Beach Energy Limited (BPT) Earnings Call Transcript

Thank you for standing by, and welcome to the Beach Energy Limited FY '26 Full Year Results. [Operator Instructions] I would now like to hand the conference over to Mr. Brett Woods, Managing Director and Chief Executive Officer. Please go ahead.

Good morning, everyone, and welcome to Beach Energy's FY '26 Full Year Results Presentation. Joining me today is Anne-Marie Barbaro, our Chief Financial Officer. Together, we will take you through this year's operational and financial results, progress we have made against our strategic priorities and the outlook for FY '27 before opening the lines for Q&A. FY '26 was a year of tangible delivery against the strategic reset we outlined 2 years ago. We assisted our operator in bringing a major project into production at Waitsia, executed a large offshore campaign in Victoria, recommenced drilling in the Western Flank after nearly a 3-year hiatus, grew margin across our business through an embedded cost discipline, commercial focus and the owner's mindset, and maintained a strong focus on safe and reliable operations. Importantly, that discipline translated into strong cash generation and strengthened balance sheet. Beach delivered positive all-in free cash flow during a major period of project execution, supported by increased realized gas pricing, lower field operating costs and disciplined capital allocation. We also reinforced as a critical supplier of domestic gas on the East Coast. Our operated assets and non-operated interest supply approximately 19% of total gas demand with 100% of our East Coast gas production delivered to domestic customers. As a result, Beach enters FY '27 in a stronger financial position with greater flexibility to fund disciplined organic investment, pursue value-accretive inorganic opportunities with a view to building the resource base to support the next phase of growth. Slide 2 sets out our compliance statements, which I'll leave to you to read at your leisure. We begin with our headline results on Slide 3. FY '26 headline results demonstrate the resilience of Beach's operating model with commercial execution and cost discipline helping offset production headwinds and support strong cash generation. Production of 19.4 million barrels of oil equivalent was 2% below the prior year, primarily due to the Cooper Basin flood event and further severe rainfall in February and March of this year. All operated assets delivered above their FY '26 targets, but this was partially offset by the delayed first production and a slower ramp-up of Waitsia. Waitsia achieved its nameplate capacity of 250 terajoules a day in April, and Beach will continue the ongoing support of the operator as it continues to work towards sustained production rates. Sales volumes were 22.9 million barrels of oil equivalent with revenue of $1.8 billion. While lower production reduced sales volumes, revenue benefited from 6 LNG cargoes with a 7% uplift in realized gas pricing, reflecting the continued value of our targeted gas marketing strategy. Cost discipline also remained a key focus with total field operating costs reduced by 3%, including the addition of the Waitsia gas plant operations from December. Together with stronger realized gas pricing, this supported underlying EBITDA of $1 billion and pre-growth free cash flow of $458 million. Today, we announced our refreshed capital management framework, which is designed to support disciplined growth and increase total shareholder returns over time, whilst maintaining prudence as we navigate through a period of uncertainty with the domestic gas reservation policy still under review. We will continue to review the framework as our policy of our portfolio evolves, but the approach is deliberately disciplined. It preserves financial flexibility, directs capital to the opportunities with the strongest returns and provides a clear pathway to grow total shareholder returns over time. Within this framework, the Board has declared a final dividend of $0.02 per share, bringing full year dividends declared to $0.03 per share fully franked. Slide 4 brings together the key FY '26 milestones that demonstrate delivery against the strategy. Across our core hubs, FY '26 was defined by safe execution and the delivery of critical infrastructure. In the West, Waitsia commenced production in December, establishing a long-life infrastructure platform in the Perth Basin. We are working closely with operator, Mitsui, to move the plant towards steady-state operations, following a planned statutory shutdown in September. On the East Coast, Beach supplied 100% of its gas production to domestic customers with our operated and non-operated interest supplying approximately 19% of the total East Coast gas demand. This clearly reinforces the critical role of domestic-only producers in the Australian economy and while we continue to advocate for policy settings that support new supply and long-term energy security. Safety performance was also a standout. The team achieved 18 months recordable injury-free, while executing major offshore activity, drilling in the Cooper Basin and day-to-day field operations across our portfolio. This is an exceptional outcome last achieved in 2011 when Beach operated only in the Cooper Basin. Moomba CCS also continued to perform strongly with nearly 2.3 million tonnes of CO2 equivalent safely stored since startup. We also maintained our focus on margins and cash generation with commercial execution and cost discipline helping to convert operational delivery into strong financial outcomes. Our targeted gas marketing strategy saw 29 petajoules of gas sold into spot and short-term markets across a diversified customer base, supporting high realized gas pricing and improved margins. The 6 LNG cargoes of Waitsia delivered revenue of $343 million, supported by a combination of gas time swaps purchases, Waitsia production and North West Shelf lifting arrangements. Our sustainable growth pillar remains focused on lengthening the duration of our portfolio. In FY '26, we took disciplined steps to high-grade the portfolio, monetize high-cost and low-margin investments and add exposure to attractive growth opportunities across Queensland, the Cooper Basin and the onshore Otway. During the year, we announced the sale of our 60% operated interest in VIC/L35, the offshore permit that contains the Artisan discovery. That transaction enables Beach to monetize the asset while preserving exposure to future development through a production royalty. Importantly, it also allows us to redeploy more than $500 million of near-term capital to higher-value opportunities. We also expanded our footprint in Queensland through new acreage awards with our joint venture partners in the Taroom Trough and Cooper Basin, alongside additional acreage in the onshore Otway. The Taroom Trough is one of Australia's most active exploration appraisal areas, and I'll speak to that in more detail later in the pack. The 3 new Cooper Basin joint venture blocks capture an existing field extension and further strengthen our exploration portfolio. We also acknowledge the Queensland government's proactive approach to the release and award of exploration acreage in both the Taroom and the Cooper. A supportive government is paramount to establish affordable and reliable energy over the long term. On the organic front, we commenced our Western Flank oil appraisal and development program with success across all 9 wells drilled to date. The remaining 3 wells are scheduled to be drilled in the first half of FY '27, along with the commencement of an 8-well exploration campaign. Taken together, these milestones demonstrate that Beach is delivering against the strategy: operating safely, improving margins, strengthening the portfolio and building the resource base to support disciplined growth. Turning to Slide 5. FY '26 was a record year for health and safety and environmental performance, achieved during a period of significant operational activity across the portfolio. The team safely executed more than 1.5 million work hours, including the offshore Equinox campaign in Victoria, an active onshore drilling program in the Western Flank and day-to-day operations across our operated assets. Beach has now been recordable injury-free for more than 18 months, a performance level last achieved in 2011 when the company operated a single offshore asset. Importantly, we recorded no Tier 1 process safety events during the year, noting our last Tier 1 process safety event was in February 2020. This outcome reflects the discipline of our operating model, the commitment to our people and the focus on planning, risk management and frontline execution. Those foundations will remain critical in FY '27 as we continue to work across programs over our core hubs. Slide 6 shows how the owner's mindset we introduced through the strategic reset is now embedded in the way Beach operates, allocates capital and captures value across the portfolio. For us, an owner's mindset means every asset team is accountable for safe delivery, cost discipline, capital efficiency and the commercial value of every molecule produced. It is about making decisions as owners of the capital, not simply operators of the assets. That discipline is visible in the operating cost base. Operated fields have reduced by 18% since FY '24, reflecting structural cost out, tighter activity planning and stronger frontline accountability. While FY '26 field operating costs finished slightly above our $11 per barrel oil equivalent target at $11.40 per barrel, this was impacted by lower production and weather-related disruption in the Western Flank. The underlying cost trajectory remains clear and strong. The same mindset is evident commercially. We have been deliberately and actively managing uncontracted gas volumes, increasing exposure to spot and short-term markets, adopting alternative pricing models, and optimizing routes to market across our portfolio. Since H1 FY '24, this has supported a 29% uplift in average realized gas pricing. Importantly, this operating discipline is translating into cash outcomes. We have kept our pre-growth free cash flow breakeven oil price well below USD 30 per barrel for the last 2 financial years and continue to meet our sustaining capital target. That is the owner's mindset in practice: lower structural costs, realized -- higher realized value, disciplined capital deployment and strong cash generation. Slide 7 sets out our position on the domestic gas reservation and the role policy can play in supporting new supply. Beach supports prospective reservations for new gas developments, provided it's implemented on a must-offer, not must-sell basis. That distinction is important because it ensures new domestic supplies are made available to Australian customers, while preserving market discipline, investment confidence and efficient allocation of gas to the customers who value it most. Our support is conditional on any scheme being prospective, rules-based, transparent and linked to a published adequacy test. It should also be recognized physical market realities prioritizing domestic supply close to customers and infrastructure and aligning obligations with market and the asset capable of serving. For Beach, this reinforces the strategic choices that we are making. We have monetized higher-cost developments through sale, and we are prioritizing low-cost onshore developments where gas can be brought to market efficiently, while continuing to target high-margin large-scale offshore opportunities that can materially extend life and scale to our portfolio. At the same time, our marketing strategy will remain focused on value capture and customer alignment. We will continue working closely with customers, expanding our routes to market across domestic supply, LNG export and emerging demand, and using portfolio flexibility to maximize value, while supporting reliable energy supply. Slide 8 sets out our reserves and resources position as at 30 June 2026 and the actions underway to rebuild and extend the resource base. 2P reserves were 156 million barrels of oil equivalent at year-end. The annual movement was primarily driven by production of 19.4 million barrels of oil equivalent, partially offset by positive revisions from the Western Flank campaign and through the Cooper Basin joint venture. The key contributors included: the Western Flank, reflecting successful oil appraisal and development drilling and improved performance across our operated assets; the Cooper Basin joint venture, reflecting improvement in reservoir performance, exploration success and additional undeveloped opportunities. The proportion of 2P developed reserves increased slightly to 77%, up from 76% in the prior year, supported by successful drilling activity in the Western Flank. 2C contingent resource position remained broadly stable at 174 million barrels of oil equivalent at 30 June 2026. Further detail on our reserve position is included in the annual report, which has been released today. Looking ahead, the FY '27 program is focused on building the resource base with targeted organic growth opportunities across the portfolio. This includes active exploration and appraisal across our East and West Coast assets, planned seismic activity across the recently awarded Queensland gas exploration blocks to high-grade future opportunities and progressing the Moomba Central Optimization project. The MCO project is expected to improve production recovery, reduce fuel consumption and support lower development costs through a more optimized central field drilling strategy, ultimately improving the pathway from 2C to 2P reserves. In parallel, we'll continue to progress growth opportunities in the offshore Otway, T30 and T50/P permits, as well as the Perth Basin backfill opportunities, which we will cover in more detail later in the presentation. With that, I'll now hand over to Anne-Marie for a deeper dive into our FY '26 financial results.

Thank you, Brett, and good morning, everyone. FY '26 headline financial metrics demonstrate the resilience of the business with disciplined cost management and commercial execution helping offset lower volumes and softer liquids pricing, largely reflected through LNG. Sales revenue of $1.8 billion was 10% below the prior year, primarily reflecting lower crude sales volumes following Cooper Basin flood impacts and lower gas sales volumes in the Otway. This was partly offset by the contribution from 6 Waitsia LNG cargoes and stronger realized gas pricing, reflecting continued execution of our targeted gas marketing strategy. These commercial benefits, combined with structural cost reduction across our operated assets, supported our underlying EBITDA of $1 billion with an improvement in EBITDA margin at 57% and underlying net profit after tax of $355 million. Statutory earnings were $281 million, with the difference to underlying earnings primarily reflecting the write-off of the unsuccessful Hercules exploration well at the half year and costs associated with unutilized Northwest Shelf processing capacity prior to the commencement of production at Waitsia. Turning to Slide 11. The waterfall chart highlights the year-on-year movement in underlying NPAT. Lower sales revenue, down 10% on the prior year, reflected lower crude and gas sales volumes, combined with softer liquids pricing. These impacts were partly offset by higher realized gas pricing, up 7% on the prior year, and the benefit of 1 additional LNG cargo from Waitsia. Cost of sales benefited from lower third-party purchases, following the commencement of production at Waitsia, coupled with lower royalties, which were driven by lower revenue in the flood-impacted Cooper Basin. This was partly offset by higher tolling, LNG-related inventory movements and depreciation following commencement of production at Waitsia. Field operating costs were 3% lower than the prior year, and that includes the addition of Waitsia gas plant operations from December. This demonstrates the cost discipline now embedded across our operated assets and reinforces the strength of the operating model. Higher other income included recognition of carbon credits received during the year at market value, the revaluation of the condensate overlift liability initially recognized when we lifted the one-off Waitsia cargo in the first half of FY '24 and foreign exchange gains during the period. Slide 12 reflects the movement in cash during FY '26 with closing cash reserves of $213 million. Operating cash flow of $890 million reflected the benefit of 6 Waitsia LNG cargoes, strong realized gas pricing and continued cost discipline across the business. Operating cash flows also include Beach's offshore decommissioning activities conducted during the financial year as part of the Equinox campaign, which is now largely complete. Sustaining capital cash payments were $422 million, including sustained capital incurred of $394 million and working capital movements, well below the $450 million operating principle, reinforcing the capital discipline now embedded in the business. Importantly, Beach delivered positive all-in free cash flow during the year of elevated capital activity, including heightened offshore activity and the decommissioning of 4 offshore wells. The outcome further strengthened our financial position and preserved flexibility to fund future growth. Slide 13 highlights the strength of Beach's financial position at year-end and the flexibility it provides to fund disciplined growth. We ended FY '26 with $983 million of available liquidity, up 51% on the prior year. This was supported by positive free cash flow generation and the $300 million Asian term loan secured in December, completed with strong lender support. We also maintained a low leverage position with net gearing of 10.6% at year-end. This remains below our target of below 15%, providing balance sheet capacity to support disciplined organic investment and assessment of value-accretive inorganic growth opportunities. As noted, the Board has declared a final dividend of $0.02 per share, bringing full year dividends declared to $0.03 per share, while preserving flexibility to fund the next phase of growth. I'll talk to this decision more now. Slide 14 sets out our refreshed capital management framework, which is designed to support disciplined growth and increase total shareholder returns over time, whilst maintaining prudence as we navigate through a period of uncertainty with the domestic gas reservation policy still under review. The hierarchy is clear. First, we'll fund the sustaining capital required to operate the base business safely, reliably and efficiently. Second, we'll allocate capital to organic and inorganic growth opportunities only where they are value-accretive, risk-balanced and meet our disciplined hurdle rates. Our through-the-cycle gearing target remains around 15% with capacity to move up to 25% through the growth cycle where the returns justify it. This provides the flexibility to navigate the current period of domestic gas market review uncertainty while continuing to pursue high-return opportunities across the portfolio. Surplus free cash flow after sustaining capital growth and balance sheet requirements will then be available for the Board to consider shareholder distributions, including dividends and other capital returns. Put simply, the framework prioritizes 4 things: sustaining the base business, investing in growth where it creates value, maintaining a strong balance sheet and returning surplus cash to shareholders. We'll continue to review the framework as the portfolio evolves, but the approach is deliberately disciplined. It preserves financial flexibility, directs capital to the opportunities with the strongest returns and provides a clear pathway to grow total shareholder returns over time. With that, I'll hand back to Brett to take you through the outlook.

Thank you, Anne-Marie. I will now take you through the outlook for FY '27 and the key activity that will support our next phase of growth. Slide 16 sets out our FY '27 guidance, which reflects a continued focus on disciplined execution, safe operations and targeted investment across the portfolio. For production, we are guiding between 19.5 million and 23 million barrels of oil equivalent. This range incorporates planned statutory maintenance shutdowns at Waitsia and the Otway gas plants, Western Flank's recovery from prior year flood impacts, progressive connection of the remaining oil development wells during the FY '26 campaign and a prudent view of Waitsia's performance as the plant moves towards steady-state operations following the planned statutory shutdown in September. In the Western Flank, recovery activities are continuing with the remaining flood-impacted wells, representing approximately 600 barrels of oil per day, expected to be progressively restored in the first half. We will also connect the remaining oil development wells drilled during the recent campaign. In the Cooper Basin joint venture, production is expected to remain broadly flat with ongoing drilling activity expected to offset natural field decline. In the Otway Basin, we expect field decline close to 10% during the year, together with the planned 28-day statutory maintenance shutdown. The extension of maintenance cycle interval from 4 years to 6 years reflects the strength of our detailed risk-based inspection program and supports more efficient long-term operation of the asset. For capital expenditure, we're guiding between $600 million and $700 million. The program is increasingly focused on our onshore assets with active drilling campaigns across our East and West Coast portfolios. We'll also progress the Moomba Central Optimization project in the Cooper Basin joint venture. And we are targeting final investment decisions for the 2-well exploration and development campaign in Otway nearshore and the Waitsia inlet compression project in the first half of FY '27. Sustaining capital expenditure is expected to remain below our $450 million operating principle, reinforcing the capital discipline embedded in our investment decisions and project execution. Abandonment expenditure reflects the completion of the Equinox campaign, which is due to complete in the coming days, in addition to our progressive onshore abandonment activity, which remains consistent with our approach to safely and responsibly manage end of field life obligations across our broad portfolio. Slide 17 summarizes the active FY '27 work program across our core hubs with capital investment directed to opportunities that can stabilize production, grow the resource base and enhance the value of our existing infrastructure. Our FY '27 program includes multiple drilling campaigns across the Western Flank, Cooper Basin joint venture, Taroom Trough and Perth Basin. Activity is focused on adding production, testing new exploration opportunities and building future gas supply options. Over in the Otway, we are targeting FID in the first half of the financial year on a 2-well nearshore exploration and development campaign, which I'll talk to in more detail in the coming slides. We are also progressing key infrastructure projects, including Moomba Central Optimization, and targeting FID of Waitsia inlet compression, which is designed to support recovery, reduce unit costs and enable future supply. In parallel, we'll continue to mature the high-margin, large-scale offshore Otway opportunities in T30 and T50/P, where the focus is on high-grading prospects and progressing with the right partnership structure. In the Perth Basin, conventional and tight gas backfill opportunities provide a pathway to extend the value of Waitsia infrastructure over time. All activity remains governed by operating principles, safe execution, capital discipline, returns focus and clear alignment to growing the resource base. Slide 18 outlines our activity across the Cooper Basin, where our focus is on disciplined drilling, production and recovery, and infrastructure optimization. Starting in the operated Western Flank, we plan to drill the final 3 wells of the FY '26 oil appraisal and development program in the first half. These wells were delayed by severe rainfall early this year. We will then undertake an 8-well oil exploration campaign focused on extending play fairways and identifying new drilling opportunities for future years. The Western Flank program will use a fit-for-purpose onshore rig, which the team have been able to operate at a 20% reduction in man hours and a materially lower cost. In the Cooper Basin joint venture, Beach and operator, Santos, will be targeting the drilling of approximately 70 wells in the year. The JV will progress the Moomba Central Optimization with long lead works underway and completion targeted for FY '29. Moomba Central Optimization is designed to rationalize existing satellite facilities into a new centralized compression facility, reducing operating complexity and support future production growth from the Central Fields drilling program. Moving to the Taroom Trough. ATP 2081 gives Beach a 25% interest in an emerging onshore gas and liquids play, strategically located adjacent to multi-Tcf CSG to LNG production hubs, regional export infrastructure and local supply lines. ATP 2081 sits adjacent to Omega's Canyon prospect, which is in close proximity to Shell's Dunk Sandstone gas condensate play with more than 10 Tcf of contingent and prospective resources currently booked in adjacent fields by industry peers. The attraction for Beach is disciplined exposure to a material resource opportunity with liquids potential and proximity to the established Queensland energy markets. We are working closely with the joint venture partners, Omega and Tri-Star, with preparation works underway for the drilling of 2 vertical wells planned to commence from October. The program follows Omega's Canyon-3 and Canyon-4 wells in the adjacent acreage and is designed to test that play, inform reservoir understanding and support future appraisal planning. Subject to encouraging drilling results, the joint venture will then consider to optimize horizontal well placement and stimulation planning in the second half of the financial year. Turning to nearshore Otway Basin. We are currently maturing a 2-well exploration and development campaign, targeting Enterprise East and Selje prospects, both of which have the potential to provide near-term backfill to the Otway Gas Plant. Enterprise East is located immediately southeast of the producing Enterprise field. And Selje is approximately 4 kilometers to the west. On success, gas can be tied back through the Enterprise pipeline processed at the Otway Gas Plant. These prospects offer a nearer-term low-cost opportunity to backfill the Otway Gas Plant, given we can utilize existing infrastructure and drill from the onshore Enterprise pad to target an all-in development cost of less than $5 per gigajoule. This is an opportunity with a clearer and lower cost development pathway than the offshore alternatives, which we have strategically monetized during the financial year. The program is progressing towards final investment decision in the first half of FY '27. Upon success, the first gas could be delivered from the first half of FY '29 with economics targeting internal rate of return well above 20%. It is a strong strategic fit for Beach, modest capital exposure, attractive economics and direct leverage to existing infrastructure already connected to market, subject to approvals and exploration success. Beyond the nearshore options, the Otway represents Beach's largest-scale growth opportunities in the basin with the potential to expand portfolio life and leverage our existing infrastructure. T50 and T30/P adjacent, 100% owned by Beach permits covering more than 3,200 square kilometers. These permits contain a deep inventory of prospects and leads, underpinned by newly represented 3D seismic and advanced geophysical workflows. The prospects are around 130 kilometers offshore in water depths ranging from approximately 200 meters to 1,500 meters. Several of the main prospect clusters are well within subsea tieback distance to the operated Thylacine platform. Upon -- in a success case, these opportunities provide scaled, meaningful backfill or expansion to the Otway Gas Plant and support the long-term value of Beach's existing Otway infrastructure. Our immediate focus is to mature the prospects, progress the development concept and deliver a joint venture to bring these opportunities forward. That partnership process is designed to bring capability and capital, share subsurface and execution risk, and allow Beach to retain exposure to the material upside within our disciplined capital framework. This is probably the point that I get very excited about Beach's future. Slide 22 provides some technical detail on the Phoques prospects within the offshore Otway inventory and demonstrates the technical work underway to mature that. Discoveries in the Otway are driven by the interpretation of strong seismic signatures, which are observed in this region. All Beach's and adjacent gas condensate discoveries have a very strong relationship between their rock physics, their gas and liquids fill, and their seismic amplitude response. We are utilizing the latest technology and geophysical analysis to extend what we observe at Thylacine, Geographe, Enterprise and Artisan, as well as the other recent discoveries and dry wells in the region to model what is a multi-Tcf scale opportunity of prospects and leads outboard of our existing infrastructure. The seismic section within Slide 22 indicates a very strong amplitude conformance to structure and interpreted gas-water flat spot, strongly indicating the potential of gas within these prospects. Below that seismic section, [ these are ] seismic gathers and rock physics assessments, which indicate that gas and oil-bearing rocks will have a strong response and compares very favorably with the producing fields we know well in the Otway Basin. The amplitude response conforms to the interpreted structure. And the AVO response is consistent with the type of signal we would expect to see in gas-bearing reservoir settings. We've then extended that assessment with advanced quantitative interpretation and seismic conversion techniques, which has further improved our understanding of the prospect inventory, including the likely distribution of reservoir and fluid fill. The map on the slide is an output of the seismic conversion, which illustrates a potential gas field anomaly across the broader Phoques complex, which is significant in scale being multiple Tcf and relatively close to the Thylacine analog that you can also see on that slide. The seismic response we observed across these blocks with the latest reprocessing have delineated some of the most compelling opportunities that I have seen in offshore Australia for a very long time. The seismic indicators do not completely remove exploration risk and not an actual substitute for drilling, but what they do provide is a strong prospect definition, better targeting selection and greater confidence in how we high-grade the offshore Otway inventory. On that basis, Phoques represents a material scale opportunity that we will continue to mature through the partnership process and our disciplined capital allocation framework. Slide 23 builds on Phoques opportunity by showing a range of tracking geometries identified across this very broad complex. The technical work has identified conventional structural traps clustered on a subregional high with amplitude fit to structure and very strong AVO support that is consistent with our geophysical model. Interpretation of potential reservoir quality is also informed by the nearby Geographe and Thylacine analogs, which provide the important basin calibration. This diversity of trapping geometries gives Beach multiple targets within one broad complex, strengthening the offshore inventory, while still allowing the team to high-grade targets before any drilling commitment. Our focus remains on continuing technical maturation, prioritizing the highest quality targets, and progressing the opportunity with the right partner and capital structure. My mission with the offshore has always been to unlock scale, as scale delivers the lowest unit cost and delivers the highest margin. I'm very proud of the team who have developed this deep inventory of prospects and leads, and I'm excited to bring this opportunity forward as we seek to develop the right partner group to unlock this high-value opportunity. Slide 24 highlights the Perth Basin backfill opportunities, which provide long-term organic growth options and a pathway to extract further value from our West Coast infrastructure. Near-term conventional targets sit close to the Waitsia field and provide potential low-cost, high-margin development opportunities through this existing infrastructure. In FY '27, we plan to drill 2 conventional wells at Stawellia and Waitsia South with further seismic work proposed to high-grade the next phase of drilling opportunities. Beyond the conventional program, tight gas provides longer-dated resource potential around the Waitsia infrastructure position. Multiple discovered resource opportunities were originally identified by former joint venture operator, AWE, following the drilling of Senecio-3 in the L1/L2 permit. These opportunities are close to existing infrastructure and could provide a future source of Waitsia backfill, subject to the technical maturation, regulatory settings, joint venture approval and our normal capital allocation thresholds. Emerging regulatory reform is expected in 2026 with first activity targeted for FY '28 if the technical, regulatory and commercial conditions support progression. Slide 25 shows how our understanding of the Perth Basin tight gas inventory has evolved over time and why it remains a longer-dated option for Waitsia backfill. When Beach acquired the asset from Lattice in 2018, the portfolio included a material 2C contingent resource booking. That resource was subsequently debooked as the regulatory environment evolved and the pathway to an active development plan was set aside. Emerging regulatory reform has allowed Beach to refresh the inventory and assess opportunities that were previously removed from booked 2C resources. In parallel, data from Waitsia-8 and Senecio-1 have improved our understanding of the reservoir presence, distribution and [indiscernible] and the potential to provide a longer-term source of backfill is exciting. Any activity will remain subject to technical maturation, joint venture decisions and approvals but critically must be aligned to our capital allocation thresholds. Taken together with the conventional exploration program, the tight gas inventory gives Beach a deeper set of organic options around infrastructure that is already built and connected to market. Again, this opportunity excites me. Having large-scale discovered resource close to infrastructure is a clear strategic advantage. We can pursue longer-term scale potential, while remaining disciplined on timing, risk and returns. To conclude, FY '26 is a year of tangible delivery against our strategic reset. We brought key infrastructure into production, operated safely through a period of significant activity, improved margins through commercial focus and cost discipline, and delivered positive free cash flow, while funding major project and decommissioning activities. Importantly, we exited the year with a stronger financial position and a clearer platform for growth. Our balance sheet gives us flexibility to fund disciplined organic investment, assess value-accretive inorganic opportunities and continue building the resource base that will underpin long-term shareholder returns. Looking ahead to FY '27, our priorities are unchanged: operate safely, maintain the owner's mindset, maximize value from every molecule, invest with discipline across our core hubs, and progress the organic opportunities that can extend portfolio life and strengthen future returns. We are clear that growth must be value-accretive, risk-balanced and consistent with our capital allocation framework. That discipline will guide how we progress the active work program, mature our organic opportunities and evaluate inorganic opportunities. With that, I'd like to thank you for joining us today. Anne-Marie and I will be now pleased to take your questions.

[Operator Instructions] Your first question comes from Adam Martin with E&P.

Brett and Anne-Marie, hopefully, you can hear okay. It's good to be back there. But just on the domestic gas reservation policy, it does look sort of quite challenging for your business. I suppose what are the 1 or 2 things you're trying to change here? What are you looking to address there, Brett, please?

Yes. In terms of my advocacy at the moment with the government, really focused on making sure it's prospective that we have a market that acts like a market, not through kind of for sale into the East Coast market in particular. What we've done is we've tried to delever as much as we can our exposure to uncontracted gas through some contracting. Effectively, over 80% of our volumes are exposed either to liquids or term contracts. So we will continue to manage our portfolio. And I'll continue to engage with the government to get something that makes sense. Critically, 65% to 75% of the gas that's used in Australia have been delivered by domestic producers. We represent a critical part of that sector. And I've had a positive engagement with the government in terms of making sure that we defend that. And if I was to point anyone to one key message is the ACCC have highlighted that gas prices between $12 and $13 are required to continue to support the market and deliver long-term value across the East Coast. So I'll continue advocating for our position as strong as I can to make sure that our voice is heard and that people understand the potential impact of any reservation policy.

Okay. Just second question, just on the capital management policy, Slide 14. There's not a lot of detail there just on numbers. We've obviously as the market got to try and forecast the dividend. Are you sticking to a percentage of free cash? Is it a percentage of profit? Just a bit more color there, please, how we should think about modeling it?

Our focus is really, as we described, is our focus on our -- supporting our sustaining business, supporting our growth agenda and making sure that we deliver against that. We were focused on our balance sheet and continuing to support having a very strong balance sheet. And after we've met those critical hurdles, that gives the Board the ability to distribute any excess cash as appropriate.

Okay. So no real change in numbers, just focused on the balance sheet effectively for the time being?

So I guess, Adam, I would say that we don't have a strict payout policy. We are being very deliberate in maintaining flexibility to ensure that what we're driving is not just cash returns for shareholders, but total shareholder returns. But it will be looked at through your all-in cash flow lens.

Your next question comes from Tom Allen with UBS.

Just again on the new capital framework. So it's also prioritizing inorganic growth now over dividends. And so can we please get more detail on Beach's strategic framework that you will apply when you consider growth opportunities. So specifically, what type of assets are in, and importantly, what are out of scope, size of project, what product mix you're seeking? It sounds like your gearing target has changed relative to the full year '25 results. If I recall correctly, Beach had noted at the time that you'd stretch gearing to 30% to 35% and you base that on gearing levels akin to the leverage at the completion of the Lattice acquisition in 2018. And so today, it sounds like you're looking for big scale opportunities, but at a much more conservative gearing ceiling. So keen to understand more detail on the specific targets that might fit your strategic profile.

Yes. I think if I just go to your final part first, in terms of gearing, I think we've always said that 15% is our target level, which we would stretch to 25%. And particularly, that's pointing to opportunities that require development capital that don't -- aren't associated with any production. I think to kind of stretch that a little bit, we would have to see a producing asset like we had with the Lattice acquisition that could offset or drive that gearing down in very short term. Fundamentally, if we're looking at an acquisition that didn't come immediately with production, we would cap out at that 25% to make sure that we've got that strength remaining in our balance sheet. It would only through an ongoing production lens that we could push that and -- but we're being very disciplined about that. And in terms of where we're focused, we're very much focused on the East Coast and the West Coast of Australia still. We're seeing those as opportunity as the areas that are focused where we have our infrastructure. That is primarily where we're looking at. And I think it was 2 years ago, we outlined what our hurdle rates were across our strategic review. And we have high hurdle rates, well north of 12% is kind of our minimum hurdle rates for our -- the way we evaluate our future opportunities. So we're looking at that combination. And I think at the half year, I alluded to the fact that we've done a lot of work on our existing organic base, and I was pleased to share with you today some of that in terms of our offshore Otway and our Perth Basin opportunities that we look at as well as the ongoing work we've done through our Western Flank. So I don't think it will come as any surprise that Beach is looking to extend its reserve life. And we see 2 key ways of doing that, obviously, organically, but also inorganically across opportunities in the West and East Coast of Australia.

Brett, the plan that you've outlined for FY '27 today, it does look busy from an organic growth perspective. You've got drilling planned in near all your key hubs. You've spoken on this call about the challenges associated with the federal domestic gas reservation scheme. But could you please guide what East and West Coast gas price is required to support your drilling plans, particularly your offshore Otway Phoques target that you've spent some time talking about today. You've made mention in the past about offshore particularly needing to be scaled and needing strong domestic gas prices. And you've called out that ACCC reference at $12 to $13 a gigajoule. Is that the hurdle? Or at what price would you walk away from those opportunities?

Yes. So we've looked very disciplined at our capital framework for this year. And everything we're executing this year is supported by the -- any effectively domestic gas price realization given they are close to infrastructure. I think I indicated through the nearshore Otway that we're targeting that $5 all in. So we see that is irrespective of what domestic gas reservation could do in the near term, that can deliver strong margins and strong growth. And scale is critical. If you looked at the reason why we opted to trade out of Artisan, it was to kind of deleverage us from things that required for Beach a higher gas price to generate our hurdle rates. We were able to monetize that, and we have access to what would have been $500 million of capital now to deploy the things that deliver value. The deeper water, which is just outboard of the Thylacine feature are multiple TCF. So we should be able to deliver those for mid-to-low single-digit all-in development costs if it delivers the scale we were expecting. So irrespective of what could happen in the DGR, we're making sure that we have our opportunity set that is strong enough to handle that. So hence, Anne-Marie and I have been very focused on articulating our discipline. It's all about discipline for us. I won't be executing things that can't make money on even the way that the current DGR has been described at the moment. Now we believe through our engagement that we can deliver a better outcome in terms of the DGR. But we're just making sure that we have that discipline programmed into our model so that we don't have any unexpected surprises in terms of the gas market.

My final question, just to follow-up on that is that if the domestic gas reservation policy is applied as drafted, which we interpret to be on a must-sell gas basis with the government trying to break that nexus with an LNG netback price in the domestic market. Would Beach -- what I'm hearing is that the growth projects that you're identifying here still stand. You'll still seek to target the same growth opportunities. And can we rule out that you consider international opportunities?

Yes. At this moment, we're not looking at anything internationally. I think if -- I think maybe in a year or two's time, if something happens, we'd maybe readdress that. But at the moment, our priority is certainly within Australia. And certainly, I can confirm that everything we're looking at executing meets our disciplined execution of capital, i.e., that even on an as written DGR policy that we would be executing these programs. We're not spending capital in hope. We're making sure that we've got the discipline in the business and the assets to make sure that I can deliver strong returns for our shareholders.

Your next question comes from Gordon Ramsay with RBC.

Just going to come back to this refreshed capital management framework. You've only got one slide in the presentation on it. And I guess the market, in my opinion anyway, was looking for a bit more detail here. Anne-Marie, you said it's based on an all-in free cash flow lens. If we compare FY '25 and FY '26, your all-in free cash flow has dropped by 56%. I mean, should we be -- your dividend should have dropped by that much and then your debt has actually gone up. So I guess what I'm looking at is what kind of metrics should we focus on for the dividend going forward? You kept it purposely vague, but it makes it really hard for us to come up with any kind of reasonable forecast for the dividend.

Yes. And I guess that's -- I guess the point, Gordon, is that with the backdrop of uncertainty in the gas market review and Beach's stated need for growth to ultimately deliver longer-term shareholder returns, we have sort of retained full flexibility on the dividend at this time. It doesn't necessarily mean that that's the way it will be for the long term. But at this time, we are retaining full flexibility. So from that perspective, I do understand that it's not simple to model because we're not giving you a payout ratio, but that is the way that Beach is looking at the dividend at the moment. It is firstly prioritizing the base business and growth. And then whatever is left, a decision could be made on that basis as to cash returns to shareholders.

Just to add, this year, we had -- this last financial year we had an extensive period of offshore abandonment. We don't have any offshore abandonment coming until next decade. So in terms of all-in free cash flow, we had a large capital expenditure period. We will be -- but having nearly $1 billion worth of flexibility in our balance sheet to acquire is strong. And I think one of the most important things for me is delivering that TSR outcome for shareholders, which for us at the moment, we see growing our reserve life and executing on high-value opportunities as a real priority for our business. But we still have a very strong cash flow generating business. And we're looking at what flexibility we can have to deploy that capital above delivering growth and above making sure that we have that sustaining business operating well.

Good point. I agree, on reserve life. It looks like it's on a 2P basis, 6, 7 years. Just another question on Waitsia. Was inlet compression always part of the field development plan on that?

Yes, absolutely. There's no acceleration in inlet compression. That was always part of the plan. I think we've talked about it several times over the last few years. So it's just bringing that to everyone's attention that it's coming up FIDing shortly. It's part of our 2P reserves is another way to think of it. Always part of the plan.

Okay. And thank you very much for the information on Slides 22 and 23. I really like that stuff.

Yes, cheers. Well, I was worried I was kind of nerd out too much for everyone. But for me, it's putting that core part of how we grow the business to life. And for me, that's exciting opportunities for Beach to step into.

Your next question comes from Nik Burns with Jarden Australia.

Another question around inorganic growth. Uncertainty surrounding the proposed domestic gas reservation scheme must make it very challenging for you to value gas opportunities on the East Coast at the moment. Is it possible to do deals at the moment whilst this uncertainty exists? Or do you really need to wait until we see the final workings and wording of the scheme? And therefore, if you are going to pursue inorganic opportunities in the near term, it will be more likely on the West Coast than the East Coast.

I think what you raised is an important point, Nik. I agree with you, and I always answer your questions, Mate. You don't have to thank me for it. For me, I think the buyer-seller spread is probably large at the moment across -- with the uncertainty associated with the East Coast domestic gas reservation. However, there's always great ways you can structure opportunities where both parties can be protected through that spread. So I don't think it's impossible to do a deal at the moment. I think it's very possible, and we will continue to have those types of engagements with the right parties on assets that we see can liberate value. We have a very strong balance sheet. We're one of the parties that can execute and support growth across the market. And we will be looking definitely across the East Coast as well as the West Coast to grow our business.

That's great. And just on Waitsia, obviously, the plants had challenges ramping up to nameplate. We obviously track the daily production data. And -- but can you just give us a bit more color on what's been happening there? And I guess, more importantly, your confidence that the upcoming 24-day scheduled maintenance your confidence that you will be able to address these issues, and we will see sustained performance closer to at the 250 terajoule a day nameplate tiers?

Yes, really good question. Thanks, Nik. Yes. So critically, we've had some issues with the lubrication rates and the packing around the compressors at Waitsia, which means that they've been episodically tripping. So over the last few months, what we've done is, we've trialed different types of injection rates through the lube system and packing solutions. And we've recently had success in delivering one that is now performing as per its expectation. So part of our 24-day statutory maintenance shutdown across Waitsia, we'll be upgrading those pieces. All of that work is just within our sustaining capital piece. There is no additional capital that's required across there. So once we've installed that effectively that fix, I don't really want to call it fix, but that different way of lubricating and maintain that packing, we should be able to deliver sustained production through those export compressors. And we've had some other minor issues, which are just commissioning issues associated with the hot water system and others, which we'll be able to fully correct a few valve issues that I've mentioned in our half year and previously, and we'll be able to fully correct that over those 24-day period. So there's no additional capital associated with the 24-day shutdown. It's all within our sustaining capital and our operating cost base. And upon delivering that, we see no reason why we shouldn't be able to deliver against our forecast rates at Waitsia.