Derek Piper - IR Reg Nelson - Managing Director Kathryn Presser - CFO Neil Gibbins - COO Mike Dodd - General Manager Exploration and Development

James Byrne - Citigroup Ben Wilson - JP Morgan Martin Kronborg - Credit Suisse Nik Burns - UBS Kirit Hira - Macquarie James Redfern - Wilson HTM Tim Masters - Canaccord Scott Simpson - GMP Securities

Good morning all. Thank you for joining the Beach Energy results call for the half year ended December 31, 2014. My name is Derek Piper, Investment Relations Manager here at Beach. And joining me today to talk through our results we have Reg Nelson, Managing Director, Kathryn Presser, Chief Financial Officer, Neil Gibbins, Chief Operating Officer, and other members of the executive and management team. This morning, we will firstly talk through our results presentation which accompanied the interim report this morning, and then we will open the lines for questions. So now I'll hand over to Reg to give an overview of the highlights for the first half. Thanks, Reg.

Thank Derek and good morning everyone. We’ll get to the slide deck in a minute but I’ll give the opening remarks -- despite the oil price, we have strong operating performance across all aspects of Beach’s business and that has really underpinned the results. We remained the lower cost operator in the Cooper Basin, we have gases as well as oil and gas in eastern Australia is not as effected by the oil price as other might think. So it does allow us to continue healthy cash operating margins. The clear important result of the half year was the record sales volumes, 5.7 million barrels oil of equivalents, up 2% compared to the previous corresponding period. Now to draw you now to slide 4. Of course, on the financial side, the sales volumes, record volumes of 5.7 billion BOE. Sales revenue 427 million, down 23%, but nevertheless despite the fallen oil prices we didn’t have an average realized oil price of AUD101 per barrel, it was 32% down from the PCB but nevertheless it’s still a fairly healthy number when you bear mind of course that that’s what our operating costs are in Australian dollars. Underlying NPAT, while it was down it was still $72 million and I think above many analytics consensus. Cash reserves $249 million and interim dividend of $0.01 which was declared by the Board. If you look at the slide you can see the sales revenue does exhibit an upward trend. Last year of course was a stellar year, we had flushed production from the Bauer Field which still continues to perform, but we did exceed our full cash production range from the Bauer Field it’s only sensible you came back to the trend, but the trend is positive and also I also refer you to the production figures on slide 15, it manifests itself there as well. Corporately, we farmed out interest in the Lake Tanganyika Block of Tanzania to Woodside. We farmed-in to ATP 94 with Drillsearch in the Cooper basin. We acquired 30% interest on the offshore Otway basin T45/P. I have a clear message that we are seeking to repurchase back on Australia particularly with the Eastern Australian gas market as a focus and of course the oil and other aspects of the Cooper basin. Slide 5, the half year highlights, production, while it was down to 4.8 million BOE it was still very encouraging. The Bauer Field in particular does perform. We had a four-well pad development campaign and results were much better than expected, and we expected some good results. We had new oil discoveries at PEL 91 at Balgowan-1 and Burners-1. The first Namur Sandstone discovery in PEL 104 and 111 at Martlet-1 and an 82 meter oil column at El Salmiya-6 in Egypt, all very encouraging results. Subsequently, we’ve completed Stage 1 of the Nappamerri Trough Natural Gas project. We believed we’ve met all the requirements we set technically for Stage 1, and also in terms of production and capital expenditure guidance, we've given some revisions there particularly because everyone will understand that CapEx is down. As we move to Slide 6, again, production guidance is actually moving very much to the top end of original range. The CapEx guidance at this stage reduced to 430 million from 470 million where we’re still looking at making prudent cuts to capital expenditure, but that’s 20% down compared with H3 FY15 spend as predicated. New Bauer Field pad development drilling envisaged, improved sales gas margins expected from oil-linked contracts with other parameters. We can’t of course give specific details about specific contracts, but let me say every time we entered into an agreement we ensured this very significant protection on the downside. That’s all prudent and sensible. On the cost side, I do think we’ll see some cost [deflation] in terms with service providers cutting costs. That will result in reduced CapEx and OpEx spend, I think, as we go forward through this period of low oil prices. We know that these low oil prices are not here forever we just know -- no one really knows when they will kick up. We do continue to review our portfolio, we are very firmly focused as I’ve said back in this part of the world as I mentioned farmed-out Tanzania, we don’t envisage any further exploration activities in Romania, and we have had divestment process with Egyptian interest that’s commenced. In that respect, some discussions are underway with interested companies and the data room opened. So all in all I think this is the time where prudently well managed businesses will survive as opportunities are found and I always as ever remain optimistic. With that I’ll hand over to Kathryn.

Thanks Reg and good morning everyone. Given that Reg is provided most of the high level financial information I’ll provide a bit more detail behind the numbers to allow more time for Neil’s operations update and for Q&A. Firstly, on Slide 8 as you can see it has been a challenging half year for Beach. This has driven significantly by the drop in oil prices but we came off the back of a recorded half year for Beach in half year ‘14. But whilst our reported NPAT has also been affected by impairment adjustments our underlying profit is still strong even with the significant reduction in oil prices as our ongoing expansion and our success in our Cooper Basin acreage continues to deliver and that was highlighted with our record sales volumes for the half year. And as Reg highlighted it clearly shows the strength of the company. Sales volumes were record 5.7 million barrels due to continued strong oil production from the Western Flank and higher gas sales from increased customer demand. The strength of the company has also resulted in the continuation of the half year dividend payment of $0.01fully [franked] and that is line with the previous half year with the record date of Friday, March 6 and payment date of Friday, March 27. This ongoing dividend stream well again we review on completion of our full year results. But I just want to give the right-down as sales revenue really on Slide 9 is fairly evident the drivers behind the decrease has been mainly due to the lower oil and other liquids prices and lower crude sales volumes. Our realized oil price was down 22% to 101 and gas and gas sales liquids sales revenue was up offset 1% to 111 million and this was mainly due to higher gas sales volumes. So on slide 10 you can really say the significant change in our underlying profit from the previous half year. The table clearly shows an ongoing increase in the underlying business and as mentioned previously with Reg said our half year FY14 was a record year for Beach and was driven on the back of oil prices, but when you compared the FY half year, FY12 and FY13 even if these low oil prices still an increase year-on-year. Now looking at our results and our gross profit for the half year was 140 million was down 52% from the previous year of 240 million and this falling gross profit was largely again as result of lower oil volumes. Low oil prices and high depreciation charges partly offset by lower third party purchases and lower cash production cost that was because of the removal of the carbon tax in this reporting period. Our cash production cost were down 6 million and what that does it’s reflect low royalty with a reduced sales review as well as the removal of carbon costs, but that was partly offset by a higher cash operating cost. However, we still continue to be a low cost operator with operating cost in total coming well under $30 a barrel including royalty and will offset DD&A increase in the half year as strong operating margins continued particularly in the Western Flank. In relation to our net profit for the half year other income of 11 million included 4 million of foreign exchange gains and in this we also had a 7 million unrealized gain on oil hedges which in this current period a quiet to an approximate unrealized gains $2 a barrel and these gains are already been realized in the second half of the financial year. So in summary our reported net loss after income tax for the half year ended December 31, of 79 million is 230 million lower than the 160 million profits for the previous period but again this was all due to impairment and lower oil prices. I just want to, now, just talk you quickly through the impairment adjustments. And as you can see on slide 11, the decline in oil prices resulted in the complete review of the carrying value of our oil and gas assets which is subsequently results of an impairment of earnings at Cooper Basin oil and gas assets and that was based on the prospect as you can see highlight on the slide. In support of the oil and currency price tick we’ve also used 8% pre-tax through discount rate using this price tick which we believe is conservative particularly in relation to the [indiscernible] exchange rate and using in area of interest approach the impairment has resulted mainly from Santos operated joint venture oil and gas assets which has risen as result of the large accounting value including our acquisition costs in this group of assets whereas our Western Flank oil assets continue to outperform. This may result in a reduction in a reduction in our DD&A cost going forward in the second half of the year but that is currently under review. So just on slide 12, I've provided a breakdown of our underlying profit, with the major adjustment to impact being impacted by impairment adjustments as compared to the previous half year. Whilst it is a decrease on our previous corresponding period of 54% again it's driven predominantly by low oil price. The additional adjustments in this period have been for our gains on a unrealized hedging as a result of the in-the-money oil floors at $65 and $70 going out to FY16 and mark-to-market gain on a convertible notes as a result of the decrease in the Beach offshore price and in the previous half year we backed our asset sales and that was made predominantly of the profit on El Salmiya, U.S. assets. So just in summary while the oil prices effected that result in comparing year-on-year Beach remains well positioned, we have strong cash flow in the second half which is expected to fund our expressions in CapEx moving forward and we still continue to have undrawn 300 million debt facility. With ongoing strong cash position our continued level the production and sales in the second half and lower operating cost Beach remains in a strong position to whether the oil price storm. I'll now hand you over to Neil to provide you the more detailed operational overview for the six months. Thank you.

Thanks Kathryn and good morning to everyone. We'll move straight on to slide 14 and take a look at our production performance in a bit more detail. As Reg indicated earlier, total net production for the half was 4.79 million barrels of oil equivalent that was just over 3% down on the previous corresponding half. Now oil production of 2.42 million barrels accounted for 51% of that total, so it's obviously pleasing to see that's holding up well. It was down 8.2% on the previous corresponding quarter where natural fuel decline was partially offset by that very strong performance that Reg mentioned earlier and higher than expected productions from PRLs 136 to 150 and just for those that they were formerly the PELs 104 and 111. That was really as a result of connection of the Martlet field and strong performance from the Spitfire field. Now sales gas and ethane production was up 4.4% on the PCP that's from 11 PJs to 11.5 PJs. The mix of this half was slightly leaner, hence total gas and gas liquids production was 2.2% higher at 2.37 million barrels of oil equivalent. For the SACB and Southwest Queensland JV's production increased to 7.1% was seen, countering a decrease in PEL 106 production, mainly due to natural fuel decline in the starting of the number one. Just not at the envy the production increased in Egypt again ahead of the completion and commissioning of the gas export line. So if we just move on to slide 15, you can see a graphical representation of the splits that I just talked about the forecast production for the full financial year. As we detailed on a quarterly call, we've tighten that guidance to 8.9 million to 9.4 million barrels of oil equivalent and that was at the upper end of the previous guidance that we supplied. And so as I said earlier it's pleasing to see that Western Flank production following so well with net oil production for a half averaging around 9,850 barrels of oil per day. It was also very active half on the drilling front with 71 wells drilled and continuing strong success rates. So as we foreshadowed though, drilling activity will decrease in the later part of this financial year and our continuing intake FY16 as a rig count drops across Beach's Cooper portfolio. This now takes us on to slide 16, and talking about those CapEx reduction side. At the time of that quarterly call we released our CapEx guidance for FY15 foreshadowing capital expenditure cut of up to 55 million or approximately 20% as you can see on this slide. We're not in a position yet to detail these any further than supplied at that time, but I will actually reiterate these savings are across most assets resulting in guidance of around 430 million to 470 million for the full year. When the sequencing of re-reductions and the scope of Santos operated reductions are finalized we'll inform the market further on these changes. At this time we're working through these reductions and assessing the impact on both FY15 and FY16 capital expenditure and we anticipate significant reductions that continue into the next financial year right across the portfolio. Primarily it's as a result of lower drilling activity and deferral of some infrastructure projects. And so if you move on to slide 17, I'll just talk a little bit about field development. In particular the recent pad drilling program where we drilled four wells Bauer 16 to 19 and as I said they were drilled from a single pad and to give you sense of savings realized from this sort of operation is effectively four wells for the cost of three vertical wells and 34 days to drill all four wells and a sideways rig walk from Bauer 16 to 17 completed in just two hours and were two of a highlights that we saw during that program. The operation itself went very smoothly, however we still believe there are a few tweaks we can make on the next four well pads improve that even a bit more. And that next pad, Bauer's 22 - 23 has already commenced and we'll look forward to seeing these results and incorporating the outcomes into a revised reserve assessment of the field. As it was highlighted previously the results for the first pad were above expectations, you can see that on the slide and we anticipate subject to the outcomes of the second pad, an upward revision to a field ultimate recovery. And that takes me on to Slide 18 and I would like to just give a quick update to the NTNG project. The recent wells and the results detailed quite well in the interim reports. I'm not going to go through those in full detail. We also made a release the morning on Boston-2 and also talked about the notification to Chevron at the completion of Stage 1 farming requirements. So following on just a bit of detail, following on from excellent fractious stimulation program at Boston-2 which is actually completed in 10 days, we undertook 8 fracs and it was a well done operation by Condor Energy. It was actually a bit disappointing that we’re unable to clean up wellbore in excess the stimulated signs for flow testing. It was particularly disappointing given the better [indiscernible] section we’ve see in some of the petro-oil formation in the wellbore. And having said that, these types of issues are not uncommon in early stage of unconventional and geothermal projects and we believe we can mitigate those by appropriate design changes as we move into Stage 2 and it’s very important though to look back at the program in total and review the objectives of Stage 1 as shown on the slide and the outcome certainly we’ve achieved through that program. And we set out to the final lateral and vertical extent at any place within the section. We drilled 18 wells, defining multiple clay types as well as a very thick and laterally extensive premium section across both permits. We've stimulated 16 wells clay gas to the surface while also testing various techniques to optimize the outcome. And two clay types, the Daralingie and the Patchawarra have been high graded on the basis on an early assessment of these results. That contingent results have also I mean booked and at the moment just going in the north and currently reviewing the results to provide an update of these numbers. So Beach is quite excited about the possibilities defined in Stage 1 program and certainly pleased that all the objectives of the programs at least set out at start of Stage 1 have actually been met. Chevron was advised Stage 1 of the PEL 208, timing was completed on February 13th and under the terms of agreement Chevron has 60 days from this break to advise Beach of its decision as to participation in Stage 2. And with respect to ATP 855 and the Stage 1 work program was completed in January of this year before this clay at Chevron is required to notify Beach as to Stage 2 participation by 31 March 2015. The Chevron had indicated to us that they really want to keep those two decisions together so we expect and have come from Chevron on that same time. And so following on from advice from Chevron, our approach to Stage 2 will be defined and communicated to the market when we can advise. That really takes us to end of the presentation and I’ll hand back to Derek and take some questions?

Thanks Neil, thanks Kathryn and Reg. We will now turn the line to ask the operator please to throw us the first question.

Certainly, we will now begin the question-and-answer session. [Operator Instructions] And our first question comes from the line of James Byrne from Citigroup. Please go ahead.

Good morning, I was hoping you could please describe the Company's outlook for unconventional longer term and if you can, just touch on your expectations of Chevron participation's in Phase 2.

Okay James, I’d like to handle that one, there is not a lot not we can say at this point with respect to Chevron. They have got their process running to make their decision and they will advise us as we got indicated and the slide indicated in the report, well, we can’t really say much more about that. We’ll then once we have that decision to fund the program going forward but as I said just a minute ago we’re quite pleased with what we've seen within the results so far and we would expect to further work. The quantity of that work we'll have to just wait and so. And also I suppose worth remembering too that we do have other areas that we’re working unconventional in Australia both in the outlying and front part.

Sure, and are the results to date at all indicative of commerciality or is it still too early?

It’s too early at this stage to indicate commerciality but as fact that we’re certainly pleased with the outcomes so far in Stage 1 where we weren’t looking at commerciality really we’re looking at if we could define the plays, start defining sweets spot and then take this program forward to start looking at the commerciality of the project.

Sure and otherwise, we've noted that your continued development drilling in Bauer more broadly speaking, how are the lower oil prices going to affect activity levels in the Western flank? Is the focus on growing the wells stock in your discovered fields and perhaps supporting exploration, therefore more meaningful reserves additions on the backburner?

Yes, look, it's always a bit of a balancing act with that. You certainly like to keep your development drilling going, we’re still in a pretty reasonable margin here on the Western Flank. We're still making good money on these projects. It's going to be a balancing act between doing development work keeping production up and also exploring and we expect to see a combination of that going forward but this part moving into FY16 budget and also signing joint ventures in FY16 as well and so as soon as we that better defined, we’ll let the market know the scope is sort of progressing.

Thank you. Our next question comes from the line of Ben Wilson from JP Morgan. Please go ahead.

Hi, good morning everyone, just -- I’ve got two questions. One, Reg, you mentioned some downside protection in the gas sales contracts that you have signed and will sign going forward. Can I just ask, do you have flaws in these contracts, in the oil link contracts? And then the second question is just about your balance sheet, your capital position, the convertible note, the potential redemption coming up in April and if you’re comfortable with your facilities, the undrawn 300 million, with or without the Chevron going forward this year? A -: Thanks Ben. First of all in terms of the first question as I’ve said in my comments specifically on particular agreement, those terms are all commercially confidential, but as I’ve said wherever we can we build in sufficient outside protection up and run to stay long enough to know we’re going through these cycles and it’s always good to have the buffer. Question two I might just get Kathryn to address that because --.

Thanks Reg. Yes, Ben just with the convertible notes given the market that we’re in at the moment, we’ve changed our accounting for the note as a burn from five years to threes so you would have seen an increase on the balance sheet of that carrying value with the expectations there is that put of course in April, that put type was opening early February and it will closed it’s a 60 days prior -- will close in the first week -- that will close next week in March. We’ve had not indication to that that note will be put to us. However as we’ve always done before we’ve got the 300 million available to us if that put does get put to it and of course, I mean the things are up as you know it does get put because the date is actually is cheaper than we’re currently showing the note as at the moment. However, what we’d like is obviously to have the note and that still we’ll keep the 300 million because opportunities do rise Ben, so we just go and watch with anticipation.

Got you, so sorry Kath, you mentioned the end date for the put on the convert?

The put time actually the April 3rd it will open sixty days prior, so it would open on the February 3rd and closes on the March 3rd. So the note holders have to put to the -- put those notes back to the trustee for that 150 million.

Okay, great thanks Kathryn and Reg.

Thank you. Our next question comes from the line of Martin Kronborg from Credit Suisse. Please go ahead.

Hi guys, just a couple of questions from me. The first are of course on the SACB JV. I’m wondering if you’ve given any ramp details yet -- is your forecast gas and gas liquids production indicative of that profile? I’m wondering why it’s down because I thought the entire point of the 2014 drilling program was to move reserves from undeveloped into developed so production could go up in 2015. I’m just wondering how you see your [indiscernible] going forward?

I’ll handle that one. I mean we were we were up on sales gas and methane. We did have a leaner mix which showed us a lesser outcome on gas and gas liquids. In terms of the SACB ramp up and production going forward you will have seen Santos’ announcements on rig reductions from seven to three and we are actually in the process now looking in production going forward and we can probably give you some clearer detail on that and when we get through the process looking at FY16 budget. As you’ll understand there is part of bit that goes into that, give further detail when we can.

Alright, well why don’t we stick with Santos guidance then, and they’ve downgraded their reserves of the SACB JV, and interestingly, as liquids buy a lot more than dry gas, or gas, I’m just wondering what’s your view on the impact of economics from that and do you agree with the reserve downgrade?

Yes, look, we foreshadowed some reserve downgrades quite a while ago and taken some of those on board already and we’re seeing the announcement that again we have to get further detail from Santos on that to see exactly where they’re coming from and we can talk more that when we get that detail. Look, in terms of the mix I think a lot of the downgrade was some of the [indiscernible] area, where there are reasonable level of liquids associated with that was their base, so I think that where you’re seeing those numbers there. In terms of economics going forward look at the economics on what we’re drilling in the contracts going forward and as Reg has talked about the origin contract that we have in place and with the level of fuller program that we’re seeing from Santos with reductions in raise I think we’re reasonably comfortable.

Thanks for that; last question from me is once again from one of your joint venture partners. At Drillsearch's result last week, they noted that their higher D&A cost is a result of a re-estimation of a cost going forward to develop their 2P oil reserves. Just wondering if your higher D&A is for the same reason and why, in your view, cost to develop your 2P reserves of oil -- I'm assuming it's PEL 91 -- are going up?

Yes, look, not sure that cost going up in PEL 91 I suppose over time, cost of production will change as your fuels decline but at this point in time our cost on PEL 91 are pretty stable. Our operating costs are pretty -- extremely low in PEL 91 in particular. Once you take tariffs and tolls out of your costs there, you're talking a few dollars in terms of cost so it's very low and so I'm not sure where that one is coming from.

And the same with capital cost going forward I'm it's not expected to increase significantly.

Yes, of course they do have other assets other than PEL 91.

Mature assets like Tintaburra.

So your D&A increase is not related to PEL 91 costs, going forward?

No, that's how we've read it, they had similar DD&A cost as us, and on their presentation they separated out their Cooper Basin and the Western Flank. And the Western Flank assets DD&A was the same as us.

And also on cost they have different tolls of us.

Yes, well thanks for sorting out those issues again, thanks very much.

Thank you. And our next question comes from the line of Nik Burns from UBS, please go ahead.

Yes thanks, look just on your oil exploration to date in FY15, just wondering how you think you're tracking relative to maybe expectations of your ability to replace production this year. Do you think with the remaining work program in place -- and you've flagged potentially higher reserves in the Bauer field, whether you could replace your production volumes this year?

Looking at this, we'll be able to answer that at the end of the financial year, but certainly we're tracking quite well on Bauer. But I'd like to wait until after we done the next four well pads and then we'll come out with some numbers on Bauer. But we think we're going to see some upside there and we've had those early discoveries that Reg has mentioned. So, we're sort of on track at this point in time.

Just a reminder, do you have many oil exploration wells remaining in FY15?

We're discussing that at the moment I think we've a couple left in PEL 92.

PEL 92, a couple of exploration [indiscernible] well in the JV budget which is still to come as well as a couple of development wells.

Okay that's great. Look, just one other quick question, November you flagged that you've got Rob Cole starting I think June 1. That date could potentially be brought forward. We all love Reg and we want him to be there forever, but just wondering if there's any chance Rob might be starting earlier than that June 1, date?

There's always that possibility but the Board's intention and my intention is that we'll be seamless and in particular because we have a great team here that you can rely on. So, this is as usual no matter what the date is.

So at this stage it's still June 1?

At this stage it is yes.

Fantastic, thank you guys.

Our next question comes from the line of Kirit Hira from Macquarie, please go ahead.

Morning Reg, Neil and Kathryn, just a couple of questions, regarding the impairments surrounding the SACB assets. I appreciate that there are some different assets in that bucket, but Santos were fairly clear that it didn't relate to any of their gas assets, purely really the oil assets. Whereas I think Beach commentary suggested that some of the oil assets were impaired. Just wondering if that comes down to a more bearish view on the actual gas assets or whether it's purely related to, I guess, differing commodity prices. I would have assumed that the Origin gas sale agreement would have been a bit better than the Horizon agreement, so perhaps not the commodity price, more so a view on the asset?

Yes Kirit, it's a combination of all of those I mean as you would have seen in our announcement we use the same price deck, I mean we have different carrying values and I mean Santos and us, we've obviously got a larger acquisition base in our gas assets than they do and it's probably they're a little bit more bullish on the forward projections than we've so perhaps we’re little bit more conservative than they're in that aspect in relation to their gas assets. So there is sort of a combination of -- but I did ask that question back to the Santos as well as to why the difference and we did -- we're in the process of reconciling.

Second question from me is relating to the unconventional, just wondering what the chance is that the deal could be somehow restructured for Phase 2. Obviously in the current environment maybe what was proposed when the deal was originally done, doesn't quite make sense -- whether the carry could be phased over a longer period or reduced? Also, what's the current book value on the exploration and valuation assets for the unconventional assets today?

Listen, I'll take the first bit there, in terms of any negotiations with Chevron or any position on the situation going forward in Phase 2 we've had no discussions on that front. We will just wait and see what Chevron come back with. But at this stage they have a yes or no decision to make and we’ll wait for their advice.

And just the book value?

We don’t put that out Kirit but you’ll be able get that -- you’ll see account of their assets exploration assets on our balance sheet.

Thank you. [Operator Instructions] Our next question comes from the line of James Redfern from Wilson HTM. Please go ahead.

Good morning everybody, just -- I just want to understand the mechanical down hold issues at Boston-2 a bit better because, from memory, the Boston-1, 2 and 3 wells had mechanical issues 12 months ago and that's why they were delayed by a year. I just want to understand those issues a bit better, thank you.

Yes, I suppose the thing to mention on Boston 2, is we changed our casing partway through program and the casing on Boston 2 was the older P110 casing which didn't certainly perform as well as the casing we used in the later on the program, and but really there is a restriction down the borehole. These restrictions that we’re seeing in some of these wells are occurring near our perforations for the fractious stimulation jobs. And then they’re not uncommon in programs in geothermal in hot pressure and hot temperature wells and also in the U.S. they are not uncommon as well particularly early in the phases of these programs. We just think that in Stage 2 and beyond and we can mitigate these quite well by redesign of casing and just well design in general. So it’s a bit disappointing that these issues have occurred but I think going forward there are points around this what we can negate it.

So just to be clear, the issues really relate to the high pressure, high temperature environments that you're having to deal with there at circa 4000 meters depth?

I wouldn’t say it’s totally that case because we’ve seen examples of these sorts of issues over in the U.S. and much lower pressure and much lower temperatures. So we’re looking into the exact cause of these things at the movement. We have some trends in our mind but we think we see in the data that we’re looking and for this point I don't want to go into that any further. Those are things that we think really neatly discus with the joint venture level before we talk about in public.

Thank you. Our next question comes from the line of Tim Masters from Canaccord. Please go ahead.

Yes, good day guys. I just had a quick question on your production guidance for the second half. You're pointing to a 4% to 13% decrease in your gas production. Santos in their half-yearly out on Friday, they just talked about a major scheduled maintenance in Moomba in Q1. Can we assume that most of that production decline in the second half is in that Q1 period and then you'll ramp back up in Q2?

Yes, we’re looking at as well and we do see a reduction in January on the basis of that and I would expect original amount of that is associated with it. Of course with February being a shorter month as well and you will see a bit of reduction in that month.

Okay. So we should expect a bigger reduction in Q1 and then a jump back up in Q2?

Yes, I look -- that will probably be the safe. I haven’t got the numbers in front of me, but usually with February being -- February is always a lot of the normal month.

Okay. And then in your deferrals or in your CapEx savings for second half is there any deferrals of any exploration or development wells which you had planned that you've cut out of that number?

We’ll wait -- ourselves and our operating environment we’re dropping back to one rig as soon as we finish the Bauer, the Bauer pad 965, we’ll finish up for us. At this stage our 930 we’re holding with what we had forecasted, but obviously we need to talk with our joint ventures about that where they’re sitting in terms of the CapEx.

Okay. So can we assume that you're still drilling all the wells that you're looking at so potentially the deferral comes from things like Stunsail and Pennington development? Is that being pushed out maybe into FY16?

Yes, we’ve got some deferral in FY16 in some of the facilities work. But that’s we’re trying to manage it at such that we don’t really impact on production too much, so it’s just a case of managing the CapEx gong forward and sequencing things right so we still maximize production and minimize the CapEx expenditure.

Thank you [Operator Instructions]

Derek again I think we might call in or we might have one more question there from Scott.

Yes, I’ll just the line from Scott Simpson from GMP Securities. Please go ahead. Excuse me the line for Scott Simpson, you’re line open. Please go ahead.

Sorry, I was just on mute there. If you could just remind me, just looking at development CapEx for SACB, South West Queensland Joint Ventures. Just some rough guidance I guess on what's maintenance CapEx there, what's CapEx in -- I guess for undeveloped reserves and I guess also just Western Flank, just a quick reminder on the split there as well.

I think I’ll hand over to Michael on that one; he has got a nice spreadsheet here.

I’m only going to talk really rough numbers here, Scott because as you know we’re looking at the budget right now. I guess if you look at the major development in expenditure and of course what we told before is we might have different classifications to Santos, so if you’re trying to reconcile that to Santos you might some discrepancy there. But I guess what reason we call maintenance versus development there -- I think what we call development is probably in order to 2/3 of the expenditures to 3/4 and that’s further development in some facilities work and some of the facilities work we would say is just maintenance site work as well.

Sure. And just in the Western Flank, we just chatted briefly before on Drillsearch's guidance on additional development cost relating to undeveloped reserve. What's the best way to think about development costs for these reserves versus maintenance CapEx?

I guess we were classifying most of that development on the Western Flank we classify as development we’re seeing in business capital, but most of the money we’re spending there capital-wise is on facilities of expansion such as Bauer and getting the [front] sale and Pennington projects going. So much -- the majority of that, we would qualify as development rather than stay-in-business

Sure. And just quickly, just in terms of the upcoming program, I think you flagged some wells, some drilling in PEL 92. If you could just add some color around I guess the development wells there and I think there were some -- a couple of exploration wells in PEL 91 to come as well. Have you got any details on those?

Yes, in PEL 92 as far as the joint venture budget goes, we’ve got a couple of exploration wells still for financial year and one which -- and another we classify as appraisal -- cost of development was -- these are all subjects of joint venture approval, we -- in terms of the development that we just asked about, we’ll say one of those wells on the Callawonga field subject to JV approval and one to come from one of the other fields, possibly [indiscernible] or Butlers.

Excellent. And in PEL 91, was there any exploration coming up?

We’re drilling that in exploration in PEL 91 right now.

Okay.

Potentially followed by second one and then we prepare another appraisal well following that.

I’ll wait on the results of those. That’s all I had. Thanks very much.

Thanks Scott.

Thank you. There are no further questions at this time. I’ll hand the call back to Mr. Derek Piper.

Thanks a lot. Again thank you everybody for joining. Have a good day, and obviously we’re here to answer any further questions. Thank you everyone joining.