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Good day, and welcome to the Cooper Energy Limited Second Quarter FY '23 Quarterly Report Conference. [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.
Thanks very much, and welcome to everybody to the second quarter FY '23 conference call for Cooper Energy. And I'm joined this morning by members of our leadership team. We released our December 2022 quarterly report this morning. And I'm going to make a few comments on the results and then hand over to Q&A. The total production for the quarter was 0.83 million barrels of oil equivalent or around 55.2 terajoules equivalent per day, which was down 16% from the first quarter.
Group production for the quarter was impacted by unplanned outages at the Orbost Gas Processing Plant. The Orbost Plant, as most of you would know, is operated by APA Group. The result was also impacted by a planned 10-day shutdown at the Athena Gas Plant. The lower production volumes meant there was less gas sold into the spot market than in the previous quarter. And the spot price was also lower as we moved into the shoulder period and moved out of the peak winter period.
This resulted in a lower average realized gas price of $8.38 per gigajoule compared to $9.06 a gigajoule in the first quarter. Total revenue for the second quarter was $45.8 million. It's important to note that the Cooper Energy term gas sales agreements and here, I'm talking about the gas sales agreements for Sole, Casino, Henry and Netherby and the sales to the spot market are not caught by the recently introduced price cap of $12 a gigajoule to 2023.
The 6-month year-to-date numbers for production and revenue are a significant improvement on this time last year, with group production up 16% and revenue up 6% compared to FY '22. Having said that, the performance of the Orbost plant for the December quarter was well below the operational standards we expect. And below what we as Cooper Energy will set for ourselves once we operate the plant. The plant was impacted by a series of unrelated interruptions and trips, which were uncharacteristically high for one quarter.
An allowance for unplanned events is included in our production forecast assumptions. The downtime events in the December quarter are not systemic, and they were unrelated to the sulphur removal treatment issues, which we have discussed on a number of occasions. As outlined in the November operations update, within Cooper Energy, we have engineering work streams that are working to implement improvements leading up to and following the transfer of the major hazard facility license, which is when Cooper Energy will commence operating the plant, taking operatorship from APA. APA continued to perform regular absorber cleans on a 2- to 3-week cycle and regularly change out the polisher media as required. I note that the polishing policy unit is not currently online. In the near term, the average production rate is expected to be around 52 terajoules a day, and we'll do what we can to increase this. During December, we appointed a very senior engineer from within our organization, who's got operations experience in a number of much bigger gas plants to the role of operations readiness manager.
We're pleased to say he's now working with APA in a site-based capacity, leading up to the license and operatorship transfer that I mentioned. Specifically, on the Orbost major hazard facility license, this was submitted to WorkSafe Victoria in early December, and we're on track for the license to be transferred to Cooper Energy by the middle of this calendar year. Submissions for other licenses, and this includes the export pipeline license, were also made during the quarter.
Our hope is to secure the transfer of all licenses by May, and we will do all we can within our control to deliver on this timing. As outlined in the September quarterly, with tie-in and commissioning of the sulphur recovery package, this is the filtration package, remains an integral part of the Cooper Energy plans at Orbost. The plan remains that we will manage and complete this when Cooper Energy is the operator.
The SRP or sulphur recovery package commissioning will be performed at a time to minimize the impact of downtime balancing market and customer needs. Now turning to a number -- to a few other highlights from the quarterly. Firstly, the strong year-to-date metrics. As I mentioned earlier, the year-to-date performance was improved markedly compared to the same period last year, with production up 16% and average realized gas prices up 18% and revenue up 6%. This is despite a difficult second quarter at Orbost, which I've just talked about.
Sole gas process through the Orbost plant is up 21% compared to this time last year. This gives context to my earlier remarks. The issues in the December quarter were not systemic, and long-term improvements continue to be made. Cooper Energy remained a net seller of gas price in the quarter with a further 386 terajoules of gas sold into the spot market. Although some third-party gas purchases were required to meet customer nominations for our Sole Gas Sales Agreements.
We will continue to sell surplus gas to the Victorian spot market in 2023 from the Orbost Plant. Our marketing arrangements mean that Cooper Energy is not subject to the $12 a gigajoule cap in place for 2023 that was recently announced and implemented by the federal government. Just as an FYI, I note the current spot price, and that's the spot price at this morning in Victoria, was $13.41 a gigajoule, and Sydney $14.95 a gigajoule.
This is higher than this time last year and reflects the tight gas supply position in Southeast Australia. Some comments on the offshore Otway gas hub and our growth plan around this hub. In the fourth quarter, Cooper Energy of last year that was Cooper Energy outlined the growth plans for the offshore Otway Basin. This is the OP3D project or the Otway Phase 3 project. Built around any and low-risk short-cycle exploration drilling.
The approach is designed to optimize capital management and maximize economic return. In November, the company entered into a long-term gas sales agreement with AGL to supply up to 10 petajoules per annum from our own equity gas for a term of up to 6 years. This underpins the OP3D development. The OP3D project entered front-end engineering and design during the quarter. The proposed rig tendering is based on a 3-well plan to drill the Annie production well and the Juliet and Nestor.
Juliet and Nestor are low-risk exploration wells that in a success case will be completed as development wells. There is an option also to drill a fourth exploration well at the Elanora prospect. The OP3D program and timing for this project will be reviewed when there is more clarity on the proposed code of conduct being developed following the federal government legislation introduced in past in the late December. The common message is gas supply for Southeast Australia is tight and more supply is needed.
We see many people making this comment. We also know that the trend has been for international and local gas prices to increase over the last year or so. However, notwithstanding the fundamentals of the need for more supply and pricing. We deem it prudent to be cautious, and do all we can to ensure the stability and certainty before making any new development investment decisions.
Hence, we'll be reviewing the OP3D investment decision once we've got more clarity around the federal government legislation and the code of conduct. On BMG decommissioning, work continues and the lead up to the abandonment -- to this abandonment project. This includes the decommissioning of 7 wells and the associated subsea infrastructure in the Basker, Manta and Gummy fields in the offshore Gippsland Basin.
Detailed planning and ordering of long-lead equipment and services is progressing to plan. And the Helix Q7000 intervention vessel is contracted to perform these works and expected in Australian borders in the second half of this calendar year. Some comments on some other events. On the 19th of December, the Board announced the appointment of Jane Norman as Cooper Energy's new CEO and Managing Director. Jane -- this will be effective the 20th of March of this year when Jane commences with the company.
I look forward to welcoming Jane to the company and ensuring a smooth transition. Jane will be joining the company when there's a solid foundation and plenty of growth opportunities. And as I mentioned earlier, at a time when our market needs more gas. We've maintained our focus on sustainability and the leading emissions management position we have established. During the quarter, we successfully retired the requisite carbon credits to maintain our net zero accreditation to the half year point of financial year 2023.
Also, during the quarter, the company announced its participation in the partnership for nature-based carbon projects in Vietnam. The Australian Department of Foreign Affairs and Trade is providing funding and support for the project through the business partnership platform. Our participation in the project is aimed at building our portfolio of offsets and supporting Cooper Energy's commitment to remain net zero for Scope 1, Scope 2 and controllable Scope 3 emissions.
In summary, it's been a quarter with some gas plant operational frustrations. I can say it no better than that. Notwithstanding this, we still achieved year-to-date records for production and revenue. I and my colleagues have confidence that we have the foundations and capabilities in place to further strengthen and grow the business. Preparations to become the operator of the Orbost plant are a priority, along with the engineering and technical work to improve the plant stability and the processing rate.
We have a strong balance sheet, including our finance facility and we're prime for growth. The guidance for financial year 2023 remains unchanged. And that's unchanged for production, underlying EBITDAX and capital spend. I'd now like to open the lines and take any questions that you might have this morning.
[Operator Instructions] Your first question comes from the line of Nik Burns from Jarden Australia.
A couple of questions from me. Just first of all, your target of 52 terajoules a day average from OGPP in the near term. Just noting that production this month has averaged around 43 terajoules a day, and you mentioned that the polishing unit is currently offline. And from the data, it looks like it's been offline for much of the last 4 months. And just looks like -- I mean, from our numbers, you really need that online in order to achieve that 52 terajoule a day average. Can you just confirm that, that assumption is correct. And also what's caused that polishing unit to be offline? And what needs to happen to get it back online to achieve those higher average rates?
Yes. Thanks, Nik. I'll answer the first part of it, and then I'm going to pick to Mike Jacobsen to pick up the second part. The rate 52 terajoules a day does include the polishing unit being online, but we've been quite prudent in what we're assuming the polishing unit can deliver. We have not assuming -- as the base case there that -- when we run a series of cases we run a Monte Carlo analysis and then across basically a lower medium and high.
And obviously, there's different rates for the polishing unit in those scenarios and different periods for which the polishing unit is online. And the forecast that we have for the remaining 6 months is not at the levels that it was for the first quarter of this year, it's a little bit under that in an average sense for the polishing unit. In terms of what's the polishing unit having been offline for a period of 4 months, I think it's not quite right to say that it's been offline for 4 months. It has been offline for some of that period there. And the reasons and what's behind that? Mike, would you like to talk to that?
Yes, of course, David. Nik. Yes, so I think, I mean, the polisher, as you know, as we've been talking about for a few months now, there has been carryover issues from the absorbers into the polishes. Now APA did bring it back online, and it was online for I think, about 3 or 4 weeks back in the quarter -- back in the fourth quarter of calendar year '22. But what they are doing to minimize the effect of the carryover on the polishing unit, they're looking to install some different types of balls, which will go into the top of -- into the total polisher.
And they're taking a little time to get. So they're trying -- so I guess, in summary, they're trying to optimize the packing of the polisher to get it to run for a longer period of time. And the expectation is that will happen during the course of February, and we'll see the polisher back online then.
And that is built into our base case forecast. But the unit will come back online in February, but we haven't assumed quite the same periods for the polisher to be online as was experienced in the early part of the first quarter. I think we've actually forecast 7 -- across the year, 7 media changes with the 5 to go. Yes. So you can see compared to 2 in the first 6 months.
Got it. So that's, sorry, 7 through FY '23, is that correct?
Correct. Yes, yes, yes. With 2 having -- 2 having been completed today, so 5 in the remaining 5 months.
Great. And just on OP3D and exploration timing, you've called out today that timing will be impacted by the proposed mandatory code of conduct. The finalization of that code will sway your views around timing. Just noting last month, you put out an announcement where you said that the gas sales agreement with AGL was not impacted by the price cap or the code of conduct. Is that still your interpretation? Or have you changed your view on that?
Yes. No. Yes, it is. Yes, that's correct. Like the gas sales agreement itself is excluded from the -- sorry, it's excluded from the $23 -- sorry, not $23, the $12 price cap, the code is yet to be developed. What the government passed the legislation that was passed in December was legislation to enable the development of the code, and the code is the way now. There are submissions on that, which are due the 7th of February. And then from that, the code will then be developed.
So I think it's going to be a few months. Conversations that we're having and I know conversations that others are having, a lot of that is around what does the code look like and then what does the code cover. And there is a mounting momentum from both the buyer side and producer side that existing -- sorry, that new projects such as OP3D, a new supply should not be covered by the code.
What I mean by that is that commercially negotiated arrangements between a buyer and a seller to support the development of a new project, be just that. Now where all of these lands is unknown at this point. But it would not be wise, in our view, to go ahead and commit OP3D until you had certainty on what the rules of the game are. So it is a case of how to buy some time, buy some flexibility and keep as much traction on the time line as possible whilst minimizing spend. That sounds like it's almost impossible. But what we mean by that is being prudent and -- in the spend, but being ready to go as quickly as possible because the market needs gas.
Your next question comes from the line of James Bullen from CG.
David and Tim, I will go back to OP3D. Just wondering, you previously talked about targeting gas production by the winter of 2025. When is the latest possible date that you can sanction the project and still hit that timing?
Good question, James, and thank you for -- our base case prior to the legislation was that we'd be looking to make FID decision around May -- April, May this year. I think that's stretched. So in absolute terms, if we're not able to make FID by April, May this year, I would think gas supply before winter of '25 would be a challenge. What we will be doing is looking at ways and means of keeping the timetable, but not exposing ourselves to the full commitment.
So maintaining schedule to the extent we're able whilst minimizing cost. Now obviously, long lead items, we've already committed long lead items which in particular, wellheads. We're in the middle of a tender process together with others for the rig, are the main long lead items. I don't think our situation is going to be any different to others. And it's going to be interesting to see how this plays out in the next 2 or 3 months.
But on a like-for-like basis, if we're not able to FID by April, May. I think before winter '25 would be a real challenge, and it would then be a question of when start-up would be.
Understood. And just with the conjecture around what Mitsui's position is. Is there any comments you can make in that regard?
We and Mitsui working very closely together on how do we maintain OP3D and meet each other -- meet the objectives of both parties. That's all I can say. We have got a robust project. We've got a gas sales agreement with a very good customer, which has got scope to put more gas into that agreement. As to the absolute Mitsui position, I think that's -- I don't want to speak for Mitsui. I think that's a question for Mitsui themselves.
And I know in conversations we've had with them, they have said to us if somebody wants to talk to us about it, then don't hesitate to give us a call. So maybe that's the best answer I can give you, James.
[Operator Instructions] There are no further questions at this time. I would like to turn the call back over to David.
Thanks very much. Look, just a couple of summary comments, and I'll make sort of 4 points really. Firstly, the year-to-date numbers are strong, first point; second point, fourth quarter -- sorry, second quarter, December quarter has been frustrating on the back of more interruptions at Orbost operated by APA than we had planned. And I know that APA themselves had expected -- wanted. We see significant opportunities for improvement there, and we are getting ourselves ready to operate that plant and putting all efforts into increasing stability and rates in the plant, and we now have somebody on site working together with the APA team in that respect.
The fundamentals for the market, we've only got stronger in terms of supply. I noted the comments this morning from Shell, which we agree with, supply close to the market is the obvious thing. And the gas prices send you signals. And consistently, over the last 18 months, month-on-month comparing 1 year to the previous, prices -- spot prices have been higher. And that trend has continued.
The government legislation, the fourth point is a frustration. That's been well verbalized by many, and it's a process that we need to work through. At the end of the day, what we do know is that more gas is needed, and we're in a good position. We're going to make sure the future investment decisions that we make are the right investment decisions for our investors.
So on that note, look, if people do have any follow-up questions, please don't hesitate to contact Morgan Wright, and he'll put you in contact with the best person in the organization to answer any further questions. Thanks for joining.
This concludes today's conference call. You may now disconnect.