 billion is repeated in the 5-year outlook from this year to the previous one. There's no material change in expected margins in that number but is really just driven by cost in, cost out. And there's probably some product issues in there as well. So that's the totality of the outcome. So it's $2.7 billion before we amend the commodity prices, and after we amend the commodity prices for the downturn, it's $2.1 billion.

Would you be willing to disclose whether you changed your East Coast gas price assumptions in that outlook?

We haven't made any material changes in the outlook. As we said in our previous outlook, we carried a very conservative East Coast gas price into the previous 5-year one. Obviously, the key issue that will change is the flow-through of oil price.

Got it. Okay. Now thanks for the disclosure on the balance sheet and oil prices. That's great. So let's say we're in a world of $40 to $50 oil prices. You still have plenty of balance sheet headroom, certainly upside, I think, for most of us when we think about long-term oil price. I appreciate you want to run a conservative balance sheet, but I wanted to understand, with that headroom, you said at a preference, you're investing in more organic growth over capital returns. What kind of opportunities do you think it accelerated if you wanted to utilize that balance sheet headroom? And how does it stack up relative to the M&A opportunities that you're seeing in the market at the moment?

It's a good question, James. I mean look, the right thing about being net cash and having the margins that we have and the headroom, as you put it, that we have is it gives us optionality. It gives us optionality, as you just said, to weigh up the investment across the 6 -- the operating hubs that we currently work through. That gives us the opportunity to look at M&A. I think the issue around M&A is, as we said, in the last 5 years here, we are always looking at M&A opportunities. We looked at every single M&A opportunity, frankly, in Australia and New Zealand in the last 5 years, and we've hit the trigger on one. So we'll look at many, but we're incredibly selective because we've got a great base business that it has to stack up against. So we have the optionality going forward. And clearly, we're screening our own business and screening others.

But if the M&A opportunities out in the market didn't stack up, like I mean I'm trying to understand what are we comparing against organically that you could use that balance sheet headroom for because -- I mean do you put up some rigs into Western Flank? Do you bring forward decisions on things like Trefoil?

Yes. No, you've named a couple of them. So if you look across the whole asset portfolio, we're slowing down a little bit in the Western Flank, but as I said earlier, certainly not fully appraised across many fields there. So we do see a lot of reinvestment opportunity. We're getting our heads clear on Birkhead opportunities because we think there's more upside there. And obviously, we also have potential in the Perth Basin to continue to grow and as well as -- and as we mentioned, we've got potential for more wells in Kupe. And we still got a fair bit of drilling going on in Victoria. So across all of our assets, we're in a really fortunate position, and we have optionality. That's what we want.

Yes. Okay. Last question from me, just around Waitsia. I just want to understand some of the risks associated in the commercial arrangements in North West Shelf. Now let's suppose that a big field like a Browse or a Scarborough or even, fingers crossed, an Ironbark was to come into North West Shelf. I would have thought that those big fields would have had priority over the Arledge in the processing capacity over a smaller field like a Waitsia. Now some of the modeling we've done in the past said if you saw North West Shelf decline at a reasonable rate or outperform expectations on decline, that there might not be room for everybody. So I want to understand, does the commercial arrangement for Waitsia have a clause in there for interruptibility, which is to say, if a big field comes on, well, Waitsia, you've got to shut off for, say, 2 or 3 years? And if there is interruptibility, how does that affect your LNG strategy you're marketing?

All very valid questions, James. But I think as you'd mentioned, I'm under confidentiality obligations, and I'm certainly not going to comment on other people's assets as well. But what I can tell you is there'll be an access profile which is logical for Waitsia given where other projects in the queue, and we're very comfortable with that. So we're very comfortable with the profile of the Arledge that we have and the commerciality of it. It's really not much more I can tell you, right, today. That's -- I think if you think about when those trains leave the station, coming to North West Shelf, Waitsia's time line is right.

Yes. Got it. I thought I'd try anyway. Perhaps you can help us out with CapEx then for 250 terajoules a day.

Yes. Look, that's a great advantage that we have on Waitsia because if you think about it, this is not a greenfield LNG development. We don't have tens of billions of dollars CapEx that's required for a greenfield LNG business. We've got a very small minute relative to that number, a number that we have to put into an onshore gas plant at Waitsia. And clearly, as you saw in the notes, we're finalizing negotiations and multi-stage negotiation around the dollars for that contract. So clearly, I'm not in a position to state the number, but as you'd expect, it's relatively modest. Yes.

Your next question comes from James Redfern with Bank of America.

I just had 2 questions, please. I think the first one is just in relation to Waitsia, just wondering, will Beach be taking spot LNG price risk in relation to that gas, that 1.5 million tonnes per annum? Or will you be -- are you planning to contract any of those LNG volumes? And I've got one other question.

Well, certainly, a good question, James. So our intention is not to take spot price risk. Our intent is to contract. As I mentioned in my comments, we've had a highly qualified LNG marketing team in place for more than a year. Clearly, you're best off marketing when you've got more certainty around the profile and the project itself. We've done soft testing at the market today. We're very comfortable with the soft testing and, now that we've come out from the shade, can be a bit more aggressive in some of our marketing over the next 12 months. Obviously, the other advantage we have in terms of not being a greenfield project, we don't have to go and secure very early contracts into the market pre-FID, for example, because we don't have that type of exposure that you do on a greenfield plant.

Okay. So hypothetically, of the 1.5 million tonnes, you might want to contract maybe 1 million tonnes per annum. Would that be fair? And then maybe sort of indication on the slopes for gas to be supplied in 2024?

And look, my expectation is that the vast majority of our portion of that 1.5 million tonnes, which is 50%, we would contract on term contracts. And that will depend on what the slopes are on the day, but our initial soundings in the market are positive in terms of that time line for us and that type of volume. And obviously, we'll play the right type of approach to get the best price and the best terms we possibly can.

Okay. And then I wanted to ask about East Coast gas prices and just in terms of your gas price assumptions that you're using in that. I mean James have alluded to it, but your gas price assumptions in the free cash flow outlook over the 5-year period. I mean is that broadly in line with what you achieved in FY '20 in terms of your assumptions?

What we've always said to the market is if you look at numbers at the ACCC out in the market in terms of the range, we always forecast at the very bottom of those type of ranges. So our forecasts have been conservative, frankly, in terms of East Coast gas pricing.

Your next question comes from Mark Samter with MST.

I've also got 2 main questions if I can. Just to follow up on James' first question, so let's be clear, we're going to do this on a pre-commodity price change basis. So we're $2.7 billion versus $2.7 billion. Now fortunately, this year, you haven't given us as much information having provided the year-by-year free cash flow. But if you go back to last year's guidance, you basically guided to effectively no free cash flow in FY '20. That meant you were guiding to $2.7 billion of free cash flow FY '21 to FY '24. Now we're looking at the years FY '21 to FY '25. I mean you've given us CapEx for FY '25, which is very low. I mean you're obviously producing more. I would assume that means the FY '25 free cash flow is at least the $1 billion that you were forecasting last year for FY '24. Now if that's the case, that means you're only doing $1.7 billion of free cash flow FY '21 to FY '24 now versus $2.7 billion previously guided. Can you confirm those numbers are broadly correct? And if so, where did that $1 billion of free cash flow pre-commodity price changes go?

I think obviously, you're right, Mark, we haven't disclosed the year-by-year movements in free cash flow. There's -- look, there's ins and outs around these numbers, right. So there's difference in product mix, there's difference in timing of projects as we pointed to relative to the previous guidance, obviously, particularly in the offshore Otway and also on Waitsia. So there's a number of ins and outs around that. I think the main message here is to let the market know that without the change in commodity prices, we are still -- we were still on track for a very large amount of free cash flow over the next 5 years even after announced commodity price change...

But it's a different 5 years as well. It's a different 5 years. That's where -- you can't compare the 2 because it's not the same 5 years. I mean $1 billion missing is not commodity assumptions here or there. That's a huge number. So I guess the only conclusion is it's not $1 billion in the first 4 years. In FY '25, free cash flow is going to be materially lower than you previously guided for FY '24. Can you steer us towards which one of those 2 assumptions might be right?

I think obviously, that if you talk about them being materially different, there's an overlap of 4 years obviously between the 2 numbers and what we're steering the market towards. There's a lot of information here, by the way, that you can go through. And obviously, we can have conversations off-line as well if you want to ring in to Nik. There's a lot of capital assumptions in there that you will need to digest. And then if you look at the free cash flow with a reduced commodity price, we're very comfortable in the numbers.

Yes. I guess just -- yes, it'd be really helpful to have it represented the way it was last year, and then these things are a bit clearer that we can see year-by-year. So next question, I guess, on to Waitsia. So just to be clear, you're going to FID. You're planning to FID obviously before any contracts are signed. I mean that's highly unusual unless you're an NOC or a couple of hundred billion-dollar super major. Do you not think that puts you in a slightly weaker marketing position if you've already committed to the project? You've just said publicly 10 minutes ago that you plan to sell all the volume. Isn't that a tricky way around?

No, we don't see this as tricky at all, Mark. The difference is the reference that you're making to other projects is you're talking about greenfield projects, right? So you're talking about companies preparing to spend $10 billion to $20 billion of capital. Now even if you're a super major, as we've seen super majors do, you need to take a P90 assumption on your volumes. You need to get the reserves done. You need to basically presell before you can commit to that sort of number. We don't have that sort of capital exposure. And we're getting told through someone else's plant, so this is a very different situation. And from our perspective, we're very comfortable on the early market soundings we've taken, being able to put those volumes away. And we think the right time for us is to do that over the next 12 to 18 months. We've got time up our sleeves because it's not a greenfield project. That's the differential.

But I mean effectively, obviously, you presume it's going to be a 100% take-or-pay on the capacity, which, yes, it's not upfront capital, but it amounts to the same quantum of liability as, okay, not funding full greenfield downstream. But you're paying for the downstream. It's just OpEx, not CapEx. Isn't that the case?

Yes. So we're paying for the drink. So we don't have the same risk exposure.

But I guess with super major prices where they are, then currently then you can't contract and do something into a market that's probably the same level as you. Okay. And just to be clear, the WA announcement this morning, his exact words that he's agreed to let you export, I think, for a few years or something like that, but the words are years. Can you just give us a bit more clarity about how long you are able to send the gas through the export market according to this agreement?

I think the best thing to see at the moment -- and as I said, given that we're in discussions with multiple parties linked into multiple confidentiality agreements with limitation on what I can say, so what we've steered you towards is start-up at the end of 2023 towards the end of that calendar year. And we've told you around 50% of the 2P reserves volume being exported. So I think that gives you a fairly decent guide to be able to back-calculate.

Okay. So it's 50% just at Waitsia, not including the Beharra Springs obviously?

Right, Waitsia.

Your next question comes from Saul Kavonic with Crédit Suisse.

A couple of questions if I may. First one, just on Otway, the rig recontracting, the mentioning that, that has less than a 5% present value reduction as a result of this. Are you able to indicate, are the terms of the rig recontracting fundamentally more favorable, yes, than they were prior to determination? And on a nominal basis, are we seeing a reduction in Otway value here? As in that 5% value reduction, is that due to discounting as it's been pushed out? Or are we looking at a higher cost for the same program?

Yes. I don't want to comment too much on the details of the contract with Diamond for obvious reasons. But the differential in terms of value is due to deferral.

Great. Can you also just -- on the reserves upgrade that we've seen at Perth Basin and Western Flank, can you just confirm that those 2 material upgrades have been independently certified?

Yes, they have. So the process we go through is a very detailed one. Obviously, we've got our own internal expert. We then run that through a management review. It then goes through the review by our independent auditor and risk. Then they also go through our Risk and Corporate Governance Committee. Obviously gets seen and viewed by our auditor in terms of Ernst & Young and then go to our Board. So it's a very detailed process, and the answer is yes. I don't know, Geoff Barker, if you wanted to touch on that at all.

That's accurate, Matt. Both of those assets have been independently audited.

Great. Just to follow up also on -- last year this time, you said you were targeting a 5-year 100% reserves replacement ratio. There's no mention of that this update. Is there still a target regarding whether it's a 4-year or a 5-year reserves replacement ratio?

Yes. I think the way to think about reserves, as you'd expect, Saul, is sort of on a rolling basis. And obviously, we're well ahead of the curve in the last 2 years. So we always said, think about that as a rolling average-type number. At the moment, we're well ahead for the last couple of years. Depends on how drilling results come out this year, but obviously, when you back out CapEx, more challenging to get reserves replacements on the stellar sort of numbers we've had in the last 2 years.

Your next question comes from Gordon Ramsay with RBC Capital Markets.

Okay. Matt, just on the processing fee from the North West Shelf, can you give us any guidance, just a range, perhaps on what that might be?

Not today, I can't, unfortunately. But I'm sure at some point in time, when we get through final agreements, we and the North West Shelf will need to agree on what type of guidance we're prepared to give to the market.

Okay. In terms of gas marketing, are you -- do you have the ability to market gas with your partner?

If we chose to, we could. Obviously, we've got a great relationship with Mitsui, as you can see, by the amount of progress we've made, a great relationship as well with the North West Shelf given the progress we've made. From our perspective at the moment, we're comfortable marketing ourselves. As I've said, we've got a very experienced LNG marketing team that's been in place for more than 12 months here. Obviously, many of us around the table have got a long background in LNG. So we've put the right team around us, and we've done market soundings. And now that we're out from the shadows, we can probably start talking more in earnest with some customers.

Okay. And just lastly for me, on the very last slide of your pack, where you've got the summary on the East Coast gas contracts. Can you give us a bit of an update on where you are with arbitration with Origin and what your view of market pricing is? Or is it just going to quote the ACCC?

Answered your own question for me there. Thank you. Look, in terms of arbitration, it's progressing as expected. So it's making progress. Nothing obviously is changed from what we previously told the market and quoted to the market too from that process. So we just have to work through all the steps. So that's all -- we're working through the steps right now. And look, I do think we all producers are giving a lot of information to the ACCC these days. So what you're seeing on the ACCC, I really can add to. You're getting the actual data there, so there is not much more I can add quite genuinely.

Your next question comes from Daniel Butcher with CLSA.

Matt, just want to clarify a couple more things. Most of my questions have been asked. But just on Waitsia, can you just say whether the 50% of reserves being put in North West Shelf, was that a North West Shelf constraint or a WA government constraint or some sort of combination of the above?

A little bit of both. But one of the things for us is obviously, we're very keen to have the right government and regulatory approvals. And I think it's probably notable that in that section of the slide that we've mentioned that number, so at the moment, we've got good alignment from regulators and government and good alignment with North West Shelf. So we're very comfortable with that number.

Okay. Great. And just want to confirm that that's currently viewed as being, for the LNG portion, equity marketing rather than joint marketing.

That's correct.

Yes. And what's sort of -- what are you looking at in terms of domestic -- the piece that goes domestic, is that more back ended? I don't know the maths yet to work how much front-loaded is in LNG. But can you maybe just give us a bit of color what you're thinking on the marketing there?

Yes. So we're active in the market already, as I've said, through our 2 joint ventures in the first place. And we're selling in the order of 40 terajoules a day in the coming year, and we're already active. We've been active in a number of bidding opportunities there. So once these opportunities -- once Waitsia is committed and up and running, obviously, it's an incremental cost story at that point. So longer term as well, there'll be more gas to put into the market via infrastructure that we've put in place, which will also be supporting LNG. Obviously, the other thing to point to is the Beharra Springs Deep discovery. And therefore, we've got substantial volumes, high deliverability at Beharra Springs. And you'll see -- we're looking at debottlenecking of that plant as well. We're doing a bunch of studies on how we get more gas into the market. So you'll see us active now. We've already been active in the last 12 months. So that's why you'll see on that chart on Slide 23 domestic gas sales is going across the entire span of the range of the deep because we've been active in all of those years.

Your next question comes from Adam Martin with Morgan Stanley.

Matt, look, the length of this deal with North West Shelf is important. I'm not sure you're necessarily going to tell us that, but -- in terms of value. But what's the ability to sort of ramp down the project in later years should one of these other bigger resources come in? Are you able to switch across domestic market operation? Are there any concerns? Can you just talk through that, please?

Yes. Obviously, can't talk to you about the details, Adam, as we mentioned, the current negotiations and agreements with North West Shelf. I think we've given you a fairly decent guidance saying, if you assume a start-up at the back end of '23 and you assume that circa half of the BP reserves at Waitsia go to LNG and you assume the type of processing numbers that we're talking about, you can pretty well back out what the time line looks like at the moment. So while I'm in negotiations on those agreements -- or the team is, I should say, I can't really give you away anymore at this stage.

Okay. And just on the downside case around Otway drilling, there's obviously some exploration wells in there. Is that still in the downside case of free cash? Or is that not in there?

So the cost of all spend is in, and we don't assume 100% success on the exploration.

Do you see one of those 2 comes in? Or is that...

Correct.

Just trying to understand what's in there baked -- yes. Okay, okay.

[Operator Instructions] Your next question comes from Scott Ashton with SHA Energy Consulting.

Look, just a quick question on Waitsia and Beharra Springs. Is Beharra Springs volumes ever going to find their way into this Waitsia deal? That's the first part of the question. And second, Beharra Springs Deep is pretty high-pressure gas. So what's the cost of the upgrade at Beharra Springs Deep?

Yes, good questions. In terms of an official term sheet, so what we're referring to there is Waitsia joint venture gas. So we're not referring to Beharra Springs. The expectation is that's Waitsia gas that we're referring to there. In terms of domestic gas positioning, as we mentioned, we're looking at debottlenecking and other opportunities around the Beharra Springs plant. And we're not in the position at the moment to release costs on those issues.

But probably safe to assume that if you've got higher-pressure gas, you probably need to upgrade the surface kit?

I think Geoff Barker, our Head of Development, is pretty keen to answer that one for you. So I'll let him have a go, Scott.

So the Beharra Springs Deep well, the engineering is nearly completed on that. And that'll be tied in towards the end of the year, early next year, calendar year that is. It's a very simple tie-in. The existing facilities are more than capable of handling the pressures and temperatures associated with that well, and future development wells will be very much the -- in the same position. So the question really is, if we undertake appraisal drilling, which we're planning to do in FY '22, is there a justified case for expanding those facilities when you're into a different set of engineering issues? But fundamentally, the existing facilities can handle that gas.

Okay. And just on the 29 million barrels of oil equivalent 2P at Beharra, are you sort of suggesting there something like 140 Bcf a day conservative? Is that roughly what is 6x that 360 is?

You might just want to repeat the questions. You just broke up a little bit there.

Sorry. The 29 million barrels of 2P there at Beharra Springs Deep, you've got about 140. Is it 6 -- 360 and 180 and 160 Bcf back there?

180. And recognize that...

Okay. And just one other sort of fairly esoteric question, and it goes back to probably a couple of the other questions on the call. You have to spike a lot of the gas coming down from North West Shelf and LPG. Do you -- I appreciate you can't probably go into the details of your agreements, but are you having to look after the spiking of the gas for calorific value and all that sort of stuff?

Yes. Adam, look, we definitely can't talk about all of the -- all the details. I think the point to note is we've been working on this for 2 years. All of the technical and commercial issues have been worked through. And so at the right time, we'll say as much as we can at the right time, but I'm not in a position to detail that right now.

Your next question comes from William Morgan with Intrinsic Investment Management.

Can I just ask you to reflect on the politics of DomGas? I mean there's obviously a lot of moving parts to it and a lot of discussion. But just in terms of how momentum might be going from your perspective with respect to Beach's assets.

Yes. I mean look, in forward ways, are you referring specifically to the East Coast?

Yes, East Coast, yes. Yes. And I mean like I look at the misplaced political will there is in hoping that bedlam might get into the market in time to save the domestic market, et cetera. It's the evolution of where the ministers are and the politics of it for you.

Yes. Look, obviously, we're well connected across regulators and governments in all states and through Canberra and through APPEA. So we've got a good understanding, and we're obviously live in all of those discussions ourselves. Look, the key still is we've got great support to Beach and what we're doing because we are obviously leading the charge on investment for more gas supply into the East Coast. And we're doing that through the Cooper, but most importantly, we're also doing that through the Otway. So we and our partners are spending in the order of $1 billion to get more gas into the East Coast market. We've got great support from regulators and governments in relation to that. But I do believe that some of the dialogue around some of gas pricing, et cetera, relative to the U.S. and other countries is probably not well informed. So I think if you look at some of the expert reports on what the cost of supply is into the East Coast, it requires numbers that are similar to what you're seeing at the moment in terms of pricing.

Your next question comes from Saul Kavonic with Crédit Suisse.

Sorry. I thought I might jump in with 2 more if that's all right. I just wanted to dig down a little bit into Otway and Western Flank. Just firstly on Otway, when you talk about natural field decline for Otway in FY '21, I just want to understand why you're seeing that decline in FY '21 given you've had Black Watch come online recently, presenting about 1/3 of the prevailing capacity. I mean that looks like a very steep decline rate. How should we be thinking about decline in Otway over the next 18 months?

Yes. I think part of the issue that you have, Saul, of course, is there hasn't been a well drilled to supply the Otway Basin since 2014 until we drilled Black Watch, right? So clearly, the asset was built down a decline curve path until we came in to arrest it. I think you see this slide on the Otway Basin. I think it's Slide 25. You will see that we've put a chart in there, which shows you a pretty clear view with what we think will happen in terms of the Otway Gas Plant. So I think that's probably your best guide, to look at that chart.

Great. And on Western Flank, you mentioned how robust the economics are with 6-month paybacks. Given that, why is Beach slowing production growth for Western Flank in FY '21 versus the growth trajectory we're expecting prior to COVID?

It's a little bit of a pause in terms of the ability to reduce capital, test how some of these wells perform, being in harvest mode and also giving the team, which has been running very hard, as you can see, in terms of doubling production in the last 2 years, to get all of our thinking straight on how we appraise the remaining fields. And we do think there's a fair bit of upside left in the basin, including McKinlay. And we're really doing the prework, so we don't get the drill bit ahead of subsurface work to get our thinking straight on that. There's multiple benefits in it.

There are no further questions at this time. I'll now hand back to Mr. Kay for closing remarks.

We've obviously provided a lot of information for everyone today, which I hope you get the chance to digest. Obviously, our Investor Relations team are here, as is the leadership team, to take questions that I'm sure will come from all that detail. I appreciate your time. Thanks, everyone.

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