康菲 (COP) 2003 Q4 法說會逐字稿

Welcome to the ConocoPhillips fourth-quarter earnings release conference call.

Today’s call is being recorded.

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

Please go ahead, sir.

Thank you.

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

I’m joined today by Jim Mulva, our President and CEO, and John Carrig, Executive Vice President of Finance and CFO.

Following Jim’s comments, both will be available for your questions.

During today’s call, we will be referring to slides which will help us describe fourth quarter and 2003 performance.

These slides are available on our Internet site and will be useful to have in front of you during today’s call.

I also need to remind you that during the call, Jim’s prepared remarks and in response to your questions, we’ll be making forward-looking statements and these could be materially different from the actual results which we achieve.

And a list of the items that could cause these potential changes can be found on our filings with the SEC.

So with that said, I’d like to introduce the President and CEO of ConocoPhillips, Mr. Jim Mulva.

Clayton, thank you, and I appreciate very much all those who are participating in our call and demonstrating the interest in our company.

I’m going to move immediately to page 3, the highlights, and I’ll start with comments on page 3.

With respect to our upstream exploration and production, we ran pretty well in most of our locations.

We produced 1.61 million BOE a day.

That’s about 50,000 barrels a day more than last quarter, and this is in spite that we’ve lost about 20,000 barrels a day from operating interruptions at some point in time during the fourth quarter in Alaska, Venezuela and Indonesia.

Also our E&P production was affected by asset sales in the fourth quarter.

And of the assets that we sold in the fourth quarter, at the time they were sold, they were producing about 22,000 BOE a day.

We produced more natural gas in the fourth quarter of 2003 than the third quarter of this year and the fourth quarter of last year.

With respect to downstream, we ran our refineries at 94 percent of capacity.

We could have run even better.

We had some unscheduled downtimes and significant turnarounds with respect to Humber refinery in the UK, our Alliance refinery in Sweeny in the U.S., and this had a negative effect on our refining and marketing earnings.

And I’ll talk more about that a little bit later.

During the fourth quarter, we were able to reduce debt a little over $900 million.

So we’ve reduced our debt about $4.8 billion, during this year of 2003, to $5.5 billion, since the merger was consummated.

And this includes bringing on some amounts as a result of accounting changes over this past year.

We also completed asset sales of $3.4 billion since the merger closed, and we expect to complete another $1 billion in 2004.

So I’m moving now to page 4, which is entitled Total Company Income from Continuing Operations.

And you can see the sequential comparison of the fourth quarter to the third quarter.

Income from continuing operations, $985 million, and that compares to $1.25 billion in the last quarter.

We realized significantly weaker refining and lower marketing margins, somewhat offset by greater upstream sales volumes and higher realized prices for oil and gas.

The fourth quarter turnaround exploration expenses had the effect of reducing earnings $82 million more than the last quarter.

And then the third quarter E&P earnings benefited from gains in asset sales which did not occur in the fourth quarter, and then that results, for comparison purposes, a negative variance of $87 million from one quarter to the next.

Our discontinued operations contributed $36 million in the fourth quarter.

I move now to page 5, Total Company Cash Flow.

Our cash flow in the fourth quarter was strong.

Cash from operations, including working capital charges, amounted to just a little over $2 million.

In addition to cash from operations, asset sales generated $1.16 billion in proceeds.

This primarily came from our Circle K divestiture and then we had some E&P asset sales, primarily Ecuador, to a lesser extent small properties in the UK, lower 48, Canada.

Capital expenditures and investments, $1.77 billion.

Paid out $292 million in dividends, with some other items that increased the use of funds by $152 million.

And then this resulted in debt reduction about $960 million.

I’m moving now to page 6.

You can see in the pie chart on the left, it shows the total cash available in 2003 was about $12 billion.

So somewhere near about 22 percent came from asset sales.

Now the right-hand side of the slide, our capital expenditures for the year was $6.16 billion; pretty much right as expected, so –

Then if you look at the other uses of funds – at reduction, dividends and others – nearly 50 percent of our total funds generated was spent on debt reduction and dividends.

I’m moving to page 7 now, the improvement in our balance sheet and our debt ratio.

So as a result of the strong earnings during the year and the cash flow and our discipline on capital spending, we’ve made significant progress of reducing the debt and strengthening the balance sheet.

You can see from the bars on the left-hand side of the slide, our equity has increased to $35.2 billion, and our debt- now is down to $17.8 billion.

So this resulted in improvement of our overall debt to-capital ratio by a few percentage points in this past quarter.

But if you look at the end of 2002 into the – or end of 2002 and beginning of 2003, in the past 12 months, the end of 2003, our debt reduction’s down about 9 percentage points.

I’d like to move on from this consolidated view – and I’ll start looking more towards the upstream and downstream on the corporate side.

So first on slide number 8 regarding exploration and production, during the fourth quarter our E&P business produced higher volumes than in the third quarter.

And this comes from seasonality of our production.

We brought on increased production at Vietnam, and we have better operations in the North Sea.

Our crude prices were up 24 cents, to $27.24 a barrel, and our realized natural gas price was up 27 cents, to $4.07 per MCF.

Exploration charges were $70 million; were up $79 million over the third quarter.

And this comes from higher dry holes and lease impairments.

But the total for the year of exploration charges, $601 million is in line with what we told you several weeks ago on our interim release.

Now the upstream earnings benefited from international tax benefits, primarily lower taxes as a result of change in tax law in Canada.

I’m moving now to page 9, production for the fourth quarter, and you can see the sources of our E&P production improvements.

In the North Sea, both UK and Norway had significant increases in natural gas production.

This comes from seasonality and lower maintenance activities.

Combine the North Sea region, increased gas production 192 million cubic feet a day over what we had in the higher period of 1.26 billion cubic feet a day.

Alaska production benefited from colder weather and less planned maintenance.

And again, this is after considering, you know, we had some downtime as a result of interruption in production at Alpine.

The oil lines benefited from new production coming from Vietnam.

And then compared to the fourth quarter of 2002, our BOE production fell less than 1 percent.

So this, putting this in perspective, this small decline is, we believe, is a good accomplishment given the fact that we sold about 3 ½ percent, or 55,000 BOE a day, of our production since the merger was consummated.

And then I previously mentioned that we lost 19 to 20,000 BOE a day because of operating interruptions in the fourth quarter coming in Alaska, Indonesia and Venezuela.

Let’s now go to page 10, E&P Income from Continuing Operations.

If we look at the sequential comparison, you can see that our income from continuing operations increased somewhat, 2 ½ percent, to $991 million in the fourth quarter.

We had somewhat higher-realized oil and gas prices.

That helped us $63 million.

The change in crude oil market prices was not a hundred percent realized due to lighter sweet and sour differentials and impacts on pricing lags.

And this is primarily the result of Venezuela, to some extent what happened to us in Alaska, and the lower 48.

The increased production sales volume increased our earnings about $45 million.

So all this combined – price, volume, improvements – added about $108 million over – compared to the last quarter.

And you can see the higher exploration expenses and lower asset sale gains.

That more than offset the improvement coming from somewhat higher prices and volumes.

And then we had somewhat higher reserve charges, DD&A, about $40 million in impairments.

So I’m going to move now to page 11, the downstream part of the company, refining and marketing.

As I said earlier, the results were lower worldwide.

Our realized refining margins fell both in the U.S. and internationally.

In the U.S., our crack spreads fell nearly 13 percent, to $5.58 a barrel; and internationally they fell about 18 percent, to $3.61 a barrel.

Marketing margins fell both in the U.S. and internationally in the markets that we operate in.

Domestic marketing represent about 12 percent of our total U.S. downstream performance of refining and marketing; so essentially, nearly close to a little bit less than 90 percent came from the refining side of the company.

Overall, our refineries ran reasonably well in the fourth quarter, but we could have done even better.

Our Humber refinery in the UK had a very large turn- around, and then we had problems getting back up to full capacity.

This resulted in additional maintenance charges.

And as a result, if you look at the fourth quarter, Humber generated a small loss instead of a profit in the fourth quarter.

From a summary perspective, as we look at the downstream, the higher operating costs – primarily for utilities and turnarounds – reduced earnings by nearly $100 million compared to the prior quarter.

And if you break that $100 million down, there’s nearly $30 million in turnaround costs, increased turnaround costs, $13 to $20 million increased utilities, and then $35 million relating to environmental accruals, projects that we discontinued, and then there’s $18 million related to the UK.

Now I’m moving to slide number 12, which talks and goes through a waterfall chart of refining and marketing income from continuing operations, and you can see it was $202 million.

We’re down $283 million compared to the third quarter of this year.

Reductions primarily lower realized crack spreads or marketing results and increased costs.

We also had lower capacity utilization, and that hurt us about $20 million comparing one quarter to another.

As I said, higher turnaround activity reduced fourth-quarter earnings by about $29 million, and then we had utility costs, environmental accruals and other things, compared to the last quarter.

Now as I said earlier, downstream earnings could have been higher and we think by, you know, maybe $35 million due to the opportunity loss of the extended downtime at our Humber refinery, and maybe about $10 billion in lost opportunity costs by not being up to capacity at Alliance refinery in the Gulf Coast.

Now I’m moving on to page 13, corporate side.

Our corporate costs, excluding earnings from discontinued operations, were $238 million cost in the fourth quarter, and that’s higher, $15 million higher than the last quarter.

Now our interest expense, net interest expense was higher caused by the premium we paid on early retirement of a higher coupon debt.

So we obviously expect to see reduced interest expense going forward, and these charges offset the lower interest expenses.

Market-to-market accounting and certain employee compensation benefits increased our compensation costs.

Now I’m moving to page 14, which gives more of a breakdown of the corporate costs.

And you can see that the losses amounted to $238 million in the fourth quarter.

That’s $58 million higher than when we talked and said we thought we’d be close to about $180 million in the quarter.

Now our net interest expense was $163 million; up $29 million from the last quarter.

But included in the $163 million, $34 million cost associated with the early retirement of debt that I just talked about a moment ago.

Merger-related costs were $40 million.

Now that’s about flat with the third quarter.

So the merger-related costs didn’t go down as we expected.

And it’s, again, a one-time settlement and transition cost.

The gain of $16 million in Other was driven by a $46 million foreign exchange gain offset by higher compensation costs.

Discontinued operations contributed a positive $36 million to reported net income.

Now with respect to the first quarter of 2004, we expect our corporate costs are going to be at or probably somewhat better than $200 million.

Now I’m moving on to page 15, which is Synergy Capture.

During 2003, we captured close to $1.31 billion in pretax synergies, and about $150 million in capital synergies.

And we estimate that the after-tax impact of that is about $654 million in earnings.

It’s made up of reductions in operating and capital costs, as well as income-enhancing items.

The fourth quarter, the increase in synergies came from an improvement in income-producing activities or enhancements.

As we described last year, the methodology we use to – we use externally reported figures and then we make adjustments for prices, margins and operating conditions.

And the baseline adjustments include the effective lower- dollar purchasing power, the higher utility cost, merger-related items, in order that we can compare apples to apples and make valid comparisons to demonstrate the synergy capture.

And these adjustments and amounts are shown in Table 1, the attachment to these slides.

Now let’s go to page 16.

To really evaluate the business improvements resulting from synergy capture, we compared the $1.7 billion of income baseline of 2002 against $4.6 billion in 2003.

And so you can see on this slide that $2.68 billion is added to the $1.7 billion, and that is really adjustments for the higher oil and gas price and crack spreads that we realized in 2003.

Then we adjust for asset dispositions, downstream energy costs, merger costs and other items so we have a valid comparison.

Without these adjustments, it’s kind of difficult to really show and demonstrate the impact of reductions, costs reductions and synergies that come from income enhancements.

But after you make these adjustments, you can see the synergies, $654 million of after-tax benefits.

And again, this comes from cost reduction and income enhancement.

So let’s go to page 17, and we talk about our synergy capture, and we demonstrate this.

We show it had a earnings impact of $654 million.

And if we use a tax rate assumption of 50 percent, that grosses up to $1.31 billion before tax improvements.

And the $150 million of capital synergies, we add that to the pretax amount.

We get the $1.46 billion, which is we see as our run rate at the end of 2003.

So the question you might ask is: Well, are these capital synergies, $150 million, are they recurring or permanent?

And we believe they are, because they relate to the benefits of procurement has with respect to our capital spending program, and we also see a permanent benefit as a result of lower exploration charges by which we conduct our ongoing exploration program.

Now I’m moving to page 18, which is our ROCE improvement, which is a fundamental strategy and objective of the company, and we’re focused on it and we’re moving over this year and several years into the future to close the gap between ourselves and our performance and our adjusted ROCE compared with the largest companies in the industry using normalized assumptions.

When the merger was completed, our baseline mid-cycle ROCE adjusted for purchase accounting was 7.1 percent.

So during 2003, we’ve increased our adjusted mid-cycle ROCE by 2 percentage points, to 9.1 percent.

And this is, you know a, 28 percent improvement over where we were a year ago.

So using the 2003 actual earnings and adjusting for purchase to pooling, our ROCE is shown on the right-hand side of the slide, 15.7 percent.

Now we don’t have a direct comparison with the largest companies in the industry because many of them have not yet reported their fourth-quarter results.

Yet we believe our 15.7 percent will compare competitively with the largest companies in the industry, and it’s also based on not only our performance in the fourth quarter, but because we’ve compared favorably with them for the first three quarters year-to-date.

Now let’s go to page 19, Total Shareholder Return.

We had a good year in 2003 based on our operating performance, took advantage of the market conditions, and we strengthened our balance sheet.

Made a lot of good progress improving our return on capital employed, growing our upstream business, increasing the contribution and value coming from our downstream business, developing our commercial business in a way that it enhances the value creation of our commercial operations in trading around our assets, and also the reduction that comes from all these things of reducing our debt and improving our balance sheet.

In terms of asset sales and synergy targets, I think they’re being met.

And as we begin 2004, we’re very focused on creating value for our shareholders through basic discipline and following our strategy.

Our 2004 operating plan that we discussed with you in New York, our operating plan is in place and is developed for all of our business units and our staffs to ensure that we meet all the corporate and business unit objectives that we shared with you back in November.

So that, Clayton, really concludes the prepared remarks, and I think we’re ready to take whatever questions our participants have of us at this point in time.

Sounds great.

If we could line up a few questions, I think we’re ready to start.

Melinda?

Gentlemen?

Yes.

We’re ready for the questions.

Thank you, sir.

Today’s question-and-answer session will be conducted electronically.

If you would like to ask a question, please press “star” 1 on your touch-tone telephone.

Also if you’re on a speakerphone, please remove your mute function to allow your signal to reach our equipment.

Again, that’s “star” 1 if you would like to ask a question.

We’ll pause for just one moment.

And our first question will come from Gene Gillespie of Howard Weil.

Jim, since the Shell reserve revision and the controversy surrounding that, there’s been a lot of focus upon the reserves booking process.

And I’d like to have your comment as it relates in general to how you guys go about it, if you feel very comfortable with how you’re doing it now, any reason to change anything going forward.

That’s number one.

The second part of that question is: Can you give us some idea of 2003 reserve replacement and finding cost experience?

Okay, Gene, thank you.

It’s obviously a very pertinent question, and I’m going to direct my comments to ConocoPhillips, because that’s really the only company that I can properly comment on.

With respect to the booking of reserves in our company, first of all, we do not book any reserves of a project unless it is approved by our management and our board, and it also has to be approved, the project, by our partners as well as all of the government entities.

So we don’t book anything until projects are totally approved.

We also follow a very centralized process which we have in place, checks and balances.

What we do is, we are rolling 12 months.

Every property, every lease that we have in the company is evaluated by an independent group, independent reserve group that works for the company – our own employees – but it’s not part of the operating side of the company.

So on a rolling basis, every lease, every project and property gets reviewed every 12 months.

And then if we – even more frequently if we have reason, for whatever reason, to adjust or look at our reserves.

When we put the two companies together in the merger, they had essentially a similar approach to handling of reviewing reserves, and we continue to follow that.

If you look over the last 10 years, we’ve had very modest changes.

If you look at it on the average, it’s 1.7 percent positive impact on changes in our reserves one year to the next.

And that really comes primarily, in my opinion, through exploitation technology.

And in terms of looking at our reserves, if you look at our approved undeveloped reserves, they equal about 30 percent of our reserve totals.

We think this reflects essentially a basic conservative approach to how we handle reserves.

So we’ve been following a very consistent approach.

That’s what I like very much is, nothing gets booked until it’s totally approved by all partners, by our board, as well as the government entities, and we just work on this every day of the year.

On a rolling basis, every lease and property is looked at.

Now in terms of reserve replacement for 2003, we’re going to be coming out with a media release in the middle of February, and we will more than replace our reserves, and we will do it at competitive finding and development.

And so since we haven’t really made acquisitions of any sizable amounts of reserves in 2003, it’s essentially coming through organic growth.

And that’s really what I’d have to say on reserve replacement.

Thank you, Jim.

Thank you, Mr. Gillespie.

Moving on to Paul Ting of UBS.

Good afternoon, gentlemen.

I have two questions.

One is, there has been a lot of writings in the public domain about Alaska natural gas; there’s some competing bids.

Can you bring us up-to-date as far as to where do you stand on that particular project and timing, any key issues of particular concern to you, et cetera?

If I’ve got this, you’re really asking a question about the Alaska gas project?

Correct.

Of course, you know, we’ve worked on this very hard over the last several years.

It is somewhat of a disappointment that the energy bill is not yet passed.

But you know, hopefully working with everyone that we do up in Washington, we’re hopeful that this will come back and maybe in the next several weeks or next month or two it does get passed, because there are three conditions that we really are looking, objectives that we need to be moving forth on the gas project, and that is: We need to have enabling legislation and that’s for the permitting process.

And that’s in the energy bill.

We need that part passed.

Second, we are working with the state of Alaska, we’re looking for fiscal certainty; whatever, we do in a project we want – you know, a $20 billion project, we’ve got to make sure that all the terms and conditions and the fiscal certainty related to it are nailed down, and we need an application, along with our partners, to start working on that process with the state of Alaska.

And the third thing that’s really important to us is risk mitigation.

We’re not looking for handouts or trying to enhance the effectiveness of the project by getting some kind of fiscal help, but we do need risk mitigation.

And we’re willing to look at how we can meet that or meet that objective, and that can come from different alternatives.

And we’re also not opposed to looking at other partners in the project to the extent that they, through their approach or whatever they do, can enhance and bring value to us as producers.

So that’s where it stands.

We’re very interested in it, but you know, we need the energy bill, and we also need to get good progress in our discussions with the state of Alaska.

Jim, is it necessary to have unified views come under three key producers in order for this project to go ahead?

Well, I think obviously on the salient, large points, it is important that we have a uniform approach towards it, and I think that’s what we’re working toward.

Okay.

Secondly, can you bring us up-to-date on Kashagan?

There are, again, a lot of writings about potential resolution of the difficulties.

Whatever you can share with us would be appreciated.

In terms of Kashagan, as I said, it’s probably, in the past, one of the largest discoveries in the last 20 years or so.

And as we see a lot of success in our exploration program, and the expectation and the excitement about Kashagan is just as sound and the expectation is high as ever.

We’ve been in negotiations, discussions with partners, as well as the authorities of Kazakhstan, to reach agreements on our development plan.

And I think we’re making good progress in that regard, and hopefully we’ll get that sorted out here in the next several weeks, next month or two, so that we can go forward with our development plan in Kashagan.

I would point out that when I made the comment to Gene Gillespie as it related to booking of reserves and our reserve replacement, my comment, we will more than replace our produced reserves in 2003.

We do not intend to book Kashagan in 2003, so – but we look at Kashagan probably as a 2004 booking exercise.

Lastly, did you book an incremental gas reserve from Alaska at all?

No.

In 2003?

No.

Great.

Thanks a lot.

I appreciate it.

Thank you, Mr. Ting.

Next we’ll here from Arjun Murti of Goldman Sachs.

Thank you.

Jim, at the time of the merger, you were pretty clear that doing another large acquisition or transaction was not a high probability in the near term.

You wanted to focus on debt reduction, synergy capture and such things.

And it sure seems like you’ve by and large achieved all those targets.

Can we assume that over the next 12 to 18 months the probabilities of something happening is probably greater than it was over the last year?

And then regarding Russia specifically, does the seeming change in the business climate there make it less attractive or does it actually make it more attractive given that stock prices and asset values have come in over there?

Thank you.

Well, Arjun, thank you.

First, we have focused all of our attention towards organic growth as well as, you know, disposition of assets that we said at the time of the merger and improving the balance sheet, and effectively whatever the market’s given us, some very good oil, gas price and crack spreads, we’ve taken that and applied it to accelerating our debt reduction.

Although we’ve dramatically improved the balance sheet and all, I would have to say that we haven’t changed our view towards acquisitions.

When you look at acquisitions of assets – and we’ve been asked about assets or publicly traded companies – when you see an oil price environment of $34 oil price and gas prices where they are, I see it’s less probable for us to be looking at doing something like that because – okay, if you look at the return on capital employed of buying assets and all, you’ve got to be pretty careful that you can pay too much.

So I think the probability of doing something like that is actually low and maybe even lower than it was going through 2003.

With respect to Russia – and not just only Russia, but also the Middle East – we’re looking very carefully at how can we, in the right way, participate in terms of where the reserves and the potential production are and how they fit into us strategically.

So we have a lot of interest.

I distinguish just buying assets or whatever that people would look at from a strategic direction of how can we participate in the Middle East and in former Soviet Union or in Russia.

Because I think that’s a different kind of participation.

And so we are working, and we’re evaluating different ideas there.

We have been working with Luke Oil with respect to how we can be working on possible participation of development of some properties up in the north.

But you know, those things take time and it takes a lot of work.

But, you know, as far as we view it, looking at strategic investments in the Middle East and Russia is something that makes good sense for us and hopefully we can come up, over time, with the right opportunity.

Jim, I don’t want to paint you into a corner, but it sounds like, if I’m hearing you correctly, the focus is more on, if you’ll call it, organic opportunities in Russia, you know, instead of partnering up on specific projects, if you will, rather than necessarily a big corporate-type transaction.

Is that fair?

That’s absolutely correct.

Thank you very much.

Thank you, sir.

Tyler Dann, Bank of America, has our next question.

Hi, Jim.

I have two areas of questions.

Firstly, just philosophically speaking, could you please talk about the $150 million of capital synergies, and if they’re not contributing to the bottom line earnings, where are they contributing?

And the second question I had is really on some of your key projects, such as the Hamaca upgrader, the Magnolia project, and also how Su Tu Den is tracking.

Thank you.

Okay.

I’ll comment on the second question that you have.

Hamaca project, we expect to bring up the upgrader in the latter part of 2004.

The project in Vietnam has come on – it really looks good.

We’re very excited about that.

And the third on Magnolia, I think I’m going to ask John Carrig, maybe you can update on that or talk about that, and also the question on synergies.

Okay.

Magnolia, I believe, is due to come onstream in the first half of this year, if I recall correctly, Tyler.

And that’s when it’s due to come on.

With respect to the capital synergies, these are not very different from what were – the people commented upon in other mergers, but they relate primarily to procurement benefits, certain best practices, as well as lower exploration costs going forward, and they would manifest themselves in lower DD&A, as well as lower exploration charges in future periods.

Magnolia is due, as I said, to come on in the first part of 2004.

I’ll have to get back to you on what the production would be from the Magnolia itself.

Okay.

So I guess to be clear on the capital synergy side, this is not necessarily stuff that has historically impacted earnings, but should be expected to in the future?

That’s correct.

And we review them as we’re covering them.

Thank you.

Thank you, Mr. Dann.

Next we’ll hear from Fadel Gheit of Oppenheimer and Company.

Good afternoon.

Just any comments on the local asset sale?

On the local –

The sale of the downstream assets –

Yes.

Actually Luke Oil and Sun announced that they acquired some marketing assets that we had packaged up and were working over in the last several – the last several months.

As you add the two together, our proceeds are about $450 million.

We think it’s a good package for us, it’s good for Luke Oil, it’s good for Sun.

What we’ve actually done is, what we sold was 104 retail outlets and 1,061 franchised and licensed outlets.

So it was made up primarily of franchised and licensed outlets.

So you have to take that into consideration when you look at the $450 million proceeds.

And we’ve broken up into two packages, because it fit better with respect to the potential buyers, what they wanted to do, it was their buy.

Instead of selling it in one package, two packages, we believe we achieved a better sales proceeds for the company.

Now we expect these transactions to close more than likely in the second quarter.

And since you asked the question, what we have left to do is – several hundred million dollars of our total program in the company, several hundred million dollars left of smaller assets in the downstream part of the company, the midstream, and possibly a small piece or two in upstream, and that will get us to the total billion that we said we were going to do this year.

So we’re off to a good start.

And then in total, that gets up, it’s about close to $4 ½ billion that we said we would do back in November in New York.

And then on a totally separate subject, Venezuela, can you give us your take on Venezuela right now, not only on your operations, in general?

Well, as I said, the upgrader on Hamaca is scheduled to come on in the fourth quarter.

We continue our production-wise – other than the interruption that I referred to in the fourth quarter, production-wise we’re doing quite well.

Operationally, everything is going well.

We monitor the situation very closely, we have the political situation, and we think from the indication it looks like they may very well have a referendum.

But – we obviously monitor but stay out of that situation.

Relationships are good.

As I said, the development of our new projects and existing operations continue to run smoothly.

Venezuela is a significant contributor financially to the company and ties in so nicely an integrated chain of feedstock into our downstream part of the business.

So we recognize the concerns, but, you know, wherever we go, this is usually some kind of challenge.

But Venezuela is an important country for our company.

Thank you.

Thank you, Mr. Gates.

Moving on to Paul Cheng of Deutsch Bank.

PAUL SINKEY.

Yeah, good afternoon, gentlemen.

We were impressed with your volumes for the quarter, but a little bit disappointed by your – can you hear me?

Yeah.

We were impressed with your volumes, but we were a little bit disappointed with your earnings and realizations.

And you mentioned that there were issues with lags in Alaska, you mentioned a possible heavy to light being an issue.

Could you give a bit more color on that?

Could you also, particularly with reference to the international realizations, talk about perhaps any foreign currency effects that there may have been.

And finally round off by saying whether you feel that there’s a secular weakening here in realizations or whether this was just one off course or where things were a little bit weaker than perhaps they have been in the past?

Well, on the realization side, we did experience the – what we experienced for the quarter was that the heavier products did not rise as quickly as the lighter products, and that manifested itself in what appeared to be a flat, relatively flat, realizations on the crude oil side.

For example, in the North Sea, even in the North Sea, where we have a lot of light oil production, we had a greater proportion from Hedron(?) and another field – which I can’t recall – that increased the heavy slate on the company’s production.

We mentioned earlier the ANS lag, and that’s a typical lag.

In the lower 48, we experienced wider sour differentials, as well as some location differential associated with our ERSA (?) volumes.

And in addition, we had the Venezuelan volumes, where pricing was down somewhat.

Turning to the foreign exchange effect, we had a gain overall in foreign currency, which is somewhat counter-intuitive with the weaker dollar, but it’s just a mix of some of the assets and inner-company obligations that we had that caused us to have a gain effect.

I would like to make one further comment.

I mentioned earlier that Magnolia started up in the first half of 2004.

It in fact is due to startup in the second half of 2004, late, towards the late end of 2004, and the plateau production is expected to be 41,000 barrels a day.

And just to refer to my question, there’s no evidence then of a secular rising cost trend or anything that we should be thinking about, and how are your costs developing over time from your point of view?

Well, we had some costs that we’d rather not see in the fourth quarter.

But we still feel that we are on plan and that the trend is as we predicted in our discussions at the analysts’ meeting.

Very specifically on Vietnam, is that a BULA (?) and oil-price-linked contract that will be producing?

I’ll have to – we’ll have to confirm that and discuss it with you offline.

I don’t recall.

Sure.

I understand.

And finally, Humber frequently seems to have some issues, if you like.

Could you talk about whether there’s a structural problem there or whether you’ve just been unlucky, or why we tend to see so many problems from that very highly-invested refinery?

Well, I believe we’ve got the Humber refinery back up near our capacity, and so I don’t think there’s a structural issue there.

It’s just unfortunate we had a scheduled – a very significant turnaround and then when we came up, we didn’t come up as quickly as we would have liked; it took us a few weeks.

And so I don’t think it’s a systemic kind of problem.

Sure.

Fine.

And finally from me, the mix between leased and owned on the sales that were announced yesterday of marketing in the U.S., could you give me a little more detail on that?

No.

I think – not really.

We pretty well told you what it is.

Yeah, Paul, it’s about a hundred owned and about a thousand that were not totally owned.

Thank you.

Thank you, Mr. Sinkey.

Next we’ll hear from George Gaspar of Robert W. Baird.

Yes.

Good afternoon everyone.

The first question is on your U.S. production deals for 2004 versus 2003.

If you could, is there any possibility in giving us some flavor on dividing of Alaska, Gulf of Mexico and onshore lower 48 as to where you may see your production on an average day, a day average basis, for the year versus last year?

Well, we look at the, what we call the “The Big Four Areas” – Alaska, Canada, lower 48 and North Sea – and we see those in the aggregate as more or less flat for the year.

You know, we’ve – consistent with what we had in our presentations here last November.

And we see those about flat.

Okay.

And secondly –

Hey, George.

Yeah?

I was going to tell you that I just want you to know that I’m just as strong and excited about Alaska as I was last quarter.

Okay.

Okay.

Good.

Secondly, if you were to line up the best sides exploration wells that you have in your focus for the first half of the year, or maybe even the year, can you outline them for us?

Well, I think you’d have to go back to –

Why don’t you go through that.

Yeah.

I guess, George, the ones we’ve identified in November were – we’ve got some wells in Southeast Asia around Malaysia and Indonesia, I think, that are of interest.

Of course, we have another well going – or two – going in the Caspian area, and then we have some drilling in West Africa that’s of interest, lastly, of course, we’re always doing something in VRA (ph).

So that’s probably – I think that’s probably the way we’d line those things up.

Okay.

And a question on the recent development last Friday of Minerals Management extending the federal royalty release to 2,400 existing leases in the Gulf for – in deep (ph) and drilling.

Is that going to encourage you at all to take a look at that?

Well, we know the area very well, and it’s a good move by the government to open up more acreage.

It’s something that we as a country need to be seeing.

So we’re encouraged by seeing the opportunity of looking at everything.

As I said, we know Alaska quite well, so obviously we, along with our partners, are going to take a good, hard look at it.

Okay.

And then lastly, on the ethanol side of the business for downstream, refining and marketing, how integrated are you across your domestic refinery stream, marketing stream, at this point with ethanol injected?

Oh, you mean – when you say “integrated,” do you mean do we have the opportunity to produce ethanol ourselves or do we make arrangements to have ethanol so that, you know, we’re not disadvantaged since we move, you know, all of our product into the marketplace?

Let me clarify.

What percentage of your volume that you’re marketing at the present time has ethanol in the gallon?

Well, we’d have to come back to you, but I know this, I mean, we kind of led the charge on the West Coast in ethanol, so that’s all taken care of.

Right.

On the West Coast.

And I guess we would have to really come back as it goes to the East Coast and –

Yeah, we could find out for you, George.

I know that we’re complying in Connecticut and New York, but we’ll find out.

Okay.

Well, and the other thing you need to know is, in no way is this holding up our ability to run our refineries at full capacity.

I mean, we have the infrastructure.

The fact that we’re converting and have different states have opt out – not “opt out.” It’s complex, and it’s difficult.

We’ve got all these different boutique fuels that we have to provide at different times of the year, different markets.

But, you know, the organization, the company, has the infrastructure and the capability that it’s not adversely impacting our ability to run at capacity to refinery.

Okay.

All right.

Thank you.

Thank you, Mr. Gaspar.

Next we’ll hear from Michael Mayer of Prudential Securities.

Hello.

Thank you.

I had two questions maybe.

When you were discussing the results in corporate, I didn’t quite hear what you said.

You referred to the $16 million in Other, and as I read the press release, there was a $46 million foreign currency gain in Other.

Was this – what reduced that figure from 46 to 16, is my first question?

Okay.

The thing that reduced the 46 to around 16 included a number of things, but the two main things were, in the second – in the fourth quarter, as we had in the second quarter of 2003, we had pension settlement accounting impact us.

That’s when you pass mechanical thresholds on your lump-sum payouts exceed your interest and service cost for the year, you have a cost.

And that was one of the items.

And the other major item was increased costs associated with variable accounting for certain of our equity-based plans.

Is that code for management bonuses?

No.

That’s code for variable accounting associated – what it is, is that the equity that’s previously been awarded but not yet vested has some – can have some market-to-market features associated with it.

That’s the variability in the accounting.

Okay.

And I believe you gave some guidance that you expected the corporate and other to be around $200 million in the first quarter?

That’s correct.

Do you have any comments on the full year figure?

I know it’s heavily impacted by the interest expense, but any –

I think we – you know, at the analysts’ conference, we mentioned that we thought it would be about 180 per quarter, and we said the first quarter would be 200.

You know, we’re going to be between 180 and 200, we think, each quarter for the year.

Okay.

So are you officially raising your guidance on that number?

No.

Okay.

My second question relates to your page 16, where you discuss the synergy capture.

Is it fair to take the two columns labeled Price Adjustment and R&M Energy Costs, net them together and make an estimate of what your earnings would be in your own mid-cycle case?

Yeah –

When I do that, it adds up to about $3.65 a share, which would imply that in 2003 your earnings would have been about $3 a share at so- called normalized prices and margins.

That’s consistent with what we had in the attachments to the analysts presentation, yes.

Okay.

Thank you.

I appreciate the answer.

Thank you, Mr. Mayer.

Paul Cheng of Lehman Brothers.

Good afternoon, gentlemen.

Several questions.

Jim, strategically, if you look at your downstream portfolio in Europe and Asia, first, Asia, you said, really cost you-all that opportunity.

You may want to (?) for Europe, do you think that you have the right mix between the marketing and refining, or that maybe you want to reduce your exposure on the refining over there?

Secondly, from a strategic standpoint, we saw you have sanctioned the project Surmont in the Canadian Oilsand.

But is Canadian Oilsand perhaps that representative in a bigger opportunity that you want to be moving more aggressively into that area, or you think that you want to go slow on that?

And then finally, with the Algeria LNG terminal explosion recently, have you experienced any more difficulties when you’re dealing with the local government trying to receiving their approval in discussion of building regasification terminals?

Okay.

Let me go through the questions that you have asked.

First, on the downstream with respect to Asia, we have a very small position in Asia made up of the Melaka refinery, and then we have marketing primarily in Thailand and I guess some in Malaysia.

It’s small in comparison to what we have in Europe, and definitely very small compared to what we have in the U.S.

The marketplace has not been particularly attractive in terms of financial return to us.

But here in the last several months, some interesting prospects are taking place with respect to a lot of demand and movement of oil and products through the growth and demand in China, which has resulted in far better returns recently in the crack spreads for the downstream part of Asia.

Now we’ve seen that.

Asia is a question for us is whether we feel we want to get larger or we want to get out, and we’ve been studying and looking at.

But like all positions that we have in the company, we will never part with any asset unless we get what we believe to be a full, fair value for, not what it’s worth today, but what it really potentially could be worth.

So I think as it goes to Asia, the study is still out there in front of us to determine what we really do.

But we do see some signs that the world’s changing, and so we just haven’t really made up our mind at this point in time.

Now in terms of refining and marketing mix in Europe, what we have in Europe, we like our position, and as the company grows and develops, the issue for us – or grows and develop the upstream side of the company, is then how does the downstream part of the company in Europe and in the U.S. fit into those plans?

Because we fully believe that the integrated company we can create a lot of value, not just in the upstream, but in the downstream.

We’re very pleased with our European position.

The issue is whether in some small way or smaller way we would like to enhance our position by moving out a little bit both as it relates to the refining side and to the marketing side.

I wouldn’t put this necessarily at the highest priority of the company, but I’m just trying to share with you that we’re looking at how does downstream fit in.

In Europe, it fits in very, very well with what we have today.

It contributes a lot to the company, but it can potentially contribute even more as we grow and develop the upstream part of the company.

The mix of refining and marketing, I think of the total company, we like our position of where we are.

There may be some small adjustments here or there.

But you know, we’ve essentially moved our marketing to a wholesale approach, and that’s done essentially in the U.S.

We’re going to be down now to about 300 to 400 retail outlets that we own, the rest is wholesale.

And we like that position.

Europe is a little bit different.

Surmont, we like Surmont.

We like the opportunity that we have.

We’ve announced that we are going forward.

I believe our other partners have given indication that they like the project as well.

But it’s not just an upstream project to us.

It ties into integrated to our downstream.

And so we think that with our properties upstream in Canada, we have the Diluent (?) and all that ties into Surmont, that we can then move that mix down into our refineries, say, potentially Wood River and maybe even Billings.

And so it helps us and supports us both upstream and downstream in an integrated way is really nice.

So we like Surmont; it fits in well.

Whether there are other opportunities like Surmont, we’ll always be looking for.

And then we come into – I guess the question had to do with LNG.

As you know, we’ve announced here, just I think it was late in December, we’ve contracted 4 billion cubic feet a day at the Freeport terminal south of Houston, and we think that’s going to be one of the first ones that’s really permanent and up and running, and that ties into our basic LNG approach, is we want multiple locations by which we can win the LNG from Qatar, substantially a lot of LNG from Qatar, and then potentially in a lot of places like Venezuela, and Nigeria, or Russia.

And we like to have multiple terminals.

So Freeport is in there.

And then we would like to own, you know, one or two others ourselves directly, and that could be primarily in the Gulf Coast.

In terms of market reception and all to permitting, I think there’s a complete understanding certainly by the government and the authorities in business that we have a gas problem, we need to get the gas into this country, and so we need pipelines from the north, and we also need LNG projects to the Gulf Coast and the West Coast.

In terms of the Northeast, we were working up in Harpswell, Maine, and we’re getting some favorable indications and support community-wise to have that potentially as a terminal for us up in the Northeast.

So the Algeria situation causes certain questions, but I think there’s an understanding, a good understanding, that the way the industry does the business and how we will bring LNG into the U.S., that yes, we have an education issue for all of us and for the consumer.

But I think it’s full speed ahead for the industry and for our companies on LNG.

Excellent, Jim.

Jim, can I ask one final question?

On the capital spending, I presume your budget is probably much lower than what is the current oil and gas price.

In the event if the year the oil and gas price is going to be much stronger than your budget, will you raise your capital spending, or are you just going to use it to further pay down the debt?

Well, our point, we put in everything that we really want to do, and it’s a $6 billion capital spend, cash capital spend for 2004, and our basic approach of 2004 is to park it at a $34 oil price.

Whatever the market gives us, we’re going to stay at $6 billion capital spend, and so we will accelerate debt reduction.

The other thing that we like and what that will lead to is we need our objectives in terms of probably debt ratio at 30 percent or a bit less than 30 percent this year.

I mean, if these kind of prices hold out, we’ll back off some.

But if they hold up, you know, $25 to $30, we’re going to meet our debt-ratio target.

But we still think the absolute level of debt is too high, and so we’ll continue to bring the debt down.

But we are not going to be looking towards immediately looking for how we can expand the capital program.

We’ll accelerate debt reduction.

We like the idea of modest annual increases in dividends, and certainly we like a better share price.

But, you know, at some point in time, if we get in a position – and we’re not there yet – we can always look at some modest- to-modest share repurchase.

Thank you.

Thank you, Mr. Cheng.

Doug Terreson of Morgan Stanley.

Good afternoon, guys.

Jim, I just had a question.

You guys have obviously done pretty well with your divestiture program in R&M, which was pretty central to attainment of your overall return enhancement objectives.

And with the announcement of the Mobile stations today, I believe you should be over your target of $2 billion in proceeds.

And so my question is whether or not that sales program is complete, and if not, what assets are left and what amount of proceeds do you expect to receive from them?

And just secondly, you guys had some pretty significant developments in your gas business last year, your global gas business.

And so could you kind of give us the update as to what the next steps are for a couple of those key projects, such as Qatar gas, and also the Brass LNG project?

Okay.

First, the question on asset dispositions, we’re essentially, unless we have a unique opportunity of a slow asset to sell that someone really wants in the upstream, we’re essentially about done.

Not really on the upstream side.

On the downstream side, Doug, what you said is right.

What few packages that have been announced, we’ve substantially done – disposition.

What we have left is, I think it’s around $300 million of small – smaller marketing properties for one reason or another weren’t in the package that we’re kind of looking to take a longer period of time.

They’re dealers-type franchise operations.

That coupled with maybe a terminal or two, a few things like that, that we think is, you know, 2, $300 million.

And we have the midstream assets that we need to – that we haven’t sold yet that was part of the program and we’re working on.

And then, you know, at this point in time, we’re, you know, about 5 or $600 million to go.

Okay.

And so essentially what I’d like to say externally and say internally is what we’re saying certainly to all of our employees, we’re essentially completed our assets program.

Okay.

Now LNG are making good progress.

We’re working towards getting with Qatar.

We’re working towards reaching agreement, definitive agreements on the first train LNG from Qatar by this summer.

And that’s going well.

It’s going well in Qatar, and it’s going well with respect to we see regas facilities and in capacity here in the U.S., to tie in and meet with the schedule of what we’re doing in Qatar.

We continue to progress and work with our partners on a potential LNG from Nigeria.

Venezuela is something that probably we’re interested in.

It’s going to take a little more time.

In terms of Russia, frequently we see our name associated certainly with Gazprom and Rosnet about Russia in the Shtokman field.

That business is quite a bit longer term, as technical and commercial challenges, but you know, we feel it potentially has an opportunity.

But right up front is Qatar, and that project’s going well.

All these projects of multibillion dollars take a lot of negotiation and a lot of work.

Sure.

But on the other hand, you know, it fits right into our plan, working on bringing LNG from Qatar into the U.S. in 2008.

Okay.

Okay.

Thanks a lot, guys.

I think we’ve done about an hour maybe.

Maybe one more question.

Gentlemen, our final question will come from Steve Pfeifer of Merrill Lynch.

Right under the bell.

Hi, guys.

Just a couple questions real quick.

One of your competitors indicated some higher turnaround time as they get ready for clean fuels.

Could you just talk about the outlook for turnarounds, say, in 1Q and through the year for your refineries and Europe?

And then the final question would be on the retail.

Could you just talk a bit about, now that you’ve got those divestments largely finished and you look at the actual proceeds relative to what you had on the books, did you end up with, you know, a net gain or a loss on those?

Thanks.

Well, first on turnarounds, it’s a heavy year, very heavy year, and we’re not unlike other companies in the industry, it just happens that we have a lot of turnaround in maintenance, but it’s also tied into clean fuels, meeting the requirements.

And so it’s not only turnaround, it’s getting the facilities ready to meet all the requirements of clean fuels.

So it’s quite a bit higher than last year.

And Clayton, you’ll come on here in a moment and say what we expect the number is for this year compared to last year.

In terms of – what was the other question?

On the retail, the disposition packages, we feel we’ve achieved good value, that the provision we chose last year, we don’t expect – you know, we’ve had some – there’s lots of moving parts and we’ve had some things that we don’t consider material that, you know, that aren’t reflected in our discontinued operations.

But by and large, we expect to be at there or maybe out perform a little when it’s all said and done.

Steve, to help you out on this a little bit more than just what John said, is, in its entirety, we see no requirement for any further provision for all these assets that we have sold; and furthermore, we test very much, you know, the goodwill that the company has.

We test all of our businesses, and we see that there’s no requirement at all – and quite a bit of free board there, leeway there – of making any provision for writing off goodwill.

I think our turnaround costs we’re expecting to be 160 for the year with heavy, heavy Q1 and Q4 expenditures, and lighter in the second and third quarter.

Clayton might have the numbers for you.

Yeah.

To give you – this shows up in our – in the supplement, Steve.

This year we’ve spent $180 million on turnaround expense pretax, and we’re estimating next year to be about $170 million on an after-tax basis for the entire 2004.

And the first quarter is going to be about $65 million after tax.

So significantly higher than we expect this year.

And just for comparability, I use a 35 percent tax rate?

Yeah.

Use – right.

Use 35 percent.

Okay.

And that is, I assume, a cost of the actual around turnaround, or does that include the opportunity losses that –

No.

That’s just out-of-pocket costs.

No opportunity cost is included there.

Could you help us on maybe what an all-end number might be last year versus this year?

That really depends on the margins, I guess, assumptions you’re going to use.

We might have a chat about that.

I’m not sure – I’m not sure how to calculate opportunity cost going forward.

But maybe another way to think of it is that it’s about 35 percent more than last year in terms of run rates and things of that nature?

I think that’s about right.

– opportunity cost, you can’t run at a hundred percent indefinitely.

So the question is, there is the cost of the turnaround and there’s the cost of implementing clean fuels or new fuels requirements, and then really the opportunity cost is not meeting your schedule and being down longer than you expect against what the market gives you.

Of course, you know that.

But I think maybe Clayton can talk to you further –

Okay.

I’ll talk with Clayton on some follow-up.

Thanks.

Okay.

I think we probably need to shut this down if we can.

You know, we appreciate the opportunity to speak with you, and obviously the transcript will be found on our Web site, conocophillips.com, and we look forward to talking to you soon.

Thanks a lot.

That does conclude today’s conference.

We do thank you for your participation.

You may now disconnect.