Derek Piper - Investor Relations Manage Matthew Kay - Chief Executive Officer Peter Sandery - Acting Chief Financial Officer Michael Dodd - Group Executive Exploration and Development

Mark Samter - Credit Suisse Dale Koenders - Citigroup Adam Martin - Morgan Stanley Nik Burns - UBS James Redfern - Merrill Lynch Andrew Hodge - Macquarie Securities

Ladies and gentlemen, thank you for standing by and welcome to the Beach Energy Limited FY 2016 full-year results presentation. At this time all participants are in a listen-only mode. Following the presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that this conference is being recorded today, Monday, the 29th of August 2016. I would now like to hand the conference over to your speaker, Mr. Derek Piper, Investor Relations Manager at Beach Energy. Thank you. Please go ahead.

Thank you, Eva, and good morning, everyone. Welcome to the call. This morning Beach released its results for the financial year ended 30 June 2016, as well as an accompanying presentation, and we will be speaking to that presentation throughout the call this morning. With me is Matt Kay, our Chief Executive Officer; Peter Sandery, Acting Chief Financial Officer; Mike Dodd, Group Executive Exploration and Development; and other members of the Executive and Management team. As well as an overview of the results, we will also touch on the outlook for FY 2017 and then we will have our usual Q&A session. So with that, I will hand over to Matt to talk through the highlights.

Thanks, Derek, and welcome, everyone, to the call. Financial year 2016 has been a successful one for Beach Energy, and FY 2017 promises even more, and we look forward to sharing that with you today. Starting with Slide 4, I’ve listed a few reflections of my first four months of leading Beach. It’s clear to me that the company presents a compelling proposition for our investors. We have a profitable base business with an enviable break-even cash flow of only US$26 per barrel, down more than 60% from previous year. The strength of our financial position was clear this morning when we announced our 15th year of consecutive dividends. We have reshaped our business to be resilient at lower oil prices and we are also one of the most highly leveraged stocks in the market for an oil price recovery. Our cost savings have been material, not only at Beach, but also in our Cooper Basin joint ventures, and we have targets of further cost reductions beyond 15%. We had a successful year with a drill bit in FY 2016, and I’m very pleased that we’re drilling 13 development and exploration wells on our operated facilities this year. We will continue to grow our business. Given our financial position of zero net debt, we also continue to focus on inorganic growth opportunities, those that fit with our strategy and present similar risk profiles to our base business. We are active, we are disciplined, and we’re prepared to wait for the right opportunity that creates shareholder value. In short, Beach Energy is in great shape. Turning to Slide 5, this demonstrates the strong progress we’ve made across the year on all of our strategic pillars. I will touch on a few highlights. The merger with Drillsearch has strengthened our core business and integration of operations was completed seamlessly and ahead of schedule. We are now ready to benefit from the A$40 million of annual associated cost savings in FY 2017. Costs were actively reduced across our business, and this included a 26% reduction in operated fuel costs, and we have further material reductions expected in the coming year. Financially, we are net debt free. We had no further write-downs in the second-half of FY 2016, and our robust business case generated another A$28 million in cash reserves over the course of the year. We will also highlight today that FY 2016 show the commencement of our gas contract with Origin Energy on attractive terms. That, along with the greater influence that Beach now has over the South Australian Cooper Base and joint venture outcomes means that Beach is not labored by sub-economic activities in relation to Cooper Basin gas. We also progressed our review of growth opportunities and we have a new approach to diligence and screening of those opportunities. Again, we are disciplined and patient in our approach. Later this morning, you will hear that Beach has elected to write-down its contingent resource associated with Nappamerri Trough Natural Gas project. This is an example of our diligent approach to technical and commercial assessments and our rigorous approach to our business decisions. To summarize, despite the market challenges, Beach has made very good progress on its strategy in FY 2016. Turning now to Slide 6, I will let Mike to talk to some of the operations in more detail, but there is a few highlights to note. These include, firstly, we delivered record production of 9.7 million barrels of oil equivalent, supported by facility installations and our development projects. Our drilling success rate was 90%. This included a 75% success rate for our exploration wells. Despite that activity and our record production, we also delivered significant cost reductions. As mentioned earlier, our cash flow break-even is now US$26 per barrel. This was delivered through reducing our costs in our own business, but also a reflection of our influence over the Cooper Base and joint venture capital expenditures. We will come back to these in more detail later. Moving to Slide 7, I know we’ve spoken about this previously, so I won’t labor the point. The Drillsearch merger has been successful for our business. Our key message today is that the merger is now entirely completed and behind us. We intend to deliver the A$40 million of annual synergies in FY 2017 and benefit from 100% ownership of the Western Flank assets, providing us again with greater leverage to an oil price recovery. I would also highlight that the successful execution and integration of dual search demonstrates our ability to successfully deliver in organic growth to our shareholders. Peter will talk later to our financials in more detail, but Slide 8 provides us with a few key highlights. Despite a further downturn in oil prices being a 33% reduction in our Aussie dollar realized oil price, our business still recorded an underlying profit of A$36 million and generated A$233 million of operating cash flow. We proactively managed and reduced our capital expenditure, which helped increase our cash reserves by A$28 million. Recognizing this performance and the strength of our financial position, the Board has declared a A$0.005 fully franked dividend. The dividend demonstrates our confidence in Beach’s outlook and our focus on total shareholder returns. Pleasingly, the dividend extends our run of consecutive payments to 15 years. As you can see, Beach is a company that is resilient to commodity cycles and has an enviable financial position. I will now hand over to Peter to talk through the numbers.

Thanks, Matt, and good morning, everyone. Whilst it has been another challenging year for Beach with a further significant decline in the oil price, Beach has performed strongly in the second-half of FY 2016, particularly with the benefit of full ownership of PEL 91 and PEL 106 following the successful merger with Drillsearch completed on 1 March 2016. Looking at the key financials for the year on Slide 10, sales volumes for FY 2016 were a record 10.8 million barrels of oil equivalent due to higher oil sales with full ownership of PEL 91 and increased gas sales. Sales revenue was lower, reflecting the drop in oil prices compared to the previous year. Despite this fall in sales revenue, operating cash flow improved 2% with lower tax payments and operating costs offsetting the fall in sales. The net loss after tax increased, even though pre-tax impairment charges were lower with deferred tax assets on impairment no longer being recognized in full due to the uncertainty of utilization. Underlying profit after tax has also declined with a fall in oil price and Beach has increased its cash balance by A$28 million to A$199 million at year end, reflecting the strong underlying operating cash flow being generated by the business along with its disciplined approach to capital expenditure and focus on reducing operating and corporate costs. Beach’s net cash position has more than doubled from A$22 million at June 2015 to A$53 million at June 2016. And despite the difficult operating environment, Beach is pleased to be able to reward its shareholders, including new shareholders following the merger with Drillsearch with a A$0.005 per share fully franked dividend, which will be Beach’s 15th consecutive year of dividend payments to shareholders since 2002. Turning to Slide 11, you can see the drivers behind the movement in sales revenue for FY 2016. Lower oil and liquids prices and lower third-party sales volumes in FY 2016 contributed to a 23% fall in sales revenue to A$558 million. Although this was offset in part by higher sales volumes of oil and gas from higher production with full ownership of PEL 91 and a greater volume of oil in the sales mix, a lower average exchange rate and higher gas and ethane prices with the first year under the long-term gas sales agreement with Origin retail. In total, sales revenue from production decreased by A$106 million and third-party sales decreased by A$64 million, although this was more than offset by a reduction in third-party purchases. Turning to Slide 12, by adjusting FY 2016 NPAT to exclude impairment and non-recurring items, underlying NPAT was A$36 million, which was down 61% on FY 2015, mainly due to lower oil prices. Whilst pre-tax impairments charges were lower in FY 2016, credit to tax expense is much less than 30%, as it was not probable in the current environment that Beach would realize this asset in the foreseeable future. And so with Beach now in a net deferred tax asset position, further timing differences on tax are no longer being recognized. Other items added back in FY 2016 were A$8 million of Drillsearch merger costs, A$15 million of unrealized hedging losses, and A$8 million for non-recovery of international taxes, which was recognized back in December 2015. Turning to Slide 13, as the graph shows, underlying NPAT has fallen again to the further 33% decline in the Australian dollar oil price year-on-year. Pleasingly, our underlying NPAT has tripled to A$27 million in the second-half of FY 2016 compared to only A$9 million in the second-half, notwithstanding lower oil prices in this period. This reflects the benefits of the Drillsearch merger, including additional earnings from full ownership of PEL 91 and other producing assets, lower depreciation and amortization with a flow through of impairment charges from second-half FY 2016 and our continued focus on reducing operating and corporate costs. Turning to Slide 14, Beach generated a strong operating cash flow of A$233 million for FY 2016, a A$4 million improvement on FY 2015 with lower tax payments and operating costs more than offsetting the fall in sales revenue. Beach’s combined net cash inflow from operating and investing activities adjusted for discretionary capital tax payments and cash acquired through the Drillsearch merger was A$128 million or A$25 per barrel. Taking this off, our realized oil price for the year of A$60, gives us a cash break-even price of A$35 a barrel, which is 60% lower than FY 2015, due to reduced capital expenditure and other costs. With Beach’s focus on capital allocation and ensuring that discretionary expenditure was limited to those projects with the most attractive returns, Beach was able to increase its cash reserves by A$28 million to A$199 million at year end. Combining this cash with A$350 million of undrawn debt facilities gives Beach around A$550 million of available liquidity at 30 June, placing the company in a strong position as we move to FY 2017. I will now handover to Mike to provide you with a more detailed review of operational performance for FY 2016.

Thanks, Peter, and good morning, everyone. Our production results are set out on Slide 16. As mentioned, it was a record year at 9.7 million barrels of oil equivalent and net to Beach, thanks to increased oil production and sustained levels of gas production. The Drillsearch merger provided four months of incremental production and we had 22 – 21 new oils wells and 25 new gas wells come online during the year. Our teams in the field worked diligently to deliver a range of development and optimization projects which contributed to our local production. Projects of note include the Stunsail and Pennington production facilities, which provide Beach with an additional capacity of 40,000 barrels of fluid a day. Artificial lift installations, which use variable speed technology, these were low CapEx projects, which provided immediate incremental production from more mature wells, and various optimization projects, such as, flow line reconfigurations, successful drag reducing agent trials to enable higher throughput and thus less reliance on trucking. Briefly on Slide 17, as I mentioned, higher oil production and sustained levels of gas production underpinned our results. I would just note that Egypt figures reflect a full year of production, which Beach received the benefit of. As we announced earlier this month, we have completed our exit from Egypt and there is no production included in our FY 2017. Turning to Slide 18, we were less active with the drill bit in FY 2016, but our success rates remained high with a number of high impact outcomes. The Windorah Trough gas program in Queensland was a standout. Five new well – new field discoveries redefined the prospectivity within this area. We also installed infrastructure allowing connection of previously stranded fields and providing a pipeline network for future discoveries. We were also successful with the development of a higher margin, liquids rich Tirrawarra and Gooranie fields and alternate drilling techniques helped to accelerate production from low pressure reservoirs in the Moomba South field. Assets in these fields will continue into FY 2017. Slide 19, provides a snapshot of our reserve and resource position at 30th of June, which we announced today. Of note, this year was a thorough assessment of permit interests acquired as part of the Drillsearch merger, and these have added 11 million barrels of 2P oil and gas reserves. We have a solid 2P reserve base with an active exploration program this year. We are well-placed to improve our rate of reserves replacement in the coming years. We have elected to reduce our contingent resources of our operated unconventional gas acreage in the Nappamerri Trough to zero. This follows completion of the Nappamerri Trough stage 1 exploration program and a review of the results of that program. The results demonstrated that the high-cost of addressing fundamental technical issues means that the Nappamerri Trough natural gas project is unlikely to be developed commercially in the medium-term. We are currently assessing our strategy for managing that acreage at minimal cost. That covers the key operational highlights. So I’ll hand back to Matt now to touch on the outlook for FY 2017.

Thanks, Mike. Just moving to Slide 21, everybody, firstly, I would like to touch on a few strategic themes, which have guided our planning for FY 2017 and beyond. Slide 21 shows what I’m sure will be a familiar chart for most of you. The outlook for East Coast gas supply and demand and a long spoken of gas shortage, which is approaching. The East Coast gas debate continues and is becoming noticeably more urgent. Outcomes from the recent COAG meeting and subsequent commentary are evidence of agreement for the need to drive change. Beach is actively part of those discussions with industry, government and customers and fortunately Beach is well-positioned. We are part owner of the Moomba gas processing facility and associated infrastructure. A newly established Moomba trading hub recognizes the strategic importance of those assets. And in FY 2017, we will continue to work with our operator, Santos, to ensure we maximize returns from those assets. The Moomba plant has spare capacity and is available for new molecules and transportation of gas supply. Beyond infrastructure, our gas business is well-established. We are now marketing our own molecules and have significantly more control over our capital expenditure. We are also actively assessing our own exploration portfolio and growth opportunities to supplement the supply of this shortfall. On the subject of East Australian gas, that leads us nicely into Slide 22. The last two years have seen a number of changes to the operating arrangements of the South Australian Cooper Basin and South West Queensland joint ventures, which we also refer to as our Delhi operations. Separate gas lifting, separate marketing, and an ability to opt out of most drilling campaigns are the key enhancements for Beach. So far, these changes have delivered, firstly, higher gas pricing and improved returns following the initiation of Beach’s oil-linked gas sales to Origin with attractive terms and conditions. Secondly, a 35% reduction in capital expenditure by Beach in the SA Cooper Basin in FY 2017. Thirdly, initial evidence of cost reductions from close collaboration with Santos with material reductions appearing and expected in FY 2017. We believe these will be in excess of 15%, but it’s too early to give it a definitive range. And lastly, as mentioned earlier, a 65% reduction in Beach’s overall cash flow break-even to US$26 a barrel driven by costs out and reduced Delhi capital commitments. So the joint venture is greatly enhanced as a value proposition for Beach considering where it has been in the past. And we believe the future outlook for Delhi is even better. Briefly on Slide 23, not only is Beach resilient in a world of oil price decline, but we are very well-positioned to benefit from a recovery in oil prices. We are a leading Australian oil producer with oil-linked gas sales and our healthy balance sheet allows us to continue exploration and pursuit of growth opportunities. Our upside sensitivity to oil price is material. We calculate on a US$10 per barrel increase in average oil price would lead to an additional A$65 million of free cash flow or A$50 million increase in net profit to Beach. Conversely, our low cash flow break-even mitigates the impact of any future oil price shocks. Across the industry, operating efficiencies and cost reductions are front of mind and Beach has made great progress in this regard. Slide 24 outlines that progress for FY 2016. Our cash flow break-even costs across the business have decreased by 65%, as I mentioned, to US$26 a barrel. We achieved operating cost savings in the order of 25% within our own operated Western Flank permits due to a broad range of activities. Our drilling costs reduced by 10%, and we expect a similar further reduction in FY 2017. It’s important to note that these reductions were achieved with safety front of mind. We achieved improvements in safety performance during FY 2016, our recordable incident rate reduced by 76%. So I’m sure you can see from this slide why Beach has been has been generating cash reserves in FY 2016. Slide 25, again highlights our corporate savings and those through the combined Beach Drillsearch merger. We’ve reduced our combined Beach Drillsearch overheads by 57% compared from FY 2017 to FY 2015. I know we’ve talked about this at length previously. So I will now handover to Mike, who will cover the operations and look forward for exploration for FY 2017.

Thanks, Matt. So, firstly, to production on Slide 27 summarizes our FY 2017 guidance that we released last month. We are confident of exceeding FY 2016’s record level and expect to produce between 9.7 million and 10.3 million barrels of oil equivalent. We’ve been talking for sometime now about the impending field decline from our Western Flank oilfields. This will be evident this year, but it’s long been expected and planned for, we’ll talk about one of the mitigants in the next slide. As such, the development projects to be undertaken and an additional project from former Drillsearch permit interests will be more than sufficient to offset the impact of natural field decline in FY 2017 and improve on FY 2016 production volumes. I also note that no additional production from FY 2017 exploration success was factored into our guidance. This leaves potential upside if we have success in that exploration program and we can connect those wells this year. Turning to the development projects in a little bit more detail on Slide 28, this describes our Bauer facility expansion and Middleton gas compression projects. These projects are being undertaken to enhance production of our oil and gas fields and, in doing so, provide additional production capacity for any new discoveries and artificial lift projects. Regarding our Namur, our oil fields, it’s important to note that these are long-life producing reservoirs. The rate of decline seen in FY 2017 is a perfect storm of the biggest field, Bauer, nearing full development, and FY 2016 being a year of lower than usual activity, meaning there are fewer than usual projects to bring online during FY 2017. Post this year with more Western Flank projects in FY 2017 and a renewed exploration program, less dramatic drop-offs would be expected in the future. Turning to our capital expenditure program, Slide 29 reiterates our FY 2017 guidance released last month. While our capital expenditure is broadly in line with FY 2016, it’s important to emphasize that our revised rigorous approach to capital allocation coupled with a greater control over our SACB joint venture expenditure, we’ll see a larger proportion of discretionary spend, which is being directed to high- impact, high-expected return projects. Over two thirds of our discretionary projects have an expected risk-weighted internal rate of return in excess of 30%. Slide 30 outlines our operated drilling program. Reduced activity in FY 2016 afforded us the benefit of time, and we used this time to review our seriatim of prospects and leads and complete an extensive regional study. The outcomes from these activities are reflected in an exciting FY 2017 program, which has a heavier focus on exploration and a diversity of play types. Our 13 operated wells for FY 2017 provide a balanced mix between development drilling, near-field exploration, and a new focus on both the Birkhead and Patchawarra play types, which I’ll touch on in a moment. The underlying objective of our FY 2017 program is to pursue what we consider are the best prospects for material fault line drilling, as well as projects located for rapid connection and monetization. For your reference, Slide 31 sets out well-by-well details of our operated program. The well, which excites our team the most this year is Kangaroo-1 expected to spud in September. Slide 32 provides an overview. The well is targeting the Birkhead formation, which is underexplored within our operated permit, but has proven success in nearby areas. The Birkhead formation presents a different type of target to our usual Western Flank Namur reservoirs. The Birkhead is a channel sand formation and the reservoir is much less aerially extensive. The wells tend to flow at lower rates, but can produce hundreds of barrels a day consistently for many years. Our application of seismic inversion techniques to high-quality 3D seismic means that we can now identify those channels with a level of confidence. Success at Kangaroo-1 has the potential to redefine the prospectivity across our operated Western Flank permits, helping to derisk areas identified for follow-up exploration. We have already identified multiple follow-on targets in the event of success. I’ll now hand back to Matt for one last time to close out the presentation.

Thanks, Mike. Two final points to touch on our portfolio rationalization and inorganic growth. We’ve made solid progress divesting assets, which we deem as non-core or poor performing. Slide 33 sets out some recent announcements. The Kenmore-Bodalla sale was an example of an asset of modest value that was remote from our other operations and therefore, had a high operating cost structure and end-of-life liabilities approaching. Releasing this acreage has mitigated those cash commitments and liabilities and directed more focus back onto our core business. We’re also very pleased to complete the Egypt exit with cash proceeds of approximately $20 million. Rationalization efforts are ongoing and we expect to announce further progress during FY 2017. Turning to Slide 34. We’ve spoken recently of inorganic growth and the rigorous framework now in place to assess these opportunities. There are a few rule sets to highlight here. Firstly, any inorganic growth that we consider will be in line with strategy and with risk profiles not dissimilar to our Australian operations. Secondly, we have revised our approach to due diligence, risk assessment, and screening criteria with very strict stage gates in place. Thirdly, while we are active in this space, our base business is performing very well and we are prepared to wait for the right opportunities. Lastly, management has a disciplined approach. We are not incentivized to close deals and we’ve already actively dismissed a number of deals that do not create the required returns to shareholders. In short, unless there is a clear path to shareholder value creation, opportunities will not be progressed. So let’s close with Slide 35 and go back to where we began. I’m very excited by the opportunity that Beach presents, not only for our team, but also for our investors. The business is in great shape. Let’s recap. We have a profitable base business with an enviable break-even cash flow of US$26 per barrel, down more than 60% on the previous year. Given the strength of our financial position, we’ve been able to announce our 15th year of consecutive dividends. We have reshaped our business to be resilient at low oil prices and we are also one of the most highly leveraged stocks in the market for an oil price recovery. Our costs savings have been material, not only at Beach, but also in our Cooper Basin joint ventures, where we have significant influence and we have targets of further cost reductions beyond 15%. We had a highly successful year with a drill bit in FY 2016, and we’re currently drilling 13 development exploration wells this year on our operated facilities, close to facilities, where we can grow our business in the near term. Given our financial position of zero net debt and cash generation of our business, we also continue to focus on inorganic growth opportunities, but only those that fit our strategy and present similar risk profiles to our base business. We are active, we are disciplined, and we are happy to wait patiently for the right deal that creates shareholder value. In short, Beach Energy is very well-positioned for future growth in shareholder value. That concludes the presentation. So if there is any questions, we’ll now open the line for Q&A.

Thank you. [Operator Instructions] Your first question comes from the line of Mark Samter from Credit Suisse. Please ask your question.

Yes, morning guys. Matt, you obviously spoke about the situation on the East Coast gas market. I’ve got to say, I almost fell off my chair last week when I read the APA transcript from their results, but I’m going to quote them. They said, one thing does appear to be certain, they were all finally in an agreement that there is sufficient gas forecast to be produced to satisfy, both LNG and domestic demand. So there was no gas crisis after all which is what APA had said all along. I don’t think, I’m quite ready to open the confetti boxes for that proclamation, it sounds like you guys aren’t too. And I guess, I mean, this morning, as much as there is a lot of great things going on in the Cooper Basin, I get that, but also post-production you wrote down 20% of your gas reserves, today it looks like there is about 60 PJs left outside the Origin contract. I mean, if you gross up your numbers to Santos’, they are about 20% short of the volumes they need for the Horizon contract. How should we be thinking about annual deliverable volumes from your guys’ perspective over the next four or five years? Should we just be thinking you are running purely at the Origin volumes and that extra 60 PJs is probably at the end of that Origin contract? And I mean, also you guys are looking at most of the basins, I presume on the East Coast of Australia. There is lots of gas in Australia, but it seems like people are looking for opportunities, they aren’t seeing much on the uncontracted space that actually is viable. So I guess there’s a lot of questions in one question. So my question is, what’s the profile for the Cooper Basin in your guys’ view? What gas price would you need to change that assumption then after that?

There are a few questions there, Mark, so thanks for that. Look, no that’s fine. Look, I don’t want to comment on other people’s views of the East Coast gas market. So obviously, we’ve told the market what we think our view is. Look, we’re active in this space, obviously a lot of it is commercial in confidence as you’d appreciate. Our main focus at the moment is continuing to deliver into our Origin contract. Fortunately, we have robust terms for that contract, it’s oil-linked. We have a lot of flexibility in terms of supply. We don’t have challenges in terms of minimum supply requirements. So we’re fortunate in that regard. Outside of that, we’re focused on other opportunities, not only within the Cooper Basin, but also in other surrounding basins, either through the drill bit or otherwise. So for us it presents an opportunity. We’ve got the infrastructure in place as we said, and I can’t really talk to a three-year, five- year outlook because that’s something we’re working on the strategy right now. And nor is it really a trigger from a price perspective, it’s really -- it’s linked to activity, risk and reward for shareholders frankly.

Okay. But I mean it’s obviously conceivable over the next couple of years you wouldn’t even be producing at the full, say, 10.5 PJs-ish a year for the maximum of the Origin contract?

That obviously depends on what happens with the drill bit going forward, frankly.

Mark, I think we’re comfortable in saying we’re comfortable that we’re going to deliver close to full volumes in that contract, it’s certainly our target. But I would also note that we do have some extra gas exploration wells in our 106 permit this year. So over and above that Origin, hopefully we do have some success and can extend some fields and have some news for wet gas play in there as well.

Okay. Commenting on storage, are you able to tell us roughly where the storage is sitting at the moment?

Yes, it’s still around the 70 to about 60 PJs at the minute, it’s still in storage gross.

Thanks, guys.

Thanks, Mark.

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

Morning guys. I just wanted to dig into the reserve downgrades in the Cooper Basin a little bit more about 15% after adjusting for production. I note your comments about opting out for future developments and some of that being reallocated to resource, can you provide us a sort of a guide as to how much of that was reallocation and how much of it was actually just downgrades?

Hi, Dale. Yes, we’ve – really what we’re looking at there is the economics of certain fields and Beach’s ability not to participate in projects that it regards as uneconomic. So what we’ve done with those fields is transfer from reserves to resources. So that gives us the caveat that we’re still holding the resource, and should the economic environment change between now and those projects being proposed, then they can be brought back to those.

Has any of the – the entire 7.5 MMboe being pushed into resource, is that how I should read it?

The majority of it, Dale. A small amount of it’s also been written off.

Okay. And then I guess you made a point about 20 gas exploration and appraisal wells due in FY 2016, 85% success rate, which is fantastic. But has there actually been reserves booked first for that program, or is that still yet to come?

Yes, we’ve booked some reserves for that, yes.

So the downgrade includes those bookings from the success case?

The overall downgrade does, yes, the net effect. Yes.

Okay. And then in terms of the opting-out process, can you maybe provide us a – more color in terms of what sort of forward program you’re planning on opting out? Is it for gas in any specific area, is it oil, is it infrastructure?

Yes, Dale, we’re really referring mainly to drilling programs. And what we’re seeing at the moment is, we’ve got very good alignment between ourselves and Santos on the look-forward business plan for the Cooper Basin. So I think looking forward at FY 2017, there is a significant amount of opting out and we are expecting that, going forward, there will be less and less as we’re further aligned on the business case for the basin going forward.

Okay. And then finally, Matt, you made the comment about 15% reduction in OpEx for the Cooper Basin, or in excess of that. Do you have a view of what could happen to sustaining CapEx within the basin, and also timeframe? Is this something we could see sort of really focused on in the next six to 12 months, or is it maybe a longer-term?

Yes, for us, obviously, sustaining CapEx in terms of the Origin contract is low. And I think more broadly for all of the infrastructure and facilities, we’re working through multiple scenarios as a venture right now, which is a little bit too early to comment on. But it is something with the revised new management at Santos, that it’s a core focus for them. I suspect it’s probably, as you say, a six to 12-month timeframe. But I wouldn’t want to put a clock on it, because it’s one of those things that you really have to get your head around, not only the business cases, but all the requirements of maintenance, et cetera, for the infrastructure before you can comment on that.

Okay, very good. Thanks, guys.

Your next question comes from the line of Adam Martin from Morgan Stanley. Please ask your question.

Yes, good morning. Just first question on the OpEx reduction, can you just talk about the sort of things that you’re targeting there?

Yes, there’s a number of them. Obviously, there’s areas around labor costs overheads, managing our costs out as a venture and, as Beach with contractors in the current cycle approaches to reduce costs on drilling and fracking are obviously a core target for us. So it’s really spread across the the entirety of our operations from overheads all the way through to the field.

Okay, thank you. And just on PEL 91, it looks like oil reserves are roughly flat after accounting for production. Historically, there was discussion about potentially higher recovery factors over time. Can you just give your thoughts on that field, what’s happening there?

Well, I’m not sure on the reference to increased recovery factors. But obviously, we do try and improve the recovery on those fields by bringing as much production forward in front of the economic cut-off for those fields. So we do – we would increase the recovery on those Namur fields by acceleration projects. But those would be artificial lift and infill drilling.

Okay. And the A$8 million that’s being spent in the SACB on CapEx, can you just roughly provide what that’s for?

Sorry, could you repeat that?

There’s A$80 million of CapEx budgeted in the SACB JV, your share, can you just run us through what that’s for?

I don’t have the break-down right in front of me, but it’s…

Roughly.

Roughly it’s development drilling. So well costs associated with drilling completion, fracking and connect that – and then and CNFA. CNFA is not much reduced – looks like being much reduced in the coming years.

Okay. Thanks for that. That’s all from me, cheers.

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

Well, thank you. Just a further clarification around that 15% cost-out target for Cooper Basin JV. What’s the baseline for that? Is that your costs incurred in FY 2016, or did FY 2016 already capture some of that cost-out target?

No, Nik, you’re right, the baseline it’s fundamentally FY 2016.

Okay, that’s clear.

Okay.

And just another question around reserves, just looking at the Drillsearch acquired reserves, there was a couple of major reductions in the wet gas reserves there. I guess, the Ex PEL 106 probably wasn’t too much of a surprise, but there was a big reduction in the Santos JV. I think Drillsearch last year had 7.9 million boe, you’ve cut that to 0.3 million, I’m just trying to think about what’s – can you just explain what’s driving that, given there was a number of gas successes there? Is that a write-down or is it another reclassification, is it because Santos doesn’t have a plan in place to develop that reserve anytime soon? Can you talk about that please? Cheers.

Yes, a number of those discoveries are waiting on an extended production test to get a better idea on the reserves. Until we’ve done those extended production tests, we don’t know whether they are economic or not. And so we hold those as resources rather than reserves until we have the results of those tests.

And is there any schedule of plans to conduct those EPTs?

We’re discussing that with the operator right now.

Okay, great. And look, just a quick final one, just on the Middleton gas compression targeting, I think, 20 million scuffs a day of compression capacity. Is it your – do you envisage that being fully utilized when that’s coming online, or will there be spare capacity there for future tie-ins?

Well, the limiting factor there isn’t the compression, it’s the separator. So what the compression does is it allows us to draw more gas from the well sock as the pressure declines. And what you can put through the separator is dependent on the amount of liquids in the gas. So you put through – you can put through more gas if it’s dry gas and less if it’s got more liquids to separate off. So we’re aiming to keep it as highly utilized as possible.

Sure, great. Thank you very much.

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

Good morning, gentlemen. Just two questions please. The first one is just around your inorganic growth strategy and just how we should be thinking about that. I mean, it seems that the strategy is focused on East Coast gas, as opposed to oil, and I’m not hearing much about the WA gas market. So should we see that any opportunities are going to be focused on the East Coast gas market? And then the second question is a housekeeping question, just around your field production cost on a boe basis. Is the number A$18.50 per boe for FY 2016, which I calculate is down 3% year-on-year? I just want to clarify that. Thank you.

First off inorganic growth one first. I think what we’ve said is that any inorganic growth is going to be in line with our strategy. And if you look at our strategy, there is not only the East Coast gas thematic, but there is also a focus on growth opportunities in Australia and nearby. So I think that’s probably a better umbrella to think about our inorganic opportunities under. So the key for us is the bottom line is it’s all about creating shareholder value. So we are being very disciplined in our approach. We do have new processes in place in terms of screening opportunities and our due diligence, and metrics in place and agreed with our Board. And So, frankly, we are going to be very patient about this and wait for the right opportunity. The base business is performing well. There is no need for us to rush. But we are active and we’re well-positioned in terms of our balance sheet right now. So it’s beyond the East Coast gas thematic.

Okay. Thanks.

Just in terms of the cost there, James, so in Slide 24, it sets out, because the total cash production costs are around the A$22 per boe, but that’s all field OpEx, tariffs tolls and royalties. Just in terms of field OpEx itself, that at the A$3.60 per boe level.

That’s for Western Flank operated oil assets, isn’t it?

Oil and gas, yes.

Yes, okay. Yes, because I was after field costs, and I’ve got A$18.50. So I mean I agree with the A$22.80, which includes royalties. So you agree with that, the field cost of A$18.50, down 3%?

Not for our Western Flank.

Not field, yes, field operating cost of A$3.60 boe oil and gas. And then when you add on tariffs, tolls and the royalties, our total cash costs are $22.

Okay, thanks. All right guys. Thank you.

Thank you.

[Operator Instructions] Your next question comes from the line of Andrew Hodge from Macquarie Securities. Please ask your question.

Just, I guess, a follow-up question about PEL 513, 632, the only thing I just wanted to ask is how much did Santos elect to spend as part of the Western gas [indiscernible]? The second question is if you could provide any update on the Tintaburra sale process. And the third one, if I can sneak one in is really just asking about the roughly A$100 million increase in provisions, I’m just wondering if you can go into more detail about it?

So just on your first question, in terms of the Southwest JV carry, there’s around about A$20 million worth of expenditure that Santos have to spend before the carry is completed at this point.

And just based on your comments on Tintaburra process, that is actively progressing and when we’re ready to send more to the market, we will did you catch with it.

So, Andy, your last question is if you could provide any…

Yes, so the last one was really just about the restoration provisions. Excluding obviously what’s happened with Drillsearch, you guys have increased the provisions by about A$100 million. So I just wanted to, I guess, to get a little bit more clarity around what’s gone on?

Yes, Andrew, it’s Peter Sandery here. Essentially, we’ve just realigned our discount rate with the fall in interest rates just to align the – we’ve just reduced the discount rate that we’re using to calculate the present value of the provision.

Okay. Thanks, guys.

Thank you. There are no further questions from the telephone lines. I’d now like to hand the conference back to presenters for closing remarks. Thank you, and please continue.

Thanks, Eva, and thank you all for joining the call and the webcast. Appreciate your time and, again, if there are any question, please don’t hesitate to reach out to us. Thank you, everyone, and have a good day.

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