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Edited Transcript of COE.AX earnings conference call or presentation 11-Aug-19 11:00pm GMT

Full Year 2019 Cooper Energy Ltd Earnings Call

South Perth Aug 16, 2019 (Thomson StreetEvents) -- Edited Transcript of Cooper Energy Ltd earnings conference call or presentation Sunday, August 11, 2019 at 11:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* David P. Maxwell

Cooper Energy Limited - MD & Executive Director

* Don Murchland

Cooper Energy Limited - IR Advisor

* Virginia Katherine Suttell

Cooper Energy Limited - CFO

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Conference Call Participants

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* Benjamin Wilson

RBC Capital Markets, LLC, Research Division - Analyst

* Cameron Hardie

Patersons Securities Limited, Research Division - Analyst

* James P. Bullen

Canaccord Genuity Corp., Research Division - Senior Energy Analyst

* Jon Scholtz

Macquarie Research - Analyst

* Saul Kavonic

Crédit Suisse AG, Research Division - Research Analyst

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Presentation

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Operator [1]

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Thank you for standing by, and welcome to the Cooper Energy Limited FY '19 Results Call. (Operator Instructions).

I would now like to hand the conference over to Mr. Don Murchland, Investor Relations. Please go ahead.

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Don Murchland, Cooper Energy Limited - IR Advisor [2]

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Thank you, Sia. Good morning, everyone, and welcome to Cooper Energy's 2019 financial results call and presentation. With me today here, I have David Maxwell, our CEO, who will lead the presentation off shortly; and Virginia Suttell, our CFO. Members of the Cooper management team -- Cooper Energy management team are also present are on the line for questions, if need be.

We're speaking to a packed lodge with the ASX this morning and also available from our website. There's a question-and-answer session following the presentation and we'd encourage you to join in with that. If you'd like to ask a question, you need to do so via the conference call line provided.

Before handing over to David, I draw your attention to the important information on Slide 2, and thank you. David?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [3]

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Thanks very much, Dan, and welcome to everybody on the call and those that I expect will listen to it later on. Through the call, I'm going to use the phrase FY and that stands for financial year.

The annual results give us the opportunity to reflect on what's been a busy and successful year and also to look at what's ahead. When I do this for FY '19, there are 4 features which stand out.

As Cooper Energy, in the past year we demonstrated our operational capability. The projects and tasks and their associated challenges were all completed successfully and safely and this is clearly a highlight.

The second feature is we finalized 5 new gas contracts at current market prices and the benefit of this is now being reflected in the revenues and operational cash flow.

The third feature is the offshore component of the transformational Sole Gas Project is ready to go. And we're advised by APA that commissioning is expected to commence in September and firm gas sales will follow this.

And the fourth feature is that what we've completed in the last financial year has Cooper Energy set for a much bigger year in FY '20 with the Sole project start, exploration in the Otway and Cooper Basins, and we get to take ownership of the Minerva Gas Plant once the Nova Gas Field is depleted.

Turning to Slide 4, what was delivered. The existing gas and oil business performed strongly in terms of production, revenue and costs. Consistent with this, the underlying profit, after tax that is, was up 36% to $13.3 million. The offshore component of the Sole Gas Project, which is operated and managed by Cooper Energy, was completed with 0 lost time injuries and within budget. And the foundation has been set for the next wave of growth after Sole.

I'll say a little more on safety later but just a few comments here. Our focus on care and doing it right delivered these results in the last 12 months. In the full year, working in some challenging environments and with some challenging tasks there was not one lost time injury.

The Australian offshore oil and gas industry average, as recorded and reported by NOPSEMA, for the total recordable injury frequency rate was 4.07% in 2018 and 3.48% in 2019. This is the number of recordable injuries per million man hours worked. The Cooper Energy stat for 2019 was 0.0.

On that note, I'll pass over to Virginia, and she'll take you through the financials.

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [4]

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Thanks, David. The 2019 financial year has seen Cooper Energy consolidate its position as an offshore gas producer. Revenue increased 12% from the previous financial year, evidencing our approach to commercializing gas through securing gas sale agreements with uplifted pricing and flexibility in terms.

The gross profit increase is reflective of the net position of higher prices of stable production and lower fixed operating costs per barrel against higher tolling for the Casino Henry Gas.

Statutory profit has been impacted by the movement in restoration provisions for the Patricia-Baleen assets. This is due to gross cost revisions announced at the half and subsequent movements in the risk-free rate across the last 6 months. I'll step through this in more detail later on the next slide.

In addition, the movement in statutory profit year-on-year is partially due to the gain on disposal of the Orbost gas plant in the 2018 results.

Cooper Energy continues to grow and establish systems and support structures appropriate for our activities in the larger company we have become. We continue to focus on delivering value through prudent management of costs. Under these circumstances, underlying EBITDA and EBITDAX are stable year-on-year with underlying profit after tax up 36%.

Cash flows from operations are down slightly, reflective of timing of operational receipts and payments in the main. The company finished the financial year with a net debt position of $53.9 million with the Sole offshore project 99% complete.

Moving to the next slide. As mentioned, the statutory net profit after tax has been adjusted for restoration provision movements to achieve an underlying result 36% higher than the previous financial year. There are a number of moving parts associated with this, so I will take some time to step through them here.

In the first half results, we disclosed that the company had undertaken a review of gross restoration cost estimates and increased these to reflect changes in technological and industry practice as well as pricing reviews. Since December, you will know that the risk-free rate has decreased by 1%, driving decreases in the bond rates which are used in the provision calculation.

The carrying value of restoration provisions on the balance sheet is a present value calculation of the future liability and is calculated using discount rates prescribed in the accounting standard. For an asset such as Patricia-Baleen in a non-production phase of its life, this results in movements being booked through the profit and loss.

Moving to Slide 8. The waterfall demonstrates the movement in underlying profit after tax from the 2018 financial year results. As you can see, high gas revenue has offset a small decline in oil revenue and the net impact after cost of sales is a marginal increase of $2.6 million at the gross profit line. The tax result benefited from deductions associated with restoration costs and movement in deferred income tax benefits.

The 2020 financial year results will be impacted by the start of Sole Gas sales. Slide 37 in the appendices identifies areas where these changes can be expected.

On Slide 9, the movement in operating and other cash flow is broken down. There's a small decrease in operating cash flows year-on-year, which is largely due to the timing of receipts from sales and the payment of invoices. Restoration payments in 2019 included the abandonment of Sole-2 and planning associated with the restoration of the BMG assets.

Exploration and development expenditure during the year is largely attributable to spend on the Sole project as well as the successful upgrade and replacement of the Casino Henry umbilical control system and planning for our exploration wells currently being executed. Drawdowns of debt were only associated with the Sole development.

The closing cash balance at 30 June 2019 still includes the $48 million received from the exited parties to the BMG joint venture that were received in the prior year.

Turning to funding on this next slide. Cooper Energy has maintained a good relationship with its lenders throughout the period complying with all covenants. As the Sole project completion, under the terms of this facility nears, the company is moving towards surplus funds being available for other purposes on redetermination. The remaining tenure of this facility is 5 years with repayments and amortization commencing post project completion on assessment of the RBL net present value.

I will now hand over to David to take you through the rest of the presentation.

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [5]

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Thanks, Virginia. On production and sales. There was a 12% decline in total production, and that's on a barrel of oil equivalent basis, to 1.31 million barrels of oil equivalent. This was more than offset by a 12% increase in revenue due to higher prices and the major factor was the increase in gas prices year-on-year.

Now I will discuss reserves. And here, I'm referring to proven and probable reserves or what's also known as 2P reserves. There was a small upgrade of 6 petajoules on gas reserves and our Otway Basin assets and in particular, the Casino Henry assets. This was due to better field performance and a revised assessment of the projects currently underway. These are projects such as the Henry development well and the Minerva gas plant. This increase was partially offset by a full petajoule reduction of Sole 2P reserves.

At Sole, we have adopted for the first time, a deterministic reserves assessment methodology consistent with that used on our other producing fields. The deterministic assessment incorporated the results of the Sole-3 and Sole-4 wells which resulted in a marginal, that's circa 2%, impact on Sole 2P reserves or a full petajoule reduction at Sole.

In the Cooper Basin, the reserves addition equated to production, so there was no net change year-on-year. I should also note technical analysis of the Manta 2C contingent resource in the Gippsland Basin has resulted in a 14% increase from 106 petajoules to 121 petajoules.

A few words on our gas marketing business. In previous years, we were building the business. We put our time and effort into growing the gas reserves portfolio and building the gas customer relationships. Last year, our focus and efforts were more on gas marketing and in particular, contracts for the next 4 to 5 years.

In FY '19, we wrote 5 new gas contracts for a total of some 30 petajoules with 4 different gas customers. These were all term contracts, that's 1 year or more, and at different market prices.

As noted on Slide 14, our gas marketing strategy has been very clear and deliberate. We have a mix of shorter-term and longer-term contracts with utility customers and large industrial customers. This combination, together with our contracting strategy, provides certainty and stability in what is a growing revenue stream.

I draw your attention to the speckled trench in FY '20. The speckled section represents the 3 months in the October to December quarter. The forecast production in sales for Sole in FY '20 are very dependent on timing for startup of the APA gas plant. As I've mentioned, APA have advised us that commissioning will commence in September and firm gas sales commence once commissioning is complete. We will provide guidance on the Sole gas production once the Orbost Gas Plant is commissioned and the plant performance test has been completed.

Now Slide 15. In FY '19, our main production asset was the Casino Henry JV, operated by Cooper Energy. This is in the offshore Otway basin. This low-cost asset accounted for 82% of our FY '19 production on a BOE basis.

We successfully completed the replacement and upgrade of a section of the offshore umbilical. And since we acquired this asset over 2 years ago, we've been reviewing and high grading the exploration opportunities in these permits. This enabled us, in FY '19, to seize an opportunity and accelerate the commitment to draw 2 preferred prospects, Annie and Elanora

Slide 16. For our Cooper Basin assets, there was another steady year of performance with the average margin, that's revenue less [all] operating costs, including royalties, was over $52 a barrel -- that's AUD 52. Overall, our Cooper Basin oil fields performed better than expected and at year-end, there was the reserves upgrade, that's 2P reserves, which meant that the reserves addition effectively replaced the annual production.

The Sole gas project has been a major focus over the past 12 months. And as I mentioned earlier, the offshore construction is complete and this has been achieved within the budget of $355 million, and within schedule. That is the offshore component is really to go within June. This is a very pleasing result, all things considered.

As I mentioned, APA is in the final stages of the upgrades to the Orbost Gas Plant and have advised us to then expect to commence commissioning activities in September.

I commented at the start about our operating capability and I'm now going to say a little more about this. On page -- see here, referring to Slide 18. The Sole offshore project has involved managing and completing a range of different and challenging activities. These activities include an onshore pipe welding, horizontal drilling of 2 shore crossings, drill, complete and flow to production wells, well abandonment in the offshore, pipe lay, umbilical lay and hyperbaric welding of the pipeline. And this hyperbaric welding is a well some 16 meters of water depth. This was the first such hyperbaric well in Australia in 15 years.

I want to acknowledge the many companies that work with us on this project, companies such as Diamond Offshore, Subsea 7, Petroleum and Mining Engineering, Solstad Offshore, TechnipFMC, Baker Hughes, GE, Slumberger, Weatherford and the Pipeline Drillers Group. Every one of these companies contributed, together with our own staff and contractors, and made the outstanding safety record a reality.

Now a few words on the outlook for the FY '20 year for each of our main assets. Firstly, the Otway Basin, and here, I'm referring to both the offshore and the onshore Otway basin. We're currently drilling the Annie exploration well and this will be followed by Elanora. We will announce the results of each of these wells once each of the wells is completed. In the next few months, with Beach, we plan to drill the Dombey exploration well in the onshore Otway basin. This is a follow-up to the Beach Hazel Row 3 gas discovery a couple of years ago. The planning is also underway for the Henry development well. And the acquisition of transfer across the Minova gas plant once the Nova field production comes to an end.

In the Gippsland -- this is in the Gippsland Basin in FY '20. We have the startup in the Sole Gas Project and the planning for the drilling of the Mantra appraisal exploration well and another exploration well in our exploration permit with P72. Soon after the Sole gas field is online, Cooper Energy, together with APA, will be looking at de-bottlenecking and opportunities to further increase Sole near-term production, meant to further increase over and above the schedules that we provided in this presentation.

In the Cooper Basin, we expect to have our busiest year yet with some 19 wells budgeted. This will increase oil reserves and oil production in the high-margin Western Flank oil fields. We've already started the Parsons 3 well drilling program. We will announce the results of these 3 wells when we've completed the third well in the next few weeks.

Slide 23. Our committed and planned activities in FY '20, are targeted to set up further production growth in the offshore Otway and the Gippsland basins; and the Cooper Basin and the onshore Otway basin, depending on exploration success. Within the existing portfolio, we now have multiple near- and medium-term growth opportunities and we will be optimizing this portfolio and the work programs to further maximize value. The results of the FY '20 program will then influence and determine the next year's program. This is further illustrated on Slide 24, where we've outlined the planned activities which we expect to generate growth in the near and medium terms. I don't plan to go into that slide in any detail.

So to wrap up and summarize. The successful projects and activities in FY '19, particularly on the Sole project and the operational and market fronts, has laid the foundation for significant growth in FY '20. And in FY '20, we have exploration, development and commercial activities underway which will be the next wave of new projects to sustain the production, revenue and operating cash flow growth from FY '21 and onwards.

Thank you, and we will now welcome any questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Your first question comes from Ben Wilson from the Royal Bank of Canada.

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Benjamin Wilson, RBC Capital Markets, LLC, Research Division - Analyst [2]

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I just had a quick question about the wells that are currently drilling or the well that's currently drilling in the Otway.

My question is specifically, success case on either of the 2-well program. Does it change your outlook or scheduling around going back to the Gippsland and drilling an appraisal well on Manta?

What I'm seeking to understand is essentially, should you see what you want to see in the Otway, do you prioritize development there or over going back and drilling at Manta?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [3]

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Thanks, Ben and good question. And not really as it relates to the Gippsland. And let me just maybe go through a couple of scenarios to illustrate.

Firstly, we're out now talking to rig contractors for a rig from late '21/early '20 -- late '20/early '21 onwards, I'm not talking calendar years there. So late 2020, early 2021 onwards.

And that program would include -- let's assume we have success with Annie and/or Elnora. That program would include appraisal and/or -- sorry, production wells and/or appraisal wells in the offshore Otway and Manta.

Let's assume we -- which is in the Gippsland. Let's assume the absolute downside case, that we don't have any success at Annie or Elanora. That's not what we expect but let's assume that is the scenario and that well -- we would still have the Manta project and then we would have the Henry development well. So the order of the wells and the number of wells in the campaign is really determined, to a large extent, by the results at Annie and Elnora. But it won't change our plans to drill the Manta appraisal well in that next campaign.

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Benjamin Wilson, RBC Capital Markets, LLC, Research Division - Analyst [4]

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Okay. That's clear. And a while ago -- you -- just a quick one on -- can I ask for some broad sense of timing around this issue of your Manta PRT credits and how you're going seeking a ruling on whether you might get a combination with Sole on that?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [5]

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You're asking me to make a prediction or ask to make a prediction on when governments will make decisions. I'll do my best, but it's got that caveat on it, I guess.

There was that review of the PRRT regime which was conducted over the last couple of years. And prior to the results and recommendations coming out of that were tabled prior to the recent election. And as I understand it, the results and recommendations of that review was supported on a bipartisan basis.

Recommendation 6 in that review specifically dealt with the ongoing cost transfer of assets between retention leases and production licenses. And that is specifically the issue that we're dealing with Manta. So once that legislation is passed, and whether that's this year or early next year, we're not too sure.

It's been a case of enacting the combination certificate. And the combination certificate, we tick the criteria on our assessment to achieve this combination certificate. So in many respects, it's a process that would just be followed through.

I mean, it's not a -- it doesn't require legislative change at that stage. What it requires is Manta is issued a production license and the production license for Manta is combined with the production license for Sole.

So at some stage through the early part of next year would be our expectation but that is dependent on when Recommendation 6 out of the PRRT review is implemented.

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Operator [6]

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Your next question comes from Jon Scholtz from Macquarie.

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Jon Scholtz, Macquarie Research - Analyst [7]

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Just a quick one on tax. See, in the year that you had the $10 million tax benefit, can you just give some color as to when you guys are expecting to actually start paying that through and when you'll see that flow through the cash flow statement?

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [8]

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Sure. I'll take that one. So I'll just qualify that we're talking about corporate tax here, not PRRT necessarily though there is some interrelationship. So as you know, accounting profit is different from tax profit. So I think they traded differently under the tax law as they are still under the accounting standards.

And when you have a look at what we have ahead of ourself, which is our exploration abandonment plan and the rig program and plans that David has just outlined, you sort of look at our modeling on this basis, you see that paying tax -- corporate tax, are sort of mid- 20s. But this is -- this isn't firm guidance as many factors need to be taken into account and many of these are unresolved at the moment. So the plans that we have in place we model. Of course, the accounting profit is always going to be a different manner.

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Operator [9]

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(Operator Instructions) Your next question comes from Saul Kavonic from Crédit Suisse.

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Saul Kavonic, Crédit Suisse AG, Research Division - Research Analyst [10]

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If I just like, may, further develop some of the discussions around corporate tax.

Virginia, do I understand you correctly? Are we suggesting that under kind of your base case modeling there, factoring in Sole developments, you're not expecting corporate tax to be paid until the mid-2020s. Is that the correct understanding?

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [11]

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There are other base case assumptions that are modeled. So as I said, if you have a little bit of a look at or think about the plans that we've outlined, for instance, exploration is treated differently for tax purposes.

So those exploration wells that we are in the process of executing are certainly being modeled into our base case, as is any of the plans we have around sort of abandonment and future works. And they are both sort of automatic, immediate deductions to tax purposes. So yes, on the basis of our base case modeling, we're sort of looking around the mid-20s.

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Saul Kavonic, Crédit Suisse AG, Research Division - Research Analyst [12]

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All right. And on the -- those abandonment provisions. Are you able to give us more color on exactly how much and where we're expecting to see abandonment expensed over the coming 3-year window?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [13]

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I'll say a couple of words at the start and then leave it with Virginia from a finance point of view.

What we are planning as a part of the next campaign that I referred to earlier is some of the BMG abandonment. And the absolute detail on that is being worked through at the moment. So there is, in the near-term, BMG abandonment is the major abandonment activity. There is no other real abandonment activity proposed at this point in our base case.

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [14]

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Yes. So as David said, that's the near-term sort of abandonment that's been worked up and planned for currently.

The rest of the provisions sort of carry out -- just looking at the dates here from sort of 2023, '25. The '23 is small, sort of Cooper Basin-style abandonment and some small permits there.

So there isn't any other significant amendment activity being scheduled in our provisioning until sort of at least 2026. Some of it goes out even much later than that, if you're thinking about pipeline, I think.

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [15]

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And that abandonment schedule is what you might call a no-success abandonment schedule. So what I mean by that is there's no exploration success. So clearly, the wells have to be abandoned. But other bits and pieces of kit, the abandonment of them and the timing of that abandonment is linked to subsequent development decisions.

And by giving you an example, there's Patricia-Baleen, where we're looking at using the Patricia-Baleen pipeline. I'm assuming Manta gas reserves -- Manta contingent resource in the order of 120 petajoules only. No Manta Deep. We would use the Patricia-Baleen pipeline and some of that infrastructure there.

In the event that we have success with Manta Deep, then that's not capable -- the Patricia-Baleen facilities are not capable of handling a bigger volume and we'll be looking to build a separate pipeline all the way to shore. So when we think about development, we really have to think about development from an integrated scenario perspective and the sort of dates that Virginia was flagging was a no-success case.

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Saul Kavonic, Crédit Suisse AG, Research Division - Research Analyst [16]

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Understood. Are you able to give some idea of what the size of the BMG abandonment is going to be?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [17]

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I think it's -- well, we've provisioned. I'll leave it with Virginia to give an indication of...

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [18]

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If you recall, we find dates of relief with the exited parties or some of the exited parties, 3 them, to the BMG joint venture in April 2018.

So the provisions that we carry for BMG abandonment assume their liability for the funds that they put in, which was $48 million. So the liability that we carry currently is the 90% with Pertamina still responsible for 10%.

And with the sort of big -- whilst those gross cost estimates are still being worked and revised and as we get nearer to it, they become more refined. We're looking circa around $90 million.

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Saul Kavonic, Crédit Suisse AG, Research Division - Research Analyst [19]

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Got it. And just lastly, on the Minerva Gas Plant acquisition. Are you able to give any indication of what has been agreed there in terms of price?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [20]

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Yes, we have. It's $10 million for 100% of the gas plant and associated infrastructure. That's on 100% basis.

It's a joint venture between ourselves and Mitsui, and we're 10% of the Minerva joint venture. So it's a net $4 million for ourselves. And we have paid -- as a joint venture we paid $1 million deposit. So the remaining amount to be paid, from a joint venture point of view, is $9 million.

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Operator [21]

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Your next question comes from Cam Hardie from Patersons Securities.

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Cameron Hardie, Patersons Securities Limited, Research Division - Analyst [22]

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Not to just -- too much tax is never enough discussion about it, but you're getting all the questions, Virginia. Just -- I'll follow-up on that. I assume that there's no tax impact on the significant items in the FY '19 ones, given they're noncash. Is that correct?

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [23]

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No.

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Cameron Hardie, Patersons Securities Limited, Research Division - Analyst [24]

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On the underlying profit?

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [25]

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The underlying profit. The tax impact associated with the gain, the provision, would already been worked in. It wouldn't be significant. The 26.2% associated with the restoration expense, yes, there's no tax impact currently on that.

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Cameron Hardie, Patersons Securities Limited, Research Division - Analyst [26]

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Okay. That's good. And if you can dust off your crystal ball, PRRT for FY '20. Any thoughts on what we could be looking at to that? I know that's a very tough question.

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [27]

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Yes, so the exploration expenditure that we're incurring at the moment is immediately transferable to offset our PRRT paying positions. So that's not an insubstantial sum to be offsetting it.

I certainly have my crystal ball on that, Cam. Can I come back to you on that?

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Cameron Hardie, Patersons Securities Limited, Research Division - Analyst [28]

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Yes, sure. No worries. I know it's a tough one.

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [29]

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It's not in my head. But yes, I wouldn't be expecting to see any sort of big uptick in our PRRT payment because of that exploration activity.

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [30]

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And our share of that exploration activity is circa $40 million across the 2 wells, Annie and Elanora.

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Cameron Hardie, Patersons Securities Limited, Research Division - Analyst [31]

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Okay, And just -- David, on that, the rig contract you talked about earlier, I assume that would also include an exploration well with P72. Is that correct?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [32]

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Yes. Yes, that would be that would be included in the program.

The way that we're thinking about it is a number of firm slots with the significant number of options to give ourselves flexibility and then optimizing across the rigs best suited for the different activities.

Water depths are slightly different. The operating environments are slightly different. So it may be that not one rig is not going to be able to do all of the wells that we might have in mind.

And that's -- these are conversations that we've got underway with other operators in the Gippsland at the moment and the Gippsland and the Otway at the moment.

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Cameron Hardie, Patersons Securities Limited, Research Division - Analyst [33]

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Okay. And just finally, the Henry development well that's planned, is there any uplift to production from that or is that? Or is that just sort of maintaining production?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [34]

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No, no, there is an uplift in production from that. And in the slide pack that we've issued -- the investor pack that we issued this morning, there's a slide in the Appendices which is Slide 28.

You'll see -- and this is the base case scenario, it assumes no exploration success at all. And you'll see an uptick in FY '22 where production goes from about 6 petajoules a year [our share] to 10 petajoules a year our share coming out of the Otway. That's the Henry development well.

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Operator [35]

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(Operator Instructions) Your next question comes from James Bullen from Canaccord Genuity.

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James P. Bullen, Canaccord Genuity Corp., Research Division - Senior Energy Analyst [36]

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Just a quick one around the de-bottlenecking potential at Sole. I was hoping you could provide a bit more color around what that could possibly be.

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [37]

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In terms of volumes?

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James P. Bullen, Canaccord Genuity Corp., Research Division - Senior Energy Analyst [38]

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Yes, in terms of production uplift.

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [39]

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Look, we really have to be pretty careful with this until the plant is operating.

Firstly, the 2 wells that we have, each of Sole-3 and Sole-4 have capacity to produce well in excess of the design capacity at the plant. So we have got reservoir production capacity and we've got offshore pipeline delivery capacity. In the first -- so certainly the first half of the Sole production period. It then comes down to -- so there's no de-bottlenecking from the offshore point of view. It then comes down to the plant. And it really depends on how that plant settles in.

But typically, you would expect somewhere 10 to 15 perhaps the size, 20% to come from de-bottlenecking. And we'd be hoping to see some of that benefit flowing through in the calendar 2020.

But please, there is not a number that we can put out there with any firm basis at this point. It's a generic assessment based on typically what you might expect in a gas plant like this.

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James P. Bullen, Canaccord Genuity Corp., Research Division - Senior Energy Analyst [40]

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Right. And just final question. The delta between pricing for interruptible gas and pricing for firm gas. So when you move across to supplying gas in into Minerva, you're moving on to firm. Could you give us a sense of how large that delta could be?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [41]

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It's something that moves with -- it moves with time and the tightness in the market.

Clearly, the best gas for Southeast Australia is gas from Southeast Australia. And what we have seen is customers prepared to pay market prices for that gas which is close to market, the markets being South Australia, Victoria and New South Wales and Tasmania.

Now prices in 1 year are slightly different to prices in another year and market demand/supply balance has changed from year-to-year. But plus/minus $0.50 to $1 is what you would expect is the difference between firm and interruptible. And a big factor in this is obviously is gas storage. And [allege] in gas pipelines, which is another form of storage.

So at the end of the day, customers will say, "Well, what's -- how do I optimize the cost I pay for gas against the profile that I require the gas to be delivered on?" and -- but it's somewhere in that plus/minus $0.50 to $1 range.

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Operator [42]

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(Operator Instructions) Your next question comes from Scott [Ashton] from Shaw Energy Consulting.

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Unidentified Analyst, [43]

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Yes, James has already asked the question I was going to ask. But look, just going back to the debottlenecking question.

What's the capacity of the plant? And I suppose is your future gas marketing strategy sort of predicated on working on that upgrade coming through, no matter what?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [44]

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The plant that APA now own, when that plant was producing Patricia-Baleen gas, the capacity of the plant was 90 terajoules a day.

Producing Sole gas that's configured differently because you get slightly different compositions, slightly different pressures and the design capacity of the upgrade is 68 terajoules a day.

So it's then a case of, "What little tweaks, what little bits of, yes, small capital investments would increase that further?" So when I talk about the 10 to 15 or 10 to 20 range, is highly indicative.

Some of that's churning in the plant and some of it's maybe a little bit of capital investment. Very small, very small increments. That is not included -- the production uplift on that is not included in any profiles we put out.

Our profiles, our production profiles are, base case, no exploration success, no upgrades.

One thing I probably should -- the point I probably should make is that we have -- our gas contracts have been structured very deliberately to maximize production on a day.

And so our hope is that the production profiles that you see coming from Cooper Energy to our customers over the next 5, 10 years, that the customers are taking close to capacity on a day.

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Operator [45]

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There are no further questions at this time. I'll now hand back to Mr. Maxwell for closing remarks.

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [46]

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Well, thanks to all who have taken the time to listen to the call.

And as I said at the outset, FY '19 was a year in which we really illustrated the operating capability of the company. We've built the relationships with a number of contractors and service providers.

I don't, in any way, want people to walk past the safety record. In our business, that's a huge achievement, and to deliver the Sole project -- the offshore components of the project within schedule and within budget is something that we and all people who have worked with us can be very proud of.

We look forward to the start-up of the Sole project. It completely transforms the business, circa 4x uplift in production and cash flows. And as you've heard on the call this morning, we're already well advanced with the number of projects, which is the next wave of growth and we'll be optimizing across those projects to maximize value for shareholders.

So on that note, thank you very much.