康菲 (COP) 2002 Q4 法說會逐字稿

Good day everyone and welcome to the ConocoPhillips fourth quarter earnings release conference call.

Just as a reminder today's call is being recorded.

At this time for opening remarks and introductions, I would like to turn the call over to the General Manager of Investor Relations, Mr. Clayton Reasor.

Please go ahead, sir.

Good afternoon and welcome to ConocoPhillips fourth quarter earnings conference call.

Jim Mulva, ConocoPhillips President and CEO, will give a review of the quarter's performance and an outlook for 2003.

After his comments, Mr. Mulva will be available for your questions.

But before we get started I'd like to remind that you in addition to talking about the fourth quarter earnings, there may be forward-looking statements made in response to some of your questions that deal with our projections and expectations of future results.

Actual results may differ materially from those we currently forecast and factors that can cause actual results to differ are found in the company's filings with the SEC and in the earnings release that we sent this morning.

Now, that said, I'll turn it over to Jim Mulva.

Clayton, thanks.

And thank you to all those who are joining us for our fourth quarter conference call.

I appreciate your interest in ConocoPhillips.

We're making good progress executing our strategic plan that we outlined last November 22 at the New York analysts meeting.

And we're building a new company with very high expectations to improve our competitive position as we compare ourselves to the largest companies in our industry.

When looking at this quarter's results, you see really the first complete quarter with the new ConocoPhillips.

So it makes it rather difficult to compare this quarter's earnings with prior quarters or other periods of time.

You have seen from our media release this morning our fourth quarter net operating income was $747 million or $1.10 a share.

And we indicated that does not include that $1.10 share does not include the $31 million in earnings related to discontinued operations in the downstream retail assets that we have identified for sale.

Had we not identified them for a discontinued operations, and had included them in our downstream earnings, then the net operating income for the total company is said to be $1.10 a share would have been $1.14 a share.

In E&P, we operated quite well and we were able to offset the loss of production from Venezuela with somewhat better production and operations in Alaska and the North Sea and refining and marketing business we improved over the third quarter of this year even though events in Venezuela and the down time at our United Kingdom Humber refinery resulted in our refineries running at a lower capacity all in worldwide 89 percent.

In the case of the United Kingdom Humber refinery we actually operated about 112,000 barrels a day and it has a capacity of 225,000 barrels a day.

Now in terms of our net operating income for the fourth quarter, you saw in the earnings release EFP did $824 million, refining and marketing $193, chemicals lost a little, midstream was at $20, emerging business was minus $40 and corporate was minus $237.

This all added up to $747 million.

I wanted to talk quite a bit more about most of these items as I go through my introductory comments.

Now, if you look at the reported net income for the company including the special items, we had a loss of $410 million in the quarter.

So we had $1.2 billion in special items in reduced net income that resulted in this loss in the fourth quarter.

A $1.1 billion of special items were caused by our planned sale of our -- a significant part of our retail marketing assets and included in that $1.1 billion was plant, property and equipment of $177 million goodwill of $257 million, other intangibles $345 million and lease financing structures of $350 million.

That adds up to nearly $1.1 billion.

Now, also, we had some other special items in the fourth quarter of $83 million.

They are primarily related to restructuring charges of our continuing operations of around $53 million and about $25 million in other transition costs and all these numbers are after tax.

Now, if we look at future -- what do we expect additional charges in net income, we see on the disposition of a substantial part of our retail marketing in the downstream of another $200 million in some time in 2003, and this is related to as we sell the assets on how we handle the lease financing structure and so we announced late last year $1.3 billion.

We recognized $1.1 in the fourth quarter and this $200 million is the remainder that we will recognize as special charges to net income as we go through 2003.

Now in terms of what we expect going forward, we don't expect any substantial large charges as part of implementing our merger and our transition.

We will have from quarter to quarter transition costs that we need to be recognizing and this is really done in the future periods to really match the cost or expenses and when they happen and this is really done for accounting purposes.

So I think for guidance you should be thinking as we have this quarter to quarter, I really look at this as BFS, you know, it's a double-digit kind of numbers.

So it's just kind of cleaning up as we go through on the transition of implementing the merger.

So far, there's been about, oh, 25 to 30 percent of the announced reductions that we expect to have as a result of the merger, 25 to 30 percent have occurred.

Now, this does not include, by the way, we have about 17,500 employees who currently work in the retail marketing assets that we have identified for disposition.

Nor does it necessarily include the employees that are associated with the assets that we have agreed with the Federal Trade Commission to be disposed of in connection with the approval for the merger.

Turning to some of the accounting items that I want to make sure everyone knows and recognizes that the merger of ConocoPhillips was completed and we used purchase accounting so financial results for the year include 8 months, that's January-August, of the old Phillips, and then four months of the -- last four months of last two months of ConocoPhillips.

During the call we'll be using pro forma production operating information which is included in the supplemental information that you can access on our website.

So this information pro forma information is calculated by combining the production data from both the old Conoco and Phillips.

And we believe that this will help you establish new base lines to evaluating our performance as we go through this current time period and future time periods.

Now, turning to the upstream exploration and production, as I said, our operating income for the quarter was $824 million.

The United States, it was $430 million.

Our international earnings were $394 million.

So, you know, roughly balanced US, domestic, and international.

Realized crude prices for E&P were $25.31 a barrel.

It's a little bit less than $25.97 a barrel in the third quarter.

In terms of our Lower 48 natural gas prices, they averaged $3.43 in MCF versus $2.65 in Mcf in the third quarter of this last year so including the gas prices, certainly for our production (indiscernible) market conditions but the differentials to HenryHub widen due in larger discounts than we had in past quarters and this is a result of where our production's located particularly in the western gas in the US.

Our worldwide gas price averaged $3.25 in Mcf for the quarter and we did $2.23 in Mcf during the fourth quarter last year.

Looking at our production, upstream did on a barrel of oil equivalent a little more 1.62 million barrels of oil a day essentially right on what we said we would do in the fourth quarter.

Worldwide gas production was 3.5 billion cubic feet a day.

Our liquids production which includes our crude oil, natural gas and Canadian syncrude totaled just over 1 million barrels a day and in fact was 1,033,000.

Although we generated acceptable level of earnings, performance in E&P could have even been better if we were able to run to our full capabilities.

During the quarter oil and gas production was impacted by down time, on the average during the quarter, about 34,000 barrels of oil equivalent a day and about 22,000 of that 34,000 relates to the shutdown of our Venezuelan production from [Akan Petros Siswata].

We were also adversely impacted on the average during the fourth quarter 10,000 barrels a day with the earthquake transAlaskan pipeline in Alaska and during the fourth quarter, Gulf Coast tropical storm, hurricanes impacted us on the average of fourth quarter 2000 barrels of oil equivalent a day.

If we didn't have these things, we could have done about 34,000 BOE a day better.

Exploration expenses in the fourth quarter were $248 million dollars pre-tax.

This is higher than we expected and they're higher than the expectations and the guidance that we see going forward in 2003.

The higher fourth quarter costs were primarily due to -- we had higher dry hole expenses resulting from the high grading of the combined exploration program as we look at the old Conoco and the old Phillips added together and our exploration going forward, we recognized additional dry hole expense because we don't have plans for developing certain of these marginal properties going forward.

And then we have some higher actual drilling results expenses that we recognized in the fourth quarter.

So as I said, under the accounting rules if you don't have plans to develop your exploration prospect within a certain time period, then you need to write those assets off.

And that's why the exploration expenses were higher.

To give you some guidance or baseline for 2003, when we put our plans together, we were with the analysts in New York, we indicated that our cash spent on exploration, cash spent, that's for everything, Cap Ex, capital and for expense, was around $750 million for our total exploration program in 2003.

And our expense part of the $750 million for the entire year is around $600 million.

So it gives you an idea as you go through each quarter for some guidance on what the exploration will be.

Now, within E&P turning to Alaska, in spite of the earthquake, despite the earthquake we had a really strong fourth quarter in Alaska.

Alaska made $282 million in the fourth quarter.

That compares to $248 million in the third quarter of this year, $155 million fourth quarter of 2001.

As I said, in spite of losing 10,000 barrels a day of oil equivalent to the transAlaskan pipeline earthquake, we produced 378,000 BOE a day in the fourth quarter.

That's made up of 323,000 barrels a day of oil, 24,000 barrels a day of NGLs and 186 million cubic feet a day of gas.

As we have been saying all along, we expect to produce between 375 and 400,000 barrels of oil equivalent a day from our Alaskan production and during 2002 our average was 384,000.

So we're right in the ballpark of what we said we would do.

Alaska is a important contributor to E&P operations, this year it has been, over the last several years.

And its strong performance is due to good performance for all of our fields but particularly the addition of Alpine Satellite fields which goes to offset the production declines that we experienced from from Prudhoe Bay and some of the older reservoirs od Kuparuk.

During the quarter first production was achieved from the Palm Satellite of the Kuparuk field.

Moving to the Lower 48 E&P, we made $148 million in the fourth quarter.

Average realized prices were $3.43 for gas and $26.36 a barrel for oil.

In the fourth quarter, Lower 48 natural gas production averaged about 1.4 billion cubic feet a day.

If you look back at prior periods, and we look back actually to the first quarter of 2002, we have 105 million cubic feet decline if you look at the first quarter of '02 to the fourth quarter of '02, and that's just on pro forma production.

Now, of that 105, 30 million came from normal field decline and 75 million came from our Gulf of Mexico asset dispositions.

If you look at the Lower 48 liquids production, which is made up of crude oil, natural gas liquids, during the fourth quarter we did 79,000 barrels a day.

Again, if you use the same comparison, the first quarter results of '02 to the fourth quarter of '02, there is a decline of 13,000 barrels a day of liquids.

Now, we had asset sales that impact that by about 8,000 barrels a day and the normal field decline was about 5,000 barrels a day.

Turning to international E&P.

International E&P made $394 million during the fourth quarter.

We did well up in the North Sea the Norwegian North Sea, we averaged 279,000 BOE a day for the quarter.

Our volumes were higher than the past quarter primarily due to better Ekofisk operations.

And the UK North Sea we produced 249,000 BOE a day, and had good strong performance.

In Canada, our production averaged 147,000 BOE a day.

And that includes 442 million cubic feet a day of natural gas.

Nigeria production increased in the fourth quarter of '02 to nearly 47,000 BOE a day, and this is due to the lifting of OPEC curtailments that we experienced through most of 2002.

So Nigeria we did about 38,000 barrels a day of crude and 51 million cubic feet a day of gas.

In Venezuela production as I said earlier was impacted by the recent events in the work stoppage at Petros Siswada and Hamaca.

This operating interruption in Venezuela began in December.

It's reduced our production by 78,000 barrels a day compared to the rates these operations were running prior to these events.

So we were getting of the 78,000 barrels a day, we are getting 18,000 barrels a day in early December from Hamaca and 60,000 barrels a day from Petros Siswada.

Indonesia and Far Eastern barrel oil equivalent production fell slightly in the fourth quarter of 61,000 BOE a day.

Turning to refining and marketing results.

Our refining and marketing business generated $193 million in net operating income, a $201 million came from our US operations, we lost $8 million in our international refining and marketing.

Now, if you look at our refining and marketing business domestically, the $201 million, 78 percent of that was generated by the refining side of the business and 22 percent was generated from marketing.

If you look at refining, the result in the financial results where the income came from, about a fourth of it came from the Eastern region, about 45 percent the Central region, 25 percent on the Gulf Coast, and a small amount in the Western region.

The Western region, you know the supply and demand situation, and there's plentiful supply and we had the result of narrow ANS WTI spreads certainly did impact the performance on our West Coast refining and marketing operation.

International earnings were negatively impacted by the UK Humber refinery being down for all of October and about 1/2 to 2/3 of November.

So the impact on the average for the quarter was we lost 112,000 barrels a day.

Now, this shutdown was a result of a significant total power outage and then we started up, we had some mechanical integrity issues and so we took quite a period of time to make sure that we had everything sorted out fully and right before we started up.

This resulted in us losing operating profit opportunities that was lost of about $50 million impact, adverse impact, in the fourth quarter.

In the fourth quarter, our domestic refining and marketing earnings were reduced by the loss of Venezuelan crude availability.

Of course, you know, certain of our refineries are really configured to run on Venezuelan crude.

So our Sweeny and Lake Charles refineries were directly affected by running at somewhat reduced rates and with sub optimal crude slates and this all took place in the fourth quarter really in the month of December.

And it had an impact to our refining and marketing operation we believe somewhere in the neighborhood of about $5 to $10 million of net income.

While we make crude oil supply decisions that are best for the entire refining system worldwide and in the US, some of our individual refineries run a crude oil that's not really optimum for that refinery.

And it also does impact the efficiency of our refineries and our total network and so this has the impact of the financial results.

Crack spreads were also negatively impacted, as you know, by the differentials in the heavy/light on crude oil and refined products.

Looking now towards chemicals.

As you might say though, before I go on to chemicals.

If you look at the $200 million that we earned in refining and marketing, it really came in the fourth quarter all from our domestic operations.

Now, I know you can always look at things in hindsight but had we been running the UK Humber refinery and did not have the lost opportunity of net income with it being down $50 million, then we could have seen our refining and marketing worldwide have resulted in net income in closer to $250 million.

So we think that's an important point that we certainly want to watch our reliability and to minimize our lost opportunity.

We would have had a much stronger result for refining and marketing in the fourth quarter.

Chemicals, our chemical joint venture with ChevronTexaco continues to experience really difficult market conditions.

It comes primarily from high cost of feed stock but it also comes from the weakness with respect to supply and demand situation and operating facilities in the industry and in our joint venture at lower rates than we would like to for profit purposes.

Our share in the joint venture generated a loss of $13 million for the quarter.

The $18 million decrease compared with the previous quarter is really primarily again, it's feed stock costs and lower spreads that come ultimately from our substantial olefins and polyolefins earnings.

Turning to midstream, our joint venture with Duke Energy and our wholly owned midstream operations from the Heritage Conoco, our midstream business earnings was $20 million, this compares with third quarter of $11 million.

So we had the benefit of in the whole fourth quarter of the Heritage Conoco midstream operations certainly benefiting results but we had low profitability from our share of the earnings from the joint venture with Duke.

Turning to corporate cash flow, debt and the balance sheet.

Corporate charges were $237 million in the fourth quarter.

And this is a $50 million increase over the -- over the fourth quarter corporate charges guidance that we gave you when we last talked it was about $190 million to $200 million.

It was primarily due to adjustments made to reflect a lower tax benefit from interest expense of 2002 as we combine the foreign operations of the two companies Conoco and Phillips.

This additional cost is not expected to impact future years or the future quarters or the synergies that we expect to capture.

So what we are still staying with, this is a unique situation in the fourth quarter.

Our guidance going forward in 2003 is corporate charges will be in the $190 to $200 million.

Now, very briefly, looking at the cash flow sources and uses of our cash flow in the company in the fourth quarter, our cash flow from operations were $2 billion.

We sold assets for about $700 million.

And we utilized drew down some of our available cash by $200 million which gave us about $2.9 billion of sources.

We spent nearly $2 billion in capital, paid our dividend of $270 million, and reduced debt in the neighborhood of $680 million to $700 million.

So that's just a very rough sketch of the sources and uses of funds.

Looking at our debt, our tax situation, our balance sheet debt, the end of the quarter was $19.8 billion.

Stockholders' equity, $29.5 billion.

Our debt-to-capital ratio at the end of the quarter was 40 percent.

Effective tax rate fourth quarter was 47 percent.

Now, turning to some more additional comments with respect to the first quarter and our outlook for 2003.

Our production in barrel oil equivalent for the first quarter is estimated to be below the fourth quarter of '02 and this is primarily as a result of lost production from Venezuela.

So we expect in the first quarter to be 1.55 million BOE a day, and this forecast assumes that production from our Venezuelan operations do not -- will not resume in the first quarter.

Now, we'll have to wait and see whether that assumption holds true or not, but the decline of production expected in the first quarter compared to the fourth quarter is primarily relates to loss of Venezuelan production.

Now, if the Venezuelan situation continues we want to give you a financial impact to the company, what it means to us per month.

And, of course, a lot depends on what our oil price is and then a lot depends what happens to crack spreads and differentials in the downstream part of the company and how it impacts.

But we believe the impact of being down, integrated impact is about $30 to $50 million per month as long as this total shutdown continues.

Our Lower 48 gas production expected to be about 1.34 billion cubic feet a day during the first quarter and during the first quarter looking at the situation around the world we expect our refinery runs to be somewhat near -- it could be plus or minus a percent or two off 90 percent of rated crude capacity.

Now, our availability of heavy sour crude does have some impact obviously on what runs we make in individual refineries and in the total network.

And also, the market conditions, crack spreads and inventory levels have an impact on our crude runs.

Our turnaround costs in refining for the first quarter of '03 will be about $50 million.

In terms of our sensitivities at this point in time, as we look out into the first quarter for 2003, a change of $1 a barrel in our crude price will impact us for the whole year, 2003, $180 million, 10 cent per Mcf natural gas price impacts us $40 million a year.

And refinery crack spreads moving by 25 cents a barrel is $130 million a day -- a year, a year.

As I said, we expect our first quarter corporate charges to be $190 to $200 million for the quarter.

And we're going to report on our synergy capture as we said in the past, uhm, when we get our first quarter '03 earnings results.

And we'll compare that results with normalized crude oil and gas price and crack spreads to out how well we did on a pro forma basis in the first six months of 2002.

We'll provide this assessment as we go through each quarter how we're doing on capturing our synergies.

Looking further ahead, we feel very good about implementing our plans to improve the financial and operating and performance of our business lines, generate higher returns, we're also [hydrating] our projects, capital projects and exploration portfolio conserving our capital for the large legacy assets to generate the longer term financial returns through all different pricing, commodity price cycles.

We are emphasizing the discipline in our cost structure, discipline on our capital spend, improving our balance sheet.

As we said in November, 75 percent of our capital goes to the upstream business.

Our financial plan provides specific steps to ensure that we reduce our overall debt levels.

We want to have a continuing improving stronger balance sheet and we think all these activities absolutely no change following the same consistent approach we outlined in November.

We'll improve our capital structure, financial flexibility, return from the business lines which will translate over time to, you know, very competitive and strong shareholder value creation.

So that really completes my prepared remarks.

So I think we'll stop now, Clayton and and the both of us will try to answer whatever questions we have.

Great.

If you would like to line up some questions we'll do our best to answer them.

Thank you.

The question-and-answer session will be conducted electronically today.

If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touch-tone telephone.

If you are using a speaker phone, please make sure your mute function is turned off to allow your signal to reach our equipment.

We will proceed in the order that you signal us and we'll take as many questions as time permits.

Once again, that is Star 1 on your touch-tone telephone.

Steve Pfeiffer from Merrill Lynch, please go ahead with your question.

Hi, guys.

I wanted to follow up on actually the corporate items where the higher corporate expense was due to the reduced tax benefits.

Just specifically on that, will you see some of those benefits come back, or are you expecting to have the, I guess lower tax benefits continue but then offsetting it with other things?

And secondly, on the corporate line as well, when you think about the 190 to 200, going forward, does that have a, you know, higher pension cost consumed in that, as well?

Steve, the tax impact in the fourth quarter had to do with the deductability of some interest charges and we expect that that deductability will increase over time.

So those interest costs will fall over time.

They're not all one-time charges.

But we expect it to be temporary in nature.

And the 190 to 200 per quarter includes the additional burdening of the pension cost.

Great.

If I could ask it just another way, ex sort of cost-cutting synergies, things like that, what would you expect the corporate number to be and then how much do you (indiscernible) down via the synergies and cost reductions?

He will with I think what we are going to do is show that -- demonstrate that as we come out with our first quarter '03 results and so I think you'll see that then, Steve.

Okay.

Thank you.

We'll now move on to Fred Lufr with Bear Stearns.

Good afternoon.

Jim, it sounds like the foundry turnaround expenses in the first quarter they sound a little high but yet, you are indicating that you expect operating rates to stay above 90 percent.

Can you shed some light on that for me?

Well, I don't necessarily view the 90 percent as necessarily a high operating rate.

I mean, we can do much better than that.

But it depends upon availability of crude and depends upon what we see in crack spreads and returns, whether we want to run at certain levels.

But, no, I don't think there's an inconsistency there.

We've got this scheduled to some extent as a result of the Venezuelan situation.

We might take a look at maybe some of the things that we could do in second quarter and the first quarter but we're pretty well following our scheduled maintenance in turnaround.

So I don't think it's inconsistent.

I mean, we could operate, you know, even higher levels than 90 percent, but we think a combination of turnarounds, our Venezuela situation, and the spreads that we see, this is probably the optimum place for us to be.

Would you characterize the first quarter as a heavy turnaround period?

Well, I think in terms of our total turnaround for the year, and I can't recall, Clayton, you might have that, it is a heavy for the first quarter.

Yar, I think we're looking at around 150 in after-tax turnaround.

It's closer to 175 for the year.

But it's a little bit heavier -- 175 -- it's a little bit heavier in the first quarter than maybe some of the other quarters.

Okay.

If I may, the release talks about additional impairment charges of about $200 million to be taken this year.

Would than spread out or is that going to come -- would that be spread out or is that going to come later?

As you know, Fred, we indicated on disposition of what's been identified significant portion of our retail would be $1.3 billion.

For accounting convention, we took $1.1 in the fourth quarter.

So the remaining $200 million of that $1.3 will be taken as we sell the individual retail assets.

And that is accounting convention that must be followed.

It relates to how those individual assets were financed.

And in terms of our disposition of retail, I think we should like to pass along, this is something that is probably going it take the better part and be really completed in our plan the latter part of 2003.

Okay.

Thank you.

We'll now move on to Dave Wheeler from J.P.

Morgan Securities.

Hi, Jim and Clayton.

Two questions for you.

Jim, a year ago you mentioned you weren't -- you were hoping to improve finding and development costs and reserving placement performance especially in the US.

Were you satisfied with the performance in '02?

Well, we have not announced that yet and that's going to be coming out in the early part of February.

As you can see from our presentations in November, in New York, we are not going to replace our reserves in 2002.

This is a result of our exploration success.

It's a result of our asset disposition and the timing by which we book the new fields.

So 2002 is not going to be a good year for us in terms of reserve replacement or our finding and development costs.

But yet we look on it at over a rolling three years or five years our reserve replacement and finding and development costs are some of the most competitive in the industry and as we look forward to our new things that we have in our plans, that we expect to book, is certainly going to show a good reserve replacement and competitive finding and development.

In other words, we have not yet booked anything from [Cashian] and Caspian and we have not booked [Coro Coro] and we have not booked gas related to the L&G project on [Biowandia].

Of course, we have to have sanction and approval of all those projects before we book them.

But I think 2002 is a lean year.

We want to you know that.

It's a result of dispositions, exploration success is not what would have wanted.

And it's how we book our large projects.

Those -- that information is going to come out in the early part of February.

Okay.

That's fine.

And just as a follow up to that, do you - this may be an early February question.

Do you replace ex the sales, did you replace reserves?

We have not replaced reserves, no.

Second question for you you mentioned dry hole expense was -- you put in there some projects that you are not going to go ahead in terms of development.

How much of the dry hole expense was that portion, and is there any production impact that's different from the guidance you've given us for '03?

Well, there is no impact on the guidance on production for '03 and probably no impact on '04, either.

In terms of the numbers or the amount, I don't have that and Clayton, maybe you could circle back on that --

We can come back, Dave.

I don't have that in front of us.

Okay.

All right.

Thanks very much.

Moving on to Mark Gilman with First Albany Corporation.

Yeah, guys.

Couple things.

I'm having a little bit of trouble with the first quarter production number, the 1.55.

Taking into consideration that I would assume, Jim, that the Alaskan number ought to be higher in the first quarter than the fourth and that UK gas sales probably ought to be higher in the first quarter than the fourth.

You know, 1.62 to 1.55 is a drop of 70,000.

The reduction in Venezuela to eliminate December, you know, is probably 60, 65, what am I missing?

Well, our production in Venezuela was closer to about 78 or 80,000 barrels a day.

And so --

Not in the fourth quarter it wasn't.

No.

But we were ramping up our production on Hamaca, I believe.

So we were -- I think the numbers were about 78 or 80,000 for the first quarter that we backed out.

Right.

The way to think about it, Mark, may be that, you know, fourth quarter impact for Venezuela crude loss would be 20,000 a day for the quarter.

And looking at first quarter the loss would be around 80 a day.

So you have 60 there.

As far as the delta between first and fourth quarter Venezuela production.

That's what I was saying but you got some things going the other way like Alaska and presumably UK gas.

Uhm, you mean -- that's correct but I think we also have some other offsets.

I think it best we -- I don't have the numbers for each field in front of me so we can circle back and answer that --

Okay.

Let me try another one if I could.

I don't -- I don't quite understand why it is at this point you haven't gone to an alternate crude source for Sweeny.

And why in the face of the continuing disruption and uncertainty, you know, regarding Venezuela and [Peda Vesa] why you wouldn't look elsewhere.

Well, we are, Mark.

We're looking elsewhere for alternative crudes.

All we're saying is they are not as optimum as Venezuela and the second thing is we're not interested in running crude just to run physical volumes.

We have to make sure that when we run an alternate slate of crude, that it's giving us some profitability.

We're looking at --around the world we have done a really nice job, I think.

Our people have done a nice job.

Minimizing the impact on the crude runs but on the other hand, we don't have the absolutely -- some of these refineries are configured on Venezuelan crude.

The reason I think we have done a nice job I think I've answered that

Okay.

So it's basically an economic decision.

Economic decision.

One more if I could the impairment numbers in the fourth quarter as broken down in the release between the PP&E, goodwill and intangibles, could you provide me pre-tax numbers for each of those?

I don't have them.

So I'll leave that to Clayton.

If you would please, Clayton.

You bet.

Thank you.

You bet.

We'll now move on to Fidel Get with Comstock Asset Management.

I have two question.

One on Venezuela.

If we assume that Venezuela is coming back a million barrels per day are your operations totally shut down now or what?

Operations are currently shut down.

And when do you expect - let's just assume that Venezuela, according to you, [INAUDIBLE] this thing that is going to increase by production by 2 million barrel per day at the end of this month at the end of next month so should we expect proportionately that your production will come back that much?

I don't think you can take it on a proportion basis because it's so complex and integrated in terms of feed stock and availability of natural gas and running all our facilities.

I think a good benchmark might be that once we start up our operations to really get into running them well is going to take the better part of 1 to 1 1/2 months or so.

And your [INAUDIBLE] refers to $50 million charge per month, that for the case is on no production whatsoever for, for what, two months, three months or more?

Our assumption was, that's the impact given current oil prices and crack spreads and differentials and the view is for an integrated impact of the company having Venezuela down cold.

Nothing running.

The $30 to $50 million a month net income.

Okay.

And finally on the cost saving and synergy benefit, how do we see that reflected on per unit basis in terms of operating costs?

How can we calculate that?

How can we calculate that?

It's very difficult to calculate.

We said we are going to give the benchmark and the data and the information for to you calculate and look at that when we come out with our first quarter results and subsequent quarter results for 2003.

Okay.

Thank you.

Moving on from Goldman Sachs Asset Management, Arjun Murti.

Thanks.

Jim, do you have any update on the timing of E&P asset sales for this year?

Should we expect them second half, over the course of the year and how is the change in the top management of E&P where Rob announced his retirement at the end of the quarter impacted either specific assets being sold or the timing or the program overall?

I think in terms of our asset disposition and exploration and production, it's going to be more toward the second half of the year than the first half of the year.

In terms of the strategy of what we sell or how we handle the sales and the operations, it is not -- we haven't missed a day.

The basic plans and approach continue.

There is no loss of time or letting the grass grow under our feet in that regard.

Okay, so despite the change with Rob leaving, uhm, you still feel you are going to be on track for not just the asset sales but the cost reductions, et cetera?

Yes.

Everything is on track.

Great.

Thank you.

We'll now move on to Tyler Dan with Banc of America Securities.

Hi, gentlemen.

How are you?

Good.

Hi, Tyler.

I guess, uhm, I'm not sure I got the full answer to the question I had, so I'll try and ask it, uhm, a different way and as I do apologize, I have been on and off the call.

But, uhm, in terms of quantifying the impact of of the $30 to $50 million per month drag on earnings.

Could you quantify that E&P versus downstream if possible?

I know these are integrated projects but as you would typically report them.

And then, secondly, in terms of what you're hearing from your competitors other operators in the region, what's the sense you are hearing with your ear on the ground in Venezuela in terms of activity levels?

Well, in terms of the impact to the company, the $30, $50 million predominant part of that is in upstream E&P.

In terms of what we're doing in working with our companies and what's taking place in Venezuela, of course, it's a rather fluid situation and I think everyone would very much like to see the situation resolved.

I don't think I have any more to comment on that.

We obviously work closely with our partners and companies in Venezuela but I don't think I have anything more to add in that regard.

Okay.

Thanks.

We'll now move on to Paul Ting from Salomon Smith Barney.

Hello, gentlemen.

Two questions, please.

I hate to ask you another Venezuela question, but just by way of clarification- You mentioned in response to a question that you should be able to run well 1 to 1 1/2 months.

I do translate that to mean you are going to be able to -- [ audio cutting out ] Within a month or month and a half?

What we were trying to say, when I say run well, what I'm really trying to say is it's going to take us -- it would be a slow startup.

It's going to be very sequential.

Take us quite a while.

Don't expect us once we start seeing Petros Zwaida, or Hamaca starts up, that's it's going to be at full capacity.

It's going to take us a good one to two months to get it up there.

That's what we are really trying to communicate.

It's gonna be a slow process, and day by day, week by week, but to get really back to where we were early late November, and early December, from the time you start, assuming all the feed stock and assuming the utilities and the gas is available to us?

It's going to take us, it's going to takes the better part of, you know, 1 1/2 or 2 months.

So technologically speaking, you will be able to get back full speed within 1 1/2, 2 months or so?

That's what we think.

Okay.

All right.

Switching gear on the downstream, I know you are wanted first companies to announce the shift from MTBE into F9 in California. [audio cut out] Calif - the market is extremely week.

Is that related to any kind of disruption?

No.

And also, do you have any data which would shed some light on how much of the industry has converted to ethanol already?

I don't know if we know much more than you do, Paul, on that.

Yourself, are you fully converted?

We are fully converted.

We fully converted I guess in the fall of last year.

Last year.

So we were ahead of the game.

I don't really know if there is a direct relationship between the shift from MTBE to - and the impact that would have on downstream margins.

I know you have had some imports into the West Coast pick up out of Asia.

And obviously, A&S prices have gone up quite a bit and that you know, you might not be able to pass that on.

In the marketing end of the business.

So that may contribute to it, as well.

Great.

Thanks a lot, guys.

Matthew Warburton from the UBS Warburg.

Please go ahead.

[INAUDIBLE] Jim and Clayton.

A couple of questions on the upstream and downstream if I may.

Firstly on the upstream, if you look at the Canadian gas production sequentially, it's down 14 percent.

Obviously you did highlight in the analyst meeting that you expected to starve that business of cash.

Is that a sort of, you know, regular decline where we should apply some production levels going forward or... other factors that are really influencing that very sharp decline?

I think, really, Matthew, it's a combination of both asset sales and decline rate and I'm not sure I've got that split.

But I know that we have been pulling capital back from that part of our E&P operation.

The short answer to your question would be no, that is not a normal decline rate.

And then, on the downstream the tax rate on the international side obviously high because of the losses.

Is that also a function of the absence of Humber because I think were you getting tax credits for the early introduction of low sulfur fuels.

That's a good question.

We'll just -- I don't know.

We'll come back on that one.

All right.

One final tax one if I may.

Looking at the Petros Siswada income, obviously you have a fairly sizable tax credit in the details you have given.

Is that just simply a function of the tax holiday that you get I think it's for the first nine years of production or is there anything else going on there?

I think you're right.

I think that's all that's -- I think it's just the tax holiday.

I don't think there's anything more.

Right.

Okay.

Thanks very much.

You bet.

We'll now move on to Paul Ting from Lehman Brothers.

Hi, gentlemen.

Good afternoon.

Several quick questions.

On the 600 million upstream market sell is it all relate to the Lower 48 properties, if not how much is relate to the other properties in other regions?

I think the biggest part of that was the sale in the Netherlands.

And we haven't disclosed precisely, but that's the majority of that 600 million is the Netherlands sale.

So the majority is the Netherlands, then.

Correct.

What's the production there?

It's about 12,000 barrels a day.

Uhm...

Clayton, when you guys switch over to the [INAUDIBLE] gasoline, is your production [INAUDIBLE] have any impact that has been reduced as a result of the phase-out of the MTBE?

You're asking if as we switch over to carb gasoline as we move away from MTBE, is our capacity reduced on the West Coast?

I don't believe so.

But I could check on that but I don't think so.

I don't think our capacity is impacted.

[INAUDIBLE] So you -- you are producing the same amount of gasoline (indiscernible).

I'm assuming that but let me check on that to be sure.

Okay.

I know this is going to be a little bit premature on Venezuela, at what [INAUDIBLE] with the current crisis is going to have a significant impact on the [INAUDIBLE] for the Hamaca upgrader as well as the Cora Cora... or is that they already have a impact that's going to be delayed?

You're asking if - at what point does the current shutdown have an impact on the startup of the upgrade or -- (indiscernible).

I think on the Hamaca project you can expect that for every day that we have the shutdown in Hamaca -- in Venezuela, is another day of deferring when that project is completed and starts up.

So it's pretty much certainly going to be a day for a day and it probably will lead to some additional costs.

In terms of Coro Coro, it's going to be deferred or delayed because we were working on sanctioning the project.

Now, so, you know, it's going to have some delay.

So far we're look at a little over a month at this point in time until we get other things sorted out and things get back to normal in Venezuela.

So, yeah, it's going to have an impact on sanctioning and startup of these projects.

Two last questions.

One on the 31 million [INAUDIBLE] you put in for discontinued operations related to [INAUDIBLE].

Is that related to the entire 80% [INAUDIBLE] that you're going to sell or is this just a portion of that?

And secondly on the midstream operations, I'm wondering if you can just share with us any kind of earnings sensitivity to the changing natural gas price or oil prices in that division?

The first question, Paul, I'm not sure I got the question on the size --

In the fourth quarter, your operating profit is $747 million for the corporation but on top of that you have another $31million that you earn that you (indiscernible) put as discontinued operations.

That's right.

Related to the asset that you held for sale.

Correct.

My question is, if that $31 million is the total earning from the 80 percent site that you decide to sell or that this is only a portion --

No, that's --

If it's only a portion, then what is the actual earning for the entire operations that you intend to sell?

No, on the -- as far as the earnings from our retail assets, for the quarter, that we intend to sell we're $31 million.

Okay.

So that's the entire thing?

That's correct.

Excellent.

And how about in the midstream?

Any sensitivity that you would be able to share with us?

We really don't at this point have sensitivities on midstream.

Can't give you a good explanation on why, uhm, earnings were -- were, uhm, up other than the fact that NGL prices did improve during the period and, of course, we had more volumes that came from Conoco's midstream operation.

Is that something that you may be able to give some guidelines to us?

I think we can.

Okay, thank you.

You bet.

We'll now move on George Gasparre with Robert W. Baird and Company.

Yes, good afternoon to you, Jim and the rest of the ConocoPhillips management team.

My first question is on Alaska.

Looking at the total output of oil in the fourth quarter versus the fourth quarter previous year, it appears to be declining there of about 23,000 barrels a day.

My questions is, what is Alpine make - what did it make up in the fourth quarter of this past year versus the previous year?

I guess looking at the 2001 Alpine production average 58,000 barrels a day, and in 2002, that number was 63,000 barrels a day.

So looking at 5,000 barrels a day.

Okay.

I understand I saw a report just in the last 24 hours that Alpine production may have hit 114,000 barrels a day on January 1 in gross.

With that a possibility, or a reality, what might you be looking at for 2003 from Alpine as a part of the total in whatever that total is, maybe you could share that with us?

I'm not sure we have Alaska production broken down by field and obviously would you expect the rates to be higher at this time of year because of the temperature in Alaska.

But, you know, we look at Alaska production forecasts and the objective there is to keep it flat at 375 to 400,000 BOE per day.

But I'd also say that Alpine is a field that seems to be getting better than what we initially always thought it was a good field and becoming even better than we thought.

And we're also putting in place some capacity to handle more gas so, you know, we feel good about our opportunities of, you know, holding or increasing our production from Alpine and satellite fields around Alpine so you know, this is a really positive development for us up in Alaska.

Okay.

Secondly, Jim, the comment that you made on the measurement, maybe you've answered this already, but I want to clarification.

The $1 per barrel equals $180 million on a per year basis?

Is that considering Venezuela up full or is that exclusive of Venezuela?

Can you just clarify that?

I think that number is based on our production forecast.

Probably based on 2003 which includes Venezuela.

Right.

And -- and you would be assuming Venezuela at it's normal operating rate?

Yes.

Okay.

And another question on Venezuela.

This restart process considering the low gravity crudes and so on and potential coagulation that's developed because of shutdowns, do you see additional significant oil service cost additions to try to get back up to previous production levels?

Well, it's going to cost to us get things going and all but I don't think it's anything more unusual than would you think -- no, I -- yeah, obviously we're going to have costs to get going and starting up.

But no, George, I don't think there is anything so unusual or significant that we need to be telling you that you need to factor in it's going it be a surprise in our announcements in future quarters.

Okay.

Now a question on refining.

In terms of the changing crude slates, due to the Venezuelan outage and the scrambles for other crudes that would allow the slate to be run, is there the possibility that as oil majors, refiners move to get other crudes in, that this could be shortening the catalysts' viability and potentially putting turnarounds at a faster pace?

I guess it could.

But talking to our refining and marketing people, they haven't voiced this as a concern.

They were just looking what they feel is an alternative crude.

It's not optimum, but I haven't heard from anyone raising too much of a concern if we run too much of this crude or that crude, is going to really adversely impact our crude runs and our turnaround costs.

It probably has an impact but I haven't heard it a concern.

Okay.

And lastly on this disposition of retail, it may you mentioned-- how many stations are involved in that?

We have said that we have about -- in total company operated stations, it's about 2500 and we said about 400 to 500 will remain after we finish the disposition, so I guess it's somewhere around 2,000.

Okay, thank you.

I think you know it's pretty close to time here.

I don't know if there are any other questions lined up or maybe we just take one more.

We could take one more.

We have Mark Flannery with CS First Boston.

Hi.

I would like to know on the disposal program on both the upstream and downstream side why is it going to take so long for us to start to see these things come through?

So on the upstream side, the announcement was made on November the 22nd, so presumably disposals data rooms are open and that kind of thing.

Is there any particular reason why the second half of the year is when we're going to see that?

It seems like quite a long time.

Well, it's a fair and a correct question.

What I was really trying to respond as we expect to be selling assets through the year.

But I think some of the things we have in mind might be a little larger or might be a little more take us more time to do because they -- they are either partners or whatever.

So I was merely trying to give indication that more of the asset dispositions would be in the second half than the first half t doesn't mean we're not working on and will accomplish some of these dispositions in the first half.

Okay.

So we should expect to see some announcements as we move through the year just weighted more towards the second half?

That's right.

On the downstream disposal, then, would you -- getting rid of 2,000 stations roughly is what's going on.

How do you see that shaping up, Jim?

Do you think that's going to be a series of small deals?

Is there any possibility two or three big deals?

I know it's difficult to comment but how does it look right now?

Well, I think it's probably premature for me to comment and it also relates then to what is our strategy regarding disposition.

I want to you know that what our objectives is you get the absolute best value that we can for the assets and do it as efficiently and quickly as we can.

I mean, those are the objectives.

Now to go further, and just who and how and what I think gets into our competitive strategy and I'd rather not comment.

Okay.

But we should expect to see -- we should not expect to see anything until, what, the third quarter or something like that?

What I said is for us to act on and do this, our plans are, because this takes time, uhm, I mean, we're working on -- having working on it for the last several months.

But this is something for guidance purposes don't expect this to be done until the latter part of the year.

Okay.

Great.

Thanks very much.

Great.

Well, uhm, we certainly appreciate your interest in ConocoPhillips.

And additional information and a replay of this conference can be found on our website that's located on www.conocophillips.com.

And we certainly appreciate your participation.

Thank you.

That does conclude the conference, everyone.

We thank you for your participation.