康菲 (COP) 2006 Q1 法說會逐字稿

Good day, ladies and gentlemen and welcome to the ConocoPhillips first-quarter earnings conference call.

My name is Jen, and I will be your coordinator for today.

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

We will be facilitating a question-and-answer session towards the end of today’s conference. (OPERATOR INSTRUCTIONS).

As a reminder, this conference call is being recorded for replay purposes.

I will now hand the presentation over to your host for today’s conference, Mr. Gary Russell, general manager of Investor Relations.

Please proceed, sir.

Thanks, Jen and good morning and welcome to ConocoPhillips’ first-quarter conference call.

I am here with Jim Mulva, our chairman and chief executive officer and John Carrig, our executive vice president of Finance and chief financial officer.

During the call today, we will be using presentation material that will help us explain the financial and operating performance of our Company during the first quarter this year, as well as our updated plans for the remainder of the year.

As you know, we have extended the call beyond the normal 60 minutes for this first quarter.

Jim’s remarks will last approximately 45 minutes and then the remainder of the time will be available for your questions.

On Page 2, you can read the Safe Harbor statement, which says among other things that our presentation today along with our responses to your questions will include forward-looking statements regarding our current expectations.

Actual results may differ materially from our current expectations.

You can find a list of those items that could cause material differences between our current expectations and actual results in our filings with the SEC.

Now I would like to turn the call over to the Chairman and Chief Executive Officer of ConocoPhillips, Jim Mulva.

Gary, thank you and I also appreciate all those that are joining us today for our first-quarter earnings conference call.

I appreciate your interest in our Company, and so I am going to start my comments on slide or Page 3.

As you can see during the quarter, we completed the acquisition of Burlington Resources, and we’re pleased with the progress we are making towards integrating the combined companies.

This transaction establishes our Company as a leading natural gas producer in North America for high-quality, long-lived gas reserves.

We, also in the first quarter, completed the acquisition of the Wilhelmshaven, Germany, refinery.

Now this is in line with our strategy to expand our global refining presence.

We also advanced plans to upgrade the refinery to allow it to process higher-sulfur crude into more light-end products.

During the quarter, we generated $3.3 billion in net income, $4.8 billion in cash flow.

We continued to fund our capital program and other investments by effectively reinvesting 141 percent of our first-quarter net income back into our businesses.

We increased our dividend in the first quarter by 16 percent.

Now because of the Burlington Resources transaction, we ended the quarter with a debt-to-capital ratio of 30 percent, and I am going to go through this with additional details and our updated plans for the remainder of the year in subsequent slides.

For the first quarter of 2006, our E&P production, now this excludes the LUKOIL segment and there is no recognition of volumes from Burlington Resources, so our production was 1.61 million BOE a day, slightly higher than the fourth quarter of last year.

Our estimated share of LUKOIL’s production in the first quarter was 322,000 BOE a day, and this reflects primarily our increased equity ownership position.

On a downstream, our refineries ran at 85 percent of crude processing capacity.

That is down 3 percent from the fourth quarter.

Our average diluted shares outstanding in the first quarter was around 1.4 billion, while our diluted shares outstanding on the last day of March was 1.68 billion, and this reflects on that date the completion of the Burlington Resources acquisition.

Now I am moving onto the next slide, Page 4.

You can see the sequential quarterly comparison of our net income.

Our worldwide realized oil prices were higher than the previous quarter.

However, worldwide realized natural gas prices, refining margins and marketing margins were quite a bit lower than the fourth quarter.

The net effect of all this along with other market impacts reduced our first-quarter net income by $482 million, as compared to the fourth quarter.

Our first-quarter net income was negatively impacted by $242 million, and this results from lower E&P sales volumes and lower volumes in our refining marketing segment.

We’re going to talk more about this in subsequent slides.

You can see our operating costs were $121 million lower than the fourth quarter, mainly the result of reduced hurricane-related maintenance expense or utility costs partially offset by a higher turnaround cost in the downstream.

The previous quarter, the fourth quarter, was negatively impacted $103 million from the results of discontinued operations, as well as the cumulative effect from the adoption of a new accounting rule.

Other items impacting our earnings for the first quarter include lower exploration expenses, reduced impact of foreign exchange.

Also we did not incur early debt retirement premiums during the first quarter like we did in the fourth quarter of last year.

These benefits were partially offset by the costs associated with the unplanned downtime at the Excel Paralubes facility at our Lake Charles refinery.

Net effect of all these other items was an improvement of $112 million shown in the slide and the first-quarter earnings, as compared to the fourth quarter.

So you can see, it all rolls up to $3.3 billion first quarter of this year.

Now I am going to slide 5.

You can see we started the quarter with a cash balance of $2.2 billion.

We generated $4.8 billion from operations in the first quarter.

We completed the acquisition of Burlington Resources and in so doing, we picked up their $3.3 billion in cash.

We then issued debt of $50.3 billion and then paid $17.5 billion, which is the cash part of the transaction to acquire Burlington.

We funded our capital and other investing activities, amounting to $4.6 billion in the quarter and paid dividends of $496 million.

But after you consider the other source with uses of cash, we then – through all of this – we ended the fourth quarter with a cash balance of $3 billion.

I am going on to slide 6, the debt-ratio slide.

The bar chart on the left shows equity grew to $73 billion at the end of the first quarter mainly as a result of the Burlington acquisition.

If you look at our earnings less dividends, we increased – in that $73 billion – we increased retained earnings by about $2.8 billion in the first quarter.

The balance-sheet debt increased to approximately $32 billion, resulting in a debt-to- capital ratio of 30 percent at the end of the first quarter.

I am going to slide 7.

If you compare E&P first quarter of 2006 to the fourth quarter of 2005, you can see our worldwide oil prices were up 7 percent from the previous quarter, up to $56.63 a barrel.

Our global realized natural gas prices were down 9 percent from the previous quarter to $7.24 an Mcf.

Our production in the first quarter was slightly higher than the fourth quarter, up a little bit more than 1 percent or 20,000 BOE a day.

However, noted that both our crude oil natural gas sales volumes were lower than in previous quarter.

Exploration expenses were lower.

As I said earlier, we completed the acquisition of Burlington Resources at the end of the first quarter of 2006.

Going to slide or Page 8 now.

This slide illustrates the various production between the first quarter this year and last year.

We saw higher production from Timor Sea, Venezuela, Lower 48.

Then the increased production was offset by unscheduled shutdowns at Prudhoe Bay, as well as lower production volumes from Canada.

Other negative impacts to our production in the first quarter included the impact of higher crude prices on our production-sharing contracts, pretty small though, but production- sharing contracts in Vietnam and Indonesia.

So then when you add to the 1.610 million BOE a day, the 322,000 BOE a day, which is our estimate of our equity share of LUKOIL’s production, then you see how we get to the 1.932 million BOE a day for the first quarter.

I am going on to Page 9.

Talk about income from the last quarter of 2005 to first quarter 2006.

As you can see, first quarter increased to $127 million to $2.55 billion.

In our first quarter, the results were improved $190 million over the previous quarter, mainly due to lower negative impact in the first quarter of the market-to-market valuation of some of our natural gas contracts in the United Kingdom.

We had the benefit of higher realized oil price.

It was essentially offset by the effect of lower realized natural gas prices.

As I said earlier, lower oil gas sales volumes reduced first-quarter net income by $159 million.

This is a result of the first quarter being shorter by two days as compared to the fourth quarter along with the timing of our crude oil [lift fees].

Exploration expenses were $68 million lower due to lower dry hole costs and lower lease impairments.

Other factors improved our first-quarter net income, as compared to the fourth quarter last year, which included lower hurricane-related charges from insurance mutuals and reduced impact of foreign exchange.

I am going now to slide 10.

We’re moving to refining and marketing comparison in the first quarter this year to the fourth quarter last year.

You can see our worldwide refining marketing margins were significantly lower than the previous quarter.

In the United States, our first-quarter realized U.S. crack spread declined $2.53 a barrel to $10.18.

Our international realized crack spread declined $3.72 a barrel to $5.01 a barrel.

Our U.S. refining system ran at 83 percent of standard capacity.

So that is down 2 percent from the 85 percent in the fourth quarter of last year, and this is the result of heavy turnaround activity and unplanned downtime.

I’m going to talk more about this in a moment.

Our international refining system ran in the first quarter 94 percent of stated capacity.

So that is down 8 percent from the fourth quarter, and that primarily is due to unplanned downtime.

I’m going to discuss the turnaround activity and this unplanned downtime on the following slide.

But before I leave, the turnaround expense in the first quarter amounted to $163 million pretax for the quarter, and that is higher than we expected and $77 million higher than we had in the fourth quarter of last year.

Now I am moving to slide 11.

As you can see, our refining/marketing net income was significantly lower than the fourth quarter last year.

It was down $583 million or 60 percent to $390 million first quarter this year.

We experienced lower worldwide crack spreads, lower marketing margins along with other marketing impacts.

This reduced our net income $667 million.

You can see it on the left-hand side of the slide.

In addition, the return of the Alliance refinery to normal operations following the hurricane damage last year is more complex and more time-consuming than we anticipated.

So as a result, the phase startup of certain processing units cost the majority of Alliance production in the first quarter to be lower valued, intermediate volumes rather than the higher value, clean products.

Now the lower volume is primarily due to turnaround activity and unplanned downtime at our refineries; reduced our net income $100 million.

Now we completed planned turnarounds at Lake Charles, Borger, Trainer and Ferndale.

In addition, we completed turnarounds at Sweeny and Ponca City, which had been delayed in response to supply disruptions following the 2005 hurricanes.

We also completed a turnaround at Bayway, which was originally scheduled for later this year, but we had to accelerate it into the first quarter to address operational issues.

And then we had unplanned downtime at Lake Charles, Bayway, Trainer, Ferndale and the Humber refinery in the United Kingdom.

The result of all this planned and unplanned downtime is the utilization rate worldwide at 85 percent.

Operating costs were lower than previous quarters and the help was $99 million driven by lower maintenance costs, normal maintenance costs, including those that are hurricane-related and by lower utilities.

This was partially offset by higher turnaround costs.

Earnings in the quarter were further improved compared to the previous quarter by $83 million, a result of the cumulative effect of an accounting change recorded in the previous quarter that did not recur.

In summary, if you look at this slide, you can see we had a significant amount of planned and unplanned turnarounds.

With respect to our planned turnarounds, if you look at the market environment, our timing was correct for these planned turnarounds.

We also want to note that there was a period of time in the latter part of January and the early part of February where the market conditions were that we actually experienced negative margins primarily on the East Coast of the United States, but to some extent in other parts of our system.

I am going to moving now to Page 12 going from Refining and Marketing to our LUKOIL investment.

You can see we increased our equity ownership by 1 percent in the quarter up to 17.1 percent.

The result, our average ownership for the quarter was 16.6 percent.

Our estimated equity earnings for the first quarter for LUKOIL, $249 million.

That is up from $189 million in the fourth quarter.

Increase is mainly attributable to higher realized crude prices and increased ownership.

I am going to slide 13 now, which addresses the midstream and chemicals joint ventures and emerging businesses.

You can see the earnings for midstream first quarter compared to $10 million.

A decline of $37 million from the fourth quarter is primarily due to lower natural gas liquids prices.

Turning to our chemicals joint ventures.

The earnings improved $35 million in the first quarter up to $149 million.

It’s primarily attributable to higher polyolefin margins, partial settlement of a business interruption claim.

In addition, olefin and polyolefin sales volumes recovered from the prior quarter hurricane impacts.

Our emerging businesses have a relatively small impact to the Company’s performance.

They were slightly positive, improved compared to the fourth quarter of last year primarily attributable to domestic and international power operations.

I am moving to slide 14, which is the corporate element.

You can see the corporate segment impact on net income was a loss of $168 billion in the first quarter.

Net interest expense was $37 million lower than the fourth quarter.

Our corporate overhead was $11 million higher, mainly due to benefit-related charges in the first quarter.

All the other factors, which impaired first-quarter results, generally relate to issues that favorably impacted the corporate segment in the fourth quarter but did not recur in the first quarter.

Having looked at the corporate side presentation so far is our normal presentation; it is focused on our operating and financial performance in the first quarter.

What I would really like to do now in subsequent slides is shift the focus to updating you on our Burlington Resources acquisition, as well as to update you on our plans for the remainder of this year.

And so what I am going to do is I am going to start on this next slide with our ROCE analysis.

You can see we have made some changes in our presentation of the ROCE analysis and this is to reflect and better represent the performance and the impact of ultimately us going forward in the Burlington acquisition.

If you look at this slide, what you can see in green shows what our return on capital employed is.

The shaded area represents the return on capital employed from the lowest to the highest of the peer group.

We say the peer group, as you know in the past, is the largest publicly traded integrated companies and that includes Chevron, Total, Shell, BP and Exxon.

So looking at this slide, you can see we have made adjustments to our ROCE for purchase accounting to put ConocoPhillips’ results on an apples-to-apples comparison with our peers for past periods, but then we’re going to use this going forward.

So going forward in subsequent quarters and annual presentations, we’re not going to make purchase accounting adjustments for ConocoPhillips.

But in the shaded area for our peers, we will make adjustments for our estimate of the pooling benefit they receive from past major business combinations in determining and representing their ROCE.

So the bar chart reflects ConocoPhillips’ ROCE without adjustments for purchase accounting.

We have for presentation purposes excluded the impact of the Burlington Resources acquisition from capital employed, since no income from Burlington Resources is included in our first-quarter net income.

Remember that transaction was completed at the very last day of the quarter, first quarter.

So you can see the adjustments that we made for a major business combination to arrive at an ROCE of our peers and this is further reflected – if you wanted to look at the numbers of how it is computed – table 1, which is attached to our presentation.

So this is the presentation format that we’re going to be using going forward in the future.

We believe that this format will provide an appropriate representation, fewer adjustments by which to measure the relative performance of our Company over time against the peer group.

Now if you look at the right bar, the annualized ROCE for ConocoPhillips’ first quarter of 2006 was 20 percent.

In that 20 percent, I’ll just give you what the various segments are.

E&P is 27 percent, Refining and Marketing about 8 percent, midstream chemicals 31 percent, LUKOIL 17 percent, combination of all this is 20 percent.

We’re going to the next slide, 16.

We have made some changes into our executive management team and this comes really as a result of retirements and also the Burlington acquisition.

As you can see, Randy Limbacher, who was formerly the chief operating officer from Burlington Resources, is EVP watching over North and South America.

With the retirement of Jim Nokes, Jim Gallogly has effectively taken leadership of the downstream part of our business.

Then you can see there are changes in responsibilities.

We swapped the roles of John Lowe and Phil Frederickson.

Ryan Lance has come in as the senior vice president, giving us far more focus and leadership and management of our large capital projects around the world, as well as the technology to support upstream and downstream.

So now I am going to go on to Page 17, which talks about the synergy associated with the Burlington transaction.

When we announced it back in December of 2005, we said that our estimate of synergies was $375 million pretax.

The integration has gone very well.

We were very organized, worked very hard and all of the Burlington Resources and ConocoPhillips employees have been identified.

We’re well on our way with all of the implementations, who is going to do what.

Synergies are certainly not the primary driver for the acquisition.

They are important to us, and we have the accountability in place as we have done with prior transactions to capture them.

The current estimate is now $500 million pretax, and then you can see on the right-hand side of the slide the areas where we expect to capture these synergies.

I am going to move on from the synergy slide to Page 18, transaction costs.

Our latest estimate of nonrecurring transaction costs associated with the Burlington transaction includes $176 million capitalized as part of the purchase price.

These costs are generally employee-related costs incurred by Burlington Resources, such as severance, benefits, outplacement, relocation.

Then we expect to incur restructuring and transition costs totaling $60 million in 2006 and $20 million in 2007.

And these will be reflected and reported in future quarterly periods in our corporate segment.

And we expect our E&P segment to incur additional $34 million in 2006 and $12 million in 2007, and this represents our estimate of employee retention costs.

Now what I am going to do on the next two slides is go back and look at the Burlington transaction from two different perspectives.

First, we’re going to look at the breakeven for the acquired resource space and then we’re also going to look at the net income breakeven.

It’s based on what we expect to see in our future income statements going forward.

So first on slide 19 is the Burlington Resources acquisition.

Now we used the year-end 2005 book reserves along with Burlington Resources of having probable unproved drilling inventory, which was about 5.6 billion cubic feet.

Burlington Resource space then is approximately 18.1 trillion cubic feet equivalent.

Based on a full purchase price of $34 billion, that translates to a unit acquisition cost of about $1.88 Mcf equivalent.

You can see that at the top of the slide.

Then we add to that a future estimated capital cost of about $2 Mcf equivalent and that we assume will be spent to develop both the proved and the unproved drilling inventory, which approximates 9 trillion cubic feet equivalent and spread over the full resource space of 18.1 trillion cubic feet equivalent, that represents about $1 Mcf equivalent.

And operating costs and taxes other than income tax at about $1.40 Mcf equivalent and $0.32 Mcf equivalent, respectively.

So then using the full synergy run rate that we expect to capture by 2008, a $0.46 Mcf equivalent, you can see the medium-term breakeven for the acquisition is about $4.14 Mcf equivalent.

We believe this break-even acquisition cost for Burlington Resources proved reserve has no inventory available prospects.

It’s competitive.

Now from a different perspective, let’s go to slide 20, net income breakeven.

Using the pro forma financial information we filed with the SEC on our form 8-K earlier this month, the unit DD&A for Burlington Resources production is estimated at $2.32 Mcf equivalent.

To this you should add operating transportation costs, $1.40 Mcf equivalent, and taxes other than income tax at $0.32 and assume full year run rate of our synergy estimate of $0.46.

The result is a net income breakeven for the Burlington transaction, about $3.58 an Mcf.

So here, prior slide and this slide are two different ways to evaluate the cost competitiveness of this transaction and its resources.

And they’re basically in a relative range of $3.50 to $4.50 per Mcf equivalent.

We believe these metrics are competitive.

Now having looked at that, I would like to transition now to another subject to provide an update on our plans for the remainder of this year.

On slide 21 – I’m going to start with slide 21.

You can see that this is the corporate strategy slide that we presented last November at the New York analyst meeting.

There is no change in this slide, no change in our strategy.

However, what I want to do in subsequent slides is update our operating, investment and financial plans resulting from the Burlington transaction, but update our operating, investment, financial plans for the remainder of this year.

Before going into all of that though, let’s look at slide 22.

You can just see that after the acquisition of Burlington, we are a leading natural gas producer in North America.

Our portfolio is comprised mainly of high-quality, long-lived natural gas reserves.

Our North American presence will be a key component to our total E&P asset base.

It represents a substantial portion of our worldwide E&P production, and we are very confident that there is a lot of upside.

The North America production includes conventional gas, unconventional gas, conventional oil, oil sands and syncrude.

Let me just point out, when you look at this slide, you can see here that 1.15 million BOE a day of production.

This represents about half of our anticipated 2006 worldwide production.

You also see that we have 49 million acres, and we have exposure to many of the producing basins in North America.

We think this is a rather unique position.

So let’s go to slide 23.

You can see how the improvement of all these investments and transactions and our E&P presence in North America also supports our natural gas strategy in North America.

Our capital budget reflects this.

We expect to spend about $5 billion in North American E&P in 2006.

And when you combine this with $2 billion in our domestic refining marketing capital budget, nearly half of our total worldwide corporate spending program is being invested in North America.

Let’s now go to Page 24, long-term growth.

We expect our 2006 production all-in, this includes our share of LUKOIL production, three quarters of production for Burlington, that is from April through December of 2006, all this adds up to approximately 2.4 million BOE a day.

And longer term, we expect growth of around 3 percent a year and this is consistent with our previous communications.

What I would like to do is transition our presentation now to give you an update on our financial plans.

Page 25, you can see our financial strategy.

This slide was used in our analyst presentation.

It is unchanged.

It’s essentially what our strategy is.

However, given the Burlington Resources transaction and the current market environment, we want to update you on our specific plans for the remainder of the year.

So we go to slide 26.

On slide 26, you can see we – no change in our plan.

We’re going to fully fund our expanded capital program, which is what we announced in November, along with the capital program in place for Burlington.

Now with an asset base after the Burlington transaction of $160 billion, we believe some optimization is appropriate.

Accordingly, we expect to have several billion dollars of asset dispositions coming from the upstream and downstream to be made over the next 12 months or 18 months.

These dispositions are not long-lived legacy strategic assets.

Debt reduction will continue to be a high priority, and we have commenced reduction on our debt from what we experienced at peak at the end of the first quarter of 2006.

Beyond debt reduction, we want to have a better balanced financial strategy, which includes share repurchase.

And in fact, so far this year, between ConocoPhillips and Burlington Resources, in the first quarter, we repurchased about $250 million worth of shares.

I shouldn’t say in the first quarter, but so far this year, we purchased $250 million worth of shares.

So given the current environment that we see ourselves operating in, we would expect to continue repurchasing shares at the rate of about $1 billion a year.

We also expect to continue annual dividend increases, and this was evidenced by our most recent increase in the first quarter of 16 percent.

I’m going to Page 27.

You see the price sensitivities.

This slide shows our price sensitivities, which has been updated after the Burlington transaction.

And they’re quoted here on a quarterly basis along with related earnings per share impact.

We’re going to take a look at this, and then I’m going to move on now to Page 28.

We call this the John Carrig slide.

Well, this slide shows you – it gives you an update of the drivers that John shared with you in prior analyst meetings and quarterly numbers.

It’s updated to include our latest estimates.

So you can see the corporate on the left-hand side of the slide, $1.23 billion after-tax.

You can see before the Burlington transaction, our annual corporate expense is $660 million.

We see in 2006 additional integration costs of $60 million over the next number of quarters.

We see your effective tax rate.

Right-hand side of the slide shows turnaround expenses for the year pretax.

For our downstream $385 million, exploration a little over $1 billion and now our DD&A on an annual basis a little over $7 billion.

Going to slide 29.

We are frequently asked what happens to our financial plan with different prices scenarios.

So this slide represents our response to this type of question.

And as you can see on this, just before we go through and explain all of this, the vertical bars, the gold bars, represent cash flow from operations.

And then the shaded green on the top of the gold bar represents our available cash position as we start.

Then behind the vertical bars, you can see the shaded areas where we apply or utilize our cash resources to pay dividends, capital investment, repay debt, increase our ownership in LUKOIL and make share repurchases.

And then you can see under each of these bars, you can see what type price scenario upstream and downstream we are using on the scenario.

You see what happens at the end of the year in our capital structure and over the right-hand side is the slide for comparison purposes.

We just showed what the pricing environment was at the end of yesterday.

So you see the different scenarios.

From the bar on the right, at First Call estimates for cash from operating activities, you can see our debt-to-capital ratio at the end of the year would be 26 percent after funding our dividend, our expanded capital program, reducing debt by $3 billion, completing our purchase or getting up to 20 percent ownership in LUKOIL, and funding a $1 billion share repurchase program.

In addition, you can see the middle bar scenario that leads to a 2006 cash breakeven.

Then the bar on the left, the scenario that funds our capital program and dividend with a lower-price environment.

I want to point out these scenarios do not include any proceeds of sale of assets.

Remember I said several billion dollars that we would sell on strategic assets over the next 12 months or 18 months.

And now to conclude the presentation, I’m going to go to the last slide.

I have got some closing comments and then we’ll go on to the questions you might have.

As we have shown, our strategic objectives, financial goals for the Company remain consistent and unchanged.

We are pleased to start 2006 by enhancing both upstream and downstream through our completion of the two large strategic transactions.

Integration efforts progressing well according to our expectations as the result of commitment of our dedicated global work force.

A key aspect of the integration plan will be to improve our financial results by capturing synergies, as well as optimizing our portfolio.

We also will continue to emphasize the importance of operating excellence and discipline in our capital spending.

As anticipated, we commenced production and we completed our initial deliveries of LNG from our Darwin, Australia, LNG facility in the first quarter.

We expect deliveries of approximately 2 million metric tons of LNG in 2006.

This is consistent with our plans and in subsequent years, we go up to 3 million tons a year for quite a number of years thereafter.

Previously communicated, we anticipated recording our share of reduction from the Waha concession in Libya in late April.

And we expect to substantially recover our underlift position by the end of 2006.

Our downstream business, the Alliance refinery, has returned to normal operations in the middle of April.

Domestically, we anticipate another quarter of significant turnaround activities.

Capacity utilization for the second quarter is expected to be in the mid-90 percent range, and we are at a level a little bit less than the mid-90s at this point in time.

Our turnaround costs will be approximately $100 million before tax in the second quarter and then also in the second quarter, we expect to complete our transition to ethanol-blended gasoline and complete preparations to comply with the new ultra low-sulfur diesel regulations.

Our 2006 capital program, excluding the acquisition of Burlington Resources but including the Burlington remaining 2006 capital program – in other words, second, third and fourth quarter – and the acquisition and initial expenditures on the deep conversion of the Wilhelmshaven refinery all-in, our capital spending is expected to be $18 billion in 2006.

Now this includes loans to affiliates of $1 billion associated with capital program and the estimated investment necessary to bring our ownership in LUKOIL to 20 percent by the end of the year.

So based on First Call consensus, 2006 earnings per share estimates as of April 18, our capital program of $18 billion, including these loans to affiliates, basing our ownership on LUKOIL effectively represents a reinvestment rate of 119 percent of net income.

So this concludes the prepared remarks.

It’s longer than normal, but we had a lot of information that we wanted to share with you.

I think now, Gary and John, we’re ready to respond to questions that callers might have of us.

(OPERATOR INSTRUCTIONS).

Doug Terreson, Morgan Stanley

Hi, Jim and congratulations on your record results.

Thank you, Doug.

You are welcome.

Returning to the financial strategy slide that you just talked about on Page 29, it appears that when using the factors on John’s slide 27 that free cash flow would probably be as much as $3 billion higher, if the forward curve were to be in the ballpark this year and that which would be the case when using the First Call scenario slide on the right part of Page 29.

And on this point, while debt repayment is obviously an important priority post the Burlington transaction and you mentioned that share repurchases would be at least $1 billion per year, my question is whether in that more positive scenario whether the balance between debt and equity reduction would change and if so, why or why not?

I think given that situation that you posed, what we would like to communicate is I think our preference as we go through the second, third, fourth quarters would be to if we have that additional cash flow, to put more of it towards debt reduction to strengthen, and we feel that it is reflected with the stronger balance sheet, less debt.

We see it reflected in better share price.

But as we go through – if this is the pricing environment that we see, we will consider whether we should up our share repurchase.

But I think just for guidance purposes, we will do primarily more towards debt reduction, get the second, third quarter behind us to give consideration to accelerating above $1 billion.

Obviously if we have a stronger pricing environment upstream and downstream as we go through the latter part of 2006 and into 2007, we’re going to be stressing share repurchases more than debt reduction.

Sure.

Okay.

Thanks a lot.

Congratulations again.

John Herrlin, Merrill Lynch

Two quick ones.

Burlington obviously was natural gas leveraged.

Rockies gas prices have been suffering from wider basis differentials.

You had discussed the cost side of the acquisition.

What about bases?

Are you going to plan to hedge more or does having more gas facilitate your marketing operations since you are number two in gas marketing?

Well, first of all with respect to hedging, we really haven’t changed our position on hedging.

We have looked at quite a number of people, buy and sell side analysts and investors have asked us to look at hedging and normally we historically have not done that.

But we look at hedging.

We have used the following one.

It is expensive.

Second, we have accounting – we would not get hedge accounting.

So it would really impact a lot of volatility on our financial reports making it difficult to explain and then third, the basis differential.

So therefore we look at our breakevens and all and we look at what we expect the natural gas pricing environment would be.

For these reasons, we are not interested in doing hedging.

Now with respect to basis differential, we’re working pretty hard on how can we evacuate and move our natural gas production into the marketplace.

And obviously, we do have and have experienced historically basis differential, but we’re participating – I know it doesn’t take place immediately – evacuation routes, new pipelines and all that we think over the medium and long term, we are going to really narrow that basis differential such as what we have experienced and the experience today won’t be going forward over the medium and the long term.

Thank you.

Next one for me is on the asset dispositions.

Burlington didn’t have a lot of short-lived assets other than North Sea.

So is this going to be a combination of upstream assets that will be monetized or will it be more Conoco in derivation?

I think what I tried to say earlier – what we are looking at both upstream and downstream are very mature, late life, nonstrategic, non-legacy assets that we could in this pricing environment sell and realize far more value by selling than we would realize in production over 12 months, 18 months or 24 months.

So not a lot of volume, not a lot of reserves, but we see some of that being done in the upstream.

In the downstream part of the Company, we are looking at are there some areas of either terminals, some small pipeline interests, some marketing assets that we could be looking at that we could monetize.

So it is more several billion dollars from that type assets; nothing that we look at that fits into our medium- long-term legacy strategic assets.

Doug Leggate, Citigroup.

You have shown us these very detailed cash break-even scenarios.

I appreciate the help on that.

However, there are a number of fairly significant projects that potentially lie ahead, Shtokman.

I wonder if you could possibly comment on how you see your chances there.

But also Brass LNG and of course Mackenzie Delta gas.

Can you just talk about what happens to your cash breakeven let’s say over a five-year view if some of those major projects come in, because I imagine the associated capital is quite significant?

Yes, the cash breakevens that we were showing were attributed directly to the Burlington transaction. (multiple speakers)

The cash scenario, sorry.

So what you’re saying, what happens to those cash scenarios given Shtokman, Brass and Mackenzie Delta.

Sure.

Well, in terms of Shtokman your first question was how do we evaluate our position with respect to one of the short-listed companies?

Yes.

We are very interested.

We feel that we submitted a competitive proposal.

We have met with Gazprom leadership.

We are in communication with them.

We expect that we will hear, and all the short-listed companies will hear over the next several weeks, and I believe it looks like now it might be the latter part of May, but we are quite hopeful and this is an important project for our Company and we would like to participate.

But I have nothing really more that I can add to that other than we have submitted a competitive proposal.

With respect to Brass LNG, it is another project that we are quite interested in.

All the projects by the way, upstream, downstream, all over the world, we do see pressure with respect to cost, capital and so we would have to factor all that into all of our projects.

Mackenzie Delta, I think we’re also finding we’re making progress in terms of sorting out some of the outstanding issues.

Hopefully we can be moving this project along with the Alaska Gas Pipeline to fruition.

In other words, these projects take a lot of time to develop and to build, but these are important.

We need to be starting in both Mackenzie Delta and gas pipeline from Alaska, as quickly as possible.

In terms of our cash flow, a lot of our spending – we have been spending over the last several years.

We can see that as we bring those projects on, we then have the freeboard or the ability to bring on these new projects such that we can fund these from our cash flow.

So we have this figured in and we normally share that and show that with you at our annual analyst meeting, but as we complete some of our heavy-oil projects like Surmont, as we complete Bayu-Undan LNG, as we complete some of our refining investments, we find that we certainly have the room to do these things like Shtokman, Mackenzie Delta, Alaska Gas Pipeline and other investments.

The impact in terms of our operating costs in metrics – all these projects have a little different metrics, but we still are looking at having competitive planning and development costs and competitive operating costs compared to existing operations, as well as competitors.

Okay, Jim.

Maybe one brief follow-up.

In previous calls, you have suggested that you were very happy with the ConocoPhillips portfolio prior to the Burlington acquisition.

Is the only thing that has changed there the price environment?

We still are happy with the portfolio we have.

All we are saying and I don’t know if this is your question, the $160 billion in assets, we see that there are several billion dollars that we can use, redeploy in our capital program, debt reduction, share repurchase.

We just think it is the right thing for us to be doing.

So we haven’t changed at all in terms of our basic satisfaction with the portfolio that we have had and what we expect to be spending on and creating the portfolio of tomorrow and five years and 10 years from now.

Arjun Murti, Goldman Sachs

I have two questions related to North American E&P.

Jim, can you just talk about your appetite for additional acquisitions?

Will that be part of growing North American E&P?

I don’t mean necessarily the size of Burlington, which is obviously very large.

But should we expect some amount, $500 million or $1 billion, of ongoing North American-oriented E&P acquisition?

Okay, Arjun, thank you.

One of the things that we have indicated with the Burlington transaction is that we will continue to fund the capital spending and part of that capital spending in Burlington is lease acquisitions, some small acquisitions, some production and in many cases, it is land.

So we will continue to do that.

In other words, continue the program that Burlington has had in the past, we will do in the future.

With respect to large acquisitions, one of the things we’re finding is yes, we paid a very full price for the Burlington transaction.

You have seen the metrics by which we have shown breakevens.

We will look at everything, but I think what we’re finding is that the cost of these things – we have even been looking at a number of things that we, based on what we would be willing to pay, we have not been competitive.

So I think you have seen a new base on what we are willing to spend, but I think it is kind of doubtful for us to go higher than what we have done with respect to the Burlington transaction.

That is very helpful.

And one other question, on the future capital related to the Burlington acquisition for the 9 tcf of drilling inventory, you mentioned a $2 per Mcf development cost.

Burlington’s historic drill bit S&D was more like $1.25.

Last year, it jumped up to $1.60, but still well below the $2 kind of number.

Clearly there is more inflation.

Are you just being very conservative or are you just trying to account for a lot more future inflation or is there some other change to their types of spending that would make development costs as conservative as you are highlighting here?

We expect to be as competitive as they have been in the past.

There is inflation, but that is a quite conservative estimate.

We aired on the side of conservatism rather than get challenged on a number that was too thin.

That’s great.

So down the road, we shouldn’t be surprised if the S&D is actually below this implied $2 number.

Clearly you’re not committing to that, but it could very well be?

That would be our goal.

That’s very helpful.

Thank you.

Neil McMahon, Bernstein

Maybe a few questions.

The first one for John.

John, is there any way you could give us some guidance as to the incremental goodwill on the Burlington deal, if we actually saw a balance sheet for the end of the quarter?

And just hypothetically, if we ended this year with a natural gas price of $7 per Mcf due to the high inventory numbers, how much of that would be exposed to a write-off?

I have got a few follow-ups.

The incremental goodwill can be found at the – I don’t have the numbers in front of me, but we filed an 8-K with the SEC on April 3 I believe and the pro forma adjustments as of year-end are in there.

At $7 an Mcf, we would not expect any exposure to a write-off of goodwill.

Okay.

Just looking at your CapEx going forward, it is obviously right up there with the likes of Exxon and Shell and others.

Given again the low gas price, do you see yourselves changing that CapEx going forward if we continue to see these low natural gas prices relative to when you did the deal with Burlington, or is your CapEx spend for Burlington this year pretty much locked and loaded and maybe for 2007, as well.

And then just a final question for Jim.

Just some comments on Venezuela and the issues surrounding the commentary coming out on the heavy oil taxation.

Thanks.

Jim, I may have some additional comments on the capital.

Our approaches to Burlington and other transactions is we are in this for the long term and obviously with each investment needs to stand on its own, but we would not expect a material reduction in the capital spend in response to the current gas prices like you said up around $7.

We want to be able to spend through a variety of price conditions and markets.

Well, to expand on that, we have the drillable prospects, so we certainly expect that capital program that is associated with the Burlington properties will continue to be essentially locked in as we go through 2006 and 2007, as well as with respect to Venezuela.

Certainly we read all the media comments regarding Venezuela and our investments in Venezuela along with other companies in the industry.

As I have said in past quarterly conference calls, we continue to operate very well in Venezuela.

We have very good operating relationships with partners and with the Venezuelan authorities.

Our people routinely meet with the authorities, PDVSA and ministry.

In fact, here in the next week or two, I believe I am going to be seeing and meeting with Minister Ramirez.

So we will be talking about our investments.

Hopefully the opportunities to expand our investments because we have capability both at Hamaca and Petrozuata to add capacity.

Petrozuata, Hamaca first and foremost on our agenda to talk about and we will and also Corocoro development continues to go quite well right and we’re right on schedule with respect to bring that production onstream.

But we don’t really have anything more to offer other than to say we have good operating relationships, and we are talking and I plan to see the Minister in the next one or two weeks.

Jennifer Rowland, JPMorgan

A question on the capital program.

At the presentation for the Conoco Burlington transaction, you had that 2006 CapEx would be just over $17 billion.

So I was just wondering what has changed to get the guidance up to $18 billion?

Is it just general cost overruns that you’re seeing throughout projects or is it a re-evaluation of the cost that you may have to spend on Burlington projects?

Well, first, we’ve added in the recognized capital spend for three quarters of Burlington.

We also have added a few opportunity projects that have come forth that I’ll just say in the neighborhood of an additional $1 billion that we would like to add to our program, which are good returns.

Then with the strong appreciation of the share price of LUKOIL, the acquisition and the remaining 4 percent at the end of last year was 16 percent.

We have been doing about a 1 percent a quarter.

The additional 4 percent is costing us more to get to 20 percent than we thought.

It is costing us more to buy that, but the value of our ownership in LUKOIL has at least doubled since – more than doubled than what we have acquired the shares for.

So that is primarily – we do have some cost inflation in our capital program upstream and downstream.

But primarily recognition adding for the Burlington transaction, adding about another $1 billion, $1.5 billion of opportunity products that we want to add to our capital program and then the additional cost to get to 20 percent LUKOIL.

Okay.

Great.

And then just a question on LUKOIL actually.

Is it safe to assume that once you reach the 20 percent level that will be it as far as your ownership stake?

Yes.

At 20 percent by agreement, that is the maximum that we can have.

So we get to 20 percent and that is by agreement; that is it.

Paul Sankey, Deutsche Bank

Regarding where you’re looking at your return on capital employed and pooled accounting, does that mean that for future acquisitions, you will be using that methodology as your hurdle rate if you like for the attractiveness of future acquisitions?

Yes, we have to use purchase accounting.

Right.

Okay, so we should consider that is your methodology from now if you like.

The further question I had was on the capital budget again.

If we are looking at – let’s say we’re looking at a $15 billion ongoing CapEx budget, is that a fair number for us to use and would it be fair for us to infer from the cash break-even slide that your breakeven will now be around the $47 WTI mark?

Further to that, would we then if we went below that level reverse your prioritization of cash uses as to what you would cut back on if you like if we were below $47?

So I’m thinking would the last thing to go be the capital budget, or how would you think about it if we were below that level?

Thanks.

Okay, first of all, I think your assumption going forward in subsequent years is something around $15 billion is a good assumption.

And then when you look at – you say, well, breakeven and the different scenarios of capital and all looks like about on the slide 29, $47.37 crude gas $6.6 in crack spread.

Well, a lot depends.

You may have a stronger or a weaker upstream or downstream, but we obviously have a lot of latitude there where we could, if we look at lower priced environments, say the mid-$40 oil price, and we say it is going to last for some extended period of time, we can adjust our capital program.

We also can defer some projects.

We would have to take a look at what we think is taking place upstream and downstream.

But I think in terms of dividends, we are very strong on the discipline of annual increases in dividends.

We would expect by the time, if we were to see a lower pricing environment like this, we would have gotten our balance-sheet debt down dramatically over the next 6 months, 12 months and 18 months, that we have a lot of optionality with respect to how to respond and adapt to a lower-pricing environment.

Is it fair to say then that this past level of debt would be a peak level?

You wouldn’t obviously want to go beyond that?

Oh, no.

We are moving the debt down.

We would like to see the debt moving down to the low 20s and then longer term – medium-to-long term, we would like to see our debt be between $15 billion and $20 billion.

Debt ratio is going to be down in the mid-teens by then.

Just to be very clear then, so you are basically looking all things equal at a $15 billion type outlook for your annual CapEx as a kind of run rate that we should consider for the years approaching, assuming that we stay in the 47 plus type environment?

That’s correct because we have a rather unique situation.

We have the projects over the next five to 10 years that we see the spending at that level with good returns out of that kind of a spend program.

Great.

Thanks.

I’ll leave it there.

Nicki Decker, Bear Stearns

My question is on your synergy estimates on Page 17.

Just four questions if I could.

First of all, could you apply a dollar amount to each of the five items on that page?

Secondly, the operating expense reductions just given that Burlington Resources operations are at a pretty low cost and that you have talked about possibly applying Burlington Resources operating excellence at ConocoPhillips sales, just elaborate if you would on where you envision the realization of those operating expense reductions.

Thirdly, the volume enhancements.

Would you please just clarify what you mean by that?

And lastly, how should we look at a time frame for realization of these synergies?

Thank you.

Okay.

Nicki, we don’t have a specific breakdown by category of those cost centers as it were that we are sharing with people.

We would expect operating expense reductions will occur over the full gamut of things, but we would expect that some rationalization of activity by being more highly concentrated in different basins would help us achieve operating expense reductions and we to focus on operating excellence.

And then you are right that if you – to the extent that you view the Burlington assets as the lower cost of the two – then we would expect to benefit from sharing of that knowledge and information.

On volume enhancements, that is going to come through application of best practices and in certain cases through say in a place like San Juan where we are able to optimize the positions of both ourselves and Burlington to add volume enhancements.

And then finally for the time frame.

We would expect to have the full run rate of this available to us in 2008.

So it’s going to ramp-up to this number between now and then.

Mark Gilman], Benchmark Company

I had a couple of things.

First on the synergy thing also.

I wonder if you can give me an idea of the quantifiable level of work force reductions and office closings that were part of the initial estimate and how that has been revised with respect to the new estimate?

We see work force reductions – I don’t have a head count number for you at my fingertips.

We can try to see what we have available, but we see that there will be some reductions and those will take place from now to say a year from now, some a little bit longer.

As we run our businesses – we have to run our businesses initially, the systems part of the business in parallel, and when it gets converted over, we would expect to realize more synergies.

So I think a good proxy for that, Mark, is – on Page 18, we had the capitalized purchase price item, as well as the corporate segment expense and the corporate segment, you can see trails down.

And the capitalized purchase price would take a similar pattern.

And the synergies would get captured in greater amounts in more of a reciprocal pattern.

No number on office closings, John?

No, no.

I don’t have a number available.

We can – maybe Gary could back with you, Mark.

Let me try something else, if I could.

John, can you help me understand how you are booking the LNG revenue associated with Bayu?

When I look at the Timor Sea gas realization in the quarter, even recognizing the limited number of cargoes that were shipped, it scarcely moved at all.

What am I missing in terms of the way in which that revenue is being reported?

It doesn’t get reported as Mcf sold.

It is LNG revenue.

It is a separate item of revenue.

So it is not reported at all in your gas price realization?

No, it is not and neither is Timor.

So it is not reflected in any of the upstream realizations anywhere?

LNG realizations, Mark.

I think there’s an LNG realization somewhere but I’d have to go through the –.

There’s a Kenai LNG realization, but if there is one on Bayu, I didn’t see it.

It may not be in this first quarter, but it will be.

I will call you later and show you where it’s at, Mark.

Okay.

That’s fine.

One final one.

Give me an idea if you could the production level at Magnolia and whether it is at plateau.

Can I get back with you on that?

I will call you after the call.

Thanks a lot.

That’s all I have.

Mark Flannery, Credit Suisse

I have got two quick ones.

One is could you break down the $15 billion in underlying CapEx between upstream, downstream and other just roughly for us?

Okay.

I think what we would do is – I don’t have it right in front of me, but you should go to the New York analyst presentation, and it is a very good approximation of just what it is because what we have done is we added on the additional cost for the LUKOIL getting up to 20 percent and then we have added on let’s say about $1 billion or $1.5 billion of additional opportunities, and I think you can split those somewhere roughly half upstream, half downstream.

And you get a pretty good number and then you know the additional capital for Burlington is all upstream and so that is how I would respond to it.

But I think Gary can come back to you with the detail on the numbers.

Yes.

I can get you the actual makeup of the $15 billion, Mark.

I can do that.

That’s great.

And one quick follow-up is at consensus earnings estimates or consensus oil price forecasts or whatever, just at a consensus pace, what would you expect stock-based compensation to run at in 2006?

Are you going to tell me the multiple?

Well, just say now if this is the end of the year and nothing much has changed?

The stock-based compensation is dependent upon obviously to some extent the stock price.

Right.

And there is some accretion numbers that are applied to a variety of factors, including the demographics of the participants.

So I don’t have that number in my --.

I guess what I am trying to get to is an idea of what net share repurchase is going to be.

I assumed the $1 billion that we’re talking about today is a gross number, which will be somewhat offset by increases in shares for compensation purposes.

Sure.

We can get that for you.

Thank you.

Bruce Lanni, AG Edwards

Good morning, gentlemen.

Good quarter.

Listen, I may have missed it in your prepared comments, but can you provide any further information of why the carry-over for R&M, the turnaround cost, is going to be so high in the second quarter?

And then I had a follow-up on the comments Jim talked about on the asset sales and divestitures.

Now I understand in the scheme of things they are not meaningful to the overall size of the Company, but are the numbers for the production and reserves factored into the growth profile you provided us and about, if you could, what percentage of production or reserves do you plan to sell?

Well, first of all, first, we don’t really know.

We have got a number of assets that we’re going to test the market on.

We know that the market is pretty good, but I would say this.

It’s a very nominal amount of production and impact on reserves.

And to say anything more than that is not really fair to – I would be saying more than what we know we ultimately will do.

It is not fair with respect to the Company itself internally, because we were just trying to communicate that we see several billion dollars of upstream downstream in cumulative asset disposition.

So it is just going to have a very minimal impact on reserves production and very modest impact on net income.

I think the other question was –.

The turnaround costs, Bruce – they were $163 million in the first quarter and we increased the total turnaround costs for the year from $350 to $385 by about $35 million.

And that in part was due to some costs in the first quarter that were higher than we expected.

We do expect some increase through the balance of the year.

The second quarter is not – I don’t recall – but is not materially higher than what we had previously forecast.

It’s exactly what we forecast.

In fact, it’s not unusual to have a heavy first quarter and then a semi-heavy second quarter, which is exactly what we have.

Well, thank you very much.

Ladies and gentlemen, this does conclude our question-and-answer session.

I would now like to hand the presentation back to Mr. Gary Russell for closing remarks.

Again, we want to thank everyone who participated this morning for your interest in ConocoPhillips and remind you that the presentation material that was used today along with a replay of the webcast of this teleconference will be available on our Web site.

You can find that at www.conocophillips.com.

Thank you.

Ladies and gentlemen, we thank you for your participation in today’s conference.

This concludes the presentation and you may now disconnect.

Have a good day.

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Therefore, actual outcomes and results may differ materially from what is expressed or forecast in such forward-looking statements.

Factors that could cause actual results or events to differ materially include, but are not limited to, crude oil and natural gas prices; refining and marketing margins; potential failure to achieve, and potential delays in achieving expected reserves or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas; unsuccessful exploratory drilling activities; lack of exploration success; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying company manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; international monetary conditions and exchange controls; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; general domestic and international economic and political conditions, as well as changes in tax and other laws applicable to ConocoPhillips’ business.

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