康菲 (COP) 2004 Q4 法說會逐字稿

Welcome to the ConocoPhillips fourth-quarter earnings conference call.

At this time all participants are in a listen-only mode.

Later we will conduct a question and answer session, and instructions will follow at that time. (OPERATOR INSTRUCTIONS) As a reminder, this conference call is being recorded.

I would now like to turn the conference over to your host, Mr. Clayton Reasor, General Manager of Investor Relations.

Sir, you may begin.

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

I'm here this morning with Jim Mulva, our Chairman and CEO, along with John Carrig, EVP Finance and CFO.

During today's call we will be referring to presentation material which will help us more fully describe fourth-quarter financial and operating performance, and hopefully give you a better understanding of the factors that had significant influence on our results.

This presentation material is available on our website, ConocoPhillips.com, and will be useful for you to have during Jim's initial comments.

On page 2 you can read the Safe Harbor statement, which lets you know that in response to questions and in our prepared remarks we will be making forward-looking statements.

Actual results may differ materially from those we expect today.

A list of items that could cause these changes to occur can be found in our filings with the SEC.

So, that said, I would like to turn it over to the Chairman and CEO of ConocoPhillips, Jim Mulva.

Clayton, thank you.

I also want to welcome all those who are participating in our fourth-quarter conference call and taking the interest in our Company.

What I'd like to do is go immediately to page 3 of the slides that have been already sent out.

My comments relating to page 3 I will go through at this point in time.

We had a strong quarter in the fourth quarter.

We generated about 2.4 billion in net income, and 3.2 billion in cash flow from operations.

This allowed us to fund our growth programs, strengthen our balance sheet, and increase our financial flexibility.

For the last 3 months of '04 E&P produced 1.6 million BOE; that's up from 1.48 million BOE in the third quarter.

This was done in spite of the higher royalty rates that we recognized coming out of Venezuela; and our performance allowed us to deliver on our '04 production target of 1.56 million BOE a day.

We also achieved our target of acquiring about 10 percent of LUKOIL's outstanding equity by the end of '04.

Our share of LUKOIL's production was 150,000 barrels of oil equivalent in the fourth quarter.

As indicated last year we report net production and earnings using equity accounting under a separate LUKOIL investment segment.

I am going to talk about all these things a little bit later in the presentation.

Our realized crude oil and natural gas prices were higher in the fourth quarter than the previous quarter.

Worldwide our refineries ran at 94 percent of capacity, about the same as the last quarter.

Refining and Marketing benefited from wider light-heavy crude oil differentials.

We had solid strong international operations, and they contributed well to the financial performance of the Company.

Our adjusted ROCE was 27 percent for quarter, and we think that's competitive with the largest companies in the industry.

I'm going to move from page 3 to page 4.

Page 4 is titled Contribution and Capital Employed, and you can see in the two pie charts they illustrate how our major business segments performed in the quarter relative to their capital employed.

You can see that E&P generated 62 percent of our income from continuing operations and represented about 59 percent of capital employed.

Refining and Marketing generated 28 percent of fourth-quarter income and it was about 30 percent of capital employed.

If you combine Midstream and Chemicals together, they generated about 7 percent of income from continuing operations and represented about 4 percent of capital employed.

With respect to LUKOIL, they generated about 3 percent of our income from continuing operations and represented about 5 percent of capital employed.

I'm going to talk more about the individual segments' ROCE in the fourth quarter and for the whole year in a later slide.

So I'm now moving to the fifth slide, Total Company Net Income.

You can see it shows a sequential quarterly comparison, third quarter of this year to fourth quarter of this year, Total Company Net Income.

You see higher liquids prices, refinery margins, higher oil and gas field (ph) volumes all helped with better sequential earnings.

The estimated equity earnings from our LUKOIL segment was $74 million for the fourth quarter.

Now in developing the estimate of $74 million we adjust the LUKOIL estimated results for purchase accounting; we also have to make adjustments for hydrocarbon reserves going from SPE to SEC (ph) reserves.

So this is our estimate of the fourth quarter.

Even though we owned about 10 percent at the end of the year, on average we had about 8.5 percent of ownership for the fourth quarter.

Now if you look at the two items in red, 97 million and 90 million, we had increases in our DD&A, some inventory losses, insurance premium adjustments, and other costs that offset commercial benefits and lower exploration expenses.

Our discontinued operations had a loss of 48 million during the quarter, reducing net income to slightly under 2.5 billion.

I'm going to move to the sixth slide, Total Company Cash Flow.

You can see our cash flow from operations are about 3.2 billion in the fourth quarter.

Capital expenditures and investments were about 4.8 billion during the quarter, quite a bit higher than in the third quarter.

But this included our investment of approximately purchasing 10 percent of LUKOIL with 2.6 billion.

Although there were sequential increases in capital spending in both E&P and Refining and Marketing for the quarter, our total capital expenditure for the year was right on target.

That's 6.8 billion, excluding LUKOIL.

If you take the 6.8 billion and put it on a cash basis, it was 6.1 billion.

So we're right on target with what we had told the financial community.

We paid out $346 billion in dividends and reduced debt by a little less than 500 million in the quarter.

I'm moving to the seventh slide, Total Company Cash Flow.

On these pie charts you can see the Company's cash generation and utilization of cash in 2004.

On the left you can see total cash flow was about 13 -- or cash availability 13.5 billion; 88 percent came from cash from operations.

If you look at cash from operations, essentially at $12 billion.

The pie chart on the right shows our capital expenditures of 6.8 billion.

As previously mentioned this is in line with our spending plans and what we have for '04.

I think the difference, if you look at the 6.8 billion and then the money spent for the LUKOIL investment, that combined, compared to the $12 billion in cash flow, shows at least we have reinvested in the Company about 70 percent to grow and develop our businesses and grow our Company.

The balance of our cash flow was utilized for debt reduction and dividends.

As you know in the fourth quarter we raised our dividend by 16 percent.

Now I'm moving to slide 8, which shows the improvements in our balance sheet, debt ratio improvement.

We've improved this every quarter as we've gone through the quarters of 2003 and 2004.

The strength of our earnings and cash flows and our discipline on capital spending all have allowed us to make good progress.

We have reduced our debt, proven our financial flexibility.

The pie chart on the left shows that equity grew to 43.8 billion for the year; that's up 8.6 billion.

Balance sheet debt at the end of the fourth quarter, 15 billion.

So the debt ratio rounds to 26 percent.

I think it is interesting our debt was down 2.8 billion in the year.

Our cash balance -- this is another interesting point -- at the end of 2003 our cash balance was 490 million; cash balance at the end of December of '04 was 1.39 billion.

So if you look at the debt balance and adjust it for the net debt for cash position, obviously our ratios are even better than the 26 percent.

I'm moving now to slide 9 which looks at Exploration and Production in the fourth quarter against the third quarter.

Our worldwide production from quarter to quarter was up 112,000 BOE a day to 1.6 million BOE a day.

This increase was largely due to return to full production in Alaska, the North Sea, after we finished our scheduled maintenance in the third quarter.

And then we have some seasonality in our production from the third and fourth quarter.

We met our annual production goal of 1.56 million BOE a day in spite of the increased Venezuelan royalty payments and the sale of our Petrovera interest in Canada earlier this year.

Our realized oil prices were $40.96 a barrel in the fourth quarter.

They were $38.78 a barrel in the third quarter, so a 6 percent increase.

For the whole year our average realized crude price was $36.06 a barrel, up 31 percent from the '03 price realization.

Turning to gas, worldwide gas prices were up 15 percent from the third quarter to $5.13 in Mcf.

As we indicated in our interim update earlier in the month we plan to revise the reserves we have booked for our Surmont project.

I am going to give you more information on the Surmont project and the situation a little bit later in the presentation.

Also the impact of the change in the government royalty rate in Venezuela, that was 15,000 barrels a day.

This has been reflected in all of our production numbers and our financial results for the fourth quarter and for the year.

I am going to slide 10, our production from the fourth quarter compared to third quarter of this past year.

It just shows, as I indicated earlier, fourth-quarter E&P production -- this excludes LUKOIL production -- was up 7.6 percent fourth quarter to third quarter.

If you add LUKOIL production in, then we are up sequentially quarter to quarter by 18 percent.

If you look what has happened to us -- and again these numbers exclude LUKOIL -- this increase was largely as I said seasonality and getting our maintenance completed in the third quarter for Alaska, Norway, and UK.

In the third quarter our production numbers were 1.484 million BOE; and then we added during the fourth quarter 66,000 BOE for Alpine and Prudhoe in the fourth quarter.

UK was plus 25,000 BOE;

Norway, 30,000; and the impact of Venezuela is a minus 9.

The impact in royalty was 15,000; but as we ramp up Hamaca production the net effect was -9,000 BOE or 9000 barrels going from third to fourth quarter.

So when compared to the fourth quarter of 2003, and we adjust for the disposition of our Canadian participation in Petrovera, production in the fourth quarter of '04 was flat.

This is because we had increased production from Bayu-Undan, Viet Nam, and Hamaca that offset these other asset sales, and the natural decline in other fields.

When you add LUKOIL production of 150,000 barrels a day to our E&P production of 1.569 million BOE, our total Company production then has gone to 1.746 million BOE a day.

I'm moving now to slide 11, E&P Net Income.

Our E&P net income for the quarter was $1.7 billion; this is up 251 million over the last quarter.

The impact of higher realized commodity prices was around 235 million, of which about 96 million came from higher oil prices.

Realized prices for Alaskan crude increased $3.89 a barrel compared to an ANS spot price increase of 81 cents a barrel through this time period.

So this beneficial difference was driven by price lag and the contract mix that we have in how we sell our Alaskan crude.

Realized prices for natural gas, syncrude, NGL, and LNG were up as well; and this combined helped us 139 million in sequential increase from quarter to quarter.

Our total sales volumes were up 4 percent from 1.505 million BOE to 1.558 million BOE a day in the fourth quarter.

However, for the year our sales and production were essentially balanced.

Our pretax DD&A and impairments were up 128 million; that's 841 million versus 713 million.

This is due to increased production volume and impairments on Western Canada and Rensel (ph) assets.

After taxes amounted to about 72 million.

Our higher operating cost including insurance premiums were partially offset by commercial activity and foreign exchange gains.

All of these items amounted to a net 75 million reduction from last quarter.

I'm going to slide 12 now, the Surmont reserve revision.

The slide shows historical statistical information about the price differential between WTI and Lloydminster blend, LLB, which is a marker for Canadian heavy.

Because an historically wide differential between WTI and LLB occurs, and certainly occurred at the end of '04, in fact the differential was 5 standard deviations below its historical mean.

Based on the year-end price for these two crudes, a net back (ph) for Surmont bitumen was calculated, consistent with the Company's practices; also it accords with SEC guidelines to have a huge year-end crisis (ph) for reserve estimates.

As a result of the whole (ph) bitumen value we removed these Surmont reserves from our 2004 books.

Now there is no asset impairment, as the project certainly is very economically viable and it's going to be developed.

Furthermore there is very nominal amount of investment on our balance sheet so far for this project.

Another thing that is very distinguishing about Surmont that we'd like to pint out is that this is an integrated project, not just an E&P project in Canada.

It is an integrated project with our Refining and Marketing position in the lower 48; and on an integrated basis it certainly is a very economical project long-term.

In the past our reserve replacement numbers will be announced in February.

Complete disclosure of year-end reserve position will all be in our 2004 10-K filing.

Had we not had the Surmont revision here in the fourth quarter, as we had given guidance, our reserve repricing would be around 100 percent.

I think you are going to see with the Surmont revision our reserve replacement now is 60 to 65 percent.

Obviously we look forward to putting the Surmont reserve back on in the next year or two.

So probably a timing question.

So we go to slide number 13, Refining and Marketing.

I am going from E&P now to Refining and Marketing.

A very strong quarter in Refining and Marketing segment of our business, and this is both in the United States as well as internationally.

Our U.S. refining volumes were flat from quarter to quarter.

International was up 3 percent.

We also formed (ph) the market margin indicators.

While we saw lower market refining margins in the West and the mid-continent in the U.S., our realized margins in refining didn't fall nearly as much.

In the U.S. the market indicator crack sequentially fell $7.24 a barrel -- or fell to;

I'm sorry, fell to $7.24 a barrel from $9.10 a barrel.

But our realized U.S. crack spread fell only 46 cents a barrel to $8.38 a barrel in the fourth quarter; and we did $8.84 in the third quarter.

We were not as negatively impacted because the decreases in the 3:1 crack spread came primarily through gasoline cracks.

And we produce about 50 percent gasoline versus the 66 percent implied in a 3:1 crack spread.

In addition we had the benefit of widening light-heavy crude differentials.

The WTI/Maya differential widened significantly, from $11.66 a barrel in the third quarter to nearly $16 a barrel for the last 3 months of 2004.

The weaker seller market also benefited our refining business.

Internationally we had the help of better margins and the ability of our UK refinery to process significant quantities of low cost resid.

We did have certain property impairments in the inventory losses that did have an adverse impact to our earnings during the fourth quarter.

I'm moving now to slide number 14.

During the fourth quarter Refining and Marketing made $753 million in net income; that's up 6 percent from the third quarter.

This change in earnings was primarily due to our advantaged crude margins and higher realized finished product prices.

Worldwide our volumes were slightly higher in the fourth quarter, although in the U.S. we saw lower volumes in East Coast and the mid-continent.

Our international refineries were up, as I said earlier.

The loss in inventory included sales out of inventory in the fourth quarter, and this reduced our earnings for the refining market in the fourth quarter by $71 million.

We experienced higher DD&A charges for the quarter and impairments caused by revaluing refining error (ph) emission credits, and completing some of our marketing asset sales.

The improved commercial contributions and foreign exchange gains were offset by higher utility and tax costs.

I'm moving now to slide number 15, looking again in a different way at our Refining and Marketing earnings.

The chart illustrates the relative contributions of Refining and Marketing major business segments during the fourth quarter and then on a year to date basis.

You can see that U.S. refining continues to be the largest contributor, followed by international refining.

For the fourth quarter and during 2004 we experienced a loss in U.S. marketing and a modest profit internationally.

If you look at the fourth quarter, the international marketing did a little bit better to offset the slight loss we had in U.S. marketing.

On a year to date basis it was almost an offset.

We lost nearly $100 million in U.S. marketing, offset by marketing primarily in Europe.

So when you look at that net, all of our earnings then really came from the refining side of the business.

If we look at slide number 16 now, the LUKOIL alliance, as you know we announced our strategic alliance at LUKOIL in the latter part of September.

Transaction is consistent with our E&P strategy, increasing our access to reserves and production, and growing another new legacy asset, and do this in an efficient and attractive way for the Company.

We've acquired about 10 percent of LUKOIL by the end of 2004.

We started the quarter when we purchased the government's 7.6 percent ownership.

So having 10 percent at the end of the quarter, our average ownership in LUKOIL for the quarter was 8.5 percent; so that's how we used to determine our share of production and our share of our estimate of financial income.

The extraordinary general meeting of LUKOIL shareholders was held on January 24, just 2 days ago.

The proposed charter amendments and everything that was agreed to and announced back in September of '03 was passed.

And it was passed by essentially nearly a 100 percent vote.

Our nominee for the Board of LUKOIL, Kevin Meyers, was elected.

Now all the things that we are working on and continuously work on in developing our strategic relationship with LUKOIL -- I routinely meet with Vagil Alekperov, the CEO of LUKOIL every other month to make sure that both ConocoPhillips and LUKOIL are doing all that we can in our asset joint venture, our chaconment (ph), our sharing of best practices, looking for opportunities upstream, downstream, both inside and outside of Russia.

I can tell you that all of our expectations in terms of how we're working is going exactly as expected.

Furthermore, with respect to the Russian authorities, everything that they said that they would do they have done in support of our strategic alliance with LUKOIL.

Now I'm going to move on to page 17, which looks at the other parts of our business, the joint ventures, Midstream, Chemicals, emerging business.

Midstream business made $100 million in the fourth quarter, primarily higher NGL prices, inventory gains.

Lack of impairments were the primary reason for the improvement quarter to quarter.

Midstream business for all of 2004 had net income of 235 million for the Company.

In Chemicals we saw net income improve from better results primarily from the olefin side of the business, the ethylene business.

Our aromatics and styrenics saw lower earnings in the fourth quarter, primarily through a weakening of the benzene market and higher utility costs.

But if you look at our joint venture in Chemicals with ChevronTexaco, we earned $250 million for the year of '04.

Our emerging businesses showed a slight improvement from quarter to quarter.

Improvement came primarily from our United Kingdom Immingham power plant; it's up and running.

That's going to be contributing to this segment of our business.

Moving now to slide 18, which is the corporate segment part of our financial results.

The corporate cost excluding the impact of discontinued operations was a loss of $177 million.

That's down from 209 million sequentially.

The fourth-quarter net interest expense tax was lower.

There was a $26 million decrease in capitalized interest, which was partially offset by a $22 million reduction in interest expense.

The early retirement of $1.85 billion in debt in the third quarter resulted in $43 million of after-tax of debt retirement cost which occurred in the third quarter.

But that didn't occur obviously in the fourth quarter, so that is a good share of the improvement.

In addition, compared to last quarter we had 10 million increase in corporate overhead due to higher benefit costs.

I'm going now to slide 19 looking at this segment a little bit differently.

You can see the component of the corporate segment cost.

We had 109 million in interest expense; that cost was 6 million.

Other costs were 7 million; and that get that gets you to the 177 million cost.

Discontinued operation had a $48 million negative impact to income, primarily due to the impairment accruals related to getting near the end of our disposition of our West Coast downstream marketing assets.

Now I'm going to slide 20 which is return on capital employed.

You can see that during 2003 and 2004 our returns are competitive with the largest companies in the industry.

For the full year of '04 our return on capital employed, when you adjust for purchase accounting, was 27 percent for the fourth quarter; and for the whole year it was 23 percent.

We can't compare these numbers with largest companies in the industry because we don't have all their financial results yet; they haven't been reported.

Obviously during this time period higher commodity prices, margins have helped us, we have also been improving in terms of our efficiency.

In terms of the fourth quarter, our return on capital employed for E&P, again adjusted for purchase accounting, for E&P we did 33.7 percent.

Refining and Marketing was 25.6.

If you combine Midstream and Chemicals it was 34.7 percent.

LUKOIL was 10.9.

Combined basis was 26.9 percent.

Nearly 27 percent for the total Company.

Now I'm going to the last slide titled Wrap-Up.

I think we have clearly established that we are consistently following our capital operating and financial plans.

We are focusing on continuous improvement in all of our operations.

We expect our 2005 E&P production to increase to 1.62 million BOE a day.

That excludes LUKOIL.

If you include the share of LUKOIL in the production numbers, then we think it is going to grow to about 1.8 million BOE a day.

Now, production growth, excluding LUKOIL, our production growth will come through continued ram-up of our production in Magnolia, Hamaca, Bayu-Undan, Belanak, as well as expansion plans in the United Kingdom, North Sea, and Alaska.

With a 6.9 million cash capital budget in 2005, we are executing legacy projects that we think certainly are going to help grow the Company, as well as executing our cleaning fuels program in Refining and Marketing.

We are always working towards a goal of more than replacing our reserves.

And we look at the development of projects of heavy oil, LNG, potential projects in Qatar, Libya, Russia, Venezuela, North America, and Asia will allow us to achieve this objective.

This, Clayton, really concludes the prepared comments, remarks.

So I think now myself and John Carrig and Clayton will take whatever questions others have of us at this point in time.

Heather, can you line up some questions for us then, please?

(OPERATOR INSTRUCTIONS) Neil McMahon from Sanford Bernstein.

I've got two questions, really on reserves.

First of all on Surmont, you have a pilot project there since 1979; and you have started construction on the project.

Yet as you mentioned there hasn't been write-down.

Could you talk us through the Surmont situation in terms of why the reserves write-down did not lead to a capital write-down?

Since I'm presuming (indiscernible) costs against the project.

Secondly, could you go over what bitumen price spreads or conditions would have been required at the end of the fourth quarter to avoid a reserve write-down?

And the second question was, basically, could you comment if you have finalized the reserve on LUKOIL reserves under SEC standards to allow you to include these equity reserves in LUKOIL when you make your reserve statement? (indiscernible) also is included in your pre-Surmont number of around 100 percent.

Thanks.

First, why was there not a write-down?

First of all, for SEC reporting purposes we use year-end price assumptions is why we took the reserves off the books.

In terms of why there's not a write-down, again, there is a modest amount of investment on the books.

But when we look at an impairment there's a different method or calculation which looks at what do we think longer-term the value creation is going to be from the project.

As we look at that, there's a different price deck that is used.

We look at that, we see that the project is going to be economical.

Even in its own right, in the E&P part of the business; and certainly it is even more economical when you look at it from an integrated basis, both on the E&P side as well as what we have in terms of our upgrading capability in handling this type of product in our own system in the Lower 48 states.

Next question was in terms of what would it have needed to be to avoid taking reserves off the books.

I think I don't know the number exactly; but I think the bitumen prices normally do fall off in year end.

Had it been gone a path more normal to what we've seen in past years, we would not have taken the reserves off the books.

The absolute numbers I can't give you.

But what we see is the standard deviation was 5 off normal.

Had it been more closer to normal, we certainly would not have taken the reserves off the books.

In case of the situation at LUKOIL, as they move from SPE to SEC reserves, they have indicated in the past they expect to complete this process in the year 2005.

So I think it's a matter of sometime during 2005 that will be completed; and then we will recognize our ownership share of their SEC reserves.

John Carrig is here with me.

John might have a few more comments on this.

Neil, I just wanted to point out that the LUKOIL reserve estimates were not included in the numbers that Jim gave earlier, the 60 to 65 percent.

They would be substantially higher with the LUKOIL reserves.

Just a follow-up on Surmont.

Obviously, the ESG (ph), you did see 5 standard deviations as you showed on your chart there on the price spreads.

But given the fact that we are seeing light-heavy differentials increase, is this a trend you think you may have underestimated?

Or could we expect something that is a bit more wider in terms of the spreads going forward?

Because I am presuming you are not going to tell me the price at which the project works and avoids a write-off.

Obviously we don't know exactly what it's going to be in the future.

But we certainly would think that it's going to look somewhere more like historical norms; and maybe the differential a little bit wider than historical norms.

But not to the extent that leads us to not booking the reserves and not certainly going forward with the project.

Great.

Thanks.

Doug Terreson with Morgan Stanley.

Congratulations, guys.

If consensus estimates are in the ballpark this year, your free cash flow should be meaningfully higher than that which was suggested at the December analyst meeting.

So I was wondering if we can get an update as to the priority for those free cash flows in '05?

That is, if the consensus scenario comes to fruition, should we assume that LUKOIL investment will receive higher priority than dividends or reduction of debt and equity in relation to the plan that you talked about in December?

If not, could you just review the current priority for cash flow in 2005?

Thanks.

If the pricing environment that we see going forward, both in oil and gas prices and to some extent the refining crack spreads, go forward as we go through the quarters of 2005, I think what you'll see is certainly we will do our capital program that has been announced.

We are looking and for competitive reasons other opportunities that we can look to be growing our E&P position.

So that could lead to some new opportunities that we would add to our capital program.

These are long-term kinds of projects.

The other is we are also looking and believe we are identifying some other opportunities that could help us grow our Refining and Marketing business both in the U.S. -- do this organically in the U.S. -- as well as Europe and in Asia.

That not only helps that business but certainly supports the integration of the Company.

So what I'm saying is there may be some additional opportunities for us to expand the capital budget that we see; not a great deal, but some expansion from what we've announced.

The other is we will continue to be increasing our ownership in LUKOIL above 10 percent.

We said we are going to do that over a multi year effort.

That is not included in the capital spending program.

Now, having done that if we look at these prices and margin we are going to continue to see more excess cash than what could be applied to the spending that I just outlined.

We will not be aggressively bringing the debt down; although I would say if we see this kind of margin environment probably bringing the debt down $1 billion a year is good guidance.

Then what we would be looking at it is we like the discipline of good dividend increases once a year.

We think that's a good discipline for us to return cash to our shareholders.

But as we see a better share price we need a higher dividend to support from a coupon and yield point of view a higher share price.

And then as we said also, if we see this kind of pricing environment, we don't want to see more than 700 million shares outstanding.

We said we would be giving consideration in the early part of this year to announcing a modest -- not a real great aggressive -- share repurchase program; but one that enables us to start moving.

So that we don't see more shares outstanding, even though there are 706 million outstanding now, back to 700 million.

I think you are going to see us work on that in the early part of this year.

So that is really the priority of how we use the excess cash.

Just quickly, late last year you guys in Gazprom signed an MOU for the Stockman field in the Bering Sea.

While I recognize that the lead time will be very long for this project, it is one of the largest gas fields in the world.

So it could end up being important for all involved.

So my question regards the next steps that you hope to take on this project in '05 and '06.

You did talk about the investment climate was still positive for you guys in Russia.

So if you have any preliminary time table, if one exists, as it relates to how you are thinking about commercialization of this field, I would appreciate it.

Thank you.

We did sign an agreement, nonexclusive, to study Stockman along with other companies that have done similar things, to study the Stockman field.

Our understanding is that will lead to probably in the middle part of this year -- this is coming from Gazprom -- that decisions will be made with respect to who will participate with them in the (indiscernible) of the field.

We are certainly interested in it.

If fits into our LNG strategies -- that our LNG strategy is to bring gas primarily to the United States and to the Gulf Coast as well as potentially over time to Europe -- is not only just Stockman.

Right at the top of the list is doing LNG projects in Qatar, the one we have announced, and hopefully more.

We are looking at LNG not only from Stockman but also from our reserves in our position that we have in Nigeria, Venezuela.

Don't forget also that we are looking for opportunities that involve gas in Asia from the Timor Sea.

The markets are really destined primarily to customers in Asia, as well as maybe longer-term or potentially to the West Coast and the United States.

But Stockman is an important one; it's not the only one in the portfolio.

Great.

Thanks a lot.

Mark Flannery from Credit Suisse.

My question is on LUKOIL.

You mentioned, Jim, earlier, that there were 2 adjustments to get from let's say a LUKOIL model to that $74 million profit that you booked.

One of them is a reserve adjustment, which I assume is a DD&A thing; and one is budget accounting.

Can you give us some guidance as to how biggest those numbers are, just to help us model LUKOIL for '05?

Those numbers are roughly in line with the numbers that we outlined for you in our analyst presentation in November.

Right.

So no changes to them. then?

They are not exactly the same;

I'd say they are roughly in line.

That is great.

I have a separate question on guidance for Alaska production going forward.

Pretty strong number for Alaska oil production.

What do you see for the general trend there in '05 and '06?

Well, I think we see that our production could be flat going from '04 to '05, and is in thousand barrels oil equivalent basis.

So we see some natural decline in our fields.

But we also see some projects that we are doing, satellite fields, and also things that we're doing with Alpine and others, with some expansion in capacity that we -- for all these reasons we see a good guidance would be flat production from '04 to '05.

Great.

On the Alaska crude realizations, which were pretty strong, are you telling us really that this is just a timing issue and eventually you are going to get back to something that looks a lot more like ANS with a normal differential?

Are you talking about differentials?

Yes.

I think we did see over a number of years some pretty tight differentials.

Then here in the latter part of '04, the differentials widened some.

So I think what you're going to see is maybe more of what we have experienced in the latter part of '04 will continue; but we also have a number of contracts that we continue to follow.

But as these contracts mature over the next several years, I think probably for guidance you might want to look at the differentials in the latter part of this year continuing, versus what we've experienced in '03 and the early part of '04.

Great.

Thanks very much.

Jennifer Rowland with JP Morgan.

I had a question on U.S.

LNG projects.

You made an announcement a couple weeks ago about pursuing Beacon Point.

Just wondering if you could talk about Beacon versus Compass?

If one project looks better than the other?

And if you get permits for both, would you go ahead with both projects?

We already are going forward and have all the permits.

Construction has started for the Freeport terminal that is onshore, where we have 1 billion cubic feet of capacity and we have the option to expand that to 1.5 billion cubic feet of capacity.

Our Compass port and our Beacon projects that we've announced, Compoass port is ahead; what we have in mind is really potentially having 3 LNG terminals, each of them can do 1 billion cubic feet to 1.5 billion cubic feet a day.

So if we look at our target of having a capacity of doing 3 billion cubic feet a day, it can be handled by all 3 or any 2 of the 3.

It gives us flexibility.

So that is really what we are doing.

Obviously as we go through the study process over the next year or two, we will refine our plans.

But the thought is we'd be working on doing the 3 terminals.

Where does Compass stand in the permitting process?

We expect Compass Port, seeing that thing go through (multiple speakers), Compass Port, the middle of this year for permitting.

Say sometime in the third quarter.

Thank you.

Fadel Gheit from Oppenheimer.

Jim, can you help us understand the ramification of the changes in royalty in Venezuela on Phillips and on Venezuela?

Maybe you can help me out a little bit, Fadel.

What are you saying?

You're asking what is the status (multiple speakers)?

No, I mean your interpretation of what the government is trying to do.

I mean aren't they shooting themself in the foot by doing that?

Because that deal will discourage obviously investors of foreign companies, and Venezuela does not have the money to develop its own resources.

So, I think the logic behind it, since you are one of the largest companies, there, and one would assume that you probably understand what the government's goal is?

First for our heavy oil projects, Petrozuata and Hamaca, the Venezuelan authorities have done a great deal of research and feel that the royalty rate of 1 percent does not reflect what -- when the projects were started oil prices might have been down toward the low 20s; oil prices are now 40 to $50 a barrel -- and so have felt that it's appropriate from a Venezuelan point of view of proper sharing that the royalty rate needs to be increased.

It has been increased.

It's been reflected in our numbers.

All other aspects of the Hamaca and Petrozuata projects continue to develop and run exactly like we expected.

These are good projects, create a lot of production and good returns for our Company.

In terms of Corocoro, there has been a lot of media attention regarding Corocoro with respect to it has technical challenges, it has economic challenges.

But we went to make sure we get this right.

I know the Venezuelans want to make sure we get it right.

I think Minister Ramirez has just recently indicated -- we have been working, our people have, with the ministry as well as with Petaveza (ph) -- that you're going to see these issues sorted out and resolved and Corocoro will be going forward.

In terms of the ramifications, it is an important country for us.

We have been there for a long period of time.

We're pleased with our investments.

They will to well for the Company.

And relationships from our perspective are very good with the Venezuelan authorities.

So that's really what I can give to you with respect to our heavy oil projects as well as Corocoro.

A question on the Libya situation, many companies expect (indiscernible) very soon there.

How important is Libya to you this year and next year, and where do you think going from here?

Well, Libya is certainly an important country for us, is why we were very pleased that we could retain our oil concessions for an 18-year period of time, and we're pleased with the Libyan government that they are very willing to have honored those concessions.

And with our group, our partners, Marathon and Amarada Hess, working together to reenter the oil concessions.

We've done a lot of work in 2004.

We kind of thought that the reentry might have been completed in '04, but it does take time to do these things and get these completed.

So we would expect that this will be sorted out here in the next several months, reentry of the oil concession.

And then the issue then is what are the incentives and how do we work in terms of the development of the new opportunities to raise production.

So Libya is an important opportunity and country for us, not only in terms of the oil concessions but the opportunities to participate new opportunities, both on the E&P side as well as potentially how we technically might be able to help them on other things downstream.

So it's an important country for us and time will tell, but we're pretty optimistic about what it can mean to us.

It's a good piece of our portfolio worldwide.

Finally, and very briefly, LUKOIL, a quick read on the positive and the negatives, what surprised you the most on the upside and what you think you should do some more on the downside?

Okay.

First in terms of -- I don't see any negatives.

As I said earlier, everything that we said we wanted to do with LUKOIL, the cooperation, the communication, the exchange and comment of employees and working on the joint venture in the north, the handling of the extraordinary general meeting and passing all the governance things, putting our company representative on the Board of Directors; everything has gone exactly as we planned and expected.

We couldn't ask for more corporation and help than we are getting in working together jointly in this strategic alliance with LUKOIL.

The other thing that I would say is everything that the Russian authorities and the government said they would do to help and support, they have followed through exactly.

So there are no negatives at this point in time.

I mean, time will tell.

This is a decade to decade kind of opportunity.

But as far as we can see, everything that has developed is very positive for us, and we're very encouraged by this new opportunity and relationship with LUKOIL.

Thank you and best of luck.

(OPERATOR INSTRUCTIONS) Paul Ting with UBS.

Yes, two questions, please.

First one on downstream and a question on CapEx.

First on downstream, you mentioned about the extended light-heavy differential.

Quite a few companies reported so far have indicated that they were able to further benefit from that by increasing their capability of processing sour and heavy in the fourth quarter.

Can you tell us your experience in the fourth quarter?

Were you able to increase your proportional amount of heavy sour crude profit?

We have some data in the New York report that shows our production, Paul, but I don't believe we took any substantial unusual action to take advantage of the margins.

We are configured in the UK to be able to process lower-cost resid products and high-grade (indiscernible) products into a better slate of yields.

And in addition, the fact that we had such good -- we had good performance from utilization permitted us more flexibility to get better yields.

But in the U.S., it's rather inflexible right now in terms of processing more heavier crude?

If you mean did we shift to more heavier crudes, at Wood River we brought up the coker this last summer, so we've gotten extra capacity there.

We've done some modest things, but I would not say it's -- other than Wood River, it's huge.

Paul, what I think is distinguishing about the fourth quarter is we have less turnaround activity.

Most of our turnaround activity primarily takes place in the second and third quarter, so we have less turnaround.

We ran quite well and we always figure out with all the right models which crude to run, and we maximize each crude to get us the best spread.

So for all these reasons, we ran well.

Longer-term, we obviously are looking organically how can we increase our capacity to handle heavy sour crude into our system because we see that those are more and more proportionately the barrels that we're going to be handling.

In terms of the refining and marketing part of the business when we do that, our cost structure, cost per barrel of processing, is going to go up, but the profitability per barrel when you look on a normalized basis should be going up.

So we are obviously always looking at our cost, but it's really the profitability per barrel which will drive it.

So if you go to a heavier sour crude slate, why, cost per barrel goes up, but we believe the profitability, this is how we're going to hopefully add volumes but also add organically the profitability of the business on any normalized assumption with pricing.

Great, that's very helpful.

If I can, just by way of clarification in the capital expenditure, $6.9 billion excluded LUKOIL.

Can you give us some idea what the CapEx amount for LUKOIL might be?

And secondarily, Corocoro, if you do get a favorable resolution, is that going to increase your CapEx?

No, the CapEx on Corocoro, the project does not really -- we have to sort out things with the authorities in Venezuela, but all of our teams continue to work in process the Corocoro project.

So I don't think you're going to see delay necessarily or spending on the project.

When we go through LUKOIL, obviously it's how quickly we increase our ownership above 10 percent, is money that must be allocated for investment.

But we still have to pay and we think it's going to be here in the next month or two, or we have to pay for the 380 million barrels of the joint venture.

That's a dollar a barrel.

So that 380 to $400 million capital spend is going to take place in the first quarter, second quarter, somewhere in there.

And then our spending to develop the joint venture in (indiscernible), I don't know what we have in the budget for the year '05, but that's already in --.

It's already in the 6.9.

It's already in the 6.9.

So over and above that is how aggressive are we in terms of increasing our ownership above 10 percent in 2005.

Thanks a lot; that helps a lot.

Bernie Picchi with Foresight Research.

Could you address and hopefully quantify the currency effect, that is the strengthening of the sterling and the euro against the dollar on your record-high reported international refining and marketing results in the second half of the year?

Because it looks as it that big jump seemed to coincide with the great weakening of the dollar in the second half of the year.

Well, let me go to one point that it's a good opportunity to say.

I'd like to go to the E&P business first, and then we can go to the refining and marketing. on the E&P side of the business, cost structure, operating cost structure per barrel goes up.

Total cost we see gone up of running our operations and our production is up about $90 million from '03 to '04.

And of that $90 million, a good chunk of it is foreign currency and some of it is the higher cost of energy to run our offshore facilities.

So, actually, on a per barrel basis for E&P, if we produce somewhere in the neighborhood of 600 million BOE and it's up $90 million, that works out to less than 20 cents a barrel, and proportionate, the large part of it is foreign currency.

Obviously, we'd have some additional energy costs.

We also know that the movement of the dollar and commodity price increase in fuel is having an impact in terms of our capital spending.

So that has gone up in terms of what it costs just for commodity of steel and whatever.

Your question on the downstream, I don't know, John or Clayton.

On the downstream on a transactional basis, the currency gains and losses were in the neighborhood of $20 million.

They're not that significant.

We would have experienced some improvement in results as a result of -- in the marketing segment as a result of the improvement in the currency.

But overall, I would say that's not been as important to us as the ability to process the lower cost for ZID (ph) products and the ability to get better yields and better flexibility out of running a stronger utilization.

Thank you.

Bruce Lanni with AG Edwards.

Good quarter, guys.

Just a little follow-up on Libya.

You may have mentioned this, but it may have passed me.

Is any of the production, Jim, included in your forecast for this year from Libya?

That would be the first question.

And then on Alaska, I haven't heard very much in respect to what's been going on in the National Petroleum Reserve.

Can you give us any type of update there on any progress or discoveries that have been made?

On Libya, there is no production included in our forecast for our production for '05.

Obviously, we think there will be, but we did not put it in our numbers.

So you could say it could be conservative from that point of view.

In terms of Alaska, we are one of the big acreage holders at NPRA.

There may be some additional acreage (indiscernible) come available.

We certainly will be looking at them.

I think everything that -- we're the largest explorer up in Alaska.

We continue to drill a number of wells up there every winter, and a lot of them have to do with satellite opportunities extending from where we already have infrastructure, but also NPRA is an important area for us.

So I don't really have a lot more to say on that.

But I would like to take the opportunity to respond and bring up the gas pipeline from Alaska.

We have a lot of help from the Alaska delegation.

We essentially passed what's required on the federal legislation to accelerate and move forward on the gas pipeline.

We along with our partners, Exxon Mobil and BP, have submitted a proposal to the Alaskan authorities, a basic conceptual proposal by which we would be willing to go forward with the gas pipeline.

And so we're right in the process of working through that.

The objectives of the producer, reproducing companies and the state of Alaska, is to negotiate a proposal that we both can live with and submit that to the state legislature end of first quarter, early second quarter, for their consideration.

This is a really important initiative for the companies as well as certainly ourselves and the state of Alaska. 0We need to get on working and developing the gas pipeline in Alaska.

I know the state wants to do that as well, as well as the federal delegation back in Washington.

This is an important project for all of us to be moving forward in 2005.

Jim, that was going to be my follow-up question, so if you could just one more thing.

If it went forward, what do you see the timing being, number 1?

Number 2 is I was going to tie in the question about McKenzie Delta gas, anything you can add with that, please.

McKenzie Delta gas is going to be developed in the pipeline in the project, and that's going to come before the Alaska gas pipeline.

But that gas primarily is going to stay in Canada.

The gas coming from Alaska is going to be going to the lower 48.

What was the other question?

As far as timing.

Oh, timing of the gas pipeline in Alaska.

Well, everyone has their different times and how quickly and whatever, but I think probably the earliest to get it on and running is 2012, and many people think it's 2013, but it's too early to tell.

What really moves that time schedule is the importance by which we reach agreement between the producing companies in the state of Alaska, the basis upon which we're going to do the pipeline.

And we need to get that done over the next several months.

That we can really work on the schedule and see how we can maximize the schedule.

Then I can surmise from what you are saying that the two projects will be independent; that Alaska gas will not tie into McKenzie Delta under the current proposal?

No, they're separate discrete projects.

Great, thanks.

Paul Cheng with Lehman Brothers.

Good morning.

Jim, can you tell us -- or maybe this is for John -- can you tell us what is the 2005 expected downstream in terms of run (ph) expense going to be?

$350 million.

350.

So that means that 2005 is going to be a more heavy turnaround year than 2004.

That is correct.

Well, it's not just turnaround, but it's the implementation of the Clean Fuel Program.

The turnarounds are a little more expensive because of putting in place the equipment and the units and all that we need to processing and meeting the specification of clean fuel.

Jim, when I'm looking at -- you are going to have very strong cash flow it looks like over the next several years, even after all the other things that you talk about early in your remarks, how you're going to utilize it.

Have you thought about increasing your '04 exploration budget?

It seems like that you're not spending quite as much money in order to fully replace your reserve base on the (indiscernible) bid, given that the strong cash flow you set a consideration there.

Well, I think the exploration budget that we outlined to you in the November analyst update is really the budget we're going to follow for all of '05, irrespective of what happens in terms of the commodity price and environment.

Now to the extent that we have exploration success in discovery that leads to appraisal and drilling, well, that would come on top of that.

That's how we would expand.

So at this point that you did not expect say to win or substantially raise your exploration expense?

No. (indiscernible) is what we've been (indiscernible).

This is probably for maybe John.

In the Timan-Pechora when you guys are finally getting the production and everything going, is that going to -- and the resulting earning -- are those being reported as part of your international E&P, or it is going to be grouped at under the LUKOIL investment?

That will be part -- the Timan-Pechora joint venture operation will be part of the international operations.

It will not be part of the LUKOIL segment.

John, is there a rough number rule of thumb what is the minimum cash balance that you need on hand to smoothly run your operation on a day-to-day basis?

Clearly, you don't need 1.3 billion.

Is it 500, 600, 700 million or anything?

It is certainly under 500.

We are always looking for ways to make sure that we have minimum cash balances global.

Finally, Jim, Corocoro, the physical term is going to be grandfathered from the hydrocarbon 2001, or that is going to be subject to the hydrocarbon 2001 law?

Yes.

On that one, I think it's something that it's really best that it's being discussed with the authorities of Venezuela, and it's really not appropriate for me to comment at this point in time.

So it's not finalized yet, in other words?

I won't reach any conclusion or thought one way or another.

I just say it's premature for us to be talking about any situation on fiscal or changes or whatever our contract is with them at this point in time.

I see.

Okay, very good.

Thank you.

Heather, we're past the hour.

I think we have time for one more.

Arjun Murti with Goldman Sachs.

Thank you, real quick one.

Did you offer or could you offer any quarterly sequencing of the production growth for this year?

Is it progressive over the year or perhaps more back-end loaded?

Well, I think, Arjun, I don't have it in front of me, but I think what you'll find is it may have some lumps in it.

It has seasonality for sure, and then the timing and the ramp-up of the new project.

So maybe we could come back to you off-line on that.

For sure.

Did you say LUKOIL will continue to be accounted for as a line item rather than allocated to the segments?

That is correct.

That's great.

Thank you very much.

Well, I think we would like to conclude our call.

We appreciate all the questions.

A replay of this call is available on our website along with the slides, and certainly those of us in IR are available to answer any questions you may have.

So with that, thank you again.

Ladies and gentlemen, thank you for participating in today's conference.

This does conclude the program.

You may now disconnect.

Everyone have a great day.