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Edited Transcript of BPT.AX earnings conference call or presentation 19-Feb-18 12:00am GMT

Half Year 2018 Beach Energy Ltd Earnings Call

Glenside Apr 18, 2019 (Thomson StreetEvents) -- Edited Transcript of Beach Energy Ltd earnings conference call or presentation Monday, February 19, 2018 at 12:00:00am GMT

TEXT version of Transcript

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Corporate Participants

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* Dawn Summers

Beach Energy Limited - COO

* Derek Piper

* Jeffrey L. Schrull

Beach Energy Limited - Group Executive of Exploration & Appraisal

* Lee Marshall

Beach Energy Limited - Group Executive of Corporate Strategy & Commercial

* Matthew V. Kay

Beach Energy Limited - CEO, MD & Director

* Morné Engelbrecht

Beach Energy Limited - CFO

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Conference Call Participants

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* Adam Martin

Morgan Stanley, Research Division - Research Analyst

* Andrew Hodge

Macquarie Research - Research Analyst

* Benjamin Wilson

RBC Capital Markets, LLC, Research Division - Analyst

* Dale Johannes Koenders

Citigroup Inc, Research Division - Former Director & Analyst

* James P. Bullen

Canaccord Genuity Limited, Research Division - Senior Energy Analyst

* James Redfern

BofA Merrill Lynch, Research Division - VP

* Mark Samter

Crédit Suisse AG, Research Division - Former Director and Co-Head of Australian Research

* Nik Burns

UBS Investment Bank, Research Division - Executive Director and Lead Energy Analyst

* Scott Ashton

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Presentation

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Operator [1]

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Ladies and gentlemen, thank you for standing by, and welcome to the Beach Energy Limited FY '18 Half Year Results Presentation. (Operator Instructions)

I must advise you that this conference is being recorded today, Monday, 19th of February, 2018.

I would now like to hand the conference over to your first speaker today, Investor Relations Manager of Beach Energy, Derek Piper. Thank you. Please go ahead.

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Derek Piper, [2]

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Thank you, Edwin. Good morning, everyone. Welcome to our half year results call. With me is Matt Kay, Chief Executive Officer; Morné Engelbrecht, Chief Financial Officer; Dawn Summers, Chief Operating Officer; Jeff Schrull, Group Executive Exploration and Appraisal; and Lee Marshall, Group Executive Corporate Strategy and Commercial. We'll be talking through our results for the first half of FY '18 this morning as well as touching on the performance of Lattice, and also the outlook for the enlarged business. We'll then open the lines for Q&A.

So Matt, with that, I'll hand over to you for an overview.

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [3]

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Thanks, Derek. And welcome, everyone, to the call. Firstly, some highlights from the half which is set out on Slide 5. It has been an active period for us and it is pleasing to report solid results across the business from the field to our financials as well as the completion of the transformational Lattice acquisition.

We continue to improve profitability and margins. Gross profit of $150 million was 45% higher than the prior corresponding period, benefiting from higher oil prices and further operating cost savings. Those numbers relate to Beach's asset base before the Lattice acquisition.

Regarding oil prices, it is worth noting that our exposure to oil remains material post the acquisition of Lattice. For the first half, approximately half of the combined pro forma revenue was generated from oil and liquids. Looking forward, as a rough guide, a USD 10 a barrel annual increase in oil price would result in our net after -- net profit asset tax being increased by $65 million and our operating cash flows by $70 million.

Regarding costs, strict discipline and a focus on continuous improvement is part of our culture. We pride ourselves on being a low cost operator. Operating field cost remain below $4 per boe and the Cooper Basin joint venture continues its transformation with operating cost savings of approximately 20% relative to the prior corresponding period. These results helped sustain our cash flow breakeven at a world-class level of USD 17 per barrel.

Drilling efficiencies and successful field development activities led to an improved full year outlook. We added an additional rig in the Cooper Basin joint venture, and with faster drill times, we now expect to participate in 98 wells this financial year, up from our estimate of 78 wells at the start of the year. With a drilling success rate of more than 80%, additional wells being drilled and optimization projects well underway, our full year production outlook has improved.

As announced last month, production guidance for the Cooper Basin increased from 10.0 million barrels of oil equivalent to 10.6 million barrels of oil equivalent through to 10.6 million barrels of oil equivalent to 11.0 million barrels of oil equivalent.

Turning briefly to Lattice, as promised, today we provide more information about the Lattice acquisition and our plans for the enlarged business. The transaction completed at the end of January. The effective date for economic benefit was 1 July 2017. And we believe it was a well-timed acquisition from a commodity price and market confidence perspective.

Beach is now a much larger and more diverse operation. We increased reserves by approximately 200% and are now producing from 5 basins. We operate substantial gas processing infrastructure and have a presence both here in Australia and in New Zealand. More on the portfolio and outlook shortly.

Financial close for the acquisition was 31 January. As announced then, strong operating performance and significant free cash generation by the former Lattice assets in the first half allowed us to report net gearing below the original target. Net debt is now approximately $860 million and available liquidity is approximately $540 million. Resultant net gearing is below 33%, which beats our original estimate of less than 35% by the end of March.

We announced today that we have reduced our end FY '19 net gearing target from 25% down to 20%. Today, we also announced an increase in our synergy and cost reduction targets from the Lattice acquisition from $20 million per annum now up to $50 million per annum by end FY '19. Our financial position and free cash generation allowed the board to announce a fully franked $0.01 per share interim dividend. We are now in our 17th year of consecutive dividend payments.

Lastly on this slide, our growth strategy. Our strategy remains unchanged and our ability to deliver growth is greatly enhanced following the acquisition of Lattice. Our model of low cost operations and margin generation remains. We now have an expanded portfolio of diverse growth opportunities, underpinned by strong and stable cash flow generation and a robust financial position. During the first half, announcement of the acquisition of additional interest in the Otway and Bass Basins and farm-in arrangements for the Ironbark prospect in the Carnarvon Basin were examples of further progress made against the growth strategy.

The figures on Slide 6 highlight further improvement in our financial performance. Profit and cash generation increased and we remain in a robust financial position. An increase in Beach-only gross profit of 45% is clearly a key highlight, along with $155 million of free cash flow from the former Lattice assets. Capital expenditure increased from a relatively low base. However, with a spend directed to projects with highly attractive internal rates of return, first half capital expenditures supported our improved financial results and our upgrades to FY '18 activity and production. Morné will talk to those results in more detail.

Slide 7 summarizes our operational highlights. As I mentioned, more wells were drilled. Success rates are high at greater than 80% and pleasingly we've had exciting results from our exploration efforts. Haselgrove-3 has been on test for the past week and results thus far have not diminished our confidence in this being a material discovery. We drilled and connected our first horizontal oil well in the Western Flank, which reached peak daily production of approximately 1,000 barrels.

Our operating gas program continues to deliver great outcomes with 4 new Western Flank producers from our 6 wells drilled. Expansion of Middleton facility to 40 million scfs a day of raw gas is well underway and a further expansion to 50 million scfs a day is now under consideration. Also in the field, we've been successful with our artificial lift and work-over programs. 13 artificial lift installations were commissioned during the half and 43 wells were connected. We had a further 25 wells awaiting connection at the end of December. Strong incremental production from these activities contributed to the improved FY '18 production outlook.

Some more detail now on the Lattice acquisitions starting with strategy on Slide 8. We've previously spoken to Lattice's alignment with Beach's competencies and growth strategy. This slide reiterates the message and summarizes the key benefits of the transaction. We increased reserves by approximately 200% and pro forma annual production by 150%. More exposure to the cash generation of the Cooper Basin joint venture, a material east coast gas market presence, multiple producing basins, gas processing infrastructure and a larger exploration portfolio are just some of the transaction's benefits. Importantly, it also provides us with exploration, appraisal and development opportunities now across multiple basins.

Our low cost and margin extraction model is unchanged and will apply the same discipline to the former Lattice assets. This provides much confidence in achieving the $50 million per annum synergy target. It's important to note that we continue to demonstrate progress against the strategy of our 4 pillars. With the acquisition of Lattice complete, we're fortunate to be executing our growth strategy with a greatly enhanced portfolio. We remain heavily exposed to oil price upside with liquids accounting for 50% of revenues and we now have the security of long-term favorable gas contracts.

Turning now to Slide 9. Beach's purpose is to deliver sustainable growth in shareholder value. With the Lattice acquisition complete, we have set clear objectives to ensure we operate our assets safely and efficiently whilst delivering our capital program as cost effectively as possible. In doing so, we'll maximize cash flow allowing us to balance the requirements of reinvestment in our business with optimal gearing levels and continued dividend payments and ultimately growth in shareholder value.

To accomplish this, the key objectives will include achieving best-in-class health, safety and environmental standards; ensuring assets are operated efficiently and development plans delivered to optimize production and cash generation; delivering our long-term capital program and optimal cash commitments by focusing on the lowest unit cost resources in each basin first. This is particularly important in the Otway Basin.

We intend to divest around 30% of the Otway gas project to reduce Beach's capital requirements and risk profile and also allow a strategic joint venture partner to contribute to the development of the Otway. Please note that the proceeds of that potential divestment are not included in our debt and liquidity forecast today. Before any divestments, we'll be able to reduce net gearing to less than 20% by the end of FY '19. And we've implemented a capital framework to oversee balance sheet and capital management requirements.

Lastly, we expect to benefit from existing gas contracts in place and favorable gas market dynamics in each of our regions. Our longer-term work programs and capital requirements are still being developed. However, we trust these objectives provide initial direction as to how we will deliver growth in our shareholder value.

Slide 10 sets out the revised view on synergies. Originally, we announced a somewhat conservative estimate of $20 million per annum. Having now had time to engage fully with the former Lattice teams during integration planning and execution, we now have confidence in guiding towards $50 million per annum with an aspirational target of more operating cost savings to come. Review of corporate and technical teams identified additional overlap which combined with overhead savings result in a corporate cost synergy estimate of $35 million per annum. This includes the closure of the Lattice Brisbane office within this financial year. We'll also be removing Lattice's previous reliance on Origin services over the course of the next 12 months.

In the field, application of Beach's cost discipline and safety mantra will ensure efficient operating and maintenance activities. This underpins our phase 1 cost-saving target of $15 million per annum. Dawn will talk to the detail in a moment. With significant integration planning completed prior to financial close, we expect to hit the $50 million savings run rate by the end of FY '19.

I'll close on a topic of much interest, our gas sales arrangements. Slide 11 firstly demonstrates how recent commercial arrangements have been negotiated by Beach to benefit from the prevailing market conditions. As a result, we've seen an increase in average realized gas sales price which was $6.50 per gigajoule in Q2 FY '18. Our new GSAs with Origin have been similarly structured to benefit from what we believe will be favorable market conditions over the medium and longer term, with annual pricing increments, market resets every 3 to 4 years and various legacy contracts to be renegotiated.

We are confident of improving gas price trends over time. In terms of pricing resets, 33% of our current east coast gas volumes will be subject to re-pricing or re-contracting by 2020, and circa 78% of pricing will be reset by 2021. Lee Marshall will provide more information on commodity pricing later this morning. You'll also hear a lot more today from both Dawn Summers and Jeff Schrull regarding our intended value extraction from and growth plans for the former Lattice portfolio.

Before we get to that, I'll hand over to Morné to discuss our financial results.

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Morné Engelbrecht, Beach Energy Limited - CFO [4]

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Thank you, Matt. And good morning all. Before I begin, I should note that the half year results as reflected in our presentation are for Beach only and do not incorporate Lattice. Our full year accounts for FY '18 will include consolidated performance for the new combined group post the acquisition. Slide 13 represents a snapshot of financial highlights for the half and shows further improvement in our profitability as our low cost operator model benefited from the 31% rise in oil prices.

Operating cost also held steady over the period despite increased activity in the field in the form of 13 artificial business relations being sanctioned. A 12% increase in sales revenue to $386 million contributed to a 45% increase in gross profit to $150 million and a 13% increase in operating cash flow to $174 million.

Another pleasing story is the continuing improvement in the cost and profitability within the Cooper Basin JV. As we saw last financial year, the Cooper Basin JV is now a material contributor to free cash flow. Despite an extra rig operating in the basin and additional field activity undertaken, the Cooper Basin generated $40 million of free cash flow in the first half. Field operating cost within the Cooper Basin JV were also down by 21%, which delivered strong operating cash flow and allowed us to increase activity in the field including contracting an additional rig. Dawn will provide more detail on Cooper Basin JV cost savings shortly.

Slide 14 sets out various financial metrics. Production and sales volumes were lower compared to record half production and sales volumes achieved in the first half of FY '17 which followed the completion of the acquisition of Drillsearch. Despite lower sales volumes, underlying profit and cash flow generation improved, again demonstrating our low cost operator model and leverage to higher oil prices.

A few points to note. Firstly, statutory NPAT was impacted by a $55 million increase in tax expense after having received an $8 million in tax benefit in the prior corresponding period. On the tax side as noted during the FY '17 results call, we recognized previously unrecognized DTAs, which means that the current half year results more closely resemble at an effective tax rate of 30% and this is all from the expectation for the full year.

Recognizing this and adjusting for impairments in the prior period and other one-off items, underlying impact increased by 5% to $93 million. As Matt mentioned, the board announced $0.01 per share fully franked interim dividend. I'll touch on the approach to dividends and capital management in a moment.

Looking forward, we do appreciate that our balance sheet position and depreciation charges are of interest given the acquisition of Lattice. We are still working through the detailed process of asset valuations and purchase price allocation. We will present a consolidated balance sheet for the first time with our full year results. We can, however, provide an initial steer on depreciation amortization for FY '19, which we expect will be in the range of $350 million to $450 million. We recognized this is a somewhat broad range and will provide further updates as soon as we are in a position to do so.

Slide 15 shows the key drivers of movements in underlying NPAT, which is the same story. High oil prices, high gas prices were partially offset by lower sales volumes and larger tax expense, delivering a 5% increase on underlying NPAT to $93 million. I should also note that the cash production costs reflect increased royalties paid as a result of increased revenue.

Turning now to our balance sheet on Slide 16, as we announced financial close of the Lattice acquisition occurred on 31 January 2018. The purchase price of $1.585 billion provided for an effective transaction date of 1 July 2017, meaning free cash flows from then to financial close accrued to Beach. For the 7-month period, Lattice performed above expectations and generated free cash flow of approximately $180 million. This flow to Beach, we have reduced completion of payment and acquired cash.

With financial close now behind us, we remain in a robust financial position. We have net debt of approximately $860 million and available liquidity of approximately $540 million comprising cash reserves of $135 million and undrawn debt facilities of $405 million.

Importantly, our net gearing is less than 33% which is below our recently estimate of being below 35% by the end of March 2018. Looking forward, gearing levels are expected to reduce rapidly with strong cash generation. Our overall approach to building on a robust balance sheet will be guided by our overall capital management framework which also provides the dividend framework with the overarching priority of creating shareholder value. Our first priority is the reinvestment in our high return on capital programs and further growth strategy over the next 3 years.

Secondly, we are targeting 20% as the net gearing ratio by the end of FY '19, which means we will ensure enough cash to shield over as a notional debt repayment to ensure we meet our debt repayment obligations.

Thirdly, we want to maintain minimum liquidity levels to provide for downside protection and further growth opportunities. The board will then consider dividend payments in the context of this cash utilization waterfall. We consider this approach as optimal for balancing the various operating capital needs of the business with our objective for sustainable growth in shareholder value.

Slide 17 provides key Lattice financial metrics for the first half. I should note that these numbers are unaudited and provided for information only. As mentioned, Lattice performed well, which was reflected in the EBITDA of $222 million and free cash flow of $155 million. The average realized sales gas in equivalent price of $6.12 per gigajoule reflects a weighted average price across the portfolio capturing higher-priced new contracts of Origin and lower-priced legacy contracts. Lee will touch on the asset for gas pricing shortly. It is also worth noting that comparative performance is difficult to present given different gas price structures prior to our economic ownership of Lattice.

That's all from me. I'll now hand over to Dawn to discuss operations in more detail.

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Dawn Summers, Beach Energy Limited - COO [5]

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Thank you, Morné. And good morning, everybody. What I will focus on providing you today will be a view of our first half performance and our key objectives going forward for operations. However, before I dive in, it's worth stepping back to reinforce our top priority and the key foundation of our business. As we focus on high performance and cost efficiencies, safety and our license to operate remains paramount at Beach. It's one of our core values and our track record we believe demonstrates this.

Slide 19 sets out our key results. As you can see, we have extended our full year period of consecutive reductions and the lost time injury frequency rate. Over recent years, Beach has achieved these reductions against the backdrop of increasing activity and major project associated with our infrastructure expansion. These projects have continued to be executed without safety incident or environmental impact.

Environmental performance also continues to improve with further reductions in spills and spill volumes. On the latter, total crude oil spills were less than 2 barrels, which is below our regulator reporting thresholds. Continual improvement in process and procedures underpin all of these results. Looking at Lattice, as these assets were transitioned to Beach, a period which understandably can cause distraction and uncertainty in our team, the focus continued on maintaining safe and reliable operations.

For the first half of FY '18, the Lattice assets continued to deliver improved HSE performance with one recordable injury and one Tier 1 process safety event which occurred on the 1st of July 2017. Going forward, our focus remains on maintaining our license to operate and working with our regulators and third-party service providers to ensure we have no accidents and cause no harm to our people or the environment.

Slide 20 shows Beach's expanded footprint. With the acquisition of Lattice now complete, we have diversified our exposure beyond the Cooper Basin and now boast diversity by basin, jurisdiction and onshore-offshore capabilities, including production from our past Otway, Bass and Taranaki Basins; offshore operated production installations in the Otway, Bass and Taranaki Basins; and operated onshore gas processing infrastructure servicing the Otway, Bass and the Taranaki Basins; and more excitingly, an expanded portfolio of development and exploration opportunities which Jeff will walk us through later.

The transaction has also delivered a material uplift in production and reserves under significantly derisked portfolio concentration via the 5 producing basins. The Cooper Basin remains our largest contributor to production, but we add material volumes from the Otway, Bass and Taranaki Basins and the exciting development potential of the Waitsia project in the Perth Basin. Regarding reserves, we will be undertaking a detailed review of our expanded portfolio as part of our usual annual reporting process and will release these results in August.

Lastly, it's important to take away from this slide that we now operate approximately 70% of our total production, which gives us considerable control of day-to-day operations under direction of our development and exploration endeavors.

Moving to Slide 21. This slide provides a summary of our 4 operations objectives required to deliver shareholder value. Firstly, HSE. As discussed earlier, maintaining our license to operate is fundamental and integral to the overall investment proposition for Beach. Secondly, people and capability, ensuring that we have the best-in-class capability and the right-sized organization to drive a culture of high performance and continuous improvement. Productivity, maximizing production from both our gas and liquids operations through management of this full value chain from reservoir to exports or markets. And finally, driving performance. Making value, not volume, based decisions, maximizing our cash flow and minimizing our operations costs. As Matt mentioned earlier, we have a phase 1 target to reduce our operating costs by $15 million by FY '19.

Moving to slide 22. Total Beach production excluding Lattice for the first half was lower than the prior corresponding period. However, an increase in drilling and field development activity has improved our FY '18 full year outlook. We are now guiding towards Cooper Basin production of between 10.6 million barrels of oil equivalent and 11 million barrels of oil equivalent, which will continue our recent trend of annual prediction -- sorry, production growth. Successful field development activity for the first half included first our artificial lift program in the Western Flank oil acreage with 13 installations commissioned. These provided material incremental production and allowed a number of new producers to be brought online.

Regarding our new producers, we connected wells drilled in FY '17 and also recommenced production from a number of the Cooper Basin JV wells following in-bore well -- in-wellbore activities. In total, 43 wells were brought online, and at the end of the first half, a further 25 new wells are awaiting connection. The half also saw our first Western Flank horizontal oil well brought online. Bauer-26 initially produced at 650 barrels of oil per day, and as Matt mentioned earlier, it increased to a 1,000 barrels a day as artificial lift was installed towards the end of the first half. The results from Bauer-26 give us much encouragement for upcoming horizontal wells to be drilled in our Birkhead and McKinlay reservoirs.

Lastly, we are progressing phase 1 expansion of our Middleton gas facility, which is on track to be completed by the end of this financial year. This will increase capacity to 40 million scfs a day and phase 2 expansion to 50 million scfs a day is under consideration. And we will be able to confirm our plans following drilling results from the second half.

It's pleasing to report that second-half production is delivering against expectations. We have seen particularly strong production from PEL 91, which produced an average daily rate of 12,300 barrels during the first week of February.

Moving to cost savings. Touching briefly on cost savings on Slide 23, the highlight being further progress made by the Cooper Basin JV. Santos as operator continues to impress with cost and capital efficiencies and progress is continuing. Recent moves to the operator-maintainer model that Beach has employed for many years coupled with reductions in headcount and optimizing maintenance regimes have contributed to a 21% reduction in field operating costs to $14 per barrel of oil equivalent.

As we saw last financial year, the Cooper Basin JV is now a material contributor to free cash flow. Despite an extra rig operating in the basin and additional field activity undertaken, the Cooper Basin generated $40 million of free cash flow in the first half.

Overall, Beach's low cost operator model was again evident in our results, including our cash flow breakeven which was sustained at a world-class level of USD 17 per barrel. Our calculations adopt the oil price at which Beach would have been cash flow neutral assuming no discretionary capital was spent. Clearly, this is not a sustainable position to be in but the metric does provide comfort in our ability to protect the balance sheet during periods of extreme market dislocation.

Moving to our Lattice assets and starting on the east coast on Slide 24. Our focus on the second half of this year is to deliver high performance through safe and efficient operations. And as Matt commented and Morné's summary, the Lattice assets have delivered strong performance in the first half of 2018. Starting on east coast, both the Otway and BassGas assets are significant value drivers of our business with a track record of steady production. Our key highlights in the first half being improvement in asset uptime and reliability, successful completion in start-up of the Halladale-Speculant project and successful completion start-up of the BassGas mid-life compression project. Looking forward, our focus will be on driving high productivity and cost state and execution of the E&D program which at Otway includes 2 exploration wells and 1 development well, which Jeff will elaborate on later, and at BassGas defining the Trefoil opportunity.

Slide 25 and moving to our west coast assets, Beharra Springs and Waitsia. Beharra Springs, a simple remote operation and a challenging market. The focus is to keep the facility full and extend the life to maximum capacity. Our objectives at our west coast business will be to deliver on the high-pressure, low-pressure tie-in project at Beharra Springs to extend plateau, to drill our Beharra Springs Deep exploration well and to drive the Waitsia phase 2 project to FID.

Finally, for New Zealand on our Kupe asset, another very important asset in our portfolio with an excellent track record and strong cash flow generation. Focus will be to further improve reliability and uptime, manage cost state and extend the production plateau via the Kupe phase 2 compression project with the potential to deliver to drill a development well post Kupe phase 2.

So that's all from me. And I will now hand over to Jeff to talk about the exciting exploration and development program. Jeff?

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [6]

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Thanks, Dawn. Slide 27 is a drilling summary from Beach activities for H1. As we said at the quarter, we've had a great first year, the highlights have been the Haselgrove-3 new field and, to make this point, new play type. There's a new deep play that we've unlocked with that well called the Sawpit play that we're quite excited about. So it's got a bit of running room and it's onshore, near infrastructure gas -- east cost gas dynamic, it fits our strategy perfectly. The test program is ongoing. We'll be collecting dynamic and static data for the next 3 weeks. But as Matt says, the results so far haven't diminished our excitement. The data will be used to come up with a resource assessment range and come up with a well-thought-out appraisal program and development options for the resource.

At Middleton, Dawn mentioned we've made 4 discoveries. We're on our way to the 40 million a day project size sometime in the next financial year. And I'd like to give some credit to the ops guys. We drilled and hooked up Lowry in 4 months and that's world-class cycle time for a gas discovery and it wasn't an easy project, so well done guys.

Made a nice discovery with Senex, made a nice discovery with operator at Marauder. We've got 2 appraisal wells planned for the second half of this year. Slowly getting ahead around the upside potential of the Birkhead play and it still holds all the value that we've spoken about previously.

In summary from my perspective, the first half focus on the proven play fairways and putting our drilling dollars into the stuff we noticed that works is continuing to pay. And we're going to continue to do that in the Cooper Basin.

Slide 28. Okay, the rest of my talk is going to be mostly focused on what Beach looks like as of today. 28 is an approach slide. We're going to be talking a lot about field development plans and basin development plans from current production all the way to optimizing value from exploration activities. We are in that 5 producing basins. Dawn talked about our low cost strategy. So we've got the producing fields, development opportunities. Just a couple of examples, compression of Beharra Springs and Kupe are on the cards, development drilling at Black Watch, continued development drilling at Cooper Basin and H-3. So all that looks good.

The third part and we're going to discriminate between relatively high-risk impact exploration and what we call very low risk exploration near infrastructure. We like to think we can get some of the risk down almost to appraisal-type level and that's where the prospects Enterprise and Artisan come in. And then we do have our high-impact exploration portfolio in the Canterbury in New Zealand. And the Bonaparte, we got a very big portfolio there with our JV partner Santos. And the Ironbark prospect in the Carnarvon Basin that we were confident we'll get funded and we'll take part in that well.

Slide 30, I'm going to spend just a bit of time on. There has been some confusion, I think, in the market. The time line shows what a basin development plan looks like for the Otway. At the time of the purchase, Lattice had an option to take 4 slots on the Diamond Monarch drilling schedule that's currently going to Cooper for various activities. Two of those wells, very high-risk exploration and a throwaway appraisal well, that to be blunt do not fit Beach's investment criteria. So we did not exercise that program. At the time, Enterprise had been identified on 2D data and the 3D data was coming in, and we felt like that would end up being a very low-risk exploration/almost-appraisal risk prospect that would be money much better spent to keep our production optimized and add new production. The map shows our -- in red our 5 producing fields and the 2 exploration prospects Enterprise and Artisan that we're very excited about drilling. And we think they on a risk basis have a very good chance of adding production and sustaining production for the next few years.

The Geographe and Thylacine infill programs are still very much valid and we're excited about them and we're going to get after them, they still add value. We just think we can do more technical studies using the seismic attributes and avoid that concept of a throwaway appraisal that just doesn't work for us. Still value added. Again, it's just about maximizing the revenues and the production over time. So basin development plans, you'll be hearing a lot about them.

Slide 30 is the Perth Basin. As Dawn said, long-term established operator at Beharra. Beharra Springs Deep is the near-term well that we want to drill because we could get production increase in the near future, we've got capacity in that plant. But the crown jewel in the Perth Basin is Waitsia. In our view, Waitsia 3 and 4 are game changers. We found [keenest] section that was thicker, more porous, higher perm, really good deliverabilities. And in our view, that's sort of a reset button for what this -- how this field does in terms of size and development plan this field can be monetized. So Beach is currently undergoing a complete bottoms-up, retying the seismic data, evaluation of the entire asset integrating these 2 new wells and we'll be coming up with our own development options that we can discuss with the operator going forward.

And at the bottom slide -- the bottom line is the Perth Basin is a major production growth, long-term sustained cash flow part of our story, and we're -- obviously, Waitsia 3 and 4 did nothing to diminish our enthusiasm.

In the -- on Slides 32 and (sic) [to] 34, we just wanted to give illustrative work programs for the basin outside the Cooper, and it's sort of split by development activities and E&A activities. Obviously subject to board approvals and will be put in more detailed plans. But this is where we feel the assets are going to go at this time.

On Slide 32, in the Otway, new producers to sustain and possibly grow exploration and as quickly as we can. So the highlights of these low-risk exploration wells that we've identified at Artisan and Enterprise, Enterprise is an ERD well that we can drill from the shore and hook up very quickly, and we'll be seeking to shorten that time line to spud an online production as much as we can in the coming months.

Black Watch. Black Watch, we'll be drilling -- we're planning for FY '20. Can we get it done earlier in FY '19? We'll see. We have -- the environmental process in Victoria is onerous for onshore wells and we'll compress it as much as we can. And then the onshore compression is obviously -- that's about as cheap as reserves in production as you can find.

And Geographe and Thylacine, we're going to do some subsurface studies and absolutely shorten the gap between appraisal and online times. A big focus going forward for our BD, basin development, plans is shorten the cycle time between drill and online. The exploration, appraisal, development, all of our drilling dollars have to put money in the bank ASAP.

Slide 33, Bass in New Zealand. Focus is going to be largely in the near term on optimization of facilities. In-wellbore opportunities at Yolla, there are several that we've seen. In Kupe compression, we'll monitor the timing of that and when it's most appropriate, and also see if we can get away without drilling another development well at Kupe depending on how the reservoir depletes. So that's a very high-end reservoir modeling at Kupe for the long-term planning but no major capital projects in terms of drilling for either of those 2 assets at the moment.

Slide 24 -- 34, the Perth Basin. As I've talked about earlier, it's about Beharra Springs Deep and the jewel that is Waitsia and getting up the project size and the field development plan optimized and get to FID hopefully in FY '19.

Lastly but definitely not least-ly, on Slide 35, the Cooper Basin, the very-high-margin Cooper Basin, it's still the highest margin probably. Western Flank Oil, we're going to continue, like I said earlier, focusing on the Namur and McKinlay pools. Bauer-26 was a proof of concept, but it's not really -- we just drilled 4 horizontal wells -- Santos drilled 4 horizontal wells in the McKinlay field with almost 3,000 meters of drain, and those wells are going to be hooked up between TD and first production in less than 3 months. So the program they did there is very -- almost analogous to the programs that we're going to have on the Western Flank. So the industry is doing it. The costs are going to come down, and there is a lot of oil to recover on the Western Flank.

The Birkhead, there's exploration and appraisal. As I mentioned, we're appraising Marauder. The Stunsail-6 well is drilling as we speak and it's going to be a horizontal -- our first horizontal producer in the Birkhead. Not optimized, it's a proof-of-concept well similar to Bauer-26, but we'll take that well and come up with a plan to optimize the design of these Birkhead horizontal wells. The Western Flank Gas, we continue to drill up our Southwest Patchawarra play fairway inventory. We've got 6 more wells planned this financial year.

Spondylus, the final survey comes in May and we'll -- the plan is to replenish that Southwest Patch proven play inventory with 6 or 7 drills. The Permian Edge play is the high-upside exploration potential. Basically, the Permian Edge inching out onto the Western Flank creates a potential huge stratigraphic trap. We've drilled one well that we had chose. Unfortunately, we didn't have good reservoir quality. And after Stunsail, the rig is going to go to PEL 630 with our partner Bridgeport and drill Lady Bay and Ulladulla, which are Permian Edge exploration wells. So if one of those hits, we'll be talking about much an expanded campaign there.

In the Cooper Basin JV, most of it's been said. We were confident of approving the third rig when Santos proposed it, wealth of inventory, a near field appraisal development drilling. They're applying these horizontal drilling techniques that are working and giving us production to exceed on our production targets, both gas and oil. But we do have some exploration drilling coming up in the second half. There's 4 or 5 risky high-potential exploration wells. One is test the Innamincka Dome flank, which is similar to the Permian Edge play fairway, but over in Queensland on the Innamincka Dome site. And again, if those wells hit, that could lead to a lot of activity.

And I will note that the operator is still targeting flat production in our Cooper Basin assets for several years. And we'll be working with them along the way to come up with any opportunities that we can show to put on the drill schedule and just keep working more and more together in the Cooper Basin to get the costs out and keep the drill bit working for us.

One of the -- one final thought about the Lattice acquisition, the synergy between us and Santos is one of those hidden value captures that we got because now our drilling teams are going to talk unencumbered with any other JV partners. And we've already started some of those discussions.

So that's what our program looks like for the next year or 2. I'll turn it over to Lee.

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Lee Marshall, Beach Energy Limited - Group Executive of Corporate Strategy & Commercial [7]

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Thanks, Jeff. Good morning, everyone. If we start with Eastern Australia on Slide 37, this is a story I'm sure you're all familiar with. You now have the gas demand, not only domestic use but also Queensland LNG with a total market in the order 2,000 petajoules per annum. This AEMO forecast shows the developed reserves in red, a declining path, and the ongoing development of all undeveloped 2P reserves, shown in orange, is required in the immediate term.

Even with this ongoing development, the market remains tight with a forecast supply deficit in 2018 and '19. Beyond these undeveloped 2P reserves, it can be seen that still a significant supply gap with contingent resources that are currently considered to be uncommercial, shown in light blue, and as yet undiscovered resources in brown are required. Even then, under this forecast, the market will be tight. Beach is well positioned as the major east coast gas supplier, explorer and developer with positions in 3 basins servicing this market.

Onto Slide 38. This slide makes 2 important points. Firstly, is due to price reopen as in contract expiries, we have excellent near-term exposure to east coast market pricing in a market where fundamentals are strong and forecast improving. Secondly, that until these pricing resets, our current gas supply arrangements remain attractive and are delivering excellent results. On the first point, the chart show our east coast re-pricing profile over time. The first column represents our current east coast supply position in terms of volume. You can think about it actually as a sum of our annual contract quantity, and the floating columns to the right illustrate how this total volume is exposed to market re-pricing over the next few years, either due to market price review provisions in the gas sales agreements or due to expiry of the agreement themselves.

You can see that by 2020, around 1/3 of our existing east coast prices will have been reset to market prices and by 2021, roughly 78% will be reset. So most of our sales will be re-priced to market in a period where the fundamentals are expected to be very strong with potential gas shortfalls forecast. And we do indeed believe in these fundamentals. You can see the spot prices today of over $9.50 a gigajoule and we've got AEMO forecasting a gas supply deficit this year and next. And as we saw on the previous slide, the supply situation is only expected to climb further with increasing reliance on lower-probability sources of gas.

The second point I'll make here is that regardless of these pending market price resets, we have right now fundamentally attractive gas supply arrangements in place. Our pro forma first half 2018 realized gas price of east coast supply was $6.33 a gigajoule, and up until the point these prices have reset to market, our existing contract prices will continue to benefit from either annual step-ups and CPI adjustments, CPI increases only or oil price upside exposure.

Slide 39. So looking at our other gas markets, this chart shows forecast Western Australia natural gas demand and supply, again sourced via AEMO. Forecast indicates that based on declining domestic gas production and indicative LNG producer domestic gas requirements that a potential supply gap emerges as early as 2021. We expect that a significant tightening of prices from current levels will be required to balance this market. We think we're exceptionally well placed to benefit from this, particularly in respect to the Waitsia development Jeff discussed. In New Zealand, we enjoy a strong gas sales agreement with our Kupe co-venturer Genesis Energy and are well positioned there to benefit from the development opportunities that Jeff also talked about.

Finally, on Slide 40. We've been talking a lot about gas and we are extremely excited about our gas position in the future. Liquid still remain a very important contributor to Beach's current performance. This recent half year, liquids contributed over half of our pro forma sales revenue with crude oil revenue [fully] 40% of this. In terms of bottom line impact, we estimate a USD 10 per barrel increase in oil results in roughly $65 million increase to NPAT and $70 million increase in operating cash flow.

I'll now hand back over to Matt.

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [8]

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Thanks, Lee. Hopefully, you've seen we've got a lot more information to provide so as we've promised around the Lattice assets. It's an exciting time at Beach and we are going through a significant transformation with a lot of opportunities. We've had a lot of information. I'm going to hand over now for the questions, if we can.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Your first question comes from the line of Adam Martin from Morgan Stanley.

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Adam Martin, Morgan Stanley, Research Division - Research Analyst [2]

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For me, just spend a bit of time just talking about the Otway farm down. Clearly got 100% of that asset now, but there is a fair bit of free cash coming to this business next couple of years. So can you just talk about the strategy of the farm down?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [3]

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Yes, sure, Adam. Look, we've signaled this quite early. We said once we had acquired the Lattice assets and one of the points we made that we were positive on all of the assets. So we weren't expecting to sell out of any of the assets completely because we're very comfortable with the entire portfolio, but what we did flag was being at a 100% of the Otway now going forward. That's a fairly unusual place to be in terms of awaiting on any particular asset. And given the capital program we've got and also wanting to have a JVP there to help us along the path challenges technically and commercially, we liked that model and we think having another party there working with us is the right way to go forward.

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Adam Martin, Morgan Stanley, Research Division - Research Analyst [4]

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Okay. And just in terms of the production profile for that asset, clearly, you've moved out some of the original developmental appraisal that Origin had planned. How should we think about production from that asset for next 2 to 3 years? Can we sort of -- sort of rough decline from current levels over the past 12, 18 months or...

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [5]

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Definitely not for 2 or 3 years. I mean, we have some low-risk development activities that were going to be getting after as soon as we can, but the development well at Black Watch and the onshore compression near the ERD wells, the exploration wells if they're successful could come on stream within 3 or 4 wells -- 3 or 4 years. Artisan, the Enterprise well like I said, it's an onshore ERD well and there is a pipeline that goes to the Otway plant that they can hook into. So give us a bit of time and let us get the timing of all these projects and approvals but definitely not any -- it will be faster than the phase 4 program that was planned by Lattice when we picked up the asset. That gap between the offshore appraisal drilling at Thylacine and the actual drilling of the development wells, which was a few years originally, we think we can diminish that gap significantly. So if the exploration wells don't work and I really think they will, then we can still develop the Geographe and Thylacine on roughly the times -- the same time frame.

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Adam Martin, Morgan Stanley, Research Division - Research Analyst [6]

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And what about the production from the existing wells? So obviously, that's a future work program to tie in undeveloped reserves effectively. But what about production from existing wells? Should we just be assuming gradual decline from here?

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Dawn Summers, Beach Energy Limited - COO [7]

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Adam, it's Dawn. We will make sure that we optimize our existing production and make decisions across the value chain, so from our reservoir to an export. So we will be looking to optimize our existing facilities and also our cash generation from there, and together with Jeff as we develop later the near-term development opportunities and understand what decisions we need to make like with regards to the right investment choices for the field.

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Lee Marshall, Beach Energy Limited - Group Executive of Corporate Strategy & Commercial [8]

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Just to close out on that end. I think we touched on that at the quarterly. The one point I would make is this is all about value optimization, all right. So I wouldn't infer that any deferral of any CapEx is diminishing value, it's quite the opposite. So when we are deferring CapEx or switching to lower unit to an equal cost opportunity, it's to enhance, really, not the opposite.

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Adam Martin, Morgan Stanley, Research Division - Research Analyst [9]

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Exactly what I'm trying to understand is what's the cash flow coming to the Otway on the next 2 years and part of that I need to understand the production profile as well. So you're deferring the CapEx, but also I want to understand what's the production profile. But that's all good.

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Operator [10]

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Your next question comes from the line of Nik Burns from UBS.

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Nik Burns, UBS Investment Bank, Research Division - Executive Director and Lead Energy Analyst [11]

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Just a question, maybe high level one on the Lattice acquisition. At the time of the acquisition, you sort of outlined the 2P reserves you're acquiring, I guess, in the same context of what Adam is talking about. But just now you've had an opportunity to take a good look at what you've acquired. We've clearly seen some positive news on Waitsia since the deal was first announced. But on the rest of the assets, is there -- are you up to give an update at all on what your view of the 2P reserves are? Are you still comfortable with the reserve levels that you acquired?

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Lee Marshall, Beach Energy Limited - Group Executive of Corporate Strategy & Commercial [12]

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Sorry, Nik. Obviously, it's too early to make definitive statements around reserves, and clearly, we're not reserves reporting today. But what I would say is we haven't seen any material negative news flow or anything we didn't previously understand before the acquisition. So we did a lot of DDs, the markets where -- around this opportunity we were looking at it before it was even known as Lattice. So we've done a lot of due diligence and there's nothing that's come through since we've been on the under the hood. It's been a negative surprise, quite the opposite. What we're saying is positive opportunities and certainly that was part of the reason we came out quickly with the increase in -- significant increase obviously in terms of synergies because we think there's a lot of value that we can drive from the assets and now that we've spoken to the individuals who are working the asset, they believe the same.

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Nik Burns, UBS Investment Bank, Research Division - Executive Director and Lead Energy Analyst [13]

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And that's clear. And just on the plan to sell down Otway, you have targeted 30%. Just wondering why that number? And why you feel that's the right number there? And I guess in terms of what you've talked about today in terms of pushing back timing for drilling, et cetera, and to take more time to understand what to do with the asset, do you plan to have all of that sorted out by the time you enter into some sort of sale process there just to give the potential buyer some clarity as what your long-term plans are there?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [14]

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Yes, absolutely, Nik. So part of the reason of scheduling this process going forward is so that when we talk to potential buyers, it will be around the optimized program rather than the previous development program. So we'll have the new program in play to talk to parties. It's fair to say a number of parties are already approaching us. The 30% is a guidance number at the moment, if it ends up being 20% or 40% or it's just in that range. Obviously, it needs to be material enough to attract the interest of the type of parties that we want to have as strategic partners as well. So it's really a guidance number at the moment, but you're right, we will definitely have the new plans in front of the market as part of that process.

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [15]

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Again, Nik, this is Jeff. As the winning bidder in closing, we put an incredible amount of technical resources getting ready for this process. As I said, the Enterprise 3D survey is just literally the interpretations hot off the press that we've seen this come in and we know technically we need to talk to whoever our partner is going to be about how we want to approach this.

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Nik Burns, UBS Investment Bank, Research Division - Executive Director and Lead Energy Analyst [16]

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And just maybe one final one, maybe for Morné, just on your guidance here reaffirming 30% P&L tax guidance, just wondering whether you are in a position to provide any guidance on cash tax just in the context of Lattice acquisition. Were there any tax losses there you can use to offset any Beach cash tax payments, et cetera?

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Morné Engelbrecht, Beach Energy Limited - CFO [17]

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Just in terms of -- Nik, in terms of the tax payments for Beach standalone, we paid a $6 million tax payment in January which was provided for pay FY '17. And then we have got installment payments for the rest of the year as well which can add about $3 million. So that takes you to about $9 million. And then from a Lattice point of view, there is no losses coming over, so again just using the 30% effective tax rate should get you there.

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Operator [18]

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Your next question comes from the line of Ben Wilson from RBC.

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Benjamin Wilson, RBC Capital Markets, LLC, Research Division - Analyst [19]

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I just wanted to clarify one thing in the breakdown of the Lattice asset review that you've done on -- this is Slides 24 and 25 there. I just get a bit of a different number in terms of the free cash flow generation from these assets versus the $155 million that you had indicated for the first half adding up those assets there plus sort of prorating that Cooper $40 million free cash flow. I get to somewhere north of $200 million of free cash flow. Am I doing something wrong or is there a bit of a difference in definition across those free cash flows there?

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Morné Engelbrecht, Beach Energy Limited - CFO [20]

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In terms of our definition we use, I mean it's obviously the operating cash minus any capital expenditure. So happy to talk to you afterwards just to reconcile your numbers with ours on that.

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Benjamin Wilson, RBC Capital Markets, LLC, Research Division - Analyst [21]

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Okay. Just the straight sum of those, those assets that you listed there?

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Morné Engelbrecht, Beach Energy Limited - CFO [22]

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Yes. Yes.

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Operator [23]

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Your next question comes from the line of Dale Koenders from Citigroup.

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Dale Johannes Koenders, Citigroup Inc, Research Division - Former Director & Analyst [24]

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Just wondering on your cost-out program, is that all OpEx or is that, I guess, within your $50 million number, there's also CapEx interest cost, tax efficiency, D&A, et cetera?

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Morné Engelbrecht, Beach Energy Limited - CFO [25]

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That's OpEx, Dale. It's basically pure cash OpEx as well.

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Dale Johannes Koenders, Citigroup Inc, Research Division - Former Director & Analyst [26]

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And then how do you think about, I guess, the development plan going forward? I guess Origin had a great success drilling onshore wells at the cost of offshore wells. Do you think there is a opportunity to reduce the CapEx within this business going forward?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [27]

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We do and part of that is obviously the Otway program that Jeff has been talking too which is the most obvious one. We think across all of the metrics being a pure play E&P company focused entirely on cash extraction from these assets we think will help them going forward. And Dawn, I don't know whether you want to comment on some of the capital and the operations.

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Dawn Summers, Beach Energy Limited - COO [28]

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I think back to Matt's point earlier with regards to making sure that we make the right choices or we have [extra] capital for the right return. And to Jeff's point, around ensuring that we will look at the full field development fund for each of the asset and we're going to do a full bottoms up for each asset to make sure we made the right decisions at the right time. Jeff?

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [29]

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I think that part of that was you think we can get lower drilling costs in historically Origin. Was that part of the question or am I throwing that in there?

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Dale Johannes Koenders, Citigroup Inc, Research Division - Former Director & Analyst [30]

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(inaudible) but I guess the follow-up...

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [31]

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I think there's an opportunity to approach drilling in a way that it's kind of similar to what we've done in the Cooper Basin, to really focus on low-cost drilling and completion techniques and that will be part of capital reduction program.

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Dale Johannes Koenders, Citigroup Inc, Research Division - Former Director & Analyst [32]

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Then when we think about the $140 million (sic) [$150 million] to $170 million pro forma CapEx in FY '18 for Lattice assets on a go-forward basis in what looks like an increased work program, should we be thinking about that number increasing, staying the same? Could you drive some cost down or do you think?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [33]

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We'll need to give you more guidance on that, Dale, as we come out with the details of the program. I wouldn't want to come out with a set range number because there will be some volatilities dependent on the work program. So I think once we come out with the detailed work programs, then we'll give you more guidance on the capital movements.

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Dale Johannes Koenders, Citigroup Inc, Research Division - Former Director & Analyst [34]

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Okay. And then finally you comment about gas prices being above Beach's last 12-month average realized price which is indicating that the Lattice assets indicating sort of greater than $6.35 a gigajoule? Am I interpreting that right, that the -- that's a little bit higher than prior guidance of above $6.10 a gigajoule?

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Morné Engelbrecht, Beach Energy Limited - CFO [35]

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Yes. That's correct, exactly.

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Operator [36]

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Your next question comes from the line of Andrew Hodge from Macquarie.

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Andrew Hodge, Macquarie Research - Research Analyst [37]

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I've just got 3 questions and the first one is the volume that you're saying that will be still contracted post '21. I just wanted to check does that mean that you're assuming that Origin extends the right for their 8-year GSA by another couple of years? Well, why don't we do one by one?

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Derek Piper, [38]

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You referring to the oil link contract there?

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Andrew Hodge, Macquarie Research - Research Analyst [39]

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Yes, that's right.

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Lee Marshall, Beach Energy Limited - Group Executive of Corporate Strategy & Commercial [40]

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Can you repeat the question, sorry?

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Andrew Hodge, Macquarie Research - Research Analyst [41]

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Sorry, say again.

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Lee Marshall, Beach Energy Limited - Group Executive of Corporate Strategy & Commercial [42]

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Could you repeat the question, please?

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Andrew Hodge, Macquarie Research - Research Analyst [43]

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Sure. Are you assuming in when you're saying 78% is uncontracted by that, that you can re-price for that point, so therefore applying 22% is still is locked in? Does that mean you're assuming that your Origin contract is extended and they take the option to be able to try and do that?

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Lee Marshall, Beach Energy Limited - Group Executive of Corporate Strategy & Commercial [44]

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The option -- it's similar -- sorry, I totally I get it. Let me just tell you the chart to see if that answers it. So this is price for the provisions under the gas sales agreement and contract expiries. Right. So up to 2021, that's 78% of the portfolio. The residual 22% is the contract expires in 2025. And there's no price reopening before then. I'm not sure that answers it. Perhaps if you want to clarify a bit further.

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Andrew Hodge, Macquarie Research - Research Analyst [45]

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We can catch up offline, it's okay. Okay, so second question then is that I was just trying to understand a little bit more about Otway since about sort of half the reserves sitting both in Geographe and -- are undeveloped and you've kind of push that out. I guess I just like to get a little bit more and it seems like you're banking a lot on Haselgrove in the near term to stop the declines. Can you give a little of bit idea about when we could expect to get some more information? Is it sort of post the production testing you're doing now? And then I think you guys did mention before about you weren't really excited about some of the exploration stuff, Jeff, but I thought T30/P and VIC -- I can't remember what the code is but -- that you guys have to do that under the requirements that Origin had. And so I just wanted to understand -- and in fact, one of them I think you had to drill by September this year. So just wanted to work out what you guys had to do there? And then I guess with Dombey as well, just to try and understand about is this just basically you guys are pushing exploration to try and offset on undeveloped reserves?

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [46]

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Okay. You said you had 3 questions and I think there were 6 you listed in that. So to start with, Haselgrove-3, we haven't made any comments about production rates or any field development assumptions going forward. We were still testing the well. Dombey was a -- is a follow up well, it's a good well. We applied for it and received a PACE grant for that, which obviously helps the economics for exploration ventures. And so that's the -- onshore Otway SA [has been over trough] part of the question. The reserves at Thylacine and Geographe are still 2P undeveloped reserves in Thylacine and Geographe. It's just a timing issue of when do you want to get the more expensive unit technical cost per boe reserves. And I'm not going to say that much more about Origin and Enterprise, now but the [more you see] is renowned in this basin when you put gas in it. You see these beautiful hydrocarbon indicators on the seismic, you can literally see the gas water contacts like you can at Thylacine. So the de-risking of Enterprise with the 3D that's happened literally just in the last 6 to -- 6 weeks to 8 weeks since the data has been interpreted has really made it an attractive opportunity. And like I said, almost, it's an appraisal-type risk. We're not talking to our final risk or sizes, but we will be with potential partner. So the -- and we would definitely put together a full field development plan for our -- for the fields, Geographe -- we already have one for Black Watch, that well has been designed and is planned. For Geographe and Thylacine, we would put together a full field development plan that we think is a more effective way to access those undeveloped reserves. The key thing that we felt we could offset is that cost of drilling an appraisal well and P&A in it and then coming out 2.5 or 3 years later and drilling some sort of a horizontal drain to get those higher reservoirs. I think we can come up with a plan where we shorten the cycle time, like I said earlier, between drill and hookup. 2.5 or 3 years is just too long to have $100 million sitting on the table. It just doesn't -- and I've worked on fields all over the world where that's been done, so I know it's doable but I guess Origins has had a very -- or Lattice had a very conservative view, which is fine, of how they wanted to approach it. I guess we take a more balanced basin-wide view. And the T30/P, that Murchison well, that we're -- we'll be talking with the government about management of our permit obligations in the coming months.

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Andrew Hodge, Macquarie Research - Research Analyst [47]

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Okay. I guess the reason why I was just wondering about the Haselgrove-3 is just because on the chart you guys got on Page 32 and I realized it's illustrative, but it looks -- you guys are kind of implying that it's going to come in first and I guess that's why I'm kind of directing the questions about Haselgrove?

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [48]

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Yes. Let me clarify that. Because of we're -- Haselgrove is an existing field and it's only a less than a kilometer and a half from the Katnook -- the old Katnook gas processing facility, and so the cycle time of getting this one well hooked up could be quite low. And there would be a local market demand. And so Haselgrove could go forward -- I'm not saying it will -- could go forward as a small one-well hookup of H-3 and it was drilled as a production well. And then followed by appraisal and maybe some project expansion in the future depending on how the resource pans out. So that end of '19 is we feel definitely possible we got a project schedule if we decide to go that route. But it would be just a small one-well hookup of this one producer.

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Operator [49]

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Your next question comes from the line on James Bullen from Canaccord.

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James P. Bullen, Canaccord Genuity Limited, Research Division - Senior Energy Analyst [50]

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Just a quick question around the organizational structure in your shift towards a more functional organization. Obviously, some of your peer groups have started to move away from functional to more asset-based. So I'm just looking for a couple of quick comments as to why you think that this is the right direction now for Beach.

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [51]

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Yes. James, it's a good question. Look, we looked at multiple structures as you'd expect and we thought that where Beach is currently at in its transformation was really important for us to set up a model where we had strong expertise across all of the functions and we became a true pure play E&P company focused on extracting value through those functions. Now that's not to say that there won't be a crossover with assets. Naturally, there will be. So there'll be connectivity across the assets into those functions to make sure that there is accountability and empowerment. So one of the key things we're working through as a new team is accountability and empowerment to make sure it's really clear on decision-making authority and making sure that we've got people driving the right outcomes. So frankly, look up what's under asset models or what's under functional models or what's under cross-functional matrixes, a lot of it really comes down to the behaviors of the individual and the leadership to make sure that we actually communicate properly and make the right decisions. So it's going to be the discipline of making the right decisions and involving the right people is the key.

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James P. Bullen, Canaccord Genuity Limited, Research Division - Senior Energy Analyst [52]

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Great. And just a question to Jeff. Obviously, you're pretty excited about what's happened to the Haselgrove, and you're talking about the potential of the Sawpit Sandstone. I'm just trying to, therefore, rationalize why you've relinquished PEP 171. Is that more of an indictment on what's happening in Victoria and the prospectivity over the border?

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [53]

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I'm looking at our legal counsel. I'm not sure I can answer that one. We've -- PEP 171 was considered a nonmaterial part of our portfolio so we relinquished it.

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Operator [54]

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Your next question comes from the line of Mark Samter from Credit Suisse.

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Mark Samter, Crédit Suisse AG, Research Division - Former Director and Co-Head of Australian Research [55]

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I have a couple of questions if I can. The first one when we look at Slide 37 and the market opportunity and I guess that a lot of orange block is Queensland CSG and we look at Ironbark, what happened on some of that more on certain lower-quality CSG, that your real exposure to take through this presentation, your real exposure at the moment portfolio-wise is much more around the price uptick rather than volumes. Your gearing is going to be sub 20% in a year's time or so. Do you think there is scope to target inorganic opportunities on the east coast in particular still?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [56]

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Mark, we will continue to look at inorganic opportunities. I think we've been pretty clear in the market that it's certainly not the right timing now to target something the size and scale of a Lattice or something similar again. Clearly, we are in a detailed integration, execution mode which has a great amount of opportunity for us. So we're really focused on getting the value add of the Lattice asset. However, there are other bolt-on opportunities and there are other opportunities in various basins that we continue to look at, or we'll just at the moment rule us out from something the size and scale of a Lattice-type opportunity.

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Mark Samter, Crédit Suisse AG, Research Division - Former Director and Co-Head of Australian Research [57]

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But just a quick question following on the question on Lattice reserves. I could be wrong in this but I would have always assumed that Origin when they cash Lattice reserves didn't assume that up -- step-up to market prices. I mean, it's pretty clear through this presentation where the Beach view is where market prices are going. I mean, intuitively, to me that says you can be testing later-life reserves or watching contingent resource at the moment and Lattice on a materially high price deck than probably Origin were. Is that a fair assertion?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [58]

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I can't really comment on what Origin had done in the past, Mark, nor am I actually aware of what they'd done in the past. What I would say is when we do our reserves testing, clearly, we take a prudent approach. So we don't take bullish outlooks when we do our testing on commerciality of our reserves. But I would say the vast majority of our portfolio as we know is low cost and high margins. So it's pretty rare that we're having discussions around the commerciality of our reserves frankly. But it's obviously something we'll have more of a discussion about going forward with some of the offshore opportunities.

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Operator [59]

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Your next question comes from the line of James Redfern from Merrill Lynch.

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James Redfern, BofA Merrill Lynch, Research Division - VP [60]

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I just wanted to touch on the Waitsia project. Obviously, there's Waitsia 3 and 4 has been really strong and talking about it is on potentially in excess of how many PJs a day. Just wanted to get some comments around the WA gas market in terms of what you're seeing there, in terms of pricing, whether you can comment on any progress in terms of the GSAs being signed. Clearly, it's been a year since the AGL hedged agreement was signed for 15 PJs a day. So I just wanted to get update on that. And then obviously your rework in the projects and FIDs moving into, what was it, another 6 months away.

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [61]

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Thanks, James. But just in terms of the WA market, certainly right now, if you look at the spot market in WA, it's a reasonably oversupplied market right now. So that's why we're seeing a low spot market. What we do see, however, going forward over the medium term is obviously a rebalancing of that market. So we do see an opportunity there in terms of that price coming back up. I think, in terms of the project itself, obviously we're relatively new in terms of having our hands on the asset. We're really pleased, as Jeff has pointed out, with those last 2 wells. Waitsia is an asset we've had our eyes on for a very long time. And I guess the surprise there with the increase in reserves, it wasn't a surprise to us, but certainly, the deliverability of those last 2 wells is a great surprise for us. So we're really pleased with that and we do think that means we can potentially rescale that project and get more value out of it. And again, it's another one of these situations where I would not assume a deferral of any kind is a reduction in value. It can actually be quite the opposite. So now that we have a better understanding of the volumes and the deliverability of Waitsia, we can potentially rescale, resize that asset. And obviously, there's a few things happening around the operator at the moment and as I said previously we're keeping our eyes on that and making sure that Beach's position is protected.

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James Redfern, BofA Merrill Lynch, Research Division - VP [62]

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And just what about some progress in terms of signs and GSAs? Is that still sort of quite active? And where you see the gas going? Is it still the Perth retail market or is it potentially north to some of the industrial customers up there?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [63]

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Certainly, nothing to announce at the moment around GSAs. What I would say is we are open in terms of how that gas is delivered and where it's delivered to. So it all comes down to really if that gas ends up going north or goes elsewhere or ends up being in LNG or swaps. So whatever it is, we're open to all alternatives. It's about the highest value that we can create from the resource.

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Operator [64]

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Your next question comes from the line of Scott Ashton from SHA Energy Consulting.

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Scott Ashton, [65]

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Just 2 exploration questions, just on Slide 13, just on the back of James' question. With respect to Waitsia, should you be thinking that if you're going to maximize NPV in Waitsia, you're looking at sort of 120, 150 PJ as a potential scenario? And then just back on the Otway, in your [latest tax release], you were talking about the Sawpit potentially flowing at greater than 25 mean cubic feet a day. Can I just get a bit of a understanding of why you think that in terms of deliverability?

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Matthew V. Kay, Beach Energy Limited - CEO, MD & Director [66]

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I'll just answer Waitsia first, Scott. So look, we are obviously with a joint venture working through the results of that recent well. So I won't make any definitive comments on the right scaling of that plant. But what we would say is given the great results of the last 2 wells, it'd be fair to say that the previous assumptions might have seen an undersized plant. But obviously you've got a balanced market and market timing amongst that as well. So we will have our eyes on potential to scale that project with potential to upsize it.

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [67]

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When we released the 25 million -- greater than 25 million a day number, that was based on the data we collected during the deliverability test. We collected that data to make the decision to go forward to the IPT, which the initial production tests, which we're currently in the middle of, I spoke about that earlier. So based on that, the pressure information that we got and the flow rates and the size of the 2 being, et cetera, then we can comfortably say that the deliverability of the well was greater than 25 million. And now we've got 7 days of dynamic production testing. We'll take that data and the static data that we get when we shut the well in, and we'll come out with some new guidance.

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Scott Ashton, [68]

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And there's no CO2 where that gas would be?

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Jeffrey L. Schrull, Beach Energy Limited - Group Executive of Exploration & Appraisal [69]

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That's one of the good news stories. It was -- the original deliverability test was 6%, I think, and then the rates that we've gotten so far, it looks like it's around 5% which is below -- 5 months back, which will really reduce the processing cost, and yes. And that's one of the risks on the Otway because [Webber Grove], which is the next field over is, I think it was like 35%. But Haselgrove had low CO2 as well, so we're not really that surprised.

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Operator [70]

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There are no further questions. At this time, I would now like to hand the conference back to today's presenters. Please continue.

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Derek Piper, [71]

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Thank you, everyone. Thanks again to everyone for joining the call. Hopefully, that was helpful. Otherwise, we're available for calls for any follow-up questions. So thank you again and have a good day.

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Operator [72]

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Ladies and gentlemen, that does conclude our conference for today. Thank you for participating. You may all disconnect.