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Edited Transcript of COE.AX earnings conference call or presentation 23-Feb-20 10:00pm GMT

Half Year 2020 Cooper Energy Ltd Earnings Call

South Perth Mar 21, 2020 (Thomson StreetEvents) -- Edited Transcript of Cooper Energy Ltd earnings conference call or presentation Sunday, February 23, 2020 at 10:00:00pm 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, Research Division - Director And Oil & Gas Analyst

* James P. Bullen

Canaccord Genuity Corp., Research Division - Senior Energy Analyst

* Jon Bishop

Euroz Limited - Executive Director & Head of Research

* 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 First Half Results Announcement. (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, operator. And on behalf of the company, I'd like to welcome you to our results call and webcast, the 6 months to December 31, 2019, the first half of FY '20.

With me today, I have here David Maxwell, Managing Director; and Virginia Suttell, who'll shortly take you through the results and then to a question-and-answer session. We also have members of the management team on the line in Adelaide and Perth. A lot of them will participate in the Q&A session if needed.

We would encourage questions and answers at the end of the presentation. To do so, you'll need to be on the conference call rather than the webcast, the details of which are in the pack that's been distributed to the ASX this morning.

Turning to Slide 2. We have some important information, which you may be familiar with, including the new ASX compliance statements.

And I'll hand over to David Maxwell.

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

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Thank you, Don, and let me add my welcome to everybody that's on the call this morning and those that are listening over the next couple of days. On the call this morning, we're going to cover 3 broad areas. We'll cover what's been delivered in the first half of FY '20, and in particular, there will be a discussion on Sole. We'll cover the first half accounts and then the project opportunities that we're currently pursuing and the discipline that’s being applied to add to the strong foundation that we've created with Sole.

Now turning to the status and outlook as at today. Sole project start-up is later than we'd planned some 6 months ago. This is due to delays at the Orbost Gas Plant upgrade, which is being managed by APA. Had the gas plant upgrade and therefore Sole started when previously planned, our cash and cash flow position would have been even stronger. However, I note, and importantly, the production is deferred not forgone or lost.

APA is in the midst of commissioning, and they advise Sole commercial operations within March. Our Sole and Otway gas is fully contracted to December this year, and almost all available production, that's 87%, is covered by take-or-pay contracts to June 2022.

We have a number of new projects underway, including the Minerva Gas Plant upgrade; the next offshore Otway gas development; and Manta gas appraisal [and in-purchase in] the Gippsland Basin. And Sole is in full production. Our cash flows are akin to utility-style cash flows. By this, I mean steady and largely indexed to CPI. And under the current finance facility, the interest rate decreases, and we have more flexibility with how we can allocate the cash. I should note that we're also preparing to restructure the finance facility once Sole is online. And we've stepped up our environmental, social and governance activities, including providing direct hands-on support for the people in East Gippsland, most impacted by the recent bushfires and the after effects.

Slide 4. We had 1 lost time injury in September. The first, since our last LTI, which was Indonesia -- which was in Indonesia 5 years ago. The Sole Gas Project, managed by Cooper Energy, was completed in July. It was completed within schedule and within budget, and this includes the pipeline repair.

The financial and operating results of the existing business improved when we compare it with the first half of FY '19. And this is mainly due to increased gas prices. And the key ingredients to further increase our cost-competitive production and cash flow are being added. And the organizational capability and systems have been enhanced to support a portfolio of projects and disciplined decision-making.

As outlined on Slide 5, our safety performance continues to be considerably better than the average of the offshore oil and gas industry. Albeit, we had one incident, which I've already mentioned. And even one is regrettable.

I'll now pass to Virginia to take you through the financial results.

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

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Thank you, David. Good morning, and welcome, everyone. On this slide, we've identified key financial results for the half. Starting with production. Production was stable as compared to the December '18 half at 660,000 BOE. This was despite the cessation of the Minerva Gas Field production in September 2019, which was slightly earlier than we had forecast, and a small decline in production from the Cooper Basin.

Our production increase at Casino Henry was the result of the optimization and maintenance activity we undertook mid-calendar year 2019 as well as the return of the Netherby well to service post-backbone and umbilical remediation work. Strong contracting in the Otway Basin has resulted in increased revenue of around $3 million or 8% and an increased percentage contribution from the gas business to total revenue.

Other income in the half captured $9.9 million of APA-liquidated damages at 31 December in addition to a noncash restoration provision adjustment due to movement in government bond rate. The half year saw an underlying loss of $2 million. This was after adjustment to the net $4.3 million, which I will step through shortly. This compared to the previous period of an underlying profit of $3.1 million. An increase in amortization across the producing assets of around $5 million half-on-half flows through the gross profit results, the gross profit margin and these underlying results.

Amortization has increased in part due to production performance, the early cessation of the Minerva Gas Field and in addition to cost estimate revisions associated with future developments. A component of future development costs, both in the Otway and Cooper Basins, is pre investment capital and will create development synergies for new discoveries.

Reserve increases from planned and anticipated exploration appraisal drilling may reduce the rate of amortization of these costs. Fixed operating costs showed savings half-on-half with increases in other operating costs associated with the higher production from Casino Henry.

In addition, the cost base of the business has changed. Throughout the period of the Sole development and in anticipation of its completion, the business has invested heavily in strengthening processes, procedures and capability. This investment is to ensure governance and risk management frameworks are in place that are requisite for a company of our increased size in order to operate multiple sites and to be prepared for future development. Notwithstanding this, the net G&A cost in the business has remained stable. Work continues in the space, and David will talk about this in more detail later in the pack.

Underlying EBITDA is down, reflecting improvement in the gross cash margin from site -- from operations for both revenues and OpEx results as mentioned. The EBITDA percentage increased half-on-half is greater than revenue as safe, efficient and cost-effective management continues to be a focus by the operations team.

Cash flow from operations is strong half-on-half, and I will talk to this in more detail on Slide 9 of the pack. Drawn debt has increased in line with interest, which has been capitalized, and the net debt increase is in line with this and the exploration and development spend during the period.

Turning to the next slide. Taking a closer look across the next 2 slides of the underlying results, while this is not the account we were hoping to present at this time, the delivery of Sole Gas as anticipated this half is not crystallized. So looking on Slide 7 at the reconciliation of the underlying loss, I draw to your attention the exclusion of liquidated damages from this result. These are associated with delays in the completion of the Orbost Gas Processing Plant. The LDs have been excluded from underlying profit for 2 reasons: Firstly, the one-offs and would reduce comparability on an ongoing basis. And secondly, as David mentioned, the delay has deferred, not forgone gas sales. The tax impact of underlying adjustments in the reconciliation is associated with the liquidated damages.

Turning to the waterfall on the next slide, which breaks down the movement year-on-year in more detail. In the waterfall, you can see the increase in revenue due to higher production and higher prices achieved in the gas business of $3.1 million. The most significant negative movement is illustrated as a high cost of sales of $5.6 million and the exploration and evaluation expense of $2.3 million.

To explain a bit further, the underlying result is impacted most significantly by 2 factors: The first, as we said, is due to the increase in amortization of our producing assets. Approximately 30% of this increase was due to the earlier-than-forecast spacing of the Minerva Field, and the rest is outlined associated with high production and the future development CapEx in both the Otway and Cooper Basin. The second relates to exploration expense for several wells in the Cooper Basin that were unsuccessful and also for costs associated with the deferred Elanora well that could not be carried forward under our E&E accounting policy to a future campaign.

Next, on Slide 9, we identified strong operating cash flow of $31.4 million, consistent with the increase in revenue, the receipt of LD and the PRRT refund as well as a reduction this year in restoration as compared to the first half of FY '19. The most significant item in the cash flow from financing and investing activities was the spend on exploration and development. This included the Annie gas discovery, the Dombey-1 well in the onshore Otway, exploration and appraisal in the Cooper Basin as well as the continued milestones for the Sole Gas project. Also included in the $44.3 million is the final payment for the acquisition of the strategic Minerva Gas Plant of $4 million.

Now turning to the balance sheet on Slide 10. You can see significant cash balances held up $150.7 million as well as the recognition of the right-of-use asset and lease liabilities under AASB 16 for our commercial property leases. The right-of-use asset associated with the Sole Gas Processing agreement with APA will be recognized in the second half of FY '20 when processing charges commence under the agreement.

Slide 31 in the appendices of this pack has some more information with regards to the [added] Note 2 in the half year financial statement.

In addition, property, plant and equipment has increased in the first half with the completion of the Minerva Gas Plant acquisition. You can see more details on this at Note 6 in the half year financial statement. Liabilities have increased in the main for restoration provisions due to the updates and discount rates and growth cost estimates. The increase in drawn debt is solely due to the capitalization of interest expense.

On the next slide, a few key points with respect to funding. The reserve-based lending facility secured for the Sole Project remains on foot with all covenants met during the period. On meeting the project completion under the facility, which includes a 90-day production test, the facility becomes subject to a reduced waterfall and funds available for general purposes beyond the Sole Project. We continue to progress discussions with respect to facility structure and then capital management internally and externally with the aim to secure access to sufficient funding and liquidity to support the execution of future activities. All debt is noncurrent at 31 December 2019 with the timing of debt repayment subject to redetermination and completion and a reducing stability limit and repayment schedule.

I'll now turn to David, who will take you through our operations and project.

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

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Thanks, Virginia. And as she mentioned, a few comments on our existing operations. Firstly, production and revenue. As illustrated on Slide 13, whilst overall production was steady, the gas production and gas prices increased when compared with the first 6 months of the previous year. This improvement was largely attributable to the Otway contract negotiated for the 2019 calendar year. Please note we have new Otway gas contracts, which were announced in June 2019 and applicable for the 2020 calendar year.

Now Slide 14. There has been recent commentary on low spot LNG gas prices and the possible impact on Australian gas prices, in particular Southeast Australia gas prices. I note that there continues to be quite a difference between the very thinly traded short-term spot gas price and the long-term contract gas prices. Our contracts are classified as longer-term gas contracts. The ACCC report issued last week reported prices for 2020 supply in the southern states within the range, $9 to $10 a gigajoule.

Over the last 12 months, we have taken the opportunity to further strengthen the gas contract portfolio with new take-or-pay contracts. As a result, Sole is fully contracted to January 2025. Casino Henry is fully contracted for this calendar year, and almost 90% of Cooper Energy's available planned production is contracted to June 2022. The term contracts we have announced in the last 15 months are consistent with the prices evident in the ACCC report issued last week.

In the offshore Otway Basin, in addition to steady production and increased revenue, we added the Annie gas discovery. We also added the low-operating-cost Minerva Gas Plant at a very low capital cost. We were granted a new license, VIC/P76, with very good exploration opportunities, and production licenses were granted for an area which includes the Black Watch gas field. These are all inputs for future growth, which I will discuss soon.

Slide 16, the Annie gas discovery. This was an important and valuable milestone for the company. This morning, we issued a contingent resource statement for Annie just some 5 months after the discovery. And for the eagle eyes on the call, there is an error on this slide. Under original raw gas in place for the Waarre C formation, the 3C number should be 98.6, not 1.2. We'll correct that later today. The main reservoir at Annie is the Waarre C formation, which is analogous to the same high-quality Waarre C intervals in the Casino and Minerva gas fields, which are located to the southwest and east of Annie respectively. Note, as Virginia mentioned, the Minerva Gas Field is now depleted. The Annie contingent resource volume is very consistent with the predrill volume expectations. However, the Annie gas includes an estimated 7% to 8% CO2.

I will now talk about our plans for the Annie development in the next section. The Annie discovery supports our view of the valuable exploration opportunities available within the VIC/P44 permit, and there's plenty of them. In the Cooper Basin, together with Beach, we concluded the largest campaign we've ever undertaken on the western flank. This involved 13 wells at Parsons, Callawonga, Butlers and Rincon. The results are now being analyzed, and we expect to include the reserves update with our year-end results in August. Over the next few months, we plan to drill 3 Parsons development wells, which will increase production; and 2 exploration wells, Sellicks South and Glenelg North. At the end of this program, we will have drilled 18 wells in the Cooper Basin in this financial year. The previous high was 12 wells in 2011.

In the onshore Otway Basin, we made the Dombey gas discovery, another milestone for our gas-driven strategy. The production results and subsequent pressure build-out indicate we drilled a relatively small compartment, which is connected to a much larger resource. 3D seismic acquisition is planned to enhance the subsurface imaging and understanding of the Dombey field size as well as providing valuable data for the analysis of other prospects in the Penola Trough. We expect the economics for onshore Otway Penola Trough discoveries to be very compelling.

At Slide 19. Cooper Energy now has a portfolio of valuable opportunities, which are all consistent with our Southeast Australia gas-focused strategy. As we move from one project under development, and that is Sole with full production imminent, to multiple projects, it has been important that we upgrade our systems and processes to maintain a strong and disciplined decision-making process based on fundamentals. Therefore, in parallel with our operating and project activities, we have implemented a new and clear operating model and upgraded the management systems. I want to commend the Cooper Energy staff and contractors for readily embracing these changes.

Now I'll turn to discuss our key projects and illustrate how we plan to leverage the existing operations, including Sole for the next production and cash flow growth wave.

Slide 21. As we continually optimize and grow our portfolio, you will see us reporting the progress consistent with our project management process known as CARP, the Cooper Asset Realization Process, in keeping with the water theme. The process helps ensure the right work activity is undertaken in the right order and appropriate assurance is conducted at key stages. In particular, before proceeding to the next stage or passing through the gate, there's an assurance review to ensure the project is feasible, that's feasible economically and technically and to help ensure the optimum value and project management.

On this slide, we illustrate where some of the projects are at in this disciplined process. The plan is that the priority projects move to the right over time and new opportunities or projects consistent with our strategy are added.

The first project, the Sole Gas Project, which is about to enter the operate phase. The picture on this slide was taken some 2 weeks ago, and it looks very different to how the site appeared 2 years ago. The Orbost Gas Processing Plant is now being commissioned. And based on advice from APA, who is managing the Orbost upgrade, we expect the gas plant commercial operations within March. Cooper Energy completed the offshore project -- that was 2 wells, the pipeline, the umbilical and shore crossing -- in July of last year. This was completed within schedule and within the budget of $355 million and with 0 LTIs.

This is an achievement which illustrates the company's operating capabilities and discipline. The impact of the delays and start-up of the gas plant, partially due to bushfire, the impact on our gas sales contracts, which was scheduled to commence in January, has been cooperatively managed with the customers. As a result, the start-up of -- for 3 of the 4 contracts has been deferred with almost no cost impacts to Cooper Energy.

The Minerva Gas Processing Project. The purchase of the Minerva Gas Plant, 50-50 together with Mitsui, was completed in early December after Minerva production ceased in early September. Work immediately commenced to prepare the plant to take Casino Henry and Netherby gas and any new discoveries for an extended period. This project is currently in the develop phase, which means the specifications for the project are being defined as preparation for a final investment decision in mid-2020. As expected, the Casino Henry Gas will be switched across to the plant in mid-2021. This is a very good segue into the next development to be processed through the Minerva Gas Plant.

Slide 24. Following the Annie discovery in early September, we initiated the CARP project management process to evaluate and identify the development opportunity. The assess phase looked at a range of different development concepts and each of the concepts reviewed was economic. Otway Phase 3 Development, or OP3D, as it will be known, is the development of Annie together with the Henry undeveloped reserves. This is more than 100 petajoules of new supply on a 100% basis.

The OP3D project passed the assess gate earlier this month, and a short list of optimal development concepts are now under review to select the concept to be taken to the final investment decision planned for late in 2020. We expect first gas from OP3D in late 2022, early 2023.

An option under review is a new pipeline, a high-pressure pipeline connecting Henry and Annie directly with the Minerva Gas Plant. This option provides a high-pressure pipeline and a lower-pressure pipeline, the -- that's the existing line, to accelerate production and establish key infrastructure for further discoveries. Annie gas could be blended with the other gas to bring the CO2 percentage within the pipeline specification. OP3D is a good illustration of the economic and strategic value of the Minerva Gas Plant together with the offshore infrastructure network to accelerate new projects and cash flows.

Now turning to the near-term outlook. For the second half of FY '20, we are guiding the market to unchanged guidance for the existing production assets. We will update the production guidance once Sole production is steady state as it is at this time, there's a material step-up in production and revenue. We're guiding the market to Sole start-up and commercial operations within March based on the latest advice from APA.

On capital guidance, we're guiding the market to $86 million to $93 million capital for this financial year, which is a reduction from previous guidance of $100 million to $110 million. The reduction is mainly due to the deferral of the Elanora exploration well and the lower Cooper Basin expenditure partially offset by the acquisition of the Minerva Gas Plant and increased capitalized interest as a result of the Sole project delay. Slide 30 in the attachments includes more on this.

Our gas production for the calendar year is fully contracted, and we are preparing to contract the remainder of the FY '21 Casino Henry gas around midyear. The milestones on the key growth projects are as I've outlined earlier and summarized on this slide.

Now to summarize or to wrap up, the transformational increase in production and cash flow linked to the Sole start-up is imminent. Albeit, this is later than planned due to the delay with the Orbost Gas Plant. Our competitive gas production is covered by take-or-pay contracts, which provide high-margin, utility-like cash flow, and this is set to materially increase with Sole. A suite of projects are now underway to deliver the next growth wave. And the Cooper Energy performance in managing the Sole offshore project, that's technical performance, commercial performance and financial performance, has demonstrated our capabilities and discipline to generate further wealth consistent with sustainable expectations for our shareholders. Once Sole is operating in a steady state, we will be in discussions to amend the current financial arrangements to support the future growth and provide greater flexibility.

Thank you, and we now welcome your 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 Royal Bank of Canada.

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Benjamin Wilson, RBC Capital Markets, Research Division - Director And Oil & Gas Analyst [2]

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Just a quick question on -- maybe a first status update, if you're able to provide us, on the PRRT credits for Manta and your thinking about the progression of the culmination certificate if possible there.

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

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I'll say a couple of comments, and then, I'm sure, Virginia can add as well. So thanks, Ben. The recommendation 6, I think, is what you're referring to there, which is an amendment to legislation to ensure that the past costs associated with Manta can be integrated together with the costs for Sole and the so-called combination certificate. Our understanding based on conversations with the bureaucracy and the politicians in Canberra is that towards the middle of this year, this is going to get their attention. And once Sole is online, our plan is to up our efforts in discussing with Canberra the best way to advance this as quickly as possible. And I'd note that what we're seeking to do here is consistent with the recommendation coming out of the recent PRRT review.

Do you have anything you'd want to add to that, Virginia?

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

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Only just I think that the focus at the moment in Canberra with regards to taxation, so oil and gas is on gas transfer pricing, which is why the second tranche is legislative amendments for PRRT has been deferred. So whilst we're expecting attention midway this year to the second tranche, the expectation would be on that basis that draft legislation might be around sort of just the fourth quarter of this calendar year. But we are very much at the mercy of the finalization of the gas transfer pricing, which is their focus at the moment.

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

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I'd also just add that the timing on this for us is linked to before the drilling of the Manta well. And at the moment, as reflected in the presentation, I mean, we are contemplating that sort of around just '22.

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Benjamin Wilson, RBC Capital Markets, Research Division - Director And Oil & Gas Analyst [6]

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Okay. Can I ask then -- I guess you've answered the question. Is that commitment to drill at Manta appraisal development well contingent on attainment of those certificates through the process there?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [7]

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We haven't gone that far at the stage, but we would want fiscal certainty before we drill the well.

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Operator [8]

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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 [9]

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Just a quick question around DD&A. The unit cost is -- I mean, that's a pretty dramatic increase. Should we expect that it will be that high going forward for the base business?

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Virginia Katherine Suttell, Cooper Energy Limited - CFO [10]

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I think there's a couple of things that sort of -- we have alluded to with regards to that increase. The first one being the cessation of the Minerva Gas Plant was earlier than expected. So there is a significant amount of amortization associated with that in that increase. The ongoing amortization cost associated with Casino Henry will be largely dependent on the settlement of the development pathway, I guess, in the Otway, so OP3D and what reserves can be associated with that cost earned. For instance, the Minerva Gas Plant upgrade is still part of that CGU, but that will have efficiency for any future discoveries in the Otway Basin that we process through the Minerva Gas Plant. So to sort of say that it's going to remain stable going forward, I'm not really able to do that, but the development CapEx as we progress through our CARP process will become more certain.

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [11]

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It's probably worth just mentioning that the DD&A and the forecast is based on Henry-3 as we have historically carried because we have not yet committed to OP3D that will occur at FID time, which is that time that the cost amortization schedule will get rechecked, if you like, in those costs assuming FID would come into the OP3 production. That’s a bit of a one-off. There's a series of one-off events in that.

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James P. Bullen, Canaccord Genuity Corp., Research Division - Senior Energy Analyst [12]

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Yes, but it sounds like it's going to be naturally going a bit higher than it has historically. Okay, that's cool. And just around Annie. Obviously, a little bit below where we were hoping it was going to be, and that seems to be primarily driven by higher levels of inerts. So 7% to 8% CO2, will that change the CapEx required for Minerva if you aren't able to blend this?

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

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Yes, good question, James. Well, firstly, I know that I've got on the line, if we need it, our Exploration Head, Andrew Thomas. And exploration is exploration, and that's why you put out a range of estimates. The volumetric size of Annie is very close to our P50. Energies reflect, and as I mentioned, the CO2 was a little bit higher than we expected. One of the things being considered as we review the concepts is how best to treat that CO2. And it appears probable, but it can be managed with blending under all scenarios. But in the event that that would not be the case, then there's relatively low cost. It's not a big volume of CO2; it's a small volume of CO2. There's relatively low-cost options for CO2 knockout in the gas plant. And we would -- yes, if we had to do that, and at the moment, there's no suggestion that we do, but if we did, then we would include those costs as a part of the FID decision for Annie or OP3D.

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James P. Bullen, Canaccord Genuity Corp., Research Division - Senior Energy Analyst [14]

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Right. And I guess we're all being a little bit scared in the investment community when we see mercury. You've got down there that's at minor levels. Is that nothing to be concerned about at all?

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

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Nothing. Nothing to be concerned about. And the reason we put it in there was because we know everybody asked a question about it. And I think perhaps, we carry the baton from others who have gone before us, where it has been a surprise. So we're dealing with it very, very openly. And one of the things that we are looking at was whether we should put a mercury knockout bid at the front end of the plant as a part of the upgrade. Again, it would -- I'm not going to say negligible cost, but it's a relatively small cost. The big impact of that is more associated with the project start-up timing. So important is if we are going to do that, we factor it in early and the team reviewing the Minerva Gas Plant is looking at that at the moment. And that -- the answer to that should be known by the middle of this year. We're looking at middle of this year, June for FID, so it should be known by then.

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James P. Bullen, Canaccord Genuity Corp., Research Division - Senior Energy Analyst [16]

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Right. And so -- and a little bit of Annie has slipped into VIC/P44. That's a -- everyone happy with how any balancing arrangements that -- I mean, it seems like only very small amounts in that area are...

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

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It didn't slip into there. It's been there all the time. But that's something that we and Mitsui will work through. We own the permit of that adjacent to VIC/P44 100%. And it's something that we and Mitsui will have a chat about. And I think if someone looks closely at the numbers, you'll see that they don't entirely go 50-50 as you go through the recoverable gas from C1, C2, C3, which reflects really how much we think at this stage is in the neighboring permit.

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James P. Bullen, Canaccord Genuity Corp., Research Division - Senior Energy Analyst [18]

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Right. Is there any likelihood there of a farm down to Mitsui because you also...

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [19]

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That's a conversation between us and Mitsui. We have a very good relationship with Mitsui. Mitsui has been very supportive of the activities that we've pursued. We have accelerated through the assess gate very quickly -- first gate very quickly for Annie, and that's supported by Mitsui. So I guess there's your answer.

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Operator [20]

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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 [21]

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A couple of questions if I may. Just firstly about the Henry, Annie integrated development. Do you envisage that's going to be able to max out the 150 TJ a day capacity? Or is that something that's going to come in likely under that level?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [22]

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I think it will come in under that level, Saul. Had we drilled Elanora and had success at Elanora within P50 numbers that we have out for that opportunity, then we would have maxed out the 150. But at the moment, I'd be reasonably confident that we won't be maxing out that 150.

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Saul Kavonic, Crédit Suisse AG, Research Division - Research Analyst [23]

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Great. A follow-on to that is Elanora is not getting a lot of mentions in the presentation here. I just -- what's the status on Elanora? Are you -- I mean, is there risk that this could be pushed off beyond FY '21 given -- assuming an Annie, Henry development gets -- proceeds on target?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [24]

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No. I -- well, at the moment, the way that we think about it is -- and we've just gone out for tender for the next drilling campaign, which would include the development wells for Annie and Henry, and we've got a series of options in there for exploration wells in the offshore Otway. The likely scenario, whether it's 2 or 3, is yet to be determined. And so no, I would say that Annie has -- sorry, Elanora has not been slipped out. What has changed is the addition of the permit that is right next door to Annie. And the Nestor prospect, which, following the success at Annie, is very, very attractive. And which one of those we would drill first, Annie or Elanora, is a conversation that is underway at the moment. I'd like to think that we drill both, and I think there's every chance that we will on next campaign. What’s to be sorted out is what the order is.

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Saul Kavonic, Crédit Suisse AG, Research Division - Research Analyst [25]

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Understood. And just lastly, you mentioned you're looking to secure funding/liquidity. Could you just outline exactly what kind of options you're considering there and the priorities you're going to take into account when considering those options?

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David P. Maxwell, Cooper Energy Limited - MD & Executive Director [26]

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Yes, those comments were all about the existing funding facility, the bank facility that we have with the syndicate of 5 banks. And please don't read any more into it -- than that. There is -- we've got, first off, when Sole is online and passes its performance test, there's a change in the arrangements under the existing facility. And then secondly, we've started the conversations for a renegotiation of that facility to flex it up and give us more flexibility for what's in front of us. That's what was behind those comments. And I would add that we've received very good feedback from the existing banks plus approaches from a number that were not in the current syndicate that are very keen to support us in a refinance facility. Virginia is leading that together with her advisers. Maybe she's got something else she wants to add.

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

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Yes, David. The statements around looking at funding liquidity and capital management, I mean, that's just part of growing up, I suppose. So it's us taking a look at what gearing ratio we're happy to carry, how high we're prepared to see that peak in the middle of the development. And I'll sort of draw your attention again to the $150 million that's sitting on the balance sheet that is restricted cash to quite a substantial amount at the moment whilst we're in the project phase of the existing finance facility.

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Operator [28]

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(Operator Instructions) Your next question comes from Jon Bishop from Euroz.

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Jon Bishop, Euroz Limited - Executive Director & Head of Research [29]

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David, just a couple of questions just regarding the exploration and Manta appraisal drilling. Do we treat those as mutually exclusive? Or would you consider employing the same rig for both? I guess obviously, you've got the combinations needed to consider. But what's your current thinking around rig requirements there and approximate timing of getting a rig into the area?

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

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Yes. Good question. Thanks, Jon. The drilling team has gone out to tender and had a range of options. And it depends what we get back in those tenders as to whether we go with 1 rig to do both or 2 separate rigs, 1 for the Gippsland essentially and 1 for the Otway. And this is all about what's appropriate for the conditions. I think it's fair to say we learned a lot from that -- the work that we did with the Ocean Monarch and the Gippsland and the Otway. And we have applied those lessons to our rig selection criteria this time around. Your first comment or your first query, are they mutually exclusive? I would say no. We won't -- we're planning on activity in both the Otway and the Gippsland, and it's the case of what's the best way to manage that is it -- if we get -- can we go with 1 rig if we get the right rig? Yes, we will. That would be our preference. But if we can't and the economic solution is 2 rigs, then that's what we would do. I'd note also that there is an offshore rig coming into the basin in the next couple of months. Diamond bringing the Onyx in to work primarily for Beach. And separately, there's a jack-up in the Gippsland at the moment, which is doing work for other operators, in particularly ExxonMobil. So we've got quite a lot of flexibility, and the drilling team is right in the midst of that right now.

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Jon Bishop, Euroz Limited - Executive Director & Head of Research [31]

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Okay. Just one other question. Just regarding Beach's activity. I note in their half yearly, there was a small reference to Black Watch and unitization discussions. What's the sort of thinking around time frame on landing on an agreement there in your mind?

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

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I don't have the answer to that question, Jon. I'd like to think as soon as possible. But I think you've actually got to get traction in conversations before you can say that. It's been met on both sides. It's been met in our permits together with Mitsui and on the other side. We’ve been issued a production license by the joint authority. And I'd hope that we can come to a reasonable settlement with our neighbors on it. I really can't say too much more than that.

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Jon Bishop, Euroz Limited - Executive Director & Head of Research [33]

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Yes. I guess we'll have some results from the wells then, so maybe that will stimulate some discussion.

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

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Hopefully, so. Yes, yes.

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Operator [35]

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(Operator Instructions) 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 [36]

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Well, thank you, operator. Thank you very much, and thank you to all that joined the call. Just reiterate 3 messages really: One, the existing business continues to operate very well, and we're growing that. Sole obviously transforms the business, and we haven't been idle in the last 12 months waiting for Sole. We've been getting ready for the growth wave that comes in after Sole because Cooper Energy is a completely different beast, different organization with Sole online in terms of production, cash flow and the opportunities that’s available to us. And we've been preparing ourselves for that in a market where, given the position that we've got and where the gas market is in Southeast Australia, there's a lot of opportunity. And for us, it's a case of selecting the best ones.

On that note, thank you.