Chris Jamieson - General Manager, IR Reg Nelson - Managing Director Kathryn Presser - CFO and Joint Company Secretary Mike Dodd - General Manager, Exploration and Development

Dale Koenders - Citigroup Mark Samter - Credit Suisse Nik Burns - UBS Kirit Hira - Macquarie Krista Walter - Morgans Tim Masters - Canaccord Wealth Management

Thanks for that Vincent and welcome everyone and thanks for joining us today for the Beach Energy FY14 Preliminary Full Year Results Call and Webcast. So today we have three presenters, firstly, Reg Nelson, our Managing Director will take us through a general overview then that will be followed by Kathryn Presser, who will talk to the financial section and then we will have Mike Dodd, our General Manager of Exploration and Development, who look at the operational side of things. So, we will start off and I will pass over to Reg.

Thanks, Chris. Thanks everyone and welcome in the interest of continuous disclosure, I advise that I am impaired today, I am just recovering from the latest thing that’s going around and Neil Gibbins, our Chief Operating Officer has just been struck down by the very same thing. So bear with us and if I fault, someone will jump in and help me out, I am sure. Just going to Slide 4 in the presentation to start on with discussion. The share price performance I think speaks for itself. We strongly outperformed our peers in FY14 and certainly the energy and all ordinaries consistently over the past four financial years. Shareholder return has really been our key focus and that hasn’t changed and I will refer later to the investment criteria that we will continue to emphasize to enhance portfolio returns. Just moving to the overview on Slide 5, outstanding FY14 performance and obviously driven by the Beach operated oil business. That’s resulted again in the very strong balance sheet and clearly we see potential to fund CapEx until the end of FY16 that’s been consistent with our performance over the last few years. The oil linked GSA with Origin is set to commence in FY15. The Nappamerri Trough Natural Gas exploration program is on track for completion of the Stage 1 exploration phase at the end of Q1, 2015. We are also advancing the review of all international assets and, in fact, that really includes all assets in our portfolio and that is because we want to ensure we have got efficiency in capital allocation over the medium term. As part of that, we have looked critically at Egypt. We have decided to do some impairment there. That said, it is an area where we have entered mostly at ground floor and added significant value particularly in the Western Desert area. And we have got now entry into some very good prospective areas that are historically underexplored. Nevertheless, we want to realign the strategic focus and we want to move key projects towards commercialization because we want to start focusing on reserves production revenue and profitability as the key drivers for everything. Having said which, Slide 6, financial overview, gives a pretty good summary of this year and certainly something for us to be proud about. Record revenue sales of AUD1.05 billion, record underlying NPAT of AUD259 million, record operating cash flow AUD583 million, still ended up with a good cash balance of AUD 411 million at the end of financial year. Ability to take the dividend to AUD$0.04 per share which is up 78% and we still of course retain the $300 million secured debt facility. Operationally on Slide 7, the safety record remains excellent but, in fact, we reduced the low injury frequency rate for employees and service providers. Production, again record production, up 20% to 9.6 million Boe. Western Flank production remained in excess of 10,000 barrels a day for the full year. 122 wells drilled with the success rate of 85%. The expansion of the Bauer and Pennington fields, the new field discovery at Stunsail. I’ll just remind you in terms of reserves growth, these fields do tend to grow upon appraisal, Bauer I think is a significant example. Pre-drill, we have carried 500,000 barrels for Bauer 1. Post field reserves for that field was 1.5 million barrels, now we are up to about 12, 13 and we have 12.6 million barrels ultimate recovery at this stage. So, pleasingly, we are starting to see new trends emerging there particularly through the Pennington, Stunsail area and so in other words we still think there is a lot of life and prospectivity in the Western Flank. This year we will be addressing some of the in-board stuff that we haven’t pursued just quite as much as the out-board stuff but in-board towards Moomba [ph] where we made our first discovery at Senex [ph]. And so that will be part of our focus this year as we will focus on some new areas Tookoonooka and other areas in the Cooper, or hopefully more Western Flanks. These are largely unexplored areas but we think they have great potential and hence we want to refocus, rebalance the portfolio and get after them. In terms of the unconventional PEL 218, the significant thing in the Nappamerri Trough Natural Gas project on the service volumes on the South Australian side is we now have long-term tenure with a fairly low commitments to retain those areas. This is crucially important, it allows us to chase the sweet spot and still hold a very large area and we’re well underway to doing that also in Queensland and have deferred license conditions for two years while they address it in much the same way. The Nappamerri Trough Natural Gas exploration program is again in line with the farm-in agreement timing for stage 2. Subsequent of it was the farm-outs to Woodside of the Lake Tanganyika area. That really is our first step in terms divestment of refocus enough to the international portfolio. If I then move to slide the asset portfolio review. Portfolio always have to be dynamic and they have to be managed dynamically. The new dynamic really is the Eastern Australian gas situation and high price of gas and so really whereas previously we’ve focused in terms of oil potential as better NPV per BOE when you have gas prices with large volumes that’s a critical factor in terms of both NPV per BOE and volume. So certainly we’re looking at certain assets for divestment to ensure that the asset portfolio has aligned with the strategic outlook. Probably most of that would be to look at the international assets but was certainly continue to look at whole assets. It does come down to opportunity and timing and I think if you look at our track record, we do have an active history of non-core and most particularly value driven divestments and investments. Tipton West low cost entry, AUD$35 million to drill, dewater 80 coal seam gas wells, later sales for in excess of AUD$350 million. The Maryborough Basin and Surat Basin permits more recently the Gippsland onshore and offshore, internationally Albania, Spain, USA North Dakota a small entry to North Dakota invaluable earning from it but also a very profitable in the sense of our original investment, divestment. The recent portfolio optimization reflects strategic priorities I mention of course the farm-out to Woodside, the relinquishment of Mesaha block in Egypt, the farm-ins to ATP 924 and ATP 732 goodwill potential in the Cooper. The Cooper Basin deep gas farm-outs to Chevron and more recently the Offshore Otway Basin farm-in to T49/P. Again that’s particular move is to start looking at major long-term prospects to address the Eastern Australian gas market. So the investment criteria to enhance overall portfolio returns fully emphasize capital efficiency and allocation. Production and reserves both, free cash flow generation and the right sort of internal rates of return. At this point I’ll handover to Kathryn. Thank you.

Thank you Reg. Good morning everyone. To echo Reg’s word FY14 has been an outstanding year financial and operating performance. We’ve achieved record for sales volumes, revenue, operating cash flow and underlying NPAT. Today’s sets of results marks the third consecutive year of significant growth for the company and this morning I’ll provide highlights in relation to our record results for FY14 and I’d like to spend a little more time behind the supporting and underlying numbers. And as you can see on slide eight, Beach continues to report record results with another year of record sales revenue and record underlying profit and that underpins a strong balance sheet. As you can see on slide 11, as a result of the significant increase in revenue we’re also passing on the rewards to shareholders with another increase in a final dividend. FY10 and FY11 dividend we had around AUD$0.0175, we went up to AUD$0.0225 in FY12, AUD$0.0275 in FY13 and now with further $0.02 dividend this year takes the full year fully franked dividend up to a record $0.04. All these dividends returns continue on the same trajectory. We hope to maintain similar levels of dividends in future years and we’re always looking at capital management initiatives. Any buyback on further special dividends will be selling that the board will consider in due course however unbelievably unlikely at this stage due to the activeness around capital expenditure program over the coming years. However, I’d expect to see similar dividends coming forward in future years. Just moving on to sales and revenue. Sales and revenue, when comparing sales revenue year-on-year all of the drivers have been in FY which you can see on slide 12 including volumes, third party, FX and process realized. As you all know it’s been a record sales revenue year for Beach. Moving forward, which we want to focus on a core system results, slide 13 is a record underlying profit. Beach continues to build on its promises that it made to shareholders and investors back in FY12 that it will continue to grow the company which was the major year of step change back in FY12 for Beach. We continue to be a low cost operator with production cost and transportation and tolling coming in at well under AUD$20 a barrel for FY14. However, this has been offset by an increase in royalty costs due to increased sales revenues. And with a continuing strong Aussie Brent oil price realized year-on-year of AUD126 Beach’s underlying profit its core business continues to grow and fund its capital expenditure portfolio and this year it’s realized in the order of gain of $100 a barrel. The full year gross profit was 78% higher in FY14 and this was driven mainly by 51% increase in sales revenue offset by higher royalties and depreciation as a result of increased revenue. In comparing the full year results year-on-year, key drivers mainly of our higher sales revenue as I’ve highlighted previously, higher third party purchases to accommodate the significant increase in sales revenue offset by high depreciation as a result of increased production. Just want to just highlight and have a look at underlying profit on slide 14. Beach has reported a record underlying NPAT of 259% (sic - see press release "AUD259 million"). However, we have reported a 34% decrease in impact of a AUD$102 million as compared to AUD$154 million for the previous corresponding period. While also being substantially an increase in gross profit as a result of record oil revenue from the Western Flank oilfields this has been offset this year by payment adjustments. And when we look at comparing our NPAT to our underlying NPAT, we add back the mark-to-market on the convertible bond as a result of increase in our share price year-on-year. This was up from AUD$13.5, 30 June, 2013 to a $1.68 at 30 June, 2014. We removed asset sales which are primarily the gain on sale of our U.S. assets. And then we offset it by impairment and that includes payment adjustments this year. We have a AUD$148.5 million for Egypt and our geothermal assets for AUD$13.6 million. Beach has an internal impairment review twice a year in which we consider of Beach assets using the area of interest methodology. When we came to Egypt, there were a number of triggers in the Egypt area of interest this year and that included the relinquishment of the Mesaha Concession, Wadi Abu Had block was released. The final exploration well in the North Shadwan block was drilled and failed to encounter any significant hydrocarbons and this exploration license expired. We continue to explore in Egypt in the Abu Sennan Concession in the western deserts and we also be undertaking significant exploration in the El Qa'a plain, which will include 3D seismic activity. Whilst it continues to be ongoing significant exploration program in the Egypt area of interest which if successful would still recover the carrying value. We’ve decided this year to impair the carrying value to the NPV of our risk mean outcomes in this area. So upon normalizing the results Beach will still report a record underlying profit of AUD259 million reporting again I would like to emphasize an 84% increase in the underlying NPAT which recognizes the significant increase in the underlying business. So in summary on our financials, Beach continues to build year-on-year on its underlying business. We cashed up with AUD411 million in the bank. We have referral of AUD300 million finance facility that can be drawn upon at any time. We have significant future cash flows which are expected to funds its operation and capital expenditure moving forward in FY15 and FY16. And as mentioned before, it’s rewarding its shareholders this year with a significant increase in dividend to a $0.02 per share final dividend fully franked to all shareholders on the share register on Friday the 5th with a payment date on Friday the 26th. So on that note, I will now hand over to Mike to run through in more detail the operation highlights. Thank you.

Thanks Kathryn. First I’ll address production and on slide 16, FY14 its fantastic production year of 9.6 million barrels made up of about 5.1 from Cooper oil and 4.4 from Cooper gas and gas liquids of which around 11% was from the Beach operated operation in 106, and at about 0.1 from international made up of production from North Shadwan and Abu Sennan. This is 38% up from the previous year and the Western Flank produced more than 10,000 barrels a day for Beach, for the entire year. This was driven by oil development and bringing the Rincon field online and the Spitfire field in the Senex operated areas. Its worthy of note that 91% of our oil from that area transported by pipeline shows a good surety of supply to that infrastructure. Moving on to the forecast for FY15, our guidance is a range of 8.6 million barrels to 9.4 million barrels. The forecast on gas is recently flat but we are forecasting a decline in oil. However, we moved strongly into the, entered the new financial year with Cooper oil at 107% of budget in July and the average net daily production of over 30,000 barrels of oil per day. The natural decline on the Western Flank is as we expected from these high water drive fields with increasing water cut and we must remember that last year had the flush production from the Bauer field which is their largest field on the Western Flank to-date. This decline was offset by new wells at Bauer, expanded facilities at Bauer. We have got new fields to come online at CKS, Stunsail and Pennington and we have also got the recent Balgowan discovery which is to come as well. During the year we will be looking at all ways to accelerate facilities work in order to accelerate this production. Moving on to Slide 17, CapEx, firstly looking at the Cooper Basin non-devo [ph] area, we are predicting a CapEx there of AUD$55 million to AUD$60 million with up to 13 Western Flank development wells. Some detail on that 23 million to be spent in PEL 91 on barrel expansion and water injection trial and expansion of the Kiton [ph] facilities, Pennington and Stunsail facilities projects, six power development wells and some artificial lift as CKAS and Hanson. Also 21 million in PEL 92 with facilities upgrades at Callawonga, Parsons and Butlers. Three development wells slated there. Some artificial lift with ESPs at Windmill and Butlers and production optimization. In the SACB/SWQ area for development, looking at a range of AUD$270 million to AUD$300 million, around AUD$10 million of that is on oil, the rest on gas. By our classification, we split that in numbers around AUD$60 million for stay-in business development and AUD$710 for new developments. Of that AUD$210 for gas development, we are looking at about half of that being on drilling activities and there will be about 70 or 82 wells during the financial year. The remainder is on plan of which about a third of the 210 would be plan and the remainder is on the field area work such as flow lines and compression. The major expenditure of plan is carbon dioxide train and a Big Lake facilities expansion. Development, also 10 million in international area, I guess pipeline project in Abu Sennan which will facilitate unconstrained oil production from that area and three development wells at El Salmiya. Moving onto exploration CapEx, so the Cooper Basin operated and Senex 50 million there with 23 to 26 of wells expected, including five gas wells with the balance oil exploration plus 500 kilometers of 3D seismic in PEL 91 with the Solidus [ph] survey. Cooper Delhi, modest effort 5 million and we are looking at around four wells spread across gas and oil. And the unconventional area, an expenditure of 50 million to 55 million and main expenditure will be the fracture stimulation campaign in ATP 855 which will be commencing in the next few weeks. In international, we have got 20 million to 25 million of expenditure and that will include around six wells, so three drills in Abu Sennan area plus seismic in El Qa'a plain also in Egypt, Romanian drilling and New Zealand. Moving onto our Slide 18, looking at our reserves and contingent resources. We have got 2P reserves of 86 million barrels of oil equivalent and 2C resources of 467 million barrels of oil equivalent. And just to put a little bit of color on some of the movements. In terms of the Santos operators section of our reserve base, they’re 2P down by the equivalent of FY13 production and that’s because we are doing an internal study on the reserve base there and we are not making any changes to the reserve base there until we have concluded that internal study. In Beach operated areas, we have additions at Bauer, Pennington, Stunsail, Callawonga and Butlers and those are a combination of exploration and appraisal success in drilling as well as production performance that’s been offset slightly by decrease on the Western Flank gas due to production performance and revised treatment of fuel gas and economic cut offs. In the Senex operated area 104/111, we’ve taken additions due to successful appraisal at both Spitfire and Mustang and slightly offset by downgrades at other fields. In Egypt, El Salmiya increased by 1.2 million barrels due to successful appraisal drilling again and also strong production performance the USA reserves have been taken off the books as we’ve divested those assets in FY14. Moving on to resources, in the unconventional part of the resources, Beach operated, we’ve taken an increment there of about 55 million barrels of oil equivalent and that’s based on D&M report which takes into account new data from wells Nepean, Marble, Streaky and Dashwood. On the Delhi side of the unconventional, we’ve taken a decrease of close to 12 million barrels of oil equivalent and that’s due to changes in some technical assumptions is in those calculations. Conventional resources reassessment of the Greater Tindelby [ph] and BMG assets have given us a decrease in the conventional resources. So, if we compare that reserve base to last year, so 86 million barrels of 2P compared to 92.7 you see an effective reserve replacement. Bear in mind that this is a fantastic production year, so we’ve actually produced the biggest amount of our resource base that we’ve ever done. Now, in terms of what we have done and in terms of reserves replacement, the best ratio of resource replacement is in our most profitable area in the Western Flank. We’ve also seen growth from fields in that area and we would expect to see further growth, so there is a tendency in this Namur field the bigger fields actually keep on getting bigger as Reg alluded to when talking about the Bauer field reserve history. We’ve had exploration success already this year at Balgowan and we’re expecting logs from the Burners-1 exploration well today actually. From the SACB side, we probably cycle a little conservative approach there. We don’t do any bookings from desktop studies we’re actually wait on our well results before we come forward and put reserves there. So the reserves replacement ratio is being addressed. We’ve got a focus on value per barrel. As Reg mentioned, we’re expanding into underexplored areas. The Western Flank has been very kind to us and we see technologies there with the areas we are expanding to in Queensland in the Tookoonooka and 924 which we’ve farmed into with Drillsearch. Those are underexplored all the prime areas, so we’re hoping to build up a similar business to what we’ve got in the Western Flank. We’re also looking inboard of the flanks and expanding our exploration for plays other than the Namur, such as the Patchawarra and the Birkhead. We’re also addressing new plays in the 94, 95 area with gas exploration at the Davenport well in 94. We’ve just drilled a well in the Bonaparte Basin at Cullen with some encouragement and we’ll be looking to drill a conventional target in the Otway basin this financial year. So moving on to my last slide, looking at some key activities for the year, firstly the operated Western Flank we’ve got a really active exploration appraisal and development drilling program for the year with about 15 exploration and appraisal wells planned around 11 development wells across 91 and 92 plus the extra 3D seismic 500 plus square kilometers at Solidus [ph] which I mentioned previously. We’re on the fourth well at the year which has been as I mentioned which will be logging today. We’ve got six Bauer development wells planned so we’ll also see the onset of some pad drilling this year as well. In the Senex operated areas we’re on our third exploration well at the year so far at the rest of the program isn’t clear that’s been debated by the JV at this point. But we planned four exploration wells during the year in PEL 106 and we’ll actually the gas exploration well in PEL 91 to start that campaign at Karrata which the rig is moving to as we speak. In 94, we’ve got the Davenport well, which we’ve just have actually stimulated it and flowed and that’s shutting now for some further testing later in the year. I mentioned the couple of farming areas in Queensland and we had to drill a well in each of those before the end of the financial year. The SACB and Southwest Queensland joint ventures. We’ve got active infill and development campaign and facilities work and these will be going on full year as I described in the CapEx section. The unconventional part, really exciting times now we’re moving into a fracture stimulation campaign in Queensland with a new provider Condor Energy. So we’ll be doing four wells back-to-back there and then with JV approval we’ll move back into South Australia and do some extra work in PEL 218. As I mentioned in the outlay we’ll be drilling a conventional target. Egypt has got a gas production project which will aide oil production and developments and exploration drilling and Romania one or two wells further drilling in Romania. Probably also worth drawing your attention to announcement by Santos’s well with Lasseter discovery over in Browse Basin which actually had 7.3% interest in WA-281 and a Santos release shows that Lasseter discovery expanding into the WA-281P and the discovery was described as material by Santos, hopefully that’s also good news for us. And with that I’ll hand back to Chris.

Thanks Mike. So that ends the formal presentations of the call. So Vincent, if we could open it up to questions now that’d be much appreciated.

(Operator Instructions). Your first question today comes from the line of Dale Koenders from Citigroup. Dale please go ahead. Dale Koenders - Citigroup: I just had a couple of quick questions on your unconventional work program. I notice you don't have any appraisal wells planned for this year. When do you expect further drilling to occur? Secondly in terms of the fracture stimulation and production testing program that's coming up, what sort of results are you looking for from this? Are you looking for IP rates that are consistent with commercial flow rates, or is it more about decline rate and just getting gas to flow still?

First question, Dale we’d expect to see drilling in early FY16, not this stage of the program, the fracture simulation campaign in Queensland for working 218 and some processing of those wells. I guess what we’re looking for with that stimulation campaign is we’re isolating some of those lines that we do not necessarily fracture stimulate in the whole wells. So we’re looking at performance from individual sides within the wells. So what we’ll be looking at is how each of those performs in terms of IP but more importantly decline rates. Dale Koenders - Citigroup: Are these zones where you think the most productive intervals are, or are those intervals still to be tested?

We haven’t discounted any zones yet, Dale, we’ve got encouragement from every single zone we’ve looked at so far. So what we’re just trying to differentiate between them and then we can then we can prioritize them in terms appraisal going forward. Dale Koenders - Citigroup: Can you provide an update to the Chevron in Phase 2? When’s that decision need to be made?

The farm-in agreement that they need to make a decision in Queensland by the 31 of March 2105 and we would expect the decision on 218 and to that. Dale Koenders - Citigroup: Okay, and then just one other quick question. In terms of the impairment in Egypt, can you please provide a bit of colour as to what assets you've impaired? Is it all Mesaha, or is that North Shadwan carry tally as well?

We’ve looked at as whole Egypt we trade as area of interest. So what we’ve looked at value is remaining. I mean particularly the NPV of the two remaining areas which of course is El Qa'a and Abu Sennan. So with NPV we looked at the risk cash flows. So effectively we’ve risked the whole area of interest to bring in line with the remaining areas that we’re exploring in.

Your next question today comes from the line of Mark Samter from Credit Suisse. Mark please go ahead. Mark Samter - Credit Suisse: A couple of questions if I can on the SACB JV. Santos talked about on Friday their expectations across oil and gas of net to them about AUD500 million a year sustaining capital going forward, once the infrastructure expenditures occurred. I guess reading that we can just divide what they spend by three to get to your number, but I know you spoke about the AUD60 million to AUD70 million number there but at different definitions to sustaining CapEx. For you guys if you divide that number by three -- let's say you're at AUD150 million, AUD160 million a year, do you think that's your expectations of what you need to spend on an ongoing basis post the infrastructure investment to keep production at that new level?

We’ve gone through our budgeting process this year and made forecasts of what it looks like, what we think it looks like over this year and the next five years. Different people who have different definitions of what’s [indiscernible] business and what’s development. But if we combine the two of those across the gas business we’ll probably be looking at an average around 200 million a year. Mark Samter - Credit Suisse: Okay. And then that to you obviously?

Yes, we have. Mark Samter - Credit Suisse: Okay, thank you. I guess if we take that a step further that's a reasonable amount of your capital budget every year deployed into that asset. [indiscernible] your assumption on the gas price, you wouldn't be saying it was fantastic value accretion obviously with the asset portfolio rationalisation I'm just curious if the SACB JV drops into that when -- I don't know how to say this tactfully -- there are incentives of other asset owners where perhaps they've got a shortage of gas in their other assets that can benefit from this being gas and there's a necessity for them to develop more gas whereas it may not necessarily be the case for you guys. Is it a core asset to you? Or do you think it is something that could slip into the non-core category? And does it belong more in other hands?

Mark, Reg here, as I mention all assets are under review and this would certainly include joint venture in the Cooper Basin with Santos and Origin. That said, we go to an extensive internal budgeting process particularly in relation to CapEx. As Mike has indicated the conventional gas business is expected to underpin the future gas sales to both Petajoule and Origin but there is certainly a very strategic value in terms of the Delhi business the third party to remember which goes year-on-year. There are very significant PRRT credits about $800 million unrecognized PRRT offsets which are in the accounts if you look. Now really that means we don’t pay PRRT on the Western Flank oil it’s a very significant component. So if you look at roll out development in sustaining CapEx the business unit is valuable to Beach and how does that fit in terms of other opportunities that’s if certainly looking at very closely this year as point out certainly other parties that might see extra value in this, but expects all to be same. We’ll just simply go through the careful exercises we rebalance the portfolio and look for the new dynamics with the new opportunities in the right timing. In terms of the joint venture we do have certain rights which we may exercise if we see that there uneconomic developments going on, we won’t be dragged into things like that. Of course I can talk about nature of those rights, but we certainly do have them. So we’re very focused, we will certainly take the advantages out of the Delhi business as I mentioned in relational to the Western Flank oil and the other critical components, but certainly everything is under review.

Your next question today comes from the line of Nik Burns from UBS. Nik, please go ahead. Nik Burns - UBS: Look just a couple of questions from me. First of all just the flagged asset sales, just looking at your accountancy, you're still carrying AUD200 million in segment assets for international, I'm just wondering going forward if you do decide to divest some or most of your international portfolio, are you saying that you think that the NPV of your portfolio internationally could be close to that level and therefore we should expect those sorts of numbers coming forward? Or should we anticipate there could be further impairments?

Nik its Kathryn I mean that’s a common that’s what our expected value is and that’s where we look at each area because it included and there you’ve got Tanzania, Romania, Egypt, so the whole combination of overseas assets and we review those on a regular basis I mean as we potentially that’s the value we believe in use for the value of those assets I mean that would obviously be with me to look at in going forward. Nik Burns - UBS: Okay, great. Look, just a higher level question for Reg, I appreciate you're not feeling that well, Reg but hopefully you can answer this one. Just looking at again a high level picture of your current cash position, you've got AUD411 million cash in the bank at June 30, 2014, AUD300 million undrawn debt, so you've got a lot of cash there. I recognize you've got a fairly aggressive investment program going forward, but you still -- I think you generated AUD90 million-odd of positive free cash flow last year so hopefully that'll be the case going forward. Just trying to think about what that use for cash will be and whether maybe your experience in Egypt may tempt you to maybe use that cash closer to home looking at inorganic growth opportunities rather than going internationally again?

Look I think clearly it reflects a very strong focus on new opportunities particularly for oil in the Cooper Basin. So as Mike mentioned Tookoonooka and those other areas in Queensland 732 and 924. So, yes we do have to purse things like that, we want to pursue the offshore Otway because we see the gas market certainly just getting shorter and shorter. That said, we’ve never ruled anything out. Our real focus this year is to get that very strong focus on the Eastern Australian gas opportunities, on the Cooper oil opportunities and on the unconventional opportunities like what’s turning now to be a conventional onshore opportunity in Otway Basin. We talk about potential divestments but that also means investments that’s all part of rebalancing the portfolio. I hope that help to answer your question. Nik Burns - UBS: Yes, so in terms of inorganic growth going forward, it sounds like you're more interested -- or increased interest in the gas market in Eastern Australia going forward, so you might look at additional opportunities in that space?

I think if you go few years back when we did enter the international area in a fairly strong way, our focus was primarily driven by relatively low gas prices in Australia although we had a few that that could change but that wasn’t as at that time guaranteed and so where we were going to find oil in sufficient volumes are the sufficient net fact barrel really Western Flank and things like that good in Australia but if we were chasing perhaps the 100 million barrel type package overseas the new dynamic of course is the increase gas price in Eastern Australia and that translates into the volume opportunity as well as the high net pack per Boe. So, the product of those two things is probably the parameter that we look at.

Your next question today comes from the line of Kirit Hira from Macquarie. Kirit please go ahead. Kirit Hira - Macquarie: Hi guys, listen, most of my questions have been answered. But maybe a question about the conventional oil and gas portfolio, predominantly the SACB portfolio. I think Mike might have mentioned that you've taken another de-booking to Tindelby [ph]. I was under the impression that most of that was done last year and going forward, as Mike suggested, that you would be I guess adding resource, or add to reserves on a well by well basis. Can you just give us a better understanding of what you guys are actually seeing in terms of the well results there? We obviously get limited facts from Santos though, it'd be good to understand given you're going through your independent review, what you're seeing?

I guess what we have seen is that we have seen some improvement on well cost, Santos set some pretty aggressive targets on there and they have got pretty close to meeting those, so that’s really good but unfortunately there was lot of rates of tender to be less than expectations. Kirit Hira - Macquarie: Yes, okay then. In terms of the oil portfolio, I guess some might have been expecting a bit more of an upgrade to Bauer reserves. Now I understand that you've got a fairly active program going forward and that will probably give you a bit more results. But given the water cut has come through a bit more slowly than expected, is there any reason why there haven't been made some more changes there, or is it just forthcoming I guess, based on those 6 development wells you're planning this year?

So, we got those six development wells and we have also got one appraisal well which we are working up at the moment, so we have in a stage-wide process incremental reserves to Bauer over the last couple of years I am not sure why there would have been expectation for a larger increment at this point to be honest but there is appraisal well that we have got in the pipeline, definitely has the opportunity to add reserves. And as we talked about earlier, the production performance of these bigger fields tends to increment reserves as we go along as well. So, I strongly suspect we are not done yet with increments to power. Kirit Hira - Macquarie: Okay, sure. Listen, last question on the unconventional resource increase, I think it was 305 Bcf net to Beach off the back of four wells. It just seems a bit lighter compared to some of the resource editions per well. Was that just because you're only booking select intervals that have been fracture stimulated versus I guess the original wells which had fracture stimulation across all zones? Or is there another reason there in terms of the way that D&M have approached the reserve certification or the resource certification?

The methodology has changed since first couple of wells, so it’s got a little bit more restrictive and what we can book and the focus a very much key to what we can book, well spacing depending on what formation you are attacking and what kind of well you are using. They vary between 40 and 80 acres, so I guess the answer is the methodology that’s been used by our independent assessors has changed over the time. Kirit Hira - Macquarie: Is there any further breakdown you can give us in terms of the -- I mean which are the most -- I think Dale might have asked which are the intervals which are most productive -- but which are the intervals that are probably getting the most credit in terms of resource adds at this stage?

The Patchawarra Sands in our opinion has the biggest resource concentration at the moment. We’ve got some further assessment to do on the Toolachee, Daralingie, which we haven’t really assessed strongly as yet so this work through there as well.

Your next question today comes from the line of Krista Walter from Morgans. Krista, please go ahead. Krista Walter - Morgans: Thanks, just a couple of quick ones. On the production costs you talked about less than AUD20 a barrel. Is there any further potential for further cost savings there, or can we expect that to remain pretty well flat going forward?

I think that is going to pretty flat. We’re forecasting costs on that fleet of scale and assessed in the kind of ballpark as last year cost of barrel equivalent and probably goes up in our operated areas a little bit as the Board increases so although the cost of sales remains flat the cost of barrel goes up a little bit and with additional handling and chemicals excess made for that. No raw materials change. Krista Walter - Morgans: Okay, thanks. And just a bit further on the reserves replacement and you've addressed it as you said via the exploration program. Just wondering if you have a focus there, whether it's a conversion, whether you're focused on proved reserves or new reserves and that just to clarify you think the program you have in FY15 you'll return to 100% or greater reserves replacement if the outcome is as you think it will be?

Okay, I guess it’s two points so I’ll pass that questions the exploration effort will be on aimed adding new reserves through exploration and our appraisal success in terms of the those replacement prove is restrictive is what we can speculate about in terms of volume additions from exploration programs now with the FX rules were depending not to speculate on that at the moment. Sorry about that.

Your next question comes from the line of Tim Masters from Canaccord. Tim please go ahead. Tim Masters - Canaccord Wealth Management: Yes, good morning guys. I just wanted to follow up with your drilling program in the SACB JV, can we expect that that drilling program isn't looking at adding additional reserves, rather it's just bringing forward some of that production and that the current levels of drilling -- say circa 70 wells to 80 wells per year -- will continue through to the end of the decade?

Yes, I think what you’re saying is correct there. The drilling program is really infill and reducing spacing so is really aimed at developing undeveloped reserves rather than reserve additions. There is a small number of exploration wells in the program obviously they have a potential to address this and we’re on a six well program and also a six rig program at the moment which is drilling at 70 to 80, so I would think in the next few years we would remain at that kind of level or actually drop five rigs but it’s going to be not similar kind of ballpark. Tim Masters - Canaccord Wealth Management: Okay, great. And also just talking about the CapEx split between the first half and the second half, I know that the CapEx is going to be largely focused on the second half as far as the plant goes -- the plant maintenance. Do we expect any production impact towards the second half as compared to the first half?

No, I don’t think that capital expense is going to impact the production to that extent sometimes in the CapEx phasing it’s quite difficult for us to get clarity on that with the discrepancy between the financial year and the calendar year. So we have to take guidance from the operator which comes in the calendar year ’14 and then finance fully into our entire financial year guidance. So take our phasing with a pinch of salt. Tim Masters - Canaccord Wealth Management: Okay, no worries. And just a final one, on PEL 92, is your exploration drilling there finished for the year, I didn't see any additional wells in PEL 92?

No, and that will be coming back to PEL 92 in the second half of the financial year. Tim Masters - Canaccord Wealth Management: And how many wells are you looking at doing there?

We’ve got 15 exploration wells across 91 and 92. So I don’t remember at the top of my head what that split is, but two or three. Tim Masters - Canaccord Wealth Management: So I can see there is five exploration wells in PEL 91.

Actually it’s going to be four exploration wells in 92. I’ve got the data in front of me now, yes.

There are no further questions on the line today. I would now like to hand the call back to Benjamin for closing remarks.

Thanks Vincent and thank you everyone for joining us on the call and the webcast and at this point we’ll bring the call to a close. So thank you.