Beach Energy Limited

Thank you for standing by and welcome to the Beach Energy Limited FY22 full year results conference call. All participants are in the listen only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by number one on your telephone keypad. I would now like to hand the conference over to Mr. Mone Engelbrecht, Chief Executive Officer. Please go ahead.

Good morning and welcome to the FY22 full year results presentation for Beach Energy. My name is Morne Engelbrecht and I'm the Chief Executive Officer of Beach. Joining me on the webcast today is our Chief Financial Officer Anne-Marie Barbaro and other members of the Beach Executive Team. For today's presentation I will first provide an overview of our results and progress for the year. Then I'll be over to Anne-Marie to run through the financials and then I'll provide an update on sustainability, our markets, and the outlook for FY23 and beyond. Following that, we will open the lines for Q&A. Before we commence, slide two includes our disclaimer, price assumptions, as well as information regarding our reserves disclosure. We will leave this with you to read in your own time. Our key message for today is that FY23 is the year of focused project execution as we deliver the foundation for growth in FY24 and beyond. For FY22, we delivered a strong set of financial results, and delivered on major project milestones. Operationally, albeit production was lower, key project milestones were delivered against a challenging backdrop of COVID, adverse weather events, labor shortages, and international supply chain pressures. Financially, the increase in demand and focus on energy security strengthened the market prices, supporting the growth in our earnings and cash flows. As this slide conveys, not so subtly, we are focused on delivering on our growth objectives. We are focused on growing our gas supply from each of our assets and materially from the Oxfam per person in particular. Growing our exposure to key gas markets, including expanding our share of the East Coast gas market and entering the international LNG markets. Growing our free cash flow and financial strength and growing our business sustainably. We are committed to the emissions reduction journey. To this end, I'm very excited to announce today our new emissions intensity reduction target. We're targeting a 35% reduction in our net equity emissions intensity by 2030. More about this later. Turning to progress in the field on slide four, it was a very productive year for BEACH with several highlights and milestones, and in particular, demonstrated our ability for delivering complex projects. The delivery of the biggest offshore drilling program in Beech and the Otway Basin's history was a clear highlight. The drilling campaign was completed safely and successfully with the campaign yielding one gas discovery and six development wells with an increase in reserves to boot. The first two development wells were connected to the Otway gas plant which supported a 47% increase in Otway Basin production. In the onshore part of the Otway, we also took a final investment decision for connection of enterprise discovery to the Otway gas plant. In the west, the transformational weight CSH2 project commenced with good progress made, the gas plant construction on the way, three of the six development wells drilled, and the LNG sale and purchase agreement with BP now also finalized and signed. Slide five summarizes a strong set of financial results. While production was lower than last year, we did progress our major growth projects to start lifting our production to key oil, liquids, gas and energy markets. We are reporting material improvements in earnings and free cash flow before major project capex with revenue from our operations hitting an all-time high. Results demonstrate the benefit of Beecher's diverse asset portfolio and strong leverage to commodity prices. We also ended the year in a net cash position with liquidity of $760 million, and this is after our biggest CapEx year on record as well. The board declared a one-tenth final dividend with our current focus remaining on prudent balance sheet management as we deliver on our major growth projects. Turning to slide six, which summarizes our FY23 activity, our overarching objectives are clear and aligned with our strategy. In FY23, there will be much focus on completing the bulk of the work programs in Otway and Perth basins. We're also very focused on maximizing plant output and extending asset lives through ongoing work over and optimization activities. Looking beyond project delivery, we will continue planning for FY23 drilling in the Bass and Taranaki basins to bring gas plants back to capacity rates. Exploration efforts will continue across the portfolio to drive longer-term growth and potential facility expansions with Perth Basin Exploration Drilling to commence in FY23 and Otmey Basin Drilling Plan for FY24-25. As we grow, we do so sustainably with the progression of the globally significant Moonburst CCS project. East Coast and West Coast acreage is integral to our growth aspirations. Flight 7 touches on the East Coast Gas supply challenges have been well documented and the market fundamentals are attractive for BEACH. Our objective is to support the market through developing new resources of gas supply and have been investing to do so. The chart on this slide highlights our East Coast contracted and uncontracted gas exposure over the coming years. As existing contracts roll off and new enterprise and thylacine volumes come online, uncontracted gas volumes grow and coincides with already tight market fundamentals. We are therefore well positioned to realize our gas growth and play our part in providing energy security for decades to come. Slide eight summarizes an exciting milestone which we announced last week, the signing of the LNG sale and purchase agreement with BP. This is a highly valuable contract which will provide a material revenue stream to BEACH over its five-year term. In summary, BP has committed to buying all of Beecher's share of waste energy volumes up to 3.7 million tons. With this into context, this is equivalent to roughly 200 million MMBTU of the SBA in line with the type of contract you would expect us to enter into considering the current backdrop of the market. Pricing is based off a mix of JKM and Brent linkage with full upside exposure and also leverages BP's leading LNG shipping capability and cost structure. We also have downside price protection, which in itself delivers a commercial rate of return on our own investment. Beyond pricing, the SPA contains terms, conditions, such as flexibility to align first LNG sales with weightier stage 2 commissioning. We are very excited to have BP as a long-term partner and look forward to delivering our first LNG cargo. Slide 9 is important as it highlights our target production of up to 28 million barrels of oil equivalent by FY24. Although we maintain our target, we note that this is dependent on the successful delivery of our major projects being on time and without any adverse or unseen events. The main drivers for reaching the target can be summarized as follows. Overall, it assumes performance in line with forecasts for all of our current assets, including production remaining flat in the Cooper Basin. In the Otway Basin, it assumes production will benefit from the greater well deliverability from the start of the FY24 year from the thylacine and enterprise wells. Customer nominations for the AGP is also assumed to be in line with a full well deliverability and therefore above take-up pay levels. And in the Perth Basin, we are targeting steady production before first gas from the wait-year stage 2 expected in the second half of calendar 2023. Turning now to slide 10, which summarizes reserves and resources movements during the year. Reserve additions this year was challenging while development projects were progressing with a lack of exploration in FY22 outside of the Cooper Basin. This is a key issue which we'll be addressing in FY23 and 24. The decline in reserves was mainly driven by production and reclassification of Bass Basin reserves as we flagged in May. In the Cooper Basin, revisions were due to outcomes from work programs during FY22, including poorer than expected fracture stimulation results in the Balgon field and infill drilling at the Caledina field and production performance at Bauer. At Bauer, production was underperforming due to higher than expected water influx from the Namur to the McKinley Reservoir. This was remediated by reinstating the water producers to cool water away from McKinley. This has improved production performance, but not yet corrected it completely. We are committed to growing our reserve space with the Perth Basin Exploration Program commencing later this year, being the next major catalyst for reserve additions. We're also announcing our inaugural Cooper Basin Carbon Storage Reserve. I'll finish this first section with health and safety and environment on slide 11. Recorded pleasing outcomes this year, particularly given it was a year of record hours worked across the organization, more than 3.3 million hours. Highlights included a number of safety awards, extended injury-free periods, and significant reduction in spills. We maintain our focus on continued improvement, and I thank all of our people for their dedication, demonstrating through action that safety does take precedence in everything we do. I'll now hand over to Anne-Marie to talk through the financial results. Anne-Marie.

Thanks, Mornay. Good morning, everyone, and thank you again for joining us today. I have the pleasure of speaking to you today to provide an update on a strong set of financial results for FY22. Turning to slide 13, and as Mornay has already highlighted, BEACH ended FY22 in a strengthened financial position setting us up well to deliver our growth projects in FY23 and beyond. Beach reported operating cash flow of $1.2 billion with $752 million free cash flow pre-growth expenditure. We are fully funded to deliver the growth agenda for FY23 with a liquidity of $765 million at year-end, and we are targeting a net cash position throughout FY23. Our results this year again demonstrate capital management discipline, which is particularly important during periods of heightened capital expenditure. As we complete our current major growth projects, we target growth in free cash flow in FY24. Slide 14 sets the scene with our production figures for FY22. This year we produced 21.8 million barrels of oil equivalent, which was in line with guidance. We have diversity of production from five basins and our gas to liquid split is now 65% to 35% respectively. Slide 15 highlights a strong set of financial results which demonstrate the benefit of BEACH's diversified portfolio and diversified exposure to energy prices. Cash from operations jumped 61% to $1.2 billion with stable cash flows from our fixed price CPI-linked gas contracts which delivered approximately 31% of total revenue. Meanwhile, unhedged exposure to oil and liquids underpinned the material increase to revenue. We announced an underlying net profit after tax of $504 million, up 39% on the previous year, and underlying EBITDA of 1.1 billion, up 17% on FY21. We announced a final dividend of one cent per share, fully franked, While we complete our major growth projects, we consider it prudent to not increase the dividend for this period. Slide 16 shows the comparison of FY22 underlying NPAT to FY21. The 15% rise in revenue during FY22 was primarily driven by a 79% increase in the realised oil price. Reduced depreciation is the result of lower production volumes. and lower exploration expense is the result of FY22 exploration activities being capitalised in accordance with our area of interest policy. The increase in cash costs was primarily driven by a 56% increase in royalties and a 45% increase in third-party purchases, both driven by increased commodity prices. Tariffs and tolls were 24% higher than FY21 driven by the successful arbitration outcome in relation to carbon recognised in FY21. Restoration expenditure of $30 million reflects the increase to restoration provisions in relation to assets in abandonment phase in the Cooper Basin. Slide 17 highlights our strong cash position with cash reserves of $255 million at the end of FY22. As mentioned earlier, operating cash flow of $1.2 billion was up 61% on FY21. This cash flow included $110 million of income tax paid and a $42 million receipt for settlement of the carbon tax arbitration. Our free cash flow pre-major growth expenditure was $752 million. Turning to slide 18 and you can see our balance sheet remains in great shape with a net cash position of $165 million at the end of the year and total liquidity of $765 million. During the year, we successfully refinanced our debt facility and upsized it to $600 million with improved terms and margins achieved. This means we're well positioned to fund our future growth strategy, including the committed capital for the connection of the thylacine wells and enterprise discovery in the Otway Basin, Waitier Stage 2 plant construction and development drilling, and Moomba CCS. FY23 will be a capital-intensive year, which will see the bulk of the work programs for our major growth projects completed. This sets the foundation for targeted growth in production and cash flow in FY24, which has been our clear focus over recent years. With that, I'll hand back to Mornay.

Thank you, Anne-Marie. I'll now turn to sustainability on slide 20. The highlights this year include our community involvement, including sponsorships, volunteering and training. and the announcement of our new Emissions Intensity Reduction target. A highlight for me is the number of volunteering hours given by our staff to great causes within the communities in which we operate, with almost 1,000 hours being donated in time. This includes volunteering at organisations like Habitat for Humanity, Foodbank and Clean Up Australia. Also very excited about a new partnership with Deakin University's Blue Carbon Lab. This involves trialling a new technology that assists the recovery of coastal wetlands, which we know are excellent for carbon sequestration. Our 2022 Sustainability Report was also released today, which I encourage you to review. Turning to slide 21, the environment we operate in is clearly very important, and BEACS is committed to the emissions reduction journey. That is why we are targeting a 35% reduction in emissions intensity by 2030. This is relative to 2018 levels when the lattice assets were acquired. This target takes into account all of all assets in the portfolio, not just our operated assets. We're already making progress towards this target with the emissions reduction project on the way across the operations, including Wimber CCS. Also pleasing to note that more than 90% of our customers have a 2015 net zero carbon emissions target. FY22 summarizes the exciting Moombaugh CCS project, a globally significant project. Taking the FID from Moombaugh CCS was another key achievement in FY22. We are firm believers that CCS will be critical for sustainable gas production and for the world to reach net zero, with the Cooper Basin depleted reservoirs making it ideal for CCS. We will initially be targeting up to 1.7 million tons of gross of CO2 injection annually, with our share being roughly 500,000 tonnes per annum. We are progressing well with the operator as we target first CO2 injection in 2024. I'll touch briefly now on our key markets. By 2024 summarises the five key markets which there's exposure to, supply gas to the East Coast, West Coast and New Zealand markets, oil and liquids to global markets and we'll soon be supplying energy to the global market as well. Each market displays attractive fundamentals with tightening supply and demand outlooks. Current themes of energy security and increasing demand have seen elevated commodity prices over the past year. Higher cost of capital and lack of stable investment policy have led to underinvestment over recent years. Accenture added current supply issues, which further supports our material investment and new gas resources. East Coast gas market dynamics are set out in slide 25, many of which I've already mentioned. Recent market studies continue to be concerned with sufficiency of gas supply to the East Coast and increasing prices with the lack of coal-fired power generation and renewables not being able to fill the gap. Those have been reflected in significant increases in spot gas prices this winter. As stated in the slide, the ACCC is concerned the higher spot prices will flow through to term contract prices. This is already evident, as shown here on the ACCC chart. A similar story in the West, as set up in slide 26. Existing supply sources are decreasing, and new demand sources are emerging, leading to tightening supply-demand outlook. Again, it's a similar story for a global LNG market, as set up in slide 27. LNG supply and pricing has attracted a lot of attention of late. The Ukraine situation and decreasing gas flow from Russia have led to increasing energy security concerns globally and heightened the demand for LNG, particularly in Europe. A similar story of underinvestment over recent years has also exacerbated the current elevated prices. There have been significant increases in LNG spot and future prices this year, as shown in the forward curves on the slide. I'll finish now with the outlook for FY23 and beyond. Slide 29 summarises our FY23 guidance. As I mentioned earlier, FY23 will continue our momentum from 22 as we focus on executing major growth projects. Capital expenditure is expected to be of a similar order to FY22, a slight change to composition reflects the progress made with our major projects, particularly in the Otway Basin. Also have additional spent on the Cooper Basin JV from Wimbledon CCS and an additional rig and optimization activities. 530 provides more detail on our underlying guidance assumptions. Basin by basin, the production path for FY23 is straightforward. In the Oathway Basin, production will benefit from recent connection of Geograph 4 and 5. Greater well deliverability will not occur until the thylacine wells are connected. We have not assumed any incremental production from phyllocene or enterprise in FY23. Outway basin production will also depend on customer nominations, which can be difficult to forecast. A base case therefore implies a slight increase in outway basin production in FY23. It should also be noted that the outway gas plant will be down for approximately three to four weeks for well connections and maintenance. In the Cooper basin, we are undertaking active work programs which provide the confidence to target flat production for both the Western Flank and the Cooper Basin JV. In the Bass and Taranaki Basins, there will be no drilling until FY24, thus natural field decline in the order of 15 to 20% should be assumed. In the Firth Basin, we are targeting steady production. First gas from Waits Year Stage 2 is not expected until the second half of calendar 2023. Turning to the Perth Basin on slide 32, the Perth Basin has generated much excitement with recent significant discoveries at Lockyer Deep and the Western South Barrow Villa. These discoveries and Beech's existing fields demonstrate the extensive nature of the Perth Basin. Most of the remaining prospectivity in the Perth Basin, in our view, is within the Kenya Gas Play and held by Beech and Joint Venture Park No. 2. Beyond Ratio Stage 2, exploration will drive the next phase of growth. The drilling is now commencing at the end of 2022 and will continue through 2023. If we can prove up in excess of 500 BCF, there will be a strong support for facility expansions or backfill of the Waitia plant. When the Waitia stage 2 development drilling is done, we'll kick off the exploration program with Mitsui operated well elegance. The full program will compromise two Mitsui operated wells and up to six beach operated wells with the sequence still to be locked in as it's dependent on regulatory approvals to some of the wells. Trick one will be the beach's first operated well of the campaign with the team excited by this prospect. It's on trend and up dipped from the West Araugula discovery and has very similar characteristics to the Lockheed Deep discovery. Discovery here would be quickly appraised as we see the potential for material volumes. So the Otway Basin now is Flight 33. You can see here how it extends the position in the offshore and nearshore Otway acreage. In FY23, much focus will be on connecting the Thylacine Well and Enterprise Discovery to the Otway gas plant. However, we're also very focused on activity and growth beyond FY23. We will include exploration in both the onshore and nearshore acreage. Site 34 looks at our offshore acreage, which excites us for a number of reasons. First, we have five prospects identified which are located close to existing fields and existing infrastructure and reservoirs we understand. Second, these prospects all have seismic amplitude support similar to the other discoveries and fields in the basin. Amplitude support increases a prospect's chance of success and has led to a 100% success rate in beaches acreage. 16 successful discoveries from 16 wells drilled. We are improving our seismic data quality currently, and with encouragement, we'll consider exploration drilling in FY24. If successful, we would look to develop these discoveries in conjunction with development of artisanal labella in a cost-efficient manner. We're also excited by our initial outbreak rates, as set out in slide 35. We are focusing our three high-impact targets located close to enterprise. One could be drilled from the enterprise platform, significantly reducing development cost and timeline. A quick run through now on other basins, starting with the Taranaki Basin on slide 36. In New Zealand, demand for our gas continues to be strong, and we've been drawing on our wells to the maximum extent possible. This resulted in a decline accelerating earlier than expected. We are now focused on drilling up to two development wells to arrest field decline and return the plant to higher processing rates. Planning is now underway, and we are targeting drilling the first well in FY24. Setting aside 37 and the Bass Basin, as always, our focus in the Bass Basin is to keep our gas plant processing at higher rates for longer. We recently provided an update on activities, which included identification of the Yellow West infield opportunity from our reprocessed 3D seismic. We were hoping to drill Yellow West this summer, but lack of a suitable rig means that we are now targeting the summer of 23-24. We also deferred decision on the trickle development to allow more time with interpretation of the newly acquired 3D prime seismic survey and to fully assess project economics. Turning now to the Cooper Basin with a look at the western flank on Spike 38. It was a challenging year in the Cooper Basin with heavy rains disrupting activity on several occasions. This meant the backlog of work over activity and well connections has been carried over into FY23. Pleasingly, we completed an active drilling campaign, including well exploration and appraisal activities with outcomes and learnings to inform our program this year. Activity includes near field exploration and appraisal drilling, targeting the Moore and Birkhead reservoirs, follow up appraisal drilling in the Martlett field, and an extensive horizontal oil development campaign of Bower, Rowler and Spitfire fields. We've already had one oil exploration success this year, Rocky 1, which discovered oil in the Birkhead reservoir. Gas exploration and appraisal drilling is under consideration for the second half of FY23. We have a number of contingent wells ready to go depending on the outcomes of drilling in the first half. With new reservoir management strategies helping arrest the decline in oil production in FY22, and much activity planned for FY23, we are confident in targeting flat oil production this year. Heavy rain also disrupted activity within the Superbasin JV, which is summarized on slide 39. This year, the joint venture is targeting up to 100 wells with a primary focus on gas. A range of campaigns will be undertaken, including appraisal and development drilling and continuation of successful campaigns from FY22, such as the Moomba South program. A fifth week is now drilling to catch up on planned activity and address production declines witnessed during FY22. I'll close out with our key takeaway on slide 40. As I said, our key messages for today is that FY23 is the year of focused project execution as we deliver the foundation for growth in FY24 and beyond. We are focused on growth, growing our gas supply, growing exposure to key gas and LNG markets, growing cash flow and financial strength, and growing so sustainably. On that note, I'll ask the lines to be open for Q&A. Thank you, operator.

Thank you. If you wish to ask a question, please press star 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2. If you are on speakerphone, please pick up the handsets to ask a question. The first question comes from the line of James Redfern with Bank of America. Please go ahead.

Hi. Good morning. Just two questions, please. The first one is just around the contracted gas market. The slide in presentation has a midpoint of around $12 a gigajoule for gas to be supplied in FY23. I'm just wondering if you could make some more comments around what you're seeing for contracted gas prices for volumes from, say, three to five years starting in mid-2023, please, because that's when, I guess, the gas price reset will begin for Beach Energy. Thanks a lot.

Good morning, James. Thanks for the question there. So in terms of the pricing, obviously, the ACCC's more recent report Sort of focus more on the period from January to February of 22. I think didn't have a lot of visibility in terms of term contracts beyond the February 22 period. The midpoint for that ACCC report was around I think the $10.98 per gigajoule in terms of the latest report. We obviously, we've got two contracts coming up for a price reset both in the off way and that will reset from the 1st of July 2023. We are starting on that process right now and at the end of this year to be able to have those prices reset by the beginning of next financial year. As we previously noted, that process is well documented in terms of the arbitration process and the basis for agreeing those prices going forward. But I think, and those rely on contracts over a similar term, similar term of the contract that we're negotiating. So we point to the ACCC, that's probably the best I can point you to in terms of the current term market. Obviously, we're seeing a lot of increases in spot prices locally, but also internationally as well. From an LNG perspective, that does impact the local market. And again, as you would have seen in the latest ACCC report, that points to a potential impact to future term pricing and term contracts as well. That's probably the most I can elaborate on that, James, in terms of the year forward.

Okay, thank you. And just one second question, please. Just wanted to understand the production profile for the Otway gas project. So Beige is expecting to reach nameplate capacity of 205 TJs a day, mid-Calendar 23. I'm just wondering, are you expecting a plateau for a couple of years and then a natural fuel decline of, say, 10% per annum, or do you have a different view to what I just said? Thanks.

Thanks, Ian. So in terms of the production profile, if we connect the partisan wells That will take us up to nameplate capacity. Obviously, we've got the enterprise well also being targeted for connection mid 2023 with the well stock, so the full phyllocene wells and enterprise, and then GeoGrav 4 and 5 that we've recently added. We can see that that plateau will be maintained for a number of years post FY24. And obviously, as I've just gone through as well, we would be looking to expand and drill in FY24, which will then give us the well stock to feed at the back end of the current well stock. So we do see a plateau in that plant for a number of years beyond that as well. Okay, great.

Okay, thanks. I'll hand it over. Thank you. Thanks, James.

Sorry, operator, next question. Operator, are you in the line?

Yes, this is the operator. I've already promoted Mr. Dale. Mr. Dale, are you there? Hi, yes, I should meet him. Please go ahead with the question.

Thanks. Just on the Cooper Basin JV, five rigs, 100 wells, $250 to $300 million capex net, further 150 to 200 mil on the western flank, but you're only targeting flat production year-on-year. Is this what's needed for flat production outlook on these assets going forward?

Thanks, Dale. There's a few things. Obviously, the catch-up, as we said previously, in terms of the backlog of activity from 22. So that will add to not only production this year, but going forward as well. We've increased the number of wells that we're drilling in FY23 versus FY22. And from, you know, we drilled 69 last year, going up to 100 this year. We're also looking at other changes in terms of the electrification project that we're starting with Santos, so more broadly, and then also starting out the CCS project as well, which adds to the CAPEX profile there.

So can you give a steer in terms of what production step up you're targeting in FY24 for the level of spend?

For the Cooper Basin, we are looking to at least keep the production flat, so we're not guiding in terms of the actual potential increase in production we're seeing there. I think it's prudent to first see how that program sort of pans out in terms of the activity we have with obviously Santos, the operator there, in terms of trying to alleviate and deal with the decline we've seen in FY22. And then in our own fields, we're looking at obviously expanding on the exploration and development program there. So we go through the western flank side of things. The first three quarters of the year, we'll look at development and operational drilling in the marklets, Spitfire and Growler fields. And then also looking at the exploration in the Rincon, Kalawanga, Hanson, and Kighton fields, and then obviously looking at how we expand around the specifically market, and then looking at the last quarter of the year, expanding on our exploration and appraisal program as well. So there's quite a bit out of the program that relates to production increases, the back end of 23, but then mostly 24 as well.

So I guess the production guidance of FY24 up to 28 MMBOE, is 28 achievable? And if so, what is needed? Is it all Victorian gas projects starting mid-calendar year 23, no customer loan nominations, wait here basically a full second half calendar year 23? What's needed to hit that number?

Yeah, that's basically correct, Dale. So as we set up on the slide, In terms of the base production, we would expect our current assets to producing at base in terms of the Cooper Basin. As I said, from a Cooper and Bass point of view, there's an underlying decline of 15% to 20%, and we're not looking to draw the Yalla well until the summer of 2023-2024. So that's an exploration well, so we're not counting on that coming in. With the off-way Again, that's keeping the plant full, and that's thylacine wells coming in from the 1st of July 2023, and obviously Enterprise being connected at that point in time. And then looking at the West in terms of the first LNG shipments, we said second half of 2023. So those are the things that add the specific material volumes in terms of off-way and weights here. So if there's any slippage of that timing to the right, then obviously, you know, that target will be at risk.

Okay. And then maybe finally, just a comment around targeting a net cash position through FY23, kind of effectively targeting a lazy balance sheet for the next 12 months. Can you talk us through what the thinking for that is? Is it lack of trust in execution, production outlook, oil price, or sort of what is it that you need so much conservative system?

Look, we still in a very, you know, in terms of the world we're operating in, in terms of the risk that involves the projects, we thought a prudent approach is better, and especially in terms of FY23 and the CAPEX here. If you look at our market cap, we're still spending, you know, close to a third of our market cap in CAPEX for FY23. So it is significant. It is still a high CapEx spend. So we are being prudent in terms of balance sheet management. It does give us the ability and the cash flows to deliver those growth projects, and it also gives us the ability to look further afield in terms of potential inorganic opportunities as well, and whether those exist in the current market. So it does give us the flexibility to look at all of our options for FY23 and then obviously look at the material increase in cash flows for FY24 and what that then means for our capital management framework going forward. So from our point of view, it's still prudent to keep the balance sheet as balanced as we can for FY23 until we can lock away the cash flows commencing FY24. Okay, thank you.

Thank you. Next question comes from the line of Mark Wiseman with Macquarie. Please go ahead.

Good morning Annemarie. Thanks for the update today. Just had a question on the East Coast gas market and the uncontracted exposure. You had talked about finding another contract on enterprise and maybe from the portfolio more broadly. Should we be expecting VEG to announce a contract at some point?

Yes. We are engaging with the market or starting to engage with the market on the enterprise volumes. Obviously targeting that to come in mid-2023. But I wouldn't expect any announcement this half. Probably second half we'll probably make an announcement on those volumes. And as you say, they are uncontracted and is the flexible part of the portfolio going forward from a Northway point of view.

And for FY23, the 11% uncontracted, should we assume that that's flexibility and sold into the spot market?

No. Obviously, that's the representation of currently contracted volumes. We'll probably look to lock that away in terms of future term contracts as well, and some of that might play in the spot market. So you shouldn't see all of that as spot market, but there might be a combination of the two going forward.

Okay, great. That's clear. Just a couple of others. On the BP contract, it was almost a year between the HOA and the SPA with BP, and the world obviously changed in that year. Could you just maybe explain, did any of the pricing parameters or contract terms change during that period of time?

Look, Mark, obviously, as you can imagine, I can't talk to any specifics in the contracts. Obviously, it's commercially in confidence. What we can say is, obviously, there's a mix of that JKM and Brent. You know, they... which allows us to take advantage of those favorable price movements in the North Asia winter periods. We've got full upside exposure, downside protection, which I said gives us a nice return from a commercial point of view. Anyway, from a project point of view, it does give us that flexibility in terms of the start date as well, in terms of the terms of conditions. So it allows us to vary the first shipment date depending on the commissioning of the plant. And as I said as well during my talk as well, is that it is an agreement that you could entirely expect us to have entered into in the current market environment. That's probably as much as I can say and willing to say.

Okay. And just finally for me, just on the dividend, you're obviously sitting on a large cash pile, but Appreciate you. You have a lot of CapEx this year as well, as has already been discussed. I guess, can we just clarify for the next couple of dividends in FY23, whilst you're still executing on the growth, should the market just assume a flat one cent per half dividend? Is that a fair assumption or will there be a point in time where you start to have that discussion around raising the dividend?

Look, that's obviously a decision for the board to make over the coming year. What I can say is that, as I said before, we do still have a big habit here in FY23. We do want to lock away the projects, the growth projects, and get to FY24 where we do see material increase in our free cash flow going forward. So I think for FY23, I wouldn't expect any increase necessarily in dividends. But we will look to have that discussion with the board in terms of how we look at our capital management framework going forward and whether that means an increase in dividend share buybacks and other capital management initiatives. Also, we still have a great balance sheet now. We've got the ability to go after growth, be that what's already on the cards or be that growth, additional growth. and looking at M&A as well when that makes sense from a value point of view. So we do have all of those available to us and we do have the flexibility to go after all of those things at the same time. So it's not mutually exclusive as well.

Okay, great. Thanks, Mono. Cheers.

Thanks, Bob. Thank you. Next question comes from the line of Mark Samter with MSD Markey. Please go ahead.

Yeah, morning, everyone. First question, if I can, just to follow up on the initial question around the price review with Origin. And I appreciate, obviously, not going to try and push you with any comment on where that ends up, but it's something that I certainly think I encounter a lot of confusion with amongst investors. Can you just confirm for us, I guess, like we saw with the arbitration process last time around, it doesn't set a price that determines as if that contract was being negotiated on the day of the price review. It takes into account deals done in the intervening three-year period, which is a benefit to you guys. Obviously, last time it came around, but can you just confirm that this price review isn't you're sitting there on the 1st of July, 2023, and you'll get what the market is then. It's a reflection of more of an average over the previous three years. Is that a fair interpretation?

Yeah, I think, hey, Mark, so in terms of the disclosure around that, I think we were pretty fulsome when the arbitration outcome was announced in our previous ASX announcement. And I think it was worth to that effect in terms of it looks at contracts over a similar period of time over the preceding period. So, and obviously delivering in those similar markets as well. So I think we were pretty awesome in that disclosure. So I think that still stands. Perfect. Thank you.

Then just another question around weights here. And I guess when we think about when it does start producing, can you give a little bit of a picture on the initial ramp profile? Particularly, I guess, if we're starting to head right towards northern hemisphere winter of 23, 24, how much we get in that early stage. And just around that, with the contract with BP, is there any seasonality in the portion that is sold? Do you get to sell them at the best or the worst of times?

Yeah, good questions, Mark. So the initial rate of the ramp-up is to the 250 kJ. So ours is obviously the 125 kJ. um there's there's only i mean obviously the number of shipments um uh the gas that's needed for the shipments will obviously get into the northwest shelf at that point in time so when we say about half the second half of 2023 uh we we assume that that ramp up will be um obviously uh done by that point in time so when we talk about volumes and the target for 28 by 24 it assumes that sort of ramp-up period as well, which will take a couple of months to ramp up to that sort of full capacity of the plant. And then in terms of the shaping, in terms of the month, in terms of winter and summer in the northern hemisphere, that will be dependent on the shipments during that period of time. So we do have arrangements where over the five-year period we will get I suppose, an equal exposure to those winter and summer periods. Awesome. Thanks. Thanks, Mark.

Thank you. Next question comes from the line of Daniel Butcher with CLSA. Please go ahead.

Hi, everyone. Just curious, a couple of things. The first one's just on OPEX. You've raised your OPEX guidance by sort of half a dollar a barrel or so. Just sort of curious, is there a production mix to high-cost fields or are you seeing general cost inflation in the fields? What's sort of driving that?

Thanks, Daniel. So that's probably a combination of all those things in terms of, you know, in terms of the cost per barrel, it's towards the high end of obviously the production capacity in terms of where that production is coming from, which may throw this to Amway as well. But it's coming from the fields that carry the higher costs. And then also production decline that's coming through FY23 as well compared to FY22 before we actually reach the new volumes coming in from FY24 onwards. So there's a bit of a component that is fixed price as well. So we do need to, you know, have that OPEX there in terms of, you know, waiting for the volumes to come in line from FY24. So that's largely unavoidable for 423.

Okay, thanks. And second one, just on your guidance, what nominations at Otway are you assuming? Are you assuming it basically produces at the full capacity you've got, or are you assuming some sort of seasonality? Given the current environment, I would have thought people were taking as much gas as they can with not much seasonality for next year. I'm just sort of curious what you've assumed.

Yeah, we are assuming, as I said, just above type of pay levels for FY23. There is a bit of seasonality in it, so we haven't assumed that our customers will nominate to 100% of the deliverability in FY23. So we have been conservative from that point of view.

Okay, great. And one final one from me, if I can. You talked about Perth basin exploration on slide 31. Just sort of curious whether you'd give us a bit of colour. about the size of the prospects or fields that you're pursuing there and your estimated success rate, given it's been a pretty successful area for yourselves and your peers nearby so far. And the second part of that question is, could some of that production be exported through Northwest Shelf as well, if you find a significant amount?

Maybe I'll cover the second part of the question first, and then I'll hand over to Sam just to talk about the Exploration Program and the Perth Basin. I think from a from a third person point of view, obviously very excited about the prospectivity there, and that's why we starting exploration process the end of this year with Mitsui. Overall, I think we are aiming to hopefully have a material increase in potential volumes coming out of the per patient as a result of the exploration program, and we we are hoping that that will give us the avenue to go and have a discussion around what that means from a domestic versus international point of view going forward and whether we can, you know, get to a point obviously with government approval and blessings in terms of expanding the plant, say by 26, 27, to actually expand the plant and hopefully get more LNG into the market after we've taken care of the domestic market. So we'll see whether we can make that work in terms of the volumes coming out of the exploration program. But that's totally dependent on the actual program and how successful we are there. And there's also the opportunity, the way to your plant, to have further backfill and extend the life from the volumes there, again, if successful. But I'll maybe hand over to Sam just to talk about the Yeah, thanks Mornay.

Yeah, I mean we're lucky to have a portfolio of prospects here. What a wide range as you can see from the map and they of course have a range in potential size and also risk. In regards to size, as I've said previously, we're not making any predictions there, but I think if you look at the area of our prospects in relation to the discovered resources that have had recent preserves an ounce, then I think that's a good yardstick to go by. And in regards to risk, I could say there's some variability there. Proximity to existing discoveries is positive, but we do regard the two Mitsui-operated elegans and genatrix to be slightly higher risk than the other prospects. But I think the whole point here is we're drilling a lot of exploration wells, and so we certainly anticipate success. And as Mornay highlighted earlier on, we are ready to follow up with appraisal to understand what the resource size is of each of those discoveries as and when they come in. And in addition, I'd highlight that we're also looking at drilling a second well in Bahara Springs Deep, which would prove up our 1P reserves and maintain our gas production. And we're also looking at planning 3D seismic over the leads which will hopefully give us a better understanding of those features and add further to the portfolio so that we can continue our drilling into FY24 as well.

All right. Thanks, Laurel. I'll turn it to somebody else.

Cheers. Thanks, sir.

Thank you. Next question comes from the line of Nick Burns with Jarden Australia. Please go ahead.

Oh, yeah, thanks. Hi, Monet and Anne-Marie. Just a couple of questions for me. G'day. On the East Coast gas contracted position, so back on slide seven, I just want to clarify something, if I can. For FY24, you're showing contracted gas of 33% and then 68% in FY25. Just trying to understand why that's increasing. Can I assume that that 68% in FY25 also increases includes the price reset volumes from FY24?

Yeah, that's correct, Nick. So that's obviously contracted by FY25, and then the 8%, you can see there, relates to the Cooper Basin volumes, the 8% reset.

Yeah, okay, that makes sense. Do you have any sense of, I guess, if you just think about your East Coast gas sales in FY22-23, what proportion of that 25 volumes would still be exposed to what you consider legacy or current gas prices versus what will be repriced or uncontracted in FY25?

I don't have that. I'm just looking across the table. No, we don't have that. Maybe, Nick, if you call us back afterwards, we can look at whether we can provide that more broadly. But I don't have that here for you today.

No worries. And look, I might just talk about just a couple of questions on weights here. Stage two, there's no mention of cost update there. I think at FID, you're talking $350 million to $400 million each share. Just wondering whether that's still valid. Are you within that range? Have you seen any sign of cost escalation there, and what's the remaining key risk here in the remainder of the program?

That's correct, Nick. So we haven't updated any of that CAPEX, so it's still within that range. We're still currently holding that range, so haven't updated that in terms of the current progress. that we see there. So, I mean, the main risk for us is in terms of, you know, the WA market is around the compressor timing. And, well, there's four compressors, really. And then, obviously, liquidating the work on site. So, we are talking to Clapham and Tsui in terms of how that could be brought forward in terms of timing. So, we are looking at whether we, say, for example, air freight some of the valves in versus putting it on a ship, you know, bringing over the compressors one at a time and then commissioning them versus, again, waiting for all four compressors to be completed before it's shipped. So we are looking at how we can accelerate the timing in terms of the weightier delivery. But that's basically the risk there is the liquidation of the work on-site and how we can better manage that in terms of sequencing and potentially bringing that forward.

Got it. Just a final one from me, just around the Perth Basin Exploration Appraisal Program. So you've sort of outlined, I think, now it looks like six to eight wells. I think previously you were talking three to six, so a good increase there. But just understanding, I guess, when do you expect to start the first well, i.e. when is when do you expect to complete weighting stage two development drilling and which will be the first well that's drilled? Cheers.

Thanks Nick. So the Perth Basin Program, the development wells going pretty well at the moment. So they are running on schedule. So we expect that to be completed by the end of calendar 2022. And then we'll kick off the exploration program from there. So the first well is material product called named Elegance, and then we'll progress it from there.

Fantastic.

Thanks, Mounir. Thank you. Next question comes from the line of Gordon Ramsey with RBC Capital Markets. Please go ahead.

Thank you very much. Mornay, just a question about capital management and strategy going forward. Clearly, your net cash, $165 million this year, you're going to be net cash next year. You've got strong free cash flow. It's growing net of growth capex. Why don't you get on the front foot and put in place a cash flow-based dividend policy net of growth capex and just have something for investors to look forward to because it's a little bit of an insult that the dividend has been sitting where it is for so long and yet your net cash this year and next year. Can you just comment on that, please?

Thanks, Gordon. So as I said before, we think in terms of prudent capital management and the capital that's still at risk and being spent in FY23, that now is not the time to come up with a revised capital management framework, acknowledging, you know, in terms of what you've just said, it does make sense. But from a current FY23 point of view and the capital spend and the exposure we have there and the risk that's still on the table, we feel it's still prudent for FY23 to maintain that. Does not mean that we're not discussing that with the board on an ongoing basis and that we're not looking at how we filled out our capital management framework going forward. It also doesn't mean that we're not looking at how we can expand and grow the business both from an organic and inorganic base in A423. But in terms of formalizing that capital management framework, A423 is not going to be the year where we announce a formal capital management framework. So I think that's That will be in the latter part of 23. We'll be looking at what that means for us going forward from April 24 when we see material free cash flow coming into the business.

Okay. And just on coupe, clearly the compression hasn't really gone to plan. You're talking about an additional two wells. Is there potential for a reserves downgrade there? No.

We don't see any reserves downgrade going forward. We did make a small adjustment in the reserves, as you would have seen in FY22, and the compression project was actually quite successful for us in terms of uplifting our production rights from the asset. We do see the need for those two further development wells going forward to increase and maintain our plateau for a number of years beyond that as well.

And just lastly for me on the BP contract on the LNG side, are you able to split the difference between JKM and Brent so we get a feel for whether it's more of a Brent oil price index contract than JKM?

Unfortunately, I can't provide that, Gordon, so apologies for that. I think there's a few commentators in the market that's obviously making some estimates and forecasts, so maybe point to them.

Okay, thank you.

All right, thank you. Thank you. Next question comes from the line of Sol Kevonik from Credit Suisse. Please go ahead.

Thanks, Moana and team. Just a few quick ones then. Can I come back to this BTSPA? I think it was a month ago at the quarterly, it said that terms are materially the same versus when the original HOA was signed. Can you confirm if terms are materially the same, Monet?

They're materially the same, but as I said, the contract we signed is reflective of the current market conditions of what you would expect us to sign.

I'm just trying to understand, I mean, has there been either an uplift in slope or has there been an uplift in the proportion of spot LNG versus a year ago or not?

Again, Sol, I can't really comment on that apart from what I've just said, unfortunately.

All right. Then just looking at the FY24 target of 28 million barrels, Like, the language has changed here. You're now saying up to 28 million barrels, and you've listed a number of assumptions there, which some of them look, frankly, pretty optimistic, like maximum nominations, et cetera. So, you know, I'd read this to say, you know, you're now guiding that you might not get 28 million barrels in FY24, which would be the fourth production outlook downgrade in as many years. Is the guidance we've now got in FY23 and this risk profile in FY24, is it conservative, or are these still targets for Because we've obviously gone through three years now of a lot of guidance has been optimistic targets, which has been disappointed. And I'm trying to get a sense of whether you think we've now got a reset of expectations to a conservative outlook versus an optimistic outlook.

Look, I would definitely say it's, you know, when we go through the basis for the production guidance as we've gone through, you know, there's obviously room in terms of the basis we've set there. And if you look at the risks and key drivers for the 28 million barrels, there's risk and opportunities there as well. I do think it's, you know, from my point of view, it's a target in terms of reaching that target. So for us, we're working to deliver those key projects, which is basically Waitsea and Otway are the two key projects to deliver to make sure we get to that target of 28 million barrels. And we need to make sure that we hit the timing as we set out, which is mid-2023 for thylacine and second half awaits here. Whether they're conservative or not, they are the targets we are setting and the targets we are setting for the business in terms of delivery of those specific projects.

Thanks. Last one, just again on the Otway contract repricing from July 23. He talks about, you know, it's the average of the last few years versus kind of the point in time when it's done. I'll just put a scenario out there. If we were to see some two- to four-year fixed price East Coast gas bill signed in the next 12 months at, say, $15, which would be our estimate of, say, where the price is, does that factor into the price review?

Yes. So as I said before, it's over the preceding period over which that contract was in existence. So that will be the three-year period that applies. So from where we're sitting right now, there's still a year to go to get to the 1st of July, 2023. So your assumption would be correct.

Great. Thanks. That's all from me.

All right. Thanks, Will. Thank you. Next question comes from the line of Adam Martin with Morgan Stanley. Please go ahead.

Oh, good morning. Just a question on Basquiat. It looks to be coming off a bit quicker just in terms of production decline. I suppose I'm trying to understand if YOLA West doesn't come in, sort of what happens? Do you sort of revert back to Trefoil or, you know, do we assume abandonment comes in quicker? Can you just talk about that asset, please?

Yeah, no, thank you. So in terms of Basquiat, As we said, we're quite excited about the Yellow West opportunity there. So we're looking to get the rig out there end of next year. In failing the successful exploration there, we are still looking at progressing with trefoil in terms of the feed there. So we are looking at the seismic, the prime 3D seismic in terms of what that means for our resources and then obviously our reserves there potentially. and how we develop that field. So also looking at what that means from a scope point of view, whether we can extend the scope and then we're also going through a program where we looking at all the capital costs that relate to that development and how and whether we can actually reduce the capital costs for that project. So all of that is hopefully feeding into that assessment and then we'll make that assessment. I would think closer to the end of this calendar year. and see what that means for the asset going forward. Obviously, if we don't go ahead with trade fall and YOLO West is not successful, then we would look at what that means from a decommissioning point of view.

Okay, that's helpful. And just on tile of seam, it looks pretty important in terms of driving that FY24 up list. Can you just talk through what are the key bits of work and what are the risks to getting those tile of seam wells connected on time, please?

Yeah, look, I mean the key piece of work is, you know, is both offshore, the flow lines, the flow lines to the thylacine platform, and then the brownfields work that relate to the liquids handling at the Otway gas plant as well. So those are the two pieces of work we need to liquidate. So the offshore part of it is reliant on the weather, so convincing that We'll commence that after the winter period, so when there's calmer weather and more predictable weather with the vessels going offshore. And the brownfields work a similar story in terms of waiting on the winter to pass and rain, potential interruptions before we start liquidating that work as well. But in terms of the actual work that's being delivered, from a technical point of view, obviously, not as technical as drilling seven offshore wells.

Yes, yeah, that sounds good. All right, that's all. That's all for me. Thank you. Thank you, Monet, Anne-Marie.

Great. Thanks, Adam. Thank you. The next question comes from the line of Tom Allen with UBS. Please go ahead.

Good morning, Monet, Anne-Marie and the team. So recognising Beech's net cash position, you've upsized the debt facility and your responses to prior questions about inorganic growth opportunities. Can you comment on the broad framework that you might assess the opportunity set? So, for example, opportunities in Australia only or internationally, or greenfield versus further brownfield, or a preference for new gas or oil? I'm looking for some comments on what defines the strike zone.

Yeah, thanks for the question, Tom. So we are focused on Australia and New Zealand in particular. We're not looking at international borders at the moment. And in terms of looking at specifically, you know, brownfields or greenfields versus producing assets, we are not focused on any particular aspect of that. We are looking at, you know, if potential assets can feed our current infrastructure. So that's probably priority number one. Obviously, if it's producing, that's a plus, but we're not focused on anything in particular in terms of whether it's greenfields, brownfields, or producing. I think what we focused on is definitely adding value, so seeing where we can add value from a beach perspective, so not looking at M&A for M&A's sake or adding volume or scale. So we do need to see a pathway forward on where we can actually add value as beach from that perspective.

Just following up a few questions in regard to Outways, just given that Origin can nominate up to the full capacity of the Outways gas plant, it looks like it might present some challenges signing contracts for Enterprise Gas. Is there any plan to expand the processing capacity of the Outways gas plant further under what commercial arrangements could see on enterprise gas contracted other than a few modest gigajoules here and there under a spot sales arrangement?

Yeah, look, we're not currently looking at any expansion on the Ottawa gas plant. So the enterprise volumes will play an important part in terms of the flexibility we have around that specific asset and the volumes we can put to market. So it will play an important role from that perspective when the nominations are not obviously nominating the full capacity that's available in the plant. So that's how we view enterprise and how we view that volumes, which will help us balance out our capacity there from a gas plant, but not looking to expand it beyond the current 205 terajoules a day.

Okay. But if Origin can nominate on a day ahead basis, how long would it take realistically to then have Enterprise up and ready to inject under a spot arrangement? Is it a matter of weeks, months, days?

No, it's immediate effectively. So if the Enterprise well is connected, we can just open the valve and the molecules flow.

Okay, great. Thanks, Mon-Anthe.

Thanks, Tom. Thank you. Next question comes from the line of Scott Ashton with SHA Energy Consulting. Please go ahead.

Good morning, Mornay. Just a quick question. It follows on the back of Nick and Daniel's question. So I thought I heard on the call for the Perth Basin assets, you're looking maybe 500 BCF would be like a threshold volume, my interpretation of whether you expand Waitseer or use it for backfill. So is that what we should be thinking, that the exploration program needs to deliver something like 500 BCS? And then on the back of that, if you're talking about expanding the Waitseer plant, is there some sort of talk underway about the capital that might be needed to accommodate either increased rates or to build in some extra capacity so you're not sub-optimising the plant. Can you just sort of make a few comments around there? I just want to understand the strategy.

Yeah, look, from a plant capacity point of view, in terms of the current footprint we have and looking at the future potential expansion, if that exists, depending on the results, we can expand that plant about to 100 terajoules a day if we see the need. Obviously, you're going to have to reach FRD on CAPEX and make sure you can get the return on that. And that will only be from, say, 26, 27 onwards. Again, that will be dependent on whether there's a market to put those volumes to at that point in time and what market you're putting it to. I might focus, Sam, on the BCF question. Sam, how do you want to answer that?

Yeah, like I said earlier, I think we've got a lot of lot of prospects in our portfolio and if you look at the other sizes of the features then 500 BCF is eminently achievable but there's also a range around that which is quite wide.

And I suppose where we're sort of going with that is, is that the inflection point or the trigger point for whether you optimise the plan even further for increased rates?

Look, it might be. It's obviously something we need to discuss and agree with the operator, which is Matui, from a JV perspective. So I suppose what we're trying to say there is that in terms of the prospectivity of the base and what we're going after by the end of this year in terms of starting the exploration program, that is quite significant and material.

Okay, and just a very quick question for Anne-Marie. Just so I've got this right, so apologies if it's already been discussed previously. The $0.48 a barrel NOCTA abandonment levy, is that deductible for PRRT purposes? And is the Otway and the Bass Gas stuff paying that at the moment, given it falls within that 21 to 29 timeframe? Can you just maybe... Make a few comments on how that works with your abandonment liabilities and provisions.

Yes, so we're not currently paying PRRT on any of our assets at the moment.

Correct.

We're not forecasting to pay any in the near-term future.

I don't think you can get it as a deductible, but from our point of view, it doesn't make a difference.

Yes, not deductible for us.

Okay, thanks.

Alright, thank you. There are no further questions at this time. I will now hand back to Mr Engelbrecht for closing comments.

Thank you everybody for dialing in this morning. Obviously, if you've got any further questions, please give Derek or myself a call. Happy to take any questions offline as well. Thank you very much. Cheers.

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