INTRODUCTION: Good morning and welcome to the BHP Petroleum business presentation. I am very pleased you could attend. We are webcasting this presentation simultaneously with the physical presentation here in Sydney and I obviously welcome those people involved in the webcast.

I am very pleased to welcome Philip Aiken who, as you are aware, is the President of BHP Petroleum and in particular Bernie Wirth who has made quite a significant effort to come across to Sydney to present on

the Gulf of Mexico.I am sure that you will find what Bernie has to say on the Gulf of Mexico extremely informative.

MR AIKEN: Thanks, Rob, and good morning ladies and gentlemen and also good morning to those with us on the webcast.

As Rob said, the presentation this morning will be made by myself and by Bernie. I will start by giving you an overview of BHP Petroleum, much of which you are aware of, then spend some time talking about our growth strategies. A major part of the presentation will be from Bernie on the Gulf of Mexico and I will come back to talk about some of the things we are doing in gas, in what we call desert or access to discovered resources, and finish off with a summary..

To commence on production, as most of you will be aware, we have three major assets, two in Australia where we are not the operator, in Bass Strait and North West Shelf and also our major overseas operated asset at Liverpool Bay. We also have some other important operations. We are involved with four FPSOs in Australia, two of which we are the operator, Buffalo and Griffin. We also have production in Bolivia, in the North Sea with Bruce and we still have some production in the Gulf of Mexico although that is going to become much more significant into the future.

Looking at our production over the last few years, this chart shows the production in millions of barrels of oil equivalent per year going back to 1994. You will see the decline in 1999 following the Longford incident and the increase this year and next year. The increase over these two years is very much about Laminaria and Buffalo coming on-stream. Then there is a little bit of a decline as Buffalo and Laminaria come off their peak and then we hope to pick up in our production with Algeria Typhoon coming on-stream.

The contribution made by a small field like Buffalo often gets missed, we often talk about the bigger deals. But Buffalo was a project which came on-stream below budget and cost in a very short timeframe and although it is very small asset it is a significant contributor to our short-term cashflow and profitability.

We will continue to look for opportunities to develop other small accumulations like Buffalo in the future because they do have a significant role to play in our overall production portfolio.

I am not today going to talk in detail about our reserves. As you know, we report our reserves at the end of our fiscal year. Over the last few years we have been successful at more than replacing our production with our average over the period 1996 to 1999 being about 130 per cent. This year we expect to book reserves from Typhoon, from Keith and there will also be some other reserve additions and revisions overall.

Our exploration expenditure this year will be around A$250 million. A substantial proportion of this, as you can see, over 50 per cent, will be in the Gulf of Mexico. There might be an expectation that our expenditure was going to be less than that. I think some figures of $200 million might have beenused, but the reason our exploration is up is basically for three reasons. We have a 13th month in this BHP year. We also have some additional appraisal drilling which we have approved in the Gulf of Mexico, and also we have had the situation where so much of our exploration expenditure is in US dollars and obviously the decline in the Australian dollar, vis-a-vis the US dollar, means that in Aussie dollar terms our exploration is slightly higher. Split overall, our exploration budget this year expenditure wise will breakdown to about 70 per cent exploration and about 30 per cent appraisal.

We are currently looking at our budget for next year. I would expect our expenditure to be slightly higher. Once again, the majority of our exploration expenditure will be in the Gulf of Mexico, but next year we will have a higher percentage in West Africa when we drill our first exploration wells offshore Angola.

Cost base is very important. As everyone knows, in the recent lower oil price environment the oil and gas industry went into a fairly major cost reduction program. Obviously BHP has done likewise and will continue to do so into the future.

There's really three areas we look a costs. The first area is our finding and development costs and the figures we have reported over the last three years of US$4.82 a barrel benchmarks very well against our peer group. Once again, at the end of the year when we do our final figures, we will report our results for the BHP trading year

Tackling finding and development costs remains a major priority for us, and we believe that by maintaining our focussed exploration program in specific areas where there is very good prospectivity, we can continue to drive our F&D costs down. Another important part is are our partnerships and partnering with the major leading companies. This is very important to achieve best practice outcomes.

Operating costs are also important to us and this year our operating costs are down about 60 cents on last year, year to date. Last year was about A$5.36 and we are running about A$4.75 now. This is an area which is very important because obviously it is a major contributor to our earnings. Overall we continue to work with the operator in assets where we are non-operator to make sure they reduce their operating costs, and obviously in our case as operator a major initiative has been on Liverpool Bay. I will talk about Liverpool Bay in just a moment.

In terms of G and A costs, the petroleum industry is not a high overhead business when it comes to manpower, but we have reduced our G and A costs from about A$30 million to A$25 million per month over the last couple of years and this has been quite a significant reduction. Overall, our manpower as an organisation has reduced from just over 3,000 people to about 1,500. Some of these reductions have been the cause of asset disposals and obviously a big chunk of that decline was following the sale of the downstream business in Hawaii.

But we have also worked very hard to get our organisation very focused. We have a portfolio group. Actually as part of BHP we run our business by assets, and we now have global resource teams supporting these assets which means we get efficiency across the whole organisation and we will continue to manage our cost base very strongly. In Australia we have reduced our numbers quite significantly as we have actually changed our operations, but we are not cutting back everywhere. In fact in Houston our numbers have increased by about 12 per cent.

The rationalisation of our operations in Australia means that we are going to be completing our move out of 120 Collins Street. This has been an opportunity created by the fact that we employ a lot less people in Australia. When BHP Petroleum first established at 120 Collins Street back in 1991 there were 920 people there. We in Australia at the end of this exercise will have about 280We have taken the opportunity to transfer parts of the business to Perth. The North West Shelf asset team is now totally in Perth, as is the Australian operated asset team. The rest of the operations in Australia will be located at 600 Bourke Street [Melbourne].

I think this is extremely important because BHP has a very major initiative on shared services and Petroleum will be part of that and obviously leveraging off that will be made more possible when we are actually in the same building.

Let me now return to operating assets and operating costs and talk a little bit about Liverpool Bay. This chart shows the gross operating cost of the Liverpool Bay asset development. What I have done in looking at these numbers is extracted one-off remedial repair costs. For example, back in 1998 these added about $20 million to our cost base. But since 1998 our normal operating baseline opex has actually reduced by about 18 per cent. We have got targets to reduce even further from the 54 million pound figure you can see in our budget for the current year.

It's always very dangerous just looking at operating costs in isolation. As I think most of you know, the UK's current tax base means that you have very strong margins and therefore in looking at the total cost of Liverpool Bay you have to take into account the lower government tax in the UK. I think that's a significant improvement and, as I have said, we have achieved 18 per cent over the last two years and we would be hoping to achieve more in the future.

This reduction in operating costs has not been from one particular initiative, it has been from a series of I have listed them there. I won't go through them all. Obviously we have done a lot of work on renegotiation with our major supply contracts, our logistical support, and we have really done well with our records and alliance-based contracts with our contractors overall.

The fact now is that Liverpool Bay's cost base has improved and our production performance has also improved. Oil production is stabilised and our gas production has been very, very good. The last two negotiations we did with PowerGen have now reduced the gas price such that PowerGen looks like taking more gas in say summer months. This is very important. It means that we commercialise the gas much earlier than we would have expected by having a contract now which reflects market prices.

Although Liverpool Bay has been a troubled asset for us, I think we have done a good job on the cost base and we are quite pleased with the operating performance.

It would be remiss in this introduction if I didn't talk about the oil price. Obviously oil prices in recent weeks went into high figures, in excess of US$30, and in the last few days we have seen the effects of the OPEC meeting. I think the market had basically built into the price reductions in the last few weeks what they thought was going to happen, and I think if you look at today WTI increased 25 cents last night.

Year-to-date we have achieved US$22.86 and you can see there what we have achieved in the February quarter year to date. This is if you exclude hedging. Hedging is a major part of managing our oil price exposure. Last year we entered into a strong hedging program which was to lock in cash flow for the corporation, and those results were reported to you with our six months results.

Going forward, we have what we reported, that six month figure, and we also have some limited coverage into next year. In the first and second quarters we have less than per cent of our production are hedged at a figure of just over US$20. This will be reported to you in more detail with the third quarter results. I make the comment that in looking at oil price hedging we must look at it in terms of the total BHP picture We have a price risk management committee which meets on a regular basis and there is a major review currently taking place looking at what BHP can achieve and wants to achieve from its hedging. Hedging is just one part of the equation we have to look at when looking at the total price risk exposure for BHP as a company.

Just to show you that we actually are quite resilient to oil price, I have tried to show on this chart the impact of oil price on our return on capital. Paul Anderson at a recent presentation to the Securities Institute of Australia talked about a 12 per cent return on capital goal for BHP as a corporation. You can see that because of the assets BHP Petroleum has, we can achieve 12 per cent at an oil price of around US$16 a barrel. This really shows the high quality of our asset.

If you are wondering what that line at the bottom is, that adjustments shows that if oil prices were at a low level we would cut back on our expenditure. We continue now to operate in an environment, where we always look at baseline and we always look at what we can afford to do if oil prices go up or go down. So we do run our business quite flexibly. Obviously the challenge for us going forward is to replace those very good assets with even better assets in the future.

I think the greatest example of this - some of you might have expected me to spend some time talking about our operating costs and our F&D costs. We do every year refer to them and we will give that benchmark information at the end of the year. I would just like to show one graph which we are very pleased with. This is prepared by our Petroleum Finance Corporation and it is an independent benchmarking of net income per barrel of oil equivalent for the industry. You will see there in that list that in 1996 to 1998 BHP had the highest net income per barrel in the industry. That's something we would like to try to replicate in the future.

Let me now turn to how we believe we are going to achieve that and talk about our growth strategies. To commence with, I think we have to realise where BHP sits. In terms of production, we rank about number 18 in the world and it is a similar situation when it comes to reserves. However, to get to number one, number two or number three or be a supermajor we would need to be about ten times larger than we are today and we recognise that is not achievable. Therefore, our strategy is to look at being a very focused niche or specialist player. We recognise we cannot compete with the scale and scope of the supermajors, but we do believe in the niches we choose to operate in we can compete quite successfully.

What do we mean about being a niche player and what does it mean overall? This really tries to explain what we see as the characteristics of a niche player. A niche player is somebody who has to have a clear focus, has to have highly strategic alliances and look at highly strategic and smaller acquisitions. We have to emphasise our entrepreneurial skills, and we have to look pretty strongly at how we can leverage off our parent BHP and what synergy we can develop with BHP Minerals.

I think this is most important because having said before we are number 18 in terms of production and reserves, if you actually looked at BHP as a corporation we would rank in size about number 10. Obviously one of the strengths that BHP Petroleum has is the leveraging it can obtain from the corporation and also off opportunities which come with our minerals business.

What we have selected is to actually operate in what we call three niche areas and I will briefly describe these. The first, which we are going to hear more about in a minute, is deepwater. Our deepwater strategy is about capturing high quality resources. We have these in areas which display good fiscal terms and, particularly in places like the Gulf of Mexico, we are mostly in areas of low political risk. Obviously establishing a strong land position is vital and we believe that the positions we have established in the Gulf of Mexico and West Africa now give us very good opportunities to develop a deepwater niche for BHP Petroleum. As I said, in a few minutes Bernie Wirth will give you a much more detailed presentation on where we are in the Gulf of Mexico.

The second focus area we have is what we call our gas niche. This is a very important area for us because the gas industry is one which offers high growth. It is also environmentally robust and obviously we are looking to leverage our position off where we are in Australia. I will talk more about the Bass Strait and North West Shelf later on, but we are looking to establish other good strong positions in gas and we have opportunities in Pakistan and Trinidad, for example, which we hope to develop over the next few years.

The final focus area for us has been called in some of our presentations our desert niche and this is really about getting access to discovered resources. This is where you have high quality resources at acceptable returns. We believe that this mostly applies to the Middle East and North Africa and overall we believe that the political risk can be managed. For BHP, this is an area where we can actually use our Australian identify and our identity with BHP overall. We believe that we can continue to develop these areas quite strongly. To date, most of our emphasis has been on Algeria but we are looking at other opportunities in the Middle East and other parts of Northern Africa.

So overall these three niches have been identified and are the three areas we are specifically focusing in on at the moment. I would just like to show, though, that these weren't thought up overnight. In fact, to some degree I think these are part of a strategy which has been evolutionary. If you go back to the early 1980s, there has been a number of areas where we have developed into, where our focussed exploration program has really led us into early entry in the Gulf of Mexico and is now into the deepwater. Our position in the desert niche or where we are looking for these discovered resources really does flow out of the Hamilton acquisition some years ago which gave us entry into Algeria. Obviously our gas business we are looking at has developed out of our strong positions in the Bass Strait and North West Shelf.

We have over the years gone into a number of areas and withdrawn, and the obvious one we show is the downstream where we went into the downstream business in Hawaii but of course we have withdrawn from that business. So I believe this overall is where we have actually shown where we have evolved our technology, we have evolved our people and it is a strategy which has evolved over a number of years. So our real focus going forward is to continue to extract value from our existing asset base and we don't forget our existing business. We continue to optimise those operations as I said before. We will try to grow the business by pursuing selected niches where we can materially develop high quality assets and contribute to growth in shareholder value. Now the tools are familiar to you all, and they are the tools we use as we move forward to develop these strategies.

What I would like to do now is to hand over to Bernie who will now give you more detail about what we are particularly doing in the Gulf of Mexico and how that applies to our deepwater business.

MR WIRTH: Good morning. It's a pleasure to be with you in Sydney this morning to provide you with an update of BHP Petroleum's Gulf of Mexico activities. I have personally been involved in BHP's Gulf activities for a number of years and I have seen the asset evolve from a pure exploration play to a more balanced business involving exploration, appraisal and near term value deliver. As Phil mentioned, BHP Petroleum is a focused niche player with one of its strategies designed to deliver material value to our shareholders through the development of a deepwater business. In the next 30 minutes I will provide a summary of our recent activities as well as an overview of our future plans.

Just to provide you with a road map of today's discussion, the first segment of my presentation will provide a general background on the deepwater Gulf as well as a couple of slides showing the indicative economics of the deepwater discovered.

It is our belief that there is a compelling value proposition here for our investors as the deepwater Gulf offers access to world class reservoirs on good fiscal terms with manageable exploration rates. The reminder of my time will be spent on BHP's position and strategy in the Gulf, with emphasis on our recent discoveries. I will conclude with a look forward at our exploration portfolio and give a snapshot of our activity over the next two to three years. 35

Now for just a brief geography lesson. The Gulf of Mexico is a partially land-locked basin connected to the Atlantic Ocean by the Florida Straits and the Yucatan Channel. Our activities are conducted entirely in US waters. They are focussed in the Central Gulf Planning Area. If you note the dark blue 2,000 metre contour line in the central area which is very near a large BHP acreage position that we have in the Atwater foldbelt. The Eastern Planning Area has not held a lease sale since 1988, but it is planning a future sale in December 2001 and BHP and a number of other companies are looking forward to that bid round in the future. The Mexican side of the Gulf, or to the south of the dark blue line, there is deepwater prospectivity but it is not currently open to outside investment.

The Gulf of Mexico remains one of the world's exploration hot spots. It's hard to believe that the basin has matured from its 1995 description as being the Dead Sea. This slide shows the top three exploration areas over the last decade ranked by oil found on the left chart and gas found on the right chart. This data was recently published by Cambridge Energy Research Associates and includes both shallow water and deepwater discoveries. You can see that the Gulf of Mexico ranked second in oil with 7 billion barrels discovered, and first in gas with 35 trillion cubic feet. In the deepwater we estimate that it has delivered proven and probable reserves discovered to date of approximately 8.7 billion barrels of oil equivalent.

It is anticipated that the Gulf of Mexico will continue with a strong growth phase for some time because of the relative immaturity of the play. In this regard, we estimate that there are some 13 to 20 billion barrels of oil of undiscovered resources in the Gulf. Our production from recent discoveries is forecast to increase as illustrated over the next slide, which shows that the expected growth in combined deepwater and flex trend production in the Gulf of Mexico over the next several years will climb from 4 billion cubic feet of gas per day, almost doubling to 9 billion cubic feet of gas by 2010, and oil production will double from 1.2 million barrels per day to 2.4 million barrels per day during that same time period. This production forecast, also provided by CERA, includes flex trend and thus consists of production from water depths in depths greater than 600 feet.

CERA's assumptions also include that there will be a projected increase in exploration spending over 1999 levels, and that is primarily due to the increase in the number of deepwater drilling rigs that are now coming on to the market and are under long-term contracts.

Looking to just the deepwater, for our purposes we define deepwater as being 1,500 feet and greater. The following slide illustrates the production history of 12 months ending July 1999. During this time over 750,000 barrels of oil equivalent per day were produced from deepwater Gulf of Mexico fields. Since then, several significant fields have come online. If you look at the anticipated plateau production rate of those fields that will add an additional 400,000 barrels a day to the 750,000 barrel per day number you see here.

The production shown is shared by a number of companies but it is very much dominated by Shell and BP Amoco. However, with the Typhoon project, which I will talk about in a few minutes, we look forward to joining this list of producers in the near future.

We have shown that we can find it and produce it. Can we make any money on it? Besides being productive, the Gulf of Mexico is also very profitable with direct access to the voracious US oil and gas energy market. This next slide illustrates the very large fields in deepwater.6,500 feet in this example are economically attractive. This example was chosen, it's a 500 million barrel case, as it is representative of the kinds of opportunities that BHP is principally targeting. Returns in excess of $5 a barrel in a flat nominal US$18.50 WTI price environment are expected after all costs, including a notional $1 per barrel exploration cost, are deducted. Now, lower prices reflected here by the second bar, which is a flat nominal US$14.50 case, investor returns are still acceptable.

The important point to note here is that the government take in the US does not disproportionately increase as prices and volumes increase. It should also be noted that this analysis does not include the benefit of royalty relief. Since 1996 and the passage of the Royalty Relief Act, leases in greater than 800 metres of water depth automatically are exempt from royalty on the first 87.5 million barrels produced. Between 400 and 800 metres this amount is reduced to 52.5 million barrels, and then to 17.5 million barrels between 200 and 400 metres in water depth.

Currently, 68 per cent of BHP's deepwater acreage is subject to royalty relief. If a lease is issued prior to 1996 companies can apply for royalty relief. Royalty relief lowers the US government take from an already low 43 per cent to 35 per cent of taxable income, which is the US corporate tax income rate.

While we are targeting large prospect sizes, this next slide illustrates that smaller fields can also be economic. On this chart the economics for fields in different sized water depths of 6,500 feet, shown in yellow, and 2,500 feet, shown in red, are estimated. You can see that in the case of the 6,500 foot water depth, the economic cutoff rests in approximately 209 million barrels in size. By comparison, at 2,500 feet this cutoff is reached at a field size of approximately 100 million barrels.

These economic thresholds are for standalone prospects that require expenditures and infrastructure. In the case of smaller fields, such as Typhoon, that are more proximal to pipeline infrastructure that economic limit can be much smaller as is indicated by the dashed red line you can see here. Besides field size and proximity to infrastructure, key drivers include individual well rights and ultimate well recoveries. The potential for high rate, high ultimate wells in the Gulf of Mexico have been very important factors in lowering the threshold for economic fields. It is now feasible to expect that the best deepwater fields will produce up to 30,000 barrels a day per well and, in the case of a gas well, from 100 to 300 cubic feet a day. The cumulative production from those wells can range from 15 to 20 million barrels per well.

This is compared with an average of 500 barrels a day and 2 million barrels cumulative production for average wells on the Gulf of Mexico's outer continental shelf. With that kind of productivity and ultimate recovery, you can see why we think that the Gulf of Mexico has very considerable potential for value creation.

Akin to value creation is establishing a position early in the maturity of a play. We have been active in the shallow water Gulf of Mexico since the early 1980s and, in fact, we still have two producing fields; West Cam 76 and Green Canyon 18. They are a legacy of that activity.

In the early 1990s, BHP and other competitors began to appreciate the commercial potential that the deepwater holds. Our experience with subsea and floating production systems gave us confidence that the technology would be available to economically produce in ever-increasing water depths. That confidence resulted in the decision to acquire a considerable ultra deepwater acreage position in several prospective plays during the mid-1990s when many of our competitors were focused on the deepwater, but they were focused on the 2,000-3,000 foot water depth play. There is no substitution for recognising an opportunity ahead of the pack and buying right, as it were. In fact, BHP was the leading debtor in the 1995 Central Gulf of Mexico lease sale, and has acquired its position at a cost well below that of the industry average.

In the five year period from 1994 to 1999, BHP's average acquisition cost is approximately US$450,000 per block. The average acquisition cost per block for seven major oil companies during that same period was US$550,000, and for six independents was US$1.2 million. In total, BHP has spent approximately US$65 million on its deepwater acreage position. In contrast, if you noted the results from the last Central Gulf of Mexico lease sale, Exxon Mobil exposed US$57 million on high bids and three blocks in the Mississippi Canyon area on a prospect which is near BP Amoco's Crazy Horse discovery.

With 204 blocks, BHP is now the eighth largest lease holder in water depths greater than 1,500 feet. In the last sale we bid on six blocks, we were the high bidder on three of those blocks which are primarily fielding blocks around existing acreage positions. Another component of our strategy was to partner and form joint ventures with technically and financially strong partners who had already established a position in the deepwater play. As a consequence, our acreage position, we are partner in joint venture with BP Amoco, Chevron and Exxon. Being an early entrant, we hope to enjoy the benefit of higher quality acreage and ultimately that will flow through to lower finding costs.

Our success to date supports this contention as BHP has participated in 12 exploration wells since 1992 with five potentially commercial discoveries. Our technical success rate of 42 per cent compares favourably with the industry Gulf of Mexico deepwater rate of' 24 per cent. In our case, technical success implies a discovery of hydrocarbon but where commerciality has yet to be determined.

Now, these five discoveries, BHP is appraising three in the Atwater foldbelt. We have sanctioned our Typhoon development and previously we sold our interest in Pluto to Marathon Energy which now has this smaller field on-stream.

As I said earlier, BHP has a substantial position with leases in the deepwater and another 19 exploratory blocks in the shelf trend area which is principally around our currently drilling subsalt prospect at Viper. Blocks in the Gulf of Mexico, as you may know, are small. They are three miles by three miles. They are individually acquired and bid on in a cash sealed bid at an annual lease sale. While we do have a substantial lease hold position, our total acreage under lease is only twice the size in square kilometres of our permanent in WA-260-P. Our acreage is concentrated in several independent play fairways, the most prominent being the Atwater foldbelt and the Green Canyon areas where we have significant discoveries.

The first of our discoveries from the deepwater program expected to be on production is Typhoon located in Green Canyon. The Typhoon project, with Chevron and BHP each owning an equity of 50 per cent, is very well advanced. Now, the field is in 600 metres of water and it's approximately 100 kilometres off the coast of Louisiana and it is operated by Chevron. An integrated project team, including BHP personnel, has been formed to manage this development.

Typhoon was sanctioned in January of this year. It has all the major contracts let and we are expecting first production from the field in the third quarter of 2001. Peak production is expected to be 40,000 barrels of oil a day and 60 million cubic feet of gas per day. It has an estimated field life of six to eight years. In Typhoon we will use many tension like platforms which you see here, which is essentially off-the-shelf technology. It has already been employed in two existing deepwater developments at Morpeth and Allegheny. This TLP option was chosen as the optimum development design, primarily to maximise reserve recovery and to mitigate flow risk issues. The Typhoon development has been approved for an Australian budget of $192 million net to BHP.

Typhoon will be a significant accomplishment for us in that we will have first oil in less than three and a half years from discovery date and perhaps, as importantly, it will provide important learnings to BHP for a more complex Atwater foldbelt discoveries that I will talk about in a few minutes.

Turning to the Atwater foldbelt. The Atwater foldbelt is a 300 kilometre long geological trend where BHP has established the dominant land position in the industry. We have identified numerous high potential prospects and we have 100 per cent success rate in having drilled three successful wells, three exploration wells, and have three discoveries. The principal play consists of Miocene aged sand in four-way closure along these folds. We elected to get into the trend because of the size of the structures which can cover between 15 and 20,000 acres and have up to 5,000 feet of relief.

Today the total of ten wild cat wells have been drilled by industry in the trend with four technical successes.

BHP has 130 blocks in this trend which we acquired for US$33 million. It is in water depths, ultra deepwater, from 5,000 to 9,000 feet and we have between five and seven years remaining on the lease term. Another important point to note is 75 per cent of our leases have guaranteed royalty relief.

In the near term we are going to focus our activities on the western Atwater foldbelt and also to the south-west at Walker Ridge. In future exploration activities will be geared toward the central and eastern Atwater foldbelt areas.

The subsurface and drilling challenges faced by BHP in these areas include seismic imaging, poor pressure prediction and, of course, drilling efficiency. Most of the features are covered by several thousand feet of salt and that makes traditional seismic imaging very difficult. However, there have been advances in seismic imaging techniques, for instance pre-stack depth migration, which are being used by BHP and other operators to identify and delineate prospects. In water depths greater than 5,000 feet, controlling of drilling costs will be a very key success factor. The key to drilling efficiency is designing a casing program and having an understanding of the poor pressure environment. From Neptune 1 in 1995 to the recently drilled Mad Dog number two well, BHP and its partners have realised a reduction of 61 per cent in drilling days required per thousand feet drilled by utilising the experience and knowledge gained from subsequent wells.

It may be presumptuous on this next slide to compare Bass Strait with any frontier exploration area, but we have done this just to get a perspective of the size of the Atwater foldbelt which compares favourable in area with that of Bass Strait. Similar to Bass Strait, BHP has high equities ranging from the mid 20s up to 70 per cent, and our average equity is approximately 40 per cent. It is still very early days but our vision is to find reserves on a scale with that of Bass Strait.

The next slide focuses on our three Atwater foldbelt discoveries. In 1995 BHP signed a joint venture with BP covering the western and central foldbelt areas. Neptune was the first discovery in the trend, followed by Atlantis and then Mad Dog. We drilled an appraisal well at Neptune and hope to drill a second appraisal well some time in the future after further appraisal is done at Atlantis and we have an assessment of what the infrastructure options and implications for the area will be. The first Atlantis appraisal well is due to commence in April, and it will be operated by BHP. We will use the global marine drill ship.

We recently completed the drilling of the Mad Dog number two appraisal well and recently issued a press release indicating the net feet of pay in that well. That well extends the discoveries significantly to the north and the next appraisal well will be planned for later this year.

We are very pleased with the results to date and have commenced preliminary engineering studies at Mad Dog with our partners BP Amoco and Unocal. It is really too early to quote any meaningful numbers in terms of possible resources for Mad Dog, but we would expect to it be in the multi-hundred million barrel range, but we really need to complete our appraisal program before we can be specific. Any time you're involved in appraisals there are ups and downs, and before we are confident as to what that number may be we want to withhold any of that information.

Referring back to the indicative margin analysis that I showed earlier, we would expect development costs to be in the US$3 to US$4 barrel range. In a field of this size we anticipate three years from sanction to the date of first production.

Going further on this slide to the southwest it shows three potential prospects located in an area that we call Walker Ridge. We just announced a joint venture on these prospects with Total Exploration Production USA. It involves drilling of an exploratory well at Chinook in 8,800 feet of water with the CR Luigs drill ship later this year. BHP will act as operator and will reserve a 70 per cent interest at Chinook and a prospect directly to the west which we call Klondike. Total will retain an option to earn interest at a later date on the Cascade prospect to the north.

Our decision to bring in a partner on these three prospects is part of an on-going portfolio management effort. It includes farm-outs to managed risk and is well to extend our exploration expenditure. We will have copies of the press release for you at the conclusion of our meeting this morning.

The next two slides we have taken some liberty with some local landmarks. To get a sense of scale of the Atwater foldbelt discoveries, this side compares the thickness of the Mad Dog pay with the height of the Sydney Harbour Bridge pylons. We change this when we go on the road. When we did this for Paul Anderson in Houston recently we compared the height of the Houston Building which is a 22 storey building, which is approximately the size of net fee of pay of Mad Dog.

Not only was the thickness of pay of the two wells impressive, but they are located more than three kilometres apart, approximately from Centrepoint Tower to Kirribilli. I walked some of this distance yesterday and I was thinking of this slide the whole way.

How are we going to get these fields on production? Development of fields in the ultra deepwater is unquestionably a change. This slide illustrates how the industry has continuously pushed the limits of deepwater development through technological innovation. It took 15 years to get production from 1,000 feet to 3,000 feet at Auger, but it took only four to go from 3,000 at Auger to 5,000 feet at Mensa. The current record for deepwater production is held by Petrobras which is producing from a field in 6,000 feet of water offshore Brazil.

Our view is that developments and water depths ranging from 7,000 to 10,000 feet will be technically and commercially feasible within the next few years. The hull forms are known and are well understood. Drilling and completion has always led developments by several years. The challenge in these water depths is how to moor the hulls and connect the wells to the surface. Essentially, in so many words, we are comfortable with what we are going to put on the water. We are also comfortable with what is going to be on the seabed. Our real challenge is how do we connect the two.

As Phil indicated earlier, BHP will spend approximately Australian $150 million in exploration in this fiscal year in the Gulf of Mexico, or about 55 per cent of our total exploration budget. The projected span for the next fiscal year will be proportionally about the same and should increase, but the total budget has not yet been finalised. As you might imagine, a significant portion of these dollars will be spent on appraisal activities in the Atwater foldbelt. This slide gives an approximation of the exploration wells we plan to drill over the next two to three years. Our intent is to participate in five to ten wells per year over the next couple of years and during that period of time it will be critical as we test several new play fairways.

As in the past, we plan to seek farm-outs, promotes and well carries as a means of extending our exploration budget and reducing our finding cost. We are always looking for more commercially innovative ways than using other people's money. For example, BHP was almost totally carried in the recent Mad Dog discovery well, and we'll pay a reduced well of the Chinook well later this year.

Before I hand the podium back to Phil, I would just like to say that we believe that the Gulf of Mexico is a premier basin in which to grow our deepwater business. It has world class potential, very, very attractive fiscal terms, and access to a premium oil and gas market. We've built a very strong position and we have projects that are short, medium and long term. Finally, you can rest assured that the Houston BHP team is very focused on delivering value on high quality opportunities as rapidly and efficiently as possible. Thank you very much.

MR AIKEN: I know many people have asked about the Gulf of Mexico and we decided today was a good opportunity to make this presentation. I think it is very exciting and I think today gives you an understanding of the various opportunities we have to develop the very strong position we have in that part of the world in the future. I am now going to go back and talk very briefly about our other two focus areas because, obviously, we wanted to spend more time today talking in more detail about the Gulf of Mexico. I will firstly talk about gas.

Obviously gas is very important to us, not only here in Australia because of Bass Strait and North West Shelf, but we are also a major supplier of gas in the UK out of Liverpool Bay and out of Bruce. We have a number of areas in which we can grow our gas business and I am going to talk briefly about three of those today.

The first refers to the Bass Strait which of course was the genesis of BHP Petroleum, a world-class hydrocarbon basin if ever there was one. The historical focus, though, of Bass Strait has been on oil. 87 per cent of the oil has now been produced out of Bass Strait. On the other hand, gas has only had 47 per cent of the gas discovered produced to date, some 4.5 tcf, and there is still some 22 per cent under contract for future production, and 31 per cent uncontracted gas reserves out of Bass Strait .

Now, the opportunity for BHP going forward is extremely important that we develop that gas and it is very important what has happened in the last few years in South Eastern Australia overall in gas industry development. For example, we now have a much more extensive pipeline system. Pipeline connections are coming into operation which will basically change the way business is done in New South Wales and Victoria. The completion of the Eastern Gas Pipeline will symbol a change in the supply and demand balance for all markets currently served by the Gibson and Cooper basins.

Another exciting new prospect for us is the proposed pipeline from Longford to Launceston. If this deal could be captured it would offer natural gas to Tasmania for the first time and will obviously provide a significant new market for Bass Strait gas. It is not just in pipelines that there has been developments. Downstream there has also been development. For the aims of reform and the gas transmission system to become effective, one must open up markets to competition. BHP and Exxon is to commence supply to BHP Steel in Port Kembla and the Smithfield co-generation facility shortly after completion of the Eastern Gas Pipeline. BHP and Exxon, are already carrying solid gas into New South Wales by Duke Energy.

In terms of upstream developments, they will also talk place. The completion of the south western pipeline in Victoria has enabled the sale of gas from Western Victoria into the main grid. This pipeline will also play an important part in meeting future Victorian peak requirements as the western underground gas storage system comes into operation.

Feasibility work continues for other discoveries such as Kipper and Minerva, but all of these are relatively expensive developments when subject to the RRT regime. We continue to look at developments here but obviously at the moment there is significant capacity already discovered in Bass Strait for developments.

This chart shows the Bass Strait and its BHP's share of revenues. You can see here the declining income coming out in crude oil. Our current crude oil forecast is to decline at about 17 per cent per annum over the next six years. As that declines we believe that will be made up by increased gas supply by the developed markets with which we have projected. We are looking at about 35 Peta joules per annum into New South Wales and up to 20 Peta joules in other markets such as Tasmania.

You will see in the graph also a most important by-product of the gas. Gas sales means that there is increased condensate and LPG production, and this will take a big part in offsetting the decline in revenue coming from crude oil. The capex required to provide this additional gas production is minimal for Bass Strait and Longford, and it is only when new suppliers such as Kipper come on-stream that significant capital will be needed. So development of the gas market is most important to us in the future as we see the decline in oil production coming out of Bass Strait.

Moving to a new part of the world for BHP, we have a new opportunity in Pakistan. In Pakistan we have the Zamzama discovery. Zamzama is a large gas discovery with competitive development and operating costs. It is also very proximate to markets and infrastructure. Pakistan as a country has very good prospectivity and has the very significant on-going gas demand. In Pakistan we are going to proceed with an extended well test which will enable us to dynamically understand the reservoir, while it also gives us an opportunity to test the market for a long-term investment.

I would make the comment here that the extended well test development is a very low cost entry. It has very robust returns and has minimal capital, and it also gives us the opportunity to look at future developments depending on whether we can capture the market which we believe would have very robust and very good returns.

In finishing off in talking about gas, I think it is very important today that I comment about the North West Shelf, ALNG and the North West Shelf expansion. Earlier this week I was in Japan and I will be in China next week with the other principals from the North West Shelf joint venture as we continue negotiations for an expansion of the North West Shelf. These negotiations are obviously taking place in a very unusual period.

For Japan, the electricity industry is currently being deregulated and many of the large Japanese power companies are not at this stage able to commit. However, the negotiations continue with the gas companies, particularly keen to progress discussions this year.

When we set up ALNG over 12 months ago, it was very much recognised that the future of the North West Shelf would probably be in conjunction with markets outside of Japan. Over the last year or so, ALNG has signed a letter of understanding with Tuntex in Taiwan. As I said, we are visiting China next week and also we are looking at opportunities in India and Korea. We believe that going forward with the expansion of the North West Shelf will be a combination of Japanese and other markets.

I make this point in conclusion. The LNG market is currently going through a very significant and fundamental change. The old days of a group of buyers and a group of sellers getting together and agreeing a long-term contract are, for all intents and purposes, over. The future will be about individual contracts and also I think there will be a growing spot mark. Although this is a challenge for the North West Shelf, I also believe it is a very big opportunity to grew that business into the future.

The last specialist area which we talk about is what we referred to before as our desert niche, it was really about getting access to discovered resources. In this particular area BHP has been actively involved in Algeria, but we are really talking here about a number of other places. The Middle East, for example, has significant discovered resources and there is a lot of evaluation of projects taking place. There is many opportunities in the Middle East and one country that often gets mentioned in some detail is Iran.

Iran has huge reserves, 9 per cent of the world's proven oil and 11 per cent of the world's proven gas reserves. It also has very good opportunities with buy-back projects. Australia and BHP has good relationships with Iran, and Iran is also looking very seriously at developing its mineral sector. The Indian subcontinent is obviously an area of growing energy demand, and Iran is the natural place to look at supplying it from.

We will continue to evaluate opportunities in Iran and other countries in the Middle East and North Africa, but at this stage these are very much at the evaluation stage.

What I would like to do now is just briefly talk about our activities in Algeria. I must admit progress in the last 12 months has been depressingly slow. This has been for a number of reasons. The Algerian government changed last year and it was only in the last few months that a new oil minister and a new head of Sonatrach were appointed. As you know, in 401/402 we have changed partners, our partners now being Agip, and also we have taken the opportunity as part of our capital review processes to make sure that any longer term contracts we enter into in Algeria are thoroughly vetted and thoroughly understood. Because we are talking about significant investments in some very, very major projects.

The Ohanet project was a major wet gas project which is a significant challenge, but we continue to negotiate and remain confident of success. In Algeria we have the traditional 401/402 exploration play which goes back to 1989 and also this year we will commence seismic work on the Boukhechba Block 219/220.

The other development we are working on in Algeria is the development of 401/402. With this look, we are looking at integrated development with Agip producing some 80,000 barrels a day. We are looking here at oil reserves of approximately 280 million barrels and for BHP this would represent an investment of some of US $200 million. As I have said, these negotiations and developments have taken a long time, but I think reflects, not just the issues regarding Algeria, but the thoroughness which we look at these projects going forward, and I look forward to concluding those negotiations in the coming months.

So ladies and gentlemen, I only touched very briefly on our gas and desert niches today because we really wanted to spend more time in talking very strongly about the Gulf of Mexico. But in conclusion I would say, from this slide you can see that shows our various businesses and shows the value creation, we have a very full portfolio of opportunities to grow BHP Petroleum into the future. These number of operations, number of exploration plays, are looking at developing access to resources and obviously in gas commercialisation, but it is a full portfolio which we will continue to develop in the years to come.

That is the end of our presentation today. We have approximately 25 minutes or so where we can take some questions, so I will throw it open for any questions that you would like to ask myself or Bernie.

LAWRENCE GRECH from Deutsche Asset Management: Given that you have some brown field operations and some green field proposals, if you look at the average capital expenditure for the next, say, three to five years, what level is that capital expenditure likely to be. And exploration, again over the next three to five years as an average.

MR AIKEN: As I said before, this year we are going to spend circa A$250 million in exploration. I would see us going forward and spending more like a figure of A$300 million. This is all subject to budget approvals and all those sorts of areas.

Going forward, what we actually spend in capital I wouldn't like to average it out over a number of years because some of these projects are quite large. If the fourth train of the North West Shelf goes ahead you are talking about a $300 million commitment for BHP. Therefore, in talking about an average capital going forward, I think it is very difficult because it really depends on what projects we actually capture.

MR GRECH: Is it fair to say that to stay still at your higher level of activity that you need to spend in excess of a billion dollars per annum? Is that off the planet.

MR AIKEN: I think we are in that range in terms of our total exploration and capital programs, in maintaining or increasing our production from our current 120 million barrels a year.

IAN MAXWELL from Solomon Smith Barney: In previous discussions with management there has been some discussion about potentially trading long term exploration potential for some near term production to utilise the US tax losses. Can you give us a bit of an update on that and whether that is still the strategy.

MR AIKEN: As Bernie said, all of our opportunities in the Gulf of Mexico are reasonably long term plays. Typhoon will come on stream 2001 and we are looking at 2004 for Mad Dog depending on the appraisal program. Therefore we would like to get some production in the US which would be, from our point of view, a very good production because of the tax loss situation.

However, in acquiring production it has to be profitable to counteract the tax losses. So we continue to have a very, very strong screening program looking for opportunities to enter into either buying properties, buying parts of portfolios, or actually swapping opportunities. There are a number of things we are working on but there is nothing at this stage that has actually come to fruition.

MR MAXWELL: Are you optimistic something might come out of it?

MR AIKEN: I hope so.

KEITH WILLIAMS from HSBC: Could you just comment on the performance of Liverpool Bay in relation to the original feasibility study cost estimate, please.

MR AIKEN: Liverpool Bay has not performed anywhere near the original submission for a number of reasons. When Liverpool Bay first came on stream we had some significant problems with some of the pipelines and we have spent quite a bit more capital than we thought. Also our production has been nowhere near what we expected in the early days, so the performance to date has been disappointing, particularly from a liquids point of view.

The nameplate capacity of Liverpool Bay is 70,000 barrels a day. We are looking this year at achieving something between 50 and 60 thousand barrels a day. The main thing I think is important going forward for Liverpool Bay is to stabilise the oil production, and I think we now have in place, as I said before, all the issues we have taken have been very much to make that take place. What actually has happened with Liverpool Bay is we are accelerating the gas production. The commercial deals we have done have been such that we now have the opportunity to sell gas in periods of the year when the spot prices are quite low, and therefore that is going to assist the asset going forward.

The main priorities really are, having recognised that the asset has not performed as it was originally intended to, is to reduce the cost base and increase the reliability. We believe in the next few years if we can do that the asset will return to what we expected overall. You have to remember now, looking at Liverpool Bay, the two gas fields we have done have returned to BHP about $900 million in terms of prepayments. Therefore, on a RoC basis, Liverpool Bay is a very strong and very robust asset. It is really now about getting the production out of it and stabilising that production in the next year or so.

IAN GALLOWAY from Macquarie Bank: You mentioned there are a number of technical problems in the Gulf of Mexico, can you just elaborate a bit more? You mentioned the seismic imaging problems and pressures, et cetera. Can you just elaborate and give us a bit more detail? It is cutting edge stuff, a lot of the technology. Can you just give us more information on that.

MR WIRTH: Yes. Obviously, as I said, we are looking at salt related features, so the seismic imaging is really, from an exploration standpoint, the number one hurdle we have to get over. As well, one of the impediments that we have had from cycle time in the past has really been access to deepwater drill rigs. That situation has really changed, because if you go back three years there were approximately three rigs capable of drilling at 6,000 feet in the Gulf of Mexico. At the end of this year there will be approximately 22 deepwater rigs. So from the standpoint of the cycle time, your ability to drill prospects, appraise them once you have discoveries, we should see a shortening of that cycle time.

The deepwater drilling problems that we have encountered, it's interesting because if you look at different areas and different plays you have a different cost curve for your wells. The Atwater foldbelt itself is a very frontier play. However, BHP and BP have participated in most of the wells that have been drilled, so we have shown an interesting and a very good learning curve with the wells we have drilled in those areas. So we are starting to bring the drilling costs down. The plays are never going to work if you spend US$40-50 million on your exploration wells, or even on the appraisal wells.

In the 2,000 to 3,000 foot water depth range we know the subsurface strata data and we are more able to predict what the drilling problems will be and we can have a better handle on the drilling in those areas. But I really think that in the ultra deepwater gulf, particularly the Atwater foldbelt, BHP and BP are setting the standard in terms of drilling costs. The other thing to keep in mind as well is when you drill discoveries in your coring, your testing, you are doing a lot of things that other companies are not doing with dry holes. Your drilling costs do go up, but that is more a function of what you find. If you drill a dry hole it can be very cheap and a lot of companies are professing as to how their drilling days per thousand are industry best practice, but if you drill dry holes, so what. When you have discoveries and you're cutting cores and taking tests, are we are more than happy to spend the extra dollars associated with getting the data out of those wells.

ANDREW HINES from ABN AMRO: Just elaborating on that further, can you give us an indication of what the drilling costs are at the moment. What would it cost to appraise, say, Atlantis two well?

MR WIRTH: The approximate drilling costs are somewhere in the neighbourhood of US$30-40 million, US dollars. That depends on how many tests, cores, et cetera, that you have. Recently, Mad Dog number two well, that well for the straight hole was drilled under AFE and we would hope that we could continue with that as we go into the future. But when you drill wells in the summer in the Gulf of Mexico, you are in hurricane season, low current environment, sometimes there are weather problems but there is nothing that you can do to control as the operator. Just as a general rule of thumb in deepwater, you are probably looking in the 4,000 foot water depth anywhere between US$20-40 million.

MR HINES: So the exploration well coming up in the Walker Ridge area, what sort of cost would you put on that one?

MR WIRTH: It would be in the same ball park.

MR HINES: The joint venture you have with Total you retain 70 per cent interest?

MR WIRTH: Right.

MR HINES: That seems quite a high percentage to retain. Are you going to look for further farm-outs at all?

MR WIRTH: We want to drill the exploration well first and see what we find. With a discovery you are operating from a position of strength if you were to trade, farm down, et cetera. So really what we are seeking to do with that prospect, which is a very large prospect, is seeking to maintain maximum flexibility.

MR AIKEN: In light of there being no further questions, I would like to thank you for joining us today. You have a copy of the presentation and there's also a copy of the press release on the Walker Ridge farm-out. Thank you for joining us and we hope you found the session informative.

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