Business Briefing

Broken Hill Proprietary Co Ld
5 April 2000



BHP Petroleum Business Briefing March 2000 

by Mr Philip Aiken
President, BHP Petroleum
Bernie Wirth
Asset Team Leader, Gulf of Mexico
 
Sydney Australia
Friday, 31 March, 2000
 
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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.  
 
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.