Well, good morning everyone, and thank you for joining us this morning in Sydney for our investor briefing presentation and webcast. My name's Tom Fraczek, and I'm the new Investor Relations and Treasury Manager at Cooper Energy. Some housekeeping before we begin. In the highly unlikely event of an emergency, please exit through one of the three doors at the rear of the auditorium and follow the corridor to my right, to the fire exit, which is situated halfway down the corridor, directly opposite the bathrooms. I'd like to begin today's presentation by acknowledging the traditional owners of the land on which we meet today, the Gadigal of the Eora Nation. After our speakers have concluded today's presentation, we'll open the floor to Q&A here in Sydney and on the webcast.
To submit questions on the webcast, please click on the hand icon at the top right of the webcast window and enter your question in the text box. The presentation was released to the ASX this morning and is available on the Cooper Energy website now. Today's webcast is also being recorded, and the playback will be made available on our website later today. As we turn to page two of the presentation, please note the disclaimer information. Now turning to slide three, I'll take us through the agenda for today's presentation. Today, you'll hear from Jane Norman, Managing Director and CEO; Eddy Glavas, Chief Commercial Officer; Chad Wilson, Chief Operating Officer; and Daniel Young, Chief Financial Officer.
The agenda for today is as follows: firstly, Jane will take us through an overview of our new vision and strategy before handing over to Eddy to talk through Cooper's strong market opportunity. Chad will then take us through our assets and operations, followed by our growth opportunities. Lastly, Dan will close out today's presentation with an update on our financial position and growth funding options. With that, I'll hand over to Jane to begin on slide four.
Thanks, Tom, and good morning everyone here in Sydney and also on the webcast. I'm Jane Norman, Managing Director and Chief Executive Officer of Cooper Energy, and I would like to add my welcome to you all today as we launch our new strategy. Many things have changed since I started in March last year. Something that is front of mind for the industry today is our positioning with government. When I started, we were in the midst of the consultation process for the Mandatory Code of Conduct. Although we successfully achieved our exemption status, it seemed like every other week there was further intervention in a market that was viewed as broken, impacting confidence in our industry. With the release of the Australian Government's Future Gas Strategy a few weeks ago, it feels like we have finally turned the narrative around.
It recognizes that gas does have an important role to play in Australia's energy future and that more gas will be needed to 2050 and beyond. The Australian Government is now aligned with our view that gas has an ongoing role in manufacturing, residential use in hot water, cooking and heating, and a growing need in power gen to firm renewables. But even during that time, it was clear to me that Cooper Energy's strategy of focusing on the Southeast Australian gas market was the right strategy. If anything, the market fundamentals are even stronger today. In a similar vein, I feel our business has turned a corner. With the safe completion of the BMG wells decommissioning program, the structural cost reductions across the business, and the steadily improving production performance, we can now turn our attention to growth and share our strategy today.
Our strategy is about building on and maximizing the value of the strategic infrastructure positions the company and our shareholders have invested in. It's about working our assets harder as we face into the energy transition. This strategy respects the capital that our shareholders have put into the business to date and capitalizes on our infrastructure position to deliver compelling returns. On to slide 5. Before we speak to the longer term plans for the business, I want to reflect on what has been delivered in Cooper Energy at my time. Production performance has steadily improved as we consistently hit new production records. We have achieved an 11% improvement on average since taking control of Orbost, but there is still more, more to do.
We have been methodically working through a plan of improvement opportunities to stabilize production at Orbost, and we continue to progress further improvement in opportunities, such as the cleaning in place of the absorbers, which Chad will discuss in detail. As you will have seen from our recent announcement, we have now completed the decommissioning of all 7 Basker Manta Gummy wells in the Gippsland Basin. We are proud of the way in which the BMG well campaign has been safely executed, and its success is due to the hard work and dedication of our service partners and our team. 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.
With this hurdle cleared, we can now turn our attention to exploring the 1,300,000,000,000 cu ft of prospective resources in this Gippsland acreage, which of course, was the reason why we farmed into these permits in the first place, and Eddy will talk to that in further detail in the growth section. Dan will provide an update on the transformation program, but I'm pleased to confirm that we remain on track to deliver a structural reset with more than AUD 10 ,000,000 a year of annualized cost savings, and Chad will speak to our major growth project in the Otway Basin, which we have renamed the East Coast Supply Project, because no one could remember the name OP3D.
We have made a commitment to a rig, which is expected to arrive in the region in the second half of 2025, and we've procured the long lead items required to maintain our timeline, with first production expected in 2028. As the operator of two gas processing plants in Victoria, Cooper Energy is strategically placed to maximize value from this existing infrastructure. We have upstream, brownfield, backfill opportunities at both hubs, and Eddy will speak to margin growth opportunities we see in the portfolio. A number of you will have heard me say Cooper Energy has quickly transformed from an exploration company to the operator of two major facilities in Victoria, as well as our offshore assets. With this change in the business, we needed to adapt and bring in new operations capabilities and experience.
I've been focusing on driving a performance culture that delivers on what we promise. A critical part of this has been ensuring accountabilities at all levels of the organization, as well as ensuring we set the right behaviors right across the business. A key part has been refreshing the executive team, who are all here in the room with us today. The size of the team has been reduced, and five of the former executive team have now moved on from the business. The appointment of Chad Wilson in October last year to the newly created position of Chief Operating Officer completed the team, which was announced within my first six months of starting as CEO. The executive leadership team is an asset-based structure to ensure clear accountabilities. I am confident we 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 improvements. The team has the right attitude, the right culture, and the ambition to deliver superior results for our shareholders. Moving on to slide 6. For those of you who are new to us, Cooper Energy's business is now focused on the Southeast Australian domestic gas market. Our operated facilities in the offshore Otway and Gippsland Basin are supported by our corporate team in Adelaide, our engineering and technical team in Melbourne, and a small project team in Perth. Our competitive advantage is our tier one resources, close to established infrastructure and the domestic market. Our strategy over the last 10 years has been to farm into these basins because they are arguably Australia's super basins.
For decades, they have been the largest suppliers of domestic gas into the Australian market, and they continue to have significant running room. In Cooper Energy's acreage alone, we have over 2,000 petajoules of mean, unrisked prospective resource potential across the two basins, with potential to meet up to 10 years of Victoria's gas demand. With control of both the Athena and Orbost plants, we are also well-positioned to bring these resources to the market. The replacement costs for our plant are somewhere in the range of AUD 450 ,000,000-AUD 550 ,000,000 each, and as you would be aware, it is becoming increasingly challenging to build new infrastructure in today's environment due to both cost inflation and approval timelines. Our Melbourne engineering team of around 10 people is primarily focused on facilities engineering to support the Athena and Orbost plants.
Our small Perth team provides specialist offshore project expertise and is located near our offshore regulators and our key service partners who are required for our upcoming growth project. And finally, PEL 92. Although this is a relatively small component of our portfolio, our non-operated share of the onshore Cooper Basin continues to contribute good margin and cash flow and a natural hedge for US dollar expenditure. On to slide 7. Delivering on our strategy requires the right ESG framework. To ensure we can maximize production and reliability at our plants, our people need to be safe, and we need to protect the environment in which we operate. I'm pleased that we had 0 lost time incidents during the recent BMG campaign, which during execution, more than tripled our normal working hours for the organization.
We have also had zero reportable environmental incidents, and our total recordable injury frequency rate remains well below the industry average on a 12-month rolling basis. Our positive and proactive relationships with our stakeholders are very important to us, especially as we move into a period of growth, which requires timely approvals and workable pre-approvals to provide certainty for our projects. A great recent example of working with local landholders is the repurposing of the tubulars we pulled out of the BMG wells. These are gonna be used as fence posts at a local farm in the onshore Gippsland, near Barry Beach terminal, and this provides the mutual benefit. We receive some value for what would otherwise have been scrap metal, and the farmer saves money by using recycled materials.
In addition, since starting as CEO, I have focused on ensuring there are clear accountabilities across the business and a structured risk management framework that defines our risk appetite in the many facets of the business. Additionally, as we turn our minds to the growth project, we will be evaluating all investment decisions with strict investment criteria under our capital allocation process to optimize shareholder value. Slide 8 speaks to where we have come from as a company and how we are thinking about the future. Over the last 10 years, Cooper Energy has delivered its strategy of focusing on the business of the premium East Coast gas market. We remain confident this market will continue to drive growth for our business. Our growth strategy will leverage the unique infrastructure position we have established, enabling us to offer gas supply at multiple delivery points.
Stable, reliable production will remain the foundation of our business, which we aim to grow in terms of both value and volume. We have a unique opportunity to feed our undeveloped resources into this existing infrastructure, in an environment where building new infrastructure is increasingly challenging. At Athena, we have the potential capacity of up to 150 terajoules per day, more than six times today's throughput. Chad will speak further on the opportunities we are exploring to fill this allotment, but we are also open to tolling third-party gas through any spare capacity. We continue to optimize our gas plants for example, improving the energy efficiency, which we expect to not only increase the amount of sales gas available, but also decrease operating costs and decrease our emissions.
We see the opportunity to add margin to our product and shape - and the shape of gas as demand changes. As more gas is used in firming power generation, the value of gas available in the peak periods is expected to be substantially higher, incentivizing storage and shaping of gas supply. Today, we use line pack to manage our operational variability at Orbost. With stabilized supply, we will be able to use this line pack for commercial opportunities, linking our products to the electricity market and giving our portfolio optionality to choose the highest value outcome. Under our new strategy, it's our ambition to grow our infrastructure position into domestic energy hubs, working our assets harder to unlock value, growing our production volumes, and creating new products. Slide nine is our vision and strategy on one page.
Today, we are an upstream Australian gas company, which explores, develops, produces, and markets domestic gas into long-term CPI-linked contracts. We operate 97% of our production, which brings control and cost discipline. We are seeking to differentiate ourselves through discipline as an operator by creating value through niche offerings and focusing on the domestic market. We believe natural gas will maintain an important role in the energy mix, and therefore, our vision builds on this core business of gas exploration, production, processing, and sales. The Southeast Australian gas market is structurally short, and gas will be a scarce and valuable resource. To win in this future, we will focus on developments that leverage our existing infrastructure positions, respecting the capital that has been invested in this business.
As the shape of gas demand changes, we will also look to move further downstream to shape gas through storage services, leveraging our upstream footprint and capabilities to create new revenue streams and capturing value of delivering gas when it is needed. This also creates an opportunity to capture value from storing potential LNG imports. To play into the market trends, we will also work with our customers to create peaking gas products. As the gas and electricity markets become increasingly intertwined, we aim to grow our understanding of the electricity markets to ensure we are capturing opportunities that this presents. Longer term, we will explore other opportunities to add value to our infrastructure, such as carbon capture and storage and biomethane production, to ensure our role in a decarbonized energy future.
Delivering our vision and strategy should be measurable, and our priority is, of course, to deliver top-quartile shareholder returns. We will do this by maximizing our cash margins and improving the reliability of our assets as a disciplined operator. We will also grow our margins by generating revenues outside of the upstream gas position and create and deliver value in the energy transition. We see a long-term future for Cooper Energy in Australia's energy sector. This is the foundation of our new company purpose. We are proud to be part of Australia's energy future. Gas is a fuel needed for the future and to ensure energy security for all of our customers. To ensure we are successful in this future and deliver our strategy, we have simplified our set of company values.
We need to leverage the competitive advantage we have built as a nimble, pure play in the East Coast and think differently to our large competitors. As a company of approximately 120 employees, we can ensure our team is driving in the same direction to deliver together and to minimize doing business with ourselves and focusing on driving outcomes. And of course, we wanna get there while acting responsibly, ensuring that our people go home safely, and we protect the natural environment and the communities in which we work and live today for generations to come. Slide 10 maps out our three horizon strategy to deliver on our ten-year vision. Most of our resources will be focused on Horizon One, which is already underway.
This horizon is around strengthening and unlocking the latent potential in the business, maximizing production with an absolute focus on safety and operational excellence. We will maximize value through our existing infrastructure, with a relentless focus on efficiency and cost leadership to structurally lower the cost base. We will aim to deliver the Otway growth to rebalance our portfolio away from Orbost, which today delivers around 80% of our production. Horizon Two grows our core business in volume and adds margin by expanding into peaking gas opportunities. Building on our stable operational base, we will turn our attention to reducing waste, such as our sulfur by-product, and improving energy efficiency and reducing emissions. As we look to Horizon Three, we will also be looking for options to evolve and repurpose our infrastructure, such as using it for gas storage.
One potential opportunity that we are investigating is restarting Patricia Baleen and using this reservoir for gas storage. Another opportunity being explored is repurposing our permits in the Otway for carbon capture and storage. We also see the opportunity to blend renewable fuels, such as biomethane, which are drop-in fuels and can utilize the existing infrastructure. These longer-term opportunities position us in the energy transition and will take time to develop. Only around 10% of our resources will be directed to this horizon, with the majority of the business focused on driving and delivering outcomes in Horizon One and Two. Slide 11 provides clarity on what we will focus on. We are deliberately targeting high-value markets that align with our assets and capabilities. We will not spend energy and resources where we do not have competitive advantage.
First and foremost, as I've emphasized already, we will continue to focus on exploration, development, production, and marketing of conventional onshore and offshore gas here in Australia. We will work with third parties to maximize throughput through our infrastructure positions. We will seek opportunities to develop gas storage and peaking gas products to capture the value of our product that we see being added downstream. As we grow our capabilities in this space, we will look to selectively consider partnering in firming power generation to capture the spark spread we see today. We will explore ways to repurpose our existing infrastructure, such as our reservoirs for CCS and our processing plants for biomethane production and processing. Leveraging our carbon neutral position, we will also investigate building a portfolio of carbon offsets.
We will not pursue opportunities in frontier basins, as these will be much more challenging to bring to market when considering the lack of infrastructure, access to capital, and the cost of that capital. We will not pursue utility-scale renewable electricity, such as wind and solar. We will consider behind-the-meter renewable opportunities to support our own operations, but we do not have any competitive advantage in developing or owning large-scale renewable projects. We will not pursue hydrogen or other commodities, again, because these require a very different skill set to ours. And lastly, we will not pursue positions outside Australia. We believe that as the Australian gas market and the resource base best present the opportunities for growth for our business. Moving to slide 12. Here is our growth ambition. Our traditional upstream gas business has the potential to triple volumes from where we are today.
This growth trajectory can be delivered from the existing organic reserves and resources in our licenses in both the Otway and Gippsland basins, feeding back into our existing gas processing plants. With our own organic resources, we can increase our production potential to more than 20 years due to the significant running room we have in what are arguably some of Australia's super basins. On top of this volume growth, we will deliver margin growth from domestic gas pricing, moving to LNG import price parity, and from our Horizon Two and Three opportunities. We aim to shape gas through storage and line pack to access premium pricing and support growing demand for firming power generation. We will aim to lower our emissions through integrating renewable energy behind the meter and blending in biofuels, which can use the existing infrastructure.
We will look to develop low-cost carbon credit projects to meet our carbon neutral needs and explore CCS to create negative carbon projects. Our ambition is to deliver both volume and value growth. With the East Coast Supply Project coming online in 2028, if our average gas price was mid-teens AUD/gigajoule, this growth in our base gas production would see us deliver over AUD 500 ,000,000 per annum in revenue, more than to double today's revenue. With Athena cash OpEx expected to be around AUD 1 once the growth project is online, this is a high-margin, cash-generative business. Looking longer term, with the Gippsland Basin backfill of Orbost and potential expansion, we could triple gas production... Our ambition is to build a business which delivers in excess of AUD 1,000,000,000 per annum in revenue from our base gas business alone. On to slide 13.
Cooper Energy is committed to playing our role in Australia's energy future, and we have been certified carbon neutral since FY 2020, which means all emissions associated with the production and processing of Cooper Energy's gas at the point of sale have been offset. Looking at emissions intensity, our assets are currently on the lower end of our peer group and even lower than some of our peers expect to achieve with their 2030 targets. Cooper Energy's gas is also produced locally in Victoria, and from our customer's point of view, locally sourced and used gas has the lowest transport costs and emissions, meaning our gas is one of the lowest emission energy options for Australian customers. Our facilities are both below the safeguard baseline. But this is not where we're stopping. We are proactively reducing our physical emissions and have just set new targets for emission reductions.
I'm pleased to announce that for Scope One, flaring at Orbost, which has been the primary source of flaring associated with the sulfur fouling issues, we have announced a target of a 40% reduction by FY 2030. For Scope Two, at our Athena Gas Plant and our offices, which are connected to the National Electricity Market, our electricity demand is forecast to remain largely flat. Therefore, we seek to integrate renewable energy into our operations. Achieving this would reduce our Scope Two emissions, but also reduce our electricity consumption from the grid and our costs. These targets have been developed based on a suite of projects that our team has identified through workshops at both the Athena and Orbost gas plants, and Chad will speak further to these in his section.
I will wrap up the strategy section now on slide 14 with a summary of our investment proposition. We are a unique company, a gas E&P pure play in a highly attractive OECD domestic market. This market is facing looming shortfalls and trending towards LNG import price parity. We are an integrated operator with strategic infrastructure in place. We operate around 97% of production, giving us control of our destiny. We have low risk, high value, organic growth opportunities in established basins connected to our infrastructure. We have almost 600 BCF in the Otway Basin and over 1,300,000,000,000 cu ft in the Gippsland on a gross unrisked basis. Delivering the East Coast Supply Project in the Otway Basin would bring our group production to over 100 terajoules equivalent per day.
Assuming gas prices in the mid-teens, this growth will create a business with over AUD 500,000,000 per annum in revenues from 2028. We have strong organic cash generation, which will deliver deleveraging over the next two years and funding flexibility for our project opportunities. We are executing a strategy that is in complete alignment with the energy and decarbonization needs of Australia, and we are doing so with a relentless focus on safety, operational excellence, and a project delivery mindset. Coupled with our exciting plans for the future, we will reward you for your patience with both growth and returns. I will now hand over to Eddy to provide an update on the East Coast Gas Market, starting on slide 15.
Thanks, Jane, and on to slide 16. Good morning, everyone. I'm Eddy Glavas, Chief Commercial Officer of Cooper Energy. Before I go into the East Coast Gas Market in more detail, I'm going to start with highlighting the role of gas in Australia's economy. 27% of energy demand in Australia is met by gas. It can be divided into three main categories: industrial, residential and commercial, and power generation. The Australian manufacturing industry employs nearly 1 ,000,000 people and relies heavily on natural gas. Natural gas is a critical source of energy for Australia's manufacturing sector, with 91% of the gas used in manufacturing serving as either a heat source or as a feedstock, where natural gas molecules are chemically transformed into other products.
While gas continues to be a cost-competitive source of low-temperature heat to industry relative to electric alternatives, there are currently no ready substitutes to gas for high-temperature heat and feedstock applications. These applications are responsible for many essential products used in society, such as food packaging, fertilizers, and construction materials, all critical to Australia's supply chain security. Some specific examples include: the heart of Australia's dairy industry lies in regional Victoria and in the communities where Cooper Energy operates. This industry relies on gas for high-temperature applications to process milk and dairy products. Gas is required to make glass and plastics for food packaging, with Visy being one of Cooper Energy's foundation gas customers, enabling it to make these products. Gas is used at our paper mills and also to manufacture products such as toilet paper...
Early this year, we saw Sorbent shift some of its iconic brands and manufacturing of those overseas, mainly due to risks around gas supply. This resulted in circa 200 Australian job losses. To maintain sovereignty in manufacturing in Australia, we need to develop more affordable domestic gas supply. Moving manufacturing out of Australia only serves to shift emissions elsewhere and to potentially less regulated environments. This also creates new emissions from the freight of those products back to Australia. Offshoring risks Australian jobs and tax income for governments to fund critical services like health, education, and civil infrastructure. Neither our economy nor the planet will be better off, and this is a key reason to stimulate local domestic gas supply. I will now talk about the critical role of gas for power generation. Gas underpins the national electricity market.
Its fast start capability provides reliability and security to the electricity sector as more intermittent renewables are integrated. This is shown in more detail on slide 17. Slide 17 illustrates the role of gas in the electricity mix. The charts are taken from the Open NEM website, and this is a tool that provides data in real time and also contains all of the historic data for electricity supply and demand. The charts illustrate a snapshot of a recent week. There was nothing out of the ordinary in this particular week. It's a typical picture for this time of year. I'll draw your attention to the top half of this slide, which is South Australia. The electricity generation mix in this state gives us a window to the future, where the penetration of renewables is one of the highest in the world.
70% of electricity generation in South Australia over the last 12 months was from renewable sources. This compares with around 39% of the overall national electricity market, which is the bottom half of the slide. To explain the role of gas and its cohesive role with renewables, let's dive deeper into a recent week in South Australia. Note in the charts, power generated from solar is in yellow, wind is in green, and imports from coal-fired power generation in black. The small pink segments on the chart illustrate battery discharging energy into the grid, which typically only has low volume supply duration for about 2-4 hours. The dark red band is gas, illustrating its obvious role in firming the power generation mix as a reliable and flexible source of generation.
At the beginning of this particular seven-day period, on Friday and Saturday, there was ample wind and solar in the system. On these days, gas kicks in for the evening peak, typically triggered when the broader population gets home and turns on their appliances. This is a consistent demand peak pattern every day of the year. On Sunday, conditions became calm and overcast, and the wind dropped off. This can be seen by the narrowing of the green band, and to maintain electricity supply, natural gas ramps up and is rapidly deployed. Usually, this electricity generation pattern is combined with imported power to South Australia, illustrated by the black segment. Imported power is supplied from electricity interconnectors to the state, which is mostly electricity generated from brown coal in Victoria.
As coal-fired power generation is retired across eastern Australia and renewable penetration increases across the other states, we can expect this reliance on gas to increase even more. As I have described, this is how it works in South Australia, highlighting again, this is the state where renewable penetration is world-leading. As a society, our emerging behaviors and reliance on technology create an insatiable demand for energy. Reliability is therefore expected, with the consequences of interruption becoming increasingly impactful. The overarching point here is that gas provides reliable, dispatchable, and fast start supply in a system dominated by variable renewables. Slide 18 shows the latest step change outlook from AEMO's Gas Statement of Opportunities, released in late March this year. Compared to the previous outlook, gas demand is staying largely flat in our primary markets.
Although AEMO has assumed that residential demand will decline due to the government drive to electrification, industrial demand remains stable, and the decline in residential demand is offset by growth in power generation demand. I'll also draw your attention to the dashed line on the chart. This is what demand could look like if residential demand doesn't decline due to electrification. So as you can see by the gap to the dashed line, there is a big assumption in the AEMO data that households can rapidly convert their appliances over time and that distribution networks will be able to keep up with the growing demand. Slide 19 shows the supply-demand balance, assuming that electrification occurs and gas demand remains flat rather than grows. From the southern states of Victoria, New South Wales, South Australia and Tasmania, there is an urgent need for more gas to be developed.
The supply side has not changed much in recent years, with a steep decline forecast in existing production. AEMO assumes that more than 150 petajoules per year, or approximately 400 terajoules per day of production, could be redirected from Queensland. Even if this was to occur, leaving Queensland increasingly short to LNG export contracts, there is still a significant demand for more domestic production from the southern states themselves. This demand can be met by available indigenous domestic reserves and resources in the southeast. The latest data from Geoscience Australia shows that there is over 11,500 petajoules equivalent of 2P reserves and 2P resources across the Otway, Bass, and Gippsland basins. If developed, this could potentially supply the southern market for almost 30 years.
Although there remains a lot of resource in these traditional gas supply basins, there are very few projects aiming to bring new supply online in the near to medium term. We think our East Coast Supply Project in the Otway Basin is one of the largest gas supply opportunities in the southern states. It makes commercial sense, leverages existing infrastructure, and is close to the market. This is an attractive formula, therefore, the industry needs streamlined incentives to encourage investment. If you recall the growth ambition slide that Jane finished on, this chart shows a significant market opportunity for us to grow our gas supply. Even tripling our production volumes over the next 5-10 years won't fill the gap to the market. More projects are needed. This leads into contract pricing on slide 20.
Due to supply constraints that we are already starting to see in the market, our customers are telling us that they see LNG imports as the only alternative if more domestic gas cannot be developed in a timely manner. The cost of LNG imports represents a 60%-100% premium on current contract pricing, based on the sources shown on the slide. We expect future contract pricing to move towards this level. We continue to see a strong demand from our customers who are interested in any new gas we can bring to the market, including strong support for foundation contracts to underpin new gas development. We are also seeing customer appetite increasing to consider pre-paying for their gas to support funding new developments to when it is needed.
We're currently in discussions with a number of potential customers to support our East Coast Supply Project in the Otway Basin. Slide 21 shows spot market pricing in Victoria, which is the key reference market that we sell our Victorian portfolio into. Due to a warmer winter this last year, spot prices were relatively stable compared to historical winter trends. Currently, the gas supply system is operating close to capacity, and the market is finely balanced. There is a high likelihood that unexpected events during this coming winter peak will lead to volatility and high price spikes. Some indicators are that just 2 weeks ago, the Victorian spot price spiked to AUD 18 a gigajoule during a cold snap. We also observed that gas levels at the Iona storage facility are now both below 2021 and 2023 levels at the same time of the year.
I also note that today, the Victorian spot price is up to AUD 16. On the weekend, it was AUD 12. Today, we're selling about 10 terajoules into this spot pricing and possibly out to 15 tomorrow. In 2022, when unexpected outages in coal-fired electricity led to higher gas demand, you can see how much the gas price spiked in the colder months. As electricity demand increases due to the push to electrify residential gas demand and coal-fired power stations approach the target shutdown dates, volatility in gas demand is only likely to increase and place upward pressure on spot prices during peak periods. As demand grows in gas-fired power generation, we also see an increasing likelihood of higher and more volatile spot price, spot gas prices when gas-fired generation is critical in the evening peaks.
The opportunity will be to supply gas when it is needed to capture the peak pricing in the market. I'll speak more specifically about this opportunity in the upcoming growth section. Now, I'd like to hand over to Chad to provide an overview of our assets and our growth opportunities, starting on slide 22.
Thanks, Eddy, and good morning, everyone. I'm Chad Wilson, Chief Operating Officer, looking after development operations. I guess before I get started today, I just want to say, it's great to be here in Sydney. Growing up in rural Alberta, it was no surprise to me that I'd end up in the industry. Every school playground and every green space where I grew up had a producing oil well or a gas well. Our family farm had even, you know, some sour gas processing plants on it. So it wasn't a shock I'd end up in the industry. I guess what surprised me is that I'd end up all the way in Australia, doing it for the last decade or so.
So getting back to the presentation, Eddy's just outlined the supply and demand dynamics and pricing signals that are driving natural gas prices to LNG parity in the southeastern Australian market. This situation contrasts sharply with my previous roles, managing developments and operations at large cap E&Ps before joining Cooper Energy, particularly in the Australian Cooper Basin through 2015 to 2020, or the Western Canadian Sedimentary Basin during the Global Financial Crisis and the shale revolution... Back then, we faced a sharply oversupplied global market that drove prices down significantly. We had to respond swiftly by stripping costs out of the business and creating a lean, efficient organization. In the Australian Cooper Basin, we successfully reduced break-even prices from over $70 a barrel to under $20 a barrel.
At the start of that journey, I don't think anybody would have thought that achieving such a dramatic turnaround would have been possible. However, with a clear vision, defined milestones to celebrate along the way, a dedicated team, it quickly became reality. In Canada, the challenge was similar, but also involved fixing up an older sulfur plant with reliability problems. I bet that sounds familiar to lots of you in the room that have been following Cooper for a while. However, as reliability was reestablished at that facility and competitiveness through cost improved, the plant became a key midstream infrastructure hub that was attractive solution for third-party gas. These experiences taught me the critical importance of collaborating with our suppliers, service partners, customers, communities, and regulators to achieve good outcomes and lower cost operations. This is the mindset I bring to Cooper Energy.
By applying these principles, we've already seen improvements in both cost and production efficiency as we continue to embed these improvements into our operations. I'll speak to our current operations starting from slide 23. Over the past 8 months in this role, I've highlighted a clear trend of improved performance at Orbost. Since taking over operatorship in May 2023, our team has been methodically working through our identified list of improvement initiatives. It's gratifying to see these efforts deliver results, as evidenced by the steady increase in production shown in the chart. We're now setting a target to deliver group production of more than 70 terajoule equivalents per day by increasing the throughput at Orbost plant into the low 60s. Our strong performance in Q3 led to a record production, but there's still more to do. We're becoming more efficient managing the sulfur fouling issue at Orbost.
Key catalysts for further improvement moving forward include increasing polisher and absorber run lengths, quickly cleaning the absorbers when needed through initiatives like the chemical clean-in-place, and improving the overall reliability of the plant. On slide 24, I'd like to speak to a couple of initiatives that the team has been working on over the last several months that are supporting us in living with this sulfur fouling problem at Orbost more efficiently. This is helping us increment our production upwards. The first picture on the slide shows the inside of the absorber. It's a crucial component of the THIOPAQ sulfur treatment process. The absorber is where we observe the majority of the sulfur build up and foaming, which reduces the plant's ability to remove H2S. Following a detailed engineering assessment, we modified the absorber internals to improve the sulfur flow through the vessel.
The modifications included changing the top distribution plate to a four-nozzle spray distributor, filling the tower with alternate packing with larger diameter holes, and replacing the support bed at the bottom. The spray distributor and packing are shown in the picture. These changes were implemented in absorber 1 several months ago, and we've seen significantly reduced fouling and foaming. Instead of needing to clean the absorber every 2 weeks, we can now extend those intervals to as long as 5 weeks. This setup has now been installed in both absorbers. The second photo shows the inlet pipe to the polisher. The improvements in polisher run length have been outstanding, allowing us to operate the plant at consistently higher rates in both dual and single absorber modes. We're applying the same continuous improvement mindset to the polisher as we did with the absorbers.
As mentioned in the quarterly results, we have observed some water channeling in the polisher, which has been reducing the performance of the media somewhat. Insulating the polisher and the inlet pipes should minimize the water condensation that we're seeing, reducing that water channeling, enabling and enabling the polisher media to perform for longer. We're nearing completion of the insulation of the inlet pipe and the polisher vessel and are targeting run lengths of over eight months. The third photo is the absorber vessel. Following our recent update in the last quarter report, we've progressed to the next phase of in-situ washing, which is a chemical clean-in-place
We aim to make this more permanent solution to achieve the time and cost savings necessary for an average production rate in the low 60 terajoules per day, and we'll complete this work in two steps. The first step, starting in July, involves using the existing spare equipment with minor modifications in temporary piping for a fairly manual process that's operator-intensive. The second phase involves permanently piping in the equipment and automating the process as much as possible. We're currently working through that, the project phases, and we'll update the status of the permanent solution once the engineering is complete. The in-situ cleaning process should speed up the absorber cleaning time, reduce costs, and eliminate the HSE risks associated with mechanical cleaning. These three examples illustrate our approach to efficiently managing the issues in the sulfur processing plant.
Our ultimate goal, though, is to solve the sulfur deposition problem entirely by finding the root cause. Obviously, this has proven to be difficult, else it would have been done already. So we've been doing it in a parallel work stream to maintain the focus on getting more production immediately.... To work towards a root cause, we're collaborating with process and technical engineering experts, but we've also engaged data science companies and organizations to explore solutions using advanced analytics and machine learning. We're fortunate to have vast amounts of high-quality data. The tenders for this data science work were received last week, and we're currently under evaluation. As announced in early April, we also continue to work on the backstop option of the third absorber.
The engineering design and tendering for this project were completed in March, and the total cost is now estimated to be less than AUD 30 ,000,000, with a potential online date in November 2025. This is promising for the project's economics, and we're evaluating the decision as we continue to monitor Orbost improving performance as a result of the initiatives I've just discussed. As shown here on slide 25, we've also been working on improvements at the Athena Gas Plant in preparation for the East Coast Supply Project. The first picture on the slide shows the compressor house, where we've resolved the longstanding dry gas seal issues and successfully applied that solution to all the compressors. The second picture displays the inlet piping, where we completed the first stage of reducing the plant inlet pressure in December of 2023.
We went from 1,200 kPa to 800 kPa. This adjustment was crucial to maximizing production from our wells. Since these wells are depletion drive, the reservoir pressure and flow rate decrease over time. By lowering the inlet pressure, we reduce the back pressure on the wells, allowing them to flow at a higher rate for a longer period. The project has increased production by approximately 1 terajoule per day and enhanced our reserves as a lower inlet pressure enables more gas recovery from the wells. Those additional reserves have extended the expected field life of the Casino Henry and Netherby fields until our backfill project is complete and is expected to be brought online into the Athena Gas Plant, so that's after 2030. 2028 is first gas of the East Coast Supply Project.
As the field continues to decline, the plant could potentially operate with an inlet pressure as low as 600 kPa. Lastly, the engineering team completed modifications to enable the use of dual export lines from Athena. Previously, we relied on a commercial arrangement to ensure gas delivery, and that incurred a cost of over AUD 400,000 per year in fees. This is no longer necessary, significantly reducing our operating cost. These efforts, along with our other initiatives by our engineering team, have substantially improved plant performance, which I'll speak to on slide 26. With a portion of the improvement projects at Orbost complete and some higher reliability periods in January and February, we're able to set a record 12-day production rate of 62.8 terajoules per day and a 60-day rate of 55.2 terajoules per day.
That period of operation showed us what could be possible as we continue to complete the improvement initiatives and highlighted to us what the next set of constraints would be as we continue to optimize the performance. The chart shows reliability at both plants and optimization loss at Orbost, represented in green. That optimization loss is primarily due to the fouling in the absorbers and historic unavailability of the polisher. The prominence of the green bars on the chart highlights why that has been the main focus of our Orbost improvement initiatives. To increase the average rate at Orbost to the low sixties, excluding plant shutdowns, we need to reduce that number by at least half. Reliability loss at Orbost is currently higher than expected as well. However, the good news is that these issues can be more easily addressed with standard engineering and maintenance practices.
The main contributors to reliability loss have been foaming and other mechanical issues at the absorbers, the poor performance of the power generation equipment, and various instrumentation issues. We've automated the antifoam skid for the absorbers, we're restoring the redundancy of the power generation equipment, and we're systematically resolving the instrumentation problems. In contrast, optimization loss at Athena is minimal due to the plant's significant spare capacity and its status as a late-life asset. By focusing on the equipment bad actors at Athena, we've reduced the reliability loss from 11% in FY 2023 to 4% in FY 2024. The primary cause of reliability loss at Athena has been the compressors and their ancillary equipment, which I've discussed before. And many of these issues were addressed during the shutdown last quarter, and we're already seeing the benefits.
Our objective is to achieve a 2% reliability loss at both facilities by the end of FY 2026, well before our growth opportunities come online. On to slide 27, where I'll talk about our efforts in a more commercial approach to minimizing our footprint. In the last year, we've developed a process that enable us to identify, assess, and develop emissions reduction and energy efficiency projects across our operated assets. We've completed workshops at both sites over the last 12 months and identified over 100 opportunities. Four of these opportunities have already been implemented, contributing to lower production costs base that we've seen through FY 2024. The delivered opportunities reduce physical emissions by approximately 4,000 tons of CO2 equivalents, which has a real cost benefit as it reduces the number of credits that we need to purchase to maintain our carbon-neutral position.
Additionally, these projects often reduce our fuel gas consumption, which makes that gas available to market. Today, I want to give you two examples of the opportunities that we've implemented already. First, optimization of the thermal oxidizer at Athena Gas Plant. So the thermal oxidizer is a piece of equipment that burns waste products at a high temperature to ensure we remain compliant to our emissions limits. It burns fuel gas to do so. So quite simply, this optimization's meant turning down the temperature when we know it's not required. Sounds simple. It was simple, but this has meant us saving approximately AUD 250,000 per year in fuel gas, which is then available for sales. Second, during the recent shutdown at Athena, we adjusted the combustion parameters of our three turbines to optimize fuel gas.
This is expected to save approximately AUD 300,000-AUD 400,000 per year in fuel, which we're currently in the process of monitoring the outcomes and validating those savings. In addition to reducing our carbon emissions, we're working at reducing our waste through the initiatives such as the beneficial reuse of our sulfur product produced at the Orbost plant. Our sulfur product is currently disposed to landfill and costs about a $1,000,000 per year for the transport and disposal costs. I'm pleased to announce that we've commenced a trial with a local farming cooperative, the Gippsland Agricultural Group, where they'll use our sulfur product and compare its performance to a conventional sulfur-based fertilizer product. If this trial is successful, there's mutual benefits. First, our sulfur ends up having a commercial value rather than being a waste.
Secondly, the local agriculture community would have access to a local source of biologically produced sulfur, reducing the need to transport fertilizer into the region. This would be a true demonstration of the circular economy. We're also currently in a tender process for our waste services at both Orbost and Athena, streamlining our contracting processes and maximizing economies of scale. We hope to finalize this by the end of financial year and see the benefits flow through to FY 25 and beyond. As part of the waste tender, our shortlisted tenders are proactively working with us to further opportunities to reduce costs and waste on-site, such as the on-site treatment for our bleed water. These improvements are a snapshot of what we've been working on and could be delivering upwards of AUD 2 ,000,000 per year of savings.
Turning to slide 28, where Eddy and I will speak to our growth opportunities in the next section. On to slide 29. As many of you know, we've been pursuing an opportunity in the offshore Otway for several years. The project entails a 3-well program that could potentially add more than 350 Bcf of gross contingent resource to our portfolio in a success case. Additionally, it would develop 65 petajoules of gross 2C resource already booked. As a reminder, we have a 50% working interest in these assets. This project is crucial for addressing the structurally short East Coast gas market. As we've previously outlined, the project is economically attractive, exceeds our internal project hurdle rates. We have a strong customer support with significant interest in underpinning the development through foundation gas contracts.
Furthermore, as announced earlier, we have joined a rig consortium that will bring a rig to the region the second half of 2025, establishing the timeline for our drilling. We aim to achieve first gas by 2028, realize large contingent resource adds for the future, and book and produce 2P reserves to satisfy our customer needs. On to slide 30. So our target project aims to deliver up to 90 terajoules per day through Athena, positioning it as one of the largest new sources of supply to the Southeast domestic market. The preferred drilling program includes the Elanora well with a sidetrack to Isabella, as well as the Juliet and Annie wells. A key advantage is that Juliet, Elanora, and Isabella are all located within existing production leases.
The production lease application for Annie has been submitted following the successful one, 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, as mentioned. And as already mentioned, the project could deliver more than 350 Bcf of mean unrisked resource potential, with a 98% chance of at least one gas discovery at Elanora, Isabella, or Juliet. It also develops the 65 petajoules of 2C at the Annie field. Additionally, as we further prove gas in the fields, it reduces the risks associated with other fields, fields highlighted in teal on the map.
Fields such as Hera, Pecten East, and Nestor, and future additional development of Elanora and Isabella to, to access all the resource that we find there, could constitute the next tranche of development, significantly prolonging the life of the producing assets well into the future. This development has minimal emissions footprint compared to alternatives. It utilizes nearby gas processing and existing brownfield infrastructure. The proximity to market eliminates the costs and the environmental impacts associated with long-distance gas transportation, including the significant emissions from importing LNG, if that becomes the norm in Australia. Slide 31. Slide 31 highlights the Elanora and Isabella prospects. These are our largest potential resource bookings in the Otway. As discussed previously, our plan is to drill a well into Elanora with a sidetrack into Isabella from a single surface location, as shown in the schematic on the left.
If the results at Isabella meet our expectations, we'll continue to complete that well as a future producer. Its proximity to a pipeline tie-in point, which is approximately six kilometers away, will make this development relatively straightforward. We're excited about drilling the Elanora prospect in the upcoming rig campaign. Many of you may recall that the well had been planned to be drilled in 2019, but operational issues prevented this. With a revised drilling plan, however, that allows us to test both Elanora and Isabella from the same wellbore, we've effectively doubled the prospective resource being tested. In a success case, we could prove up more than 300 BCF of gas. Like the successful Annie-1 exploration well and the adjacent producing fields, these prospects are supported by seismic amplitude data. The red color on the map highlights the area of the Waarre formation amplitude.
For comparison, the seismic amplitude area at Elanora alone is twice the size of the amplitude anomaly at our currently producing Netherby field, which is estimated to produce about 100 BCF of gas. Slide 32 shows the Juliet prospect we plan to drill. The schematic on the left shows that it is a fairly simple vertical well development. It's directly analogous to the Casino field, and the reservoir quality has been proven in adjacent wells. The resource potential might look modest, about 50 BCF, but the prospect is underpinned by a seismic amplitude anomaly, as shown in red on this slide, and the well is very likely to find gas. It is located directly beneath a tie-in point on our pipeline, meaning a low-cost tieback in a success case. Additionally, it's expected to have gas quality like the adjacent Casino field, so low in CO2.
This will enable us to blend it with gas from the proven Annie gas field and avoid the cost, additional cost of amine treatment at the Athena Gas Plant. This further enhances the economics of the program as a whole. These types of low-risk backfill projects with quick turnaround... In the tight domestic market, and they're the types of opportunities smaller players like Cooper Energy can excel at developing. Slide 33 shows the proven Annie field, which was discovered in 2019. The Annie-1 well intersected a very high-quality, 70-meter-thick Waarre formation sand zone that will deliver gas at high rates. The gas column height is about 150 meters. It's a very simple structure, as shown in the schematic, so we'll only need one well to develop the entire resource, which in the mid case is estimated to be 65 petajoules.
This field is about as simple and straightforward as it gets. Slide 34 provides a summary of the next steps of our East Coast Supply Project. The three-well program aims to deliver 90 terajoules per day through Athena on a gross basis, or 45 terajoules per day for our Cooper Energy share. I want to highlight again, this will be the largest new supply of gas for the Southeast market. I'm sure many of you'd like me to give you a number on the cost for the project, so you can put it in your models. Since we're actively tendering, it isn't really appropriate at this time. We'll update this, we'll update the market when we FID the wells program.
The conventional asset will deliver gas at high pressure at the plant, resulting in a low ongoing operating capital cost, around AUD 1 a gigajoule, as already has been discussed, in other presentations. These factors will enable the project to generate significant cash flow to pay for the upfront capital expenditure in a timely fashion. It's a highly commercial project that adds value to one of our core assets. Finally, we have strong customer support for this gas, including options to secure prepayment. Customers are eager for this gas and are willing to secure it in advance. The East, East Coast Supply Project is a Horizon Two opportunity in our strategy. I'll now hand back to Eddy to talk about the opportunities we're pursuing in the Gippsland and some of our longer-term Horizon Three opportunities.
Thanks, Chad, and on to slide 35. A few weeks ago, at the Australian Energy Producers Conference in Perth, we announced a farm-out process of our Gippsland exploration permits, which cover the Manta Deep, Gummy Deep, and Wobbegong prospects. These permits are within the black line highlighted on the slide. There is 185 petajoules of 2C contingent gas resource and 1,300,000,000,000 cu ft of mean unrisked prospective resource in these prospects. This is an opportunity for a partner to farm into a prolific hydrocarbon basin adjacent to existing infrastructure. The Gippsland Basin Joint Venture, whose assets are adjacent to our prospects, have produced 5 ,000,000,000 bbl of liquids and 11 ,000,000,000,000 cu ft of natural gas in the last 60 years.
This is one of Australia's super basins, and there is still significant opportunity for further development to meet the gas demand that I spoke to earlier. With BMG now behind us and the potential to use an optional drilling slot in the next campaign, we can lift our eyes to the next opportunity to fill the hopper and backfill Sole, further growing the Cooper Energy portfolio. The farm-out does not include Cooper Energy selling down Sole and Orbost at this time. There is still upside to realize from this asset, as explained by Chad, and the strong cash flow generation from Sole is a key component feeding Cooper Energy's growth plans. Slide 36 shows another opportunity that we are pursuing in the Gippsland region, the restart or repurpose of the Patricia Baleen for gas storage.
There is a significant market need for underground gas storage to the east of Melbourne for a couple of reasons: the rapid decline of the prolific Gippsland Basin fields that have traditionally supplied the majority of winter demand for decades, and the expectation of increased daily peak demand for gas to firm an increasing share of renewables.... These factors have created a gap in the market for gas storage to play an increasingly important role. There is also gas that remains in the Patricia Baleen field that could be produced via Orbost. I will speak shortly to gas storage and peaking opportunities that we think Patricia Baleen could support. In the longer term, we see opportunities to participate further downstream in gas peaking products and potentially brownfield firming power products.
Cooper Energy is investigating all opportunities to work with owners of latent power generation capacity to utilize our flexible twin hub gas supply position to its potential. The next slide, 37, is an example of Cooper Energy delivering on one of these opportunities. I'm pleased to announce today that we have signed an agreement with Alinta to provide as available gas to their Bairnsdale Power Station. This is only just one hour away from the Orbost facility. Delivering gas to this power station when it's needed allows us to capture a premium gas price, with both Cooper Energy and Alinta saving on transport costs. This is a starting point for Cooper Energy to provide shaped gas products, meeting the changing demand of our customers and the market. Slide 38 speaks to three areas which comprise Horizon Three of our strategy.
First, through our carbon neutral certification, we have developed our understanding and capability in carbon credit markets. We are now leveraging this to grow our portfolio of carbon credits, participating in long-term projects to lower our credit costs. Second, continuing on the theme of important technologies in a low carbon future is renewable gas, such as biogas and biomethane. Our focus is on these drop-in fuels that can potentially be blended easily into our existing infrastructure, leveraging our gas handling and processing capabilities. Utilizing existing infrastructure is critical to unlocking and capturing the potential of renewable gas. It minimizes the cost. We are currently assessing the opportunity to use empty buffer land surrounding the Orbost Gas Plant to grow energy crops for biogas production.
In the first instance, this biogas could be blended into our own fuel gas at Orbost to make more sales gas available to our customers. Last, carbon capture and storage. The technical capabilities required to develop a CCS project are well aligned with the skills and capabilities we have as an upstream exploration and development company. In November 2023, when the Australian government released the offshore greenhouse gas storage permits, Cooper Energy put in a bid for the permits that overlap our existing acreage position in the Otway Basin. I do want to emphasize that the market remains uncertain about the maturity of this opportunity at this point in time, but it is something we will continue to monitor closely. I'll finish today on slide 39. Our team is constantly exploring opportunities to maximize the value of our gas.
To enable us to be nimble and exploit these opportunities, we are registered in both the Victorian Declared Wholesale Gas Market and the Sydney Short-Term Trading Market. We also have master sales, master gas agreements with all of the major participants along our export pipelines. As I discussed earlier in the market outlook, we see an increasing need in the future for making gas available to gas-fired power generators to meet peak demand in the electricity market, especially if households electrify and more variable renewables are integrated into the system, which is what we're seeing. The shape of our gas demand is changing, and we are building the capabilities to ensure we capture the value of our product.
As the organization has demonstrated it has done with Sole, we are now on the cusp of transformational growth once again, but this time with established commercialization pathways in place through our infrastructure position. We are also pursuing opportunities to maximize the value of our gas through gas storage and peaking products, as well as longer-term opportunities to create value in energy transition. So to conclude the growth section, I will leave you with some key messages. Cooper Energy has a proven track record as a niche energy company, commercializing opportunities that have been overlooked by some of our larger industry peers. I'll highlight the asset base that Cooper Energy has purposely built. The entry cost for this position has been relatively low, as we have seen opportunity where others haven't.
We have acquired and put critical infrastructure back in service that, if not for Cooper Energy, would have been abandoned, with vast gas resources left stranded. Support from customers and the community has enabled Cooper Energy to further grow the Otway and Gippsland Basins to commercialize more energy in the permits that we operate, fulfilling our obligations to the government as permit holders in the best possible way. We are doing this with a relatively low cost structure and low carbon footprint, which is underpinned with a view that the best option for gas supply to Australians is supply as close as physically possible to where it is used. The East Coast Supply Project in the Otway Basin, the opportunities highlighted in the Gippsland Basin, and integrating the three strategic horizons-...
demonstrates the substantial running room this company has, and the value from growth still to be generated for our shareholders. Now I'll hand over to Dan to speak to the financial slides, starting on slide 40.
Thanks, Eddy, and good morning, everybody. Last Tuesday, we announced the completion of the BMG wells decommissioning, alongside the Q7000 coming off hire and mobilizing to its next customer. Goodbye. For the next 18 months, we can now look forward to a period of growing margin expansion, growing underlying free cash flow generation, and resultant financial de-leveraging, as well as an acceleration of capital activity for the East Coast Supply Project. In the time I have today, I will focus on each of these topics in the next few slides. In speaking to cash flow generation, I'm going to first start with the top line on slide 41. Here we set out the contracted gas stack alongside uncontracted or spot gas exposure for our equity share of total production. I should say at the outset that this is not production guidance.
We're showing a profile based on 70 terajoules a day, based on an expectation of ongoing, continued improved rates at Orbost, alongside our 50 percent share of current Otway production. As noted in the call-out box at the top right-hand side, the chart does not include increased volumes that will come from our East Coast Supply Project. The light green portion of the stack reflects the contracted gas today, which is all fixed price and indexed annually to CPI. The Orbost contract stack currently averages around AUD 9 a gigajoule for the company. And for the company overall, as Eddy mentioned earlier, the average is AUD 8.82. You'll note the light green tranche increases in 2025.
Assuming we do see sustained higher Orbost production rates averaging around 60 terajoules a day, we'd expect to deliver an additional contracted volume to one of our customers, which explains that step up. The final average rates for Orbost, following the improvement project, will ultimately determine the annual contracted gas delivery profile. In the teal color, you see the recontracted gas we announced last November, with that tranche stepping up in January 2026, aligned with current mid-teen type pricing. This teal tranche, together with the lighter blue uncontracted or spot volumes, illustrate the portfolio's attractive and growing exposure to higher priced gas within the next circa 18 months and beyond. This is therefore one of the key drivers for margin expansion for Cooper Energy and driving increasing underlying cash generation. Beyond the picture that we see today, we will continue to seek to optimize the customer portfolio.
Like the extension we announced last November, we may well reshape existing contracts with our customers where it makes good economic sense for us to do so, while seeking to offer investors as much exposure to East Coast spot gas pricing as we can. On slide 42, we set out the approximate split of our production expenses, shown in the pie chart on the left. In the light green, we show the upstream costs for each of Sole, Casino Henry Netherby, and our Cooper Basin Oil. In teal, we show the Orbost costs, which represent around 60% of that total. And lastly, our half share of the Athena production costs, shown in gray. We set out guidance for FY 2024 production expenses at the beginning of the financial year at AUD 60,000,000-68 ,000,000.
In mid-April, with continued progress in the cost out program generally, including the improvement initiatives at Orbost, we reduced the low end of guidance and narrowed the range to AUD 57 ,000,000-AUD 63 ,000,000. We continue to work to reduce costs across the business, including production expenses. The biggest prize here remains at Orbost, with the sulfur plant being the most critical area. Reductions in production costs in FY 2024 have contributed to the AUD 10 ,000,000 of annualized savings we're on target to unlock by mid-year. As we reduce the frequency of absorber cleans, as we shorten the duration of the absorber cleans, and as we lengthen the duration of the polisher media life, we then reduce our labor and contract services costs, as well as our materials costs.
We will set out our guidance for FY 25 production expenses, along with our guidance for FY 25 production and FY 25 CapEx as normal in August. There will be some elements of our cost base that will remain stable, but we also expect to see further reductions in production costs, including from the sulfur plant in August at Orbost, in aggregate, delivering the potential to unlock further margin expansion. As we look further ahead, and in particular to the East Coast Supply Project, it's important to note again the operating leverage at the Athena Gas Plant. The cost base at both plants has a high fixed cost component, giving rise to a lot of operating leverage. As we grow the denominator, our unit costs fall significantly....
With production rates at Athena of 90 terajoules a day on a 100% gross basis, our unit cash costs can be expected to be around AUD 1 a gigajoule. On slide 43, we include some detail on G&A in the middle of the slide, along with the other elements of cash costs that are reported separately in our income statement from production expenses, shown on the left-hand side, and we also include stay in business CapEx on the right. Starting in the middle with G&A, the largest of the three elements, you can see the approximate split between people, insurance, finance costs, compliance and other. While we've already reduced reported G&A by 20% half on half, there are more cost savings to come here. This is partly due to some non-recurring items incurred through the cost out program, such as redundancy costs.
Alongside production expenses, G&A has been a key contributor to the $10 ,000,000 of annualized savings we are on track to unlock by mid-year. There are some G&A items that remain relatively sticky, including, for example, the legal and compliance costs shown in the lighter gray color here. And while aggregate headcount is falling with the wind down in the BMG team, we're already a pretty lean team with limited scope to further reduce cost savings across employed functions. That said, there is still room for further savings in this line over and above the non-recurring costs falling away, both for the second half of FY 2024 and into FY 2025. Other operating costs shown on the left-hand side of the slide include costs for parking gas on the pipeline, care and maintenance costs, and some other elements, including sustainability.
Over the last year or so, we have reduced OpEx and transportation costs with the improved performance at Orbost, and we have reduced our sustainability costs as our approach here has matured. Collectively, collectively, this group is typically well below AUD 10 ,000,000. There is also further room for savings linked to further improvements in the Orbost rate and the evolution of our sustainability initiatives. On the right-hand side of the slide is an approximation of the split for stay in business CapEx, which is typically somewhere in the range of 4 or 5, up to AUD 10 ,000,000, depending on scheduled activity, with around half of this at Orbost. On slide 44, we have a reminder on the cost out program, which continues to mature. The program is company-wide across both people and culture on the one hand, as well as business processes on the other.
Jane has talked about direct accountability for outcomes, and it is also about working more efficiently, including a more disciplined approach to planning activities. Collectively, we are seeking outcomes that result in higher uptime and result in production, lower aggregate costs that will result in significantly lower unit costs and incremental margin expansion. We are also seeking to not only maximize the potential for savings in FY 2024 and FY 2025, but also to embed a culture of continuous improvement. We remain on track to unlock around AUD 10 ,000,000 of annualized cost savings from the middle of the year, with a number of initiatives touched on already this morning. Our intention remains to chase a higher number through next financial year, as illustrated in the chart on the right-hand side. As we continue to deliver further performance improvements at Orbost, we can expect to unlock further savings.
We recognize there can be some skepticism among some investors with these kinds of programs. For example, that we might just be shifting activity from employed functions into a growing contractor or consultant workforce, or that activity is just being shifted from FY 2024 or FY 2025 into FY 2026. In each case, analogous to a game of Whac-A-Mole. I can say that we are consciously working to ensure the cost savings are sustained structural changes rather than temporal savings, and further updates will be provided on this in the full year results in August. Turning to the balance sheet on slide 45, capital funding for our business is simple. We have common equity alongside the senior secured reserve-based loan and nothing else beyond a small amount of management performance rights.
This is a 5-year RBL, which we established in July 2022 with a group of large, of 8 large banks. 2 of the domestic Big Four, 2 Japanese, 3 Europeans and 1 North American. All of them are experienced lenders to upstream oil and gas. RBLs are a highly effective form of funding for a growing midcap E&P company. They maximize upfront borrowing proceeds and offer a sculpted facility reduction schedule. Our facility offers a competitive cost of funds at BBSY plus 325 basis points or around 7.6% on the drawn portion. The loan was established with a $100 ,000,000-$180 ,000,000 dollar 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.
That established that the borrowing base is well above the fully committed and available AUD 400 ,000,000, an attractive backdrop as we look to the potential to unlock a portion of the accordion for the East Coast Supply Project. We've also commenced a process to reset the loan back to a 5-year term out to 2029. Pushing out the loan term will unlock additional significant funding flexibility for the group during the East Coast Supply Project funding phase, over and above the undrawn capacity today and the de-leveraging we anticipate over the interim period, as well as the potential incremental funding from the accordion. Turning to slide 46, we have pulled together a view on the group's underlying cash flow generation potential before CapEx reinvestment into the East Coast Supply Project.
Chad has talked about the combination of better management of the Orbost Sulfur Plant, alongside improved reliability and uptime, which will result in higher average production rates. Eddy and I have talked about higher average gas price realizations. Collectively, we expect to achieve significant growth in revenue well above the CPI escalation embedded in our gas contracts. With continued vigilance on costs across the business, including further advancements in the Orbost Improvement Project and further reductions in GNA for the business, we expect to see further success in cost management as well. The light green color in the chart shows underlying free cash flow generation, assuming an average Orbost rate of 50 terajoules a day, which is below average rates for the second half of this financial year.
And assumed contract gas prices of AUD 13 a gigajoule during the summer and shoulder periods, and AUD 20 a gigajoule during the peak winter period. There are three non-recurring items reflected here. The first is the final AUD 20 ,000,000 Orbost installment payment due to APA at the end of next month. There is also our 10% share in the Minerva abandonment project and our 90% share in the BMG equipment recovery project. Before talking more about these two decommissioning activities, it is worth noting that with the completion of the BMG wells decommissioning project, we've reduced the total restoration provision on our balance sheet by almost a third. As we've announced last Tuesday, the BMG wells program is on track to come out towards the top end of the guided range of 240-280.
Of the remaining two-thirds balance of restoration on our balance sheet, more than 85% is expected to fall due in 10 or 15+ years from now. If I focus on decommissioning activity over the next 5 years, the great majority of that is represented in the two projects called out here. Plans by the Minerva operator should see activity occurring in the mid or second half of calendar 2025. We have a 10% interest here, with the program to include either 3 or 4 subsea wells, subject to regulatory acceptance on the current plug and abandonment conditions at the 4th well. Exact timing of this activity is subject to change, depending on the progress of the Equinox rig on its existing work program offshore Western Australia.
The second item in the chart covers the activity to pick up the remaining BMG equipment from the Gippsland sea floor. This includes well heads, manifolds, umbilicals, and flow lines. With the wells work now completed, this second phase of work is much more straightforward, utilizing a much lower cost vessel. We will seek to piggyback off activity by the main Gippsland Basin operator, with our work likely to occur sometime in the coming 2.5 years. Timing will be driven by Cooper Energy as the operator, with opportune day rates being the main driver. The remainder of the decommissioning activity in the next 5 years arises from reasonably smaller participating interests in some onshore wells, where the costs are relatively modest.
Beyond these non-recurring items, you can see that the business generates significant underlying free cash flow over this period, providing the basis for significant de-leveraging, even at an average 50 terajoule a day rate at Orbost, shown in the light green. This would take the business to be net cash positive by mid-2027, before growth CapEx spend. The teal color provides an indication of the underlying free cash flow at a 60 terajoule a day average rate for Orbost, under which the business is net cash positive around 12 months earlier or mid-2026. The right-hand side of the slide seeks to reflect how we think about financial management. We have very attractive organic brownfield growth projects that commercialize our discovered gas and our low-risk prospective gas resources through existing invested infrastructure that sits close to a tight and growing market.
These kind of brownfield organic gas projects mean we are getting the most out of invested infrastructure in place and maximizing ultimate gas. Gas can be commercialized at prices approaching regasified LNG as the marginal source of supply and offers relatively low emission gas. These are exceptional investment opportunities, and we will seek to capitalize on them. We do recognize the need for shareholder returns in time, but the short-term imperative is to fund the organic operated East Coast Supply Project and to continue to mature the other early-stage initiatives we've talked about this morning. Slide 47 is my last slide. For the last several months, many of you will have heard us talk about the focus on the three pools of capital shown on the left-hand side of the slide for the purposes of funding the East Coast Supply Project.
Firstly, we want to continue to utilize senior secured bank debt funding, given the competitive cost of funds. This includes the existing undrawn committed funding under the RBL, as well as through resetting the tenor for 5 years to push out the current reduction schedule and via the accordion. Secondly, we are continuing our discussions with a small number of gas customers to incorporate a prepayment alongside a vanilla gas sales agreement... Eddy has talked about the market having moved to mid-teens for contracted gas. That kind of pricing delivers attractive economics for the East Coast Supply Project, inclusive of the cost of capital embedded into a prepayment. Bear in mind as well, that our project is the largest source of new gas over the next 3 years for Southeast Australia.
As a result, we are seeing significant interest from the major gas wholesalers in the East Coast gas market. Funding via an investment-grade offtaker amidst a tight and tightening gas market offers us another source of competitively priced capital relative to other options. Finally, there is the organic free cash flow generation, which I've just spoken to. The combination of these three pools of capital deliver what we believe to be the optimal blended cost of funds. The right-hand side of this commentary on the slide is a reminder that our business is based on conventional gas reservoirs, offering reasonably flat production volumes that are commercialized through medium-term GSAs with investment-grade offtakers at a fixed price indexed to inflation, with high take-or-pay volumes, and with relatively low overall cash operating costs.
That kind of backdrop means that these assets can support more meaningful levels of bank debt and medium-term gas-customer prepayments. With that, Jane will now review the key messages from this morning.
Thanks, Dan. I'd like now to wrap up this morning's presentation before we open the floor to Q&A. On to slide 49. As I discussed earlier, we have turned a big corner this year with the completion of the BMG wells decommissioning program. The new executive team is in place with greater operations capability. This is a team that has a relentless focus on safety leadership, on cost leadership, and operational excellence. This is a team with the right attitude, right culture, and the ambition to deliver superior results. We have got our arms around our technical issues, and we continue to deliver incremental production improvements to maximize revenue from our plants. We have macro tailwinds, we have a credible growth story, and a funding plan to deliver it. FY 2024 has been a strong year for Cooper Energy.
With our strategy set, we are now focused on delivering in FY 25. We will continue to focus on production and performance across our portfolio. This will be driven by continued improvement at the Orbost Plant, improving both reliability across both plants, Orbost and Athena. We are targeting average production in the low 60 TJs a day from Orbost, resulting in group production of more than 70 TJs a day equivalent by the end of FY 25. Our priority will be on maximizing cash generation and paying down debt ahead of investing in our major growth project. There are two parts to this: increasing our realized gas prices through our increased exposure to the tight spot market, and accessing more rent in the spark spread by providing gas when our customers need it.
Maintaining focus on the lower cost base, which we have delivered 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 volume, but position us as an operator of choice when looking to bring in third-party gas supply through our facilities. And of course, we will continue to progress the East Coast Supply Project with the aim of locking in our preferred three-well program in preparation for the arrival of the rig. On to slide 50. I'm wrapping up today by reinforcing our investment proposition.
We believe that gas maintains an important role in the energy mix, and therefore, our strategy builds on our core business of gas exploration, production, processing, and sales. The Southeast Australian gas market is structurally short, and gas will be a scarce and valuable resource. We have structurally important infrastructure positions to supply gas into Australia's largest cities. To win in this future, we will focus on developments that leverage our existing infrastructure and our upstream and plant operating capabilities. We will stabilize production at Orbost and Athena, and we have unlocked the latent potential of our business, and we're now focusing our attention on growth, including the East Coast Supply Project. With this project online, group production will be over 100 terajoules equivalent a day. The growth strategy and investment proposition for Cooper Energy remain compelling. There remains deep value within the business that we will capitalize on.
We look forward to this journey with you as our shareholders, and thank you for your time today, and I'd now like to open the floor to questions.
Thanks. So just raise your hands if you'd like to ask a question, we'll bring a microphone over to you. We'll take questions from the room in Sydney first, and then questions on the webcast. As a reminder, please click the blue hand on the webcast to submit questions over the webcast. Over to you, Dale.
Morning, Dale Koenders from Barrenjoey. Just wondering on slide 46, which Dan's presented about the cash flow outlook, which, you know, potentially AUD 500 ,000,000 of free cash flow over the next three years, which is pretty close to your market cap. Just wondering why is it then that you're talking about RBLs and sort of needing extra debt? Like, what is the big? Is it AUD 500 ,000,000 of CapEx you're looking to spend over the next three years at the same time? Like, how do you think about that balance of, you know, potentially for dividends, or if, if you truly are cheap, using some of your spare cash to buy your own stock back?
Thanks, Dale. I'll pass that over to Dan.
Yeah. Is the mic working? Can everybody hear me? So Chad has talked about the sensitive point we are in, in the process around costs for the East Coast Supply Project, and so we will say more about that as soon as we're able to, and as the wells program is FID'd. We want to strike the right balance in terms of getting the optimal cost of capital overall. And so we do think that the business profile, as I talked about, the credit picture for the business can support more debt than you know may typically be seen across the broader, let me say, oil and gas space. You know, a contracted EC domestic gas business like ours can do that.
And so we do want to make sure we're using the balance sheet and making sure we do have the optimal lowest cost of capital, and we think that's the right balance. It's very early right now to be talking about shareholder distributions other than to acknowledge and recognize as we pursue this next phase of growth in the Otway, and get to cash generation from that growth. That at that point, it would be natural to be thinking about more shareholder distributions at that time.
Yeah. Mark Wiseman from Macquarie. Just a question. Congratulations on the Alinta contract for Bairnsdale. Are you able to talk about how that, how the economic rent is shared with that peaker? Are you getting some portion of the spark spread, or is it some sort of premium on the, the spot gas price?
Sure. I'll hand that to Eddy.
Thanks, Mark. At the moment, that is an arm's length transaction to be able to supply a peaking power opportunity. I think we will look at opportunities to step into firming power and then, you know, participating in that spark spread, but not yet. We're just facilitating a peaker that needs the gas at a short period in time, and that, because of our proximity, that enables us to get a premium price for it above spot.
Yeah. So Mark, I think it's fair to think about this as a sort of small deal, but a step in the right direction, where we're sharing upside and creating value for both parties.
Hey, Jane,
Hi.
Morning, all. Thanks for the update. Henry Meyer from Goldman Sachs here. You highlight the significant value of Athena. It's AUD 500 ,000,000-AUD 550 ,000,000, and if you get the three-well program successful, still hold a bit of leverage at the plant there. Can you talk about how far progressed you are in potentially extracting value from that leverage and toll, if you still see opportunity to drill the other prospects in the region, or you'd be happy to move through with the toll earlier?
Thanks, Henry. So there's two parts to this. One is working with other players existing in the basin to optimize both developments and production, and that means bringing gas through whichever makes the best sense in terms of the existing infrastructure positions. The other opportunity is with new players coming into the basin. We've got Conoco there, backed into the 3D energy acreage, and if they find gas, we're sure they're going to be interested in talking to the existing gas processing plants about leverage opportunities. So, we're very open to looking at business opportunities that reduce costs, both in our offshore developments as well as the onshore processing.
Thanks, Jane. Declan Bonnick from Euroz Hartleys. So when are you targeting FID for OP3D or the East Coast Supply Project, given we are, you know, getting closer and closer to spud date?
Yeah, we are working on that really hard, Declan. We have a number of optional slots with the rig, which continue right up until March 2026, so that gives us very good flexibility. The best way to think about this program is in two parts. There's three wells we want to drill, and as Chad explained, it's Elanora with a sidetrack into Isabella. Isabella and Juliet are exploration wells, so we need to we believe there's commercial gas there, but we need to drill and actually prove it, and then Annie is a discovered resource. So what we're aiming to do is drill three wells and then complete those wells using trees to suspend them, and then the second part of the program will be executing that with all the tie-ins, so flow lines, umbilicals, and so on, back into the existing offshore pipeline.
So, it's best to think about it as a drilling program with two exploration wells. On success, they'll be completed. It's really important we do as much as possible while the rig is in the area. We don't want to be waiting five years to bring a rig back to tie in, and we believe these are such high prospects of success that we should complete them and then immediately tie them in, subject to achieving the planning approvals required from NOPSEMA and NOPTA to do that. So, we will be updating the market as soon as we can on the wells, the timing of the wells and drilling.
... Yeah. G'day, Alistair Rankin from RBC. The partnerships with the gas peaking plants looks a really interesting method for capturing additional value through the spark spread. Could you just give a little bit more detail on what a partnership like this might look like in the future, beyond the Bairnsdale, which I understand is sort of a step in the right direction, but what would one of these partnerships in the future look like, and how would you capture that additional value, do you think?
Mm-hmm. Sure. Thanks, Alistair. I'll make a few comments, and then hand to Eddy. The first step is peaking products, which is really ratable gas supply through line pack or storage, and providing that to our customers. We use line pack today to manage the operational issues of the plant. When we know we're going into an absorber bed clean to remove the sulfur, we park extra gas on the pipeline, and we pull it back during the clean to meet nominations. So as we extend out those cleans, and hopefully reduce the time taken for the cleans, we'll be able to use that line pack to create peaking gas products for our customers, and in particular, the big power generators. So that's the first step, is thinking about how do we shape gas more and create ratable supply.
The second part is really thinking about how do we share some of that upside margin around the spark spread, and we're just kicking off discussions with the power generators now, but I'll hand to Eddy to comment on that.
Yeah, thanks, Jane. I guess in this environment, we can see a lot of the retailers and the owners of power gen aren't really stepping into the upstream anymore. So effectively, the partnerships and the way they work now, we're. We can be in a position where we can be the upstream arm for these companies, and then looking for that synergistic relationship where we can actually step into the value chain to get that spark spread. And look, there is quite a bit of latent brownfield power gen across that part of Victoria, close to Orbost, so it makes perfect sense that we step into that supply chain. And just because they see us as an upstream arm, there's a natural space now for us to play, in that area.
Yeah.
It's Mark Wiseman again. I just had a question on the offshore Otway growth phase, the East Coast Supply Project. In terms of joint venture alignment and your partner's decision to invest or not invest, is there a point in time between now and when the rig arrives that there's a line in the sand where that decision has to be made? And how far away is that?
Yeah, that's a great question, Mark. So Mitsui is our 50%, joint venture partner in that, and I think it's fair to say they have been very distracted with the Waitsia Perth Basin development. We believe they are working this hard at the moment. We know that their technical people support our view that this is a highly economic and attractive project for them, and ranks well globally for them. So we expect to be able to provide clarity shortly on the project, and we are working that as hard as we can.
Hi, Kieran Barratt, Petra Capital. Just a question around the contract stack, more specifically the capped component of it. Just given the magnitude of the price movements that we've seen in contract prices, is there any scope for renegotiation on those?
Yeah, interesting question. Potentially. I mean, what we have seen with some of our contracts is that we can move to renegotiate the price sooner in exchange for extending the contract duration, and giving additional gas in the longer term to those buyers. When you put a gas supply agreement in place with buyers, it's always done with reference to their other options in the market and prevailing market conditions. And so when we signed the GSAs, this was the best pricing at the time, and the best terms at the time. So of course, those market conditions can change, especially as we're seeing now with it tightening up. So we will look at whether we can reshape the contracts in exchange for giving some additional length and duration in exchange for revised pricing in the near term.
But the current contract is locked into both, a maximum or capped increase and a capped decrease, so it protects both the buyer and seller. But clearly, we've seen a shift in the market.
Hi, Jane. Henry Meyer again. Just to follow up on the free cash flow outlook on slide 46. We're seeing a step down in second half 2027, kind of independent of the high and base case scenario. Is my understanding right, that this could be the PRRT payments commencing at Sole?
Yes, correct.
Mm.
I might move to some questions on the line then. So a few questions from Nik Burns, from Jarden. I'll just take the ones that haven't already been asked, but perhaps first to you, Chad. What needs to be achieved at Orbost to see average production rates increase from 52 terajoules in the March quarter to 58 per day in the near term? And from 58 to 62, what else needs to be done?
Yeah. So as I discussed in the presentation, the key catalysts for us are extending the polisher run length to greater than 8 months. It's getting the absorber run length longer, so right now we're in that 3-4-week period between absorber cleans. So to continue at that 3-4-week period will enable us to get to that 58, and then it's implementing faster absorber cleans when we need to do it, and that's through the chemical clean in place. So all the elements are actually have been shown to work. It's stringing them together, and then running the plant reliably through that period of time.
... similar line of questioning, when will you make a call on a third absorber? And, and even if you're confident of achieving those higher rates without the need for a third absorber, wouldn't the addition of the absorber provide extra redundancy and other benefits, such as improved facility reliability, more consistent supply into contracts, and lower operating costs?
Yep, that, another great question. So, I think I've talked about it before, is I actually thought the decision for the third absorber was gonna be fairly easy. Because when we originally put out the guidance for pricing, it was AUD 30,000,000 -AUD 40 ,000,000 for the third absorber, and at the time, our production through the plant wasn't all that great. What's ended up making it a lot harder decision is that the... Despite the market being an inflated market, where the costs are coming in higher generally for projects, our costs came in on the lower end, so below the AUD 30 ,000,000 dollar number. So that definitely made the decision a lot harder.
We also started to see significant improvement in production through Orbost with some of our record production rates that I quoted earlier. So between the higher production and the lower cost, it became a hard decision in terms of it, it started to look economic again. So that's where we're at today. If we continue to move with the low 60 terajoules per day throughput through Orbost, then we would likely not be committing to the third absorber. So some of the questions around reliability, all the third absorber does is helps us with the fouling issues at the plant. It doesn't necessarily impact the reliability issues or foaming or some of the other elements, so there's a smaller wedge of incremental upside that it would have.
The last one from Nick, on the gas storage opportunity. Perhaps this is to you, Eddy. Can you walk us through the work program required to evaluate the suitability for Patricia Baleen for gas storage? And are there any gas reserves in Patricia Baleen that could provide backfill for Orbost, or would you leave these reserves in place for use as a gas cushion for future storage? Maybe that's for you, Chad.
Yeah, another good question. We'll announce something once we've actually worked out the scope and the timeline, the cost, et cetera, for the program. There is some gas in Patricia Baleen that's left, and, you know, with storage, you do need some cushion gas. So whether or not we produce some of that, all of it, leave some in place at the right time, that's what we're working through at the moment. But we'll be ready to announce more details around that program as we get through our work.
Yeah, people might not know, but the Patricia Baleen field was shut in because the umbilical out to the field failed, and so all of that is shut in, and the reservoir has recharged. What we're working through now is an assessment of what that recharge is and how much pressure and deliverability it could support in terms of storage. And then, what's the cost for repairing the umbilical and the modifications of the plant to accept that gas into it, either as a re-life project that produces back into the market, or potentially for gas storage, where we use the gas that's recharged as the cushion for gas storage to make sure we've got the rate.
One last one on the line that hasn't already been asked, but perhaps, if there's any more detail we can provide around the timeline to first gas at the East Coast Supply Project, between the rig arriving in the region around early 2026 and then first gas into 2028, the sort of key steps that you'd see.
Okay. Thanks, Tom. You know, I talked earlier about thinking about this project in two halves. It's the drilling and then the successful completion of those wells to suspend them, and then there's a separate execute phase that requires separate approvals with NOPSEMA and NOPTA. So, the drilling, let's assume we start our drilling in late 2025, early 2026, then we will complete those wells, get them ready for tie-in, but they're effectively suspended. Then, we come back with an execute program with the flow lines, umbilicals, any manifolds, and tying that all into the existing offshore pipeline. So that work will happen through 2027 and into the start of 2028.
Thanks, Jane. Looks like we're all done with questions. So thank you everyone for your time. If you're on the webcast, you may drop off now, and for those in the room, please join us for some tea, coffee, biscuits at the end there. Thank you.
Great. Thanks very much.