APA Corporation
Q3 2007 Earnings Call Transcript

Published: 26 Oct 2007

[Operator:]

Good day everyone and welcome to the Apache Corporation thirdquarter earnings 2007 conference call. Today's presentation will be hosted by Mr. Bob Dye, Vice President ofInvestor Relations. Mr. Dye, please goahead.

[Bob Dye:]

Thanks for joining us today. This morning Apache Corporationreleased third quarter 2007 results which reported earnings per share of $1.83. I think most of you saw the $1.83 numberincluded a $0.34 non-cash charge, primarily related to the impact of foreigncurrency fluctuations on our deferred tax balances. Without that, our adjusted earnings were$2.17 per share. Cash flow reach an all-timerecord of $1.6 billion which is a non-GAAP number. Today’s discussion may contain forward-looking estimates andassumptions and no assurances can be given that those expectations will berealized. A full disclaimer is locatedon our website at www.apachecorp.com. In addition, any non-GAAP number that we discuss will beidentified as such with the reconciliation also located on our website. Steve Farris, our CEO and Roger Plank, ourCFO will now make prepared remarks prior to taking questions. With that, I will turn the call over to Steve.

[Steve Farris:]

Thank you, Bob. Good afternoon, everyone and thanks forjoining us today. Apache’s performancein the third quarter was outstanding. It was driven by our portfolio balance,quality and depth of our growth opportunities. Third quarter production, as I am sure you have read, was 516,000barrels of oil equivalent a day which was 9% year-on-year growth and just underour all-time record set in the previous quarter. Henry Hub spot gas prices were down 17% on an average in thethird quarter compared to the second quarter. Differentials meant that as an industry, many people saw $3 gas in the Rockies. On the flip side, the average WTI oil price increase 16%from the second quarter. The average oilprice I am quoting is about $75 and hence, doesn’t really reflect the morerecent strong rise in oil prices. In this volatile commodity setting, our average realizationswere stable for the quarter and cash flow of $1.6 billion set an all-timequarterly record, which was 25% year-over-year growth and 10% relative to thesecond quarter of 2007. That is largely on the strength of our commoditybalance. Liquids production accounts for47% of our production by volume, but accounted for 67% of our revenues duringthe quarter. As Bob pointed out, net income was again impacted by a weakeningU.S. dollar that requires us to mark-to-market our non-cash differed taxbalances denominated in foreign currencies. Without this charge, earnings wouldhave been $2.17 per share. Times like this underline the competitive advantage thatApache’s balanced portfolio represents. We have a one of the largest North American gas portfolios in theindustry with over 5 Tcf in proved gas reserves as well as in excess of 20 Tcfof unrisked resource potential. ButApache is really much more than that

[Roger Plank:]

Thank you, Steve. Good afternoon everyone. Themerits of Apache's balanced global strategy was evidenced in our strong thirdquarter results. Rising oil prices had an outsized impact on our bottom-lineresults given that oil figures so prominently in our production mix. As a result, while many North American gas orientedcompanies wrestled with nearly $1.50 sequential decline in NYMEX gas prices a$10 per barrel increase and the benchmark price of oil on strong productiondrilled Apache's oil revenue up $150 million sequentially during the quarter,enabling total revenue to reach the $2.5 billion mark for the first time in ourhistory. Earnings of $612 million or $1.83 a share where also quitestrong, especially when taking into consideration the $114 million non-cashcharge related to the impact of the deteriorating U.S. dollar on Canadian and foreigndeferred tax balances. Theoretically, when it comes time to pay our defer taxes in Canadait will take more US dollars to do so. So, we have to reflect that change in our income statement at the end ofeach quarter and frankly it’s kind of pain rear as it significantly distortsour true performance. The important thing to note is while this reportingconvention reflects the proper accounting treatment for movement in foreigncurrency, it is just a non-cash change and not a current period economic event.Therefore, setting aside the impact of the changes in foreign currency, Apacheearnings did total of $2.17 per share substantially Street expectations. It is also well ahead of both last quarterand third quarter of ’06 earnings which excluding the impact of foreigncurrency fluctuations and other non-recurring items totaled $2.09 and $1.70 pershare. If you are interested the [inaudible]lays out those adjustments so that you can see each of the components. The strength of our quarter is readily apparent in our cashflow from operations which being unaffected by this foreign exchange fluctuationreached a record $1.6 billion or $4.83 of share, up 25% from last year’s thirdquarter; 10% higher than the second quarter of this year and well ahead of consensusestimates as well. Again, the strong results speak to the benefit of a balancedportfolio approach. I can’t tell you hownice it is for our liquid hydrocarbons -- roughly half of our quarter’s production-- to generate just over two-thirds of our total revenue. Revenues are the beneficiary of higher oil prices of lateand while the weaker US dollar generates the deferred tax amount we projectthat we may pay someday there is little question that this currency weakness isalso benefiting Apache in the form of higher oil prices. From that standpoint, Apache has a naturaloffset which mitigates the income statement impact resulting from the weakerdollar. As Steve indicated, our third quarter production was up 9%year over year; it was down 2% quarter over quarter while the slight decline inthird quarter production may have surprised some of you, it was relativelyconsistent with our internal expectations due to the anticipation of thescheduled turnaround in the North Sea which is why we do continue to expectyear-over-year production growth at the upper end of our 9% to 12% growth range. If you do the math, to reach the upper end implies significantgrowth in the fourth quarter which we fully expect will enable us to close outthe year with our highest production level ever. We also anticipate continued strong returnsdriven by robust margins, the impacted strong global demand and limitedsupplies on oil prices fueled Apache’s highest cash and pre-tax marginsyear-to-date despite realizing the lowest gas prices of the year and fightingour industry’s ongoing battle with rising costs. For the quarter, overall cash costs dropped 1% to $13.55 perboe and combined with 3% higher realizations, propelled margins up 5% from lastquarter to $34.83 per boe, our highest year-to-date. Even including DD&A, our total pre-taxmargin increased to $22.72 per boe from $21.40 sequentially. Focusing on costs, our third quarter lifting costs increased2% or $0.17 of boe sequentially to $8.21 per boe. Roughly half of this increase was related to expandedworkover activity to increase production on the Anadarko acquired propertiesand the other half relates to the lower North Sea volumeswhich as you’ve heard, are forecasted to recover in the fourth quarter. I also note that the quarter included $0.09 related to theforeign exchange movement and absent fee impacts, LOE per boe would have beenaround $8 which is a level we consider achievable going forward, even withcontinuing higher work over activity. G&A costs dropped 13% sequentially to a $1.19 per boe,probably a good rate, achievable rate going forward. Full cost DD&A was up just 2%sequentially to $10.94 per boe as drilling costs continue above historicallevels. Severance and other taxes of$2.42 a boe decreased $0.10 quarter over quarter. This is primarily driven bylower North Sea PRT as lower volumes more than offset higher oil prices. Financing expense decreased $0.05 to a $1.17 per boe on $126million lower debt. Continued strong oil prices and rising production shouldresult in further debt as well as debt to cap reductions from the 25% rate thatwe ended third quarter at. Our effective tax rate was 48% for the third quarter, thelingering effect of exchange rate fluctuations and further currency weakeningso far this quarter should cause our fourth quarter effective rate to remain ataround the same level and portion that is deferred should move to around52%. Fortunately, the costs start over every January 1st, soabsent further FX changes next year’s rateshould be back below 40%. Before closing, I’d like to underscore that not only are wegratified with Apache’s third quarter results, but we also look forward to avery strong finish to our year for good reason. First, solid fourth quarter production will contribute to double-digitgrowth year-over-year and our 28th increase in the last 29 years. Second, despite concerns over the USeconomy, Apache is among those multinational companies benefiting from strongglobal demand for our product. While itis too early to know exactly where prices will shakeout for the quarter,current WTI oil prices are again over $10 higher than the third quarter NYMEXaverage of $75 per barrel. With 7,000 barrel per day of old hedges rolling off thismonth in October, where the prices was capped $39.25 or less than the half thecurrent price, approximately 85% of Apache’s oil production is now unhedged andenjoying the price run up toward $90 perbarrel. In addition, our lowest gas price hedges rolled off inOctober. Some 90 million cubic feet perday capped at $6.32 per MMBTU leaving only around 15% of our total gas hedgedas we head into the winter demand season. Finally, today’s cover article, some of you may have noticedin the Wall Street Journal mention price controls in Argentina.I would add and as Steve has indicated, Argentinahas begun to take steps towards that with respect to natural gas we’re startingto see the benefit of that. Thus far into fourth quarter Apache’s averagingjust over $1.40 per MCF on 200 million cubic feet of gas per day and that’s 40% or so higher than what weactually received in the third quarter. So in a nutshell, the combination of rising production andprospects for strong product prices should enable continued attractive -- oreven improving -- margins resulting in a very strong finish to 2007.

[Steve Farris:]

Thank you, Roger. I might just close with a fewcomments. The third quarter was outstandingfor Apache both financially and operationally. Cash flow set records, we had outstanding earnings. Operationally, our evolving high impactexploration portfolio in our core growth areas, resulted in two natural gasdiscoveries in Australiaand a gas condensate discovery in Egypt.In Canada we addedabout 104,000 gross 52,000 net acres to our British Columbian shale gasresource play, and now control over 400,000 gross, 200,000 net. We look forward to testing the viability ofthis play with the drill bit during the winter campaign. Our portfolio balance has shown through in our commodity mixas Roger pointed out, liquids which account for half of our production generatedtwo-thirds of our revenues, and that should continue into the fourth quarter. We should exit the year with a rising production profile andshould end the year on the high end of our range and with development projectsunderway scheduled to add 108,000 barrels of oil equivalent per day over thenext three years fueling our growth. Ourresource base is capable of delivering strong growth through the end of thedecade. With that we would love to take your questions.

[Operator:]

Your first question comes from Ben Dell - Bernstein.

[Ben Dell:]

Myfirst question is really around reserve bookings. You outlined a number of your discoveries,there are obviously timing issues in terms of when you book those. Last year your F&D in the US was a particular drag. Do yousee that coming down this year or your overall F&D declining this yearversus last year?

[Steve Farris:]

Finding cost? Well, we still got a quarter to go and ourreservoir engineers haven’t told me what the numbers are yet. I will tell you this; the thing that is goingto affect our finding cost in the U.S. this year is same that’s affected themin last year, that is we still have an awful lot of the hurricane damage thatwe put in this year which was really as we pointed out last year, was reallythe impactful thing in the United States.

[Ben Dell:]

Maybe turning over to Argentina,can you give some color, and you obviously mentioned the collar on the gasmarket there. With the elections comingup, do you have a feel for what sort of escalation in gas prices you could seeover the next two, three years as the market tightens?

[Steve Farris:]

Well, everything I am going to tell you is obviously what --as I always mention we go into new country we are their guest, and they are thehost. There is a lot of anticipation that the new administration is going to atleast relook at that issue. I will giveyou some anecdotal comments about that though. We recently entered into athree-year contract with a major gas user there that’s in other parts of theworld. In the three years they are at 15million a day and they go from $3 to $3.50 to $3.90 over the next threeyears. So we are seeing, already we’re seeingactually more than I anticipated when we got in there at this point oftime. I don’t think that’s going to change as you I am sure youare aware. They need indigenous gas terribly. They import 250 million a day from Boliviaat over $6 now. I am hopeful that everybody is reasonable about the way youattract foreign investment and part ofthat is that you have to make a return and in order to do that, you have tohave acceptable prices. So I can’t forecast. I can tell you what we’ve been able to do lately, but in terms of ourexpectations I think our expectations are pretty optimistic, frankly.

[Roger Plank:]

The other thing I would add to that is, the article in thepaper implies everything is regulated and priced and gas is too, but it isreally the residential market and some of the small usage markets that areregulated, and it is certainly low price, but they also recognize that they arerunning out of gas. They have to import it, like Steve says, at $6 so they havelet incremental gas sell for whatever the market will bear. So once we have delivered into the lower priced, regulatedmarkets then we can go after these markets that Steve just indicated where weare seeing prices at $3 or triple what we got last quarter. So they have the right ingredients in place and they havethe right mindset; people who bring on new gas will get rewarded with higherprice.

[Ben Dell:]

Just one last quick one. On Enesco’s call today theysuggested the demand for jackups in the Gulf of Mexicois picking up and highlighted yourselves as one of the key players coming backto the market. Can you give us an indicationon what your rig demand in the Gulf will be next year versus this year?

[Steve Farris:]

I think they are hopeful. I will leave it at that.

[Operator:]

Your next question comes from Brian Singer - Goldman Sachs.

[Brian Singer -Goldman Sachs:]

When you look at your Australiagas exploration program can you talk to where you stand on prospect inventoryand how aggressively should we expect gas exploration to be in ‘08, givenwhat’s going on?

[Steve Farris:]

We will have a very active program. We have a number ofother prospects on the block 356; we have a block that is north of our old EastBar which is a field that made about 750 Bcf of gas, it is west of Varanus Island that we are going todrill. We have Norbo which we are goingto drill. We have a number of additionalprospects in the Carnarvon Basinto drill next year. I guess you are asking the potential of the market or thepotential of our gas resource base?

[Brian Singer -Goldman Sachs:]

Really just the potential of the gas resource base and howaggressively you plan to drill that in ’08 versus your program in ’07?

[Steve Farris:]

Well I actually I think we have two rigs running next year.I will tell you it is difficult to get a rig into the Carnarvon Basin and I will give you the firewe just had. It will be December beforewe get another rig into the Carnarvon Basin because they have safetycases that a new rig has to go through. We think there is about 2.2 billion barrels of resourcepotential that we have in front of us of exploration stuff. The beauty of wherewe are right now is if you look at Julamar Brunello which we believe iscommercial as it sits; and our Reindeer, our only downside is not getting thatdone and executed. Because as you knowonce you get infrastructure and you can look for lesser and lesser sizedreserves or add-ons to the infrastructure. So we will have a very aggressive program in the Carnarvon Basin on thegas side next year as we will and in the [Gypsum] Basin starting about Februarywith one jackup coming in there.

[Brian Singer -Goldman Sachs:]

In the U.S.were there any intricacies of oil production being up relative to the secondquarter with the gas production being down a bit? Anything you need to sharethere?

[Steve Farris:]

You mean in the gas production in the Gulf of Mexico?

[Brian Singer -Goldman Sachs:]

Yes.

[Steve Farris:]

We were down about 40 million a day and about 20 million ofthat was strictly facility related or pipeline related; 20 million a day ofit. A little bit of it was weather and thepart was natural declines. Quite franklywe’re expecting a little uptick on our gas production for the fourth quarterand our oil production should be about flat to up a little bit.

[Operator:]

We’ll go next to Tom Gardner - Simmons.

[Tom Gardner:]

Good afternoon, guys. Given the continued success you are having in Egypt,particularly in the Khalda concession, at what point does it make sense to takeanother look at your gross gas processing plants and perhaps revising thoseupward?

[Steve Farris:]

Well we have two plants that are going to come on startingin the fourth quarter of 2008 which is about 200 million a day of processingcapacity. I will say that we had abigger appetite than that. We go throughthe operating companies, each company in Egypthas an operating company that is owned 50% by the foreign contractor and 50% bythe EGPC which is the government arm of the oil industry. It would not surprise me at all for us to bestarting discussions in earnest on drilling, at least filling one more 100 Mcf trainsometime in the next year. They aregoing to need the gas, and we have to take away capacity.

[Roger Plank:]

The other thing we have an arrangement where we move gasthrough another operator’s plant that supplied basically by one field that hasbeen depleting. To the extent that, thatgas isn’t replaced that frees up room for more Apache gas into the future.

[Steve Farris:]

To be a little more specific, we take about a 150 million aday of our gas out of Cosor, North to a field called Obiat that has a 380million a day gas plant. Obiat has beenonline for a number of years and continues to decline so to the extent they declineour gas rates will go up through there also.

[Tom Gardner:]

To be clear, this 100 million a day that you speak of , isthat incremental to these 700 million gross?

[Steve Farris:]

That would be, yes sir.

[Tom Gardner:]

Jump over to the North Sea, you continueto have success there as you mentioned in the Bravo well, I guess appropriately named. Some people arepulling out of the North Sea, I just want to get yourthoughts on the UKnatural gas market perhaps consolidation opportunities in your capital spendingplans there going forward?

[Steve Farris:]

We continue to put together exploration projects but our mainconcern frankly right now is to get 40’s up and running because if you look atthe fields in the North Sea I think the 40’s field is either the second orthird largest field still in the UKNorth Sea and if you consider that and we are seriously believe there isanother 450 million barrel resource potential there it would rival any field thathas been found. Our immediate goal is tomake sure we make that run everyday and I think we are later than what Ianticipated but I think we are pretty close to be in there. With respect to the gas markets, I mean with the UnitedStates Bank, they had a psychedelic ride, I mean they have gone through one ofthe most aggregated volatile markets. It went from sometimes over $20 to $4 to$3. Frankly I think that gas market willcontinue to be tremendously volatile in the UK for the very reason that I thinkit’s going to be somewhat volatile in United States and that is they have to importtheir commodity and that has to do, as gas becomes more and more worldwide thegas is going to find the place that is going to pay a nice price because oncethey get on the water in the LNG they are going to the highest priced gasmarket. So in terms of our future on the gas side, I think thatdepends on how other people look at it, because at $86 a barrel the things thatwe have seen that have come through have been pretty high priced. We certainly didn’t get into the North Seajust on 40’s however. So we are veryhigh on the potential of the North Sea and things thatwe know how to do very well.

[Tom Gardner:]

one last question with respect to Australia. I just want to get an idea of to what degreeyou are able to manage those higher spot prices? How much of your gas is termedout and when does that come open for free negotiation? Then the growthcomponent on top of that, what does that look like relative to what you areproducing today?

[Steve Farris:]

We have about 40% of our gas that is going to come off, 40%to 50% of our gas is going to start coming off 2009 and 2010; our existinggas.

[Tom Gardner:]

Meaning come out of contract?

[Steve Farris:]

Yes, come out of contracts. The real demand for gas today in Australiabesides the rollover contracts that we will obviously try to renew are the hard metals that you are seeing in the restof the world, if you look at the copper prices or anything, steel prices. Thereare a number of new mining plants going in on the western side of Australiato capture that price for minerals. If youlooked at a demand curved in Australiaover the next five to six years, it is not unlike the demand curve you see in Egyptwhich is about 12% per year. Our honest Achilles Heel is we have to get these projectsdone, and it is not an Achilles Heel, but our future is in front of us if wecan take advantage of it. We have the closest, we have the gas that can get tomarket in the near term. We had a tender, we had 23 expressions of interest forgas, so there is definitely a demand for gas, and there will be an advance forgas. I don’t know if you read some ofthe information that comes out of the Western Australian government, they areconcerned about natural gas starting in 2009, 2010.

[Tom Gardner:]

Is Apache being aggressive in going after that market thengoing forward?

[Steve Farris:]

Yes sir. I might add to that again I want to make sure Imade my point as I made it. Our Reindeergas we are into the engineering design and it should come on in 2010. We justended a tender process where we were asking for interested parties to submitindications of interest by last week Friday. We got 23 indications of interest; now obviously we are going to picktwo or three and deal with them, but their appetite was overwhelming.

[Operator:]

Your next question comes from Jack Hayden – PritchardCapital.

[Jack Hayden –Pritchard Capital:]

A couple of quick questions. First on the tax rate issue youtalked about Q4 tax rate being about the same as Q3 assuming you report it the same way,stripping out the forex impact, where would you expect the tax rate to shakeout? Can you give some additional detail on what you have goingon in the Canadian shale play? If possible, some results from these couple of wellsdrilled and a little color on the depths, targeted well costs, anything likethat?

[Roger Plank:]

Regarding the tax rate, I think I got the gist of what youare asking. There has been furtherdeterioration in the fourth quarter. Sothe number that I gave before or the comment I made before that the fourthquarter rate, although it would be comparable to the third quarter rate of 48%is taking into consideration that deterioration in the U.S. dollar that we’veseen so far in this quarter. So if thereis no further deterioration from here we still ought to have a rate of about48%. Does that answer your question?

[Jack Hayden –Pritchard Capital:]

No. You had 48% but you stripped out components as unusual dueto the forex change, which got the tax rate down to about 38% ex that. So assuming you considered the forex impact inQ4 again to be kind of unusual, should we expect a recurring tax rate of about38% again?

[Roger Plank:]

Our natural un-foreign currency changes, tax rate of 38%,39% something like that. Now, but to get there we have to go through year endbecause of the changes that have takenplace so far that the impact is blended throughout all the quarters ahead of you. So you won’t see that until next year. If you know what I am saying. We have acarryforward of that impact from the change in the foreign currency year todate.

[Steve Farris:]

The clock starts over January 1st and so it would takeanother currency move like the one we have seen to drive rates next year up tothat mid to high 40% range.

[Roger Plank:]

So far,I mean it’s been a $0.15 move from start of the year to the current timeframeso that would be another huge move. Well we’ll just see, but hopefully with theclock starting over we will be back below 40% next year.

[Steve Farris:]

The question on the shale, you're exactly correct. Actually,we have four wells in the shale, two vertical wells and two horizontal wells.One of the horizontal wells I would describe as actually legitimately testingin a play the way we will this winter. We put three fracs on a well; obviouslythe next well we'll probably put seven or eight fracs on it. We're very encouraged by the results of that well. The ratewas about commensurate with a three frac well. The decline curve has not beennearly as steep as we anticipated. It has been actually tremendous; it hasdeclined but it's been a tremendously shallow decline. We're designing fracs.We'll probably do two or three different kind of fracs in the wells that we'regoing to drill this year. But between us and EnCana, our partner, we'll end updrilling nine wells this year. We have 400,000 acres under lease of which we own 50% across-the-boardand EnCana owns 50%.

[Operator:]

We'll go next to JohnHerrlin with Merrill Lynch.

[John Herrlin:]

In Australia,Steve, you talked about Julimar and the associated discovery being commercial.How are you going to produce that, or where?

[Steve Farris:]

John, in terms of the development plans, we have about threedifferent scenarios that we're working on because we have obviously a lot ofpipe to lay. One version is to take it close to Varanus Island without taking it on Varanus Island so that we can move gas. Wehave a 450 million a day pipeline that goes to shore right now at Varanus Island. Reindeer will have apipeline to it because we're going directly to shore at Reindeer to the north. So the design plans would have either going over, throughReindeer, or coming down and making sure that we can get Julimar gas, Brunellogas, Maitland gas, whatever else gas we find not coming through Varanus, butcoming close to Varanus so we can continue to be able to take gas in from thatpipeline also. Actually, we haven't settled on a design currently, John.

[John Herrlin:]

In Egypt,you spent a fair amount of time talking about your gas discoveries and the AEBand the condensate to the south. Do you think they're connected? How big do youthink the condensate field is?

[Steve Farris:]

The reason I bring up the two independently is -- and I'm sure you caught the gist of it –they are 17 milesapart and one is on a ridge that goes up on the eastern side of the MatruhRidge. We currently have two more exploration wells drilling in the MatruhConcession. One is called Amber which is along the Jade Ridge to the north, andthe other one is a big Jurassic structure which is more than a step out butit's east of Obiat Field. That's a Jurassic test. We have six exploration wellsthat we're going to drill either between now and the end of the first quarterof next year up there. The potential of the Ridge on the Jade side, I think wetalked about that in order to be one of our significant discovery or potentialprospects it has to have the potential of 50 million barrels of oil or 500 bcfof gas.

[John Herrlin:]

Gulf of Mexico, you mentioned thatrig rates are coming down. It's a good free cash flow generator for you, eventhough it's not always a growth province. Would you consider more consolidationsthere since some of the small fries have had operational issues?

[Steve Farris:]

I would point out that we've never indicated that we aregoing to organically grow the Gulf of Mexico. Ourposition has always been that it is doing and has done a tremendous job for anumber of years and in generating a lot of cash. It has a good size to it rightnow. I can't see us getting significantly larger. From a smaller standpoint, there are still a lot of playersin the Gulf of Mexico. If the right opportunity came by,that would be something we would be interested in. But we are a portfolioplayer so in terms of its size, it fits very nicely in with longer life gas in Canadaand the U.S.and Central Region.

[Operator:]

Your next question comes from Leo Mariani - RBC.

[Leo Mariani:]

I just wanted to clarify the growth in your Egyptian gasvolume. Correct me if I'm wrong, but do you feel that you expect some plantcapacity expansions in the first quarter of '08 as well as in the fourthquarter of '08? If that's the case, could you give us a sense of the magnitudeof those?

[Steve Farris:]

Well, if I said thefirst quarter, I misspoke. I meant to say the third quarter. We have two trainsthat are coming on, one will be right behind the other. Actually, it should beon a little bit before the end of the third quarter, and they're both 100million day trains. Both of those will come on first or the fourth quarter. Sowe have 200 million a day gross, which has the capacity of about 16,000 barrelsof liquids or a little less, of which we have between 45% and 50% depending onwhat the prices do, because price has something to do with the cost recoveryoil that we get.

[Leo Mariani:]

A question on Argentina.One of the things you referred to in your prepared comments was the fact thatyour price realizations weren't as strong third quarter but you would pick upin the fourth quarter. I was just trying to get a better handle of thedynamics. I noticed your volumes were down around 9% sequentially on the GAAPside. I'm just trying to understand that a little better. I guess you guys weretalking about a cold winter down there in Argentinaand I was a little surprised to see your volumes down if that's the case.

[Steve Farris:]

Well, the volumes are down specifically because the take isout of Tierra del Fuego. That's not a performance issue.That has to do with a Methanex contract that's going to Chilethat Argentinadoes not want us to export gas to Chileright now. So, the volume, we can produce what we produced every quarter beforethat, and hopefully, we'll continue to raise that. Our production from when we got in there, we're up about 19%on the gas side, and we can find gas. We can find hydrocarbons down there. Thisis going to be an issue of economics and what they allow us to do in thefuture.

[Roger Plank:]

It's a little bit upside down like a number of things downthere. They say you can't export because we need the gas in this country but inTierra Del Fuego, basically that time of the year thepipelines to the north where the population is are full. So the net result iswe've got to shut in the production rather than selling it to Methanex. Sothat's about 16 million to 20 million a day that was curtailed.

[Leo Mariani:]

Can you give us a sense of how oil drilling is going downthere in Argentina,what your plans are for the near future?

[Steve Farris:]

We have basically twodifferent areas as you might know. We have Tierra Del Fuegowhich is down at the south and then we have our Neuquen drilling and most ofthe Neuquen stuff that we're doing is extensional type work around fields thatwe acquired from Pioneer. In the Tierra Del Fuego area, we are shooting a 2,000 squarekilometer 3D seismic shoot there that should be done by the second quarter ofnext year, across not only the existing fields but also as part of a shootacross 680,000 acresdown there. This is a very, very under-drilled province in terms of explorationpotential. San Sebastianfield is a 65 million barrel oil field, so there is a lot of potential downthere to find additional oil. One is an exploration play and the other one isan exploitation play.

[Floyd Price:]

A couple ofspecifics, we drilled an oil well.

[Steve Farris:]

I'm sorry -- forthose of you who don't know, this is Floyd Price who runs our international Argentinaand Australia.

[Floyd Price:]

Just to give you a feel about Tierra Del Fuego,like Steve was talking about, we just fracced a well down there that came onfor 165 barrels of oil a day. We drilled another exploration well that came inon Don Piadra and it came on for 5 million a day but it was about 50 barrels amillion when you took into account the gasoline as well as the condensate wewere making with it. So very rich, and we think we can do pretty well with ourliquids.

[Steve Farris:]

Sometimes the gas gets clogged up down there because oflimited pipeline capacity. They are expanding and looping that line to thenorth, aren't they, Floyd?

[Floyd Price:]

That will happentowards the end of 2008.

[Leo Mariani:]

Moving over to AustraliaI know it's a little early in the game and you had three very nice discoveriesthis year, you talked about potential around 1.3 Tcf and you're still workingon development plans. Do you have any estimate of the kind of potentialdevelopment cost there on a per Tcf basis or anything like that?

[Steve Farris:]

I mentioned to John Herrlin that we have three differentdesign schemes. It really depends on which one of those we pick. When we getcloser to a final design that we are going to go with, it's probably moreappropriate to talk about where we think the cost will be. I'd be estimating right now, and it could besignificantly off one way or the other.

[Operator:]

Your next question comes from David Hiberon - Wachovia.

[David Hiberon –Wachovia:]

You mentioned in Alberta worst case scenario, if the taxpackage goes through or the interest goes through as planned, if you look at aCapEx budget call it $700 million to $800 million, you reduce that, where doesthat CapEx go?

[Steve Farris:]

In Canada?

[David Hiberon –Wachovia:]

Yes, if you were to take it out of Alberta,where would you deploy it elsewhere in the program in your portfolio?

[Steve Farris:]

Well, our winter drilling program in our shale gas in B.C.is about $100 million this year. We have the opportunity to spend it. What I'dhope and as many of you might know this evening they're supposed to detail theoutline of their new royalty scheme. I don't know who listened to the Premieryesterday, but it was a little more steady than at least what the rhetoric hasbeen around it. There's some hope that they will phase in any royaltyadjustments they may have, which would go a long way in trying to look atcapital budgets in Alberta nextyear. There's some talk that their deep drilling royalties may not be part of adeep gas drilling. It would probably cut at least a couple hundred milliondollars out of our budget in Albertanext year, but that's a supposition, honestly.

[David Hiberon –Wachovia:]

I know that's a supposition, though it sounds like you wouldallocate a little more to B.C., and then just elsewhere throughout the program.

[Steve Farris:]

Unless it just gets really chaotic up there in Alberta,I can't imagine us spending -- our budget will probably be somewhere aroundwhat it is this year and honestly it could be higher.

[David Hiberon –Wachovia:]

One more big picture question. There's been a lot ofspeculation and I think the general consensus was Canadawould come off a little quicker, not for you but for industry as a whole oncethe rig count plummeted last year. I think maybe some people were surprisedabout the level of exports into the U.S.,that it didn't fall off more. Do you have any feel for why that was? Was it afunction of CBM production or was it a function of the marginal wells gotknocked off first?

[Steve Farris:]

I don't know. The only thing I would say is if they use theproposal that they're talking about or the one that the panel came up with, andit may take six months to fall off but you are going to see a real reduction inAlberta drilling. That can't doanything but reduce the amount of gas that's going to come this way. Two orthree months are really hard to forecast.

[David Hiberon –Wachovia:]

Yes.

[Steve Farris:]

A year is much longerbut that's even pretty short. Some of these things have a long term effect.

[David Hiberon –Wachovia:]

We'll wait and see what happens tonight. Thanks.

[Operator:]

Your next question comes from James Pascelli – TMV.

[James Pascelli:]

This is a follow-up on the last question. I know the trendsdon't look good for Canada but with Alberta gas recently around 5.95 or so, notterribly low, it's been lower, are you thinking that the industry is lookingfor something closer to $7 an Mcf to really get things going again or do youjust think that the latest announcement about the royalties et cetera is goingto put a big damper on any more interest in Canada? I'd like to add to that,that when everybody is getting discouraged with Canada,perhaps it's time to take a second look or we're getting close to a time totaking a second look.

[Steve Farris:]

I think the biggestconcern, frankly, is the uncertainty around what is going on. I heard thePremier last night say that they want to put some certainty in this and if theydon't, it will put a damper on it because in the world today, people have a lotof different places to put capital and I think that the most important thingthey could do would be to come up with something and stick to it. I think it has more to do with the places a lot of peopleare drilling than it does necessarily on price. Certainly costs have been highin Canada. Theyare coming down as they're coming down in the U.S.We're not totally oblivious to the large service companies earnings and wherethey're getting their earnings, but I think there is an awful lot more capacityout there. I happen to have agentleman from one of the very large service companies in this morning, and ifrig rates just stay the same there's probably 20% more capacity than there wasa year ago and there's going to be 20% more the following year. So I thinkthat's going to have an impact on the competition and what the cost side is goingto do.

[James Pascelli:]

Well, I think the negativity is extreme. The question is howmuch worse does it get? Obviously I've heard a lot of the calls on the servicecompanies. The tax proposal is somewhat self-defeating. I'm just wonderingwhere the turning point is.

[Steve Farris:]

We'll find out. It's going to be interesting, let me put itthat way. We're supposing about something we know nothing about yet because wehaven't seen the final proposal.

[Operator:]

Your next question comes from Adam O'Laughlin - BMO CapitalMarkets.

[Adam O’Laughlin:]

Can you revisit quickly again what you're expecting inproduction in the North Sea again for the next quarter?

[Steve Farris:]

We're looking at about 60,000 barrels a day.

[Adam O’Laughlin:]

Next year, where is the growth in production really going tocome from? I assume it's really in Australiaand the oil. Can you elaborate a little bit? I know it's exploration success,but just a little bit of segmentedgrowth?

[Steve Farris:]

Well, I thinkcertainly you're going to see some growth in the United States, you're going to see growth in theCentral Region. I think given where we are in the North Sea,I think you could see some growth in the North Sea.We've had a bunch of ups and downs in the North Sea thisyear. Certainly, we're going to see some growth in Egyptas we have in the past and with two trains coming on that are going to come onat the end of the third quarter, you're going to see some significant growth inthe fourth quarter of next year coming out of Egypt.But we have an active drilling program there. Unless we get some surprises out of Argentina,you're going to see some growth in Argentina.I think the only area that we don't advertise growth in is the Gulf of Mexico, because that is a different part of our engine than therest of our regions, and it is wide open with respect to Canada.I mean, that's a function of how much capital and what kind of returns you canget in Canada,because many of you probably have heard me say, there's more gas in the WesternSedimentary Basin of Canada than any other place in North America.So it's just a question of economics.

[Operator:]

Thank you. It appears we have no further questions. At thistime, I'd like to turn the conference back over to our presenters for anyadditional or closing remarks.

[Bob Dye:]

Thanks for joining us. If any of you have further questionsI'll be in my office. Thanks again.