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 two of the presentation before moving on to slide three. I'll start today by reflecting on our accomplishments through FY 2025 compared to our business priorities set out at the start of the financial year. FY 2025 marks yet another record year for Amplitude Energy, laying the foundations for transformational growth.
Firstly, on production, we exceeded our target with an average annual gross production rate of 73 terajoules equivalent per day across the year. In June 2025, Athena 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 2025 was 77 terajoules equivalent per day. This was delivered not only by the strong performance at Athena, but also strong reliability at the Athena gas plant, which delivered greater than 99% reliability across FY 2025. Huge improvement compared to its historical performance. As we've previously discussed, we are now investigating opportunities to push Athena production beyond its nameplate capacity and undertaking the required regulatory approvals.
Secondly, on the East Coast Supply Project drilling program, as announced on the 1st of August, LG Energy's acquisition of Mitsui's 50% stake in the Otway Basin joint venture has now been completed. Their entry into the East Coast Supply Project back in March and then commitment to start paying their 50% share of project costs from the date of signing has enabled us to lock in the Three Wells drilling program with confidence. The project remains on track to bring gas online at building 2028. In the last quarter of FY 2025, 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 on domestic gas has delivered higher average realized gas prices of circa $10 a gigajoule to FY 2025, a 12% increase compared to FY 2024.
This is partially due to new short-term contracts we've signed off the back of stronger Athena gas plant performance, but also higher realized gas prices in our spot sales, providing new opportunities to sell into both the Sydney and Victoria markets. 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 2025, 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 2025. For a business such as ours, keeping our costs flat as we increase production rates and revenue drives 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 2025.
The next slide, slide four, highlights how delivery of these priorities has translated into strong financial performance. When I assumed the role of Managing Director in early 2023, one of the things I heard loud and clear from our shareholders was 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 2025, we delivered production and financial records across the board, including record production of 26.6 petajoules equivalent, up 17% on FY 2024, record revenue of $268 million, 22% higher than FY 2024, record underlying EBITDA 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 2024, 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 cost, which demonstrates the operating leverage within the business. Record low production cost of $2.33 a gigajoule in FY 2025 represents a further 10% decrease from FY 2024. We are pleased that underlying EBITDA 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 sector and to invest in growth. At 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 startup 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 six.
Safety is an intrinsic part of the culture at Amplitude Energy, and our safety performance through FY 2025 was excellent. Our total recordable injury frequency rate in FY 2025 was 3.36 injuries per million hours worked, well below the 4.35 recorded in FY 2024 and the industry benchmark of 5.16. We have now gone 18 months without recording a lost time injury. Our commitment to safety was evidenced when competing against our larger industry peers. 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 2025. 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 seven and an overview of Orbost's performance. The FY 2025 average processing rate at Orbost was 62 terajoules per day, up 25% on FY 2024. Production levels steadily increased throughout FY 2025 financial year as the benefits of our Orbost improvement project began to show through in the sulfur processing and the general plant reliability. 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 process efficiency. This has resulted in a significant increase in runtime between absorber cleans.
It has now been over three months since we performed the last absorber clean in Orbost , quite a contrast to the nearly weekly cleans we inherited when we took operatorship 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 polisher unit, which we will now look to do after the winter months. The polisher media was last replaced in early November 2024, over nine months ago, and again a far cry from where things 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 through de-bottlenecking of the plant and inlet pipelines.
Internal technical work on this is completed, and we are now working through the required regulatory steps. The plant achieved reliability loss of only 0.6% for FY 2025, well ahead of the company's target for reliability loss of less than 2% by the end of FY 2026. Moving on to our Athena gas plant and Cooper Basin production assets on slide eight. The average processing rate at Athena during FY 2025 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 as a proportion of asset capacity in FY 2025 compared to 2.4% in FY 2024. Regular cycling of the CHN wells was impacted between November 2024 and February 2025 by a failure of the CHN electrohydraulic umbilical cable, resulting in a temporary increase in the rate of field decline over that period.
Repairs to the umbilical in February 2025 reestablished communication to Casino 5, Henry 2, and Netherby 1 wells, allowing cycling of these wells to resume. The company continues to assess 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 edge on US dollar expenditure. Flooding in the Cooper Basin and natural decline of the fields saw reduced production in the second half of FY 2025, and we intend to pursue a new development campaign in FY 2026 to add to the production rates. Slide nine provides a summary of our reserves position. Our 2P reserves at the 30th of June were 31.1 million barrels of oil equivalent, or approximately 191 petajoules equivalent.
FY 2025 production of 26.6 petajoules equivalent was offset by a significant upward revision in the estimate of expected ultimate recoverable volumes of Sole. We flagged in May that more consistent production data from Orbost was increasing our confidence levels in the Sole reserves estimate, and this continues to be the case. At the 1P level, the reserves revision replaced 100% of FY 2025 production from Sole and 84% of production at a group level. Our FY 2025 2C contingent resources are largely unchanged on FY 2024. More details on the movement in reserves and resources are contained in our announcement released today to the ASX. Turning to slide ten now on our continuous improvement program. A key focus area over FY 2025 was the continued building on the success of the FY 2024 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 expansion, and cost and emission reductions. In aggregate, the continuous improvement program realized around $20 million in cash flow improvements in FY 2025, with the completion of remaining initiatives expected to be realized to realize benefits in FY 2026 and beyond. Around 70% of the value realized in FY 2025 can include new operational improvements at Athena gas plant, primarily those associated with absorber cleaning and polisher treatment improvements. Gas marketing and trading initiatives to maximize the company's realized gas price contributed 15% of the value realized in the program over FY 2025. Our corporate focus on cost control continued this year with a further $2.8 million reduction in G&A expenses in FY 2025 compared to FY 2024.
We expect that the completion of some initiatives started in FY 2025, combined with new initiatives, will sustainably reduce our cost base by over $5 million in FY 2026 relative to FY 2024 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 Athena gas plant, which is now being used by local 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, 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- 18 months. Highly sophisticated domestic and global investors have chosen to commit growth investment of well over $1 billion to the basin. As you can see in the map on the right, our fields and infrastructure lie 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, which formed the basis for the Otway production for many years, exploration activity went relatively quiet for around 15 years. The focus on domestic gas exploration activity moved to northern and western Australia for many of those years.
The lack of recent exploration and availability of 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 for all basin participants to benefit from future activities, including vessel sharing, brownfield 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 market with infrastructure needed to deliver the gas already installed. Gas supply from the Otway is much more cost-effective, lower emissions, and faster to market than any gas imported from northern Australia or offshore. Success in this region could make a meaningful difference in increasing Australia's energy security. On slide 12, we dive a little 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 de-risk exploration. This has resulted in 16 gas discoveries from 17 seismic amplitude-supported exploration targets that have been drilled in the offshore Otway Basin by us and other operators. The ECSP prospects, Eleanor, Isabella, and Juliet, have the same seismic responses as the adjacent gas fields, making us confident of their success and that upon discovery, the new ECSP fields will have similar reservoir characteristics to the existing CHN fields. Further seismic prospects such as Nesta, Para, and Pegdonese provide low-risk exploration upsides for future drilling in our permits.
Within the sector, it is unusual to see the probabilities of gas discovery, otherwise known as PGs, as high as they are in our prospects. The fact that our prospects are located within the existing production licenses also assists with project approvals and overall timeline 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 two plants strategically located close to the largest demand centers in the domestic market. The replacement value of the two 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 plant and offshore infrastructure. First and foremost, this means backfilling the Athena gas plant, as we will do by the East Coast Supply Project.
Athena will continue to have latent capacity beyond the ECSP, which means we will have the ability to toll third-party gas through the plant or tie in additional developments to offer higher margin peaking products to customers. We've spoken already about getting the most out of Orbost and the cash generation and margin benefits that accrue from doing so. Our improvement and de-bottlenecking projects at Orbost are extremely capital efficient, so the returns on success are excellent. A restart of our Patricia Baleen asset is also likely to be a high-returning portfolio accretive project. We are undertaking the select phase of work on this now ahead of any FID decision. A Patricia Baleen restart could also provide additional production and present an interesting storage opportunity and potentially opens up an opportunity to process gas from Seven Group locked on fuel.
We have offered Seven Group Energy the opportunity to participate in the select phase under a longstanding 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 2025 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 2025 marks the strongest year of production on record for Amplitude Energy . It is important to recognize that the company has now had five years of uninterrupted production growth, with few companies in our sector able to claim this. The FY 2025 results also represent the highest year on record for revenue, operating cash flow, and underlying EBITDA tax. It is increasingly apparent that we are now consolidating our position as a strong EBITDA tax generator. I draw your attention to a key insight that sits behind these numbers. EBITDA tax 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 EBITDA tax margin in FY 2025 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 2024. FY 2025 production was at the top end of our guidance range, which was revised higher twice over the financial year, and we exited FY 2025 with Orbost 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 2026. On a unit cost basis, our production costs declined over 10% to $2.33 a gigajoule over FY 2025. Underlying EBITDA tax was $173.9 million, up 36% compared to FY 2024, 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 2025 was up 40% to around $160 million. I note that this excludes non-underlying and other non-recurring items such as decommissioning spend. CapEx incurred for the year was $64.1 million, largely related to the ECSP . This includes the long lead items purchased on a 100% basis prior to LG Energy's entry into the Otway Basin. LG 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 2026. 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 Maneuver 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 2024, reflecting the impact of the improved production, the competitive gas market environment, and disciplined and targeted cost control. Slide 16 provides further detail on EBITDA tax in FY 2025. Here we provide a bridge of FY 2025 underlying EBITDA tax of $173.9 million back to the result for FY 2024 of $127.5 million.
Higher gas sales volumes and higher gas price realizations underpin the 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-wide flooding. Increased cost of sale will stem from higher variable pipeline-related costs and greater waste disposal due to the high 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 2024 transformation program, plus additional savings found in the FY 2025 continuous improvement program. Although sales revenue has increased by 22%, the underlying EBITDA tax 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 2025. 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 2025. 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 2025. When those are added back to the reported operating cash inflow figure, we arrive at an adjusted cash flow from operations of $160.5 million. The sustained 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 2026. Restoration payments should be significantly lower than FY 2025, with the largest item there being some residual payments for the Maneuver Wells Decommissioning Program. Additionally, we would expect FY 2026 operating cash flows to increase again based on expectations of high revenue from the 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 the Orbost . In FY 2025, 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 auction 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 our FY 2025 average realized gas price of $9.91 per gigajoule, being over $1 higher than FY 2024 levels, and so far in calendar year 2025, 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 displaced coal, both in the short term to prop up the NEM when coal breaks down and more sustainably in the future as coal is gradually retiring. 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 therefore 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 two years, we have been building a strong track record with the domestic job priorities, and I look forward to continuing that in the execution of the ECSP. As a reminder, this is a two-phase project. The first phase is a drilling and completion phase, planned such that we can case, complete, and run a subsea tree on our exploration wells on success to enable us to rapidly enter phase two, the development and tie-back to the Athena gas plant. The ECSP is targeting to backfill the Athena gas plant with up to 90 terajoules a day of gross gas supply as early as 2028. The three well program includes an exploration well into Eleanor with a sidetrack into Isabella, an exploration well into 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 resources through discoveries at Eleanor, 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 rig is now working in the offshore basin and is expected to commence drilling of our Eleanor well around December this year. Detailed planning and engineering for the ECSP has continued over the last six 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 approvals required to proceed with the drilling phase of the project.
Planning for the plant modifications and subsea development phase of the ECSP is also progressing, with FEED having been commenced on this phase of the project and tenders for the subsea tie-in scope being issued over coming months. In the June quarter, we commenced a marketing campaign with potential gas customers regarding foundation contracts for supply from the project, which include 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 than 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 early 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 gleaned 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 three years, the spend profile and pace fit within our funding capacity from a combination of the company's existing cash reserves, strengthening cash generation performance, and the support of the eight bank syndicated corporate facility. Deleveraging accelerates post the drilling campaign and our base case business assumptions. On our base case business assumptions, in the first year of plateau production, the business should be completely de-leveraged. 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 increase 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 two times compared to FY 2020 levels, with free cash flow over $300 million per annum, completely deleverage the business in the first year of production when combined with the strong cash generation growing from sale, increase our group reserves and resources, giving us steady plateau production across both the Otway and Gibson 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 Eleanor 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 2026 guidance on slide 24.
Consistent with prior years, today we are providing FY 2026 guidance on production, expenses, and CapEx. FY 2026 production guidance is 69 terajoules- 74 terajoules equivalent per day. The midpoint of the FY 2026 production guidance assumes continued production increases at Athena gas plant above the FY 2025 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 Athena gas plant 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 2026 as we receive greater certainty on this. Production expenses in FY 2026 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 2026 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 noted exclude selling and transport costs associated with accessing the Sydney spot gas market, which as a trading cost are difficult to forecast and offset by the higher revenue in any case. We expect additional non-recurring costs of an estimated $16 million for general visual inspections or GBI of the Patricia Baleen and Sole offshore pipelines. These exterior integrity inspections are required once every five years or so. Followers of Amplitude Energy may recall we guided to GBI costs for the CHN and Sole pipelines for FY 2025, while stating this work could fall into FY 2026. GBI of the CHN pipelines was completed in FY 2025.
However, the Sole pipeline GBI was indeed deferred into FY 2026, which allows us to save some costs when combining this work with the neighboring Patricia Baleen pipeline. FY 2025 capital expenditure guidance of $125 million to $150 million, the vast majority of which relates to the drilling of the Eleanor and Isabella wells for the ECSP , as well as fees 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 2026 priority.
With our base business performing strongly, we are now turning our focus to the execution of the ECSP, a transformational growth opportunity and one of the largest new gas supply projects progressing across Eastern Australia. In FY 2026, we will continue to drive shareholder value through increased gas production into a tight market. Specifically, we have four clear priorities. Firstly, progressing the ECSP, which includes drilling the Eleanor and Isabella prospects, completing the development fee, securing gas sales agreement at market competitive 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 the Athena gas plant to an instantaneous rate of more than 70 terajoules per day by the end of FY 2026, 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. Fourth, continuing to reduce our production costs and streamline systems and processes through our continuous improvement program, growing our margin and improving cash generation. That brings me to the end of our presentation today. Our priorities for FY 2026 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 2026. With the turnaround of the business in the last two 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 line for any questions.
If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you are on a speakerphone, please pick up the handset to ask your question. The first question today comes from Alastair Rankin with RBC Capital Markets. Please go ahead.
Good morning, Jane, Eddy, and the board of 10. Thanks for taking my question. Just firstly, on the guidance for FY 202026, it's touched below our estimates. I'm just curious, what are you expecting for the rough split of production rates from Orbost and Athena that feeds into those estimates? Thanks.
Great. Thanks, Alastair. I'll answer that and then I'll hand to Chad to provide a bit more detail. The buildup on Orbost reflects historical performance of the plant and the most recent, the high end reflects the most recent performance. Given we haven't done a builder clean since March this year, we are still trying to understand how the new system is going to work with the stainless steel packing. The range really reflects the historic production and experience we've had over the last 12 months. I'll hand to Chad to provide a bit more detail.
Yeah, thanks, Jane. The other thing that we want to mention is that it doesn't include any de-bottlenecking work. The range assumes various reliability loss scenarios, and it's stochastically built up from that. Those ranges are about between 1%- 5% for unplanned and planned reliability loss. That's how the range was built.
Okay, no, that's clear. Just on the Orbost increase in 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?
Sure. Chad, do you want to cover that?
Yeah, it's mostly a paperwork exercise, but we have had to do the paperwork just to increase the pipeline capacity to higher than the 68 terajoules a day. We're in the midst of that now.
Understood. All good. Okay, thank you.
Once again, if you would like to ask a question, please press star and one to enter the question queue. The next question comes from James Bullen with Canaccord. Please go ahead.
Good morning, Jane and team. Just a quick question here. Just around the 2028 timing for first supply from ECSP, could you tell us what's on the critical path to achieving that and what are the biggest risks to it?
Thanks, Jane. The project is targeting FID early calendar year 2026, which means we'll have the gas sales agreements in place to support those foundation contracts, and we will move to securing the services for the subsea tie-ins. We're looking at long lead orders for umbilicals and flow lines, given there's around a two-year waitlist at the moment for that. It's really a matter of contracting the services to tie those wells in, which is a relatively simple exercise. Getting that done ideally over the summer months is the plan because that will minimize waiting on weather and other sorts of risks to the program.
Thank you. There's also looking like there's going to be a change of operator in the Gippsland Basin with Woodside coming in. Could you provide us with maybe some of your initial thoughts around the threats and opportunities that could create for Amplitude ?
Sure. Thanks, James. It's a very interesting development, and certainly as we think about the backfill of the Orbost plant in the future, we have a number of prospects there in Manturam, Wobegong, and so on that sit very close to the Kipper Field and that Kipper Field infrastructure. It potentially opens up an opportunity. You know Woodside on record is saying they want to see domestic gas supply grow and that they're prepared to look at opportunities that Exxon wasn't willing to look at. That all sounds positive, and certainly we're interested in discussing those opportunities.
Thank you very much.
There are no further phone questions at this time. I'll hand it back over for any closing remarks.
Thank you, and thanks for the questions. We've had an exciting six months, and we've got another exciting six months coming up. We look forward to seeing many of you over the coming days and weeks, and we'll sign off for now. Thanks, operator.
That does conclude our conference for today. Thank you for participating. You may now disconnect.