Woodside Energy Group Ltd (WDS) 2006 Q4 法說會逐字稿

Good day, everyone, and welcome to the Woodside full-year results conference call. Today's call is being recorded. At this time for opening remarks, I would like to hand the conference over to your moderator for today, Mr. Don Voelte. Please go ahead.

Good afternoon. Welcome, everyone, to Woodside's 2006 full-year results briefing. I appreciate everybody taking the time to listen in. My name, of course, is Don Voelte. Seated with me today for today's teleconference is our Chief Financial Officer Mark Chatterji and Agu Kantsler, our Director of Exploration and New Ventures, and also Mike Lynn, our Investor Relations Manager.

Earlier today Woodside released its full-year 2006 results and presentation slide pack. We will be referring to this pack during our teleconference, and you can follow our discussion by viewing a hard copy of the slides or by clicking into the Woodside website on your computer.

Over on slide number two, a disclaimer and important notice, our standard disclaimer.

Slide three, Mark Chatterji is going to go through the financials in more detail in a little bit; however, let me start on slide three by saying that 2006 was a year for records for us, record production, earnings, cash flow, dividends. Our reported net profit after tax was a record $1.43 billion, up nearly 29% compared to the same period last year. The Company also achieved an underlying profit of $1.4 billion, up 35% from 2005.

Now, in addition we have achieved records in EBITDAX at almost $3 billion -- that is 2.98 to be specific -- and net operating cash flow at $2.35 billion. However, even more significant was a 27% boost to our 2P reserves, which increased by 336 million barrels of oil equivalent. This is, of course, mainly due to the booking of Pluto, but just the heads of agreement volume whether to Japanese customers. Now these records, although somewhat lower than they would have been with a stronger performance at Enfield and Chinguetti, and we acknowledged that last November investor briefing, still represents a pretty significant achievement I think at this point and points to a pretty healthy company and a company that continues to achieve a growth pattern, as well as create value towards shareholders.

Now Woodside is delivering these projects in a tough environment, and you're seeing the beginning of a lot of great opportunities for growth for this Company. Now this was reflected in our strong total shareholder return as shown in the bottom of the chart on slide three.

I'm going to turn it over to page four, 2006 LNG highlights. Actually where we were struggling with a few of our oil projects last year, LNG was really ramped well to this company. I will go through it in detail, but everything from Train Five through Pluto, Browse and now, of course, the news at Sunrise, even good news I think coming at Ocean Wave, so it's been a good year for LNG.

The particular milestone I would like to point out on slide four is the proof funding of the Pluto long [p-dot] leadtime items, our securing of our market for Pluto, and also even though maybe not well pointed out here, it is amazing where Train Five the construction is taking that project. You can read the rest of them there.

Going to slide six -- I'm sorry to slide five, 2006. In addition to LNG, we had oil and gas exploration highlights. In oil and gas, you can see here some of the significant -- everything from the 1000th cargo of condensate out of North West Shelf to project approvals and continued project development of Vincent and Neptune, Stybarrow, etc.

In exploration, I don't know after Pluto, it is kind of hard to repeat. We had a really good year in the North West Shelf. We had two great discoveries there. Of course, we only get 1/6 of those on our reserve book. But Persephone and Pemberton was one of the best years we've had in North West Shelf in the exploration side of the business. And then again, we had our Zena discovery right next door to Pluto, and you can see here some of the other issues. We are drilling in the onshore Olivia and hitting hydrocarbons, and we will talk about it here in a little bit.

I'm going to turn it over now to slide number six, safety and environmental performance. Disappointingly, our total recordable case frequency increased in 2006 compared to 2005. However, the number of high potential incidents did decrease. We can, we will and we should do better with renewed focus on our commitment that nobody in Woodside should get hurt and that there are no incidents. Our reportable environmental incidents, more than half from the prior year 2005, and we aimed to further reduce our environmental impact and minimize greenhouse footprint across our operations.

I just want to note here that for the first time we will be putting out a sustainable development package along with our annual report that has a lot greater detail and a lot greater information on environmental discharges, emissions, as well as other social programs and activities that Woodside is involved in.

Moving over to slide seven, production sales performance, 2006 saw a 14% increase above production in sales over 2005, primarily due to the new production from Chinguetti and Enfield. In most cases and for most companies, this would be a great result, but of course, we were expecting better at the start of the year. So while the Company demonstrates it's great profile for growth, we are a little disappointed as we told you in November, and as you are aware, we're going into this year with new projects coming on and a large 2008 in front of us even next year.

On slide eight, turning to our reserves performance, 2006 has seen a significant increase, and this is the start I think of over the years to come of multiple moving contingent resources into proved and probable reserves for this Company as we bring a lot of our large LNG projects on production.

With the work we did in 2006, we believe now that there is certainty and the Board believes there is certainty that Pluto will go ahead and we have booked the reserves for the heads of agreement sales volumes. Now that has led to a 2P reserve add of about 336 million barrels of oil equivalent, or put another way, we have increased our 2P reserve base by about 27%.

Our proven or P1 reserves have increased by a net 293 million barrels of oil equivalent close to a 33% increase in our 1P reserve base. Well, we just grew the Company by a third. It's kind of hard for me to read this. I have not look worked in companies that have increased by a third in a year or so the way it goes.

With all the work we're doing this year on Pluto, we're confident a significant amount of the remaining contingent resources, though we have booked the base volumes and next year after FID, we potentially and probably will book the other reserves that are the remaining volumes that the plant is FIDed to build or to produce. Now that is all contingent, of course, upon FID.

As we go to our reserve statement, the Browse and Sunrise volumes remain in contingent resources. There was no movement of those reserves.

Moving over to slide nine, listing cost. Gas listing costs per BOE have increased by around 27% compared to 2005 due to an increase in maintenance and shutdowns in the North West Shelf and more specifically Train Four. Now we have put in our plans this year at Train Four we will have some more downtime to look at the compressor again and do the maintenance on it if we need to.

When we look at this increase, and I know another company one of our partners made a large deal about 25% increase, overall we're talking A$0.40 per Mcf or thereabouts. We're talking about a A$0.10 increase because of this unplanned downtime on Train Four. That was the major cause of it. Still a very good price, a very good cost on a competitive basis for moving gas.

Now our oil lifting cost per BOE, which includes leased FPSO capital costs, have increased about 8.5% from the corresponding year to just over $6.14 per barrel of oil equivalent. Now this result is a result of onetime subsidy repairs at Cossack, Laminaria and Legendre. Now we exclude the effect of these one-offs, the listing costs and excluding the FPSO costs by the way, they would have been about $5.00 dollars per barrel of oil equivalent.

Now finally, our leased FPSO capital costs increased with the startup of Chinguetti oil project in February 2006 and should be captured in your accounts going forward with the [Ugari] project.

Moving over to slide 10, competitive performance metrics. Now this slide shows Woodside's performance in two important cost metrics versus our peer group, and this is all based on 2005 data, although we have included our Company's 2006 data. This is from [JS Harold] data for the peer group, and of course, the Woodside numbers have been already published and calculated into the JS Harold methodology. Woodside's performance in each of these metrics in 2005 is represented by the pink bar. We then included, of course, the 2006 in the red bar, and it is moving in the right direction. As you can see the three-year average, finding costs and the three-year average finding and development costs per BOE has improved significantly in 2006. We believe these results place us in the top quartile of each of these categories.

Now I will come back and talk later, but I think it is time to get into the financials and talk a little bit more in-depth. So I'm going to turn it over, starting on slide 11 here, to Mark Chatterji, our CFO.

Thanks, Don, and good morning or good afternoon, everybody, depending on what timeframe you're in. Let's move on to slide 11, which provides a high-level summary of Woodside's financial performance.

Some of the key things I would like you to take away from this slide are firstly volumes have increased, so combined with higher oil and gas prices, revenues have increased significantly. Secondly, the exploration expense is also significantly higher than 2005 due to the increased work program that we undertook in 2006. Thirdly, our reported profit includes the sale of our interest in the [Kepner] gasfield, and so we have broken out that $31.1 million item separately in the slide as you can see. Fourthly, the total dividend in 2006 will be $0.126 per share, so that is up 36% compared to the previous year. Finally, our debt and consequentially our gearing has increased in line with our capital and exploration spending programs increasing over the prior year.

Now one correction in the table, let me point out that the EBITDAX number, the EBITDA plus exploration expense number, that was released in the presentation lodged with the stock exchange this morning was incorrectly stated as 2949.7. The correct number should actually be 2978.6. So I will say it again -- $2978.6 million.

Moving on to slide 12, slide 12 you can see that we have provided you a reconciliation between our NPAT in 2005 and our NPAT in 2006 as reported numbers. If we compare the results between 2006 and 2005, the primary reason for the improved result was increased sales volumes and increased commodity prices. Sales volumes were up 14%, and the 2006 realized oil price increased by 17% compared to 2005. Now these increases were partially offset by cost, expense expiration and valuation and tax increases. Now the cost increases have already been touched on by Don, but just to reiterate, the startup of Chinguetti and the Enfield oil projects have been the major driver in cost increases combined with costs associated from the first full-year of operating Griffin, which we purchased in 2005. Production costs were up $96 million, while depreciation and amortization is up $263 million. Now these are offset by lower shipping and marketing expenses of $6 million.

As I mentioned, the expense for exploration and evaluation has also increased, primarily as a result of the larger exploration program, plus higher drilling rig and seismic vehicle rates and the increased amortization of license and acquisition costs in the Gulf of Mexico due to the Griffin acquisition. And finally, taxes are up as a function of production and revenues being up.

Moving on to page 13, as Don mentioned previously, Woodside achieved an impasse before significant items of $1.4 billion, so that is up 34% from 2005. We've gone ahead and highlighted the continuing of the positive trend you have seen over the last three years. Just let me point out that on this slide and the next two slides, the indication for CAGR should actually be cumulative not compound annual growth rate.

Going on to slide 14, we have done the same thing on cash flow growth, operating cash flow. You will also see the same positive trends in operating cash flow that you saw in NPAT on the previous slide. And furthermore, going to the next slide which is dividend growth, since our improved profits and our operating cash flows are doing so well, it has facilitated the board being able to declare a record total dividend for 2006 of $0.126 per share, and this is, as I mentioned, an increase of over 35% compared to 2005.

In December we activated the dividend reinvestment plans, which will give our eligible shareholders the option of reinvesting their dividend in additional Woodside shares without incurring brokerage or other costs. And, in fact, they will get a 2% discount to the determined market price on the 2006 final dividend. The plan, the DRP that is to support Woodside's growth and also assist in funding our future capital requirements. For the 2000 final dividend, the DRP is fully underwritten. With that, I will take you over to slide 16.

Slide 16 is our gearing detail, and as you can see and as I mentioned before, both net debt and gearing have increased as a result of higher capital budgets and exploration expenditures. An additional $398 million of long-term debt has been drawn down since the end of 2005. Now this increase is in line with the increased budget.

And speaking of budgets, it will take you to the next page, which is page number 18. This highlights our capital and exploration expenditures.

As you can see, the total capital and exploration expenditure for 2006 was about A$2.3 billion, which is a little less than the A$2.5 billion advice we gave at the November briefing. The main changes were in the categories of exploration, other and the Enfield area, and as you can see on the right hand side of the slide, I realized this slide is quite busy in terms of the number of slices to each bar but if you can follow along exploration and other in the Enfield area and look at their appropriate colors.

Other in Enfield area spending differences were primarily due to timing, while the exploration underspend was due to resequencing of planned 2006 exploration wells into 2008. For 2007 we expect a total of around $3.65 billion will be spent on capital and exploration, which is down from the $3.9 billion forecast we told you in November. The adjustments have been made to make allowance for the lower production and (indiscernible) cash flow expectations from Enfield, which were also identified at the November briefing. These adjustments do not affect committed projects or our LNG growth projects.

Moving over to the next slide, slide 18 shows that our business unit margins have continued to improve compared to the corresponding period last year for the North West Shelf, Australia, Middle East and Africa and the US in line with the improved commodity prices and new production. Exploration increases have been discussed in previous slides, so I will not go through that again. For the group in unallocated profit, that is primarily due -- the change is primarily due to the PRRT augmentation benefits of $31 million, foreign exchange gains of $35 million and gains on the fair value adjustment of our investment in ceramic fuel cells of $20 million.

Going over to the next slide, we provide you with some NPAT sensitivities. Obviously we always say with oil price, gas prices, exchange rates and interest rates, we give you the change for an increase. That obviously works in the opposite direction as well. But we did want to provide you with a little bit of guidance so you can get an idea depending on what you think the oil price is going to be and what you think the exchange rates are going to be how Woodside's earnings look for 2007.

Now with that, I am going to go ahead and hand it back to Don who will take us through several projects and then wrap up with his outlook for 2007.

Okay. Thanks, Mark.

First, on slide 21 is the start of our numerous growth projects. We will start with Chinguetti. Production is currently averaging 20 to 23,000 barrels a day. As most of you probably know, we drilled our first Enfield well in our Phase IIB, well number C18. We successfully intersected the reservoir, and now we are completing the well, and we're waiting to see what impact it will have on production. We will probably have that information at the end of the first quarter.

Next up is our 4-D seismic, and then later this year or at the end of the year will be our Phase IIB drilling opportunity based on our 4-D seismic.

Moving over to slide 22 is Enfield. We have two slides on Enfield for you today. Back in November we gave an estimate of 45,000 to 55,000 barrels of oil per day production in 2007. Now if there is delays to delivery of critical subsea equipment things like Christmas trees, valves, umbilicals, etc., it may cause us to come in at the lower end of this range. The expectation is that the forward program will cost the joint venture around $500 million (indiscernible). Of course, that is $300 million Woodside share.

In the meantime, the January production figure is holding up quite well at an average of around 42,000 barrels of oil per day. As you know, the ENA-03 well, we tried to put it back on right around the investor day, and it did make an awful lot of sand, and we were not able to bring it back on production.

So we have some planned shutdown to remove strainers in the facility from the startup in January. If you take those planned production outage out of the January figures, we average around 45,000 barrels a day on our run-rate time for January.

Now going over to slide number 23, let me tell you how the 2007 work year may unfold and I say may. We're still working through it at this time. Of course, our ENA-03 was our best producer, so the repairer of this key well is a priority for us and will be the first opportunity which we believe will be somewhere in the April timeframe. We have a rig scheduled for it is.

Behind that, as you can see on the chart there, the next one that is scheduled up at least preliminarily is the [ENC-04], which is a new injector. We think that will provide enhanced pressure support for the repaired well, as well as the current injection as we go.

Now the next well after that we predict at this time as you can see in the yellow background, ENA-06 producer, and it is designed to access unswept oil.

Now I say these are planned; we want to see our 4-D seismic, and the 4-D seismic I believe is already going on out there. Agu is giving me a thumbs up on it, so it is in the process of being shot right now. The reason I'm a little hesitant on this, from the results and interpretations of 4-D, we may change either the priority, the sequencing or add additional opportunities that may fall out.

Now our activity, we have [roof swap] scheduled for the rest of this year. The biggest issue is equipment and getting everything else. And so some of this work made fall into the beginning of 2008, but we are confident that everything is going well on the rework on Enfield. And Agu is also sending me little notes here saying the quality of the 4-D is coming in very good, so that is good information to have.

I'm going to move it over then to the next slide, Otway, the one I pulled all my hair out of. On slide 24 here, we've had ongoing construction delays at the onshore gas plant. Now, in our first-quarter production report that we released, we said that over the Christmas holiday we had implemented some programs to try and increase the worker activity, and we noted that we were frustrated with the level of progress that we made over the Christmas holidays due to the fact that the labor workforce was more interested in doing other things.

Now we are very focused at this point. We're making really good production I understand from Betsy and from Roy on progress since Australia date when most of the workforce showed back up. We're really focused right now on the end of first quarter getting mechanically complete. We have got a good shot at that. It may slide over into the first week or two of April. So, at that point, we will be in decommissioning process. And I know you will ask, well, what time are you going to come on production? Don't know, but basically we will be in the commissioning in April at this year.

Now we have watched this Otway delay. Last year we were on our heels all the time, and this year we are trying to get out on our toes. We have taken some preemptive action to guard ourselves on the Otway earnings issue, and I will talk about that here in a few slides.

Moving over to Neptune, of course, it is BHP operated for us as you can see. We have a 20% interest here. And this Neptune is Gulf of Mexico obviously. We expect Neptune will start production close to the end of 2007. What we understand is that some of the equipment that was going to do the installation has been damaged in other projects for other people, and BHP is assessing that at this time. We again conservatively planned in some delay to Neptune fourth quarter, and I will talk about it again in another slide how we tried to protect ourselves on an earnings point of view from potential Neptune delay. But I will say this, the wells that are coming in on Neptune, the reservoir looks good, and although the costs have been a little higher on the drilling than we had wanted, but everything else BHP says that they are still -- look for advice from BHP on startup dates that they give. We're about as beholden to the operator as some of you for this information.

Moving over to Stybarrow. Stybarrow ventured the FPSO sales away from the Korea yard in February earlier this month where they will put the top slides in Singapore. Now the drilling program started. We had two water injectors and two producers completed, and as we have probably alerted you before, we plan for first oil for early 2008. Schedule at this point looks good. We've got about a six-month ramp-up planned for this facility. We are carrying in our books a plateau, 100% for the field of 50 to 60,000 barrels per day. Obviously operator may have or BHP may have different planned production rates, but that is what we have for us.

On Vincent, the next slide, again the design procurement construction is underway, and Vincent is looking good, on schedule. You might say it is right next door to Enfield. Do you expect the same problems they had at Enfield? And the answer is that it's a completely different reservoir, and we feel pretty confident on Vincent about the reservoir. We have taken hard looks. We have taken the lessons we have learned from Enfield and Chinguetti, and since we are operating this project, we know the heat is on us to make sure that this comes on.

As you can see on the slide, the development drilling start is to start in March 2007. The rig is lined up for it, all contracted, and the hull installation and topsides are fixing to begin in March of this year also.

Now we have given you some guidance here again, trying to help you with these ramp-up periods. It is kind of a new feature Mike Lynn has installed here, but first oil is planned for quarter three of 2008. With the second manifold involved in the first half of 2009, we are planning for peak production around 60 to 80,000 barrels per day.

Now, because of the nature of the reservoir, there is really essentially no production plateau. Once we start the field up, there will probably be a natural field decline.

Next slide, sales of Legendre oil operations. Now let me just kind of give you a -- for some of you that are not familiar with Legendre, it has been a field that has really produced well for us. I think like 43 million barrels have been produced over the lifetime. It has been a strong performer for us over the years. It is just at the end of life as far as Woodside is concerned. We're down to a point where the margins are very thin, production is quite low, and we have scheduled it for PNA activities at the end of next year or the beginning of the year thereafter.

Now we signed an agreement to sell our interest in Legendre field and adjacent exploration permits, although we did withhold some properties. We have sold this for around A$84 million. Actually it is in US $65 million. We have made the conversion to A$84 million. Now this sale is still subject to government and JV approvals and is consistent with our strategy of focusing on our assets. When I get to the end of life, sometimes there is other operators that have different ideas about end of life properties and what we do at this site. Now this plays into kind of our Otway Neptune play, and I will show you that here in a little bit.

Moving over to North West Shelf, the venture Phase V expansion. Like I said, our LNG projects really went well last year, overshadowed by Chinguetti and Enfield. But it is amazing. A couple of months ago North West Shelf consisted of just a bunch of foundations. All of a sudden, we've got a train out there and being built before our eyes. The large modules have come in. We've got a few more modules to go, but really pleased with the progress on Phase 5 construction as it is shown here on the slide.

Like I said, a large number of the (indiscernible) that arrived from overseas are being fitted together. We have had absolutely no problems with the offloading. The transport up to the site, and things are going well. Now we expect a commissioning on Train Five by mid 2008 with the first LNG cargos in the fourth quarter of 2008. So we are pleased.

Now let me just make one other comment here. It seems like -- I will probably get in trouble for this statement, but you guys are used to this -- we got bashed for 20% increased costs, and we're holding really tight at 20%. It is under pressure, but we're still hanging in there. And I have got to tell you, if we built this train especially with the contracted volumes and the recontracts that we have signed over the HOAs we have signed over the time period, I would just tell you, I just think for what we [ASEed] that thing for, if we bring it in at 20% over, even though the media may not like it, I'm going to be very, very happy. I know our joint venture is going to be very happy too.

So enough of my advertisement there, let's move on to Pluto on slide 30. Pluto is progressing well. There's a lot of certainty in this project now. As you know we are under construction up there in the respect of preparing Site A for the storage tanks and the jetties to be built.

Now in December of 2006, as you all recalled, the board approved $1.4 billion for long leadtime items and site preparation. Now on this slide, we show you the earth moving on slide eight, as I had mentioned before, has already commenced. We're been very, very careful up there. At this time we're moving some of the very precious rock art, and up to this point, everything is just fine. We have not damaged any rock at all, and right now we are at 100%. And I will tell you, that is really important to me. I'm really proud of what our people are doing up there, and I will tell you it is costing us a little bit. But it is okay because they are being extremely careful. So so far 100% on any disruption of rock art, which is absolutely something we don't want.

Now on top of this, there's enough certainty with the HOAs and the other work involved. The board felt convinced that the recommendation by our reserves committee to book the HOA volumes was the proper prudent thing to do, and they went ahead and did this. We do expect a final investment decision to be made either at our June or August board meeting this year.

Moving over to Browse, on slide number 31, we will be progressing Browse LNG with further appraisal work this year. We had a good year last year. After all the appraisal work, I guess it is not too exciting, but we still believe the volumes will be what we have predicted them to be from the beginning. So we are getting -- you know, every time we drill a well, one is a little better, one is a little less than expected. But overall it is going quite well.

In addition to the appraisal work, we're doing environmental studies, as well as confirming LNG buyer interest in this project. Now to further evaluate the area, we're going to be drilling the Snarf prospect in 2007. This is one I know Agu is excited about, and he may be asked questions about it after we get done talking here.

Now just recently we have been offered three new exploration blocks shown in yellow by the government to the East and South of our existing leases. Now these blocks would have a three-year work commitment of 3700 square kilometers of 3-D seismic and five wells. This equates to a minimum indicative expenditure cost of three blocks of around A$267 million. Now we're currently evaluating that offer, which was accepted at 100% our equity share to Woodside.

Moving over to Sunrise, this well has been pretty active. I will tell you I won't tell you the amount of effort within this country in the Australian government, the government of Timor-Leste and the employees of Woodside. It has been very active yesterday. The (indiscernible) team last they voted for ratification of the International Unitization Agreement or as we call IUA and the treaty on certain Maritime arrangements in the Timor-Leste CMATS. Now this provides the required legal and regulatory certainty that we were looking for. We're happy with them, and as you know, our PSE still stands, and we don't need any modification to that. And these major milestones have been very encouraging for the project. We're pretty happy with them. However, for Sunrise to go ahead, of course, we are going to have to have an agreement on the optimal development concepts, including any additional appraisal work that might be needed. And real important, the conclusion of a fiscal certainty arrangement with Timor-Leste on this deal.

So we always said that there would be three things required. We have got two of them. We have got one left to go on the fiscal certainty, and of course, at the end the day, you have got to have customers for this. Of course, we think the market is pretty good going in through the next decade, of course.

Now watch out for Sunrise. It has potential to quickly come on the radar screen for development. In fact, I would not be surprised to see it run neck and neck with Browse in our portfolio of activities.

Moving over to Libya exploration, I would just say here that offshore as soon as we get done with our Chinguetti 18 completion, we will be moving that rig up to drill at least -- well, I will just say at this point our plan for offshore wells. We're going to drill those in sequence as we come into the country and just drill going from West to East. We think that the first well will spud sometime at the end of Q1 2007 onshore, and then Murzuq and Sirte Basin we have seven to 10 wells planned for 2007. And if there's any questions as to an addition to what we have have already released on the onshore, Agu is here to answer those questions.

Gulf of Mexico exploration is a huge number of leases. As you know, there's a 10-year rollover in the Gulf of Mexico of deepwater leases. And starting in 2007, there is a huge number of leases that come on the block that we are very interested in, and we have built our Gulf of Mexico exploration team at this point. Agu is supplementing our team with additional key individuals getting ready for this big lease sale. But more importantly, our rig will be available in early May to mid-May of this year to start our deepwater development program.

I'm pretty excited about the first two wells, [Corona Del Mar] and also our Terrebonne. Now Terrebonne may switch out. If something else comes available that we like to drill better, but the sequencing isn't important. We have got our projects lined up for us this year in the Gulf of Mexico.

Now the next slide, Korea, as you know, Agu's group has been working on concession. We went ahead and I ran up to Korea the other night and signed this concession for Agu. As you can tell, this exploration agreement is a 50% joint equity deal with the Korea National Oil Company. I want to just mention that this is located offshore in the East Sea of Korea.

Moving over to rig capacity, we often get asked a lot of questions about, are you covered on rigs? And in this high-priced market, you don't want to be too covered. So we try to basically cover our development wells, and basically you don't want to go naked, but also it is not good risk management we believe to completely cover ourselves. So we thought we would kind of give you a little indication of where we sit here and give you as much information and make our company even a little more transparent in that area.

I think that speaks for itself. I will move onto the next slide.

As you know last year we had some production issues on Chinguetti and Enfield, and I got to tell you we were on our back feet. You saw us at November investors. We were not happy campers at Woodside. As the management team, we hold ourselves accountable for this stuff, and we said, you know, this is a tough environment out there. It is hard to get all the contractor equipment. The equipment out there has not been maintained in a lot of cases and just a lot of issues that really caused a lot of issues with predicting the startup times.

Some of our projects like Vincent, North West Shelf, Train Five are going just fine. Other ones, we're struggling. We told you in November that we were very concerned about Otway, and we highlighted Neptune or at least gave a heads up on Neptune.

What we decided this year was going into this year was get on our front foot on this one, not continuing to be back on the back heels. When we took a look at our Legendre asset, we said you know we think it's worth more to somebody else and is worth more on an earnings basis than what we will make on it continuing to produce it. So what we tried to show you here is what we did a little financial I call it engineering. I understand it might be a bad term over here, but a little financial management of taking Otway and Neptune and the production impact. So we are losing production, but we're protecting the earnings of our shareholders here.

So what we did here was just show you what potentially could happen. Let's say we had a potential three-month delay on Otway and a potential four month -- in other words, take production completely out of 2007 for Neptune. And the Legendre sale, of course, we lost that production since that effectively is to be sold from the first of this year. You can see the production lost here of nearly 3 million barrels. But, as you can also see, the earnings from the loss of that production equals about $30 million. When I say 3 million, I should equate it on the slide, it shows 2.7 million obviously. But the after tax of that $84 million is approximately $45 million. So in the end, when you take the actions of those three activities, we have tried to protect the earnings even though we cannot protect the production.

Okay. I am just about ready to wrap-up because if you're not tired after three days of committee meetings and board meetings, I'm getting a little tired.

2007 outlook. Our November 2006 production target of 2007 was $75 million to $80 million. I have just shown you where this 2.6 million barrels rounded to 3 million, to take the downside down to 72 million, and what we did was we decided, oh, let's just take half of those probabilities of Otway and Neptune happening and then add that on. Now, of course, we subtracted the 1 million barrels or thereabouts on Legendre that comes off the top of this. So that is how we got from the 75,80 to 72 to 78 million. In any case this is more production than last year from 6 to 15%, and we are absolutely focusing in on the earnings side of the business.

Now when we say that we are improving margins, I want to just reiterate we are not compromising on things as you can see on the slide. There is safety, environment, maintenance, etc.

Now the target to lift production at Enfield and Chinguetti to targeted drilling campaign, we will also see that come into this forecast, as well as you will have Otway production -- I say we have -- we better have Otway production sometimes this year. Hopefully we will get a little bit of Neptune in, too.

Moving over to the next slide. On slide 39 we have listed the projects that we will continue to advance in order to deliver value and sustain growth for shareholders. Now with delivery of the new projects, our production for 2008 is expected to exceed that of 2007. Our 2007 production, like I just said, is expected to exceed what we achieved in 2006, but we are aware, however, that so far in 2007 we're seeing a softer oil price than we saw in 2006 -- I'm sure you have noticed that -- and that a number of you have seen this softness continuing through this year. Now we don't predict oil price into the future. We certainly look at the strip. But I will just tell you that if you take a look at last year's realizations versus this year's realizations, from the strip pricing, there is significant softening in the marketplace. I just want to make sure you catch that, even though our production is forecast to increase.

In summary, you can see we are in for another busy year. I have got to tell you, some of you were a little worried about us being too down, beating ourselves up a little bit too bad in November. We take this stuff really seriously. Folks got time off over Christmas. I tell you the management team and the employees of our Company, we are back up to it. Got the energy. We're going to make 2007 good. Going to make 2008 good. We're excited about our prospects in Australia. Really excited about LNG and what's going on. We have had things really turn our way. I think we will get another good year here in exploration. We get some luck in Libya, a get a little bit of luck in Gulf of Mexico. We ought to be off and running. So now I'm going to open up after kind of a little marathon front end here the teleconference -- we will open up this teleconference to questions. And thank you very much for your patience to get through this 45 minutes or so.

Gordon Ramsey, UBS.

Just on Pluto, back in November [Lucho] mentioned that we might get an update around April in terms of a better definition of project cost. And I see that in the results here you highlighted there is going to be some money spent on compression around 2017. Are we still on target to get a finer cost estimate by April, or will we have to wait until FID (technical difficulty) by around the middle of the year?

Yes, good question, and Pluto reminded me here to remind the marketplace that he remembered saying that. Thank you, Gordon, for your question. Let me try and answer it here, and anybody else jump in if I missed it. I think in November we gave this wide estimate of A$6 billion to A$10 billion for the cost of Pluto.

What we found was people did not realize that we had cost into the future into this project all the way up to PNA of capital cost that is. And what we wanted to remind people is we have a very large cost, and I think it is 2016 or 2017 for compression. That is a part of that A$6 billion to A$10 billion. So our initial cost of the project all will be somewhere between A$1 billion to A$2 billion less than that for the initial expenditure. That is what we were trying to signal there in compression.

To answer your question, I'm not going to commit to giving you a better cost estimate until FID, mainly because we think we're going to take just about all the time up to FID to lock in everything just about perfectly.

Now some of this -- Mike is telling me here that slide 30 is probably the best reference point for this discussion. The last issue I just put on with this is that you just don't cost estimate a magnitude project like this. We go out and get tenders. Right now we're getting tenders in on the onshore and the offshore. We're backing up our estimates with real live contractor bids. So basically we have got the firmness of the market and everything else.

I can just tell you one little hint here. The onshore is coming in a little higher than we expected, and the offshore is coming in on or a little under than what we expected. But right now I would just say this, if we thought there was any problems with Pluto going forward, we certainly would not have booked the reserves.

Andrew Blakely, McQuarrie Bank.

I have a follow-up question on Pluto, particularly with regard to the booking off the reserves. It's obviously a very confident and bullish step forward, but is there any occasions or anywhere else in the world where reserves have been booked on the gas developments product financial investment decision?

Yes. Well, two things is, we work under the SPE guidelines here and we always have, and we clearly have a greenlight on that from the certainty in markets, the certainty in permitting, the certainty in commitment from the management and reserves, etc., etc. Yes, there is a precedent for this. BG booked the Egypt reserves I believe eight months or thereabouts before FID. Don't quote me on the number of months. But it was well before FID on Egypt.

Okay. And then in terms of the follow-up reserves, obviously you have booked the initial heads of agreement, and obviously you have got another up to 4.5 Bcf. Is there any progress on additional reserves, are or you still looking at 4.5 Bcf feeding in at 6 million ton per annum train?

Yes, well, let me make sure we are using the same assumptions here. I don't want to commit to a 6 million ton train. I think we said 5 to 6 million ton train, number one. Number two, the reserves stand the same as what we have pushed in the past. Pluto 5 is a good result for us in the respect again on slide 30 I have been asked to reference you to, Andrew.

Let me just say this on reserves. Of course, we have the three big [Cazadores] blocks well to the north of this but basically should feed in. We re going to be shooting seismic on that. We own those blocks at this time 100%. Of course, we have our what we call T Block to the left -- when you're looking at a map, to the left of the block. We have got some opportunities there. More specifically, those are [WA-370-P] and 269P which we have opportunities on. In those cases we do have joint venture partners.

So we have a lot of playground to play in exploration-wise, and I hate saying that in front of Agu because he usually takes advantage of it when I say that.

The booking of the reserves were 90% of the base volumes. The reason they are 90% is, of course, you know we have the two 5% option for equity for our customers. At this time we predict and project that if next year assuming FID, we would be able to project forward the booking of the rest of the reserves as we see them to a certified level.

Now I want to make this statement, and my CFO is kind of punching me here in the side to say, hey make sure they know this. If for some reason FID does not come through, if something bad happens to us or something happens in world events, those reserves will come off the books, will come off the books (technical difficulty)--. At this time we don't anticipate that obviously or we would not have made the booking.

Okay. If I can ask a follow-up question on a different issue. With regard to Enfield, perhaps you can give a little bit of guidance. Nothing seems to have changed in what you're saying with regard to the rig availability and concerns about some of the infrastructure availability, but you have downgraded reserves very significantly in the reserves statement. What should we be reading into that with regard to forecasting production going forward? Is it conservative external reserve reviews?

Yes, there are three things that are growing on there in the reserves. Number one, I mention that we are running on a day that runs without incident out there. In other words, no downtime trips or anything. I think the number is running around 45 for the month of January. We had some planned downtime that took us to 42,000. So if you add the 30,000 barrel well that we lost, the field is hanging in there really well. I would like to say that we -- it's producing about what we were saying it was producing back in November. We don't see any deterioration in that respect.

We're excited about the future drilling program. We're more excited about the 4-D seismic. But the water flood appears to be working, and we do see the mobility of the oil through the reservoir pushed by the water.

To answer your question, there are three reserve components. Number one, we have rerun with a new simulator. We're taking a look at the same basic assumption data, and what we did was we did not feel very comfortable or quite feel comfortable with the original oil in place. In other words, the container side. We have taken that down a bit. That is number one.

Number two, we alerted you in November that our drilling, basically along the way drilling, we again found some drilling issues on some sliver blocks where we took some reserves off of or are going to take some reserves off the block that we have taken now.

The third issue is we just don't have the metal in the field. We don't have the wells in the field for enough penetrations, and basically if you don't have the metal in the fields, you cannot put the reserves on. So depending on future drilling results, future production performance, the reserves could be adjusted in the future both ways. And I will just say that at this time, we are very, very transparent in our books and we are very, very religious to the rules on reserves, and basically we try to employ here and on Chinguetti exactly what we believe we have out there at this point until we do more drilling. Anybody want to add anything? Nope. Okay. Next question.

John Hirjee, Deutsche Bank.

A couple of questions if I can following a similar vein to some of the other questions. Don, in terms of Pluto $6 billion to $10 billion, you said you are refining that. Have you given -- what is the thinking behind how you're going to finance that CapEx?

Okay. That is a CFO question for sure. I just like to spend it; you figure it out.

Yes, absolutely. On the funding plans for Pluto, we actually are looking at a combination of things as you might expect. The first-line and one of the most important ones is the activation at the dividend reinvestment program. And so, as has been noted, since we're fully underwriting the dividend investment plan for the final dividend of 2006, you're going to see an equity inflow of about $517 million, and we have the ability to go ahead and extend that dividend reinvestment plan as our capital budget dictates over the next few years. Obviously that is the equity component of it. There is going to be a debt component as well, and as this point in time, we are looking at a number of options ranging from the capital markets to a combination of some funding from commercial banks and the capital markets.

Okay. Thank you. The second question then is again related to LNG. In your release you mentioned that the new recontracted LNG contracts with the Japanese customers, you're getting over 15 to 20% increase on previous ones based on the $60 oil price. Just can you give us some further clarification, have the caps and collars been removed from the previous contracts?

John, either one of us can answer it, Mark or myself here, but let me just try it first and Mark can chime in. We're very hesitate -- we hesitate a lot when we get into this, and we gave you 15 to 20 as a directional. Yes, the market continues to look strong. We were predicting 2012 the strength in Asia-Pacific. We're looking more like 2014 now. So we see a good opportunity for Browse and Sunrise to get up.

Now, as to features of the contract itself, I might just say that things are very competitive out there right now. People are looking for secure supply from reliable sources, and they are even more confidential now with these contracts than they were before. And they were lock solid. So anytime they even venture into this area, John, it puts at jeopardy our relationship with our customers. So I'm sorry. I just really cannot say much on that. Mark?

John, I would just draw your attention back to what we talked about in November because, I think as you will recall, there was a fairly lengthy discussion on LNG pricing and how in general what you have seen is the old bargain where buyers and sellers trade up upside and downside risk is certainly giving way to a more linear relationship between LNG and the price of oil. And nothing we have seen between November and today makes us change that. We obviously, as Don said, cannot get into the details, but you definitely see a more willingness to just shoulder the risk on an unkinked basis in terms of the curve.

And final question then if I may. On Enfield you said you are going to spend another 5 million or so, 300 million your share, how are the economics looking for the field given that the reserves have been downgraded by over 50% of the proven level? How are the IRRs looking?

Well, clearly you would have seen an impairment if we were in that situation. We don't see that at this time. The economics are -- we have designed Enfield I think it was based on a $22 oil when we built the field, and that was a long-term price protection. So you don't like to sit here and say, we got bailed out by price, but it is absolutely true in this case.

It is not a situation right now that it is a negative territory or anything like that. We make a pretty good margin on it we expected even with the current situation going forward. Like I said, the reserves are still subject to change up or down based on this future drilling, so the new $500 million of capitalization, of which $300 million is ours, will be based on what we find out there. So that is part of the risk that is offset by our technology moving forward.

Mark Greenwood, JPMorgan.

I just had a question on the Sunrise project. Now that you have the Timor-Leste, Parliament has ratified the Unitization Agreement and the Maritime arrangements, I was just wondering how you think about Browse versus the Sunrise project? What are the relative merits of those projects? How do you think about just starting on which project you should proceed with first?

Yes, I think that is a great question. I'm glad you asked that actually. CEOs just love to have some really good positive internal composition. We let these projects go head up with each other, and basically we adequately staff all of them. We put good people on each one, and basically we let each one compete.

I think a lot of this has to do with our partners, how fast they may want to go in these projects, and now there is a little competition because they know Woodside operates both of them and which way we go. But if you take a look at -- definitely Pluto is going to go. At least in our present world, we see Pluto definitely going. LNG Train five kind of in our mind kind of fits out the rest of the reserves we have at North West Shelf at this time. So yes, I think it is a little competition between Browse and Sunrise which one gets up.

I think for the governments it is also important in the respect for Sunrise to make sure that fiscal certainty gets put in there. And you know, maybe there will be a little bit of a horse race there, which is not always bad.

Could you expand a little bit more on some of the merits of all the projects?

Okay. Well, Browse is big. It is just plain world-class stuff bigger than Sakhalin. Probably the third major resource, maybe the second major resource no knowing where Gorgan is going, but you know North West Shelf supposedly Gorgan, and then basically Browse are the three big chunks of gas opportunities. Appraisal is going well up there.

I guess the positive also for Browse would be actually we have worked with these JV partners before. They are the same partners with the exception of one, a limitation of one of who we have in the Northwest Shelf. We kind of know how they think, kind of what they do, kind of up to them. Technology-wise and reservoir-wise, technology we're looking at an interesting offshore concept for Browse, as well as an onshore concept. It is a situation where there is a lot of opportunity to optimize and to select train size, etc., etc. I think another big positive there, of course, is the potential customers are very used to Western Australia and Woodside as operator. I don't see a lot of downside to Browse to be quite honest with you. So I guess it's just the speed the joint venture wants to move. Agu has got a comment here on Browse on the reservoir end. He might want to add anything in on Browse.

It is early days, but as Don said, there is big volume, but the area that we're working is so large between 800 and 1,000 square kilometers that to some extent every well is an exploration well. We're learning a lot, and the numbers go up and down as we drill each well, but certify the remaining fairly robust around the 20 that we have already (indiscernible).

Sunrise, the same evaluation is that we're probably further along in the overall appraisal. You know, it has been so long since we did that appraisal, we're going to have to get -- I guess the negative is you've got to restaff the project. We've got plans to do that with the joint venture. You have got to dust off a little bit of the cobwebs of the knowledge of the field. You may want to drill a few new wells because technology has changed since we appraised it. So there might be a little bit more appraisal on top of it. Otherwise, we're pretty well ready for feed.

The concept of development there is pretty simple, but it's not simple in the respect of where we end up with the gas plant. The gas plant could go one of about three or four different places there, so we're going to have to work that. I think the other issue is, Timor-Leste has to approve the development along with Australia, and again it's kind of like how fast do they want to go, how much influence do they want to have in final decision. Agu, do you want to make any comments about the quality of the reservoir of Sunrise?

It is clearly better understood than Torosa in the Browse project right now. As Don said, technology is moving along, and we have been doing some very interesting work with wide-azimuth 3-D on the North West Shelf, and that is probably a technique that we would like to employ at Sunrise as well. And that will help us better define what to do with the reservoir. So some additional seismic is certainly something that the joint venture may well want to debate, and I think at this stage we are certainly looking at drilling a couple of extra appraisal wells.

Are the fiscal terms being finalized for the Sunrise project?

Fiscal terms, the PSC terms will not change. We're happy with the PSC terms. It is basically the agreement -- what it does is it resplits the same size pie between Timor-Leste and the government of Australia. So it does not impact our agreement or the fiscal operations of the Sunrise field.

You did not ask the question here. Let me just kind of throw something on top here because we did not mention it. I do want to give a little shout out to our Californians in the Company. We're at a point here I think we are going to get really into the game in our OceanWave project. I neglected to say something about it, but I'm pretty optimistic about how that has moved, where we're at over there, and I just wanted to make a mention of it because I think our workforce over there, our team over there has done a great job bringing that project along, and I think we're fixing to get in the game over there. So sorry about me asking a question to myself, but I am just kind of feeling guilty here that I skipped over that.

Stuart Baker, Morgan Stanley.

Just a couple of questions on Mauritania and then coming back to Pluto. Just on Chinguetti, I just wanted to confirm the $160-odd million I think is planned to be spent this year. Is that to recover the current 2P of 22 million barrels remaining?

I believe that number is 100% number. I think we are carrying around -- what is it? About 88 million (indiscernible) on our books. So what that includes is the following. It includes what ever work landed on this side of the beginning of the year on Chinguetti 18 doing a little bit of work on one other injector well over there while we had there. It covers the 4-D seismic, and also it covers what we call the 2B phase. We are in 2A at this time. But any work in the 2B that we do at the end of this year.

Okay, and just moving on to some of the other assets in Mauritania that received a little less priority, perhaps Tiof and Tiof-A and development of some of the opportunities did not seem to get a mention here today. Is there a price that is underway to sell or monetize this asset or the Mauritania assets in general?

Well, of course, we never preannounce any activity in that area until we make a decision or have some type of activity. I think what I have said in the past is where I stand today, and that is we've got to look at all of our assets the best way to monetize our value that we believe we have in. As to Tiof and [Lebedna] and [Naveva], we have had a really high-powered team on top of the base team to put some experts in there at the end of last year, and that is not to denigrate the work that has been done up to this point. But we really wanted to try and see what we had there at Tiof, and they have come up with an answer that is more encouraging than we have had before, although it is just for a small portion of the reservoir to see if we can make a go of it.

So I would say at this point we have got a constructive, positive outlook, but it is nothing really -- let me put it this way -- it is not a company maker or a game changer in that respect, but it is a go-forward plan for Tiof. Mark, do you want to make any comments on that?

No, I would just add, as we talked about in November and I think as we said in the fourth quarter, Mauritania remains an area for the Company that we are looking at every way that we can extract value from the assets. As Don said, we have been working Tiof quite hard on the development front, and all those activities are going to continue.

We're taking a quick look at the gas too. Not a quick look, but we have put a lot of people on the gas side this. We're going to take a look at those opportunities too and have -- everyday is just kind of a better answer as to opportunities set there.

Thanks. Just a final question on that. Given what you have invested in Chinguetti today and the licenses in general, which is about $0.5 billion and given the reserves downgrade, I am just wondering about whether the issue of asset impairment came up highly on the agenda. Clearly it has not been written down. I was wondering how close you are to that and how much fat you have got left in the book versus where it might go given the performance we have seen from it?

I think there on the impairment obviously when you look at impairment of any asset, whether it is Mauritania or anything here in Australia or the US, you have got to look at a couple of tests, and among the tests that you look at is not only what your internal valuations are under different pricing scenarios but what your external market benchmarks are. As you know, there actually have been transactions in Mauritania. Specifically I believe Hardman was bought by [Colo] and then BG sold out. When you look at the value of those transactions and what it would imply for the holding value of our Mauritania asset, we would not see an impairment at this time.

I just might mention on top of that that there is a lot of -- I think there is quite a bit of difference between a 10% non-interest or non-operator interest, a whatever Hardman was 26, 27% interest in comparing the boating rights, and also our 47% someodd interest as an operator.

Okay. Thanks for that. The final just another question on Pluto, just coming back to the second phase of investment, the compression of a couple of billion dollars or one to two anyway sort of five or six years in. That implies to me at least anyway a fairly steep pull on the reservoir given you've got 4, 4.5 Bcf. So it's a lot of money going in relatively early in project life to compression. I was just wondering how that investment sits versus perhaps other opportunities for that capital, which would be to obviously find more gas through just continuing to explore and/or buying or (indiscernible) trade gases others might have in surrounding reservoirs?

Well, I think we nominally place it out there at that time. You are right. You picked up a very good point here. That is probably the earliest that that field needs compression based on what we know now.

You are correct. If we find other exploration opportunities that provide positive results, increases your baseload of gas as long as it can be developed more economically and compressed. Also other people have contacted us. I'm not going to get into that again in very much detail, but it is one just other party out there. There's a lot -- I got to tell you on the Pluto thing, there was an analyst report recently that kind of had some assumptions that I read it and it was one of those where you almost picked up the phone and said, you know, you got this thing wrong. But the fact of the matter is we've got an awful lot of 100% exploration acreage around the area. We have an awful lot of interest. Don't always read what you read in the media. Just because a company says they are going to do something else, that does not mean they have additional gas.

But I do say that there is probably more than one other company that has contacted us and interested in Pluto. Especially now you know it seemed like when we actually started construction, everybody I think kind of felt like this is not really real. All they are doing is basically trying to wind the North West Shelf into a better deal or something like this. I got to tell you even the JVs just sat up and took notice. The world changed for us when construction started. This thing is now real up there. People I think believe it is real. People are knocking on the door. Mark?

Yes, I think that is right. If you look around the Carnarvon Basin, as I am sure we have all noticed from time to time, there is an inordinate amount of gas up there, but in terms of discovered and yet to find volumes. When you look at the discovered resources, there are a lot of resource owners who up until now really have not had a monetization route. If Pluto goes forward, they will have a monetization route, and it is not just the plant itself but the commercial arrangement surrounding the plant has been structured to take advantage of that fact.

One last item on that before we bore you to tears on this. There's a lot of those concessions out there that have been suspended and rolled over because there's no way to get the gas out called retention leases. You know, if you've got a viable opportunity in the area, there's an issue there that has some companies who are going to sit there and say, we better go and investigate that operation.

On the exploration side, we were planning to drill two to three wells to find extension volumes for Pluto this year. Unfortunately through the issues, we have had on Enfield, we have divided that rig capacity to the Endfield project. But if additional rig capacity becomes available in '07, then it is most likely that we would use that on drilling at least one if not two of the additional prospects in the immediate vicinity of Pluto.

Yes, the way I look at this and I guess this is basically when you have the ultimate trust in your exploration director, which I do in Agu and his team, Peter Moore, etc., you know we've got enough gas there. I see people (indiscernible) you don't have enough for 18 years. For the amount of acreage we have up there and the amount of prospects in the 2-D seismic, what I see, what they show me I should say, we've got plenty of gas to keep that train full for X number of years. When it gets down to me is, are we not going to find any more gas in the Carnarvon Basin within reach of Pluto in the next 12 years?

I think the answer is, if you take a look at our track record and with improved seismic technology and everything else that we have, to me we don't bank it. We don't pound it in our economics or anything else. I certainly don't believe that there's going to be any issue of getting a lot more gas in that area into that plant. I don't want to say a lot; I don't want to overblow this, but more gas into that plant just based on what we have already.

Bernard Picchi, Wall Street Access.

I just want to ask you about -- just a philosophical question about lessons learned from Chinguetti and Endfield and Otway. Each one has gotten off-track for a different reason, of course. But I'm curious about the common denominator that you see among those projects and what organizational and procedural reforms you can bring to the table or have brought to the table to minimize the chance of future problems? You have a lot of the things going on. One of the lessons that you have learned and how would you incorporate those in changes in your procedures going forward?

Thank you very much. What time is it over there?

It is about a 10:45 PM.

Yes. Okay. Good evening. I think you asked absolutely the right question. It is the one that I'm responsible for. Chinguetti and Endfield, and I got to tell you we look an awful lot like at Stybarrow, which is basically an Endfield, so how are the lessons being transferred to Vincent, Stybarrow, etc., that is the real question.

Looking back, let me just say that both the Endfield -- a couple of lessons. Number one, both the Endfield and Chinguetti, there's a lot of history here. Those reservoirs are really designed -- the design concept was done in 2002, 2003. We FIDed those projects in about February of 2004. So basically the base design was done -- what -- five years ago. So when you go back to take a look at our development team and how they did it at that time and the management decisions that were made -- and by the way, this is just not a bunch of employees that got it wrong or not quite right. Management is completely responsible for this back then and now obviously.

So what has changed? We have really changed a lot in the development group all the way from the director of it who is running it, all the way down to how we are basically designing it. Just simple little things about the quality of collaboration between geophysics, geology, engineering, the amount of seismic that you shoot on these fields. Also, in Vincent we're going to be doing a Phase I, Phase II. Actually what we have now at Chinguetti is a Phase I, Phase II along with Endfield. So, at the end of the day, the point is -- and I cannot go through it all right here -- there had just literally been 10, 12, 14 really key learnings in look back, and we absolutely are going through our future projects to make sure that we have not made these mistakes on them. And the execution will be a bit different. The collaboration will be a lot different within the groups of getting certain skillsets put together, and the management of the team is different than it was before.

One of the other areas is, is to make sure that the risk in these reservoirs are properly evaluated from the positive to the negative and make sure that what you might call bad news or downside risks are adequately conveyed to management and from management to management. So that these risks are absolutely identified not only by the development director but also the CEO, the CFO, the management team, the XCOM and the board of directors.

So I would like to sit down and have a coffee with you someday and just go through what we have learned. We have had a real -- we have had a reaal investigation as to these issues. There's all sorts of background 2001, 2002.

One other issue -- back at $20 oil, to get these projects to work, there are a few things that we did on the facilities, etc. that absolutely we won't do in the future. Sand control, a number of separators and things like that to make ease of operations a lot better for our field folks. So a long answer for you and I'm sorry to bore everybody else, but it is something that obviously I have spent a lot of time on in the last few months.

Good answer. If I can ask one other question of Mark, Mark, you talked a lot about the -- a little bit about the funding for Pluto. But if you take kind of a longitudinal view, kind of a long-term view of all the development projects you're likely to be tackling here in the next five years, Pluto and Browse, you know maybe a little bit of Sunrise,you are obviously going to be increasing your debt level. Can you give us an idea of what you anticipate that gearing to be kind of at peak and how you would fund it, what seems right now? I realize, of course, conditions can change in the Capital Markets, but what would be sort of right now the ideal funding mechanism?

Yes, I think you're absolutely right. I identified a series of phase projects or a sequence of projects that we're looking at, namely Pluto, Browse and now Sunrise with the announcement contingent upon fiscal certainty as Don was mentioning. But, if you take each of those in turn, when you look at our ability to fund Pluto, Woodside's ability to fund Pluto, if you factor into the equation the effect of the DRP, and remember what I said earlier, we have the ability to switch the DRP on at every dividend from here on out, that really provides a shot in the arm in the balance sheet in terms of gearing management. Obviously, as we go forward, if we move into Browse and then especially Sunrise in a relatively close period of time, we would have to reevaluate the mix between equity and debt in terms of our funding plans. But for the moment when we look at our plans as we can see it from now for the next few years, we definitely see that between the DRP access to the debt markets, we're not going to have an issue in gearing given where the oil prices are today. Obviously oil prices, as you know, are kind of a fool's game to try to guess, so I'm not going to try to guess them.

Angela McDonald-Smith, Bloomberg News.

I think one of your slides you said you started trading third-party LNG cargoes last year, and I just really wanted to get a little bit more information about that and how you see that going forward? And also just connected with that, you mentioned in the past Woodside wanted to enter the Atlantic Basin LNG market. Can you kind of let us know where you are with moving ahead there?

Yes, sure. First off, let me just say to have the aspiration that we have with our LNG equity and operations, we become a global player. To become a global player, you have got to be able to transfer your molecules throughout the globe. Clearly, if you have a huge basis in Australia, you are a long ways away from a few of the most valuable markets in the world.

So in this day and age you might have people who have a lot of gaps other places in the world, and you end up in arbitrage-type opportunities where you trade gas, etc. Third-party trading or buying third-party cargoes and trading them to help your good customers out of some bad times, etc., these are just additional customer capabilities and profit opportunities that we might have along the way. We have got this capability. We are increasing our shipping credibility, our trading capability. I thought we just ought to note that we're in that business now, and it is a bit opportunistic. We don't do this as a matter of having to do it. We do it as a matter of helping our customers, number one, and number two, trying to be smart about it and make some money on the side.

As to the Atlantic Basin, yes, clearly it should be obvious to everybody why we desire it. There's lots of ways to achieve bit. You can buy some physical gas over in the area. You can drill for it. You can trade your gas, so you might trade a train with Atlantic Basin. I mean there's lots of ways to achieve it. It is strategic. It is more than aspirational for us. It is a strategy. I cannot tell you right now that we're executing tactical plans to achieve it, but we would. And one of the issues I have mentioned like the bid we made for the Company something like [EPOL] is once you launch your ships from Australia and you go into the Atlantic Basin, you would certainly like to have the opportunity to make more money than your base contract, let's say, the Henry Hub Lake Charles by backfilling that with physical contracts or physical gaps that you may have in the states and send your LNG cargo to higher valued marketplaces that develop during the time that they leave. Mark, any comments to add?

I think what I would add to that is, as we pointed out previously, the interest in Woodside from the Atlantic Basin buyers really started about a couple of years ago, and when people first started coming through the door, we were a bit surprised that they came all the way out here. It gradually dawned on us one of the reasons they were coming all the way out here is number one, there is a plentiful supply of gas in Australia in terms of discovered resources and potentially yet to find resources. But number two, there is an increasing desire to see stability in terms of what the producers are able to deliver because these contracts and the supply horizons that they are making the investment decisions on are so long-term. So maybe from a surprised reaction a couple of years ago, we have become quite used to dealing with buyers in Europe, buyers in the United States and in terms of talking about Pluto as well as our future LNG output.

Anthony Bishop, Goldman Sachs.

Perhaps a question for Mark. I apologize if I have missed this in the presentation material, but have you identified the likely increase in CapEx associated with Neptune, (indiscernible) and Stybarrow given there has been consistent comments about budgets under pressure from other operator companies and yourselves?

If you look on the slide pack, bear with me for one second. If you go back and you look at slide number 17, which is the capital budget slide, that shows kind of our protection for 2017 -- sorry, 2007, those numbers are actually the kind of latest numbers that take into account the different things Don was talking about in relation to Neptune and the other projects.

Okay. But clearly there can be some timing differences there. Have you got a project by project breakdown anywhere, or can you give me some guidance on those projects?

That is on that slide.

Yes, nothing beyond what is on this slide that we have got identified for 2007.

Okay. I'm just thinking if Neptune rolls into 2008, for example, I might be missing the total CapEx spend. 2007 might not give it to me?

Yes, I think remember on Neptune from Don's earlier comments, number one, obviously we're waiting to see what operator ultimately decides in terms of what the schedule is going to be. But conservatively our idea is simply to forecast into the beginning of 2008. So you're not talking about a big slip. Yes, beginning going back to what we talked about earlier, it is really dependent upon what operator buys it.

Yes, understand. The second question, just in relation to LNG pricing, we have talked about increases in LNG prices. I appreciate it is a sensitive area. Correct me if I'm wrong, but the implication that seems to be being drawn by others in the market is that the Japanese contracts are, as I roll over into the new period beyond 2009, you have had an uplift in prices. And they also seem to be a second view that other contracts in the market as you highlighted have done without the escrow forming a bit of a more of a linear relationship with oil price and gas prices, and that they seem to be at significant premiums to the Japanese contracts and the roll-off of those contracts. Now is there any guidance or assistance you can give us in that regard in clarifying those two points of view?

Yes, I mean I think -- let me rephrase. Was your first question to confirm that when you look at recontracting with the Japanese that that recontracting is being done at a premium?

Yes, correct.

Yes, I think we have disclosed that before in actually our documents that, in fact, when we look at the results we have gotten, for example, out of North West Shelf recontracting, that has been at a premium. What was your second question?

And the second one relates to non-traditional and non-foundation LNG volumes from the North West Shelf potentially for contracts like Pluto or others to try and size that might be done with other parties, that they seem to be at significant premiums to those rolled over contracts if you like from our non --

Yes, I think what you see like, for example, is you will still see in Asia a bit of a distinction, although it is a rapidly diminishing distinction between greenfield and brownfield pricing. So when you look at North West Shelf recontracting pricing, those people are really looking at a brownfield price expectation.

In terms of how a particular contract is going to interplay against what is achieved with the Japanese recontracting, it is difficult simply because it depends on where you are in the oil price. Certainly, as you look on the upside of oil price, some of the newer contracts that are struck in the market are really aggressive, but it depends on how far the oil price goes. As I think you know, a lot of times oil prices are only specified for a certain range. After you get outside that range, there is another period that the negotiators have to get together. Sorry to be kind of complicated about it, but it is not an easy subject because a lot of it depends on individual one-off negotiations.

Is there any guidance you can give up on the likely gradient of that curve that we are seeing in terms of (multiple speakers)

The answer is no, (multiple speakers). You're going to have to (multiple speakers)

Nice try.

Thank you. Last question. Clearly there is a lot of thought your end has been going into in terms of managing the likely capital requirements as these large somewhat capital-intensive projects come on for the LNG. One thing that seems to be missing from the equation that is worth asking and you might shoot me down straightaway, but the subject of hedging. Is hedging going to be considered into the future to actually alleviate potentially some of these issues you have on the large capital burden that you have coming forward?

Yes, look we have I think disclosed that as a policy we don't actually look at hedging except in two specific purposes. One is in connection with acquisitions, but the second one is to underpin investment opportunities which might otherwise not be robust. I don't think you can see with any of the projects that we have been discussing in terms of LNG that either one of those are going to be applicable. It does not mean that we're not going to consider the whole spectrum of possibilities, but certainly I think it is completely different when you look -- as you know, we hedge Vincent at startup because we wanted to underpin some of the economics. That is not the same when you look it over at the LNG projects.

As always, we will lead you know transparently if we put any hedges on, so you can calculate it into your spreadsheet.

Okay. So apart from what you have got at the moment, nothing planned, and you think the LNG developments will really and truly stand on their own two feet with the pricing you have seen?

Absolutely.

Stephen Bell, Dow Jones.

Don, just taking us back to Sunrise, you talked a bit about quite a lot a bit earlier on, of course. You mentioned you will need to restaff and all. Can you give us an idea of how many staff you're looking to put on there and really how much money the joint venture will be looking to spend in 2007 on that project?

Yes, first off, we will take most of the staff in our existing organization. We have got other projects that are coming to conclusion, etc. We will obviously be looking for a few more as we always do. The joint venture may want to put some people (indiscernible) into the organization. I don't know at this time we have talked about it.

The restaffing is not going to be as big of an issue as what people may believe. It just stretches. As to the amount of money, I think that the joint venture stated communication is through this entire stalled period. We've got a lot of work to do with the Timor-Leste government on resituating our people. I mean there is a whole networking that has to go on with a new team and the government players, getting through this fiscal certainty and some other things.

So I don't think you're going to see a whole large amount of money spent this year on it. Mainly this year is regearing -- I should not say regearing, but reteaming, making plans, getting everybody back on the same page, getting the governments lined up and getting our plans put together. So it takes a little while to reramp up these teams.

That pretty well finishes it, but let me just mention one other thing we have not talked at all about here with the exception of one thing, and I don't want to leave it. Woodside is a changing company. It is changing everyday around here. And the amount of capital that we have to spend on these new projects with the environment we are in, with the exceptional assets that we have in this Company. The other thing we're working really hard in this Company, but we work on it very quietly, and that is we're changing the culture of the Company. We're changing the cost equations of the Company. And it is all about making sure that we pay and spend all the money that we need to for safety, environment, mechanical integrity, preventative maintenance and training. But it is also spending as little dollars as possible on things that don't add to the bottom line that are not necessary, simplifying our business and basically making this Company run a lot more efficient.

We have been achieving that. I think some of these results here have snuck in here as you are starting to see some of the front-end on cost control.

The other area that Mark Chatterji and [Lori Tremaine], our new Controller, is absolutely adamant about is capital management. Make sure we have a really strong capital management in the Company.

So I just wanted to finish up with that. I did not feel good leaving this conversation without talking about that aspect of our business. Because it is -- at the end of the day, it is a cash flow business. It spits out dividends and growth projects, and we are really careful about how we spend every dollar, and we're getting more careful everyday.

So I want to just say to everybody, thank you very much. It has been long. For those of you that hung with us, thank you very much. We will be out there in the marketplace talking to the investors over the coming weeks and months, and we appreciate your interest in our stock.

That concludes today's conference. Thank you all for joining.