Derek Piper - IR Matt Kay - CEO Morné Engelbrecht - CFO Dawn Summers - COO Jeff Schrull - Group Executive Exploration and Appraisal Lee Marshall - Group Executive Corporate Strategy and Commercial

Adam Martin - Morgan Stanley Nik Burns - UBS Ben Wilson - RBC Dale Koenders - Citigroup Andrew Hodge - Macquarie James Bullen - Canaccord Mark Samter - Crédit Suisse James Redfern - Merrill Lynch

Good morning, everyone. Welcome to 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 will be talking through our results for the first half of FY18 this morning as well as touching on the performance of Lattice and also the outlook for the enlarged business. We will then open the lines for Q&A. So, Matt, with that, I will hand over to you for overview.

Thanks, Derek. And welcome everyone to the call. Firstly, some highlights from the half which is set out on slide five. 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 continued to improve profitability and margins. Gross profit of a $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 US$10 a barrel annual increase in oil price would result in our net profit after-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. Operated field costs remained below $4 per boe and the Cooper Basin joint ventures 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 US$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 million to 10.6 million barrels of oil equivalent through to 10.6 million to 11 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 five 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 2019 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 upto $50 million per annum, by end FY 2019. Our financial position and free cash generation, allowed the Board to announce the 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 six highlight further improvements 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 the $155 million of free cash flow from the former Lattice assets. Capital expenditure increased from a relatively low base. However, with the spend directed to projects with highly attractive internal rates of return, first half capital expenditure supported our improved financial results and our upgrades to FY 2018 activity and production. Morné will talk to those results in more detail. Slide seven summarizes operational highlights. As I mentioned, more wells were drilled, success rates are high at greater than 80%, and pleasingly, we have 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 operated gas program continues to deliver great outcomes, with four new Western Flank producers from a six wells drilled. Expansion of Middleton facility, 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 workover 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 FY18 production outlook. For more detail now on the Lattice acquisitions starting with strategy on slide eight. 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 we’ll 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 four 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 nine. Beach’s purpose is to deliver sustainable growth and shareholder value. With the Lattice acquisition complete, we’ve 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 us 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 will be able to reduce net gearing to less than 20% by the end of FY19. 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, results 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 will 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 through the detail in a moment. With significant integration planning completed prior the financial close, we expect to hit the $50 million savings run rate by the end of FY19. I will 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 FY18. 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 three to four 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 repricing or recontracting 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 will 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 will hand over to Morné to discuss our financial results. Morné Engelbrecht: 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 FY18 will include consolidated performance for the new combined group, post acquisition. Slide 13 represents a snapshot of financial highlights for the half and shows further improvement in our profitability as our low cost operating 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 lift installations 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 a $174 million. Another pleasing story is the continued improvement in cost and profitability within the Cooper Basin JV. As we saw last financial year, the Cooper Basin JV has now materially contributed to free cash flow. Despite an extra rig operate in the basin and additional field activity undertaken, the Cooper Basin generated $40 million of free cash flow in the first half. Field operating costs 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 and additional rig. Dawn will provide more detail on the Cooper Basin JV cost savings shortly. Slide 14 sets out various financial metrics. Production and sales volumes were low compared to frequent [ph] half production and sales volumes achieved in the first half of FY17, 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 process. A few points to note. Firstly, statutory NPAT was impacted by $55 million increase in tax expense, after having received an $8 million tax benefit in the prior corresponding period. On the tax side, as noted during the FY17 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 also the expectation for the full year. Recognizing this and adjusting for impairments in the prior period and other ones-off items, underlying NPAT 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 the consolidated balance sheet for the first time with our full year results. We can however provide initial steer on depreciation and amortization for FY19, which we expect will be in the range of $352 million to $450 million. We recognize this is a somewhat broad range, and we 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 in 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 seven-month period, Lattice performed above expectations, and generated free cash flow of approximately $180 million. This flowed to Beach via reduced completion 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 based on 33%, which is below our original 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 our robust balance sheet will be guided by our overall capital management framework, which also provides dividend framework with the overarching priority of creating shareholder value. Our first priority is the reinvestments in our higher return capital programs and further growth strategy over the next three years. Secondly, we are targeting 20% as a net gearing ratio, by the end of FY19, which means we will ensure enough cash is held 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 from EBITDA of $222 million, and free cash flow of $155 million. The average realized sales gas and ethane price $6.12 per gigajoule reflects a weighted average price across the portfolio, capturing a higher price, 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 will now hand over to Dawn to discuss operations in more detail.

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 in lost time injury frequency rate. Over recent years, Beach has achieved these reductions against the backdrop of increasing activity and major projects 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 underpinned all of these results. Looking at Lattice, as these assets were transitioned to Beach, a period which understandably can cause disruption and uncertainty in our team, the focus continued on maintaining safe and reliable operations. For the first half of FY18, the Lattice assets continued to deliver improved HSE performance with one recordable injury and one Tier 1 process safety event which recorded on 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 and offshore capabilities, including production from our Perth, Otway, Bass, and Taranaki basins, offshore operated production installations in the Otway, Bass and Taranaki basins and operated onshore gas processing infrastructure servicing Otway, Bass and 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, and has significantly de-risked portfolio concentration via the five 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 we’ll 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 and the direction of our development and exploration endeavors. Moving to slide 21, this slide provides a summary of our four 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 to right size our organization to drive a cultural of high-performance and continuous improvement; productivity, maximizing production from both our gas and liquids operations through management of the full value chain from reservoir to exports on 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 $50 million by FY19. 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 FY18 full year outlook. We are now guiding towards Cooper Basin production of between 10.6 million and 11 million barrels of oil equivalent, which will continue our recent trend of annual production growth. Successful field development activity for the first half included first 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 on line. Regarding our new producers, we connected wells drilled in FY17 and also recommenced production from a number of the Cooper Basin JV wells following in-wellbore activities. In total, 43 wells were brought on line. And at the end of the first half, a further 25 new wells are awaiting connection. The half also saw a first Western Flank horizontal oil well brought on line. Bauer-26 initially produced at 650 barrels of oil per day; and as Matt mentioned earlier, it increased to 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 are 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 scf a day is under consideration and we will be able to confirm our plans following drilling results from second half. It’s pleasing to report the 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 employees 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 operating model was again evident in our results, including our cash flow breakeven, which was sustained at a world-class level of US$17 per bottle. 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 sustainable position to be in, but the metric does provide comfort and an ability to protect the balance sheet during periods of extreme market dislocations. 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 Mark commented and Morné summarized, 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 for 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 startup of the Halladale-Speculant project and successful completion and startup of the BassGas midlife compression project. Looking forward, our focus will be on driving high productivity and cost saves, [ph] and execution of the E&D program, which are Otway and includes two exploration wells and one 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 for 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 at Beharra Springs deep exploration well, and to drive the Waitsia Phase 2 project, 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 base, 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’ll now hand over to Jeff to talk about the exciting exploration and development program. Jeff?

Thanks, Dawn. Slide 27 is a drilling summary from Beach activities for H1. As we said at the quarter, we had a great first year. The highlight have been the Haselgrove-3 new field. And make this point, new play type, there’s a new deep play that we’ve unlocked at that well, call it 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 strangely perfectly. The test program is ongoing. We will be collecting dynamic and static data for the next three 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 four discoveries. We’re on our way to the 40 million a day project size, sometime in the next financial year. 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 Marauder. We’ve got two appraisal wells planned for the second half of this year, slowly getting our head around the upside potential of 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 know it works, is continuing to pay us. And we’re going to continue to do that in the Cooper Basin. Slide 28, the rest of my talk is going to be mostly focused on what Beach looks like as of today. 2018 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’re in that five 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 our Beharra Springs and Kupe are on the cards, development drilling at Blackwatch, continued development drilling at Cooper Basin and [indiscernible]. 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, the 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 Carnarvon basin that we are 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 timeline shows what a basin development plan looks like for the Otway. At the time of the purchase, Lattice had an option to take four slots in the Diamond Monarch drilling schedule that’s currently go into 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, optimize and add new production. The map shows in red our five producing fields and the two exploration prospects, Enterprise and Artisan that we are 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 in-fill programs are still very much valid and we are excited about them and we are 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. It just doesn’t work for us. It’s 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, Beharra. Beharra Springs deep is a near-term well that we want to drill because we could get production increase in the near future. We have got capacity in that plant. But the crown jewel appraisal in the Perth Basin is Waitsia. In our view Waitsia 3 and 4 are game changers. We found tenuous section that was thicker, more porous, higher term, really good deliverabilities, and in our view that’s sort of a reset button for what -- how this field -- both in terms of the 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 two new wells and we will be coming up with our own development options that we can discuss with the operator going forward. And 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 where obviously Waitsia 3 and 4 did nothing to diminish our enthusiasm. In the -- on slides 32 and 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 approval, we’ll be putting more detailed plans. 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 have identified at Artisan. And Enterprise, Enterprise is an ERD well that we can drill from the shore and hook it very quickly and we’ll be seeking to shorten that timeline to spud an online production as much as we can in the coming months. Blackwatch, Blackwatch will be drilling -- we are planning for FY20, can we get it done earlier, in FY19, we’ll see. The environmental process in Victoria is on exploration [ph] 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 and production as you can find. And Geographe and Thylacine, we’re going to do some sub-surface 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. 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, invariable opportunities at Yolla; there are several that we’ve seen. In Kupe compression, we will monitor the finding of that when it’s most appropriate and also see if we can get away with out-drilling another development well at Kupe depending how the reservoir depletes. So lots of 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 two assets at the moment. Slide 24 and 34, the Perth Basin, as I talked about earlier, it’s about Beharra Springs deep and the jewel that is Waitsia and getting the project size and the field development plan, optimize and get to FID, hopefully in FY18. Lastly but definitely not leastly on slide 35, the Cooper Basin, the very high-margin Cooper Basin, still our highest margin, probably. Western Flank oil, we’re going to continue, like I said earlier, focusing on the Namur McKinlay pools. Bauer-26 is a proof of concept, but it’s not really -- we just drilled four horizontal wells, Santos drilled four horizontal wells at the McKinley field. With almost 3,000 meters of drain, those wells are going to be hooked up between TD and first production in less than three months. So, the program they did there is very -- almost analogous to this 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’s a lot of oil to recover on the Western Flank. The Birkhead, there’s exploration and appraisal. As I mentioned, we’re appraising Marauder with [indiscernible] 6 well is drilling as we speak and it’s going to be our first 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 in these Birkhead horizontal wells. The Western Flank gas, we continue to drill up our Southwest Patchawarra play fairway inventory. We’ve got six more wells planned this financial year. Spondylus, the final survey comes in, in May, then we’ll -- the plan is to replenish that Southwest Patch proven play inventory with six or seven drills. The Permian Edge play is the high upside exploration potential, basically the Permian Edge pension out on to the Western Flank, creates a potential huge stratigraphic trap. We’ve drilled one well that we had showed. Unfortunately we didn’t have good reservoir quality. And after [indiscernible] the rig is going to go to PEL 630 with our partner Bridgeport and drill Lady Bay and [indiscernible], which are Permian Edge exploration wells. So one of those -- we’ll be talking about much and 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 a wealth of inventory, near field appraisal development, drilling, they’re applying these horizontal drilling techniques that are working and giving us production, exceeding our production targets both gas and oil. But, we do have some exploration drilling coming up in the second half. These four or five risky, high potential exploration wells, one is going to test Innamincka down flank, which is a similar to the Permian Edge play fairway, but a little -- in Queensland on the Innamincka down side. 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 down 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 joint tams 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 two. I’ll turn it over to Lee.

Thanks, Jeff. Good morning, everyone. If we start with Eastern Australia, on slide 37, a story, I’m sure you’re all familiar with. We now have the gas [technical difficulty] domestic use and 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 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 the forecast supply deficits in 2018 and 2019. Beyond these undeveloped 2P reserves, it can be seen that still a significant supply gap where contingent resources that are currently considered to be on commercial, 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 three basins servicing this market. On to slide 38. This slide makes two important points. Firstly, is due to price reopen as in contract expires, we have excellent near-term exposure to East Coast market pricing in a market when fundamentals are strong and [technical difficulty] Secondly, having two of these pricing resets, our current gas supplier arrangements remain attractive and are delivering excellent results. On the first point, the chart shows 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 eventually as a sum of our annual contract quantities, and the floating columns to the right illustrate how this total volume is exposed to market re-pricing over the next two years, either due to market price review provisions in the gas sales agreements or due to expiry of agreements and sales. You can see that by 2020, around one-third of our existing East Coast prices will have been reset market prices, and by 2021, roughly 78% will be reset. So, most of our sales would 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 gigajoule and we brought AEMO forecast in a gas supply deficit this year and next and as we saw in 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 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 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 by AEMO. Forecast indicates that based on declining domestic gas production and indicative LNG producer domestic gas requirements that potential supply gap emerges as early as 2021. We expect at 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 of 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’re extremely excited about our gas position in future. Liquids still remain a very important contributor to Beach’s current performance. For this recent half year, liquids contributed over half of our pro forma sales revenue with crude oil revenue fully 40% of bids. In terms of bottom-line impact, we estimate a US$10 per barrel increase in oil results in roughly $65 million increase to NPAT and $70 million increase in operating cash flow. I will now hand back over to Matt.

Thanks, Lee. Hopefully you’ve seen we’ve got a lot more information to provide as we 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 am going to hand over now for the questions, if we can.

[Operator Instructions] Your first question comes from the line of Adam Martin from Morgan Stanley. Please ask your question.

Good morning. I was hoping if you could spend a bit of time just talking about the Otway farm down. Clearly, you’ve 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?

Sure, Adam. Look, we’ve signaled this quite early. We said once we’d acquired the Lattice assets, 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 pretty unusual place to be in terms of a weighting 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 locked that model. And we think having another party there working with us is the right way to go forward.

Okay. And just in terms of the production profile for asset, clearly, you’ve moved out some of the original development appraisals that originally planned. How should we think about production from that asset for next two to three years? Do you think sort of rough decline from current levels, over the past 12 to 18 months.

Definitely not for two to three years. I mean, we have some low risk development activities that we are going to be getting after as soon as we can. But, development well at Blackwatch and the onshore compression near the ERD wells, the exploration wells, if they’re successful, could come on stream within three to four years. Artisan, the Enterprise well, like I said, is an ERD well and there’s a pipeline that goes to the Otway plant that it can hook into. So, give us a bit of time and let us get the timing of all of 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 the asset. That gap between the actual appraisal drilling at Thylacine and the actual drilling of the development wells which was a few years originally, but 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 Geographe and Thylacine on roughly the times -- the same timeframe.

And what about the production from the existing wells, so, I’ll 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?

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’ll be looking to optimize our existing facilities and also our cash generation from there. And together with, Jeff, as we develop like the near-term development opportunities and understand what decisions we need to make with regards to the right investment choices for the field.

Okay, all. It’s very good. Thank you. That’s all for me.

Just to close out, Adam, and I think we’ve touched on it at the quarterly, the one point I would make is this is all about value optimization. So, I wouldn’t infer that any deferral or any CapEx is diminishing value; it’s quietly opposite. So when we’re deferring CapEx or switching to lower unit technical cost opportunities is to enhance really, not the opposite.

Actually what I’m trying to understand is what’s the cash flow coming through the Otway in the next two years. And part of that I understand is production profile as well. So, you’re deferring the CapEx but I also want to understand what is the production profile. But that’s all good.

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

Thanks, Matt and team. Just a question, maybe a high level one on the Lattice acquisition. At the time of the acquisition, you sort of outlined the 2P reserves you were requiring, I guess in the same context of what Adam was talking about. But just now you’ve had an opportunity to take a good look at what you’ve acquired with clearly seen some positive news on Waitsia since the deal was first announced. But on the rest of the assets is -- are you able 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?

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 or negative news flow or anything we didn’t previously understand before the acquisition. So, we did the lot of [indiscernible] the markets aware 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 under the hood that’s been a negative surprise, quietly opposite. What we’re seeing is positive opportunities and certainly that was part of the reason we came out quickly with the increase and 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 assets, they believe the same.

Okay. That’s clear. And just on the plan to sell down Otway, you’ve targeted 30%. Just wondering why that number, why you feel that’s the right number there. And 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 sell process there, just to give the potential buyer some clarity as what your long-term plans are there?

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 the 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 strategic partners as well. So, it’s really a guidance number at the moment, but you’re right, we would definitely have the new plans in front of the market as part of that process.

Okay. Nik, this is Jeff. Between just remaining bidder and closing, we’ve put an incredible amount of technical resources getting ready for this process. As I said, the enterprise 3D survey is just literally the interpretations out of the press that we’ve seen this coming and we know technically we need to talk to whoever our partner is going to be about how we want to approach this.

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 the cash tax, just in the context of Lattice acquisition. Were there any tax losses they can use to offset any Beach cash tax payments, et cetera? MornéEngelbrecht: Just in terms of making some of the tax payments for Beach standalone, we paid $6 million tax payment in January, which was provided for pay FY17 and then we’ve 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’s no losses coming over. So, again just using the 30% effective tax rate should get you there.

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

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 pro rating that Cooper $40 million free cash flow. I get to somewhere north of $200 million bucks 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? Morné Engelbrecht: In terms of our definition we’ve used, I mean, it’s obviously the operating cash flow minus any capital expenditure. So, happy to talk to you afterwards just to reconcile your numbers with ours on that.

Okay. Just a straight sum of those as assets that you listed there? Morné Engelbrecht: Yes.

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

Good morning, guys. Just wondering on your cost out program, is that all OpEx or is that, I guess within your $50 million number also CapEx interest cost, tax efficiency, D&A, et cetera?

That’s OpEx. Dale, it’s basically pure cash OpEx as well.

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

We do and part of that is obviously the Otway program that Jeff has been talking to, 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 operations?

I think back to Matt’s point earlier in regards to making sure that we make the right choice where we invest our capital for the right return. And to Jeff’s point around ensuring that we look at the full field development fund for each of the asset, we’re going to do full bottoms up for our each assets and make sure make the right decisions at the right time. Jeff?

I think, 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? I think there’s an opportunity to approach drilling in a way that 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 our capital reduction program.

Then, when we think about the $140 million to $170 million pro forma CapEx and apply to Lattice asset on a go forward basis, it looks like an increased work program. Should we be thinking about that number increasing, staying the same, could you drive some cost out or what do you think…

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 some volatility, as you know, dependent on the work programs. So, I think once we come out with the detailed work programs, then, we’ll give you more guidance on capital movements.

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

Yes.

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

Thanks, guys. I’ve’ just got three questions. And the first one is, the volume do you think that will be still contracted post ‘21, I just wanted to check does that mean that you are seeing that Origin extends the right for their eight-year GSA for another couple of years?

Are you referring to the oil [ph] contract there, Andrew? Could you repeat the question please?

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

The option, I’m trying to get it. Let me just tell you the chart to see if that answer it. So, if it is price review provisions under the gas sales agreement and contract expiries, so after 2021, that 78% of the portfolio, the residual 22% is -- the contract expires in 2025, and there’s no price reopening up before then. I’m not sure that answers it. Perhaps, if you want to clarify a bit further?

We can catch up offline. The second then is that I was just trying to understand a little bit more about Otway since about sort of half the reserves did involve [ph] in Geographe and are undeveloped and you’ve kind of pushed that out. I guess, I would just like to get a little bit more -- and it seems like you’re banking a lot of Haselgrove in the near-term to stop the declines. Can you give a little bit of 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 had mentioned before about you weren’t really excited about some of the exploration stuff, Jeff. But, I thought [indiscernible] that you guys have to do that under the requirements Origin had. And so, I just wanted to understand, in fact, one of them I think you had to drill by September this year. So, just wanted to work out what you guys have to do there. And then, I guess, with Dombey as well, just to try and understand about, is it just basically you guys are pushing exploration to try and offset undeveloped reserves?

So, start with Haselgrove-3, we haven’t made any comments about production rates or any field development and something going forward. We’re still testing the well. Dombey is a follow-up well, it’s a good well. We applied for and received a pace grant, so that which obviously helps the economics for exploration ventures. So, that’s the onshore Otway SA, half part of the question, the reserves at Thylacine and Geographe are still 2P undeveloped reserves at 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 Artisan and Enterprise now, but the [indiscernible] 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 six weeks to eight 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 final risk or sizes, but we will be with potential partner. We will definitely put together a full field development plan for the fields. Geographe, we already have one for Blackwatch that that well has been designed and is planned. For Geographe and Thylacine, we will 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 a drilling an appraisal well and P&A 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 hook up, 2.5 or 3 years is just too long to have $100 million sitting on the table, just doesn’t. And I’ve worked on the fields all over the world where that’s been done. So, I know it’s doable, but I guess Origin just had a very -- or Lattice had a very conservative view, which is fine of how they want us to approach it. I guess, we’d take a more balanced basin-wide view and the T30P Murchison that we’ll be talking with the government about management of our permit obligations in the coming months.

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

Let me clarify that. Because we’re -- Haselgrove is in existing fields and it’s only less than a kilometer and a half on old Katnook gas processing facility. And so, the cycle time of getting this one well hooked up could be quite low. And there will be a local market demand. So, Haselgrove could go forward. I’m not saying it will, go forward as a small one well hookup base 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 2019 is -- we feel, it’s definitely possible, we’ve got a project schedule, if we decide to go that route, but it would be just a small one well hook up of this one producer.

Your next question comes from the line of James Bullen from Canaccord. Please ask your question.

Hi, guys. Just a quick question around the organizational structure and your shift towards a more functional organization. Obviously, some of your peer groups have started to move away from functional to more asset base. So, I’m just looking for a couple of quick comments as to why you think that this is right direction now for Beach? Morné Engelbrecht: Yes. James, it’s 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, I’m not sure there will be, so, the connectivity across the assets into those functions to make sure that there’s accountability and empowerment. So one of the key things we’re working through as the nee team is accountability 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 is under functional models or what’s under cross-functional metrics is, 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 in the game.

Great. Thanks very much. Just a question to Jeff. Obviously, you’re pretty excited about what happened at the Haselgrove, and you’re talking about the potential of 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 than the prospectivity over the border?

I’m looking at our Legal Counsel. I’m not sure I can answer that. PEP 171 was considered non-material part of our portfolio. So, we relinquished it.

Okay.

Your next question comes from the line of Mark Samter from Crédit Suisse. Please ask your question.

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 orange block is Queens in CSG and we look at orange box, what happened on some of that more on certain lower quality CSG. Your real exposures to take through this presentation, your real exposure at the moment portfolio-wise is much more around the price uptick rather than volumes. Your gear is going to be sub-20% in a year’s time, say. Do you think there is scope to target inorganic opportunities on the East Coast in particular?

Hi, 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 are really focused on getting the value out of the Lattice assets. However, there are other bolt-on opportunities and there are other opportunities in various basins that we continue to look at, just at the moment we’ll list out from something the size and scale of a Lattice type opportunity.

Then just a quick question following on the question on Lattice reserves, I could be wrong on this. But I would have always assumed that Origin, when they test Lattice reserves, didn’t assume that step up to market prices. I mean, it’s pretty clear from this presentation where the Beach is and where market process are going, I mean intuitively to me that says you can be testing lighter life reserves or watching contingent resource at the moment and Lattice on a materially higher price deck [ph] than probably Origin were. Is that a fair assertion?

I can’t really comment on what Origin has done in the past, nor am I actually aware of what they’ve done in the past. What I would say is when we do our reserve 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 is now low cost and high margin. And so, it’s pretty rare that we’re 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.

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

I just wanted to touch on the Waitsia project. Obviously, Waitsia 3 and 4 has been very strong, and talking about design potentially in excess of [indiscernible]. Just want to get some comments around the WA gas market in terms of what you’re seeing, in terms of pricing? Would you comment on the progress in terms of the GSAs being signed because it’s year been a year since the AGO was signed for 15 [indiscernible] day, just want to get update on that? And then obviously you’re reworking the projects, FIDs moving into what was, six months away? Thank you.

Thanks, James. Just in terms of the WA market, certainly right now, if you look at the spot market in WA, it’s a broad 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 that still obviously we’re relatively new in terms of having hands on the asset, we’re really pleased, as Jeff’s pointed out, of those last two wells. Waitsia is an asset we’ve had our eyes on for a very long time. And I guess the surprise, there was increase in reserves was not a surprise to us but certainly the deliverability of those last two wells is a great surprise for us. So, we are 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’ve said previously, we’re keeping our eyes on that and making sure that Beach’s position is protected.

Thanks. And just what about progress in terms of signs in GSAs? Is it still sort of quite active [ph] and where do you see the gas going, is it still the Perth retail market or is it potentially north -- to some of the industrial customers out there? Thanks.

Certainly nothing to announce at the moment around GSAs .What I would say is, we’re 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 north or goes elsewhere or ends up being in LNG or swaps or whatever it is. So we’re open to all alternatives. It’s about the value that we can create from the resource.

Your next question comes from the line of Scott Ashton from Shaw Energy Consulting. [Ph] Please ask your question.

Jeff, just two exploration question just on slide 13, just on the back of James’s question. With respect to Waitsia, should you be thinking that maximizing improving Waitsia, you’re looking sort of 120, 153 J as a potential scenario? And then, just back on the Otway, in your ASX release, you were talking about the Sawpit potentially flowing at greater than 25 million cubic feet a day. Can I just get a bit of an understanding of why you think that in terms of deliverability?

I’ll just answer Waitsia first, Scott. So, look, we are obviously, with the joint venture, working through the results of that recent well, so won’t make any definitive comments on the right scaling of that plant. But we would say is given the great results of the last two wells, it’d be fair to say that the previous assumptions might have seen an undesired plant, [ph] 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 and potential to upsize it.

When we released the $25 million, greater than $25 million a day number that was based on the data that 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 earlier. So, based on the personal information that we got in the flow rates and the size of the two being, et cetera, then we could comfortably say that deliverability of the well was greater than 25. And now, we’ve got seven days of dynamic production testing, we’ll take that data and the static data that we get when we shut the well, and we’ll come out some new guidance.

And there is no CO2 in that gas there?

That’s one of the good new stories. That original deliverability test was 6% I think. And 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 costs. And that’s one of the risks on the Otway, because Ladbroke 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.

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

Thanks again to everyone for joining the call. I believe that was helpful. As always, we are available for calls for any follow-up questions. So, thank you again and have a good day.