Derek Piper - Investor Relations Matt Kay - Chief Executive Officer Jeff Schrull - Group Executive of Exploration & Development Michael Dodd - Chief Operating Officer Morné Engelbrecht - Chief Financial Officer

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

Good morning, everyone, and welcome to the call. This morning, Beach released its preliminary full year results for FY '17 as well as an accompanying presentation, and we'll be talking through that presentation this morning. Discussing the results will be Matt Kay, our Chief Executive Officer; Morné Engelbrecht, our Chief Financial Officer; Mike Dodd, Chief Operating Officer; and Jeff Schrull, Group Executive, Exploration and Development. And we have other members of the executive team here with us as well. We'll talk through the presentation and then open the lines for Q&A. So Matt, I'll hand over to you to begin with an overview of the year.

Thanks, Derek. And welcome, everyone, to the call. FY '17 proved to be a successful year for Beach, not only with regard to our financial performance but also in readying the business for an upcoming period of active exploration, development and production. We delivered clear progress against our strategic pillars by enhancing the value of our Cooper Basin acreage [Indiscernible] our gas business and further strengthening our financial position. I'll start by turning to Slide 5, which summarizes what we consider our key value drivers for Beach today. Firstly, we are highly profitable despite the continuing low oil price environment. Our strict focus on costs and operating efficiencies has further improved returns on the base business. Underlying profit was up 353% to $162 million. Costs were reduced across the business, and our cash flow breakeven is world class at U.S. $16 a barrel. Performance of the Cooper Basin JV with Santos was particularly pleasing, generating 115 -- sorry, $105 million of free cash for the year. Across-the-board, we've seen a significant results turnaround from recent years. Our robust base business provides the platform for organic growth. We've commenced a multiyear work program which begins with a step-up in activity in FY '18. We will participate in up to 78 wells, 20 more than last year, explore and appraise undeveloped play fairways and continue with a broad range of field and production initiatives. This program and our results from FY '17 give us confidence to target more than 10 million barrels of oil equivalent production through to FY '20 and target a 2P reserves replacement of more than 100% through year-end FY '19. Lastly, we have the balance sheet to support our growth aspirations. With $700 million of available liquidity and a seriatim of high-returning capital projects, we are well placed to ensure growth within our existing business and also external opportunities. We continue to assess the number of inorganic growth opportunities, but at this time we're not in a position to discuss any specific transactions. Moving to Slide 6, which summarizes results from the field. We've spoken previously of record production, drilling success, costs out and facility expansions. I would emphasize that work in the field this financial year, particularly in the second half, has provided strong growth momentum to the business as we move through FY '18. We're very proud of the performance of our field teams to date. We've commenced tie-in of wells at the Bauer facility expansion and are benefiting from incremental production. Work is underway to connect our new Mokami and Crockery gas discoveries, which will provide additional gas to sustain maximum production capacity beyond FY '18. Our work over rig will be working actively from now through to year-end, completing and connecting more than 20 currently cased and suspended wells. We're continuing to work through our artificial lift program, which provides incremental production from existing fields for a low-capital outlay. As this activity progresses, it is comforting to know we have already expanded our production facilities to sustain the current levels of production. The figures on Slide 7 tell a good story. I'll let Morné talk in a moment to the financials in more detail, but what is particularly pleasing is the turnaround in underlying profit, a further reduction in our break-even cash flow and the strength in net asset position due to profit and impairment reversal and a deferred tax asset recognition. The impairment reversal and DTA reinforce an improved outlook for Beach. All financial metrics demonstrate a strong turnaround in the Beach business. The board has announced a final dividend of $0.01 per share fully franked, which takes full year dividends to $0.02. This is a $0.015 increase from last year and the 16th consecutive year of dividend payments. Moving to Slide 8. As we focus on high performance and cost efficiencies, safety remains paramount and number one priority of Beach. If you look at Slide 8, it shows further improvements in safety and environmental outcomes in FY '17. It was the fifth consecutive year of reduction in our lost time injury frequency rates. This was achieved during a period of major contract projects associated with our infrastructure expansion projects. These were completed without safety incident or environmental impact. Environmental performance also improved, with reductions in spills and spill volumes. On the latter, total crude oil spills were less than 2 barrels. And there were no hydrocarbon spills outside of secondary containment, such as bunds. Slide 9 outlines another pleasing and significant result from FY '17. We achieved a 7% increase in 2P oil and gas reserves and 179% 2P reserves replacement ratio. A number of factors contributed to the upward reserves revisions, including new discoveries, field extensions, production performance and cost efficiencies. The reserve outcomes support our work program and confidence in our longer-term production targets. Reserves as at 30 June 2017 were independently audited by RISC Advisory. All in all, FY '17 has been a very pleasing year for the company. And I'll now hand over to Morné to discuss the financial results in more detail. Morné Engelbrecht: Thank you, Matt. Good morning, everybody. As mentioned, it has been an outstanding year for Beach, which is reflected in our strong results today. You will note a common theme throughout our results: Higher production, improved oil pricing, reduced costs; operating efficiencies underpin the growth we achieved this year. I'll touch on a few highlights from Slide 11. Firstly, the turnaround underlying NPAT, as Matt mentioned, is significant and demonstrates the robust nature of our business, where a 353% increase to $162 million was achieved, aided by 9% uplift in production, 13% increase in realized oil prices and a broad-ranging cost savings. The impact of cost savings is also evident in our EBITDA margin, which expanded from 34% last year to 59% in FY '17. These results clearly demonstrate our ability to remain highly profitable in a low oil price environment. Secondly, the Cooper Basin JV has been transformed into a material cash-generating unit. Santos as operator realized substantial cost savings and capital efficiencies and continues to seek and drive further reductions. Combined with Beach’s ability to opt out of projects that do not meet our strict capital allocation hurdles, the Cooper Basin JV has definitely turned around. This year, the JV generated $105 million of free cash flow, count that as pre-tax operating cash flow less capital expenditure. Lastly, our ability to generate cash flow at low oil prices continued to strengthen our financial position. We ended the year with cash reserves of approximately $350 million and our cash flow breakeven reduced to world-class level of USD $16 per barrel. Our calculation of cash flow breakeven adopts the oil price, at which Beach would have been cash flow neutral in FY 2017 assuming no discretionary capital was spent. Clearly, that’s not a sustainable position to be in, but this metric does provide comfort in our ability to protect the balance sheet during periods of extreme market dislocation. On Slide 12, it sets our various metrics, all of which have been moving in the right direction. Statutory NPAT this year includes two adjustments, which reflect the great result achieved in FY 2017 and also improved outlook for Beach going forward. Firstly, we reversed $150 million of pre-tax impairments previously booked in relation to the producing assets in the Cooper Basin. This reversal must lead to sustainable performance improvements, cost savings, capital efficiencies, upward revisions. And the reversal is noncash in nature but does reflect the improved prospects for the reasons mentioned. Also related to our improved outlook was recognition of $79 million of deferred tax assets. Our assessment of future profitability indicated that timing differences previously not recognized are now likely to be utilized. Again, this is a noncash adjustment. Regarding our tax position going forward, we do expect to pay cash tax in FY 2018. And the statutory tax rate, of 30% should be used to approximate our effective tax rate over the coming years. The last point on the slide refers to dividends. As Matt mentioned, a $0.01 fully franked final dividend has been announced, which takes full year dividends to $0.02. The board considers this an appropriate level, given current market conditions, to balance capital returned to shareholders and reinvestment of profits into the business. Slide 13 shows the components of the increase in underlying net profit. Again, it’s the same story: higher production, higher oil prices, reduced cost, which accounted for most of the profit improvement. Gas pricing also increased marginally as we transitioned to a higher price contract for our product, Western Flank gas business. We expect pricing to continue to increase as we benefit from contracts throughout the remainder of calendar year 2017 and seek to re-contract these volumes for calendar year 2018. With increased Western Flank gas production expected in FY 2018 and a potential facility expansion under review, Beach is well placed to benefit from gas supply shortages currently impacting the East Coast and southern gas markets. As cited before, the broad-ranging cost savings played an important part of the result, and mainly related to the reduced Western Flank operating cost, which is down 15%; the Cooper Basin JV operating cost, which is down 20%. Overall headcount, which is down 11%; and we also reduced costs from low-margin assets which were sold during the year as well. Slide 14 is a nice one for me to finish on. Beach is navigating the low oil price environment extremely well, as evidenced by our cash reserves and ability to generate material free cash flow. In FY 2017, we generated $321 million in net operating cash flow. Of this, almost $150 million was added to cash reserves, $155 million was directed to capital expenditure; and $20 million was paid in dividends. With cash reserves of almost $350 million and undrawn debt facilities of the same amount, Beach has available liquidity of approximately $700 million, which provides a solid foundation to pursue appropriate growth opportunities. On that note, I'll hand over to Mike to talk you through operations in more detail. Over to you, Mike.

Thanks, Morné. And good morning to all. Turning now to Slide 16. Beach continues to lift the bar on production year-on-year. This was a record year of production at 10.6 million barrels of oil equivalent. And that was driven by Beach-operated production, which now constitutes more than half of the group's production on an annual basis. It's a great team effort to get to this number. And if we look through the whole work stream with M&A; exploration and appraisal; success development drilling; execution at facilities, projects; production optimization projects; and importantly, the dedication of the production team in the office and the operators in the field, it is a true team effort by the company. It's been a very busy year to get to that number, but it's been a safe year, as Matt mentioned. Lost time injury frequency rate is down again year-on-year. And not a single uncontained hydrocarbon spill over the year, so great results there. Of particular note was the focus on the installation of artificial lift, both ESPs and variable-speed beam pumps. And all these have added around 800 barrels of oil per day of incremental rate. The Middleton gas compression project was commissioned in March and moved to full volumes in early May. Gas production of 25 million a day has been achieved, and liquids production has been optimized. On occasion, that's been over 1,000 barrels of condensate per day. The Bauer north facility expansion has increased the Bauer fluid-handling capacity to 120,000 barrels of fluid a day. As a result, new wells are being tied-in through this facility and have returned PEL 91 to production over 10,000 barrels of oil per day. We're guiding to 10 million to 10.6 million barrels of oil equivalent for FY '18, which is then underpinned by a busy year of production optimization projects in the field. Moving on to Slide 17. This gives details of a very successful year with the drill bit. The overall success rate was 79%, which tells a good story in itself. Operators exploration is worthy of highlighting. Pulling that out, for oil exploration we increased the success rate from 33% to 75%. Of particular significance were the Birkhead discoveries, especially Kangaroo-1, a seismic-driven discovery extending the PEL 91 Birkhead fairway to the north, a long trend with the Growler and Spitfire fields. There were a number of follow-up locations to this discovery, which I'm sure Jeff will talk about shortly. Also significant was the operated gas exploration program with a success rate of 75%, again including the Mokami-1 well, which flowed over 8 million a day on DST, with a good liquids content. This well was designed to and successfully tested the Patchawarra pinch-out plant PEL 92 -- in the PEL 91 area. And again, Jeff will talk about follow-up plans for that play. Slide 18 looks at cost savings. There's been a sharp and successful focus on driving costs out of Beach's business through FY '17, and this is borne out in the results and sets a firm foundation for FY '18. Across the whole business, we've driven our break-even oil price down to just USD 16 a barrel. This number is helped by reducing our already impressive operated field OpEX down by 15% over the year to an average of $3.10 per barrel of oil equivalent as well as driving down drilling costs and reductions in headcount across the business. Slide 19 demonstrates the ongoing focus of the Cooper Basin joint venture in improving its cost structure. We've reported progress on this effort all year, and this slide is a good summary of some of the key outcomes. Moving to the model that Beach has employed over many years of slightly operator maintain a tight work, coupled with reductions in headcount, fit-for-purpose monitoring regimes and, amongst other initiatives, have contributed to a reduction in OpEx from $20 a barrel to $16 a barrel. A 35% reduction in drill costs as well as a transition to risk-based maintenance and better contract terms have meant that CapEx has been more than halved in FY '17 compared with FY '16. A combination of all these factors have turned the business around to a free cash flow generation of over $100 million in FY '17. So with that quick look at some of the operational highlights for FY '17, I'll hand back to Matt and Jeff to look forward to FY '18.

Thanks, Mark. Jeff will provide an overview of our FY '18 campaign in a moment, but first, let me revisit our capital expenditure and production guidance for FY '18. Details are unchanged from our announcement of 27 July 2017. Slide 22 summarizes the FY '18 program. As mentioned previously, a multiyear program has commenced to fully appraise the undeveloped reserve and prospective resource potential of the Cooper Basin. It will be an exciting and active year in FY '18 as we aim to establish the foundation for ongoing activity, reserves replacement and sustained production levels. We're guiding towards capital expenditure in a range of $220 million to $260 million. Approximately 75% of this is discretionary in nature, 2/3 of which is allocated to projects with internal rates of return greater than 60%. With regard to production, we have confidence in guiding towards 10 million to 10.6 million barrels of oil equivalent. And we are targeting at least 10 million barrels of oil equivalent of production in FY '19 and FY '20. Importantly, FY '18 guidance is underpinned by existing producers and more than 20 currently cased and suspended wells, which we will be bringing online. This means we are not relying on exploration drilling success. I will now hand over to Jeff to expand on the activity within our main play fairways for the year.

Thanks, Matt. Let me take you through what Beach's FY '18 program looks like. We continue to focus on our 2 oil play fairways on the Western Flank and our 2 gas play fairways on the Western Flank, in addition to participating in the South Australian JV that we're in with and Queensland JV we're in with Santos. Let's start on Slide 22 with the Birkhead oil play fairway. The objective for FY '18 for the Birkhead play fairway is to add new reserves. And we've got a very focused exploration program to achieve that. 7 exploration wells are planned in PEL 91 and PEL 104. The recent discovery at Marauder flowed 655 barrels a day. That's obviously a great way to get the year started. Our approach in PEL 91, we first want to further calibrate what we're calling the Birkhead mega trap, the GC40 mega trap. It shows in the wells, it covers close to 150 square kilometers, pretty much Kangaroo and Stanleys, both lines' production wells. We'll drill 2 calibration wells at Goldsmith and Donington, and then we plan to come back later this year or early next year to try double horizontal development wells. And the key is to find the cheapest cost-effective way to develop this resource. And that's what we'll be planning to do in the beginning of the calendar year 2018. So the, on slide -- moving on to the Namur play fairway, Slide 23. The purpose, I mean the key element of this and the purpose for FY 2018 is to stay in production. The Namur McKinlay play fairway is what may be, as you can see on the slide there, the numerous producing fields. As Mike said, we had a record operating production number for FY 2017 and we hope we can continue that in FY 2018. You can see the center work that we've done, the highlighted-in-yellow area, these very, very large areas of prospective resource and some appraisal site risk resources, such as the McKinlay and Namur. We’ve undertaken a full velocity model over the entire Western Flank. The first one has been undertaken, and we’re really seeing some exciting results. And some of those prospects you see there on the map are a result of that. Recently, we’ve also drilled the Bauer-26 horizontal well. There was a GS Deer well, quite happy with it. It’s on free flow. We’ll put a pump on it in December; and so far, so good. It’s wire-free production, which is what we had modeled, and that will lead to much more McKinlay infill in Bauer and our other fields. We also have four to six Namur appraisal/development wells planned that we’re currently developing. So that’s the oil play fairways and lot of really exciting drilling. The rig is currently in Donington, by the way, in the Birkhead play fairway. And we’ll evaluate those results and then move in to Goldsmith. Slide 24 is the Southwest Patchawarra and Permian Edge play fairways. This slide focused mainly on the southwest patch play fairway where we have our gas production hub in Middleton. And you can see on the map, the two discoveries Mike mentioned, Mokami and Crockery, that will be hooked up and producing, hopefully later this year, maybe early calendar year next year. And you can see our other suite of producers. The thing to notice on this map is that the wells that we’re drilling are basically near field step outs to the existing discoveries that we’ve made in the existing wells, and hence they have a chance of success of around 50%. So, the goal of this campaign in and around Middleton is to, hopefully, expand our production capacity to double over what our current production capacity is. And the beauty is the hook-up times for these near-field discoveries, the ones near Middleton, are quite short, less than a year. So, the longer-term reserve-add part of our gas portfolio is the Permian Edge play fairway, which the Mokami discovery is right on the edge of it. And we’ll be drilling a well called Laos, which is our westernmost discovery, early in the campaign. Four to five Permian Edge wells are targeting this play fairway in FY 2018, and the risk there is a little bit higher. It’s not 50%, it’s more 25% to 35%, but there’s quite a big upside potential. 70% of the whole play fairway has no 3D, so if we crack this play, it really will give us a lot of running room. That’s the two gas play fairways. Moving on to Slide 25, this is the Cooper Basin JV that we’re in with Santos and Origin. You can see a number of programs, two rigs going full time over the year. The red highlighted areas are gas drilling, mostly infill or near field appraisal drilling, some exploration drilling. And the green are oil drilling programs. One highlight is Merrimelia, where Santos will be drilling two horizontal wells that we’re really hoping increase the oil production in that field. All in all, 35 appraisal and development gas wells, 14 oil wells. The beauty of these two rigs is we're getting 30% to 35% more wells per rig year because of the reduction in drilling time, which leads to basically more production per investment dollar. The Snowball 3D interpretation that you see highlighted there, Beach is doing a full evaluation of that, and we're hoping to have multiple gas exploration wells to drill from that. And we'll be working with Santos to move those forward as quickly as possible. So in summary, it's very busy, very exciting year for Beach. We're going to have four rigs going, two operated -- excuse me, one operated, three non-operated, throughout most of the year. 78 wells in total, 34 development wells, 44 very low-risk E&A wells, all in the core play fairways, all with short cycle times to hook up; roughly 32 oil wells in total, 46 gas. And obviously, we've got the 18 wells Western Flank oil producers and the two gas wells to hook up this year that Matt mentioned that I'm really looking forward to seeing how those Callawonga wells come on stream when we get them perforated. Really looking forward to those wells. The other well that we'll be drilling, so we will actually be in five rigs for a few months, is Haselgrove-3 at Otway. It's a directional well targeting roughly 30, 32 Bcf un-risked gas resource with a chance of success of about 1 in 3. And that gas will be delivered to the South Australian market, which is obviously in dire need of gas at the moment; and we hope we can contribute to the energy needs down in the southern part of Southern Australia. And then we've got, obviously, several more debottlenecking projects and optimization projects, more beam pumps going in, et cetera, to keep getting more oil and gas out of these fields and keep finding more fields in the future.

Thanks, Jeff. Well, that concludes the presentation, so up to Q&A. So can I ask the operator, please, to open the line. So the operator there, please, if we could open the lines for Q&A. Thanks.

[Operator Instructions] Your first question comes from the line of Mr. James Redfern of Merrill Lynch.

Just two questions, please. The first one is, just in terms of the free cash flow breakeven in the Cooper Basin JV. Given that you generated $105 million free cash flow, can you just confirm what the breakeven oil price is, please? And then, I've got another question as well after that.

Actually, James, the cash flow breakeven figure that we quoted in the presentation is for the business as a whole, so we haven't actually quoted one for the Cooper Basin JV. So...

Right, okay, okay, got you. All right then. And then just the other one, I'm having trouble reconciling the EBITDA. That $385 million, is that an underlying EBITDA number? Morné Engelbrecht: Yes, it is, James.

Okay. Because I'm just having trouble reconciling it. I'm thinking that it's in the other income or other operating costs. Can you -- are you able to confirm what the -- what those two figures are, please?

It's just in the notes, James. If you take the operating profits pretax and add back the reversals, which is [Indiscernible].

Yes, maybe we'll take it offline.

I'll give you a call after the... Morné Engelbrecht: Yes.

Your next question comes from the line of the Mr. Adam Martin of Morgan Stanley.

Just on your 2C number in the Cooper Basin JV. I mean, clearly the market's calling out for further gas over time, so can you just talk about the strategy about trying to move some of that across into reserves over time, how we should be thinking about that?

It's something that we are obviously discussing with Santos at our JV meetings every time we have a JV meeting, but I can't give you any specific work program for FY '18 that's in the Cooper Basin JV. We have put in for some PACE grants for some horizontal wells in some of the deep coals, which could help. But I think it's safe to say that the focus for the FY '18 budget is conventional gas and oil wells near the fields that we can get onstream very quickly.

And that 2C number of 308 PJ, is that mainly conventional gas? Or is it [fed]? Because you've got -- you've obviously got unconventional separated out. I'm just trying to understand. Is that conventional, or is there a portion of unconventional in that?

I don't want to give you a proportion right off the top of my head. I would say, a large percentage of it would be [nonconventional], would be the stuff associated with the deep coals.

Okay, okay. And just on the oil business, obviously some good reserve upgrades there. How should we be thinking about sort of production, particularly, I mean, at PEL 92, PEL 91, et cetera, over the next few years? How should we be thinking about production? A similar decline or more of a flattening? How should we think about that?

Well, our production guidance for the next three years is to try to stay above 10 million barrels and keep it flat for the next three years...

Yes, I know, but a proportion of that will be due to exploration success. I'm just trying to understand, for 91 and 92, how we should think about, should we be sort of assuming similar declines over the last two or three years? Or given the reserve upgrades, is there some sort of activity coming that will flatten out production declines?

Yes, when we put out the production guidance, we said it will come from a number of factors, more infill drilling, the kind of programs that we're doing this year for gas and oil; and also, that we would need some exploration and appraisal success. So it'll contribute for each of them. We haven't given the specifics. But I would say, that it's a fairly modest-risk exploration adds to stay flat. And I'll just reference this velocity modeling that we're doing in the McKinlay horizontal well that we just drilled at Bauer, so a lot of that stuff is currently carried as prospective, and my team's job is to make that as low risk as possible before we start drilling it.

And Adam, obviously Jeff's referenced [had exploration adds] he's referenced to FY '19 and '20. You've seen that we've announced that FY '18 is basically current producers, plus the 20 wells we're going to bring online. And there's fundamentally no exploration add, or it's very minor, for FY '18.

Yes. I'm just trying to get a sense. Like, look, I can understand the '18 numbers look relatively low risk as well as '19 and '20, and how we should be thinking about that. But I'll take it offline, but that's helpful.

Yes. And specifically, the gas -- an example, the Permian Edge play fairway wells and the southwest patch wells, those won't be able to be hooked up in this financial year. So whatever discoveries we have there has been modeled going forward to the FY '19 and '20 production. So you've got some risks in the table here, if you want to play with some numbers.

Okay, alright, well thank you.

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

Yeah. Good morning guys. Just first, a quick question on reserves. I guess, when we strip it out and you actually look at operated fields and reserve replacements up around 250%, 260%, which is extremely impressive. The Cooper Basin, well, maybe the market’s perception might have been where more -- sorry, SACB, Cooper Basin saw what market might have thought more of that was going to come from, you guys have been conservative. How should we be thinking about that at a time when, I suspect, the operator certainly seems considerably more excited about it? I know you guys are, to an extent, but we’re not seeing that come through reserves. Should we just see this as Beach has traditionally always taken a pretty conservative view to these -- to the SACB JV and the risk is skewed more to the upside there? Can you maybe just talk around how you see reserve progression there?

I think there was a question there, but I lost track of it along the way. Are you JV?

Yes, sorry. I’ll -- JV. Sorry. I was talking to myself at the end there. The SACB JV, how should we -- how are you guys thinking about the reserve position there? I mean you, obviously, you didn’t have 100% reserve replacement there. It was the only asset that you didn’t. Is this just conservatism at this stage, or...

Yeah. Well, we took a very hands-on approach this year to the reserve booking in the SACB. We’ll be working with Santos and sharing with them our numbers. We had RISC -- as Matt mentioned earlier, we had RISC do a full audit of all of our work, including the stuff we did on the SACB. We couldn’t get to all the fields, just doing the DCA, and we will be doing that. I’d say there’s probably scope for some -- hopefully, some reserve additions. The other thing, when you talk about -- my point earlier, about two rigs gets you 35% more wells with two rig years, what that carries through is the ultimate recoverable economic size for a well to be drilled drops significantly. So, a lot of these 40,000-, 50,000-barrel wells that might struggle at $3.5 million well cost, if you can do them for $1.5 million or $2 million, you can make them work. And we’re still -- the transformation that -- Santos operations is still ongoing, the costs are still coming out. They’re still drilling wells. They’re still improving. So we’ll – I’m pretty bullish, going forward, on our reserve position in the SACB.

Mark, I think, just moving forward on the reserves, I’m pleased to note there’s some expectation, I think, from the market that it would be gas-price related. It’s not really the case. So, if you look at the 2P reserves it’s a pretty even spread across exploration and appraisal outcomes, new developments or new undeveloped well locations and also well performance and ultimate recoveries. And cost out is contributing, but it really is a pretty clean spread across the business.

Perfect. Look, I’ll try and keep this second question a bit more to a question rather than statements from me. PEL 106, is there any update you can give us on the potential capacity expansion there, particularly in light of the massive reserve upgrade there?

Yeah, look, we’re obviously drilling a number of gas wells there this year. We’ve obviously had three out of 4 discoveries last year. So, if we have two or three successes in this upcoming campaign, there’s a good chance we’ll look at expanding Middleton for sort of 40 million to 50 million scufs a day of oil, gas.

Your next question comes from Dale Koenders with Citigroup. Please ask your question.

I was hoping to maybe connect some of the dots from some of the prior questions. I guess, production guidance of at least 10 million barrels of oil equivalent over the next 3 years seems to be premised on sort of minimal-risk exploration success. Should we be thinking that, if you continue to add this reserve replacement, 170% per annum, going forward, each time you do that, does it add an extra year of the same production at the end of that profile?

Well, I think the first comment I'd make, Dale, is no we're not forecasting that we will continue with 170% per year. It would be nice to end up in that space and certainly there are some success scenarios where we would. What we are forecasting is there will be at least 100% reserves replacement through to FY '19. And look, in terms of the forward view out to FY '20 on production being above 10 million barrels of oil equivalent, there's certainly not a substantial amount of exploration success required. That is really an expectation outcome for us on the current programs we've got going forward.

And what should we be thinking about exploration going forward then? Because it's really not factored into the current production targets, in that they're material volumes, yet you're obviously spending a lot of money on exploration fields. Does this continue to extend those [applied to] oil production? Or could this provide upside to production numbers?

The current program is factored in. I mentioned the, like, the 106 wells would be hooked up and producing in FY '19. Beyond that, I'll just talk about the Birkhead mega trap. It depends on how we go. It depends on how effectively we can come up with a development scheme to fit the resource. So we're still figuring out how big the resource is. We know it's there. We've got producing fields. We need to figure out how big it is and what sort of -- how aggressive we can be with the development plan. So I mean, that's the purpose of the 2 exploration wells I mentioned. And then we're going to try a couple different development-type wells, horizontal or high-angle wells early next year. And then we'll have a better feel for just how big they are and what sort of commercial plan fits the resource. Sorry, that's an explorationist's answer to that question, but that's the business that we're in.

I guess, what I'm trying to get to and struggling to get an answer is, how sustainable is the business model when you think about 10 million barrels of oil equivalent production at the moment if we -- prior management has discussed an exploration portfolio, drillable targets of 100 wells-plus. Has that number changed as you bring in new technology? And if there is that volume of drillable targets less than you do continue to drill and have exploration success, is the 3 years of sustainable production potentially quite conservative?

Well, I guess, I'll -- the simple answer to that is, our focus for exploration drilling is going to be on the forward -- the 2 gas and the 2 oil play fairways in the Western Flank. So we're going to be -- if you look at that Namur map and you look at all that almost 30-kilometer-long string of fields where the north and end -- north and south end of the fields, is still prospective. So we're going to be focusing on the very low-risk core play fairways over the next couple years. Some of the other 100 might have been riskier things that are outside of those core play fairways, but our focus is to intentionally keep the risk as low and keep the cycle time as short as we can over the next 2 years.

So one way to think about it is the extra frac way '18 is pretty low risk, because it's [Indiscernible] premised on production projects that we'll be doing out in the field, this little exploration there. And you talked about previous exploration [Indiscernible] recent years, where there's been a little bit capital-constrained on those programs due to the employment, and we've really concentrated on development drilling side. I think what you're seeing now for the next couple years is a much more aggressive exploration focused on those plays that Jeff has described. So a realistic view on what will come out of those exploration plays is talking to the FY '19 and FY '20 production numbers.

Your next question comes from the line of Mr. Ben Wilson of Royal Bank of Canada. Please ask your question.

Matt and others, I just had two quick points of clarification. Firstly, your reserve replacement target out to FY '19, based on what you've said on the call today, can I interpret that as in each year as we look out? Or is it to be looked at as a -- maybe a three-year reserve replacement average when we look back from FY '19? I'll just ask the second one. It's quick. You touched on it before, about gas pricing assumptions that went into, either your reserve changes or your asset testing for the gas assets in Cooper there. Can we assume then there was no change over the course of the year to your gas price outlook that fit into those assumptions?

Yes, Ben, look, on both those questions. Firstly, on the reserves replacement side, no, we really think of that as a program out to FY '19, so -- but I think about it as an annual target as such, so 1 of those years would be higher, 1 of those years lower and vice versa. So I really think about it as a target of the current campaign, so that's why we came out and said we're basically running a 3-year capital campaign starting this year. So you should think about it that way. On gas pricing, obviously we have our current Cooper Basin joint venture gas contracted with Origin. This year's 106 gas, we have contracted to Adelaide Brighton Cement. We are re-contracting that gas for next calendar year. So we're in that process right now. So there was some increment, but obviously a lot of that is longer dated after the Origin contract, and -- but if the question also circles back to are we seeing heightened activity in the market from a buyer's perspective and price movement upwards, yes, absolutely. So, I think we've mentioned earlier, this market [commentators], you talk about historical [indiscernible] gas prices at four to six. It's moved through to the six to eight range and is now going beyond that. That's consistently what we're seeing as well.

Okay. And just to sort of finally clarify, so your three-year target incorporates the reserve replacement that we've seen this year.

We're basically saying, if you banked what we've done this year and you look out to FY '19, then we're looking at 100% as being our -- what we think we can deliver.

Okay, thanks.

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

Look, I will just have another crack at Cooper Basin reserves -- JV reserves. Just on Slide 13, you went through the 20% reduction in field operating costs and 35% reduction in drilling costs. I mean, high level, that should mean that you should -- the JV should be able to produce the -- [all of the] gas at a profitable level for longer. And I think, Jeff, as you touched on, there's areas and wells which may have been deemed to be uneconomic at gas -- at whatever gas price assumption you've got, but with a lower drilling cost, would you consider it economic. So why is it wrong for us to be slightly disappointed that reserves didn’t go up more? Was there some negative there that offset the positives that might have been otherwise coming through?

We had a -- most -- a lot of it was in 2P undeveloped that Beach had carried in the past. And it wasn’t associated with wells. It was associated with infill -- in-well programs. And when we went over the whole seriatim with risk, we felt like it didn’t quite have the definition of what the projects were going to be. And a lot of it is pretty basic stuff, just workovers and that, so we’ve removed that from the 2P undeveloped. That was the main difference.

Right.

And the -- what makes it tricky is that Santos does their reserve booking at the end of the calendar year, so we’re always six months out of sync with them. And they’re – we’re already talking to them about the work we’ve done, and they’re very keen to see where we’ve seen pluses and minuses. So we’ll – I’ll repeat it again: I’m bullish with where we get between now and the end of the year with Santos, hopefully.

Okay, that makes sense. And look, just on Western Flank oil reserves, that was pretty material increase we saw coming through. Just trying to understand the key drivers in the assumptions you’ve got there. Was there a change in recovery factor in how these wells could perform? Is it, again, a function of lower operating costs? So these wells will produce at a low rate for a very long period of time. Is it -- sort of is this adding reserves at the end of life? Or is there any inbuilt assumptions around increasing fluid-handling capacity at Bauer again?

Well, I think all of those, actually. That was a pretty good summary. I guess, the one area that we got very pleasing performance was the northern end of Bauer. Just the history matching that we did, it shows that there’s going – there’s probably more there than we thought. The infill drilling we did at Callawonga last year was very positive. We got more infill drilling to do there, same thing at Pennington. The -- obviously the -- we drilled some of the wells at Callawonga for under $1 million. So, the well cost lowers the economic ultimate recovery. So it -- all of these things factored in to feeling like we -- there was more potential left in the fields. And the -- our -- we -- the McKinlay that we’ve been talking about, the McKinlay, we didn’t actually -- we didn’t book that much 2P undeveloped in the McKinlay yet, but hopefully, we will be doing that over the coming 12 months.

Thatss great, Jeff. And look, maybe just quick, one final one. Matt, I think previously you -- last year, you were kind enough to give a guidance of greater than 15% cost-reduction targets for Cooper Basin JV. That was certainly delivered. What’s your expectations for this year?

Yeah, thanks for the question, Nik, putting me on the spot there. Look, I think, in terms of the Cooper Basin joint venture, look, I don’t think it’s appropriate for me to speak on behalf of the operator in terms of cost targets. What I would say is they have done well and delivered, which is fantastic, both on drilling cost and in the field. Look, I think they’re still reasonably early days in terms of field efficiencies, so I think there’s still more to come, but really not in a position for me to give some -- anymore guidance on that at this point.

Thanks, Matt.

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

Thanks, guys. I have actually three questions. The first one was on Western Flank. It looks as though the costs in the second half went up compared to where they were in the first half. And I just wanted to understand, is that from artificial lift? Or is that just because production was lower and so therefore, when production should be increasing in this first half of FY '18, we actually should see costs go back down again? Morné Engelbrecht: Yes, I think you're exactly right. I mean, Andrew, with the half year productions. The [Indiscernible] production drive that in new costs yet.

All right, the second question was around the Middleton gas facility. And then, just obviously that's expanding to 25 MM, but if we think about going to 50, given the sort of high levels of condensate and liquids really, you guys could go hit at the moment, trying to understand 2 things. One, how much would you need to actually discover and have success with to be able to try and go ahead with that project? And then secondly, what would be kind of the ballpark ratio you guys would be thinking about in terms of liquids versus gas?

Well, all of the reservoirs in that southwest patch area have very high liquids rates, and the Permian Edge play fairway as well. Mokami was almost 100 barrels per million. In terms of expansion, a lot of it isn't just total volume that we find, it's the capacity from the wells. What sort of flow rates we get. That was one of the great things about Mokami and Crockery. Those are both very high-flow-rate wells. You can see the estimated online rates on Slide 24. I guess, I'll give you a statistical answer. I think, if you look at the 6 wells that we're drilling and we have the 50% chance of success, then most likely we should add three more producers to Mike and Kevin's portfolio to manage. And I would -- my anticipation will be that would be enough to do some level of expansion.

Great. That's really clear. And then, the third question was just around the gas contract you mentioned with Origin before. I'm just trying to understand 2 things about it. One, the extension that's available to Origin, is there a re-pricing of that, that happens with that extension? Or does it continue on at the same price? And then two, whether or not just in general there's a repricing event sort of 5 years in, like what we've seen with some other GSAs.

Yes, look, Andrew, we're not in a position to disclose the details of our gas contract with Origin to the market, unfortunately. So I think the guidance we've given on oil price [Indiscernible] is as far as we can go. So obviously, we're under confidentially restrictions on contractual terms.

Okay. Do they -- can you say how far in advance they need to tell you about this year extension?

That's obviously a contracted term that we can't disclose.

Your next question comes from the line of Mr. James Bullen of Canaccord.

Just a quick question. Firstly, around the impairment reversal. You provided us your oil price spec. I was hoping you could provide us with currency assumptions in there and also confirm whether those have real or nominal oil price forecasts. Morné Engelbrecht: So the oil price forecast is real. And the FX rate we used is $0.75.

Great. And obviously, you've been doing phenomenally well around the cash flow breakevens, coming in at $16 for FY '17. Do you have a target for FY '18?

Look, we don't say the specific target on cash flow breakeven. Our key focus, as you've seen, is to make sure, from an operating cost perspective, we can get those operating costs as low as we possibly can. And I think we've done a good job of that in the last 12 months. In terms of capital, what we've disclosed is that the bulk of our capital is actually discretionary in nature. So three-quarters of that capital is discretionary. And therefore, obviously fixed capital is pretty low, which is obviously helping our lower numbers from a breakeven perspective. So we tend to more so focus and manage around the components of free cash flow breakeven rather than that number itself.

Great. How much in the way of costs do you think you can squeeze out in your own-operated assets? You've obviously had quite a few years of that now. Is there much left at all?

I think we're pretty lame, frankly, James. I think, if you look at this on the national or international benchmarks, you're not going to see much lower than this. So I think, in our own-operated acreage, we're pretty well close to being at the limit, at the moment.

Great, thank you very much.

[Operator Instructions]

It looks like that's the end of the questions. I think we'll bring the call to a close. So again, thank you, everyone, for joining the call. Thank you, and have a good day.

Thanks, everyone.