Good day, and welcome to the Cooper Energy Limited FY 2023 half year results. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press Star one on your telephone keypad. If you would like to withdraw your question, press the Star one again. For operator assistance throughout the call, please press Star zero. 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. 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 two and the first half highlights. In this period, we delivered record first half production, revenue, and underlying EBITDAX, with zero 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 recurring unplanned downtime at 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 gonna hear from Nathan, who'll 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 2022. That's from 39 terajoules a day to 48 terajoules a day. 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 rates were steady throughout the first half of FY 2023. 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 AUD 101 million, attributable to higher gas prices received. Underlying EBITDAX increased 134% to AUD 60 million. This follows the acquisition of Orbost and a big reduction in third-party gas purchases. Operating cash flow increased 98% to AUD 55 million. That is, they're pretty close to double. Dan will give you a breakdown of these increases soon. On slide three, 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 zero lost time incidents 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. We maintain our carbon-neutral accreditation and remain net zero 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 four 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 four 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 AUD 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 Victorian 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. 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 five now, which is the only industry thematic we'll speak to today, but highly relevant to our story. This data is taken from the opennem.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, 63% of electricity was generated from variable renewables, as compared to 34% for the entire NEM. 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 the electricity supply system in other states.
There's nothing special about these seven days, more or less the 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 on 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 six, 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 AUD 101 million was also a record for the first half, 6% higher than the first half of FY 2022.
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. 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 1st. This one-off change meant a reduction in revenue of around AUD 1.8 million based on the average realized oil price in the 1st quarter. Unit cash costs were around AUD 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.
Excluding the cost of third-party gas purchases of 128 terajoules and line pack costs. Underlying EBITDA more than doubled. I'll talk more about that in a couple of slides. As David has mentioned, this was also a record for the company. Operating cash generation almost doubled to AUD 55 million. In summary, the business has started to really show its cash generation potential, although I would note the 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 2022, continuing the broader trend over the last 15 months of higher average processing rates.
This was driven by strong plant performance in Q1 FY 2023, averaging 51 terajoules a day, with September a particularly good month, averaging 56 terajoules a day with high 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 plant trips, as well as a planned two-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. 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. 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. 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 eight and a review of the Otway. Production in the Otway from Casino Henry net upbeat 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's 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 nine provides an overview of the expansion in underlying EBITDAX following the acquisition of Orbost, bridging performance back to the prior comparable period. The first two 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 two bars together amount to an increase of around AUD 7 million-AUD 8 million. As I mentioned earlier, average realized gas prices were also up by about 17.5% or another AUD 16 million or so.
We saved around AUD 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. At the end of July, we paid the main tranche of consideration of AUD 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, as set out here.
From the pro forma cash balance of AUD fifty-two and a half million dollars, you can see we generated positive operating cash flow generation of around AUD 55 million, growing cash to a total of over AUD 107 million. CapEx for the half was just under AUD 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 AUD 80 million at the end of the half. If I exclude the three CapEx elements I just mentioned, the business generated around AUD 50 million underlying free cash flow for the half. 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 AUD 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 the new loan agreement that we had mandated at the time we announced the acquisition of Orbost. This resulted in the debt facility more than doubling and the bank group growing from five to eight . In fact, we scaled back demand within the bank group, which bodes well for the utilization of the additional AUD 120 million accordion feature when new borrowing-based assets can be brought into the facility, such as Annie.
The bank group comprises a strong group of commercial banks, providing the company with competitive terms out to Q1 FY 2028. This provides us with around AUD 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 later 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. Processing rates at Orbost fell to 44 terajoules a day on average in Q2, significantly below its already conservative forecast.
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 June. 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 forecasts 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 polishing 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 AUD 115 million to AUD 133 million. Due to the large impact that 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 2023. On slide 13, we have 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 AUD 20 million, and 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 AUD 1 million less than the original guidance, inclusive of the Orbost integration spend. On slide 14, we are now around six 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 two and a half 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 three years later. Our P50 estimate for the wells abandonment activity remains at around AUD 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. 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 rate and reliability improvements to the plant. Firstly, on the Orbost gas plant transition, we're on track to deliver the transition of operatorship in Q4 FY 2023. Positive engagement, dialogue, and information sharing is progressing with the key regulatory bodies, Energy Safe Victoria, WorkSafe Victoria, and the EPA. Landholder engagement is also ongoing and progressing well. As David and Dan have mentioned, we've now positioned an experienced Cooper Energy gas plant manager on-site working with APA.
This is providing insight into key transition-focused improvement 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's 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 four months can, in my view, be avoided through bringing strong, 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. 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 with 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, Earthcare Group engineer, that has firsthand 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 lead and objective.
A weekly technical forum is in place, where each opportunity is reviewed in depth and progress for the last week and plans for the coming week are discussed. This includes input of the team at the plant, we are pleased to be doing this real work as early as we can with APA's flexibility ahead of the MHF license transfer. What are some of the examples? Firstly, solution chemistry, which is the focus area of Earthcare Group. As mentioned, the water treatment specialist, Earthcare Group, is formally engaged or re-engaged. The objective of their work is to reduce the fouling and foaming in the H2S absorbers. A particular focus is determining 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 polishing unit. Since commissioning by API, the polishing 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 fouling and has a controlled size distribution, which will achieve a lower pressure drop. Core vendors, including Haldor Topsoe, 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've appointed the project manager who's developing the tie-in and commissioning scope, with a view to commissioning the plant, solids removal plant, in the second quarter of FY 2024. 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 by the team, such as an alternative absorbent, sorry, absorber packing type, installing spray distributors in the absorbers, and replacing the antifoam dosing skid, which I won't go through here.
Hopefully, I've given you some insight into the, 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 and planned for when the operatorship transfers from APA to ourselves. We believe we've 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 Eni 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, the review of costs and joint venture arrangements.
There's also huge upside in the Gippsland Basin for the existing Manta resource, and then the Manta Deep, Camira 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 zero emissions position. To maintain and grow this leading position, we work on three pathways which are interlinked. Firstly, we're maintaining the net zero 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 zero 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. Thirdly, we're assessing new energy opportunities where we, Cooper Energy, have a competitive advantage. 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 zero 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.
Thank you. At this time, I would like to remind everyone, in order to ask a question, press star then the number one on your telephone keypad. Your first question comes from the line of Dale Koenderink from Barrenjoey. Your line is open.
Good morning, guys. Just wondering, Dave, 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 OP 3D to FID and Manta appraisal forward?
Yeah, thanks. 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. 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. What we'll be able to do. Let's assume, you know, in a few months' time, the regulatory arrangements are satisfactory. We've got the financing in place. We will have to revise our costs 'cause we have to go out with what are the costs at the time.
Obviously, we're keeping a track of that. The biggest determinant on timing is the offshore rig campaign. We, together with three others, in a rig, formed a rig club to bring a rig into the region. The current expectation that that would be from 2024 onwards. We're in the process that we're expecting bids to be received, bids, I think, are in the next couple of weeks. 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 2025. 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 and what slots we end up with in the program. That program will include as well as Eni, 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. Then also, we would wanna put at least one, and depending on timing, maybe two wells in the Gippsland. One of those would be Manta, which would address, there would be appraisal development well for the existing Manta resource, and deepening into Manta deep and probably one of the other two prospects. The timing of that, I think, you know, we.
I wouldn't be surprised if the company's participating in that rig program in two different time slots. One around the Otway and then a second one around the Gippsland. Does that answer the question? I know it's quite a long answer, but Dale, does that answer the question?
No, it does. That's perfect.
Yeah.
Maybe just a second question. Depreciation's kinda stepped up meaningfully in the period versus last year's. 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, 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. The other-
Across that. Yeah. The other one is, as you say, Dale, you've got it, is we did reset our abandonment obligations or restoration provisions back in June last year. That's at that time, there was a fairly significant bump up in restoration costs associated with, you know, the general rise in industry costs around that activity. Also some of the activity or some of the regulatory asset views in terms of incorporating abandonment estimation costs for materials on the seabed. 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.
Sorry, even though you haven't sort of taken ownership of the plant, you're still now depreciating it on a...
No, 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 28th of July. Sorry, I'm one day late. 28th of July.
Okay.
Yeah. I mean.
Great. Thank you.
... that's probably the biggest contributor to the increase.
Your next question comes from the line of Gordon Ramsay from RBC Capital Markets. Your line is open.
Thank you. Thanks very much for the presentation, gentlemen. Yeah, I was just gonna ask about the D&A as well. It looks like the provision's gone from AUD 27 million up to AUD 157 million. Can we assume that that basically is the main driver of the increase in D&A? You also mentioned Orbost Gas Plant acquisition. Just wanna kind of understand, I guess, the split, Dan, if that's possible.
The restoration provision for Orbost is in the region of AUD 60 million-AUD 70 million, roughly. The other impacts are the reset of restoration provisions at June of last year.
Got it. Thank you.
You're talking.
Just another-
Total there. Yeah. Yeah.
Yeah. 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 gonna be on decline, or are you gonna be able to maintain production at current levels going forward?
Yeah, thanks. Good. There is some decline, and we're mitigating that decline through the cycling of the 4 wells. I'll answer the question this way and then invite Andrew Thomas to answer things from a subsurface point of view. If there's no OP3D at all, the existing life of Athena runs to, at the moment, the earliest cutoff is 27. There is steady decline. It's not rapid, steady decline in the offshore. Andrew and maybe Mike Jacobson, who are both on the line, if you've got anything you wanted to add to that.
I can go first, David. I think that's right. I mean, I think, as related to reserves, there's a window of when the production will go to, and that could be, as you indicated, David, all the way past 2030. 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?
Yeah, 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
That's a piece of work that we're going through now, which we're almost complete. What that will allow us to do is draw harder on the reservoirs, which will allow us to, you know, take the tail out for longer. Certainly beyond 2027, as David mentioned, into sort of 2028, 2029 with the existing reserves that we've got.
Okay. Thank you.
OB-30 obviously, would extend that quite significantly and add to the reserve base.
Yep. 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.
Yeah, I'm happy. Yeah, Nathan, you go for it.
As I referred to in the presentation, the polishing media or the polishing unit has been experiencing elevated pressure drop. In the most recent fill in January, the pressure drop was at the limit during free 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 we notionally think is gonna occur in the month of April.
Okay. Thanks, gentlemen.
Mike, did you want to add anything to that?
No, I think, I think Nathan's captured it there well, David. Thanks.
Yep.
As a reminder, if you would like to ask a question, please press star one on your telephone keypad. Your next question comes from the line of Nik Burns from Jarden Australia. Your line is open.
Thanks, team. Just some questions on slide 16, the OGPP, Performance Improvement Plan. You've got a sort of a nearer term target average processing rate of high fifties terajoules a day. Just so we can get that definition correct, we shouldn't assume that your average rate between now and say, December 2023 is gonna be high fifties. You're 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 fifties by the end of that period. Is that correct?
Yes. Yes, that is, that is correct. Yes.
Okay. Yeah, that's easy. Just looking back, I think at end of November, you gave a presentation, you had some shorter term target average rates of low 50s terajoules a day. To achieve that high 50s number, I think it was in a separate band, you included activities such as the commissioning of the sulfur removal package there. 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. I think we're running at about 49.6, 49.7. 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, you know, that can easily add on two absorbers, 7-8 terajoules a day, and some possibly more. That takes you into the low 50s.
The other one, obviously, aside from the chemical work that chemistry and other little projects that are going on, one that Nathan spoke about is the commissioning of the solids recovery package, which is being slated for the end of winter this year. It's a series of projects or a series of tasks, if you like, some of it operational and some of it. Don't underestimate the value that comes, or the increased volumes that come from operational discipline. That's the low-hanging fruit. We've seen the benefit of that in the last four weeks. The February numbers are a hell of a lot better than the January numbers. That's just off operational discipline.
Then there's the things like the polishing unit, the self-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.
Yeah. Look, I think that explains it pretty well, David. Thanks for that. You've got a couple of dates on that slide as well about improved operational discipline, saying now to December 2023 or June 2024. Does that, those two dates, does that, is that the dates that you think that the sulfur removal package will be commissioned by that? Is there a chance it may not happen, say by December, it might be, say, six months later?
No. The sulfur removal package comes in under the second chevron. 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. I'm gonna hand across to the technical experts to answer that in a little bit more detail. Nathan, did you wanna 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. That work goes hand-in-hand with the solids removal package. The solids removal package is to essentially remove a certain size distribution of solids out of the rich solution. Any refinements we make to the circulating solution directly correlates or is an interdependency with the solids removal package. We are optimizing the schedule and the timing of those two activities so that they can work effectively and efficiently together. As David said, we're notionally working towards half one FY 2024 for the solids removal package tie-in.
Acknowledging there is still commissioning tie-in work, activities still to be performed and work through the project manager that we've reinstated, I referred to earlier in the presentation.
For the non-technical folk that'll be listening, I mean, what we've got here is a solution that goes round in a cycle. By removing the solids, we are changing the composition of that solution. As it's a chemical, it's a chemical process, 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. The solids removal package we realize is gonna 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 cashflow period, which is winter.
Thanks for that, David and Nathan. Look, might just flick one more question in. Just the appointment of a 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 staff post-handover? Isn't there a gas plant manager there already? Cheers.
Mike, do you wanna have a first crack at that?
Yeah, sure.
I can add anything.
Yeah, sure, Dave. Yeah.
Yeah. No, sure, Dave.
Yeah, Nick, just, I think probably the first point really is what we wanted to do is to have an experienced person down there, a Cooper Energy person, to understand, when we get to day one, when we take on the license, any issues, any gaps that we need to close. It would be very hard for us to come in at day one without any prior experience and then come in to operate the plant efficiently and safely. The first, you know, the first objective was to have someone down there, see how the plant's operating, give us some insights, you know, into what's going on down there.
We can put plans in place, if that's what is, you know, required to be able to fill any gaps or any shortfalls that we see to our own systems. Our systems are somewhat different to APA's, so we need to close that gap. That's what that is the number one thing. The number two is, you know, we wanna stamp our own, you know, I guess flavor on this. We want to. This is a Cooper Energy plant, and we want, you know, to be doing this the way that we've been operating with, you know, Athena. The operational discipline that you've seen. You know, it's very important that we continue to operate Orbost as we have Athena.
That's, that's part of the reason. That's the second part of the reason. I hope that answers it.
Can I add, also, Nick. 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. 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 suitable technical capability on site. We 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.
No, that's clear. I was just trying to work out, understand like the acquisition of the plant, including contingent payments to APA if production rates are above 50 terajoules a day. It's just looking increasingly unlikely that'll be triggered. I'm just wondering if that was motivating the staff on-site, and now they can't potentially achieve it, whether you sort of need to take a more firm action there to ensure higher plant performance until you get the formal handover of operatorship.
I think if, yeah, in a, 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.
Great. Thanks.
It's gonna have to be outstanding, it's gonna have to be outstanding performance between now and the transfer of the license, which we at the moment hope is in May.
That's clear. Thanks, David. Thanks, team. Cheers.
Your next question comes from the line of Nick Paltoglou from Ord Minnett. Your line is open.
Hi, David. You deserve commendation for building and positioning the company along Hard Road. 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 improvements be?
I can't. I don't have a number for you to give you that right now, Nick. I think, you know, when we talked about the acquisition, at the time of the equity raise, we did talk in detail about the transaction being accretive.
Yeah.
I think, you know, we talked about the saving from the removal of the toll being very substantial in terms of our overall cost basis. You know, those that view hasn't changed. I think once we are operating the plant at the kind of levels that Nathan has been talking about and that we've covered here, you will see that reinforced in a really strong way. Right now we're in a period, as I said, where 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.
You know, I talked about the fact that free cash flow generation on an annualized basis looks around AUD 100 million, but it really should be 50% or more than that. That's very, very attractive in terms of free cash flow yield relative to the share price today.
Yeah. No, thanks, Dan.
Can I just add a couple of things, Nick? Firstly,
Yeah, sorry, Dave.
Thank you.
Yep.
Yeah, sorry. Thank you for your comments. Appreciate it. Look, I want to acknowledge the frustrations of the last two, three years. It's not been easy for the team. I could use some other language, we're on a public call, so I won't. It's been frustrating. Just to put the purchase of Orbost in context, at AUD 270 million, which is what it's looking like, I'd be surprised if it's not AUD 270. That Our original contract with APA was for them to build the plant for no more than AUD 250 million plus AUD 20 million acquisition costs, which coincidentally equals AUD 270.
We've acquired the plant, notwithstanding they spent well in excess of AUD 500 million on it, for what was the price that we had originally contemplated. Albeit it's not working at 60-68 terajoules a day nameplate yet, 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 translated to 55 terajoules a day. I think the emphasis on getting the rate up and stable, the accretion value back to shareholders is rapid.
You add over on top of that whatever happens to spot gas prices. I'm expecting, you know, 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.
Yep. 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 four-letter word called rest.
I'll leave that.
There's a four-letter word called rest, which is, the first. A family that needs a bit.
Absolutely. Well done.
Thank you.
Your next question comes from the line of Stuart Howe from Bell Potter Securities. Your line is open.
Thanks, Dave and Dan. Just moving across to gas sales agreements. Could you talk a little about when the next price resets on those occur, roughly proportions and perhaps also when some of those come off contract?
Firstly, Eddie, I'll ask you to answer that. We have disclosed that in previous presentations, we do increase our gas sales agreements by 100% CPI. There was a circa 7.5% increase as of January this year. Eddie, Do you wanna talk about that?
Yeah. Thank you, David. Yeah, I was gonna mention 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, 2025, but it is based on the volumes that were produced and it is balanced between alternative delivery points with Orbost as well. As we get closer and depending on what the rate of the OGPP is, we'll start to narrow down further exactly when that price review will be. Then the other contracts have extended where the two parties come together and negotiate if an extension applies or if another GSA becomes available.
If the rate does improve, you know, into well into the 60s or, you know, 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
Sorry, we can send. There was a presentation which we did in... When was that one, Morgan?
The latest investor presentation.
The latest investor presentation. Shows a graph of existing contracts, when they expire and when the price reviews. As Eddie said, you'll see the first one coming in in 2024, and then they sort of stagger through to 2026, 2027. They are in some respects, rate related.
Great. Thanks, guys. Then just on Dan's comment around annualized free cash flow and that sort of 50% higher expectation, can I just talk a little bit around some of the metrics and timing of that, Dan?
Well, we don't wanna be too specific yet in terms of timing around that. It's partly just an acknowledgement and a reflection that first half and Q2 in particular wasn't where we expect performance to be. You know, we tried to and were able to take some immediate steps at Orbost with the plant manager down there, for example, with our own person down there as an experienced plant manager. I think the, you know, the outlook for when can we expect that kind of free cash flow generation, I think we have to prove that.
Hopefully what we've done through the call, in particular with some of the time that Nathan's given you to talk through some of the activity, you can see a way for us to move from that kinda average 40 terajoules a day, which we were seeing for a good portion of November and December, to getting back to, you know, levels around 55 terajoules and beyond. 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 that, the current level that we've talked about and experienced in the first half.
That's good. Thanks, Dan. Just finally, if I may, 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, you know, assuming that is somewhere around the middle of this calendar year, would you be out pretty quickly with capital costs updates and the like for, and product economics for OP3D?
Yes. Yes, I would expect we would, Stuart. It, 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 magicked an acceptable code today, we'd be going flat out to progress to FID as quickly as possible. We've learned over the last four, five months to expect the unexpected from this government. We're just being a little cautious. We're getting ourselves fit and ready, packaging everything up to press of the button and go out and get the latest costs. We don't wanna overpromise and under-deliver on the timing of OP3D. Some of this has been dealt with through master agreements that we have with key providers.
We've built alliance type arrangements with key providers, you know, wellheads, the pipe lay, and umbilical vessels. For example, organizations like that who we've worked with in the past. We've matured everything. We've put it, 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. 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's at in terms of timing of, you know, submissions were due, I think, earlier this month?
Yes. Yeah. We understand that a draft code will be issued in the middle of next month, in the middle of March. Now, when the government says the middle of March, to me, that means any date between the second of March and the 28th of March, or 29th of March. The end would be the 30th and the early would be the first. So I'm expecting some stage in the next couple of weeks. Then we're told, our intelligence is that it'll be a couple of weeks for comment on the code. Then that will be considered before the code is implemented. 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.
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.
Great. Thanks, guys. That's all from me.
Thanks, Stuart. Thanks, Joey.
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 to the Q&A. I hope you take three things from it. One, that the last few months, in particular, you know, it 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 is taking 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. 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.