Hello, and welcome to the FY '21 full year results presentation for Beach Energy. My name is Matt Kay, and I'm the Managing Director and Chief Executive Officer of Beach. Joining me on the call today is our Chief Financial Officer, Morné Engelbrecht. We're also joined by some of the Beach executive team. For today's presentation, I'll first provide an overview of the current state of play at Beach. We'll then hand it over to Morné, who'll run through the financials, and then I'll provide an update across our portfolio of assets. Following that, we'll open up for Q&A. Before I begin, Slide 2 includes our disclaimer as well as information regarding our reserves disclosure. I'll leave this with you to read in your own time. Now let's move on to the main part of today's presentation. We'll go through a fair bit of information with you today. So Slide 3 captures what we consider to be the key takeaways from a very active FY '21. The past year saw Beach make a strong start to our gas growth agenda. We completed our FY '21 work program in a safe and stable manner and are well positioned financially and operationally to deliver future growth from our key gas assets. Our confidence is driven by the fact that, one, the compression project at Kupe is now in the commissioning stage, with first gas expected soon. Two, the Ocean Onyx is continuing its offshore Otway drilling program, its drilling scheduled to be completed by the end of this financial year. And three, all relevant approvals are now in place at Waitsia Stage 2, and early construction works have commenced. In relation to Beach's share of LNG from Waitsia year Stage 2, we've made very good progress on the marketing front, and we look forward to sharing some more information with you later this year. Despite the challenges faced in the Western Flank in FY '21, Beach's balance sheet remains extremely robust. The circa 1.5% of net gearing at the end of FY '21 are well positioned for the delivery of the growth agenda in FY '22 and FY '23. Indeed, as of today, we are back in a net cash position. Finally, on the emissions reduction front, we are very pleased with how we are tracking against our 25 by 25 targets, with our estimated emissions already 12% lower at the end of FY '21 as compared to the FY '18 benchmark. Slide 4 is a snapshot of what we've achieved in FY '21. Notwithstanding the 2P reserves downgrade in the Western Flank, FY '21 was a highly active and successful year for Beach. This is even more apparent when you consider the backdrop of the enduring COVID-19 pandemic. First and foremost, FY '21 was our safest year on record, something we take significant pride in given the level of activity progressing on our growth agenda. In the Victorian Otway, we drilled 2 exploration wells and made 2 discoveries. The successes at Enterprise and Artisan not only delivered 2P reserves and 2C contingent resource, respectively, but also helped to further de-risk future Otway Basin drilling programs. We also drilled the complex Geographe 4 extended reach well and landed the subsea Xmas tree on Geographe 4 and Geographe 5 well locations. In the West, as previously noted, we reached FID at Waitsia Stage 2, and we've made very good progress with the Waitsia LNG marketing negotiations. We are targeting the execution of Beach's first LNG sales contracts in FY '22. In New Zealand, we progressed the Kupe compression project to the commissioning stage. This was achieved despite the logistical and border-related challenges that were presented by COVID-19. It was also a busy year on the commercial front with favorable outcomes in our 2 Lattice East Coast gas sales price reviews as well as resolving the carbon liability associated with the Kupe GSA in our favor. In addition, we also delivered bolt-on acquisitions in the Cooper and Bass Basins. On the sustainability front, our JV participant and operator, Santos, we progressed FEED for the Moomba carbon capture and storage project where we have a circa 33% interest. Turning our attention to FY '22. And on Slide 5, you will see this year will again be an extremely active one across the portfolio. In the Victorian Otway Basin, we will complete the drilling and tie-in of Geographe 4 and 5 development wells, the incremental gas targeted for mid-FY '22. In addition, we'll complete the drilling schedule with 4 Thylacine development wells as we target incremental gas from that field in FY '23. Moving closer to the coast line, we'll make a final investment decision, the Enterprise nearshore tie-in project targeting first gas in the second half of FY '23. In the Perth Basin, construction activity will ramp up significantly at Waitsia Stage 2 as we move towards our first gas date targeted in the second half of calendar year 2023. As previously mentioned, FY '22 will see Beach reach a significant milestone in becoming a global LNG player as we expect to execute our first LNG sales contract. Over to Tasman and in the Taranaki Basin, first gas is expected soon from the Kupe compression project. In the Bass Basin, we'll progress FEED activities in FY '22, the Trefoil project. We'll also undertake a 28-day statutory shutdown of the Lang Lang gas facility and the Yolla platform. In the Cooper Basin, we'll recommence exploration in the Western Flank as well as complete FEED studies in the Moomba CCS project. The year of high activity and significant milestones, I think Slide 6, is arguably the pick of the bunch as nothing is a greater priority at Beach than the safety of our people. As previously mentioned, FY '21 was the safest year on record at Beach, and we've chalked up 3 million work hours without a lost time injury. Beach recorded a total recordable injury frequency rate, or TRIFR, of 2.1, an improvement of 40% on the previous year. This is an outstanding result from our teams and sets the benchmark for us to beat in FY '22. Moving to Slide 7. And later this week, Beach will release its 2021 sustainability report. I'll leave you to read that report at your convenience, but I can provide an early highlight today and that is our aspiration to reach net zero Scope 1 and 2 emissions from our operations by 2050. We accept as a member of the energy industry we have a role to play in managing our carbon emissions. We're committed to playing our part and have already taken tangible steps through our 25 by 25 initiatives. To that end, Slide 8 provides more detail about what we've completed in FY '21 and our aim to reduce emissions by 25% by FY '25. In FY '21, we completed 4 emissions reduction projects at our Otway, Middleton and Lang Lang facility. We also completed leak detection and repair surveys at all major assets. This remedial action is being taken through the maintenance schedule. On the non-operated front, we continue our work with Santos on the Moomba CCS project where we have a working interest of about 33%. Beach is currently conducting our FEED assurance gate reviews in readiness for a final investment decision on that Moomba CCS project. At Waitsia Stage 2, we've committed to offsetting all of our reservoir CO2 from the start of production. In addition, we continue to work with our operator Mitsui to reduce the remaining 40% of emissions of the project. Turning quickly to Slide 9. As at the end of FY '21, our Scope 1 and 2 emissions are around 12% lower compared to our FY '18 benchmark levels. I should point out that these numbers are preliminary and are yet to go through the necessary auditing and verification process. The final national greenhouse emissions reporting scheme verification will occur in October. In short, we're around halfway towards our 25 by 25 target. Slide 10 helps summarize where Beach currently stands following the FY '21 program. Beach recorded production of 25.6 million barrels of oil equivalent in FY '21, down 4% on the previous year but at the higher end of our revised FY '21 guidance. Our EBITDA of $953 million was in line with the original FY '21 guidance. As a result, our underlying NPAT was $363 million in FY '21 and now into FY '22 in a strong position as we continue our pursuit of value-accretive growth in our gas portfolio, which will, one, deliver stable and long-term revenue streams; two, provide diversification across 4 gas markets; three, improve our positioning in the tightening East Coast gas market; and four, enable us to access global LNG markets. I'll provide more detail on this shortly, but our production guidance for FY '22 is between 21 million and 23 million barrels of oil equivalent. As we continue our growth agenda, our capital expenditure guidance for FY '22 is between $900 million and $1.1 billion. Our robust balance sheet means we're well positioned to deliver on the growth program. At financial year-end, our net debt figure was just $48 million, while our net gearing was only 1.5% despite a $117 impairment. We entered FY '22 with $402 million in available liquidity. As mentioned, as of today, we're again net cash. Our final dividend of $0.01 per share fully franked is unchanged on the prior period as we continue to prioritize total shareholder returns through value-accretive investment. On Slide 11, you can see our reserves overview. The key takeaway is that despite our previously announced Western Flank 2P oil and gas reserves downgrade, our 2P reserves life remains unchanged at 13 years. In fact, despite the FY '21 downgrade, Beach has delivered a 4-year Western Flank 2P oil replacement ratio of 125%. Across the entire Beach portfolio, our 3-year 2P reserves replacement ratio is at 132%. Notably, the Enterprise gas discovery delivered a net 2P reserve addition of 20 million barrels of oil equivalent. I would highlight that this exploration success did mean that La Bella was reclassified from reserves to contingent resources. You recall that La Bella was an insurance policy against exploration failure that did not eventuate. Reflecting the evolving nature of our business, sales gas and ethane volumes now contribute 79% of Beach's 2P reserves. Slide 12 provides some more detail around our FY '22 guidance. As previously outlined, our production guidance sits between 21 million and 23 million barrels of oil equivalent, while capital expenditure is between $900 million and $1.1 billion. Our per barrel guidance for unit field operating cost sits between $11.50 and $12.50 per BOE. This increase is due to lower production and the increased interest in the higher-cost BassGas project. Our unit DD&A guidance is between $15.75 and $16.75 per BOE due to lower Western Flank production and impairment of the SA Otway assets. On Slide 13, you can see our production guidance is lower compared to FY '21 primarily because of lower Western Flank oil volumes. The lower production out of the Western Flank as well as BassGas and the Katnook Flank is partially offset by increased gas volumes from the Perth Basin and Victorian Otway. The uplift in Otway production is expected from mid-FY '22. In relation to the capital expenditure guidance, much of this figure relates to committed growth projects, predominantly Waitsia Stage 2 and the Victorian Otway program. In addition, we'll focus on a single rig in the Western Flank program in the Cooper Basin, comprising of an initial 7-well drilling campaign, up to 90 wells in the drilling campaign with the Cooper Basin joint venture, FEED activities for the Trefoil development and 3D seismic surveys across the onshore SA Otway Basin and the offshore Bass Basin, targeting Trefoil, Bass and White Ibis areas. I'll now hand over to Morné to run you through the financials. Morné Engelbrecht: Good morning, everyone, and thank you again for joining us today. As highlighted on Slide 15, Beach announced a statutory impact of $317 million for FY '21, which is a decrease of 37% on the previous year mainly due to the decline of Western Flank production and the recognition of $117 million of impairment relating to our South Australian onshore Otway assets. Underlying NPAT of $363 million decreased 21%, while underlying EBITDA of $953 million represented a 14% decrease. Despite the impact of lower-than-expected production during the year, Beach delivered earnings above the top end of our FY '21 EBITDA guidance provided in April. This was well supported by a favorable arbitration outcome of a contract dispute relating to the Kupe GSA, which resulted in a $50 million uplift in underlying earnings. Cash from operations delivered $760 million with stable cash flow from our fixed price CPI-linked gas business alone, delivering approximately 40% of our group revenue. We continue to boast a strong balance sheet with $48 million in net debt and a gearing of only 1.5% at the end of the financial year, which includes the $83 million settlement relating to the acquisition of the Senex Cooper Basin assets. We also announced the final dividend of $0.01 per share, fully franked, taking our full year dividend to $0.02 per share, unchanged from the previous year. Slide 16 highlights the financial performance compared to last year's results, showing that underlying NPAT and underlying EBITDA and EBITDAX include the reversal of the previous year's Kupe carbon cost, which was paid for by Beach in expense in FY '18, '19 and '20. This relates to the favorable Kupe GSA arbitration outcome, noting that these costs were treated as an underlying expense in previous years. We also note that those FY '20 financial results that have been restated due to an IFRS Interpretations Committee decision in April relating to the expensing of Software-as-a-Service setup costs. Slide 17 shows the comparison to last year's underlying NPAT. Production revenue during FY '21 was mainly due to the decline in Western Flank production, impacting our product sales and a 3% fall in realized oil price. This was offset by -- marginally by higher realized gas and ethane price. Lower cost of sales, which includes field OpEx, tariffs and tolls, royalties and third-party purchases, provided $105 million positive variance compared to FY '20. The main driver for the variance related to the $50 million reversal of carbon costs previously expensed going to the favorable Kupe GSA arbitration outcome, as previously mentioned. Tolls, tariffs and royalties were also lower due to reduced production, lower realized oil prices and lower sales volumes, with third-party purchases being 26% lower compared to FY '20 and impacted by timing of crude liftings and lower realized oil prices. Exploration expense was $57 million, which was as a result of the unsuccessful Ironbark 1 exploration well and the relinquishment of the Wherry and Barque permits in New Zealand. On Slide 18, as mentioned earlier, Beach booked $117 million noncash pretax impairment of our South Australian onshore Otway Basin assets. This was due to the reassessment of the value of further activity on the asset, with the Katnook plant expected to be mothballed during FY '22. Importantly, the assessment of the Cooper Basin cash-generating unit did not indicate the need for impairment following the reserve downgrade in April. There are a number of reasons for this, including the fact that the Western Flank oil and gas assets are combined with the Cooper Basin joint venture assets as a joint cash-generating unit. We also saw an improvement in oil and gas price outlook assumptions since FY '20 showed a positive impact, especially over the short term. It should also be noted that the Cooper Basin cash-generating unit as a whole had significant headroom to start with, has mainly absorbed the impact of the downgrade to the Western Flank reserves. Slide 19 highlights our strong cash position. As mentioned earlier, operating cash flow of $760 million was down 13% from the prior year, which included $153 million in income tax payments, adding to our franking credit balance. Extension of the federal government stimulus initiative relating to the up-front deduction for tax on certain capital works is expected to have a further positive impact on operational cash flows over the next 3 years. Previously, we noted this benefit to be in the order of $100 million to $150 million. With the extension of the time frame to 30 June 2023, we now estimate this benefit over the next 3 years to be in the region of $150 million to $250 million based on our current growth investment. Subsequent to the end of FY '21, Beach completed the acquisition of Mitsui's Bass Basin interest and also received a cash payment of $42 million relating to the previously outlined Kupe arbitration outcome. Moving to Slide 20 now. We have continued to maintain an impressive balance sheet, ending the financial year with $48 million net debt, a net gearing of 1.5% while boasting liquidity of $402 million. As Matt has mentioned already, we are pleased to report to you today that with the receipt of the cash settlement relating to the Kupe GSA dispute last week that Beach is now in a net cash position. We therefore remain well positioned to fund our growth program, executing our committed growth projects within the Otway and Perth Basins. On Slide 21, the unexpected nature of the Western Flank decline experienced during the year highlighted Beach's prudent capital management and focus on maintaining a strong balance sheet, which will allow us to withstand the adverse event and fully fund our growth. Beach remains a growth-orientated company, with the priority being reinvestment of free cash flow into our organic growth projects. Execution of these high-returning organic projects is underway with the commencement of the Otway drilling program and sanctioning of the Waitsia Stage 2 development during FY '21. Those 2 projects are expected to deliver a significant uplift in gas production to Beach, putting stable, long-life revenue generation. We will also continue to take a prudent assessment of inorganic growth opportunities as we have demonstrated in the past. On that, I will hand back to Matt to run you through markets and operating assets.

Thanks, Morné. I'll just quickly run through the current gas market dynamics that we're seeing before jumping into the asset portfolio. On Slide 23, you'll see that Beach's geographical diversity and market distribution is across 3 gas markets: Australia's East Coast gas markets, some West Coast gas markets and the New Zealand domestic gas market. These 3 markets provide for a well-diversified portfolio in 3 robust markets. In FY '22, we'll look to add another market to that fold as we contract into the global LNG market. First off, on Slide 24, you'll see a summary of the East Coast market. You've no doubt seen this slide or similar numerous times before, but it's an important one as it articulates our business strategy, investing in markets where the gas is needed. As you can see, the Australian Energy Market Operator, or AEMO, continues to see gas shortfalls within Eastern states from as early as winter 2023. This timing underscores the importance of our Victorian Otway development campaign. Our aim is to have the Otway gas plant back at full capacity by 2023 to help arrest those potential shortfalls and capitalize on the opportunity presented in the East Coast gas market. Moving to Slide 25, and you can see what will soon be Beach's newest market global LNG. Beach's entry into the LNG market is not only a significant milestone for the company, but it's also occurring at an opportune time. With supply tightness forecast between 2022 and 2025 and no new greenfield LNG supply anticipated until post 2025, Beach is well placed as we start to deliver volumes from the second half of 2023. We continue to have positive detailed discussions with customers regarding our equity share of Waitsia LNG volumes, and we're pleased with the progress, and we look forward to providing an update at the appropriate time. As always, we won't be rushed as we work through customer engagements and negotiations, and we remain focused on getting the best value for our shareholders. On Slide 26, we turn to the domestic WA market. While it does not have the supply issues in the near term, this is forecast to change from midway through the decade. With Waitsia currently approved for LNG export until 2029, more domestic gas will become available to supply the market, thus as this demand is forecast to become critical. As a company that has a long history as a domestic supplier of gas, we support supplying the domestic market at the times when the gas is needed. Changing pace a little, let's move to the asset base. Slide 28. Pretty quickly, as you can see, the FY '21 performance across our asset base. As previously noted, our production was down 4% on the previous year to 25.6 million barrels of oil equivalent. This was driven by a 22% reduction from Victoria Otway primarily due to the 28-day shutdown that we took place there, a 10% fall in Western Flank oil volumes and 7% less production in the Cooper Basin JV due to compressor downtime and natural decline. This was partially offset by a 105% increase from the Perth Basin following the tie-in of Beharra Springs Deep 1, a 34% rise in the Bass Basin because of the Mitsui asset acquisition and a 3% increase from Western Flank gas, thanks to improved Middleton facility reliability. From a capital expenditure perspective, you'll recall, at the beginning of FY '21, we took a prudent approach to our capital expenditure program to reflect the lower oil price environment and the impacts of the COVID-19 pandemic. As you can see, we delivered on this front spending $671 million in the year, a 22% reduction on FY '20. Despite this, it was an extremely active year with the commencement of the Victorian Otway drilling program in March and 64 wells drilled across the Western Flank and the Cooper Basin joint venture. Slide 29 is an important slide in the context of medium-term ambitions. This shows what is driving the growth profile of Beach. Growth is happening, and it's happening across our key production hubs. We are pursuing growth by investing in high-returning projects across the existing business. We saw this opportunity when we made the Lattice acquisition, and now these plans are being delivered upon. If you look at the 2 major assets we're currently investing in that both have targeted project IRRs of more than 20%, these represent high-quality reserves and resources close to infrastructure and markets. And therefore, they generate material returns. Both these assets will deliver long-term, stable returns, thanks to their asset lives of around 15 years or more. When you look at the combination of IRRs expected payback periods and life of the assets, this is a high-quality asset portfolio, which we are proud we've developed over recent years. Now let's take a deep dive into each of our assets, starting with the Perth Basin. On Slide 30, you can see what acts as essentially the base business of the Perth Basin. In FY '21, you saw Perth Basin deliverability increase to around 40 TJs per day, following the expansion of the Xyris production facility and the tie-in of the Beharra Springs Deep 1 well. Our FY '22 gas volumes are fully contracted, and we're pursuing further debottlenecking and plant optimization opportunities. While it's easy to focus on Waitsia Stage 2, it's important to remember we believe there are further opportunities in the Perth Basin. To that end, we're planning for exploration drilling within EP 320 likely during FY '23. Moving to Slide 31, and we are now at the pointy end of the development of Waitsia Stage 2. FY '21 was a big year for Waitsia after we secured all necessary approvals, finalized the agreements, utilized North West Shelf infrastructure and reached FID on the project. However, F '22 is set to be an even busier year, with Clough having already commenced our construction. We're also currently tendering for a drill rig with plans to drill up to 6 conventional development wells in the second half of FY '22. As previously mentioned, we've seen strong market interest for our equity LNG volumes, and good discussions continue with selected parties. We're targeting to execute a sales and purchase agreement in FY '22, and I look forward to updating the market at the right time. On Slide 32, we turn to the Western Flank where it's fair to say FY '21 was a disappointing year for that asset when compared with its previous outperformance. As previously mentioned, our review of our Western Flank oil and gas assets resulted in a 2P reserves downgrade. Notwithstanding this, Beach completed the acquisition of Senex' portfolio in March 2021, making us the sole operator of Western Flank infrastructure. This acquisition and our exiting portfolio provides Beach with prospective acreage, which is planned to be tested during the FY '22 drilling campaign. Slide 33 provides some more detail on this exploration campaign. Following a subsurface review of the Western Flank acreage, we've now recommenced drilling activities. The single-rig program aims to, one, reduce decline experienced within the existing oil fields; two, better constrain existing fields yet to be fully developed; and three, extend plateau production from the Western Flank gas fields. While the Western Flank took a hit in FY '21, it's important to remember this remains a low-cost, value-accretive asset in our portfolio. With low-cost tiebacks to existing infrastructure, development well IRRs range from 15% to more than 100%. In short, we're refocusing our efforts on exploration, and we look forward to providing more details once results come through. On Slide 34 and turning to the Cooper Basin joint venture where our strategy remains to pursue high-value, low-risk opportunities. Beach participated in 43 wells at an 84% success rate in FY '21. Furthermore, we successfully concluded a price review of our Lattice Cooper Basin GSA with Origin. This delivered favorable terms for volumes between 1 July 2021 and 30 June 2024. In FY '22, Beach plans to participate in up to 90 wells with a 4-rig program. As previously mentioned, in FY '21, Beach executed an agreement with Santos for Beach to undertake FEED activities for the proposed Moomba CCS project. We're currently conducting our FEED assurance gate reviews and readiness for a final investment decision for that project where we have a circa 33% interest. Moving to Slide 35, we move east to the Otway Basin. FY '21 marked a good start to our Otway exploration and development program. A highlight, of course, was the discovery of the nearshore enterprise gas field, which delivered net 2P reserves of 20 million barrels of oil equivalent, including 96 PJs of net sales gas. The Otway offshore drilling campaign commenced its 7-well program in March with the Artisan 1 gas discovery. The Ocean Onyx also completed drilling of the most technically challenging well of the campaign with the Geographe 4 extended reach well, with the results in line with expectations. The subsea Xmas trees were also landed at the Geographe 4 and Geographe 5 top-hole locations. Poor weather over the last few weeks has hampered our repairs to the mooring system on the Ocean Onyx. As expected, the repairs will be complete and the rig will be operational before the end of this month. From an operational perspective, it was an excellent year for the Otway gas plant, which operated at 99.3% reliability. The team also completed a 28-day statutory shutdown at the OGP in November 2021 on time and on budget. This is an even more impressive feat when you consider the state of Victoria in terms of COVID-related lockdowns in the lead-up to and during this shutdown. The fact we were able to complete the shutdown safely and successfully is a testament to the team involved, the Victorian government and the community in and around Port Campbell. Slide 36, and you can see activity continues to ramp up in FY '22 as we complete the tie-in of Geographe 4 and Geographe 5 and commence gas production around mid-FY '22. We work towards a final investment decision of the Enterprise tie-in to the Otway gas plant and also drill the 4 remaining Thylacine development wells. This suite of works in FY '22 will have us well positioned to return the Otway gas plant to circa 205 terajoules a day capacity mid-FY '23. On Slide 37, we move to the Bass Basin where we look to continue investing in East Coast gas supply and extend the life of our existing infrastructure. Following the acquisition of Mitsui's interest in the Bass Basin assets, we're progressing our plans on Trefoil where FEED activities have commenced. I'll provide some more detail on Trefoil shortly, but in relation to the existing business, we'll conduct a 3-well wireline intervention campaign at Yolla in the first half of FY '22. We'll also undertake a 28-day statutory shutdown of the Lang Lang facility in the second quarter of FY '22. On the appraisal side, we expect to conduct a Prion 3D seismic survey to improve the imaging of the Trefoil field and quantify potential of White Ibis and Bass discoveries as tie-back opportunities. Slide 38 provides a little more color on the Trefoil project, but we currently envisage potential project IRRs of more than 20% on an asset life around 15 years. The Trefoil project aims to unlock the gross 2P undeveloped reserves of 26.1 million barrels of oil equivalent, including 120 PJs of gross sales gas. We've initiated FEED activities, and we'll keep the market informed as we move through our stage gates. So to Slide 39. So we end with our Kupe gas project. We've said it before, but this is an excellent asset in the portfolio, and we're looking to continue the life of Kupe. Thanks to the efforts of our New Zealand team, we're now expecting first gas from the compressor project soon. This project aims to lift production to around 77 terajoules per day plateau until FY '24. To ensure the continued life of this asset, we're now reviewing opportunities to extend plateau production beyond FY '24, including further nearby drilling opportunities. On the commercial front, Beach has received a one-off cash payment of around NZD 42 million following a favorable arbitration outcome in relation to the carbon liability associated with the Kupe GSA. Let's go to Slide 40. So before I move to Q&A, I just want to quickly recap on some key takeaways for today. FY '21 was clearly a busy year for Beach, but we expect FY '22 to be even busier. Our gas growth program is in action, and we continue this program in a net cash position. The anticipated highlights for FY '22 include: one, the Kupe compression project coming online soon; two, completing the drilling and connection of the Geographe wells, with first production expected from these wells in the middle of this financial year; three, drilling of the 4 Thylacine wells as we move towards production from these wells in FY '23; four, Waitsia construction ramping up and the drilling of the relevant production wells as we move towards first gas in the second half of calendar year 2023; five, implementing our single-rig Western Flank drilling program; six, reaching FID on the Enterprise project as we move towards delivering first gas by the end of FY '23; and finally, seven, targeting FID on the Moomba CCS project in this financial year. And with that, let's open up the lines for your questions.

[Operator Instructions] Our first question is from Dale Koenders of Barrenjoey.

I was hoping you could provide a little bit more color on the Western Flank production outlook. The guidance into 3.5 million barrel of oil equivalent dropped year-on-year. However, considering a full year of production from the acquisitions, half year of Geographe production, et cetera, it looks like it's more like size and then BOE dropped on a like-for-like basis. It looks like Western Flank is really the key issue, which is inferring something like a 50% production decline. Is it the right outlook? And is this kind of the end of these production levels in the Western Flank unless you find another Bauer?

Yes. Thanks, Dale, and welcome back. The -- I think you're around the mark on those numbers. So in terms of production at the moment on Western Flank, we're running at about 12,000 barrels a day at the moment, and we're seeing decline rates. Obviously, they're different well by well and field by field that we're seeing general decline rates at about 15% to 20% per quarter at the moment. Now clearly, we're getting the rig back out there at the moment. So you'll see us drill, I think, circa 4 Western Flank gas wells, about 4 Western Flank oil development wells, 3 appraisal wells on the oil front. And then the key really is our exploration program. Now we've got the ability to turn this rig on and off. But if we're successful, we may drill up to 15 wells from an exploration perspective out there. So you're right, a lot of it is really premised at the moment on how the exploration program performs over the coming year. And in terms of the production outlook, there's pretty modest volumes that are included from the development drilling. Circa 7% of the volumes for next year are -- for this year, I should say, are predicted from the development drilling. So exploration is a game really in terms of turning the Western Flank around you're on.

Can you give us a feel for some of those exploration targets over the next 12 months? Is there anything that could be Bauer alike? Or are these more typical smaller sort of 0.5 million barrel oil pools?

Yes. Sam, you might want to make a comment on that. So I'll let Sam Algar maybe touch on that for you. Sam?

Sure. Yes. So I think the first thing to note is that we have a lot of opportunities, which we are working through and ranking. And then maybe the second thing to note is that when Bauer was discovered, it was perceived to be a very small field. And through further appraisal, it obviously got a lot larger. So there's a fair number of unknowns. We're applying some new technologies and new approaches, and so time will tell. And I think to find another Bauer would be very impressive, and smaller volumes are extremely commercial. So our focus is on creating value in the Western Flank. And once we've prioritized the program and put that forward, we'll see what we find.

But obviously, we'd love to find another Bauer there, but we're not prepared to predict it. It's certainly not the case.

Our next question is from Max Vickerson of Morgans.

Just wanted to ask about -- look, I appreciate you probably can't say pretty much, but just on the commercialization strategy for the fully utilized Otway plant. Are you leaning more towards fixed price contracts? Or should we think you might have more of an oil-linked pricing structure? What's the market looking like at the moment?

For the Otway, Max, we're generally pretty fully contracted at the moment, so -- and committed, obviously, in terms of our development and producing fields to produce into Origin contracts. Obviously, you'd be well aware of our price renegotiations with Origin through the course of the year, which we're pleased with. But from a spot market perspective, if that's what you're thinking about, which has obviously peaked in recent months, we don't have a lot of swing factor to be able to play into the spot market. I think one of the keys, however, is in terms of our exploration success of our Enterprise, then we have the ability to market that more broadly. And at the time that we're marketing, Enterprise volumes will give good consideration to how much of that goes to fixed price contracts and how much is held back for spot or other mechanisms. But generally, if you're thinking about the Otway, you should be thinking about the production and development wells going into the existing Origin contracts.

Okay. So you won't have any spare capacity once you've filled those contracts that's all in the plant, but still, would there still be some uncontracted volumes?

Yes, it needs to be coming out of our exploration fields, basically. So Enterprise is the key in terms of being able to market more broadly outside of our prevailing Origin contracts.

Our next question is from Adam Martin of Morgan Stanley.

Just on production cost guidance, up 15% to 20% or so, I presume majority of that's Western Flank production coming down. But are there any other assets where costs are rising?

Sorry, Adam, you mean in terms of operating costs?

Yes, I guess.

Yes. So look, just in terms of operating costs, yes, it's obviously impacted significantly by the reduction in Western Flank production. Also, there's a re-weighting happening across the portfolio with our increased equity interest in BassGas. BassGas is our highest cost producer, but there's a re-weighting of the portfolio, obviously, taking place post the Mitsui acquisition. So they are the 2 key factors that are driving the unit operating cost increase.

Okay. And second question, Beach is obviously new to LNG marketing. You've -- 12 months or so into that process. Can you talk about what you've learned during that process, anything you -- given you are new to that business, please?

Yes. I think it's a good question. Look, we're new as a company to that business, but we've got a lot of people who've done a lot of LNG and myself included. And we've had a specific LNG marketing team in place now for more than 2 years, and they've been active, particularly post FID, which is the best time, of course, to be able to market. And one thing I can tell you, as I mentioned earlier, is if you look at the timing that we're coming into the market, it's an opportune time in terms of the window we're coming to. I think the best example of that is we've had proposals come to us from more than a dozen customers, right? So that's part of the reason we're taking a little bit of time here is there's a lot of people wanting to talk to us and wanting to put proposals on the table. So there's a lot of proposals we're working through right now. We're obviously working through all of the elements in relation to risk allocation and also in terms of what we're going to be linked to. And I suspect at the moment, the most likely outcome is we'll be partially linked to JCC and partially linked to JKM. I think that's probably where we'll end up. That's where discussions are leading from our perspective. But it's fair to say at the moment, when you've got more than a dozen customers wanting to talk to you, you've got a fair bit of flexibility from a seller's perspective. And of course, we're absolutely leveraging fantastic reputation that North West Shelf offtake and lifting has.

Our next question is from Nik Burns of Jarden Australia.

Just firstly, on emissions, well done on joining the net zero by 2050 club. Just a couple of questions on this. First of all, Moomba CCS, Santos, I think, is calling the project FEED ready, but you're saying you're entering FEED there. How should we reconcile those 2 statements?

Yes. Thanks, Nik. I think the best way to think about it is Santos is obviously operator, which we've clearly fully support, which means they're slightly ahead of the curve from our perspective in terms of their time line and where they've been running. We're well down the path on FEED, and the aim of our process is to be FEED ready in line with them when the FEED moment comes. And I think we're getting pretty close to that now, and we're not seeing any showstoppers. So at the moment, what we're seeing is we're fully supportive of the operator, really pleased with the way they're progressing the project, and we're putting a lot of effort into our own technical assurance on the project itself and obviously on all the commercial and government elements as well, but fully supporting Santos is the answer. But that just means we're shadowing because we're the non-op.

Okay. And then just in terms of your emissions reporting, any plans on moving from gross operated emissions to equity share?

Yes. We do look and track both metrics, Nik. From our perspective, obviously, our current disclosures are predominantly related to our operated share. I mean we're tracking what others are doing in the market. It's a bit of a mixed feast at the moment as to who's reporting against which metrics. So it's something we're definitely looking at, and I think probably you have a read of our sustainability report when it comes out in the next week, and we can circle back on some of those issues with you if you want.

That would be great. Look, just on Bass Basin, you've got planned 3D seismic this year and you're also now in FEED for Trefoil. Just wondering, is there a time to get results from the seismic to influence plans for Trefoil given potentially you could be finding additional volumes in some of the discovered fields there? Or it will mainly tie into plan for future opportunities to tie back those fields to Trefoil?

It's designed to do both, Nik, but I might let Sam give you the better answer on that.

Yes, exactly. So we'll certainly have the results from the Trefoil acquisition in time for the FID decision. But you're right that in addition, we will be covering the White Ibis and Bass discoveries, and we'll be obviously looking to interpret that quickly and get a good feel for the potential of those as further tie-ins. So that will be coming very soon, hopefully, also before FID for Trefoil.

All right. And just on the equity share of Trefoil, I think you're over 90% following the Mitsui acquisition. What's your plan around that? Are you comfortable taking a 90% interest through FEED FID? Or are you thinking you might bring a partner in at some point?

I think it's a good question, Nik. I think if you look at the strength of our balance sheet and the strength of our cash flows from the gas business, we have the capability of doing either. So both options are on the table. We'll progress through FEED towards FID. There have been other parties historically who wanted to talk to us about our portfolios, of course. So we'll reassess as we get closer to FID, make a decision at that point to see how the market is playing out, see how our balance sheet is playing out and see what interest is out there as well. But certainly, from the strength of the balance sheet, we have -- we can turn left or right, which is an advantage.

Our next question is from Saul Kavonic of Crédit Suisse.

I have a quick question on CapEx guidance for next year, $0.9 billion to $1.1 billion. If I refer to the CapEx guidance which you provided in August last year, you kind of provided that shaded bar where very top of that bar was $1 billion, whereas now $1 billion seems to be the midpoint case to next year. And I guess I would have thought if anything, CapEx should come down next year since given what's happened with Western Flank, you're not throwing on the second rig and so on. What am I missing here? I guess, why does it appear that CapEx guidance has gone up versus what was provided in August for FY '22?

It's a good question. So it's a buildup of multiple issues. Frankly, obviously, one is timing of Otway drilling is a few months later than we initially planned. So there's a little bit of slippage from '21 into '22, which is part of the reason why we were under on FY '21. So there's a little bit of a rollover effect there. You've also now have Moomba CCS included, which wasn't previously included. We've got Santos running a fourth rig, which we support in Cooper Basin joint venture, which wasn't planned back at the time of that earlier forecast. And you've got Trefoil in FEED with a higher equity share, obviously, post the acquisition of Mitsui's interest, and also you've got some CapEx flowing through from the Senex acquisition. So it's 5 or 6 factors. It's not one big lump sum. So it's not a big issue that we had missed. It's basically just a change of circumstance on those 4 or 5 issues that when you add them up together gets you to that midpoint, which is relative to the higher end previously.

Our next question is from Mark Wiseman of Macquarie.

Just 2 questions. Firstly, previously, you had given a number on sort of gearing through the cycle. I was just wondering if you're willing to comment on where you think gearing is going to peak based on where we are today.

Morné, do you want to have a... Morné Engelbrecht: Yes. Thanks, Mark. I mean in terms of how we look at it, obviously, we still feel very comfortable with that comment we made previously in the market, especially in terms of where we're sitting today in a net cash position and, obviously, sitting on more than $400 million of liquidity as well and with the stronger outlook on oil and, obviously, the good outcomes on the gas arbitration as well that all fits into our thinking around that. So no change on that.

Okay. Fantastic. And just on the Perth Basin, could I just ask, from your map, it looks like you've got 3 pretty large prospects South, Southeast of Beharra Springs Deep. Are you able to just comment on how large these prospects are? And I appreciate the drilling is not until FY '23, but do you have an idea of how many you would expect to drill in?

Yes. And look, they're attractive prospects, no doubt. And I think as we've spoken about before, one of the issues for us strategically has been with the thinking around are we resource constrained or market constrained in the Perth Basin, and it's a bit of a chicken and egg situation. But certainly, our focus right now is executing on Waitsia during the Waitsia development drilling and bringing Waitsia to the market. And obviously, we've expanded on the domestic gas play there as well. So we haven't felt the need to go and drill those exploration opportunities too early in the cycle. But certainly, we have them there and they're attractive. And as I said, we do expect to have some exploration drilling in FY '23. I don't think we want to say too much more predrill on size, Sam, unless there's anything you wanted to add to that. But as you've seen from drilling experience in the Kingia, it's a pretty prolific play, and we're looking forward to getting out there and exploration drilling again.

I think the only thing I'd add to that, Matt, would be that we've got good alignment between ourselves and Mitsui. Both recognize the value of our portfolio here and very keen to hit off drilling in EP 320, but also we're looking at other wells in the other blocks, including those that Mitsui operates. It's a very strong portfolio and it's just a question of prioritizing which wells and how many we do in FY '23.

I would just say and add to that, probably just on other questions as well. We've obviously got an Investor Day coming up as well on the 28th of September, you might want to schedule into your diaries. And some of those questions like the one that was just asked in relation to the future of the Perth Basin, I think we'll address in a more fulsome way at that Investor Day.

Our next question is from Daniel Butcher of CLSA.

Just a couple of quick ones from me, actually. Just curious if you give us some guidance on when Otway brings on Geographe and so forth. Mid-FY '22 or in FY '22, what sort of exit run rate are you assuming for that?

Yes. I think probably best off following the flow in the pack of the timing of when the Geographe and Thylacine wells come on, and we haven't guided well by well at this point in time. But I think if you look at also the growth project, right then, you'll see what we think the total increment is from the Otway program and the total incremental production is when Waitsia is on as well. That will give you a reasonable outlook. I think it's probably something you might want to sit down and talk through the details with Chris off-line because one thing you need to keep an eye on in your modeling is seasonal variation in the Victorian market as well. So that's why I'm a bit reluctant to quote a set number because you have to take account of the seasonal variations, but happy to have the conversation in more detail off-line with you.

Sure. Okay. Another one is quite simple. There's a lot of talk in the market about a rumor deal with BHP Petroleum and Woodside. If any of their stakes because they're noncore like, say, matters or something like that, would you be interested in having got that?

Yes, I wouldn't comment on any specific asset. But look, we're always active. As we've said many, many times in the last 5 years in the M&A market, we're always hunting. We're always looking. We're looking at bolt-ons. We're looking at what we can add to the portfolio. A lot of times, we're looking at assets, making sure they haven't changed. And if we don't want to touch them, confirming that we don't want to touch them. We're always in routine dialogue with other companies in the sector around their portfolios. We don't feel any desperate need whatsoever at the moment to undertake M&A. Frankly, we've got a really good portfolio under our belt. We've got a lot of really good development prospects that we're executing on as well. I'd also flag that it always depends on the cycle and other things as well. And if you think about where we sit on oil prices at the moment, you think of where we sit on the cost of money from an interest rate perspective, certainly feels like more of a seller's market than a buyer's market right now. But look, we're always active. But as you know, we set some pretty harsh metrics for ourselves that we have to hit on any M&A.

Our next question is from Mark Samter of MST.

Actually, I might just start with a question on what you just said, Matt, and I think you're the first person I've heard say a seller's market, not a buyer's market, given the inability of so much of the industry to participate in M&A. I mean on that basis, would you be looking at asset sales yourself if -- you sound like you're pretty well ruling out any M&A -- outbound M&A?

No. I wouldn't say I'm quite ruling out M&A, Mark. Like I said, we're always looking, we're always hunting. But from our perspective, we'd love to buy assets at the right -- or companies at the right time in the cycle and at the right values. So we're not going to do M&A just for the sake of news flow or anything of that nature. It needs to have a genuine shareholder value associated with it. And that's obviously more challenging when the boats are riding high on oil prices and low interest rates. So we're certainly hunting. Do I think we're a seller of assets? No, I don't really think so. We've got a really cracking portfolio that we've brought together here over the last few years, which has, as we've said, high returns infrastructure. We operate 2/3 of our portfolio. We're actually really pleased with the composition of the assets that we brought together. So other than potential farm-downs where we have high equity interest, I doubt very much that you'd see us in sell-down mode.

Then just I'm curious to get a bit more clarity on the La Bella declassification. And particularly, in the comment, I know you said, obviously, things have changed with the discovery in the Otway, but I look at your reserve booking and cash and carried away to the reserves for a couple of years before you even FID the project. There's a route to market for La Bella gas, even if it's slightly more delayed than you potentially had depending on our exploration success. So nothing to do with the economic as in you think in 2 years' time, this is going to get rebooked as reserves? Or...

Yes. Yes, potentially, obviously, I'm not going to forecast what may or may not happen in 2 or 3 years' time because a lot of things can change between now and then. Now I think it's also important to recognize the difference between PRMS and SEC rulings. Obviously, all of the bookings that we've done previously and continue to do follow PRMS. They're all signed off by our external auditor and go through a rigorous internal assurance process and through our Board as well. So we're very comfortable with our booking process that's taken place historically on La Bella. La Bella was seen as earlier in the sequence previously. Now that we've had substantial exploration success in the Otway Basin, particularly at Enterprise, that means that La Bella being a further offshore field will bring the cheaper cost gas on first, lower unit technical cost on first. So that means La Bella gets pushed out a little bit. So we still see it as being commercial, yes. We still see it as coming through the Otway gas plant at some point, yes, just not as soon as it was previously planned if we'd had exploration failure. So that's the reason for the debooking.

Okay. And then just one more question just on Western Flank oil. This isn't a rhetorical question because there's every chance it's just my math failing me. But I think when you strip out SACB JV and take away the acquired production from Senex, we're talking about core Western Flank are doing less than 10,000 barrels a day. Can you confirm whether actually expectations have deteriorated further since you gave the update at the end of April? And I'm particularly cognizant of, for example, I think Cooper Energy care about 25% less for their reserves and albeit a small part of the Western Flank that they share with you. Is there any further risk on reserves? Or is this all running as you expected at the time of that business update?

Yes. No, look, what we're seeing is we're running predominantly as we expect at the time of the business update. Obviously, as always, we've got multiple wells and multiple fields running out there, and we're getting daily data that we're taking account of in terms of field performance. So we've got to watch the field performance closely. But there's nothing there that we need to disclose at this point in terms of field performance or reserves. Obviously, we'll work through how the drilling program goes over the next 6 months or so and then update the market, obviously, quarterly along the way on drilling performance and production performance. And if there's anything material to disclose, we'll disclose it. That's the way we'll move. But Sam, did you want to add anything?

I think you covered that well, Matt.

I'm also taking one really very quick question. Last one if I can. My phone dropped out earlier, so I apologize if this was covered. I mean, I think backing it out, obviously, there's a lot less disclosure on production guidance now, but it looks like you haven't really got gas growing much FY '22 on FY '21, which, again, when we're trying to unpick the historic 5-year guidance, I suspect you probably had gas growing and particularly in Otway through this year. Has there been any downgrade of gas ramp-up through FY '22?

It's not a downgrade, Mark, as such. Obviously, you've got natural decline at Bass. You've got the OGP coming on, but probably 3 months or so later than what we were talking about a couple of years ago in terms of sequencing. And part of that was obviously COVID delays and rig delays, et cetera. So from our perspective, in the next 6 months, that's probably what you're seeing is the next field decline taking place. But I think you need to think beyond that and think about what's happening in '22 and '23. And if you look at our growth project slide, that's when you really start to see the impact of the Geographe and Thylacine wells coming in, refilling the Otway gas plant. And then obviously, by the end of -- or back half of 2023, bringing Waitsia up. So the growth is absolutely happening and coming. We're executing right now, but you're right, in the next sort of 6 months or so, we don't have substantial new gas coming in through Perth Basin and all the Otway.

Our next question is from Gordon Ramsay of RBC Capital Markets.

Matt, just on your LNG contracts you expect to sign in FY '22, you get an indication of pricing mechanisms. What about volume? Compared to your total volume that you've got available, how much would you like to sign?

I think the way you'll see it play out, Gordon, is that we'll end up signing the totality of our volume and likely with 1 or possibly 2 but likely with 1 customer. Given the volumes that we have are relatively modest from an LNG perspective, you've got to watch, obviously, the lifting portfolio and the cargoes. So for us, it looks like much likely we'll end up putting the total volume away and probably put the total volume away with one customer.

Okay. That's good. And just secondly, more a strategy question. Kind of longer term, looking at the company, you've got growth and basically gas asset. And Western Flank, obviously, you're doing your best to arrest decline there. From a strategic viewpoint, if you're looking at inorganic growth, would you have a preference for oil over gas, if you were to go down that path? Do you think the portfolio is too low in gas now going forward?

It's the perennial question, isn't it, Gordon? And I think I'll give the same answer that I've given for the last 5 years, which is we're focused on value and where we're going to make the most money for shareholders. And whether that be oil or gas, I mean, as we know, if you're focused on Australia as we are, we're far more gassy as a country than oily. So from our perspective, growth generally comes from the gas area in Australia more so than the oil space. And look, we won't go and acquire an asset just to say we're more oily and overpay. That's just not the way we painted with our stripes. It's all about value. So from our perspective, we're not driven that we must have X percent of oil or Y percent of oil. It's really a focus on what's the best way to create value for the shareholders. I've got to say there's a lot of investors we talked to, particularly globally, who are very happy that we're becoming more gassy in terms of on our emissions profile, but also to the sustainability questions that are coming at us and also the longevity of the profile of cash-wise.

Our next question is from Baden Moore of Goldman Sachs.

Just one of your smaller assets in Kupe, I was interested if you could just talk us through what you've achieved in the arbitration to yield the $50 million. And just as we think about the New Zealand market, which is quite tight energy at the moment, is there any pricing upside once the asset comes online in FY '22 that we should be thinking about versus historic gas pricing? And just one follow-up question as well on the result. It was a bit of a beat versus our numbers. I was wondering, did you have any leverage to the spot gas volatility that we saw through the last quarter and any volume that you could link to that?

Yes, good question. I might start with the last one first. Look, most of our gas, as we've said previously, is fully contracted on term contract. So we have a limited availability to play spot. Where we normally do that, it's out of the Cooper Basin. We have put some volumes into the spot market through the Cooper during that uptick but relatively modest volumes compared to our portfolio. But one advantage we do have, however, when you do see the spot market take off as it did for a period is you tend to see our offtake increase. So that means that our customers are keen to take as much gas as they possibly can so that they can play the gas further downstream. So that's a benefit when you see the spot market take off as it just did. In terms of Kupe, that really fundamentally relates to the allocation of the liability for carbon, which we were paying for but challenged through arbitration and was successful, which means we've had to be repaid. $42 million already received New Zealand from Genesis. That means the future liability sits with Genesis as well. But Morné, I don't know if you want to touch on that from an accounting perspective. Morné Engelbrecht: Yes. No, thanks, Matt. So in terms of how we account for it, there's obviously an underlying reversal of those carbon costs to be accrued for FY '21, which is about $10 million. And then there's previously carbon costs to be paid in '18, '19, '20, which is about $40 million. That's why you're seeing an underlying increase in earnings of $50 million relating to that. So there's -- and obviously, that's had a positive impact on our NPAT as well, improving that by about $42 million after tax.

And just your other question on Kupe, on price upside, we're getting a pretty solid price out there already. We're also seeing strong offtake as well. So I think we'll continue to see strong offtake over time given the lack of new projects and new developments in the resources space in New Zealand. But the uptick in terms of potential price upside is still a couple of years away for us, further upside. But we're already receiving a very strong gas price there as well.

There are no further questions at this time. I'd like to hand the call back to Mr. Kay for closing comments.

Appreciate your time, everyone. I know there's a lot of information that we've just deluged you with as always. So please feel free to reach out to Chris in the first instance for any follow-up, and obviously, very pleased to have any calls with you that we can to help. And keep in mind, please, the Investor Day is coming up on the 28th of September when we can delve further into the assets and some of those more strategic issues as well about the future of Beach. I appreciate your time. Thanks, everyone.