Thank you for standing by, and welcome to the Cooper Energy Limited FY 2024 full year results webcast. All participants are in a listen-only mode. There will be a presentation followed by a question-and-answer session. If you wish to ask a question, you will need to press the star key, followed by the number one on your telephone keypad. 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 2024 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 two of the presentation before moving on to slide three. I'll start today by reflecting on the accomplishments we have achieved through FY 2024. FY 2024 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 four, we show the company's delivery against our business priorities as set out at the start of FY 2024. Production performance has steadily improved throughout the year, hitting multiple production records over the last 12 months. The improvement initiatives we have implemented at Orbost over the last year are now delivering new production records, and the plant recently started to operate consistently around its nameplate capacity. Orbost achieved an 11% improvement in production from the second half of FY 2023 to the second half of FY 2024, 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 cleans. As previously announced, the decommissioning of all seven 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-based reset through our transformation program, realizing AUD 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 timeline to first production in 2028. The drilling rig is expected to arrive in the Otway region in mid-2025 and commence drilling our first well in FY 2026. Finally, a lot of focus has gone into driving a performance culture that delivers on our promises. A critical 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 am 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 five. Our total recordable injury frequency rate for FY 2024 was 4.35 injuries per million hours worked, slightly below 4.38 recorded in FY 2023, and well below the industry benchmark of 5.86, despite the hours worked having tripled during the BMG Wells decommissioning project and our first full year of operatorship at the Orbost plant. Disappointingly, we did record one lost time injury, with a finger injury that resulted in a lost time period of three days. We maintained our exemplary environmental performance throughout the year, with no reportable or no notifiable environmental incidents in FY 2024. 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 six and an overview of the Orbost operations. The FY 2024 average processing rate at Orbost was 49.5 TJ per day, up 5.5% on FY 2023. Production rates increased by 11% in the second half of FY 2024 versus the prior corresponding period, largely due to the implementation of the Orbost Improvement Project initiatives and increased plant availability. Numerous improvement initiatives were implemented over FY 2024, focused on minimizing foaming and fouling in the absorbers and increasing the time between absorber cleans and reducing the duration of the cleans. The polisher unit had a significant positive impact on production this year. In late December 2023, a new type of polisher unit media was loaded and achieved a record life of nearly five months, 4x longer than the previous record. With the support of the polisher unit and other improvement initiatives. A record absorber runtime of six weeks between cleans was achieved over June, July 2024, compared to the previous typical absorber runtime of two to three weeks. Absorber two has currently been running for seven 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 nine 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 TJ 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-day, 60-day, and 90-day production record, with the plant producing an average of over 60 TJ 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 processing rate at Athena during FY 2024 was 10.4 TJ per day, net to Cooper Energy's 50% share. Low inlet pressure operations were successfully implemented in the beginning of FY 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 for the CHN fields. Production in Q3 FY 2024 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 continue to contribute good margin and cash flow, and a natural hedge for US dollar expenditure. slide eight provides a summary of our reserves position. Our 2P reserves reduced by 33 million bbl of oil equivalent, or approximately 202 PJ equivalent at the thirtieth of June 2024, mainly due to FY 2024 production of 22.7 PJ equivalent, with some very minor other revisions. Our FY 2024 2C contingent resources are unchanged on FY 2023. More detail on the movement in reserves and resources are contained in our announcement released on to 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 booking have had no major unexpected revisions in recent years. slide 9 summarizes the now complete BMG Wells decommissioning project. The BMG Wells decommissioning 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 Wells decommissioning program is expected to be around AUD 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 cost. 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 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 sea floor. 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 II 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 two to three 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 AUD 10.5 million in annualized net savings have been realized. With over a hundred initiatives identified across the business, around 85% of the identified initiatives were completed or actioned by the end of FY 2024, with the full effect of cost savings and benefits realized into FY 2025 and beyond. Significant savings in production costs were achieved across the business, in particular at Orbost. 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 2025, we have conducted half the number of cleans that we conducted in the same period during FY 2024. If this continues, we will significantly reduce the aggregate costs of the cleans this financial year. A great success of the program was a 24% reduction in annualized net G&A costs from FY 2023 to 2024, with further savings to come in FY 2025 as we move past the FY 2024 restructuring costs and other non-recurring 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 three-well program includes the Elanora well, with a sidetrack to Isabella and the Juliet and Annie wells. These fields are geologically similar to our existing discovered fields, and supported by amplitude seismic data, we have extremely high probabilities of gas discovery. We are also encouraged by the excellent 2P 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 unrisked resource potential through discoveries at Elanora, Isabella, and Juliet, while developing 65 PJ 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 Juliet, Elanora, and Isabella are all located within the existing production leases. The production lease application for Annie 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 TJ 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 costs 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 sanction drilling of our preferred program in FY 2025. We are maintaining the project timeline by procuring long lead items ahead of the drill rig's 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 265,000 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 Basin and Gippsland Basin. This is echoed by AEMO's in the latest GSSO, 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 PJ of 2P and 2C in conventional supply basins in the Otway, Bass, and Gippsland. This is equivalent to almost twenty-five years of current Victorian gas demand. I'll briefly recap on our FY 2024 financial highlights on slide thirteen, before handing over to Dan. In the June investor briefing, we talked specifically about our opportunities to expand production, margins, and cash generation. I'm pleased to say that in FY 2024, 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 2024 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%-90% of our daily gas production via medium or long-term contracts. Those contracts are predominantly to investment-grade off-takers at around AUD 9/GJ, 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 AUD 10-AUD 15 per GJ range. In June, the Victorian spot price spiked to AUD 28 per GJ, 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 2022 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 2022 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 2024 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 was 62.1 TJ equivalent per day, which is a record for the company and 4% above FY 2023. 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 2025 with average production substantially higher again. Pleasingly, despite an increase in production, absolute production expenses fell to AUD 59 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% to AUD 127.5 million compared to FY 2023, another record for the company. This highlights the cash generation potential of the business, and indeed, adjusted cash generated from operations for FY 2024 was up 20% to around AUD 115 million, excluding the BMG wells decommissioning spend and the other non-underlying and non-recurring items, which is also a record for the company. CapEx incurred for the year was about AUD 24 million, in line with guidance. As Jane has mentioned, we expect the total cost of the BMG wells decommissioning project to come in at around AUD 268 million, within the revised guidance range of AUD 240 million-AUD 280 million. This cost is spread across three 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 2023 and FY 2024 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 AUD 265 million. There remains a small amount of costs to be incurred on the wells program in FY 2025, which gets to the final number of around AUD 268 million. Speaking of Pertamina's 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 2024 income statement. That is due to two reasons: The majority of this relates to the increase in the BMG wells decommissioning costs from the amount that had been provisioned at the beginning of the year. As many of you know, we waited around four months for the Q7000 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 AUD 1.4 million, compared with an underlying loss after tax of AUD 5.6 million in FY 2023, 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 2024. Here we provide a bridge of FY 2024 underlying EBITDAX of AUD 127.5 million, back to the result for FY 2023 of AUD 109 million. Higher gas sales volumes and higher gas price realizations were the main driver for the improved result, 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 2025 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 2024, you can see the contribution from operations of AUD 121 million. This comprises total customer receipts, less total payments to suppliers and employees. Followed after is the impact of the BMG wells decommissioning project, which makes up almost the entire share of restoration costs. The BMG wells program consumed all the cash generated from FY 2024 operations and resulted in the increase in net debt. Other draws on cash were the first Orbost deferred consideration payment, which was paid back in July 2023, and CapEx payments of AUD 26.5 million. CapEx included regular stay in business spend, as well as procurement of some initial long lead items related to the East Coast Supply Project. Cash at June 30 was AUD 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 wells decommissioning program over FY 2024. 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, + 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 at 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 AUD 180 million balloon repayment, reflecting the confidence of the lenders in 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 AUD 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 five-year term out to 2029. Pushing out the loan 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 de-leveraging 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 2024 is AUD 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 non-recurring costs this financial year of AUD 2.2 million. Some of that relates to staff redundancies, and we also had some non-recurring compliance costs in the earlier part of the year. As a result, we look forward to further reductions in reported G&A- Ten seconds left. Consistent with prior years, today we are providing FY 2025 guidance. Your recording has reached its maximum length. To end, press hash. To cancel, press star. To- I'll just check with the operator. Is everything still fine with the call? Yes, please go ahead. Okay, we're on slide 21. Consistent with prior years, today, we are providing FY 2025 guidance on production, production expenses, and CapEx. FY 2025 group production guidance is 62- 69 TJ equivalent per day. The midpoint of FY 2025 production guidance assumes measured improvements at Orbost above the FY 2024 average production rate, offsetting declining productions from our mature wells in the offshore Otway Basin and Cooper Basin oil. Production expenses in FY 2024 are expected to total between AUD 55 million- AUD 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 non-recurring costs of up to an estimated AUD 12 million for general visual inspections of the Sole and CHN offshore pipelines. These inspections are once in every circa five years type of activity, which are scheduled as general integrity inspections. While we are conservatively guiding to this activity being performed in FY 2025, there is potential for a part of this work and the associated costs to push out into FY 2026. FY 2025 capital guidance, capital expenditure guidance is AUD 50 million-AUD 60 million, the biggest portion of which is long lead item procurement for the East Coast Supply Project. This is based on the company's preferred three-well program, with a partner sharing 50% of the costs. Up to an additional AUD 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 Orbost 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 Wells 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 - 15 + 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 five years. The great majority of that is represented in our 10% share in the Minerva decommissioning and the BMG Phase II 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 three 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 our 90% share in the BMG Phase II 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 five years arises from much smaller amounts related to small, a number of onshore wells. I'll now hand back to Jane to discuss FY 2025 priorities. Thanks, Dan. FY 2024 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 2025, anchored across these four key objectives. We will continue to focus on production performance across our portfolio. This will be driven by continued improvement at Orbost and improving reliability across both Orbost and Athena gas plants. We are targeting a group production run rate of more than 70 TJ 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 project. We will continue to progress the East Coast Supply Project, with the aim of locking in our preferred three-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 gas when our customers need it most. We will maintain our focus on the cost base to continue delivery of reductions 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 volume under our agreement with Alinta to provide as available gas to their Bairnsdale Power Station, which is just one hour's drive from the Orbost facility. Delivering gas to this power station when it needs it most allows us to capture a premium gas price with Cooper Energy and Alinta 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 their 2030 targets. Cooper Energy's gas is also produced locally in regional Victoria, and from our customer's point of view, locally sourced and used gas has lower, 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 2025 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 2025. In combination with our strategy reset and transformation program, Cooper Energy is future fit and positioned for growth. I'd now like to open the line for questions. Thank you. If you wish to ask a question, please press star one on your telephone and wait for your names to be announced. If you wish to cancel your request, please press star two. If you are on speakerphone, please pick up your handset to ask a question. The first question comes on the line of Dale Koenders with Barrenjoey. Please go ahead. Morning, Jane and team. I'm 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 2025 is really sort of the right level for the next few years before any production starts up? Or, you know, is there upside or downside risk to that number? Thanks, Dale. Look, the production over the last four to six weeks has been very strong, and we're obviously aiming at keeping that level of production going. What we have seen with the plant 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 sixties. Is that still how you're thinking about a midterm outlook? Yeah, sure. I'll hand to Chad to answer that. Yeah. Yeah, no, that's, that's correct. So that low 60s is still our, 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? Thanks. Yeah. 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 five 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 a member 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 wells activity will occur over the next 18 months or so, at some point in the middle or around the middle thereafter of next calendar year. That's a three-well decommissioning program that's to be undertaken. And then the second piece is our 90% share in the BMG Phase II equipment pickup, which Jane and I both spoke to. And we're pleased to be doing that, 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 two items of restorations that you should see coming through our cash flow statement over the next five years or so. Everything else is really 10-15 years at least away. And as I spoke to briefly, with further development in both our basins, repurposing as well the plants and fields that might be suitable for storage, et cetera, there's opportunities to continue to push back other activities. Okay. Do 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 costs and the learnings that you've seen from BMG Phase I and cost inflation you've seen in 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 BMG Phase II activity, and so you know, anything that's likely to occur in the next five 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 as you know, 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. Okay. Thank you. Thank you. Next question comes from the line of Nik Burns with Jarden Australia. Please go ahead. Yes, thanks. Hi, Jane and the rest of the team. First of all, congratulations on the result 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 2025 we should be thinking about? And is there planned pipeline inspection? Does that interrupt production in any way? Thank you. Hi, Nik. Chad here. The plant has a planned seven-day shutdown later on in the year. In terms of any planned pipeline work, it's none, 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 AUD 20 million if you for sole risking some of the long lead items for Otway. Can you just walk through the scenario 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. Yeah, if you can provide a comment on that, please. Thank you. Yep, sure. Thanks, Nik. Look, the program we're focused on is a three-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 subsurface 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 T- pieces in the existing pipeline. So in order to allow for that capital efficiency, we've proceeded with the three 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 misalignment in the JV. But we are really focused on a three-well development at 50%. Mitsui 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 project. 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 three-well development. That's clear. Thanks, Jane. Thank you. Next question comes from the line of Alistair Rankin with RBC Capital Markets. Please go ahead. Oh, good morning, Jane, Dan, and Chad, and thanks for taking my questions. Just first one on the target reliability loss of less than 2% from Orbost by the end of FY 2026. 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 reliability loss for FY 2025? Yeah. Hi, Alistair. So that 27% was total loss, so that includes planned and unplanned loss, not just reliability loss, which is the loss associated with things that break down. So far, year to date, our reliability loss. We're at our target, and that's 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 2026. 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. Is that a result of this clean-in-place process sort of being plumbed in and becoming part of BAU? 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 eight and a half 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. We'll be comparing that to the time that we would take to do a chemical clean-in-place. Yeah, that's clear. Thank you. And just one last one. You mentioned that on one 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 to the 15%. Yeah, thanks, Alistair. 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 2024. The 15% relates to activity that, for one reason or another, we couldn't get done and completed by the end of FY 2024. 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 2024. You will see activity focused on the operations and production side, but also on G&A and other costs in the business. So, you know, there's a range of things. We've talked historically, and you'll remember from the June investor briefing, that, you know, we have a view towards, you know, significant double-digit savings across both production expenses and G&A, and so that's what we're targeting. We'll give you regular updates. We'll certainly give a focus on that at the half year in February. So, you know, you'll see more information on costs across both G&A and production expenses as we look to go after further cost savings. Okay. Thanks very much. Thank you. Next question comes from the line of Louisa Ho with Maven Corporate. Please go ahead. Hi, Jane and Dan. Thank you for the informative update, and 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 Longtom 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 during the expected imminent shortfall from the East Coast? Thank you. Yep, sure. Thanks for the question. So we have an MOU in place with Seven Group to look at whether the system that Longtom pumps into can be restarted. So, if you're not familiar with it, the Longtom 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 going to look at the cost for repairing the umbilical, the condition of the pipeline, and then any plant modifications that are required to take that gas into the Orbost plant, obviously, without compromising the Sole 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 that assessment, we can determine jointly whether it's economically attractive to restart that asset and produce the Longtom gas through the Orbost plant into the East Coast market. Great. Thank you very much, Jane. Thank you. Next question comes from the line of Kieran Barratt with Petra Capital. Please go ahead. Hi, Jane and team. I was hoping we could shift gears for a moment to the Gippsland Growth portfolio, which, you know, understandably doesn't get as much limelight these days, given the Otway focus. Are you able to elaborate on your latest thinking for the Manta development? From a CapEx sequencing perspective, should we be thinking about it exclusively as backfill for Orbost? And then, yes, further to that CapEx sequencing, are you expecting an outcome around a sell down anytime soon? Yeah. Thanks, Kieran. So we are just about to kick off a farm down process for the exploration acreage, which includes Manta, Manta Deep, Wobbegong, and those assets. And looking to bring a partner in to help fund the exploration. The plan would be for that gas to backfill Orbost, as you've described, once the Sole field completes, which on a P50 estimate is likely to be well into the 2030. And that gas could tie into the Sole pipeline, or potentially Patricia-Baleen, depending on whether we restart Patricia-Baleen or use it for storage, and also the Longtom 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. Thanks for that. And just to follow up, if possible, like, if you do proceed with the sell down at Manta, does that kind of impact discussions with the ATO around potentially applying the PRRT credits from Manta across to Salt? On that issue, we're continuing our discussions with government to make sure that recommendation six of the Callaghan Review gets adopted. The government has said it plans to adopt all the recommendations, all 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. Thanks. That's it for me. Thank you. Our next question comes from the line of Stuart Howe with Bell Potter Securities. Please go ahead. Thanks. Hi. Hi, 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. There's 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. Yeah, maybe I'll start by just describing how we're thinking about the project in terms of the phasing. It's really a two-step project. The first part is a drilling program, which includes two exploration wells. So Elanora, Isabella is one well, but tests two prospects through the sidetrack, and then the Juliet 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 the most capital efficient project, we want to suspend 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 T-pieces, so this activity will be spread over around three 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 rig's 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. Then our drilling should be towards the end of that year and into early calendar year 2026. We'll provide more details on this, but the next step is effectively locking in the drilling program for those three wells with a partner. 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 that initial program? I think it's hard to be definitive right now, Stuart, in terms of timing. But, as Jane said, you know, this is our key priority, and we'll be giving it updates as regularly as we can. Right. Thanks, guys. Thank you. Next question comes from the line of Declan Bonnick with Euroz Hartleys. Please go ahead. Morning, Jane, Dan, and Chad. I was just wondering, that spend on the OGPP improvement CapEx of about AUD 10 million for financial year 2025. Could you just maybe go over what that is sort of looking at and the expected uplift in production that might target, please? Yeah. Hi, Declan. So, about half of that is for just things on our Orbost improvement plan that were already in the works, which had to do with things like changing our piping and a few of those other items in that. Just trials and continuation of things like the clean-in-place, chemical 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 2026. 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 result, team. Yeah, thank you. Thank you. A reminder to all the participants that you may press star one to ask a question. 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 TJ 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. Continuing to keep the cost base low and drive margin improvement through gas prices is the other area of focus. We're really pleased with the results from FY 2024, and they provide a really great platform going into FY 2025. So thanks again for joining us today. Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.