Amplitude Energy Limited (AEL) Earnings Call Transcript & Summary

Good day, and welcome to the Cooper Energy Limited FY '23 Half Year Results. [Operator Instructions] And finally, I would like to advise all participants that this call is being recorded. Thank you. I'd now like to welcome David Maxwell, Managing Director, to begin the conference. David, over to you.

Thank you very much. And let me add my good morning and welcome to everybody. Thank you for joining the Cooper Energy 2023 Financial Year First Half Results Webcast and Presentation. I'm joined today by the Chief Financial Officer, Dan Young; and Nathan Childs, our Engineering Manager, who will be taking us through some of the presentation this morning. Also with us on the conference call are members of the executive leadership team when we come to the Q&A session. The Q&A session will follow the presentation, and clearly, we welcome your questions. The presentation and half year report were released to the ASX this morning and are available on the Cooper Energy website. Today's webcast, as advised at the introduction, is being recorded, and a playback will be available on our website later today. Please note the important disclaimer information at the back of the presentation and on the final page of the ASX announcement made this morning. Turning now to Slide 2 and the first half highlights. In this period, we delivered record first half production, revenue and underlying EBITDAX with 0 health, safety and environmental incidents. This has been achieved whilst remaining carbon neutral accredited for Scope 1, Scope 2 and controllable Scope 3 emissions. Despite a frustrating December quarter that was impacted by a recurring unplanned downtime of the Orbost Gas Processing Plant, first half production was still a record of 1.82 million barrels of oil equivalent, 16% higher than the first half of the previous year. APA continue and remain as the operator of the Orbost plant. This is until the license transfer, which is on schedule to be complete by June of this year. We now have engineering resources and work streams in place to address the Orbost performance before and immediately following the transfer of the major hazard facility license to Cooper Energy. You're going to hear from Nathan, who will provide further detail on this work. The processing trend at the Orbost plant is positive with plans to get to nameplate and maybe above that as soon as possible. The average processing rates have increased 21% from the first half of FY '22. That's from 39 terajoules a day to 48 terajoules a day. And this has been supported by continued strong reservoir performance. I note the Orbost processing rate today is 59 terajoules. At the Athena Gas Plant, the average monthly processing rate was steady throughout the first half of FY '23. I note the average rates were impacted in the December quarter by planned maintenance. Although total sales volumes decreased 10% compared to the previous corresponding period, revenue increased 6% to $101 million, attributable to higher gas prices received. Underlying EBITDAX increased 134% to $60 million. This follows the acquisition of Orbost and a bigger reduction in third-party gas purchases. Operating cash flow increased 98% to $55 million. That is pretty close to double, and Dan will give you a breakdown of these increases soon. On Slide 3, a few comments on safety, environment and community indicators. Our financial year 2022 safety and environment management performance was industry-leading and top quartile. This has continued. In summary, the results are 0 lost time incidents and more than -- and it's now more than 1,200 days since our last lost time incident. The total recordable injury frequency rate up to the end of December of 0.0 compares with industry average benchmark for offshore Australia of 7.38. And we maintain our carbon neutral accreditation and remain net 0 for Scope 1, Scope 2 and controllable Scope 3 emissions. These safety and environmental performance results illustrate the discipline embedded in the facilities we operate. I note that since the end of the half year, so since the end of December, in January, we had one medical treatment incident. This was not a lost time incident, and this will be included in our year-end results. Cooper Energy will instill this operational discipline at the Orbost plant when we become the operator. Turning now to Slide 4 and the government intervention in December. This is in the press almost every day. The federal government's proposed mandatory code and reasonable price mechanism significantly risk much-needed and already lagging investment in new gas supply, including Cooper Energy's Otway Phase 3 Development. There are 4 key issues impacting the Eastern Australia gas market at the moment, and these are: existing fields are in decline; costs are increasing; new supplies needed from as early as this year; and increasing delivered gas prices. The government's market intervention hampers much-needed new supply developments. Foundation gas sales agreements need to be excluded from the mandatory code as they are critical to the financing and ultimate project sanction of major gas developments. For those reasons, undeveloped reserves and resources should be excluded from the mandatory code. We will only take FID on our OP3D project when we are comfortable on these and other issues. On the $12 per gigajoule price cap for 2023, this does not apply to Cooper Energy's existing contracts, including the OP3D gas sales agreement we signed with AGL in November, nor does it impact Cooper Energy's spot sales. This is because the company is a direct seller into the Victoria declared wholesale gas market, a marketing arrangement which is not captured by the cap. Cooper Energy made a submission to the government earlier this year on the code, and our submission is available on our website if you'd like more detail. I'll now hand over to Dan, our CFO, to provide an operational and financial overview.

Thank you, David, and good morning, everyone. Moving to Slide 5 now, which is the only industry thematic we'll speak to today, but highly relevant to our story. This data is taken from the openm.org.au website and shows the week's energy mix in South Australia for the purposes of electricity generation. South Australia is the mainland state which is the most advanced in terms of the transition to variable renewables. In the past year in SA, 53% of electricity was generated from variable renewables as compared to 34% for the entire NIM. The flip side to that is that SA has by far the highest reliance on gas for electricity generation as a result of this high percentage of variable renewables. South Australia is a window to the future for electricity supply system in other states. There's nothing special about these 7 days, more or less a typical picture for this time of year. Solar is in yellow, wind in green, imports in black, and gas is shown in red. The front end of the week saw a large contribution from solar and wind with some support from baseload generation. By Wednesday, when the contribution from wind was much less, the call on gas became very significant. And this was repeated on Thursday, while at the weekend, gas remained an important contributor with less variable renewables. To maintain electricity supply, natural gas kicked in, together with imports supplied by electricity interconnectors. The imports are mostly brown coal-fired generation from Victoria, turning down in the daytime when solar was dominant and up again in the evening. As coal-fired power generation is retired across Eastern Australia, we can expect this reliance on gas to increase even more. Natural gas provides reliable, dispatchable and fast start supply in a system dominated by variable renewables. Turning to Slide 6. Today, we reported record half year results across almost all key metrics. Production for the half was nearly 10,000 BOEs per day or 1.8 million BOEs for the full half, which is a record for the company and 16% above the prior comparable period. I'll talk more about individual asset-based production in the next couple of slides. But as we set out in our Q2 quarterly report last month, performance was particularly strong in Q1. Top line revenue of $101 million was also a record for the first half, 6% higher than the first half of FY '22. Average realized gas prices were up 17.5%, but total gas volumes sold were down by around 8% as a result of the renegotiation of a major customer's nomination quantity that we agreed last year. And this also meant a large reduction in third-party gas purchases. Oil prices were up more than 75%, but volumes sold down slightly, mostly due to the one-off change in the offtake arrangements at Port Bonython on July 1. This one-off change made a reduction in revenue of around $1.8 million based on the average realized oil price in the first quarter. Unit cash costs were around $2.20 a gigajoule equivalent, which excludes the toll we paid to APA in July while Orbost was still under their operatorship, and hence, also July production in the denominator, plus excluding the cost of third-party gas purchases of 128 terajoules and line pack costs. Underlying EBITDAX more than doubled, and I'll talk more about that in a couple of slides. As David has mentioned, this was also a record for the company. And operating cash generation almost doubled to $55 million. In summary, the business has started to really show its cash generation potential, although I would note that plant performance in Q2 at Orbost fell short of our expectations, which I will now talk about in the next slide. Two key messages here. Firstly, we benefited from a more than 20% increase in plant performance at Orbost compared to first half FY '22, continuing the broader trend over the last 15 months of higher average processing rates. This was driven by strong plant performance in Q1 FY '23, averaging 51 terajoules a day with September a particularly good month averaging 56 terajoules a day with higher utilization of the polishing unit. Performance in Q2 fell short of expectations, particularly in November and December. In late November, we provided an operational update, which included details of the various downtime events that impacted processing rates. Subsequent to that update, there were several further unplanned but avoidable planned trips as well as a planned 2-day shutdown. Collectively, this resulted in average processing rates of around 40 terajoules a day. We took immediate action to ensure, although the plant remains operated by APA, that we're doing everything in our power to maximize safe performance. We negotiated and obtained APA's agreement to have an experienced Cooper Energy gas plant manager on-site working with APA's team, and we are accelerating operations and engineering work streams to optimize production. Nathan will talk more about this in a moment. The polishing unit is currently offline, counter to the operator's plans and our own. It will be returned to service following media change-out, but this is later than anticipated. We are more involved in ensuring the new media is fit for purpose. This is expected to enable incremental spot volumes. And as you can see on the right-hand side of the slide, there is significant upside beyond current processing rates. The potential bar here implies we are hitting nameplate capacity of 68 terajoules a day and averaging 65 terajoules a day after allowance for more customary levels of downtime. I'll now turn to Slide 8 and a review of the Otway. Production in the Otway from Casino, Henry, Netherby for the first half was roughly 22 terajoules a day on a 100% gross basis. It was higher in Q1 as a result of a planned 10-day shutdown in November at Athena to undertake a customary annual inspection and maintenance program. More recently, there has been a period of unplanned downtime associated with repair to a compressor resulting in processing rates in the low teens. There is a lot of capacity available at the plant, and the chart shows an indicative processing rate inclusive of Annie. As we've said very clearly, the timing of FID for OP3D is now subject to a satisfactory finalization of the government's proposed regulatory intervention. We're nevertheless completing the main OP3D FEED work streams in order to position the project to proceed to FID as soon as acceptable arrangements are in place. Slide 9 provides an overview of the expansion in underlying EBITDAX following the acquisition of Orbost, bridging performance back to the prior comparable period. The first 2 blocks in the bridge relate to the reset to the offtake arrangements from Sole that were agreed with a key customer in the middle of last year. As a result of this reset, we sold less volumes, which ensured we no longer had to purchase the same volumes of third-party gas. Those first 2 bars together amount to an increase of around $7 million to $8 million. As I mentioned earlier, average realized gas prices were also up by about 17.5% or another $16 million or so. We saved around $27 million from ownership of the plant as a result of lower tolling costs. This has been partly offset from higher production costs under APA's operatorship, which remains a key focus for us during this transition period and beyond. The second bridge on Slide 10 sets out the change in our cash balance. The first part of the bridge sets out the movements associated with the purchase of Orbost from APA, including the completion of the equity raise and related funding arrangements. The net proceeds of the retail portion of the equity raise were received in mid-July. And at the end of July, we paid the main tranche of consideration of $210 million to APA. We also incurred stamp duty along with other transaction costs associated with the acquisition, and the equity raise and debt refinancing at that time is set out here. From the pro forma cash balance of $52.5 million, you can see we generated positive operating cash flow generation of around $55 million, growing cash to a total of over $107 million. CapEx for the half was just under $20 million, which includes the FEED work on OP3D and the capital portion of transition and integration costs at Orbost, along with the acquisition of 3D seismic data in the Gippsland and smaller amounts in the Cooper. This left us with cash of just under $80 million at the end of the half. If I exclude the 3 CapEx elements I just mentioned, the business generated around $50 million underlying free cash flow for the half, but this was clearly well down on its potential given the performance at Orbost in Q2. The key challenge for us in the next 12 months is getting free cash flow generation from $100 million on an annualized basis to something 50% or more above that level supported by our portfolio of high-quality gas contracts and substantial gas reserve and discovered resource base. A quick reminder on Slide 11 that we continue to maintain very healthy levels of liquidity. In July, we executed a new loan agreement that we had mandated at the time we announced the acquisition of Orbost. This resulted in a debt facility more than doubling and the bank group growing from 5 to 8. In fact, we scaled back demand within the bank group, which bodes well for the utilization of the additional $120 million accordion feature when new borrowing base assets can be brought into the facilities such as Annie. The bank group comprises a strong group of commercial banks, providing the company with competitive terms out to Q1 FY '28. This provides us with around $340 million of fully committed and available funding today with the use of proceeds set as general corporate purposes. We will utilize committed available funding under the facility to partially fund the BMG decommissioning work for late this calendar year. Turning now to guidance on Slide 12. When setting guidance this year, we took a conservative approach knowing that APA would be operating Orbost for most of the financial year. With little ability to influence day-to-day operations, this was the right thing to do. Yet processing rates at Orbost fell to 44 terajoules a day on average in Q2, significantly below its already conservative for forecast. And note by comparison that the plant averaged 51.5 terajoules a day in the period leading up to the sale being agreed with APA back in January. Full year forecasts also included the impact from the polishing unit returning to service in the second half of January. These assumptions informed the work we did to reaffirm guidance in mid-January. This was in line with the forecast we received from the operator. Unfortunately, these time frames were not met, and as a consequence, in Q3 to date, average processing rates have not increased as much as we had planned. While it is pleasing to see the rate at around 59 terajoules a day today, as David has mentioned, we have factored in some conservatism at the bottom end of our range regarding the resumption of the polisher unit in the remainder of this financial year. This has led to a revision to our production guidance, which is now set at 3.5 million BOEs to 3.7 million BOEs, and to our underlying EBITDAX guidance, which is now set at $115 million to $133 million. Due to the large impact the incremental spot sales have on the business, underlying EBITDAX guidance range remains relatively broad. If the polishing unit does come on sooner and perform more strongly and we see high spot prices in Q4, there remains the potential to deliver a stronger second half FY '23. On Slide 13, we've also narrowed guidance for CapEx with an overall reduction in total spend. I say spend here because we are also capturing the Orbost integration costs, some of which are expensed rather than capitalized, hence the reference to total spend. When we first gave CapEx guidance in August, we deliberately noted that we had excluded the spend on Orbost integration costs, which at the time we said was around $20 million. And then we had excluded it because we weren't in a position to split that activity between CapEx and what would be expensed. We're now able to do that. And as you can see on the chart, the adjusted guidance means our overall spend will be around $1 million less than the original guidance, inclusive of the Orbost integration spend. On Slide 14, we are now around 6 months from receiving the Helix Q7000 to undertake the planned wells decommissioning activity at BMG. The rig is currently in dry dock in Johor and will make its way to the Taranaki Basin before coming to the Gippsland Basin for the BMG activity. Cooper Energy contracted the Q7000 nearly 2.5 years ago in September 2020. Independent assurance reviews have been completed, covering technical benchmarking and process documentation. The plan is to plug the BMG wells during the course of the autumn period this year with the remaining subsea infrastructure to be removed 3 years later. Our P50 estimate for the wells abandonment activity remains at around $165 million. I will now hand over to Nathan to talk through the current status of the transfer of operatorship work streams at Orbost and the various initiatives underway to bring greater stability and higher overall processing rates at Orbost.

Thank you, Dan, and good morning. I'll speak to the 3 interrelated Orbost plant improvement plan work streams, namely the transition of operatorship of the Orbost gas plant from APA to Cooper Energy; the establishment of safe, sustainable and efficient operations at Orbost under our control; and delivering material rates and reliability improvements to the plant. Firstly, on the Orbost gas plant transition, we are on track to deliver the transition of operatorship in Q4 FY '23. Positive engagement, dialogue and information sharing is progressing with the key regulatory bodies: Energy Safe Victoria, WorkSafe Victoria and EPA. Landholder engagement is also ongoing and progressing well. As David and Dan have mentioned, we have now positioned an experienced Cooper Energy gas plant manager on-site working with APA. This is providing insight into key transition focused in proven areas such as Cooper Energy's competency-based training framework for the Orbost workforce, the site leadership structure and embedding a continuous improvement mindset. It's also pleasing to note that transition costs are tracking presently approximately 20% below budget. Turning now to Slide 16 and driving operational discipline and plant engineering and technical solutions. The objective is to establish a disciplined gas plant operating model at Orbost through the transition and the first 100 days of operation. This means delivering safe, reliable and efficient operations with a continuous improvement mindset. It is implementing Cooper Energy standards and approach to operating as described in our corporate management system and the regulatory approved safety management system. Some of the unplanned downtime we've seen over the last 4 months can, in my view, be avoided through bringing strong and continuous operational discipline to the site day in, day out. An engineering services team has been built with highly competent, experienced, disciplined engineers in mechanical rotating, electrical instrument control, process integrity and reliability and process safety to oversee the site. The plant leadership structure is being reorganized to bring greater focus on operational discipline and continuous performance improvement. We're deploying a training program specific to Orbost to support the transition across to our competency-based training framework. We're driving an operating culture where our business processes are followed, our procedures are followed, and a continuous improvement mindset is nurtured. This is the first chevron on the slide. So what about further production and reliability improvement, the second chevron? As we announced back in our November 25 webinar, we've established a project team chartered with delivering sustainable reliability and production rate increases at Orbost. The team is led up by an engineering services team leader, who has 25 years' experience as a senior process engineer with extensive refining knowledge and experience. Two specialist service providers have also been engaged, which includes the water treatment surfactant specialist at EARTHCARE group. This is the same group previously jointly engaged by APA and Cooper Energy to identify surfactants in the inlet gas stream, but his work was restricted and not completed. A highly experienced senior processing and project engineer that has first-hand experience and knowledge of the Orbost plant has been engaged. The team also includes the incumbent Orbost operations engineer who is based at Orbost. In addition to the knowledge and experience of this team, I can say that they are all passionate problem solvers and are highly motivated to improve plant performance. The team is adopting a rigorous approach and has identified multiple relatively low-cost improvement opportunities ranging from immediate to the medium term. Each opportunity has an assigned leading objective. A weekly technical form is in place, where each opportunity is reviewed in depth, and progress from the last week and plans for the coming weeks are discussed. This includes input of the team at the plant, and we are pleased to be doing this real work as early as we can with APA's flexibility ahead of the MHFL license transfer. So what are some of the examples? Firstly, solution chemistry, which is the focus area of EARTHCARE group. As mentioned, the water treatment specialist from EARTHCARE group formally engaged were reengaged. The objective of their work is to reduce the fouling and foaming in the H2S absorbers. A particular focus is to determine why the sulfur species being produced in the process has a sticky characteristic and is hydrophobic, i.e., water repelling. The technology is intended to produce hydrophilic, i.e., affinity for water sulfur species that are not sticky in nature. A solution may well be the development of an alternative antifoam. A sample program has been developed with samples being collected in the next few weeks to commence testing at EARTHCARE's plant in New South Wales. Secondly, the polisher unit. Since commissioning by APA, the polisher unit has not performed as expected. Specifically a rapid increase in pressure drop has been experienced, limiting run life to between 20 and 30 days or most recently less. This initiative is focused on replacing the existing absorbent media with a product that is less susceptible to water and solid sailing and has a controlled size distribution, which will achieve a lower pressure drop. Core vendors, including Haldor Topsøe, Johnson Matthey and UOP, have been engaged and are providing technical and commercial bids. We anticipate selecting a new absorbent material very soon. Thirdly, the solids removal package. I know a lot of people are curious about this. The packages are on-site, and we have appointed the project managers developing the tie-in and commissioning scope with a view to commissioning the plant -- solids removal part in the second quarter of FY '24. The project team is progressing testing of the solids removal package on the live processing solution. We want to do this testing as soon as possible as this will also work in partnership with the work EARTHCARE group is progressing given their interdependencies. There are other initiatives being progressed with the team such as an alternative absorber packing type. The installment spray distributors in the absorbers are replacing the antifoam dosing scheme, which I won't go through here. Hopefully, I've given you some insight into how we are going about the improvement initiatives at Orbost before we become the operator so that we can implement the right solutions as soon as possible. Importantly, we expect this work, together with improved operating discipline, to lead to more reliable and much higher processing rates at Orbost. I will now hand back to David.

Thanks, Nathan. As you can understand from that or take from that, there's a lot going on around Orbost than planned when the operatorship transfers from APA to ourselves. We believe we have assembled the right technical team who are working hard to deliver step changes to reliability and the rate at Orbost. The upside value in both the Otway and the Gippsland Basins for the company is very material. This is from the existing business and new projects. The next new business growth is in the Otway with the OP3D project. This involves developing the Annie discovery and additional high-quality, high-value, low-risk prospects. This is obviously, as mentioned earlier, once there is clarity on the regulatory regime and the pre-FID review of costs and joint venture arrangements. There's also a huge upside in the Gippsland Basin for the existing Manta resource and then the Manta Deep, Chimaera East and Wobbegong prospects, which can be processed all via Orbost. The strong balance sheet and growing operating cash flow to fund this growth mean the upside is material for Cooper Energy shareholders. Turning now to Slide 18. A few words on how we're building and growing our ESG credentials. This is an embedded part of our strategy. The cash flow growth is being achieved whilst we maintain our net 0 emissions position. To maintain and grow this leading position, we work on 3 pathways, which are interlinked. Firstly, we're maintaining the net 0 position, which delivers competitive advantages relative to our peers. Here, I refer in particular to finance costs, access to finance, people resourcing, and something for the future also is a net 0 premium on some of our gas pricing. Secondly, we're evaluating and pursuing opportunities to further improve the energy efficiency and reduce emissions intensity where this adds value and at our plants and nearby our operating sites. And thirdly, we're assessing new energy opportunities where we, Cooper Energy, have a competitive advantage. And importantly, it adds value to the existing assets and portfolio. One example, in November, we announced we're participating in a nature-based project in Vietnam with the Commonwealth Government's Department of Foreign Affairs and Trade and some other partners. The reforestation project will build capacity in local project implementation organizations and pursue opportunities for further project initiatives in Vietnam, and that's offset projects in Vietnam. This is a valuable low-cost source of offset credits with significant upside value in the volume of offsets we may be able to access. We view this project as an example of how our existing net 0 credentials and relationships enable benefits within our business as well as the community. Before we open the line for questions, a few summary comments. Notwithstanding the growth in production, revenue and cash flow, I want to acknowledge for the first half year, it has been very frustrating. As management, employees and shareholders, we share the frustration. The focus is on upping the performance, particularly at Orbost. The market is playing out as we forecast some 10 years ago. Southeast Australia is short of gas as soon as this winter. We have an excellent portfolio of assets, customers and relationships that will allow us to react to market conditions to optimize value and the returns for our shareholders. There is huge growth possible in both the Otway and Gippsland Basins with clear opportunity to commercialize via the Cooper Energy gas plants. Importantly, the company has the liquidity to pursue these opportunities with the expanded debt facility underpinned by the growing long-term cash flow. Cooper Energy will soon commence a new chapter with the new Managing Director, Jane Norman, to commence on the 20th of March. The company has the capability, the drive, the financial strength and the market opportunity to accelerate through our portfolio of opportunities. Under Jane's leadership, I'm confident this will happen. We can now open the lines for questions.

[Operator Instructions] And your first question comes from the line of Dale Koenders from Barrenjoey.

Just wondering, David. You spoke about the portfolio to react to opportunities in the gas markets. How quickly do you think Cooper could pivot if federal government intervention is acceptable both in terms of sort of moving Annie OP3D to FID and manage your appraisal forward?

Yes. Thanks, Dale. Let me just explain what we're doing to position for that, which I think will answer the question. We're completing the detailed FEED streams and finishing that work, as Dan said. So we can then press the button and go pretty quickly. That means that at the moment, our plan had been FID in April, May. That's now lost. That timing is foregone because of the regulatory changes that are pending. But what we'll be able to do, let's assume in a few months' time the regulatory arrangements are satisfactory. We've got the financing in place. We will have to revise their costs because we have to go out with what are the costs at the time. And obviously, we're keeping a track of that. The biggest determinant on timing is the offshore rig campaign. We, together with 3 others, formed a rig club to bring a rig into the region. The current expectation that, that would be from '24 onwards. We're in the process that -- we're expecting bids to be received. It's, I think, in the next couple of weeks. And our slots in that program will be something we'll discuss with the other members of the rig club. Previously, we've been expecting to hit first gas out of OP3D before the winter of '25. I think that's gone now. I think now we are looking at some period after that. As to when it is after that will depend on when we go to FID and what slot we end up with -- what slots we end up with in the program. That program will include as well as Annie -- our plan is to include subject to regulatory confirmation and other bits and pieces, a couple of wells in the Otway. So OP3D would fully utilize the capacity at Athena. And then also, we would want to put at least one, and depending on timing, maybe to wells in the Gippsland. One of those would be Manta, which would address -- there will be appraisal development well for the existing Manta resource and deepening into Manta Deep and probably 1 of the other 2 prospects. The timing of that, I think, would -- I wouldn't be surprised if the company is participating in that rig program in 2 different time slots. So one around the Otway and then the second one around the Gippsland. Does that answer the question? I know it's quite a long answer, but does that answer the question?

It does. That's perfect. Maybe just a second question. Depreciation has kind of stepped up meaningfully in the period versus last year. What should we be inferring from that? Is that a step-up of just project completion? Is that reserves? Is that higher abandonment CapEx feature?

No. The big -- I mean I'll leave Dan to get through the detail of it. But the big change, obviously, is the acquisition of the Orbost gas plant. And we're amortizing that on a per unit of production basis and the [indiscernible].

Yes. And the other one is, as you say, Dale, you've got it, we did reset our abandonment obligations or restoration provisions back in June last year. And that's -- at that time, there was a fairly significant bump up in restoration costs associated with the general rise in industry costs around that activity and also some of the activity -- or some of the regulatory asset views in terms of incorporating abandonment estimation costs for materials on the seabed. So that includes -- those things were included into our restoration provision at June, and you're seeing the impact of that on top of the Orbost -- capitalizing Orbost, as David mentioned.

So sorry, even though you haven't sort of taken ownership of the plant, you're still now depreciating on a...

We are the owners of the plant. APA is operating it on our behalf until the major hazard facility license is transferred.

That's what I meant.

We became the owners of the plant on the 29th -- 28th of July. Sorry, I'm 1 day late, 28th of July. And that's probably the biggest contributor to the increase.

Your next question comes from the line of Gordon Ramsay from RBC Capital Markets.

Yes, I was just going to ask about the D&A as well. It looks like the provision has gone from $27 million up to $157 million. So can we assume that, that basically is the main driver of the increase in D&A? You've also mentioned Orbost gas plant acquisition. Just want to kind of understand, I guess, the split down, if that's possible.

So the restoration provision for Orbost is in the region of $60 million to $70 million roughly, and the other impacts are the reset of restoration provisions at June of last year.

You're talking total there.

Just another quick question on Casino, Henry, you're cycling production out of wells there. Delaying OP3D, what does that mean in terms of the production outlook from the existing fields? Is that going to be on decline? Or are you going to be able to maintain production at current levels going forward?

Yes. Thanks. There is some decline, and we're mitigating that decline through the cycling of the 4 wells. If there is no -- I'll answer the question this way and then invite Andrew Thomas sort of answer things from a subsurface point of view. But if there's no OP3D at all, the existing life of Athena runs to -- at the moment, the earliest cutoff is 27. And that's -- there is a steady decline. It's not rapid, steady decline in the offshore. But Andrew and maybe Mike Jacobsen, who are both on the line, if you've got anything you want to add to that.

I can go first, David. No, I think that's right. I mean I think as related to the reserves, there's a window of when the production will go through. And that could be, as you indicated, David, all the way past 2030. And then, of course, there's probably some other things we can do at the plant to manage that as well. Mike, would you like to add some comments?

Yes, just to add to that. Andrew, thanks. What we're looking to do, Gordon, is we're looking to lower the inlet pressure of the plant. And that's a piece of work that we're going through now, which are almost complete. And what that will allow us to do is draw hard on the reservoirs, which will allow us to take the tail out for longer. So certainly, beyond 2027, as David mentioned, into sort of '28, '29 with the existing reserves that we've got.

Obviously, we'd extend that quite significantly and add to the reserve base.

Just last question on the polisher unit. The restart in January has been delayed. What was the reason for that?

Nathan and Mike, I can answer it, but I'll give you a non-technical answer. Nathan and Mike?

Thank you for the question. As I referred to in the presentation, the polishing media or the polisher unit has been experiencing elevated pressure drop. And in the most recent drill in January, the pressure drop was at the limit during pre-streaming and was taken immediately offline. We've identified some of the potential root causes associated with that, which would be implemented, defeating to the next cycle of media change-out and recommissioning, which notionally is going to occur in the month of April.

Mike, did you want to add anything to that?

No, I think Nathan has captured it very well, David. Thanks.

[Operator Instructions] And your next question comes from the line of Nik Burns from Jarden Australia.

Just some questions on Slide 16, the OGPP performance improvement plan. You got a sort of a near-term target average processing rate of high 50s terajoules a day. Just so we can get that definition correct, we shouldn't assume that your average rate between now and, say, December '23 is going to be high 50s, just basically saying that the activities you've got underway, you're planning to improve the average rates from current levels up to that high 50s by the end of that period. Is that correct?

Yes, yes, that is correct. Yes.

Okay. Yes, that's easy. And then just looking back, I think at the end of November, you gave a presentation. You had some shorter-term target average rates of low 50s terajoules a day, and to achieve that high 50s number, I think it was in separate band. You included activities such as the commissioning of the sulfur removal package there. But now you're saying you think you can achieve it without commissioning the sulfur removal package. Is that correct?

I'd phrase it this way, Nik. At the moment, we're averaging just under 50. I think it's 49 for this month, but I think we're running at about 49.6,49.7, and with the small incremental changes are making -- edging up that average rate, everything else staying the same. The step changes occur with the increased uptime and reinstatement of the polishing unit. That adds -- that can easily add, on 2 absorbers 7, 8 terajoules a day and some possibly more. And so that takes you into the low 50s. And then the other one, obviously, aside from the chemical work that -- chemistry and other little projects that are going on that Nathan spoke about is the commissioning of the solids recovery package, which is being slated for the end of winter this year. So it's a series of projects or a series of tasks, if you like, some of it operational and some of it -- and don't underestimate the value that comes -- or the increased volumes that come from operational discipline. That's the low-hanging fruit. And we've seen the benefit of that in the last 4 weeks. The February numbers are a hell of a lot better than the January numbers, and that's just operational discipline. And then there's the things like the polishing unit, the sulfur recovery package and the other projects that Nathan mentioned, plus a few that he hasn't. Does that answer your question? If there's more needed, I'm sure Nathan and Mike can add.

Yes. Look, I think that explains it pretty well, David. You're just thinking about the -- you've got a couple of dates on that slide as well about improved operational discipline saying now to December 23 or June 24. Does that -- those 2 dates, does that -- is that the date that you think that the sulfur removal package will be commissioned by that? So is there a chance it may not happen, say, by December, it might be, say, 6 months later?

The sulfur removal package comes in under the second chevron. And at the moment, the expectation is that, that would be after winter. There is an interplay between that and the work that the EARTHCARE group is doing. And I'm going to hand across to the technical experts to answer that in a little bit more detail. So Nathan, did you want to have a crack at that?

Yes. Thank you for the question. The interplay Dave is referring to is -- I made reference to the work EARTHCARE group is doing, looking at the solution chemistry and specifically looking at the sulfur characteristics we're seeing. And some of the potential solutions associated with that work goes hand in hand with the solids removal package. The solids removal packages essentially remove a certain size distribution of solids out of the rich solution. So any refinements we make to the circulating solution directly correlates -- is an interdependency with the solids removal package. So we're optimizing the schedule and the timing of those 2 activities so that they can work effectively and efficiently together. As David said, we're notionally working towards half 1 FY '24 for the solids removal package time. Also acknowledging there is still commissioning time work activity still to be performed and worked through the project manager that we've reinstated I referred to earlier in the presentation.

For the nontechnical folks that will be listening, the solids removal package, I mean -- and what we've got here is a solution that goes around in a cycle. By removing the solids, we are changing the composition of that solution. And it's a chemical process. So there is a need then to understand what taking the solids out -- the impact that, that will have on the process. We expect there to be some period before the process would settle down. Whether that's a couple of days or a couple of weeks, time will tell. It's for that reason that we don't want to commission the solids removal package in the middle of winter, which is a time when you want production to be stable as possible, as high as possible and minimizing interruption. So the solids removal package, we realize, is going to introduce a change to the chemistry. And to understand and properly interpret that change and make sure it's having the minimum impact, we do that outside of the peak revenue, peak cash flow period, which is winter.

Look, I'll just slip one more question in. Just the appointment of Cooper Energy gas plant manager at Orbost, can you talk about why you felt it necessary to have your own plant manager there? What do you expect them to achieve given, I guess, APA staff on-site will effectively become Cooper's staff post-handover? Isn't there a gas plant manager there already?

Mike, do you want to have the first crack at that? And then I can add anything.

Yes. No, sure, Dave. Yes. Nick, just I think the first point really is what we wanted to do is to have an experienced person down, a Cooper Energy person, to understand when we get to day 1, when we take on the license, any issues, any areas that we -- and gaps that we need to close. It would be very hard for us to come in at day 1 without any prior experience and then come in to operate the plant efficiently and safely. So the first objective was to have someone down there, see how the plant is operating, give us some insights into what's going on down there. So then we can put plans in place if that's what is required to be able to fill any gaps or any shortfalls that we see to our own systems. So our systems are somewhat different to APAs. So we need to close that gap. So that is the number one thing. The number two is we want to stamp our own, I guess, flavor on this. We want to -- this is a Cooper Energy plant, and we want to be doing this the way that we've been operating with Athena. So the operational discipline that you've seen. It's very important that we continue to operate Orbost as we have Athena. So that's part of the reason, and that's the second part of the reason. So I hope that answers it.

Can I add also, Nik? And it was referred to in the talk track. There was a series of interruptions through December, January. We got very concerned, but some of these were avoidable. And we were talking active -- we were in active conversations with APA, recognizing the need for transition. We sought and APA supported us locating a senior person on-site. To answer your specific question about is there a plant manager there in place at the moment, the APA organizational structure is different to ours. The previous head of the asset was not based at the plant. There was someone at the plant reporting to that person. Our model is to place the sort of technical capability on-site. And we will keep using the word discipline. A key part of that is making sure the conversations are had, and the operators are in constant communication with the plant manager, and the training modules and skills needed are there on a 24/7 basis. Take from that answer that some improvement was needed, and we've taken action to aid that improvement before we own the license.

That's clear. I was just trying to work out -- I understand like the acquisition of the plant included contingent payments to APA if production rates are above 50 terajoules a day. It's just looking increasingly unlikely that will be triggered. I'm just wondering if there was -- if that was motivating the staff on-site, and now they can't potentially achieve it, whether you suddenly need to take a more firm action there to ensure higher plant performance until you get the formal handover of operatorship.

I think if -- in a way you've summarized it, yes, correct. I think at the moment, our expectation is there will not be any performance-based payments. It's going to have to be outstanding performance between now and the transfer of the license, which we at the moment hope is in May.

Your next question comes from the line of Nick Palethorpe from Origin Capital.

David, you deserve commendation for building and positioning the company along hard road. And one would hope common sense prevails in the years ahead and the true value is realized. And we wish you well for your next chapter. A question of Dan, if I may. Dan, if you recast some of the financial improvement on a per share basis, recognizing the major share issue to acquire Orbost, what would approximately the percentage improvement be?

I can't -- I don't have a number for you to give you that right now, Nick. But I think when we talked about the acquisition at the time of the equity raise, we did talk in detail about the transaction being accretive. And I think we talked about the savings from the removal of the toll being very substantial in terms of our overall cost basis. So those -- that view hasn't changed. And I think once we are operating the plant at the kind of levels that Nathan has been talking about and what we've covered here, you will see that reinforced in a really strong way. Right now, we're in a period -- as I said, we're through this transition period. APA is operating it until we get the license, which as we've talked about, is very much on track. We plan to be operating it certainly much more effectively, and that includes in terms of costs as well as other things. And I talked about the fact that free cash flow generation on an annualized basis looks around $100 million, but it really should be 50% or more than that. And so that's very, very attractive in terms of free cash flow yield relative to the share price today.

There are a couple of things, Nick, yes, and thank you for your comments. Appreciate it. Look, I want to acknowledge the frustrations of the last 2, 3 years. It's not been easy for the team. I could use some other language, but we're on a public call, so I won't. But it's been frustrating. But just to put the purchase of Orbost in context, at $270 million, which is what it's looking like, I'd be surprised if it's not $270 million, that -- our original contract with APA was for them to build the plant for no more than $250 million, plus $20 million acquisition cost, which coincidentally equals $270 million. So we have acquired the plant, notwithstanding they spent well in excess of $500 million on it for what was the price that we had originally contemplated, albeit it's not working at 68 terajoules a day nameplate yet. But we've got clear pathways to get there. The other way of looking at it is when we did the back calculations and the tariff that we were paying APA at the time and then said, okay, now net present value that back, that equated to a steady rate of 55 terajoules a day -- actually, a little bit less than 55 terajoules a day. I think $285 million translated to 55 terajoules a day. So I think the emphasis on getting the rate up and stable, the accretion value back to shareholders is rapid. Then you add over on top of that whatever happens to spot gas prices. So I'm expecting the good work being done by the technical folk over the next couple of years to see significant accretion together with increased exposure to spot prices, which are on the up, whichever way you look at it.

And David, very quickly, your next chapter. I would hope your expertise is not being lost to the industry.

Thank you, Nick. I haven't thought about that too much. There's a 4-letter word called rest, which is the first, and a family that needs [indiscernible].

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

Just moving across to gas sales agreements. Could you talk a little bit about when the next price resets on those occur, roughly proportions and perhaps also when some of those come off contract?

Yes. Firstly, Eddy, I'll get -- I'll ask you to answer that. And we have disclosed that in previous presentations. But we do increase our gas sales agreements by 100% CPI. So there was a circa 7.5% increase as of January this year. But Eddy, do you want to talk about that?

Yes. Thank you, David. Yes, I was going to mention that the CPI increases every year. So in the range of the inflation that you mentioned, David. Also, the largest contract, there will be a price review originally coming up in 2024, '25. But it is based on the volumes that were produced, and it is balanced between alternative delivery points in Orbost as well. So as we get closer and depending on what the rate of the OGPP is, we'll start to narrow down further [ actually ] when the price review will be. And then the other contracts have expected where the 2 parties come together and negotiate if that extension applies or if another GSA becomes available. If the rate does improve into -- well into the 60s or average 65, as you mentioned in the previous slide, there will be room to put another GSA into the market for some of the additional volume.

We've just also put up on the screen -- sorry, we can't send -- there was a presentation which we did in -- when was that one, Morgan? The latest investor presentation shows a graph of existing contracts, when they expire and when price reviews. And as Eddy said, you'll see the first one coming in, in '24. And then they sort of stagger through to '26, '27. But they are, in some respects, rate related.

Great. And then just on Dan's comment around annualized free cash flow and that sort of 50% higher expectation, perhaps just talk a little bit around some of the metrics and timing of that, Dan.

Well, we don't want to be too specific yet in terms of timing around that. It's partly just an acknowledgment and a reflection that the first half and Q2 in particular wasn't where we expect performance to be. And we try to -- and we're able to take some immediate steps at Orbost with the plant manager down there. For example, our own person down there as an experienced plant manager. So I think the outlook for when can we expect that kind of free cash flow generation, I think we have to prove that. And hopefully, what we've done through the call in particular with some of the time that Nathan has given you to talk through some of the activity, you can see a way for us to move from that kind of average 40 terajoules a day, which we were seeing for a good portion in November and December to getting back to levels around 55 terajoules and beyond. And so if we -- if the plant is performing along those lines and we have a more normal environment, then I'm confident that we'll see free cash flow generation well above the current level that we've talked about and experienced in the first half.

That's good. And then just finally, if I may, and sort of harks back to the first question around how quickly could you get going on OP3D, assuming the regulatory framework is satisfactory. I imagine assuming that is somewhere around the middle of this calendar year, would you be out pretty quickly with capital cost updates and the like and project economics for OP3D?

Yes, yes, I would expect we would, Stuart. It's really linked into -- I mean, we've pretty much got close to final capital costs now. I mean if someone -- if the government [ magic ] an acceptable code today, we'll be going flat out to put -- to progress to FID as quickly as possible. We've learned over the last 4, 5 months to expect the unexpected from this government. And so we're just being a little cautious. So we're getting ourselves fit and ready, packaging everything up. It's a press of a button and go out and get the latest costs. But we don't want to overpromise and underdeliver on the timing of OP3D. And some of this has been dealt with through master agreements that we have with key providers. So we've built alliance-type arrangements with key providers, [ wellheads, the pipelay and umbilical vessels ], for example, organizations like that, that we've worked with in the past. We've matured everything. We've wrapped it up, put it on hold, knowing that -- and told them that don't be surprised if we come back and press the button quickly. So we've done everything we can without putting ourselves in a place where we're taking unreasonable risk.

Dave, perhaps just remind us of your understanding of where the government is at in terms of timing of submissions, would you, I think, early this month?

Yes. We understand that a draft code will be issued in the middle of next month, in the middle of March. When the government says the middle of March, to me, that means any day between the 2nd of March and the 28th of March -- or 29th of March. The end would be the 30th and the early would be the 1st. So I'm expecting some stage in the next couple of weeks. And then we're told -- our intelligence is that will be a couple of weeks for comment on the code. And then that will be considered before the code is implemented. And that's where the real rubber hits the road for us. The position that we've sought and others we understand have been consistent as well, including some of our competitors and large companies, but new resources, new developments such as OP3D and other projects are excluded from the code. If that's the case, and it's very clear, and then that's embedded in the regulations, then we'll be back into working this very hard very quickly.

There are no further questions at this time. I turn the call back over to David Maxwell for closing remarks.

Well, thanks, everybody, for listening and the Q&A. I hope you take 3 things from it. One, that the last few months in particular, that hasn't been what we had expected, we had planned. It has been frustrating, and the bulk of that frustration rests with the performance of Orbost. Secondly, the company has taken action to accelerate its involvement with Orbost to put the best people we can, best leadership we can in and around the plant to get that rate up as early as possible. And thirdly, that the fundamentals of the strategy, the fundamentals of the business, the assets that are in the business are very well positioned. It's a case of getting reliability into particularly the Orbost gas plant, getting certainty around the regulatory regime and allowing our good technical people then to improve performance. On that note, thank you very much for your support. Over and out.

This concludes today's conference call. You may now disconnect.