Hello, and welcome to the FY '21 Half Year Results Presentation from Beach Energy. My name is Matt Kay. I'm the Managing Director and Chief Executive Officer for Beach. Joining me on the call today is our Chief Financial Officer, Morné Engelbrecht. And we're also joined by the Beach Executive Team. For today's presentation, I'll first provide an introduction on the current state of play at Beach Energy. Then it will be over to Morné, who will run through the financials, and then I'll provide an update across our portfolio of assets. Following that, we will open the lines for Q&A. Before I begin, Slide 2 includes our disclaimer, price assumptions as well as information regarding our reserves disclosure. I'll leave this for you to read in your own time. So let's move on to the main presentation. There's a lot of information to get through today. So Slide 3 captures what we consider to be the key takeaways. My message to you today is that Beach is on track to deliver on its 5-year plan. Growth is happening and it's happening across the portfolio. The 6 takeaways which I'll explore in further detail today are as follows: One, Beach is already delivering on the key requirements to meet about 37 million barrels of oil equivalent production target by FY '25. This has now been supported by the recent success at Enterprise; as well as taking FID on the Waitsia LNG project, which became unconditional last week. Two, the Enterprise gas discovery nearshore to our Otway gas plant has exceeded our expectations, particularly with its high-liquids content. This is not only positive for refilling the gas plant but also supports upside from further near-shore exploration potential in the Otway Basin. Three, Beach is about to commence its offshore Otway Basin campaign with the spud of the Artisan 1 exploration well. The rig is currently on location. It's a very exciting milestone for Beach and an important development for the East Coast gas market. Four, the Trefoil development in Bass Basin is progressing towards FEED. We are soon to be the owner of a 90% interest in the project when our acquisition of Mitsui's interest is complete. Five, speaking of acquisitions, we see the 2 bolt-on assets of Senex Energy's Cooper Basin interests and Mitsui's Bass Basin interests as creating not only synergies but incremental platforms for growth. And six, we've committed funding to the carbon capture and storage or CCS project with Santos in the Cooper Basin. It should be noted that this project is in addition to our existing 25% by ‘25 sustainability projects. Before I move on, I’d also highlight one issue we do not shy away from. The Western Flank has been a great success for us over the recent years, having previously announced production doubling over a 2-year period and recoverable volumes almost tripling over a 4-year period. In the past quarter, however, we've seen increases in well interference and faster declines than we'd anticipated. We'll discuss that more later. Again, we don't shy away from it. And we won't have all the answers for you today, as our teams are still working through the data and what it means for our future production plans. Moving on to Slide 4, which provides a summation about key achievements and activities on what has been a very busy half for Beach. Make no mistake, this has been a pivotal half for the business. And when you look at the foundations, we are delivering on our growth agenda. It's not every day that you can look back at a half and say you've reached unconditional FID for the company's first LNG project, Waitsia; and delivered a material liquids-rich gas discovery in the Otway Basin, Enterprise, a discovery that supports refilling the Otway plant and more future drilling potential. When you add in the 2 value-accretive acquisitions that we're in the process of completing, you can see that this has been an extremely active half for Beach. As mentioned before, our offshore Otway campaign is imminent. The Ocean Onyx is now on location at Artisan, and we expect to spud soon. Significantly, we made a separate release today regarding our new gas discovery from the Enterprise initial well in the Victorian Otway. It materially supports our 5-year production outlook, but we had only assumed one exploration success from the campaign. The discovery has resulted in the booking of 21 million barrels of oil equivalent of 2P reserves net to Beach, with significant liquids content, and it supports our belief in nearby prospects and leads. Finally, Beach is committed to operating sustainably and reducing emissions. This is demonstrated by our 25% by ‘25 initiative with projects already underway to cut Beach's emissions by one-quarter by FY '25. As I said, it's been a busy period and lays the foundations for our future growth. On Slide 5, you'll see how we will continue to execute and deliver our growth strategy in the second half of FY '21. As I mentioned, we are now unconditional on FID for Waitsia. We've executed the EPC contract with Clough, and detailed design for construction activities are progressing. First LNG is anticipated in the second half of 2023, and yes, marketing activities have commenced. As I said before, the Ocean Onyx has mobilized to the Artisan 1 exploration well site, and spudding expected very soon, effectively kicking off the offshore Otway campaign. In relation to Enterprise, we will enter a FEED phase for the field connections, targeting first gas by the first half of FY '23. Following our contracted acquisition of Mitsui's interests in Trefoil, we are progressing the development into FEED. Meanwhile, in WA, we expect to commence production from the Beharra Springs Deep well. And across the Tasman, in New Zealand we will complete important compressor installation at Kupe. In addition to this, we expect completion of the Origin price review arbitration. As you will expect, of course, I won't be able to comment further on that today. Our position remains unchanged. Lastly, following our recently announced changes to our Executive Team, Thomas Nador and Sam Algar will be commencing their new roles next week, both Thomas and Sam bring valuable experience to Beach. On that note, I'd like to sincerely thank both of our Geoffs, Geoff Barker and [indiscernible], for their outstanding service to Beach in what has been a transformative period for the company. As mentioned in a previous release, these changes have been long planned and have been well coordinated. Both of them are here with me today. I mentioned before that we're on track to deliver on our 5-year growth plan, and Slide 6 shows exactly what I mean. As you can see, the middle column outlines the key assumptions we set at our full year results in August in order to meet or exceed our growth plans. The right-hand column outlines our track record to date. We are delivering on the key planks, including Waitsia LNG, refilling the Otway gas plant and making progress at Trefoil. And hence, we now have increased confidence in meeting the production target of 37 million barrels of oil equivalent in FY '25. Slide 7 gives you a snapshot of operating and financial results for the first half of FY '21. Beach recorded production of 13 million barrels of oil equivalent for the half, a result which is on par with the prior half. We remain vigilant when it comes to reducing field operating costs, and these were reduced by 2% from the corresponding period. A major maintenance shutdown at the Otway gas plant was completed safely, on time and on budget. Western Flank's oil production was up 8% on the corresponding period following the FY '20 drilling program, which saw 27 horizontal oil wells drilled across the Western Flank oil fields. However, we've seen higher-than-expected decline rates in a number of these wells. The company is focused on understanding the reasons for these prior to deciding the optimum production strategy for these assets. We'll discuss this more later. Most importantly today, and I'll expand on this point in a moment, Beach achieved a company safety record of 1 million hours injury free, a remarkable achievement. I'll let Morné unpack the financials shortly. And Beach's balance sheet remains rock solid. Our statutory NPAT is $128.7 million for the half. And our underlying EBITDAX was $446 million, generating a 63% margin on our sales revenue, again reiterating our high-margin business. Our cash and existing loan facilities allow Beach to continue to invest in the high-returning growth projects required to deliver on our more than 37 million barrels of oil equivalent target by FY '25. Beach also today announced an interim dividend of $0.01 per share fully franked. Slide 8 is arguably the most important slide today and the one of which I'm most proud. Nothing is a greater priority at Beach than the safety of our people. During the first half of FY '21, Beach recorded a total recordable injury frequency rate or TRIFR of 2, as well as achieving 1 million hours injury free. The latter achievement is a company record, a company which celebrates its 60th year in 2021. We've also reduced the number of minor spills by 75% in the current year-to-date. As we gear up for our offshore campaign at Otway, I can assure you that our teams will not let their guard down when it comes to safety. On Slide 9, I want to highlight Beach's commitment to sustainability. During the half, we announced our 25% by ‘25 initiative, with a number of projects kick-starting our campaign to reduce our emissions by 1/4 by 2025. These projects are just beginning for us and we'll announce more as we roll out our 25% by ‘25 program. As previously mentioned, Beach is committed to its share of FEED funding for the Moomba CCS project. Again, this project sits outside of the 25% by ‘25 swipe. Also outside of the 25% by ‘25 program, Beach, with its JV partner and operator Mitsui, will also offset 60% of total project emissions from Waitsia once we reach first gas. Moving on to Slide 11. And I know many of you today will be keen to hear about our update on guidance, so I won't keep you waiting any longer. As you can see on Slide 11, we have narrowed our pre-acquisition guidance to 25.5 million to 26.5 million barrels of oil equivalent. The reason for this shift is a result of the aforementioned lower production rates at the Western Flank oil fields and some Cooper Basin joint venture connection delays, partially offset by higher gas customer nominations and the optimization of Western Flank gas activities. On a pro forma basis, which includes the production from the contracted acquisitions of Senex and Mitsui assets from 1 July 2020, our updated production guidance is 26.5 million to 27.5 million barrels of oil equivalent. We've narrowed CapEx towards the higher end of guidance mainly as a result of more Cooper Basin JV spend and our acquisition activities. Furthermore, underlying EBITDA is narrowed to the lower end primarily due to the $39 million of exploration expense during the half, offset by improved commodity pricing forecasts in the second half. Unit operating costs are expected to be higher due to the lower production, while unit DD&A is expected to be lower. Slide 12 unpacks the production and CapEx guidance updates in more detail. Importantly, on the CapEx front, the reason we expect to be at the higher end of guidance is due to the decision to participate in more wells in the Cooper Basin and our commitment to progress Trefoil through the define phase. I'll now hand over to Morné to run through our financial results in a little more detail. Morné? Morné Engelbrecht: Good morning, everyone, and thank you for joining us today. As Matt has already touched on, the results from the Western Flank and the impact from the major planned maintenance at the Otway gas plant were not going to affect our sales volume and revenue during the half. This was further impacted by an almost 40% fall in the average realized oil price when compared to the first half of FY '20. Beach reported an NPAT of $129 million during the half; and an EBITDAX of $446 million, resulting in an impressive sales margin of 63%. In accordance with accounting standards, Beach continued to expense exploration items not within an established area of interest. This resulted in the company expensing $39 million of greenfields, frontier exploration expense during the first half of FY '21. This mainly relates to the unsuccessful Ironbark well and the relinquishment of the Wherry block in New Zealand and permits in the Bonaparte Basin. This resulted in EBITDA of $407 million. Beach continued to have an impressively strong balance sheet supported by stable revenue from our gas business, the backbone of the company. We've access to more than $400 million of total liquidity, including $114 million of cash. We have moved into a net debt position recently following the impact of the weaker commodity prices during the first half. However, at net gearing of 1.5%, we continue to have broad flexibility with our robust balance sheet. Our stable gas business continues to provide a platform for the company, with gas and ethane sales accounting for more than 40% of our total revenue. This is despite the Otway gas plant being offline for 22 days for planned maintenance. It should also be noted that more than 99% of our gas volumes were sold on the contract, providing downside protection. Oil prices have improved more recently. We are not taking our eyes off our cost base. Unit field operating costs were down 2% on the previous corresponding period. And positively, our operational team managed to deliver the Enterprise 1 campaign approximately $8 million below budget, a great achievement. Slide 15 provides more detail of our financial highlights. Production was steady when compared to the prior corresponding period. However, revenue was down 22% due to an almost 40% fall in average realized oil prices. The flow-through impact of [weaker] revenue resulted in an underlying EBITDAX of $446 million, down 28% from the prior corresponding period. As previously mentioned, EBITDA of $407 million was impacted by $39 million of exploration expense items. Also, as Matt mentioned, the Board has elected to pay an interim dividend of $0.01 per share fully franked. Moving to Slide 16, you can see the underlying NPAT movements over the first half when compared to the first half of FY '20. As previously mentioned, Beach delivered an underlying NPAT of $129 million, down 53% from the corresponding period. Revenue was the largest factor, falling by more than $220 million, including a $27 million reduction in other revenue mostly associated with the unwinding of the GSA liabilities and exploration expense, driving a softer NPAT. This was offset by lower operating costs, reduction in royalty payments and lower tax. Slide 17 shows the results on a segment basis and the key drivers of production during the period. It was again worth highlighting the impressive EBITDAX margin across all 3 segments, with a total group margin of 63%. Slide 18 reiterates our current financial position. Beach remains well capitalized to deliver on the FY '21 and '22 investment program. On the left, you can see the changes in the movement in our cash position, with operating cash flow of $296 million down 16%, impacted by low revenue and $128 million of income tax paid. Cash capital expenditure of $345 million was down 18%. This included drilling costs for Enterprise and Ironbark, offset by reduced Cooper Basin and Western Flank costs as activities reduced to single rig. It's also worth noting that -- when the contracted acquisitions for the Senex Cooper Basin assets and Mitsui's interest in the BassGas settles, that the amount of the net cash outflows will depend on the final cash flow adjustments from the effective date of 1 July 2020 to the settlement date. As previously highlighted, we maintained liquidity of more than $400 million, with the current cash and available undrawn loan facilities expected to support the delivery of our growth program. We're also currently assessing the federal government's stimulus initiatives that allow us for an instant tax write-off of qualifying capital assets. This measure is expected to have a positive impact on our operational cash flows over the next 3 years. Importantly, Beach remains a growth-orientated company with highly value-accretive organic growth opportunities which we are in the process of executing. Free cash flow will continue to be reinvested into our high-returning projects, the majority of which allow us IRRs in excess of 20% and short-term payback periods. With that, I will hand back to Matt. Matt?

Thank you, Morné. Before I go into a snapshot of our asset portfolio, I want to talk a little bit about the current dynamics of our markets. On Slide 20, you will see that Beach's geographical diversity and market distribution is across 3 gas markets: Australia's East Coast gas market, the West Coast gas market and the New Zealand domestic market. These 3 markets provide for a well-diversified portfolio in 3 robust markets. We maintain a relatively even split between gas and liquids production across the portfolio with a diversified spread across 6 production hubs. Moving to Slide 21, I want to show you why we believe Beach's entry into the LNG market is occurring at an opportune time. While LNG prices have improved in the northern hemisphere due to a colder and normal winter, you know that beyond this supply is forecast to tighten between 2022 and 2025. This may tighten even further if projects currently waiting to be sanctioned are further delayed beyond their intended start dates. If the market tightens, Beach's LNG volumes from the already sanctioned Waitsia Stage 2 development will be delivered through the highly reliable and reputable North West Shelf facilities. We have very experienced LNG marketing capabilities supporting this project. Following the sanctioning of the project in December 2020, we've commenced discussions with customers regarding our equity share of Waitsia LNG volumes at an opportune time in the LNG cycle. As always, we won't be rushed as we work our way through customer engagements over the course of the year. We will be value focused. On Slide 22, we turn to the domestic WA market. While it does not have the same supply issues in the near term, this is expected to change from midway through the decade. With Waitsia approved for LNG export until 2029, more domestic gas will be available to supply the market just as this demand is forecast to become critical. On that note, I want to commend the Western Australian government in supporting our plans and striking the right balance in supplying the domestic market at a time when the gas is needed. Moving to the East Coast market. On Slide 23, we can see a chart from AEMO that we've shown you previously which clearly demonstrates the shortfall in supply from around 2026. Going forward, the picture doesn't get any better, so this reliance on diversions from LNG projects set to increase over time unless there is a significant increase in supply. The message is simple. The East Coast needs gas development and it needs it now. That's precisely why Beach is currently undertaking the $1 billion campaign in the Victorian Otway along with our joint venture participant O.G. Energy. And with fewer of our volumes contracted at legacy pricing, each is set to capitalize on the opportunity presented in the East Coast gas market. Now let's change gear and take a look across our asset base. Slide 25 is one of our most important slides for the day, so let's take some time to digest it. I want to show you what's driving the growth profile of Beach. Remember that I said at the outset that we're on track for our target of reaching more than 37 million barrels of oil equivalent annual production by FY'25, and we're doing this by investing in high-returning projects across the existing business. Growth is happening and it's happening across the production hubs at Beach. We saw this opportunity when we made the Lattice acquisition, and now these plans are being delivered upon. If you look at all of the assets we're investing in, we have targeted project IRRs of more than 20% and a number greater than 50%. In days come by, we were questioned about the quality of the Beach reserve space, and here is the answer: We have high-quality reserves and resources close to infrastructure and markets and may generate material returns. This includes our assessment with the Trefoil development, which is why we've acquired more. We've also been questioned from time to time about the longevity of our reserves base. Again after the Lattice acquisition and our discoveries since, for example, Beharra Springs Deep and Enterprise, amongst others, almost all of our assets have lives beyond 15 years. The Perth Basin and Victorian Otway Basin are growth engines for the business. In my opinion, that legacy concern over our reserves should now be put to bed. When you look at the combination of project IRRs, expected payback periods and the life of these assets, Beach truly boasts a high-quality asset portfolio. Frankly, I can tell you from 30 years of experience that it doesn't get much better than this. Now let's take a deep dive into each of these, starting in the Perth Basin. On Slide 26. I've already spoken a bit today about Waitsia reaching FID in December, and that FID became unconditional last week. Let's break it down. One, agreements to process up to 1.5 million tonnes of LNG over 5 years are in place. Two, agreements with AGIG to transport Waitsia gas by the Dampier to Bunbury Natural Gas Pipeline have been executed. Our interconnection to the Dampier to Bunbury Natural Gas Pipeline is already in place. Three, Clough has been awarded the EPC contract to construct the 250 TJ onshore gas processing facility. Four, key government approvals have been received, including the environmental approvals granted earlier this month. We'll continue LNG marketing throughout this year with an experienced LNG marketing team and first gas expected in the second half of 2023. Going forward, if you -- don't read anything negative into a lack of near-term news on the marketing front. We will be taking our time and getting it right. What I want to emphasize is the fact that Waitsia is a long-life asset with high-quality reserves that will not only supply the global LNG market in the near term but also support the WA domestic market for many years going forward. To Slide 27 and Victoria. Earlier today, we announced a 2P reserve booking of a liquids-rich Enterprise gas field which was only discovered in December last year. This nearshore gas discovery has turned out to be an absolute cracker with 2P reserves of 21 million barrels of oil equivalent net to Beach, including 97 PJs of sales gas and 2 million barrels net of condensate that cannot be underestimated. It should also be noted the liquids yield of approximately 25 barrels per million scfs is well ahead of our pre-drill expectations. The go-forward plan is to commence FEED in the current half of this financial year, and subject to approvals, we'll be targeting first gas from mid-2022. Development is relatively simple and low cost, which will include a new pipeline connecting the onshore wellhead to the Otway gas plant only 9 kilometers away. Most importantly, the discovery supports our 5-year production forecast for the Otway basin, which had assumed a single exploration success and supporting the Otway gas plant towards full utilization by FY '23. Further, these gas volumes are uncontracted, which will allow for offtake diversification from the Otway gas plant and will be available at East Coast gas market prices. Importantly, we see more prospects and leads coming into play following the Enterprise discovery. There is a long and successful future ahead for the Otway gas plant. Remaining in the Victorian Otway Basin on Slide 28. And we saw a production decline of 33% during the first half largely because of the successful planned major maintenance shutdown in November. The shutdown was delivered on time, on budget and safely. Other activities: The successful downhole well intervention at Thylacine 1A delivered an uplift of 20 million scfs a day to the plant. As I've said earlier, this now all lies on the Artisan 1 exploration well, where the Ocean Onyx rig is on location and we plan to spud very soon. The Artisan well has around a 50% chance of success, so we keep our fingers crossed and wish the team a safe and successful campaign. To Slide 29 and moving on to the Western Flank oil. I once again want to provide assurance that the Western Flank remains a very good asset but also not shy away from the fact that we've had some production decline above expectations in the past quarter. Most of you know that we've doubled production and almost tripled recoverable oil volumes over the past 4 years at the Western Flank. The operation is barely recognizable from a few years ago, but we now have around 150 producing wells, with almost 100 on pump support. The FY '20 drilling program was an extremely busy year. We saw 36 oil development wells drilled on the Western flank, including 27 horizontal wells. What we've seen in the past few months is a higher-than-expected well interference from the McKinlay drilling on the Namur and McKinlay existing producers and, as a result, faster decline rates. That means the team is busy taking stock of all the production data before we execute our next steps. It also means we won't have all of the answers for you today. We need to do the work. We have a further 6 horizontal wells planned for the second half of FY '21 and 8 wells to be connected. Do we still believe in a strong future for the Western Flank? Yes, we do, but we need to determine the best way to exploit the reservoirs moving forward. Slide 30, speaking of the Western Flank. The acquisition of the Senex Cooper Basin assets is a logical and value-accretive acquisition for Beach. Funded through existing cash and debt facilities, on completion, the acquisition makes us the sole operator and infrastructure owner in the Western Flank. We have several exploration prospects that we are now evaluating, which will be incorporated into the FY '22 drilling program. On Slide 31, moving to the Bass Basin, where our strategy is to continue to invest in East Coast supply and extend the life of our existing infrastructure. Following the contracted acquisition of Mitsui's interest in the Bass Basin assets, Beach is stepping forward on Trefoil, where we currently envisage IRRs of more than 20% and an asset life of around 15 years. We expect to commence FEED during the second half of FY '21. Subject to approvals, we're targeting first gas from FY '25 to be sold to the East Coast at market prices. Slide 32 and turning to the Cooper Basin joint venture, where our strategy is to pursue high-value, low-risk opportunities. Production was steady for the half; and our operator, Santos, completed 19 wells at a 90% success rate. There were some production impacts in October due to weather-related events and the Big Lake-to-Moomba trunk line shutdown. Our plan going forward will involve participation in 28 wells in the current half, including follow-up for the successful Anna North-1 well. Moving to Slide 33 and across the Tasman to our Kupe gas project. This is an asset we are very proud to have in the portfolio, and we're looking to continue the life of Kupe. We're now ready to commence with the meaty end of the compression project, with all materials in country. And planned well intervention will occur this quarter, and the compression project will come online in the first half of FY '22. Now before I move to Q&A, let's go to Slide 34. There's been a lot of information. Let's recap some key takeaways. One, Beach is already delivering on our key requirements to meet our 37 million barrels of oil equivalent production target by FY '25. This has now also been supported by the recent success at Enterprise; as well as taking FID on Waitsia LNG, which became unconditional last week. Two, the Enterprise discovery has exceeded our expectations, particularly with its high-liquids content. This is not only positive for the current program. It also supports upside from further nearshore exploration potential in the Otway Basin. Three, Beach is ready to commence its Otway offshore campaign with the spud of the Artisan 1 exploration well, with the Ocean Onyx rig on location. It's an exciting milestone for the company and an important development for the East Coast gas market. Four, Trefoil is progressing towards FEED. In addition, we are soon to be the owner of a 90% interest in the project, and as such, we're excited about the additional value we can create at BassGas. Five, we see the bolt-on of Senex' Cooper Basin interests and Mitsui's Bass basin interest creating not only synergies but additional platforms for growth. Six, we've committed funding FEED for the CCS project with Santos in the Cooper Basin. It should be noted that this project is in addition to our existing 25% by ‘25 sustainability projects. And finally, we still see the Western Flank remaining a key asset for us. It's a quality asset. And as I've said, we need to do some extra work; and better understand how we continue to best explore, develop and produce there. In short: Growth is happening at Beach. It's happening across our portfolio with high-quality and long-life assets, and we're very excited about delivering on these growth plans and delivering shareholder value as a result. On that basis, I'd now like to open it up for Q&A.

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

So yes, really interesting presentation in the context of the 5-year outlook. You've had obviously the acquisitions in the Cooper and the Bass Basins and you've described Enterprise as being a cracker, but I guess I've just noticed a subtle change in language in terms of the production outlook now being meeting 37 MMboe by FY '25 as opposed to the prior stated goal of 37 MMboe to 43 MMboe. It just feels like you're deemphasizing the top end of that range there, so it does feel like it's a bit of a softer outlook despite the fact that you've had those acquisitions. So is it are you just deemphasizing that because of the uncertainty around the Western Flank decline rate? Or is there anything else in the portfolio that maybe is performing below your expectations?

Thanks, James, for the question. No, look, there's nothing else in the portfolio that's delivering below expectation. We've fully disclosed today anything that's happening on the assets. And I think we've been very clear about the Western Flank, or as clear as we can be right now. All we're saying is that, that 37, we always said, was base target and then we had an upside target above that. We've got a slide there which pretty much shows you what those key assumptions were and what the track record is. And what we're seeing at the moment is a high degree of confidence in terms of delivering on the base because of Enterprise and because of Waitsia FID. And then you can see exactly what we need to happen to have the higher case come in. Now the fact that we're progressing Trefoil will absolutely help with that. The great thing about our portfolio right now is -- having 6 production hubs is we're going to have ups and downs and ins and outs from all of those assets, but we now have diversity where, if one of the assets has a downturn, then the other assets lift the game, all right? So we're very, very confident on the 37. A high-side case will depend on a few other things coming in. And what we've done has been pretty clear in that slide to flag what those items exactly are.

Yes, I got it. So if I look at -- I think it was Slide 23. I can't remember but -- the table with all of the growth projects. You've reiterated the very high IRRs from the Western Flank, 20% to 100%. If I think about those new wells you're drilling that are effectively cannibalizing production from other wells and yet you've still got very high IRRs, is it right to say that you're probably thinking about still committing to reach higher volumes consistent with that 5-year outlook but, I guess, it would come with a higher capital intensity? Like it's still NPV positive because of those IRRs, but you're having to spend more CapEx to achieve that same volume. Is that fair, or do you just not know yet?

No. Look, I think the way to think about it is the reason we've reduced the band on some of those rates of return in the Western Flank is, if you roll back 2 years, the vast majority of our production in the Western Flank was coming out of the Namur wells, which we were getting incredibly high rates of returns, over multiple hundreds at the same IRRs. A lot of our production is now coming out of the McKinlay. And we're also working obviously some of the other parts of the basin as well, well up Birkhead. And on some of those campaigns, we're seeing lower returns than the pure Namur play. So we're just showing the range at the moment. From our perspective, in terms of exactly what's going to happen here going forward, that's where we want to do the work before we come out and announce to the market. There's a range of options varying from accelerating drilling on wells, going to slowing down, going to targeting gas first, going to targeting more of the Senex acreage. The great thing about the Senex acreage is it's a good add for us that gives us some opportunity to work out which elements we want to move forward on first, but we need to do the technical work, frankly. That's why we're not being too explicit today.

Yes, got it. And then the last one for me: I guess, following on from having to do that work, is that why you haven't reiterated yet the CapEx for the 5-year outlook? I think, from memory, it was $4.2 billion, but you've obviously got these acquisitions you've made. You're participating in the Moomba CCS project, maybe a little bit more CapEx to go into Western Flank. So is it fair to say that the CapEx intensity for the whole business is starting to creep up a bit versus that prior disclosure?

I think, what we've said in terms of this year, there is obviously 2 acquisitions that we've undertaken. Therefore, we've got higher equity at Trefoil. We've obviously got the Senex assets as well. So clearly, that will come with some additional CapEx but also additional production and additional value. The process is going in our planning cycle right now. This is where we start doing our 5-year planning recap, so we've got a chance to do that, and at the right time, we'll update the market on what the future looks like. I don't expect it to be substantially different from what's already out there, but I want to withhold being definitive on that until we can come out post our 5-year planning, replanning with that new portfolio.

Your next question comes from Mark Samter from MST Marquee.

A couple of questions, if I can. Just to leave nothing to doubt. Can we be crystal clear on the 37 million barrels that you're still targeting in FY '25? Does that include now Trefoil and Senex assets? Because I mean, Trefoil, your production guidance would give you -- the acquisition gives you another 1.5 million barrels, and then Senex there's another 0.5 million barrels. Should we see this supposed reiteration of guidance actually being a 35 million barrel target for the original portfolio and we've added through acquisitions to that?

Not in relation to Trefoil, Mark. Trefoil would send us -- if it comes on in FY '25, which would be the plan, would send us well above 37, so I wouldn't count Trefoil in. In terms of our confidence, I think the main issue is the 2 key things we had to land was one FID on Waitsia-2 and exploration success in the Otway, which we now have. And then you have the ins and outs in basically what will happen on the Western Flank going forward. So we're very confident mainly because of what's happened in the west -- or what's happened in the Otway. And then the ins and outs will be what happens on the Western Flank going forward, but it doesn't rely on Trefoil.

I mean, I guess, can you just help us contextualize that? You're talking about an increase in confidence, but if we go back and look 2 years ago what you were targeting for FY '20 and FY '21, you've had 10%-plus production misses versus those original targets. And you spent 50% more CapEx over those 2 years to achieve much lower production. I guess, what's different about the next 3, 4 years? And why we should, I guess, trust your enthusiasm for that outlook; and yes, what you've seen over these last couple of years that has made you reasonably materially miss your expectations on higher CapEx?

It's a fair question, Mark. I think, if you look back what's happened in the last 12 months, you have to take into account the decisions we made during the downturn. So decisions, one, to reduce some of our drilling in the Cooper; and more importantly, the fact we in effect delayed the entire Otway program by about a year predominantly because of COVID and the fact we were in a $20 oil scenario for a while there. So we've been very clear with the market on those moves we've made and the impact it's had, but a predominant issue, if you think back, the last 2 years has been the fact that we slowed down the Otway Basin drilling program by almost a year.

Okay. And just one sort of around the Otway. I know you said in the answer to James that not less than some of the Western Flank have underperformed, but if we go back to your August result, the chart showed Otway doing about 30 PJs growth this year. And I mean, gosh, even if you did 100 [TJs] a day, which at the moment you're doing 50, you'd be like you'd hit 25 PJs for the year. Should we think about the existing wells potentially underperforming? Or is that all customer nomination?

That's customer nomination related. So what -- being obviously a gas business, what you see in terms of our fluctuation in the Otway particularly normally depends on customer nominations.

Okay. And then just one quick last question, if I can. At the full year '20 results, you gave us oil production guidance of 9.2 million to 10.2 million barrels for FY '21. If we look at that underlying production guidance, to some excess, you've given us the group number, obviously, but can you tell us what the oil production assumption is within this, the new guidance?

Probably easier just to disclose to you what's happening at the moment on the Western Flank because that's really the change. So obviously what we said is we were expecting the Western Flank to be running by the 20,000 a day, and what we're seeing at the moment is we're now sitting at around 18,000. And that's purely really because predominantly the interference that we're seeing between those new wells from the FY '20 program across the existing producers. So that's been the key impact. I think that's the focus area for us. Q - Mark Samter: Okay. And I guess that's -- mathematically filters through into FY '22, that by the time you've taken your decisions, I mean, even if the conclusion is to add a second rig and go hard, obviously you're going to be cycling much lighter production than thought. So I guess we should think there's a pretty material filter-through to FY '22, potentially in FY '23.

No, I'm definitely going to hold my response on that question. It's an appropriate one, but I'll hold my response until we've done the work because it will depend on what we come out with. It will also depend on what happens to those wells going forward over the next few months and how they settle down. Geoff, I don't know if you want to comment.

Yes. We've still got 8 wells to connect, 6 or so, from -- to drill and another 8 -- including 8 wells to connect. So there's a fair way to go yet and a couple of fracs we've got a chuck in as well. So a lot of the wells that are going to contribute to production. We haven't seen what their performance is like yet.

That's -- it's the right question, Mark, but it's too early for us to answer it accurately.

Your next question comes from Adam Martin from Morgan Stanley.

Yes. Just on the Western Flank. Those decline rates, are they similar in both horizontal and vertical wells? Any difference there? And is this likely to have a reserve implication in August? How are you thinking about that at this point, please?

Yes, I'll have a go at that, Adam. And then I'm sure Geoff will add something. In terms of what we're talking about, really we're talking about Bauer. And we're really talking about some interference between the new wells and the historical producers both at Namur level and McKinlay. At the moment, it doesn't necessarily mean it will have an impact on reserves. There's a lot of data obviously that we're working through right now. There's 30 to 40 kilometers of laterals in McKinlay. There's course. There is production from about 150 wells, so there's a lot of data we're working through, but it does not necessarily mean that it will have a reserves impact. But Geoff is a reserves expert. He might want to comment.

No, I really don't have anything more to add. I think you covered it off pretty well, Matt. The reality is that we are assimilating a lot of information from a number of recently drilled wells. We've currently got about 40 horizontal laterals that have been drilled. 25 of those are in Bauer. As I said, we've got another 6 to 8 to go. We'll build 16 wells this year in the first half, this sort of first half. There's a lot of information that we need to assimilate before we come out and make a prediction on what the reserves will be.

Okay. No, it's good. And next question, just on Enterprise. You've put in 63 TJs that it flowed at. Should we expect similar production rates when that's tied in first half '23, or lower? What should we expect from Waitsia?

Yes, look, the well potential is good. And we can expect those sort of initial rates.

Okay, good. And that -- and final question, just on Waitsia. Can you just remind, is that joint marketing with Mitsui? And perhaps just a bit of color on sort of what countries, markets you're trying to market to there, please?

It's -- no, it's separate marketing, so we're marketing separately. We -- as I've mentioned previously, Adam, we've got a very experienced LNG marketing team in place that have been with us for a little while here, knowing where we were heading. Did we want to market heavily during the market downturn and COVID peaks? No, we didn't, so we held off. From our perspective, we're doing one-on-one engagements at the moment. We'll probably have a tender process running forward. We're getting very good interest because of the volume we're talking about and the reputation of North West Shelf, we're getting good interest not only from the longer-term customers but also getting interest from the traders. And so we've got all those options open to us. We haven't made any decisions on how much we're going to contract and how much we're going to hold back to spot. Because of the limited CapEx relative to greenfield and brownfield LNG projects that we have ahead of us, we've got that optionality. It's too early to speak exact countries and exact terms and what our price linkage will be. At the moment, the answer is all options are on the table as they should be at this point in time.

Your next question comes from Daniel Butcher from CLSA.

Just one quick one, to start. Just I mean the result from Enterprise looks very good and well above what we assumed for that well. I'm just wondering. Does the size of that discovery and liquids contents change your views on the pre-drill expectations for Artisan or any of the development wells? And if possible, can you give us a rough feel for what you think they might come in at?

No. Enterprise is in a separate previously undrilled basin, hence the -- we've never seen condensate rates of 25 barrels per million. So our size and enthusiasm for Artisan remains unchanged. And the -- of course, at Geographe and Thylacine, we've got well controlled. Those are infilled 2P undeveloped reserve wells, so...

I think the difference is, Daniel, that we have existing prospects and leads around Enterprise that we can drill off the same pad. So that gives us a lot more confidence for those, and we can mature those. And hopefully, we have the challenge going forward of how we're going to sequence these wells on these fields. That would be a nice challenge to have.

There were a few bits of good news. One was the liquids rate, and the other was low condensate -- excuse me, the low CO2 percentage that we saw. So then that -- those 2 risk elements are much lower for any further drilling.

Sure. And would you care to give us a rough estimate of your pre-drill estimate for Artisan then?

No, can do.

We haven't...

Well, it's worth a try.

Worth -- it was worth a shot, Daniel.

Can we just go back to Adam's question maybe just to fill in a few things there? You gave the IRR for Waitsia this time. It's 20% roughly, and I'm just curious. I take that you mentioned you'll hold back for them to spot. You're not quite sure how much. Can you maybe give us a few more of those options that go into that number? We've got CapEx, so far. I mean, what sort of average LNG price are you assuming? Or you assume a certain oil price and slope in there. Or what do you think to get to 20%? I've got a lower number, so far.

Yes. No, look, I think we're well above 20% is what we're saying. So from our perspective, Daniel, I think we've given you the rates. We've given you the timing. We've given you the CapEx. You can use your own seriatim process on top of that, from our perspective, on what we see as prevailing forward curves, the type of returns we're looking at, hoping to get more, having to hit peak and get the marketing spot on. But what we can say is this is a highly economic project. You've got high deliverability from onshore wells already connected into the Dampier to Bunbury pipeline. You've got a tried-and-tested cookie-cutter, in effect, plant to go in as well. And then we go through North West Shelf with all the credibility of the North West Shelf facilities and offtakes, so we're very strong in terms of how that project sits and its returns.

Okay. If you have time, one very quick last one: Half year production for the acquisitions, the Senex and Mitsui ones, I think, was 0.7 million barrels, but your underlying -- sorry, your production after acquisition has gone up by about 1 million barrels, so it doesn't sort of imply a very steep decline in the second half on the acquired assets. Just curious if you can give us some color on that.

Guys, do you want to try that? Morné Engelbrecht: I think it's -- I mean, on the number, it was pretty evenly split between the 2 halves. So we've given the range today on one of the slides in terms of the guidance in terms of what we see coming from the acquisitions, which I think was around 1 to 1.3 for the year.

Yes, Slide 12, yes, right, but the bottom end of 1, less the 0.7 from the first half, would imply 0.3 at the low end for the second half. I'm just curious about that. Morné Engelbrecht: Yes. Look, we can get back to you afterwards, both Mitsui and Senex acquisitions. So both of those.

We would be happy for you to dig into the detail with Chris, Daniel. Morné Engelbrecht: Right, yes.

[Operator Instructions] Your next question comes from Gordon Ramsay at RBC.

Just on the Lattice negotiations. I know you said you didn't want to get into the details, but I just want to reconfirm the timing. You had previously stated third quarter FY '21, and then that's pushed out to second half. Is it still second half FY '21?

Yes, it's hard to predict timing, Gordon. It's now in the hands of the arbitrator. So it -- look, it could happen in the next month. It could happen in the next 6 weeks. It could happen in the next 8 weeks. So the process is well advanced is all I can say at the moment. And obviously, I can't give you any details, unfortunately.

Okay. And just on the Waitsia LNG contracts: I know you're not sure whether it will be between contract and spot, but just on the contractual side, would you be looking at multiple buyers? Or would you be happy to sign up with just one buyer for the full 1.5 million tonnes, or you're share with...

It -- yes, it depends entirely on price and terms, right? If someone comes in with knockout price and terms and they're a high-quality buyer, then they'll do very well. I mean, as I said, this is still early days out of the gates. We're having one-on-one conversations with multiple buyers. We will almost certainly run a tender process for the volumes and what the competitive tension brings and we'll decide from that point. Obviously, it also depends, as you know, on the quality of buyer. I mean, if we have a premium, high-quality buyer with limited risk profile, then clearly we'd be happy to sell the vast majority of volumes to that buyer at the right price.

Your next question comes from Saul Kavonic from Credit Suisse.

A few quick questions, I think. Sorry, and perhaps if I missed it, but are you perhaps able to outline more the instant write-off tax benefit that was announced in the budget last year? Have you got any further color on the degree to which you expect Beach to benefit over the next 2 years from that? Morné Engelbrecht: Yes, no, thanks. So probably before -- I'll give you a very wide range in terms of the numbers we're sort of thinking about because obviously it's highly dependent on the strict criteria we need to meet, which is around the specifics of it being a qualifying asset. So it can't just be general CapEx. And it's obviously highly dependent on the commitment being made after the budget was announced and obviously being installed and ready for use by the 30th of June 2022. And obviously it's also very highly dependent on the work program and budgets for FY '22. As you would expect, it's probably more geared towards the short end in terms of onshore development in terms of committing and getting it ready for use. So I suppose, with of all those caveats, we're probably looking at about $100 million to $150 million of cash benefit over the next 3 years.

Great. That great disclosure. My next question is on just talking about the work that's being done in Western Flank and as part of this assessing the situation before you determine the optimized production levels going forward. Do you have an ETA on when you expect to have, I guess, concluded that work and be able to announce what the plan for Western Flank production outlook might be?

Yes, look, I think this work is ongoing. We probably -- our plan would be to have that ready for obviously the FY '22 budget cycle. So the intention would be -- I would imagine, Matt, is to make disclosure as part of that cycle.

Yes, that's right, Geoff. And it depends partly as well on how material the impacts are that we see along the way and how definitive they are. I mean, as we mentioned earlier, if you look at the flank now, we've got 150 or thereabouts producing wells, 100 on pump. We've still got some more wells, as Geoff mentioned, to drill and connect over the coming months, so there's a lot of data to get through. My preference when we come out is to be definitive when we can, so that, if we see anything that is material and definitive and we have to disclose, we'll absolutely disclose, but obviously we've got reserve announcements coming up down the track. And then we've obviously got our guidance for next year as well, so there's obviously looming deadlines. The work has gone forever, clearly.

And parallel to the work on developing the fields is developing the final portfolio of the [ENA] opportunities that we're going to be pursuing over the next couple years. We spoke a couple years ago about the [ENA] prospect inventory that still remains on the Western Flank. So a big part of the go-forward production forecast is going to be the new fields that we plan on finding in the next couple years.

Got it. I guess a follow-on to that is can you just perhaps give us a bit more color on what are the potential targets that can be built around adjacent to Enterprise and potentially Artisan if it comes in?

Jeff, do you want to talk to the prospects around Enterprise?

We -- I don't think -- we don't have any numbers for them. I can give you some names. They have names like [Rayville, Archer and Lindi] at the moment. And we're probably going to have some seismic acquisition to fill some of the gaps in the seismic database that we have. I mentioned earlier, one of the key risks we had to eliminate from that little mini basin was the CO2 content in the gas. And we were that's -- to be honest, that's why we had a risk. It's kind of 50-50 pre-drill. So they're probably a combination of some seismic acquisition and further studies, but obviously, once the pipeline is in back to the plant, the [MEPs] for anything drilled from an onshore location is going to be extremely low. So I guess, watch this space.

Got it. And Matt, sorry to come back to just on the Western Flank. Under the long-term 2025 37 million barrel production target, are you able to just give us an indication of what the on the -- of that 37 was Western Flank when you provided that guidance last year? And can you just clarify again that Trefoil and the Senex acquisition is not included within that 37?

Yes, correct. So Trefoil was not included in the 37. The 37 was the base case. Obviously, Trefoil will be material. We haven't included obviously acquisitions in those targets either. In relation to Western Flank, obviously not dissimilar to our current production targets. We'd had them starting over 20 a day, but we did certainly have decline coming in over the 5-year period. We haven't released exact numbers on that, but naturally we had decline coming in. And really the dependency on that will be what we'll work through in the coming months around Western Flank going forward. Bottom line is, for me, this is the whole reason we did the Lattice acquisition, all right, to end up with 6 production hubs and multiple development options so that, if one is having a peak, fantastic. If one is having a down, it can be carried by the others and covered by the others, but don't be too quick to put a line through Western Flank would be my advice. It's still a very, very strong asset; still has great returns. And we've just got to get our heads around the current data that we're seeing which we didn't expect.

Especially with the remaining exploration portfolio on the Western Flank.

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

I appreciate everyone's time and interest. And I thought we got a really good series of questions there, so thank you so much for the questions and your interest. If there's anything outstanding, of course, please feel free to call Chris anytime. If there's a need to have a follow-up conversation with management, that can happen, of course, as well. So thank you, everyone, and have a great day.

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