Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Cooper Energy Limited FY '24 Full Year Results Webcast. [Operator Instructions] I would now like to hand the conference over to Ms. Jane Norman, Managing Director and Chief Executive Officer. Please go ahead.

Good morning, and thank you for joining the Cooper Energy FY '24 Results Webcast and Presentation. My name is Jane Norman, and I'm the Managing Director and CEO of Cooper Energy, and I'm joined by Chief Financial Officer, Dan Young; and Chief Operating Officer, Chad Wilson. After the presentation, we will be hosting a Q&A session, and we welcome your questions. The presentation and announcement were released to the ASX this morning and are available on the Cooper Energy website. Today's 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 the accomplishments we have achieved through FY '24. FY '24 was a pivotal year for our business. We delivered on our commitments, refreshed the executive team and rolled out our new vision, strategy, purpose and values. We have now set the direction for the business going forward and reset our company culture to be more performance and delivery focused. On Slide 4, we show the company's delivery against our business priorities as set out at the start of FY '24. Production performance has steadily improved throughout the year. hitting multiple production records over the last 12 months. The improvement initiatives we have implemented in August over the last year and now delivering new production records and the plant has started to operate consistently around its nameplate capacity. August achieved an 11% improvement in production from the second half of FY '23 to the second half of FY '24, but there is still more to do. We continue to methodically work through our planned suite of improvement opportunities, focusing on pushing out the time between absorber cleans and reducing the durations of the clean. As previously announced, the decommissioning of all 7 Basker-Manta-Gummy wells in the Gippsland Basin was completed in May. We are proud of the way in which the BMG Wells decommissioning program was safely executed, and its success is due to the hard work and dedication of our team and service partners. I'm very pleased to confirm that we have delivered a structural cost base reset through our transformation program, realizing $10.5 million a year in annualized net savings. Further to our update at the June investor briefing, our East Coast supply project remains on track with the procurement of long lead items required to maintain our target time line to first production in 2028. The drilling rig is expected to arrive in the Otway region in mid-2025 and commenced drilling our first well in FY '26. Finally, a lot of focus has gone into driving a performance culture that delivers on our promises A critical part of this has been -- part of this has been ensuring accountability at all levels in the organization as well as ensuring that we set the right behaviors across the business. I'm confident we now have the right team in place. This is a highly capable, highly experienced team with a track record for delivering transformational cost reductions and performance improvement. This team has the right attitude, the right culture and the ambition to deliver superior results for our shareholders. The following slide goes into the detail of our delivery against our priorities, starting with our health, safety, environment and community performance on Slide 5. Our totable recordable injury frequency rate for FY '24 with 4.35 injuries per million hours worked slightly below 4.38 recorded in FY '23 and well below the industry benchmark of 5.86 despite the hours work having tripled during the BMG Wells decommissioning project, and our first full year of operatorship at the August plant. Disappointingly, we did record one lost time injury with a finger injury that resulted in a lost time period of 3 days. We maintained our exemplary environmental performance throughout the year with no reportable or no notifiable environmental incidents in FY '24. We also maintained our carbon neutral certification with respect to scope 1, scope 2 and relevant scope 3 emissions. These results illustrate the discipline embedded into our operations and activities. Turning to Slide 6 and an overview of the August operations. The FY '24 average processing rate at Orbis was 49.5 terajoules per day, up 5.5% on FY '23. And production rates increased by 11% in the second half of FY '24 versus the prior corresponding period, largely due to the implementation of the August improvement project initiatives and increased plant availability. Numerous improvement initiatives were implemented over FY '24, focused on minimizing foaming and fouling in the absorbers and increasing the time between absorber cleans and reducing the duration of the cleans. The polish unit had a significant positive impact on production this year. In late December '23, a new type of polisher unit media was loaded and achieved a record life of nearly 5 months for longer than the previous record. With the support of the polisher unit and other improvement initiatives, a record absorber run time of 6 weeks between cleans was achieved over June/July 2024 and compared to the previous typical absorber run time of 2 to 3 weeks. Absorber 2 has currently been running for 7 weeks and counting. Earlier this month, we completed the fastest absorber clean on record. The clean was completed without confined space entry requirements in less than 9 hours and with gas-to-gas duration of less than 17 hours. These durations were less than half the time of the previous records. Pleasingly, these improvements have really started to show through in plant performance rates since July. Nameplate production of 68 terajoules for a full day was achieved in July; and average production has been sustained at near nameplate levels for almost the last month. We've hit a new 30-, 60- and 90-day production record, with the plant producing an average of over 60 terajoules per day for the quarter to date. Work continues to identify the root cause of the absorber foaming and fouling issues. While this work is ongoing, the success of the improvement initiatives, to date, has allowed Orbost plant to operate more consistently, and at higher rates. Further initiatives are being progressed to improve the reliability of the plant and maximize production rates, including further opportunities to extend the time between cleans and minimize the duration of cleans. With the recent production records, we have decided to stop work on the third absorber. Moving to our Athena and Cooper Basin production on Slide 7. The average food processing rate at Athena during FY '24 was 10.4 terajoules per day net to Cooper Energy's 50% share. Low inlet pressure operations were successfully implemented in the beginning of 2024, resulting in a production uplift of approximately 1 TJ per day on average compared to the expected decline rate. Well cycling operations continue to be implemented throughout the year to optimize production from the CHN fields. Production in Q3 FY '24 and was impacted by a planned maintenance shutdown and additional unplanned compressor maintenance. There have been noticeable improvements in plant reliability since then with stable operations in Q4 and zero reliability loss since the end of April. Our non-operated interest in the onshore Cooper Basin continued to contribute good margin and cash flow, and a natural hedge for U.S. dollar expenditure. Slide 8 provides a summary of our reserves position. Our 2P reserves reduced by 33 million barrels of oil equivalent, or approximately 202 petajoules equivalent, at the 30th of June 2024, mainly due to FY '24 production of 22.7 petajoules equivalent with some very other -- minor other revisions. Our FY '24 2C contingent resources are unchanged on FY '23. More detail on the movement in reserves and resources are contained in our announcement released onto the ASX on the 23rd of August. It's worth pointing out that consistent with recent years, our fields are performing in line with our expectations and that our reserves and resources bookings have had no major unexpected revisions in recent years. Slide 9 summarizes the now complete VMG Wells decommissioning project. The BMG Wells commissioning project was completed in May. The program incurred more than 360,000 work hours with no lost time injuries and no significant environmental incidents. The scale of the BMG program was significant in the history of decommissioning work in Australia, especially compared to the size of our company. A true reflection of the first-class capability of our workforce. The total cost of the BMG well decommissioning program is expected to be around $268 million, with the final value subject to remaining invoice reconciliation. Decommissioning costs were funded from cash on hand, organic cash generation and the existing senior debt facility. We continue to pursue our Supreme Court claim against Pertamina for their 10% share of the BMG decommissioning costs. Earlier this month, the Victorian Supreme Court issued a decision ordering Pertamina to file its defense by next week. This is a positive step forward. With the well's decommissioning now completed, we are in the early stages of planning for the second phase of work to pick up the remaining BMG equipment from the Gippsland C4. This is a much more straightforward project, utilizing a much lower cost support vessel. We have been working with the regulator to align the timing of the BMG Phase 2 work to occur at the back end of our East Coast supply project development activity. This will help minimize vessel mobilization and demobilization costs. It will also mean we can conduct the work around 2028 or so, or around 2 to 3 years later than previously estimated. Turning to Slide 10 now and our transformation program. The transformation program has been all encompassing, targeting savings and efficiencies across the entire business. To date, approximately $10.5 million in annualized net savings have been realized, with over 100 initiatives identified across the business. Around 85% of the identified initiatives were completed or actioned by the end of FY '24, with the full effect of cost savings and benefits realized into FY '25 and beyond. Significant savings and production costs were achieved across the business, in particular at August. A large part of the savings related to cleaning of the absorber beds, including renegotiating long-standing contracts with third-party contractors as well as reducing the time and frequency of the absorber cleans. So far in FY '25, we have conducted half the number of cleans that we conducted in the same period during FY '24. If this continues, we will significantly reduce the aggregate cost of the cleans this financial year. A great success of the program was a 24% reduction in annualized net G&A costs from FY '23 to '24, with further savings to come in FY '25 as we move past the FY '24 restructuring costs and other nonrecurring items. Dan will discuss this in further detail in his section. Slide 11 provides an update on the East Coast supply project. As many of you know, our preferred 3-well program includes the Elanora well with a sidetrack to Isabella and the Julia and Annie wells. These fields are geologically similar to our existing discovered fields and supported by amplitude -- seismic amplitude data, we have extremely high probabilities of gas discovery. We are also encouraged by the excellent [indiscernible] recovery factors that we have demonstrated in single well Otway producing fields where Cooper has an interest. Further detail on these recovery factors are provided on Page 32 in the appendix. The project could deliver more than 350 billion cubic feet of mean un-risked resource potential through discoveries at Elanora, Isabella and Julia while developing 65 petajoules of 2C at the Annie field on a gross basis. As a reminder, we have a 50% working interest in these assets. A key advantage of this development is that Julia, Elanora, and Isabella are all located within the existing production leases. The production lease application for Anie has been submitted following the successful Annie-1 exploration well, and is expected to be received prior to drilling. This approach shortens the approvals timeline allowing us to bring first gas online as early as 2028. The project is crucial for addressing the structurally short East Coast gas market. As we have previously outlined, the project is economically attractive, exceeding our internal project hurdle rates. We have strong customer support with significant interest in underpinning the development through foundation gas contracts. Our target project aims to deliver 90 terajoules per day through the Athena plant, positioning it as potentially the largest new domestic source of supply in the Southeast market. This is enough gas to supply over 600,000 Victorian homes with gas for heating, cooking and hot water. This development also has a minimal emissions footprint compared to alternatives -- it utilizes nearby gas flow lines and ties into existing infrastructure. The proximity to market and brownfield infrastructure eliminates the cost and environmental impacts associated with long-distance domestic gas transportation or imported LNG. We are working with stakeholders, customers and financiers to ensure we are in a position to sanctioned drilling of our preferred program in FY '25. We are maintaining the project timeline by procuring long lead items ahead of the drill rigs arrival in the region next year. There have been multiple independent technical assessments performed on the prospects, which confirm our view on gas in place and recovery factors. On Slide 12, we highlight that the need for this project is there and the other new gas supply is required, and is increasingly recognized by our key stakeholders and the general public. The public narrative around the need for new, local, gas supply has dramatically changed over the last year. While industry has been warning about the potential for gas shortfalls for many years, governments, regulators and the media are increasingly alive to the urgency of the issue. The market opportunity for our business is larger than ever. Gas is, after all, central to Australia's way of life. It is used for cooking and heating in our homes, to firm variable renewables in power generation, and in the manufacturing of everyday essential products such as food packaging, fertilizers and construction materials. In Victoria alone, some 265 sales and workers are employed across a broad array of manufacturing industries, which are reliant on affordable, reliable gas supply to keep their manufacturing operations running. The Australian government's future gas strategy released last quarter recognizes the critical role of natural gas and the importance of supporting the timely development of gas supply in existing basins such as our positions in the Otway and Gippsland basin. This is echoed by AEMO in the latest [ G-SU ], which forecasts a long-term increase in gas-powered electricity generation. as more variable renewables are added to the system and coal generation retires as part of Australia's energy transition. The shortage of gas supply is translating to higher market pricing and we expect this to continue, absent a significant source of new local supply. It is important to note that Victoria and Australia are not short of gas resources. On the contrary, in Victoria alone, there is approximately 6,500 petajoules of 2P and 2C in conventional supply basins in the Otway, Bass and Gippsland. This is equivalent to almost 25 years of current Victorian gas demand. I'll briefly recap on our FY '24 financial highlights on Slide 13 before handing over to Dan. In the June investor briefing, we talked specifically about our opportunities to expand production, margins and cash generation. While I'm pleased to say that in FY '24, the company achieved record results in these key metrics. Our declining production unit cost, in particular, showed the operating leverage that this business can deliver. As I stated in my introduction, we are striving to build a performance culture that delivers on what we promise. With the strong gas market tailwinds behind us, improving production performance, and the startup of the East Coast supply project, shareholders should expect consistent improvements in profitability over time. We have started to build this track record, but recognize that consistent delivery of results is required to continue to build trust and confidence in our business. During June's investor briefing, we talked about the potential for incremental margin enhancement and greater underlying cash flow generation, and you can see evidence of this getting delivered already across both unit production expenses and adjusted cash from operations. With that, I'll hand over to Dan to talk through the details of the FY '24 financials, starting on Slide 15.

Thank you, Jane, and good morning, everyone. I'll start my section with a few comments on the wholesale gas market. First, a reminder that on any particular day, we are selling 80% to 90% of our daily gas production via medium or long-term contracts. Those contracts are predominantly to investment-grade off-takers at around $9 gigajoule depending on contract nominations, and they are all indexed to inflation. The balance of our gas production is sold into the spot gas market. This chart shows spot market pricing in Victoria, which is the market where our spot gas is traded. Due to a warmer winter last year, 2023 spot prices were relatively stable compared to historical trends. However, average prices have trended upwards and now sit in the $10 to $15 per gigajoule range. In June, the Victorian spot price spiked to $28 per gigajoule, influenced by cooler weather, increased gas power generation amidst the wind drought and reduced supply from the Longford gas plant. Gas levels at the Iona storage facility are below 2021 and '22 levels, and well below 2023 levels for this time of the year, which does mean unexpected events can drive further volatility, including price spikes, as was commented in the press yesterday. As an example of that, you can see how the gas price spiked in winter '22 when there were unexpected outages in coal-fired electricity generation. We see an increasing likelihood of higher and more volatile spot gas prices as gas-fired generation becomes critical to firm the electricity grid in the evening peaks. This will create opportunities for us to supply gas when it is most needed to capture the peak pricing in the market. Turning now to some of the detail in our FY '24 financial results. Today, we've reported another set of record results for the business across a number of key metrics. As Jane has touched on, production for the year with 62.1 terajoules equivalent per day. which is a record for the company at 4% above FY '23. And despite a relatively weaker result for first quarter production, when some of the Orbost improvement trials resulted in increased plant variability, full year production ended up well within the top half of the original guidance range, and we have commenced FY '25 with our -- with average production substantially higher again. Pleasingly, despite an increase in production, absolute production expenses fell to $59 million(sic) [ $59.2 million ], within our reduced guidance range and reflecting a 7% decrease in the unit cost of production. A significant part of this reflects savings from the transformation program that Jane spoke to. Underlying EBITDAX was up 17% and to $127.5 million compared to FY '23, another record for the company. This highlights the cash generation potential of the business and indeed adjusted cash generated from operations for FY '24 was up 20% to around $115 million, excluding the BMG well's decommissioning spend and the other non-underlying and nonrecurring items, which is also a record for the company. CapEx incurred for the year was about $24 million, in line with guidance. As Jane has mentioned, we expect the total cost of the BMG Well's decommissioning project to come in at around $268 million, within the revised guidance range of $240 million to $280 million. This cost is spread across 3 financial years, and so it's a little tricky to track it in our financial statements. I would point investors to the accounting cost incurred line, which is in Note 15, the restoration provision note. If you add the FY '23 and FY '24 cost incurred line, and if you gross that number up from Cooper's 90% share to the full 100%, you'll get a number of $265 million. There remains a small amount of costs to be incurred on the well's program in FY '25, which gets to the final number of around $268 million. Speaking of Pertamina 10% share, I'd also echo Jane's comments that we continue to pursue our case through the Victorian Supreme Court for Pertamina to pay its share of the BMG oil decommissioning costs. There is also a restoration cost reported in the FY '24 income statement. That is due to two reasons. The majority of this relates to the increase in the BMG well's decommissioning costs from the amount that had been provisioned at the beginning of the year. As many of you know, we rated around 4 months for the Q-7000 vessel to arrive at the BMG location, which added considerably to the cost, alongside several other factors. The other reason for the income statement charge is a revision to the estimated cost of the second phase of the BMG decommissioning program due to general cost escalation, and costs for additional mobilization of equipment and vessels. Underlying profit after tax for the year came in with a small profit of $1.4 million, compared with an underlying loss after tax of $5.6 million in FY '23. And reflecting the impact of the improved production, the competitive gas market environment, and reductions to the group's cost base. Slide 17 provides further detail on EBITDAX in FY '24. Here, we provide a bridge of FY '24 underlying EBITDAX of $127.5 million, back to the result for FY '23 of $109 million. Higher gas sales volumes and higher gas price realizations were the main driver for the improved results, driven by the higher production at Orbost. We also had an extra crude oil lifting which resulted in higher crude oil revenue, partly offset by higher other OpEx. Lower G&A as a result of the transformation program also contributed, with the full benefit to be seen in FY '25 and beyond, as the restructuring costs are fully washed through. The increase in other costs at the end of the bridge includes costs associated with the assessment of the restart of the Patricia Baleen system. On Slide 18, we provide a 12-month cash bridge. As we step through the activities of FY '24, you can see the contribution from operations of $121 million(sic) [ $121.4 million ]. This comprises total customer receipts, less total payments to suppliers and employees. Following after is the impact of the BMG Well's decommissioning project, which makes up almost the entire share of restoration costs. The BMG wells program consumed all the cash generated from FY '24 operations and resulted in an increase in net debt. Other draws on cash were the first Orbost deferred consideration payment, which was paid back in July of 2023. And CapEx payments of $26.5 million. CapEx included regular staying business spend as well as procurement of some initial long lead items related to the East Coast supply project. Cash at June 30 was $14.3 million. Moving now to our liquidity position on Slide 19. As anticipated, we utilized a portion of our RBL facility to fund the BMG Well's decommissioning program over FY '24. Our RBL remains a highly effective form of funding for us maximizing upfront proceeds with a sculpted commitment reduction schedule. Our facility offers a competitive cost of funds, with debt service on the drawn portion at BBSY plus 325 basis points, or around 7.65%. The assessed borrowing base reflects the current quality of our conventional gas supply arrangements, selling fixed price gas with indexation and inflation into medium- and long-term gas contracts to predominantly investment-grade off-takers and with ongoing work to further reduce our cost base. The loan was established with a $180 million balloon repayment reflecting the confidence of the lenders and the financial position of the company in late 2027. The RBL is subject to an annual redetermination, which was undertaken late last year, and which we will shortly undertake again. Last year's redetermination established that the borrowing base is well above the fully committed and available $400 million and based on much lower assumed Orbost production rates than what we've seen since that time. This is an attractive backdrop as we look to the potential to unlock a portion of the accordion for the East Coast supply project. We have commenced a process to reset the loan back to a 5-year term out to 2029. Pushing out the long term will unlock additional significant funding flexibility during the East Coast supply project funding phase over and above the undrawn capacity today. Potential incremental funding from the accordion and the deleveraging we anticipate prior to the drilling program for the East Coast supply project will provide further funding flexibility. Turning now to G&A costs. Reported G&A for FY '24 is $14.5 million, a reduction of around 24% year-on-year based on reported numbers. Under the transformation program, we have successfully taken costs out of G&A across a wide range of areas, including people, the Board, the usage of consultants and T&E. As we spoke about during the June investor briefing, we are also mindful to ensure we don't shift a lot of headcount costs by reducing our own salaries and total comp, while simultaneously increasing consultant costs. We're also focused on ensuring these cost decreases don't get eaten away over time from increases in other areas. We spoke about the importance of margin enhancement at the June investment briefing and it continues to be a key theme as part of the increasing operating cash generation profile for the business. The incurred restructuring and other nonrecurring costs this financial year of $2.2 million. Some of that relates to staff redundancies, and we also had some nonrecurring compliance costs in the earlier part of the year. As a result, we look forward to further reductions in reported G&A [indiscernible]

Ten seconds left.

Consistent with prior years. Today, we are providing FY '25 guidance.

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Yes, please go ahead.

Okay. We're on Slide 21. Consistent with prior years, today, we are providing FY '25 guidance on production, production expenses and CapEx. FY '25 group production guidance is 62 to 69 terajoules equivalent per day. The midpoint of FY '25 production guidance assumes measured improvements at Orbost above the FY '24 average production rate, offsetting declining productions from our mature wells in the offshore Otway Basin and Cooper Basin oil. Production expenses in FY '24 are expected to total between $55 million to $63 million, excluding any third-party gas purchases and royalties. This range reflects the benefits of the cost-out transformation program detailed earlier, partly offsetting the costs of increased production and general cost inflation. Cooper Energy expects additional nonrecurring costs of an up to estimated $12 million for general vision inspections of the Sole and CHN offshore pipelines. These inspections are once in every circa 5 years type of activity, which are scheduled as general integrity inspections. While we are conservatively guiding to this activity being performed in FY '25, there is potential for a part of this work and the associated costs to push out into FY '26. FY '25 capital guidance -- capital expenditure guidance is $50 million to $60 million, the biggest portion of which is long lead or in procurement for the East Coast supply project. This is based on the company's preferred 3-well program, with a partner sharing 50% of the costs, up to an additional $20 million in CapEx budget -- CapEx expenditure is budgeted if the East Coast supply project long leads are funded on a 100% basis in order to maintain the project timeline. CapEx guidance also includes some additional spend at the Orbos plant as part of the improvement project, while noting that a decision has now been made to not proceed with a third absorber, and hence, there is no spend planned on that item. There is also a small amount here for umbilical maintenance on the CHN pipeline. Turning to Slide 22, where I provide detail on our decommissioning provisions. Firstly, it is worth noting that the completion of the BMG Well's decommissioning project has substantially reduced the total restoration provision on our balance sheet; and secondly, that more than 80% of the provision now relates to work expected to fall due at least 10 to 15 plus years from now. With further development of our discovered 2C contingent gas resources and our prospective resources across both basins, as well as the potential to repurpose certain of our assets, such as the gas plants and depleted gas fields that prove suitable for storage. This would ordinarily push some of these abandonment costs out further in time. The main purpose of this slide is to focus on decommissioning activity over the next 5 years. The great majority of that is represented in our 10% share in the Minerva decommissioning and the BMG Phase 2 equipment activity, both of which are called out on the left-hand side of this page. Plans by the Minerva operator should see wells decommissioning activity occurring around the middle of calendar 2025. We have a 10% interest here with the program focused on 3 subsea wells. Timing of this activity is subject to change, depending on the progress of the Equinox rig on its existing work program offshore Western Australia, as well as the final sequencing of the Otway rig consortium program. There is also a 90% share in the BMG Phase 2 project, which covers the removal of residual equipment from the sea floor, and which Jane described earlier. We're confident of our ability to move this activity to the back end of the East Coast supply project. It enables us to maximize potential savings by integrating the activity into the East Coast supply project. And of course, this activity phasing is a better value outcome for the group. The remainder of the decommissioning activity in the next 5 years arises from much smaller amounts related to small -- a number of onshore wells. I'll now hand back to Jane to discuss FY '25 priorities.

Thanks, Dan. FY '24 was a strong year for Cooper Energy, and I'm proud of the delivery against what we promised. My focus now turns to ensure we continue to deliver in FY '25 anchored across these fee -- these four key objectives. We will continue to focus on production performance across our portfolio. This will be driven by continued improvement at August and improving reliability across both Orbost and Athena gas plants. We are targeting a group production run rate of more than 70 terajoules a day equivalent per day by the end of the financial year. Our priority will be on maximizing cash generation and paying down debt, ahead of investing in our major growth projects. We will continue to progress the East Coast supply project with the aim of locking in our preferred 3-well drilling program in preparation for the arrival of the rig. We will increase our realized gas price through higher exposure to the tight spot market, and we are exploring opportunities to gain exposure to the spot spread by providing gaps when our customers need it most. We will maintain our focus on the cost base to continue delivery of reduction through the transformation program. Our intent is to leverage this to drive a mindset of continuous improvement to keep identifying opportunities to do things better, reduce costs, and improve productivity. We will also be giving more attention to improving energy efficiency, and reducing waste and emissions at our plants. This will not only maximize our sales gas volumes but position us as an operator of choice when looking at bringing third-party volumes through our facilities. With our production targets and East Coast supply project having been discussed at length during this presentation, I will wrap up by addressing the bottom two focus areas on the remaining slides. Slide 25 describes our first step in providing shaped gas products. Earlier in August, we were pleased to supply the first volumes under our agreement with Alinta to provide as-available gas to their Bairnsdale Power Station, which is just 1 hour's drive from the Orbost facility. Delivering gas to this power station when it is need -- when it needs at most, allows us to capture a premium gas price with Cooper Energy and Alinta of both saving on transport costs. As you can see from the chart, we delivered gas to Bairnsdale at a time of extremely high electricity demand and prices. Supplying our gas to Bairnsdale reinforces the critical need for physical gas to be available in the right places at the right time. Greater availability of gas powered generation, in general, will assist the market to moderate these kind of price spikes in future and provide firming power required for an increasingly renewable grid. In line with the government's future gas strategy, this is a great example of the important role of gas in ensuring energy security through Australia's energy transition. While the volumes supplied to date are small, the Bairnsdale agreement is a starting point for Cooper Energy to provide shaped gas products, meeting the changing demands of our customers. I'll finish now on Slide 26 and then move to Q&A. Cooper Energy is committed to playing our role in Australia's energy future. Looking at emissions intensity, our assets currently sit at the lower end of our peer group and even lower than some of our peers expect to achieve in the 2030 targets. Cooper Energy's gas is also produced locally in regional Victoria and from our customers' point of view, locally sourced and used gas has lower transport costs and emissions, meaning our gas is one of the lowest emission energy options for Australian customers. Our facilities are both well below the safeguard mechanism threshold. But this is not where we are stopping. We are proactively reducing our physical emissions and have set new targets for emission reductions as described on this page. That brings me to the end of our presentation today. Our priorities for FY '25 are clear. We will continue to focus on increasing Orbost production and generating incremental cash flow. We will continue to work with stakeholders and customers and financiers to ensure we are in a position to sanction drilling of our preferred program in the East Coast supply project in FY '25. In combination with our strategy reset and transformation program, Cooper Energy's future fit and positioned for growth. I'd now like to open the line for questions.

[Operator Instructions] The first question comes from the line of Dale Koenders with Barrenjoey.

Just wondering in terms of the production outlook and the 30-day record of 65 TJs a day for Orbost. Are we thinking that production guidance for FY '25 is really sort of the right level for the next few years, before any production starts up? Or is there upside or downside risk to that number?

Thanks, Dale. Look, the production over the last 4 to 6 weeks has been very strong, and we're obviously aimed at -- aiming at keeping that level of production going. What we have seen with the plants is there have been surprises in the past, and reliability has not been strong. We had 27% production loss last year. So we are being rightly conservative in the production guidance, but the production we've seen in recent weeks is consistent with the upper end of that range.

Okay. And in terms of, I guess, the sustainability rate for Orbost, you've previously spoken about something that would average, on an annual basis, in the low 60s. Is that still how you're thinking about a midterm outlook?

Yes. Sure. I'll hand to Chad to answer that.

Yes. No, that's correct. So that low 60s is still our long-term target, and that's averaged for the year, including all planned maintenance and planned shutdowns.

Okay. Thank you. And then maybe a question for Dan. Just in terms of how should we be thinking about the remaining decommissioning costs that exist for the business?

Yes. So the slide I talked through is really designed to answer the question of what's likely to come through the cash flow statement over the next 5 years. And really, the vast majority of that is, firstly, our 10% share in the Minerva activity over the next, call it, 18 months or so. Where the operator will be doing that work as part of the rig club that we're remember of. So depending on when the rig arrives and their sequence in that program, that activity is, as I say, sort of to occur, the well's activity will occur, over the next 18 months or so at some point in the middle of -- or around the middle thereafter of next calendar year. That's a 3-well decommissioning program that's to be undertaken. And then the second piece is our 90% share in the BMG Phase 2 equipment pick up, which Jane and I both spoke to. And we're pleased to be doing that at the -- sequencing that to occur at the back end of the East Coast supply project. So that's something around circa 2028 that we would be doing that. That's a much, much smaller piece of work. So those are the two really -- those are the [indiscernible] items of restorations and that you should see coming through our cash flow statement over the next 5 years or so. Everything else is really 10 to 15 years at least away. And as I spoke to briefly with further development in both our basins, repurposing as well of our plants and fields that might be suitable for storage, etcetera, there's opportunities to continue to push back other activity.

Okay. And the current provisions on your balance sheet with the increase that came through the P&L in the second half as well. Are they now reflective of the cost and the learnings that you've seen from BMG Phase 1 and cost inflation you've seen in the industry? Or are they still a dated estimate in some of these fields?

So we've revised -- as part of the exercise, we have revised the estimates for the BNG Phase 2 activity. And so anything that's likely to occur in the next 5 years, we feel very -- we feel like our provisions are strong. We have to review these every year, of course, and there will be changes as a result of a range of different things that may lead to those numbers changing over time. Because naturally, when we're looking out 10, 15, 20 years into the future we'll end up being wrong in some way, but we feel like there's a reasonable basis for everything we have in the balance sheet today.

Next question comes from the line of Nik Burns with Jarden Australia.

First of all, congratulations on the results and what you've been able to achieve at Orbost recently. Just following on from Dale's question in relation to Orbost, and I note your comment, Jane, around there is a level of conservatism in your estimates for this year. But just wondering, in addition to, I guess, unplanned downtime, is there any material planned maintenance in FY '25, we should be thinking about? And is the planned pipeline inspection -- does that interrupt production in any way?

Hi, Nik, Chad here. Yes, so the plan -- the plant has a planned 7-day shutdown later on in the year. In terms of any planned pipeline work, it's not thought to impact production.

Got it, okay. Thanks. And just a note on your guidance slide, you called out the potential for an additional $20 million if you sole risking some of the long lead [indiscernible]. Can you just walk through some scenarios from here, whether you would consider going sole risk on this? Is there an outcome where you do end up with 100% of the Otway program? And if that was the case, would you still commit to not just the firm well but the two exploration wells -- or the three wells? Sorry. Yes. If you can provide a comment on that, please.

Yes. Sure. Thanks, Nik. Look, the program we're focused on is a 3-well development at 50%, and we feel that's the right risk exposure for us and meets our funding availability and it spreads the risk of project development and subservice risk across those three opportunities. The long lead items that have been procured include trees for the wells, and we have previously talked about this program being optimized to be the most capital efficient possible. And that means that on a successful gas discovery, we plan to suspend the wells with trees, which means we can come back in the execute phase and simply tie those trees in with flow lines to the various key pieces in the existing pipeline. So in order to allow for that capital efficiency, we've proceeded with the tree orders for the second and third trees, and that's a significant saving in terms of capital optimization. The JV agreement does have sole risk provisions, as many of these do. And that would allow one of the parties to proceed if there was a misalignment in the JV. But we are really focused on a 3-well development at 50%, so we continue to run their sales process for their Otway position, and there's significant interest in that. We've talked before about running a data room with the details of the growth project. Mitsui didn't participate in the front-end engineering design work. And so they don't have all the details around the growth projects. So we've supported their sales process with a data room on the growth project itself. So we can see there's significant activity in that data room and significant interest in the assets. And hence, we're confident to be moving forward with procuring the long lead items for a 3-well development.

Next question comes from the line of Alistair Rankin with RBC Capital Markets.

Just first one on the target reliability loss of less than 2% from Orbost by the end of FY '26. You mentioned that it was about 27% this year. Just wondering what contributes to that loss? And based on the run rate over the last 35 days, what's the projected the liability loss for FY '25?

Yes, hi, Alistair. So that 27% was total loss. So that includes planned and unplanned loss, not just reliability loss, which is loss associated with things that break down. So far, year-to-date, our reliability loss -- we're at our target. And that's why we've -- partly why we've had such strong performance in production throughout the year. So we're continuing to invest in reducing that reliability loss even further, and we're still on track for that 2% by end of FY '26.

Okay. That's clear. Just on the clean in place process, you've been working on at Orbost. Given that fast clean that you had, I think you said it was about less than 17 hours in August. So is that a result of this clean in place process sort of being plumbed in and becoming part of [ CIU ]?

So the clean in place is a chemical clean in place. The quick clean that we did was just taking the principles of LEAN and applying that to remove all the waste from our cleaning process. The actual physical work for the cleaning process in that quick clean was 8.5 hours. The rest of the time was just bringing the unit down and starting it back up. With the chemical clean in place process, you still need to bring the absorber down and then bring it back up. So the target is really, can you get it faster than the 8.5 hours with the chemical clean in place. Through the LEAN process, we've highlighted a few other opportunities where we think we can continue to reduce that mechanical cleaning time. And we'll be comparing that to the time that we would take to do a chemical clean in place.

Okay. That's clear. And just one last one. You mentioned on 1 of the slides that the cost-out initiatives were 85% complete or actions. Just wondering what is remaining there and what kind of benefits we can expect from those remaining sort of 15%?

Yes. Thanks, Alastair. It's Dan. So the 85% number refers to the first sort of suite of initiatives that were identified and focused on in the course of FY '24. The 15% relates to activity that, for one reason or another, we couldn't get done and completed by the end of FY '24. There's a range of different things. It really is across the whole business. And so we're in, now, a second phase that is more of a continuous improvement phase, but also completing the things that we didn't get done in FY '24. You will see activity focused on the operations and production side, but also in G&A and other -- and other costs in the business. So there's a range of things we've talked historically, and you'll remember from the June investor briefing that we have a view towards significant double-digit savings across both production expenses and G&A. And so that's what we're targeting, and we'll give you regular updates. We'll certainly give a focus on that at the half year in February. So you'll see more information on cost across both G&A and production expenses is that we look to go after further cost savings.

Next question comes from the line of Luisa Ho with Maven Corporate.

Jane and Dan, thank you for the informative update, a majority of the questions have been answered. I just had a quick one. Could you please provide us with some more details around the MOU with SGH Energy? Which is in relation to exploring the development pathways for the long-term gas fields, such as some color on timing, estimated production should the MOU progress further with SGH Energy and Cooper Energy's ability to monetize the gas drink expected in the shortfalls on the East Coast?

Yes, sure. Thanks for the question. So we have an MOU in place with Seven Group to look at whether the system that long-term plumbs into can be restarted. So if you're not familiar with it, the long-term system plugs into Patricia Baleen and that pipeline back into the Orbost plant, there was a shut-in at the field because of an umbilical failure. And so the work that the MOU will cover is a technical assessment of what's involved in restarting which is, look, going to look at the cost for repair and the umbilical, the condition of the pipeline, and then any plant modifications that are required to take that gas into the Orbost plant. And obviously, without compromising the sold production too much. And so there's a technical service arrangement going to be put in place where we'll provide that analysis to Seven Group. And then on the back of the assessment, we can determine, jointly, whether it's economically attractive to restart that asset and produce the long-term gas through the orbost plant into the East Coast market.

Next question comes from the line of Kieran Barratt with Petra Capital.

And I was hoping we could shift gears for a moment to the Gippsland growth portfolio, which, yes, understandably doesn't get as much line light these days given the Otway focus. Are you able to elaborate on your latest thinking for the [indiscernible] development? From a CapEx sequencing perspective, should we be thinking about it exclusively as backfill for Orbost? And then, I guess, further to that CapEx sequencing are you expecting an outcome around the sell down any time soon?

Yes. Thanks, Kieran. So we are just about to kick off a farm down process for the exploration acreage, which includes Manta, Mantadeep, Wobbegong, and those those assets and looking to bring a partner in to help fund the exploration. The plan would be for that gas to backfill August, as you've described once the Sole field completes, which on P50 estimate is likely to be well into the 2030s. And that gas could tie into the Sole pipeline, or potentially into Patricia Baleen, depending on whether we restart Patricia Baleen or use it for storage and also the long-term processing we just discussed. So in terms of capital and phasing, yes, we definitely see that work and any capital expenditure taking place after the East Coast supply project and that Otway Basin growth project is online.

And just a follow-up, if possible, if you do proceed with the sell-down at Manta, does that kind of impact discussions with the ITO around potentially applying the PRRT credits from Manta across the Sole?

On that -- On that issue, we are continuing our discussions with government to make sure the recommendations [indiscernible] of the Callahan review gets adopted, the government has said it plans to adopt all the recommendations, or the remaining recommendations that have been implemented. And so we're continuing to discuss and encourage and reinforce the importance of delivering on that promise.

Our next question comes from the line of Stuart Howe with Bell Potter Securities.

Jane, and Dan, just on the East Coast supply project, and I understand you're not yet in a position to be able to provide capital cost estimates for that and some commercial things going on. Just wondering what are the steps over the next 12 or so months that we should wait for, that you will be able to then provide some guidance on the capital cost estimates, noting that, I guess, now it's scheduled to kick off within around 12 months?

Thanks, Stuart. Maybe I'll start by just describing how we're thinking about the project in terms of the phasing. It's really a 2-step project. The first part of the -- it is a drilling program which includes two exploration wells. So Elanora -- Isabella is one well, but test two prospects through the side track and then the Julia exploration well. And then Annie is a development well into an already discovered resource. So that drilling program will confirm the gas is available. And as I said earlier, in order to make this most capital-efficient project, we want to spend any successful wells with trees in order to minimize the capital and allow for an easy tie-in. The second phase of the project is the execute phase where we come back and tie all of the new wells in with umbilicals and flow lines into the existing pipeline and pieces. So this activity will be spread over around 3 years. And therefore, it can be funded from a mix of organic cash flow as well as debt facilities and the customer prepayments that we're currently discussing with a number of parties. The next trigger is firming up the option slots that we have provisioned on the rig and then waiting for the rig to arrive. At this stage, the rigs up in Crux, in the Crux field drilling there, and we expect it to arrive into the Otway Basin sometime in the middle of next calendar year, and then our drilling should be towards the end of that year and into early calendar year '26. So we'll provide more details on this, but the -- the next step is effectively locking in the drilling program for those three wells with a partner.

So I guess on the back of that, is it fair to say that we're sort of still 12 months away from having some understanding of the capital cost of the initial program?

I think it's hard to be definitive right now, Stuart, in terms of timing, but as Jane says this is our key priority, and we'll be giving updates as regularly as we can.

Next question comes from the line of Declan Bonnick with Euroz Hartleys.

I was just wondering that spend on the OGPP improvement CapEx of about $10 million for financial year '25. Could you just maybe go over what that is sort of looking at and the expected uplift in production that might target, please?

Yes, hi, Declan. So about half of that is for just things on Orbost improvement plan that were already in the works, which had to do with things like changing our packing and a few of those other items in that. Just trials that continuation of things like the clean in place, The other half of that is focused on bringing up the plant reliability to get to that 2% reliability loss by FY '26. So that is currently under assessment on what are the top priorities for us to reduce that reliability loss, and then we'll be executing that through the year.

Excellent. Thanks, Chad. And congrats on the great results team.

Yes. Thank you.

[Operator Instructions] There are no further questions at this time. I'll now hand back Ms. Norman for closing remarks.

Great. Thanks very much, and thanks to everyone for joining us today. We appreciate you attending. As discussed, the focus is really maintaining the improvement in production, getting the company run rate to over 70 terajoules a day equivalent by the end of the year and then progressing the East Coast supply project. And that is an absolute priority for us and a big focus of the company right now and continuing to keep the cost base low and drive margin improvements through gas prices is the other area of focus. So, we can -- we are really pleased with the results from FY '24 and they provide a really great platform going into FY '25. So, thanks again for joining us today.

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