西方石油 (OXY) 2002 Q4 法說會逐字稿

Good day, all sights are now on the conference line.

Welcome to Vintage Petroleum's 2002-year -end earnings results conference call.

This call is for the benefit of its shareholders and other interested parties and any rebroadcast of this call for commercial purposes is prohibited without the permission of Vintage.

As we indicated earlier to you, people such as the press and Bloomberg can listen to the conference call but cannot ask questions.

I'll now turn the program over to Mr. Bob Phaneuf.

Thanks very much, I appreciate all of you taking time to be with us today.

On our agenda, just one or two housekeeping items.

Yesterday we made two press releases, one essentially an earnings release discussing the fourth quarter of 2002 [Inaudible] new targets, and we also made a second press release reporting our 2002 operational results and plans for 2003.

On the agenda today, I'll begin with a short discussion of highlights and try to walk you through reconciliation on earnings and cash flow.

We'll follow that with Bill Abernathy, our COO who will discuss year-end reserves, our production replacement and finding costs, as well as our '03 capital budget and revised operations target.

He'll be followed by Bill Barnes, our CEO, who will discuss revisions to the '03 financial targets, and Bill will also elaborate on our accomplishment of 200 million dollar debt reduction program, and also talk about our debt level and liquidity as it stands going into 2003.

Craig George, our CEO, will follow that and will discuss an overview of operations and take that to Q&A.

So we'll begin on page, for those of us who are following us via the Web cast on page three of the slide presentation, we'll begin with 2002 highlights.

Essentially we feel like 2002 was a good year in many ways, we achieved our 2002 production, our key cost targets, also, we achieved targets, or exceeded targets for cash flow and EBITDA, in addition we were very successful in achieving our $200 million debt reduction target.

Also, our exploration program gained momentum, as you'll see as Craig discusses some of those issues.

Additionally, we replaced 123 percent of our 2002 production at a cost of $3.23 per BOEand Bill Abernathy will elaborate on that, as well as proved reserves at year end, we ended up with 529 million BOEof reserves, after the sales of 13.3 million BOEof divestitures.

On page 4 of the slides we go into a little bit more detail on the 2002 targets, which we achieved.

First, with respect to production, our target was 32.1 million BOE, our actual results exceeded that, we were able to come in at 32.5 million BOE for the year, with fourth quarter actual at 7.7 million BOE production.

Additionally, we hit a number of our key costs right on target.

Our LEO (ph) we had targeted for $6.70 per BOE this year.

We came in a little under at 656 per BOE.

DD&A, similarly, a target of 540.

We came in at 543 per BOE there.

And finally, with respect to G&A, our target was $1.60 and we ended the year with $1.59 per BOE of G&A.

So we feel good that we hit a lot of our operational targets.

Additionally, we were successful in hitting our key financial targets.

EBITDAX, we had a target of 335 million.

Actually, we came right up against that at 334 million.

And we're defining EBITDAX as basically earnings before interest, taxes, DD&A, impairments, exploration expense, changes in accounting - impairments from changes in accounting principles as well as from the early extinguishment of debt and gains and losses from property sales.

So you can also make that - make that calculation to see that it foots (ph) .

Also, with respect to cash flow, we had a target of $230 million and actually achieved that target, coming in at $241 million as adjusted as we'll talk about on page five of the slide presentation.

And we thought it, hopefully, helpful to walk through a reconciliation of cash flow and earnings because there were a number of special items in each case, helping you to try and reconcile your earnings models with our results.

Cash provided - well, imbedded in the text of the earnings release and, again, on page five of the Web cast slide, is a reconciliation of cash flow provided by operating activities according to GAAP presentation, with adjustments to conform to cash flow presentation.

So that used by analysts and investors in order to reflect continuing operations.

Accordingly, what you see on this page is that we've made adjustments to remove the nominal impact of changes in working capital, current taxes on gains from property sales and early extinguishment of debt, which results in an adjusted cash flow of $241.3 million.

Again, about five percent above our targeted cash flow from operations for the full year.

Additionally, because there were a lot of special items, hopefully, it's instructive to walk through a reconciliation of net income, exclusive of these special items and other adjustments.

And similarly imbedded in the text of the earnings release is a reconciliation of special items which impact net income.

But we don't think that presentation is sufficient to easily allow investors and analysts to reconcile their estimates to our results.

Accordingly, on page six of the Web cast slide presentation, we've made adjustments to remove the substantial impact on income from special items, the majority of which are attributable to property and goodwill impairments, principally in our Canadian business unit, both for the fourth quarter and the year '02.

In addition, we've shown the per share impact of both exploration expense and currency translation gains and losses.

Since we don't provide published targets for either total exploration expense or currency gains and losses, the amount of impact anticipated in investors models is likely to vary widely.

On page six of the slide, we show that, for the fourth quarter, the net loss per share including special items was $2.08.

Deducting the per share after tax effects of the special items, which aggregate to $2.12, produces a per-share income of $0.05 per-share as shown on the third line in the table.

The after-tax per-share impact of all exploration expenses and currency losses for the fourth quarter totaled $0.26. $0.21 from the exploration extension pack and a nickel from the translation loss.

And these were deducted in the calculation of the first year income to arrive at $0.05 exclusive with special items.

That's to the extent that some of the $0.26 is not considered to result from analyst's and investor's modeled expectations of continuing operations, then that portion should be added to the per-share income of $0.05 to ascertain how closely the company's results mirrored earning expectations.

And a poor example there is - in the press release we talked about fourth quarter exploration expense being $21.1 million and approximately half of that is associated with cost - with the [Inaudible] prospects in Yemen that were written off.

In addition, we show the - sorry - similarly for the 2002 year, the company had per-share income of $0.48 excluding special items, and expenses equal to $0.40 per-share are included in that $0.48 number.

The result basically to account for the combined impact of exploration and currency gains in Yemen.

So again, to the extent that some of the $0.40 is not considered to result from analyst's and investor's modeled expectations of continuing operations, then that portion should be added to the per-share income of $0.48 to ascertain how closely the company's results actual mirrored earnings expectations.

Well, I hope that's helped rather than confounded things.

I'll stop here and turn it over to Bill Abernathy for his prepared remarks.

Thank you Bob.

I am going to spend the next several minutes giving a brief review of year-end 2002 reserves.

A reconciliation that goes back to year-end 2001 reserves.

I am going to talk a bit about Canadian reserve revisions and impairments, then I will move to the 2003 capital budget and the resultant operational forecasts that flow from that.

For those of you who are on the web cast, if you'll turn to slide number 7, then we will begin the discussion of year-end reserve summary.

Year-end reserves were composed of about 349 million barrels of oil, 1.1 TCF of gas - that's about 529 million BOEs equivalent.

The reference prices for the year-end for oil is $31.20 per barrel; for gas, $4.79 per MMBTU; and the present worth at 10% of that reserve cash is $4 billion.

Of these 529 million BOEs, 64% of those reserves were approved and developed.

For those of you on the webcast, we have some finding costs and production replacement figures on slide number 8.

We had net reserve adds of 40 million BOEs, this translates to 123% production replacement.

A finding cost of 323 per BOE, and that is using $129 million of capital allocated to oil and gas investments.

And if we examine only the extensions and discoveries portions of the ads, we get a finding cost of 570 per BOE.

Finally, our three-year production replacement and all end finding costs are 189% and 675 per BOE respectively.

During the year we sold assets in Trinidad and in the US totaling 13.3 million BOEs, so had we not sold those assets, the year-end reserves would have been something in excess of 542 million BOEs, or an increase of about 2 1/2 percent.

This is all compared to a year-end 2001, when the reserves were 535 million BOEs, and reference prices were 19.84 (ph) for oil, and 2.65 (ph) for gas, and the PW10 (ph) of that case was $1.9 billion.

Next, I'd like to take you through a reconciliation that gets you from the 2001 year-end reserves to the 2002 year-end reserves, so for those of you on the Webcast, that would be slide number nine.

Starting with year-end '01 reserves of 535 million BOEs, we produced, during '02, a total of 32 1/2 million BOEs, and we sold 13.3 million BOEs, which would yield an intermediate starting point of 489.3 million BOEs, to which we had additions from extensions and discoveries of 22.7 million BOEs.

The largest of these was 13 million barrels in Argentina, where we identified quite a number of new PUD locations using both our existing and some new 3-D seismic.

We also had 6.4 million BOE of adds in the US, largely extensions in California and in south-central Texas, and in--and in Canada we had adds of 2.9 million BOEs.

The next category is revisions of previous estimates, where we have a total of 17.3 million BOEs.

There's a price-related positive revision that is part of this 17.3 million BOE figure.

We're not prepared to discuss that today, but we do plan to discuss it at some later point what our reserves would look like in a moderate price environment.

The US and Argentina both had positive revisions in this category, while Ecuador and Canada had negative revisions.

US revisions were 17 million BOEs and Argentina was 12.4 million.

A 4.1 million BOE negative revision in Ecuador resulted from the cost recovery feature of the Sherapuno (ph) concession, and Canada experienced a negative revision of 8.2 million BOEs from well performance, which I'll cover in a little bit more detail here shortly.

All of this brings us to the bottom line, which is year-end '02 reserve figure of 529 million BOEs.

At this point, I think I'd like to spend a little time on the issue of Canadian reserve revisions and impairments so you can get a better feel for what the reasons and the drivers were there.

I'll pick the two fields that generated the largest impairments, and describe generally what happened there.

The first of those is the Pine Creek field (ph), in the west-central area of Alberta.

Pine Creek (ph) generally produces from Ladouc reefs (ph) , Ladouc pinnacle reefs (ph) , and from the Miscouv (ph) and Woggoman (ph) formations.

There were six gas wells that for the most part were drilled in 2001 that were the root of the impairments.

These wells had originally had significant volumes of gas reserves, both proved and probable put (ph) to them.

When the wells were drilled and logged, there was no gas-water contact that was seen on the log, and reserves were estimated on the basis of a reasonable drainage area around the world--around the wells, considering the amount of productive pay seen in the well.

But at this point, those six wells are producing in such a fashion that they are expected to recover substantially fewer reserves than originally was estimated, and as a result the remaining proved and probable reserves were reduced significantly.

In the second field, which is Gourard in Central Alberta, there were somewhat similar problems in some gas wells, and also in some oil wells.

There were three significant gas wells producing from the geffing (ph) zone that started producing water much earlier than had been expected, and then there were a number of blue sky heavy oil wells that were drilled this year whose initial rate, or decline rate were below expectations, so in this case not only the proved producing reserves but also the offset proved undeveloped reserves were reduced significantly.

In both fields the results of the negative reserve revision is a reduction in the estimate future net cash flows from the properties, and when this reduced net cash flow figure is less than the basis of the field, then the field is impaired to the present worth at ten percent of the future net cash flows, which is exactly what happened here.

This is obviously something we're disappointed about, actually very disappointed, as well as the accompanying goodwill impairment.

But this doesn't mean that we're going to pack our bags in Canada.

To the contrary, we still think that Canada's a great place to be in the oil and gas business.

We believe we understand the reasons for the reserve revisions, we're obviously smarter than we were a year or so ago, we know the property base a whole lot better at this point and we're going to move ahead and make this asset base the best that it can be.

And Craig George will discuss this in a bit more detail towards the end of the call.

As we've done in the US and South America as part of the normal course of business we do plan to divest a number of non-strategic properties in Canada.

We're in the process of identifying those right now and this will help us in our continued efforts at debt-reduction and allow us to focus on our remaining core assets.

Let's move on now to the 2003 capital budget.

On the Web cast this is slide number 10.

At the third quarter '02 conference call we announced a preliminary 2003 capital budget of 180 million dollars, which reflected a return to drilling in Argentina, as well as a more robust exportation program in the US and continued expansion of our exploration program.

We've increased that budget marginally to $185 million, reflecting a carry-in of about five million dollars budget but not spent in Yemen in 2002, and some re-allocation of exploitation dollars between the US, Canada, and Argentina.

A total of $56 million, or 30 percent will be allocated towards exploration. 31 million in the US, eight million in Canada, and 17 million in the international arena.

The remaining 129 million, or 70 percent, will be allocated to exportation, 49 million in the US, that's an increase of five million, 30 million in Canada, that's a reduction of 12, and 48 million in Argentina, an increase of five.

The resulting volume forecast, which is shown on slide 11 in the Web cast, is unchanged at 29.1 million BOE (ph) , although there's a half a million BOE increase in the US and some more reduction in Canada.

Both of those functions of well performance and a budget increase or decrease, and Argentina and Bolivia are effectively unchanged.

Obviously, this is below our 2002 volume of 32 and a half million BOEs, but I need to point out that pro forma for the asset sales would have been 30 million BOEs so this still reflects a small decrease for '03 volumes, but I should further point out that capital spending was curtailed in '02, and had the full year, and had we not been curtailed in our spending, then we would have had higher volumes in '02 and had the full year effect of those volumes in '03, so '03 would actually have been expected to be above '02 in that case.

Let me also point out that as we mentioned in the last conference call our forecast shows volumes building through the year in 2003.

Finally, LOE (ph) per BOE is forecasted to increase marginally, largely due to increased severance and export taxes resulting from higher estimated product prices in our forecast.

So, at this point, I'll turn the floor over to Bill Barnes who will discuss our financial targets for this year and the achievement of our debt reduction targets.

Thanks, Bill.

For those of you viewing the Web cast, we're now on slide number 12.

For our revised 2003 financial targets, we've increased our NYMEX price assumptions to $26 per barrel for oil and $4.50 per MMBtu for gas.

These, compared to recent NYMEX swap prices for 2003 of over $30 a barrel and $5.30 per MMBtu for gas.

So you can see from the slide our price realizations remain relatively unchanged from our previous guidance.

And based on these price assumptions and our existing hedge positions, the resulting cash flow target for 2003 has now been increased to $235 million, with EBITDAX target for 2003 of $330 million.

With the closing of our Ecuador sale in January, we have exceeded our $200 million debt reduction goal that we established last year.

The after tax proceeds from property sales of about $150 million added to our excess cash flow in 2002 resulted in a debt reduction - a net debt reduction of over $225 million since year-end 2001.

The table on page 13 shows our net debt position at year-end 2000 pro forma for the after tax proceeds from the January property sale.

Bank debt is reduced to zero, leaving us with 800 million of senior and subordinated notes.

These notes have an average fixed rate of eight-and-a-half percent with no maturities prior to year 2009.

Pro forma debt net of cash is $775 million.

In addition, our $300 million bank facility provides us with unused availability of over $280 million pro forma for the recent sale.

At this point, I'll turn the presentation over to Craig, who will discuss our plans moving forward.

Thanks, Bill.

As Bill Abernathy said a little bit earlier, we plan for significant investments at all three of our core producing areas - the U.S., Argentina and Canada.

On slide 14, we show an overview of those plans.

In the U.S., with our streamlining mostly behind us, we're focused on exploitation and exploration programs.

In Argentina, we've resumed drilling in response to a stabilization of a number of economic factors that I'll talk about later.

In Canada, we'll be developing previously identified reserves as well as building our exploration program.

And at the same time, we'll sell some non-strategic properties to help us focus more on upside opportunities.

In our frontier exploration program in 2003, we'll be drilling in Yemen, Northwest Territories and Italy.

In the U.S., we have exploitation activities planned in essentially all of our producing areas.

The most significant area is shown on slide 15 - our (ph) South Texas horizontal development programs in West Ranch and Luling Fields (ph) and then horizontal development programs in California and our U.S. exploration program will have activity in all three of our focus areas this year.

In South Louisiana, we're currently drilling the Rashad (ph) prospect, which is part of what we used to call the Tiger Bayou (ph) prospect area.

It's right now drilling at about 17,000 feet on its way to 21,000 feet.

In our West Texas horizontal program, we are drilling at Leatherwood, which is our first of three prospects to test this year.

And it is drilling at about 11 thousand feet on its way to 18 thousand feet.

In Texas Gulf Trust (ph) program, we are a little bit behind in time compared to the other two.

We are maturing prospects right now in assembling acreage, and will plan to start our first well in the second half.

In Argentina, slide 16, we have a much higher degree of confidence in the outlook than we had a year ago.

The currency is stabilized, the inflation rate is declined, and the government has been stable.

The INS and Argentina have reached an interim agreement and economics for drilling are again robust.

We have allocated $48 million of our capital program to Argentina subject, of course, to continued stability.

We recently picked up a second rig and made it back to our previous level of three rigs before midyear, which will put us back on the road of growing production again in Argentina.

Next I will show you some factors that have given us a comfort.

On slide 17, you can see that inflation is moderated and up to about a percent of month, which isn't bad.

Devaluation for the most part has held steady since June, which is good.

On slide 18, you can see that National Bank reserves stabilized last summer, and have been growing modestly.

And here again, you can see exchange rates likewise stabilized and may even be trending slightly downward.

And in our industry, people are back to drilling.

If you look at slide 19, you can see - although there are only about 55 rigs drilling now compared with a peak of a couple years ago at 75, the difference is really mostly in gas rigs with oil drillers at Vintage getting back to business.

Finally, on page 20, the bottom line in Argentina is that our cash flow remains strong. the government reaffirmed our right to continue to repatriate up to 70% of export proceeds paid in U.S. dollars in U.S. banks, so all-in-all, we are very encouraged in Argentina right now.

As Bill said, although we are extremely disappointed with our write down in Canada, our production has been on forecast for the last few quarters.

We are planning our strategy to focus more, focus geographically, focus on technology driven opportunities, and focus on projects that can have meaningful impact for us as we go forward.

In this vein, we are generating new drill bit opportunities with meaningful potential in both shallow and deeper plays, which we've been concentrating on for the last year or so.

We will continue to look at acquisition opportunities over time, particularly those that will [Inaudible] up, and [Inaudible] historically in U.S. and Argentina.

On the other side of the acquisition coin, now that we've had the properties for a while, we have a better picture of where we should focus and plan to divest the outliers, as Bill mentioned before.

We think this should establish a good platform for growth for us.

Our Canadian activity is shown on slide 22.

Our exportation activities will be focused in areas where we have met with success already.

Gourard with 3-D seismic generated fuel and oil wells, and horizontal oil developments in Gourard, East of Five, and Sturgeon Lake.

We will continue with the development of our gas reserves in West Central and East of Five, Sturgeon Lake and Peace River Arch.

As we transition into discussions about our Frontier opportunity set, we are currently drilling in the Northwest Territories and will be testing three wells that were drilled in prior drilling seasons.

The [Inaudible] right now is about half way on its way to 6 thousand feet.

Next on slide 23 is Yemen.

And here we are continuing with our second drilling campaign.

Currently drilling the Inagia (ph) number three, targeted via confirmation well to our 2002 Inagia (ph) number two discovery.

If successful, we'll continue to work to further delineate this structure, as well as develop plans for other prospects on trend.

In Italy, we're continuing with our G&G (ph) work, but early geochemical work gives us some encouragement that good prospects exist on our blocks (ph) .

Our plan here is to set our first well late in the year.

On slide twenty-four, we show geochemical anomalies on our block (ph) which are similar to anomalies seen on nearby producing fields.

There are mature pipeline infrastructure there, so that should allow us for early sales into a strong marked if our exploration is successful.

Next I'll talk a little bit about hedging.

With commodity prices improved pretty substantially from a y ear ago, we've been a lot more aggressive in our hedging program.

For North America Oil in 2003, we have 53 percent of our production hedged at an average price of a little over $26 per barrel.

On slide twenty-six, for North America Gas in 2003, we have 43 percent of our production hedged at an average price of 4.11 per MMBtu's.

And then on slides twenty-seven and the summary we significantly improved our balance sheet through non-strategic property sales and applying excess cash flow with more debt reduction planned from the Canada streamlining.

We have a robust exploitation program, once again, active in all of our core areas, and that should hold our production nearly flat.

Our exploration program is hitting full stride now, with lots of upside potential in North America, as well as international, and finally, acquisition opportunities may be improving, as majors (ph) become sellers again in 2003, and capital markets appear to be coming more conducive to the sector.

I guess the next slide, here we have our forward-looking statement, and with that, we'll open it up to questions.

Okay, thank you.

If you'd like to ask a question, please enter the queue by pressing the star and one on your touch-tone phone.

In the interest of allowing all questioners to have an opportunity to ask questions, Vintage has asked that each participant limit themselves to one question and one follow up.

If you have additional questions, you may return to the queue to ask them.

Also, if your question has already been asked, just press the pound key to withdraw your question.

Again, if you would like to ask a question, press the star and one on your touch-tone phone, and we'll have our first question momentarily.

Okay, we'll take our first question from Van Levy with CIBC.

Good morning--or good afternoon gentlemen, how are you?

Hi Van.

Hi Van.

I was hoping you could give us a little more, I guess a breakdown of information in terms of finding costs and year-end reserves by country?

Okay, Van; let me give you some--some totals here.

For the US, total oil and gas spending was about $29 million, total adds from all sources, about 23 1/2, so that's about $1.23.

Canada, altogether only spending about $58, 59 million, and the composite reserves were down there excluding production about 5.3 million BOEs so that doesn't give you [Inaudible] numbers.

Argentina, oil and gas spending was about $19 million, total reserve adds about 25 million BOEs, and so that's about 74 cents per BOE.

Bolivia spending was about 2.6 million, very few additional adds there, so that calculates about $14.

Ecuador, we spent about $11.6 million dollars, although there weren't any technical changes there, there was a price-related reserve revision because of the sheer puno (ph) contract, which was about a 3.7 million BOE altogether reduction, so that calculates negative dollars per BOE.

That's really kind of a non-sensical number because we're spending dollars on crude reserves and it was just a price-related issue.

In the composite, I think maybe that the thing that makes the most sense is about $129 million spent and altogether adds for about 30 million BOEs and that's $3.20.

And in Canada, if we took the negative reserve revision out, because that was generally not from money you spent in 2002, but before, if that's correct, let me know, so if we took that out, and just looked at the extensions, what kind of funny (ph) cost would you add and...

The extensions were what, 2.9 million BOEs?

Maybe what really makes sense is to pay attention to dollars that were spent to add reserves, that's the exploration dollars, and the dollars that were spent on non-proved additions, but probable, and things that weren't identified as proved last year, which was $31 million, and that stuff works out to about $10.80.

If you want to use the total capital of 58 million dollars, and that 2.8 million BOEs, you don't get a very good number, but you're not comparing the right dollars to the right reserve adds in that case.

I think all things considered, there were quite a few dollars spent, of $129 million, that refer to for total oil and gas investments, about 62 million of that was spent converting proved undeveloped or proved developed non producing reserves to producing reserves, and I think maybe one thing we need to make sure that we're cognizant of there is that typically wouldn't result in very much change in reserves.

We spent about 67 million dollars on exploration and non-proved exploitation.

And that yielded something like 22.7 million BOEs, and that's $2.93 per BOE.

OK, so looking forward, it looks like you're spending about 30 million in Canada, and clearly you did good in the US and Argentina, both of which are increasing your cap ex, so I think most people will feel comfortable with that, looking forward in Canada, how would you assuage fears that you'll have a repeat of bad finding costs there?

I think probably the best way to answer that is with the adjustment of the capital budget that allows Gary Watson (ph) and the team there to pay attention to their absolute very best opportunities - they obviously have learned a lot from this past year.

And there were a few things that dollars were spent on that didn't work and, obviously, those kinds of opportunities won't get any capital allocated to them next year.

I think we know, at this point, the things that are working and those are the kind of things that will get the capital allocated to them in the coming year or so.

Plus, beyond that, then, there's the exploration program that's got quite a few good things on tap there that we're hoping to have some pretty good results from.

OK.

Well, congratulations on coming out of a real rough spot.

Thanks Van.

OK.

OK.

Our next question is from Joe Allman with RBC Capital.

Go ahead.

Good afternoon.

The PV10 number you gave - $4 billion - was that a pretax or after tax number?

Pretax.

OK.

Could you give us the after tax number?

We don't have it calculated at this point, Joe.

OK.

Just another quick one - I know I'm supposed to limit it to one, but extension and discoveries, you mentioned 13 in Argentina, 2.9 in Canada and what was the other number in ...

The U.S. was 17, I think.

OK.

Appreciate it.

Thank you.

OK.

Our next question is from Ken Beer with Johnson & Rice.

Go ahead.

Yes.

Hi, guys.

My [Inaudible] international.

Over in Yemen, obviously, you've got the last well going here.

Could you give us just a - the - your thoughts as to if the well is good, kind of where you go from here.

And if this well is not particularly good, you know, where do you go from here in Yemen.

And then I have one follow-up.

Ken, if the number - if the Inagia (ph) number three is what we hope it is, it would be a confirmation of the structure in the sub-salt section called the lamb (ph).

That would begin to give us something that is approaching the size that we could begin to sake (ph) about a project to go forward.

I would estimate it would take at least one and maybe two additional delineation wells before we could really tie down the size of that project.

But again, we're keeping our fingers crossed and we're hopeful.

And if the well is successful, you know, I think the things we'll begin to think about is where we need to put the next delineation well in order to confirm that we have a sufficient size of reserves that would be able to allow us to justify a project.

Which would be about - maybe you could just give us some clarity as to ...

Yes.

I think probably the absolute minimum where Inagia (ph) sits is probably something in the gross reserve size of maybe 10 to 15 million barrels.

If we were a little closer - if we were a little further northwest, closer to the infrastructure, it might be a little smaller.

But we're talking about something, probably, in the 10 to 15 million barrel size as kind of being the minimum to generate sufficient project economics to go forward and, like I said, if this well works, we think we're pretty darn close to that number.

And probably take at least one, maybe two more wells to just - to firm that up.

You know, if the well doesn't work, we've still got a couple of really large structures out there that have not been drilled, and we would anticipate going ahead and making sure we would test those before we would make a decision on whether or not we'd stay.

OK, and would that be this - in 2003 or probably 2004?

Yes, I think it would be this year.

OK.

And then just a - my follow up would be just sticking with the same thought in Italy, is this well is good verses bad, you know, how does that work in Italy?

Italy is - we had two wells that we're attempting to permit, and what we're working off of, as Craig showed on the slide is a regional geo chem that we tied in with some regional 2-D seismic that also ties into some existing producing fields.

Largely what we're working is a little more of a stratagraphic concept.

If the wells work, we have a number of potential prospects out there, but likely what we would do is go ahead and shoot a 3-D in order to really firm that up very well, and you know, obviously our thought is that it could be a meaningful size or we wouldn't be there.

Got you.

And so really these first two wells just past that concept and it would be hard for me to say until we drill the wells and find out exactly what they do - where we would go from here.

OK.

That's fair enough.

All right, well I will stop there.

Thank you, guys.

Sure Kenny.

OK, once again if you have a question, press the '*' and '1' on your phone.

And we will go to Brad Bego (ph) with Credit Lyonnais.

Go ahead please.

Good afternoon, gentlemen.

Hi, Brad

A couple of my questions have been answered, but going back to the reserves, what are your prod percentage - or proved develop percentage - either way you want to look at it, in Canada, after the write downs?

We're checking.

And I was also curious, as a company, [Inaudible] I am getting - you're at 43.9 MMBtu net of Ecuador.

What would be the prod percentage on your adjusted reserve volumes for the total company?

Brad, this is Gary Watson.

As the PUD reserves in Canada, year-end, are at about 23% of the total.

Twenty-three percent.

Yes.

OK.

And, Gary, you add the total company or - after Ecuador's excluded?

Brad, Ecuador's reserves were about 18% of [Inaudible] .

OK.

Brad, we have to do the math here yet.

But we'll...

OK.

I can do it.

That's fine.

Back to the drilling program in Canada, can you kind of characterize what worked this year, and what didn't work.

I am trying to figure out whether the majority of what we are seeing is a cleanup that we already really knew about from 2001 versus new disappointments for 2002.

Brad, this is Gary again.

I think some of the things that worked for us were the horizontal drilling in Sturgeon Lake.

We've had great improvement through the year using the 3-D and - with the horizontal drilling there.

Some of the shallow drilling in new areas on the exploitation side didn't work for us.

I think if you look to 2003, we will probably - you know, we high graded our program and we'll probably move away from some of the projects of that nature.

And I think in the new ventures, or exploration side, you are going to see that too.

But I think we're looking for some bigger prizes and probably will drill on the aggregate, maybe some deeper targets throughout the year.

Okay, how much of the budget, during 2002, was exploration versus development?

Five percent (ph).

Sorry?

Is this just Canada? (ph)

Yeah.

Five percent.

Okay, so it was largely development and ...

Extensional.

Okay.

Right.

Okay, and then you mentioned, you didn't have the calculation on the--on the price impact of upward reserve revisions?

We're not prepared to talk about that today.

Okay.

We will be discussing it at a later date with a couple of more moderate price environment cases.

Okay.

One other question, just kind of mechanical in nature.

What was the--what would be the severance tax for the fourth quarter, including I guess Argentina taxes?

Apart from lifting costs.

About $10 1/2 million, both export tax and severance taxes, on a consolidated basis.

Right.

The answer to your other per (ph) develop question is that it goes up to about 68 percent when you exclude Ecuador.

Okay very good; all right, thanks guys.

Thanks, Brad.

While we're on the reserve question that--Joe asked a question a couple of minutes ago about the US adds from extensions, and I think the answer that I gave him was in error.

I think I said 17 million; actually, that's 6.4 million BOEs.

Okay, once again, if you have a question, press the star and one on your phone now please.

Okay, we have a follow up from Van Levy.

Go ahead.

Can you break down the reserves by country, hopefully between oil and gas, and give the--both the--I guess you did for Canada, but the pipe (ph) percentage, and maybe the future development cost to convert the puds (ph)?

Van, this is Bill Barnes, we've included a table in the release that has all that information. [Inaudible] helpful.

Okay, then next question, EBITDA by country for 2002, do you have a rough breakout of that?

Sure.

And really, what I'm trying to gauge is Argentina's contribution to the totals, say compared to even, you know, three years ago.

In the--in the US, for 2002, EBITDAX (ph) was 98 1/2 million.

For Canada, 58.7 million, 58.8.

Argentina, 161, and if you're trying to gauge it against last year, it was 175 million last year.

'01.

I'm sorry, '01.

Okay.

And Bolivia was 5.1 million for 2002.

Okay, and I guess the other question is that acquisitions, particularly in Argentina, what are you seeing on the slate there?

I noticed it looks like Exxon is still working, I guess mes-uro-chada (ph) area, but I don't--I get the sense that the activity there and potentially the sales there could be meaningful this year.

So far, at this point in time, there really hasn't been a lot of activity.

There's been a lot of rumored activity, but I think really until we get over the next wave of uncertainty in Argentina, which is probably the presidential election, you probably won't see a lot of change of hands, but I think beyond that there maybe a number of sellers and we'll certainly be sensitive to that.

OK, last question, do you have a year end kind of a DDNA (ph) by country?

Like a DDA (ph) per BOE or just a total...

DDA (ph) per BOE.

OK.

DDNA (ph) per BOE, and this is oil and gas only, it doesn't include some of our gavine (ph) pipeline facilities, and so forth, were '02 for the use was $4.63 per BOE, Canada $10.78 per BOE, Argentina $3.72 per BOE, and Bolivia $3 per BOE.

And, because of the reserve revisions, Bob, would you expect any material changes in these numbers going into 2003?

Most of the countries will be relatively flat, maybe even improved a little bit, Canada's probably will go up a little bit but not significant.

OK, all right thanks again.

OK, that concludes our Q&A, Mr. Phaneuf, we'll hand it back to you for any closing comments.

Thanks very much, Kyle, and thanks to everybody who took the time to be with us on the conference calls and asked us some good questions.

We appreciate your time, and if there are no more questions we'll stop here and sign off.

Thank you very much.