Amplitude Energy Limited (AEL) Earnings Call Transcript

Welcome to the Amplitude Energy Limited Fiscal Year 2025 Full Year Results Webcast. [Operator Instructions] I will now pass over to Jane Norman, Managing Director and Chief Executive Officer of Amplitude Energy. Please go ahead, Jane.

Good morning, and thank you for joining us. This is Jane Norman, and I'm joined today by our acting Chief Financial Officer, Eddy Glavas; and Chief Operating Officer, Chad Wilson. After the presentation, we'll be hosting a Q&A session, and we welcome your questions. Today's presentation and announcement were released to the ASX this morning and are available on the Amplitude Energy website. The webcast is being recorded, and the playback will be available on our website later today. Please note the disclaimer information on Slide 2 of the presentation before moving on to Slide 3. I'll start today by reflecting on our accomplishments through FY '25 compared to our business priorities set out at the start of the financial year. FY '25 marked yet another record year for Amplitude Energy laying the foundations for transformational growth. Firstly, on production, we exceeded our target with an average annual group production rate at 73 terajoules equivalent per day across the year. In June 2025, August averaged its nameplate capacity of 68 terajoules per day for the first time in its history and our group production run rate at the end of FY '25 with 77 terajoules equivalent per day. This was delivered not only by the strong performance at Orbost, but also strong reliability at the Athena gas plant, which delivered greater than 99% reliability across FY '25. Huge improvement compared to its historical performance. As we previously discussed, we are now investigating opportunities to push all this production beyond its nameplate capacity and on taking the required regulatory approvals. Secondly, on the East Coast supply project drilling program. As announced on the 1st of August, OG Energy's acquisition of Mitsui's 50% stake in the Otway Basin joint venture has now been completed. Their entry into these supply project back in March and their commitment to start paying their 50% share of project costs on the date of the signing has enabled us to lock in the 3-well drilling program with confidence. The project remains on track to bring gas online as early as 2028. In the last quarter of FY '25, we entered into front-end engineering design or FEED for the development phase of the project in preparation for connecting the wells as soon as possible. Thirdly, on increasing realized gas prices, the stronger market environment for domestic gas has delivered higher average realized gas prices of circa $10 a gigajoule to FY '25, 12% increase compared to FY '24. It is partially due to new short-term contracts we've signed off the back of stronger August performance, but also higher realized gas prices in our spot sales providing new opportunities to sell both into Sydney and Victorian market. Finally, we continue to build on the success of last year's transformation program to drive a mindset of continuous improvement identifying further opportunities and efficiencies across the business. Throughout FY '25, our continuous improvement program targeted cost reductions, value and system improvement with over 70 initiatives across the business, half of which were added through FY '25. For a business such as ours, keeping our costs flat as we increase production rates and revenue, drive margin growth and stronger cash generation to accelerate debt repayment and to fund our growth opportunities. Overall, this program has delivered circa $20 million in cash flow improvements in FY '25. The next slide, Slide 4 highlights how delivery of these priorities has translated into strong financial performance. We now assume the role of Managing Director in early 2023, one of the things I heard loud and clear from our shareholders the importance of delivering on our commitments. I'm proud of how the company has responded, building a consistent track record of performance. In FY '25, we delivered production and financial records across the board, including record production of 26.6 petajoules equivalent, up 17% on FY '24. We record revenue of $268 million, 22% higher than FY '24 a record underlying EBITDAX of $174 million, up 36% and representing a margin of 65% which is approaching industry-leading levels and record adjusted cash from operations of $160.5 million, 40% higher than FY '24 and corresponding to a yield of 20% on our enterprise value at the 30th of June. I'd also like to call out our declining unit production costs, which demonstrates the operating leverage within the business. Record low production cost of $2.33 a gigajoule in FY '25 represents a further 10% decrease from FY '24. We are pleased that underlying EBITDAX and cash flow from operations are demonstrating the company's strong potential for margin expansion and organic cash generation. This gives us comfort around our ability to manage our senior debt and to invest in growth. Amplitude Energy, we strive to build a performance culture that delivers on what we promise with strong gas market tailwinds behind us, improving production performance and the start-up of the ECSP, shareholders should expect continued improvement in profitability in the future. The following section goes into detail on our delivery against our priorities, starting with our safety and environmental performance on Slide 6. Safety is intrinsic part of the culture at Amplitude Energy and our safety performance through FY '25 was excellent. Our total recordable injury frequency rate in FY '25 was 3.36 injuries per million hours worked, well below the 4.35 recorded in FY '24 and and the industry benchmark of 5.16%. And we have now gone 18 months without recording a loss time injury. Our commencement to safety was evidenced when competing against our larger industry tiers, we received the industry recognition at the Australian Energy producers awards held in May, awarded for our outstanding performance on the BMG decommissioning campaign. With regards to the environment, we maintained our exemplary performance throughout the year with no reportable or notifiable environmental incidents in FY '25. We also maintained our carbon neutral certification with respect to Scope 1, Scope 2 and relevant Scope 3 emissions. These results illustrate our unwavering commitment to safety discipline and environmental excellence that is embedded in our operations and all activities. Turning to Slide 7, and an overview of August performance. The FY '25 average processing rate at August was 62 terajoules per day, up 25% on FY '24. Production levels steadily increased throughout FY '25 financial year as the benefits of our August improvement project began to show through in the processing and the general parts of the liability. These improvements stem from a combination of physical modifications undertaken at the plant over the last 18 months and a greater focus on operational excellence and gross efficiency. This has resulted in a significant increase in run time between the silver claims. It has now been over 3 months since we performed the last silver claim in August, quite a contrast to the nearly weekly claims we inherited when we took ownership at the plant. Strong absorber performance and additional redundancy provided by the H2S scavenger injection has enabled us again to defer replacement of the media in the polishing unit, which we will now look to do after. The polisher media was last replaced in early November 2024, over 9 months ago and again, a far cry from where polisher stood in 2023. With sulfur processing no longer creating a regular constraint on plant production we are assessing the potential to increase the plant's instantaneous nameplate capacity above 68 terajoules a day, 3d debottlenecking of the plant and inlet pipeline. Internal technical workers on this is completed, and we are now working through the required regulatory steps. The plants achieved reliability loss of 0.6% for FY '25 well ahead of the company's target for reliability loss of less than 2% by the end of FY '26. Moving on to our Athena Gas Plant and Cooper Basin production efforts on Slide 8. The average processing rated Athena during FY '25 was 9.4 terajoules per day net to Amplitude Energy's 50% share. The reliability of the plant has significantly improved compared to previous years, with 0.1% reliability loss, the proportion of asset capacity in FY '25 compared to 2.4% in FY '24. Regular cycling of the CHN wells was impacted between November 2024 and February 2025 by a failure of the CSN to hydraulic umbilical cable resulting in a temporary increase in the regular field decline over that period. Repairs to the umbilical in February 2025, we established communication to Casino 5, Henry 2 and Annie wells, allow cycling of these wells to resume. The company continues to assess the options to reestablish communication to the Casino 4 well. Our non-operated interest in the onshore Cooper Basin continues to contribute good margin and cash flow and a natural hedge on U.S. dollar expenditure. In the Cooper Basin and natural decline of the fields saw reduced production in the second half of FY '25, and we intend to pursue a new development campaign to the production rates. Slide 9 provides a summary of our reserves position. As of 30th of June were 31.1 million barrels of oil equivalent or approximately 191 petajoules equivalent. FY '25 production of 26.6 petajoules equivalent was offset by a significant upward revision in the estimate of expected ultimate recoverable volumes sold. We flagged in May and that more consistent production data from Orbost was increasing our confidence levels in the sole reserve estimate, and this continues to be the case. At the 1P level, the reserves revision replaced 100% of FY '25 production from Sol and 84% of production at a group level. Our FY '25 2C contingent resources are largely unchanged on FY '24. More details on the movement in reserves and resources are contained in our announcement released today to the ASX. Turning to Slide 10 now on our continuous improvement program. A key focus area over FY '25 was the continued building on the success of the FY '24 transformation program. to drive a mindset of continuous improvement, identifying efficiencies and opportunities to extract further value from operations. This year, the program is focused on delivering value and cash flow improvements. to improve productivity, margin exapansion and cost and emission reductions. In aggregate, the continuous improvement program realized around $20 million in cash flow improvements in FY '25. We with the completion of remaining initiatives expected to be realized -- to realize benefits in FY '26 and beyond. Around 70% of the value realized in FY '25 and grew new operational improvements at Orbost, primarily those associated with absorber cleaning and polisher treatment improvements. Gas marketing and trading initiatives to maximize the company's to realize a price contributed 15% of the value realized in the program of FY '25. Our corporate focus on cost control continued this year with a further $2.8 million reduction in G&A expenses in FY '25 compared to FY '24. We expect that the completion of some initiatives started in FY '25, combined with new initiatives, will sustainably reduce our cost base by over $5 million. in FY '26 relative to FY '24 as a baseline. Within this figure, we are anticipating cost reductions in waste disposal, maintenance and the pipeline management. This includes a successful project to commercialize the sulfur byproduct from August, which is now being used by local East Gippsland farmers as a soil additive for agricultural applications. These examples highlight the culture of continuous improvement within our organization and demonstrate what can be achieved with a collective mindset of thinking differently to look for new opportunities to do things better at reduce costs and improve our output. On Slide 11, we dive a little deeper into our investment and opportunities in the Otway. We are excited about the upcoming Transocean Equinox campaign in this region. Significant local and global investment has been committed to the Otway Basin with a 400-day drilling program over the next 12 to 18 months, highly sophisticated, distinct and global investors have chosen to commit growth investments of well over $1 billion to the basin. As you can see in the map on the right, our fields and infrastructure lies surrounded by permits and drilling activities of other operators. The chart on the left puts this campaign into historical context, you can see that after the first wave of exploration in the Otway for the Otway production for many years, exploration activities went relatively quiet for around 15 years. The focus on domestic gas exploration activities in Western Australia for many of those years. the lack of recent exploration and be a high-quality seismic data and strong local demand for gas combined to make the Otway Basin a very interesting and relatively low-risk exploration province. With exploration success, there are opportunities to face some participants to benefit from future activities, including vessel sharing, ground infrastructure synergies and activity scale benefits and so on. The Otway Basin is truly a strategic national asset differentiated from other domestic supply options it is proximal to mark with infrastructure needed to deliver the gas already installed. Gas supplies from the Otway is much more cost effective, lower emissions and faster to market than any gas imported for Northern Australia or offshore, Success in this rig could make a meaningful difference in increasing Australia's energy security. On Slide 12, we dive deeper into our opportunities in the Otway. Firstly, I think it's worth emphasizing again the excellent prospectivity of our Otway basin acreage, modern 3D seismic data, calibrated to the responses at the discovered fields have been formulated to derisk exploration. This has resulted in 16 gas discoveries from 17 seismic Amplitude support and exploration targets that have been drilled in the offshore Otway Basin by us and other and other operators. The ECSP prospects, Elanora, Isabella and Juliet have the same seismic responses at the adjacent gas fields, making us confident of their success and that among discovery, the new ECSP fields will have similar reservoir characteristics to the existing CHN fields. Further some prospects such as Neste, Pera and Peptans provide low-risk exploration upside for future drilling in our permits. Within the sector, it is unusual to see the probabilities of gas discovery is now as PGs as high as they are in our prospects. The fact that our prospects are located within the existing production licenses all services with project approvals and overall time line to first gas. On to Slide 13 now, where I'll speak about sweating our assets to their maximum potential. We are well positioned with 2 plants strategically located close to the largest demand centers in the domestic market. The replacement value of the 2 plants alone is over $1 billion with the cost and time involved in constructing greenfield sites becoming more and more challenging. Our focus, therefore, must be on unlocking the latest potential capacity in our existing plants and offshore infrastructure. First and almost, this means backfilling the Athena Gas Plant as we will do by the Escosupply project. Athena will continue to have latent capacity beyond the ECSP which means we would have the ability to toll third-party gas through the plant or tie in additional developments to offer high-margin peaking products to customers. We've spoken already about getting the most out of August as generation and margin benefits that accrue from doing so. Our improvement and development projects at Orbost are extremely capital efficient so the return to are excellent. A restart of our Patricia Baleen assets is also likely to be a high-returning portfolio accretive projects. We are undertaking the select phase of work on this now ahead of any decision. Our Patricia Baleen restart could also provide additional production and presents an interesting storage opportunity and potentially opens up an opportunity to process gas from Seven Groups, we have offed Seven Group Energy, the opportunity to participate in the select phase under a long-standing MoU between us since we acquired the OGPP in 2022. With that, I'll now hand over to Eddy to talk through the details of the FY '25 financials, starting on Slide 15.

Thank you, Jane, and good morning, everyone. I'll start my section highlighting another set of record results for the business across several key metrics. FY '25 marked the strongest year of production on record for Amplitude Energy. It is important to recognize that the company has now had 5 years of uninterrupted production growth with few companies in our sector able to claim this. The FY '25 results also represent the highest year on record for revenue, operating cash flow and underlying EBITDAX. It is increasingly apparent that we are now consolidating our position as a strong EBITDAX generator. I draw your attention to a key insight that sits behind these numbers. EBITDAX growth is outpacing revenue growth and revenue growth is outpacing production growth. Not only are we improving the price we are selling our product for, we are concurrently lowering our unit costs. This translates to an improved EBITDAX margin in FY '25 of 65%, well above the average for our industry. Let me now elaborate further on some of the key items. As Jane has touched on, production for this year was 73 terajoules equivalent per day, totaling 26.6 petajoules for the year. This is 17% above FY '24. FY '25 production was at the top end of our guidance range, which was revised higher twice over the financial year, and we exited FY '25 with almost running at its full nameplate capacity of 68 terajoules a day through June. Production expenses were also in line with guidance at $62.1 million for the financial year. Commensurate with increased production, there were some variable cost increases attributable to waste disposal and pipeline transport. But these increases were offset by savings from the continuous improvement program. As you heard we have initiatives currently underway, which we expect will generate additional savings in FY '26. On a unit cost basis, our production costs declined over 10% to $2.33 a gigajoule over FY '25. Underlying EBITDAX was $173.9 million, up 36% compared to FY '24 and as mentioned, another record for the company. This highlights the improving cash generation potential of the business. Adjusted cash generated from operations for FY '25 was up 40% to around $160 million. I note that this excludes nonunderlying and other nonrecurring items such as decommissioning spend. CapEx incurred in the year of $64.1 million, largely related to the ECSP. This includes the long lead items purchased on a 100% basis prior to OG Energy's entry into the Otway Basin. OG will reimburse Amplitude for 50% of all ECSP-related expenditure that was previously incurred on a 100% basis. This reimbursement will be in the form of a cost carry of ECSP expenditure in FY '26. It is important to note that with this transaction, our net exposure to ECSP from its inception has been reset to our 50% joint venture share. Restoration payments of $63.3 million predominantly relate to payment of final invoices for the BMG Wells decommissioning program, and Woodside Energy's Minerva program in which Amplitude Energy has a 10% interest. Underlying profit after tax for the year came in at $11.4 million compared with $1.4 million in FY '24, reflecting the impact of the improved production, the competitive gas market environment and disciplined and targeted cost control. Slide 16 provides further detail on EBITDAX in FY '25. Here, we provide a bridge of FY '25 underlying EBITDAX of $173.9 million, back to the result for FY '24 of $127.5 million. Higher gas sales volumes and higher gas price realizations underpin improved result, driven by the higher production at Orbost. This was slightly offset by lower crude oil revenue due to a decline in oil prices and production from the Cooper Basin impacted by the extensive basin white flooding. Increased cost of sales stem from higher variable pipeline-related costs and greater waste disposal due to the higher production and general visual inspection costs of the CHN pipeline. These were offset by lower G&A costs, which show a full year benefit of the FY '24 transformation program plus additional savings found in the FY '25 continuous improvement program. Although sales revenue has increased by 22%, the underlying EBITDAX has increased proportionately higher by 36%, as I alluded in my earlier remarks. This clearly demonstrates the strong operational leverage inherent in our business, increasing our operating margins as you often hear us speak about. On Slide 17, we provide a breakdown of cash generation over FY '25. We previously talked about the business now generating annualized underlying organic cash flow of around $150 million. This slide shows the simple maths behind that figure reconciled to our actual performance in FY '25. Cash paid for restoration activities consumed $63 million of our operating cash flows and we made a number of other smaller one-off payments in FY '25. When those are added back to the reported operating cash inflow figure, we arrived at an adjusted cash flow from operations of $160.5 million. The same business CapEx requirement of our business is not particularly high, typically around $10 million per year which leaves over $150 million of cash flow available for growth projects and debt repayment. We anticipate this picture will look better in FY '26. Restoration payments should be significantly lower than FY '25 with the largest item there being some residual payments for the Minerva Wells decommissioning program. Additionally, we would expect FY '26 operating cash flows to increase again based on expectations of higher revenue from Orbost and the focus on cost control that Jane spoke about earlier. This provides us with the financial flexibility to pay down debt while still funding growth. I will now round out this section on Slide 18 with some information on our gas sales performance. Our increasing exposure to the domestic spot market is largely due to the improved production performance of Orbost. In FY '25, we were able to sell over 30% of Orbost volumes into spot markets, up 15% in the prior year. During the financial year, we commenced sales from Orbost into the Sydney spot gas market in addition to the Victorian market. We do this by participating in a day ahead option for pipeline capacity from Victoria into Sydney. As you can see from the blue bars on the chart, the Sydney spot market often trades at a slight premium to its Victorian equivalent. From around August last year, the Sydney premium became wider and more volatile with Sydney spot prices often trading around $1 per gigajoule or more above Victorian prices. We generated additional margin through accessing the Sydney market and shaping spot sales to where gas is needed most. This was a contributor to FY '25 average realized gas price of $9.91 per gigajoule, being over $1 higher than FY '24 levels. And so far in calendar year '25, it has risen to over $10 per gigajoule. There is an increasing likelihood of higher and more volatile spot gas prices as gas-fired generation becomes more critical to firm the electricity grid. There is no escaping our growing energy appetite, particularly for the evening peak demand period. Society's push towards electrification is feeding a trend towards record-breaking demand in the National Electricity Market, commonly referred to as the NEM. In the last 12 months, coal-fired power generation contributed to approximately 52% of the electricity generated in the NEM. With an aging fleet of coal-fired power generators operating under a planned shutdown regime across the next decade, the energy mix is becoming proportionately more intermittent with the uptake of renewables. This creates volatility. Gas is the most viable, available and rapidly dispatchable alternative to displace coal, both in the short term to prop up the NEM when coal breaks down and more sustainable in the future as coal is gradually retired. Our business is premised on providing gas to the domestic market. We offer a rapidly dispatchable product available to households, industry and power generation by our existing ideally located infrastructure position. We are then able to create opportunity from the volatility in the NEM. Back to Jane now to speak to the East Coast supply project on Slide 20.

Thanks, Eddy. Over the last 2 years, we have been building a strong track record to deliver into our priorities and I look forward to continuing that in the execution of the ECSP. As a reminder, this is a 2-phase project. The first phase of the drilling and completion phase plans such that can, case, complete and on a subsea tree on our exploration wells on success to enable us to rapidly enter Phase 2, the development and tie back to the Athena gas plant. The ECSP is targeting to backfill the Athena gas plants with up to 90 terajoules a day of gross gas supply as early as 2028. The 3-well program includes an exploration well into Eleanora, then sidetrack into Isabella, an exploration well at Juliet and a development well into the already discovered Annie field. This drilling program is targeting more than 350 Bcf of gross mean unrisked prospective resource through discoveries that Elanora Isabella and Juliet, and the development of the 65 petajoules of 2C at the Annie field on a gross basis. Exploration success could deliver 2P reserves plus 2C resources equivalent to over a decade of production from the Athena plant. The Transocean Equinox drilling route is now working in the Otway Basin and is expected to commence drilling of our Elanora well around December this year. Detailed planning and engineering for the ECSP continued over the last 6 months with multiple contracts awarded during the quarter to progress drilling. Key long lead items, including subsea trees are on track to be delivered ahead of our drilling window. We also received the key approval required to proceed with the drilling phase of the project. Finally for the plant modifications and subsea development phase of the ECSP is also progressing. We've seen having been commenced on this phase of project and tenders for the subsea tie-in scope being issued over coming months. In the June quarter, we commenced a marketing campaign with the gas customers regarding foundation contracts for supplies from the project, which includes marketing gas on behalf of OG Energy. Amplitude Energy and OG Energy intend to proceed to a final investment decision to undertake the development phase of the project in the first half of calendar 2026. You will have heard me say before that there are no better projects in the oil and gas sector, the ones that tie in nearby conventional resources into existing infrastructure. These types of projects are always nearly always lower risk, faster to bring online and offer better economics. While significant upfront investment is required for the ECSP, the returns on this investment comfortably exceed our internal hurdle rates. I'll pass back to Eddy now on Slide 21 to cover the ECSP CapEx phasing and what success could mean for Amplitude.

Thanks, Jane. The information provided earlier this year in March 2025 regarding the indicative cost estimate for the ECSP remains consistent. What we have provided here outlines an indicative profile and pattern of cost commitments through the various phases of the project. It is important to highlight that the ECSP is effectively a brownfield near-field tieback campaign. The cost estimates assume an appropriate level of contingency with weather and downtime allowances, based on empirical data planned from previous Otway Basin campaigns. This is matched to the operability of the rig and other services required for subsea construction. Additional contingency is also applied at the suitable level for the class of cost estimation assumed. Given the phasing of the ECSP is over 3 years, the spend profile and pace fits within our funding capacity from a combination of the company's existing cash reserves, strengthening cash generation performance and the support of the APAC syndicated corporate facility. Deleveraging accelerates post the drilling campaign and our base case business assumptions -- and on our base case business assumptions, in the first year of plateau production, the business should be completely de-geared. The ECSP is transformational for Amplitude Energy and a crucial new source of gas supply for the East Coast gas market. This project has the potential to provide significant margin expansion and value accretion to our portfolio. With exploration success, the ECSP could increased group production to more than 100 terajoules per day or 36 petajoules per annum, grow revenue to around $500 million or more, grow group earnings over 2x compared to FY '20 levels with free cash flow over $300 million per annum, completely deleveraged the business in the first year of production when combined with the strong cash generation growing from Sol, increase our group reserves and resources, giving us steady plateau production across both the Otway and Gippsland basins, and extend the life of our Athena gas plant for at least a further decade. We are excited to embark on the next phase of growth with the drilling of Elanora and Isabella being the first major activity commencing in the next few months. I'll pass back to Jane for the concluding section now, starting with FY '26 guidance on Slide 24.

Consistent with prior years, today, we are providing FY '26 guidance on production, expenses and CapEx. FY '26 production guidance is 69 to 74 terajoules equivalent per day. The midpoint of the FY '26 production guidance assumes continued production increases in August above the FY '25 average production rate offsetting declining production from our mature wells in the offshore Otway Basin and Cooper Basin oil. The guidance range does not assume increases in August nameplate capacity which we are confident of achieving, but the timing and extent of which are yet to be determined. We will update production guidance during FY '26 as we receive greater certainty on this. Production expenses in FY '26 are expected to total between $54 million and $60 million. This range reflects the benefit of the cost-out transformation program detailed earlier, partly offset by general cost inflation. We expect other cash expenses and cost of sales in FY '26 of $24 million to $28 million. This includes the general and administrative, care and maintenance, royalty, transport and tolling costs and other cash OpEx items. I note it excludes selling and transport costs associated with accessing the Sydney spot gas market, which as a trading costs are difficult to forecast and offset by the higher revenue in any case. We expect additional nonrecurring costs of an estimated $16 million for general visual inspections or GPI of the Patricia Baleen and Sol offshore pipelines. These exterior integrity inspections are required once every 5 years or so. Followers of Amplitude Energy may recall, we guided to GBI costs for the CHN and Sol pipeline for FY '25, while saving this work could fall into FY '26. GBI of the CHN pipelines was completed in FY '25. However, the sold pipeline GBI was indeed deferred into FY '26 which allows us to save some costs when combining this work with the neighboring Patricia Baleen pipeline. FY '25 capital expenditure guidance of $125 million to $150 million the vast majority of which relates to the drilling of the Elanora and Isabella wells for the ECSP as well as speed and long lead order costs for the development phase of the project. This guidance is based on our 50% of project CapEx and the $28 million cost carry by OG Energy. CapEx guidance also includes a small amount of additional spend for Cooper Basin development activities. I'll finish now on Slide 25, which discusses our FY '26 priorities. With our base business performing strongly, we are now turning our focus to the execution of the ECSP, our transformational growth opportunity and one of the largest new gas supply projects progressing across Eastern Australia. In FY '26, we will continue to drive shareholder value through increased gas production into a tight market. Specifically, we have 4 clear priorities; firstly, progressing the ECSP. Which includes drilling the Elanora and Isabella it develop prospects, completing the development fee, securing gas sales agreement, upmarket prices, receiving all of our required regulatory approvals and taking FID on the development phase; second, maximizing our asset utilization, including increasing the capacity of Orbost to an instantaneous rate of more than 70 terajoules per day by the end of FY '26, while maintaining reliability loss of less than 1% across both plants; third, continuing to increase realized gas prices across the portfolio through our marketing and trading initiatives, including seeking opportunities to link our product to power generation; and fourth, continuing to reduce our production costs and streamline systems and processes through our continuous improvement program, growing our margins and improving cash generation. That brings me to the end of our presentation today. Our priorities for FY '26 are clear. We will continue to focus on driving value from our existing assets to increase cash flow. We will continue to work with stakeholders, regulators and customers to ensure we are in a position to sanction the development of the ECSP in FY '26. With the turnaround of the business in the last few years and a demonstrated track record of delivery, Amplitude Energy is future fit and uniquely positioned for transformational growth. I'd now like to open the lines for any questions.

[Operator Instructions] The first question today comes from Alistair Ranking with RBC Capital Markets..

Just firstly, on the guidance for FY '26. It's a touch below our estimates. So I'm just curious what picking the rough split of production rates from Orbost and sand other ads into those estimates.

Great. Thanks, Alastair. I'll answer that, and then I'll hand to Chad to provide a bit more detail the buildup on Obus reflects historical performance of the plant and the most recent -- the high end reflects the most recent performance. given we haven't done that policy since March this year, we are still trying to understand how the new system is going to work with the stainless steel packing. So the range really reflects the historic production and experience we've had over the last 12 months. So I'll hand to Chad to provide a bit more detail.

The other thing that we want to mention is that it doesn't include any debottlenecking work. The range assumes various reliability loss scenarios and it's stochastically built up from that, and those reserve between 1% to 5% for unplanned and planned reliability. That's how the range was built?

That's clear. Just on the Orbost increasing that nameplate, just sticking on that one actually. Are there any sort of regulatory hurdles that you've got to jump through to get that nameplate capacity increase over the line.