Gary Russell, General Manager, Investor Relations James Mulva, Chairman, Chief Executive Officer John Carrig, Executive Vice President of Finance, Chief Financial Officer

Douglas Terreson, Morgan Stanley John Herrilly(?), Merrill Lynch Doug Leggate, Citigroup Arjun Murtie, Goldman Sachs Neil McMahon, Sanford Bernstein Jennifer Rowland, JP Morgan Paul Sankey, Deutsche Bank Nicole Decker, Bear Stearns Mark Gilman, Benchmark Capital Mark Flannery, Credit Suisse First Boston Bruce Lanni, AG Edwards

Operator instructions.: Gary Russell, General Manager, Investor Relations: Thanks, Jen, and good morning and welcome to ConocoPhillips Q1 conference call. I’m 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 Q1 2006, 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 Q1. Jim’s remarks will last approximately 45 minutes and then the remainder of the time will be available for your questions. On page two, you can read the Safe Harbor statement. It says among other things that our presentation today along with our responses to your questions will include forward-looking statements regarding our current expectations. The 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 CEO of ConocoPhillips, Jim Mulva. James Mulva, Chairman, Chief Executive Officer: Gary, thank you, and I also appreciate all those that are joining us today for our Q1 earnings conference call. We appreciate your interest in our company and so I’m going to start my comments on slide, or page, number three. As you can see, during the quarter we completed the acquisition of Burlington Resources, and we’re pleased with the progress we’re making toward integrating the combined companies. This transaction establishes our company as a leading natural gas producer in North America, with a portfolio of high-quality long-life gas reserves. We also in Q1 completed the acquisition of the Wilhelmshaven Germany refinery. Now this is in line with our strategy to refine our global refining presence. We also advanced plans to upgrade the refinery to allow it to process high-sulphur crude into more valuable high-end products. During the quarter we generated $3.3 billion net income, $4.8 billion in cash flow. We continued to fund our capital program and other investments by effectively reinvesting 141% of our Q1 net income back into our businesses. We increased our dividend in Q1 by 16%. Now because of the Burlington Resources transaction we ended the quarter with a debt to capital ratio of 30%, and I’m going to go through this with additional details in our updated plans for the remainder of the year in subsequent slides. For Q1 2006, our E&P production – now this excluded the LUKOIL segment, and there’s no recognition of volumes from Burlington Resources – our production was 1.61 million BOED, which is slightly higher than Q4 2005. Our estimated share of LUKOIL’s production in Q1 is 322,000 BOED, and this reflects primarily our increased equity ownership position. On the downstream, our refineries ran at 85% and accrued processing capacity that’s down 3% from Q4. Our average diluted shares outstanding in Q1 was around 1.4 billion, while our diluted shares outstanding on the last day of March was 1.68 billion, and this reflects from date to completion of the Burlington Resources acquisition. I’m moving on to the next slide, page four. 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 Q4. The net effect of all this, along with other market impacts, reduced our Q1 net income by $482 million as compared to Q4. Our Q1 net income was negatively impacted by $242 million. 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 Q4, mainly the result of reduced hurricane-related maintenance expense or utility costs partially offset by a higher turnaround cost in the downstream. Q4 was negatively impacted to $103 million from the results of discontinued operations as well as accumulative effect from the adoption of a new accounting rule. Other items impacting our earnings for Q1 include lower exploration expenses, reduced impact of FX. Also, we did not incur early debt retirement premiums during Q1 like we did in Q4 2005. These benefits were partially offset by the cost associated with the unplanned down time at the Excel Paralubes facility at our Lake Charles refinery. The net effect of all these other items was improvement of $112 million shown in the slide in the Q1 earnings as compared with Q4. You can see it all rolls up to $3.3 billion for Q1 2006. Now I’m going to slide five. You can see we started the quarter over with a cash balance of $2.2 billion, we generated $4.8 billion from operations in Q1, we completed the acquisition of Burlington Resources and in so doing we acquired or picked up $33.3 billion in cash. We then issued debt of $15.3 billion, then paid $17.5 billion which is the cash part of the transaction to acquire Burlington Resources. We funded our capital and other investment activities amounting to $4.6 billion in the quarter, and paid dividends of $496 million. After you consider the other sources and uses of cash through all of this, we ended Q1 with a cash balance of $3 billion. I’m going on to slide six, the debt ratio slide. The bar chart on the left shows the equity grew to $73 billion at the end of Q1, mainly as a result of the Burlington Resources acquisition. If you look at our earnings plus dividends, in that $73 billion, we increased retained earnings $2.8 billion in Q1. The balance sheet debt increased to approximately $32 billion, resulting in a debt to capital ratio of 30% at the end of Q1. I’m going to slide seven to compare E&P Q1 2006 with Q4 2005. You can see how worldwide oil prices were up 7% from the previous quarter, up to $56.63 a barrel. Our global realized natural gas prices were down 9% from Q4 to $7.24 in MCF. Our production in Q1 was slightly higher than in Q4, up about a little bit more than 1% or 20,000 BOED. However, notice that both our crude oil and natural gas sales volumes were lower than the previous quarter. Exploration expenses were lower, as I said earlier we completed the acquisition of Burlington Resources at the end of Q1 2006. We’re going to slide eight now. The slide illustrates the variance in production between Q1 2006 and last year. We saw higher production from Timor Sea, Venezuela, Lower 48, and the increased production was offset by on-schedule shutdowns at Prudhoe Bay as well as lower production volumes from Canada. Other negative impacts to our production in Q1 include the impact of higher crude prices on our production-sharing contracts, pretty small though, but production-sharing contracts in Vietnam and Indonesia. Then when you add the 1.61 million BOED, the 322,000 BOED which is our estimate of our equity share of LUKOIL’s production, then you see how we get to the 1.932 million BOED for Q1. I’m going on to page nine, to talk about income from the last quarter of 2005 and Q1 2006, and you can see Q1 increased $127 million to $2.55 billion. Our Q1 results were improved $180 million over Q4 2005 mainly due to lower negative impact in Q1 of the mark to market valuation of some of our natural gas contracts – United Kingdom. We had the benefit of higher realized oil prices (inaudible), would offset the effect of lower realized natural gas prices. As I said earlier, all our oil and gas sales volumes reduced Q1 at income by $159 million. This is a result of Q1 being shorted by two days as compared to Q4, along with the timing of our crude oil (lift feeds?) Exploration expenses were $68 million lower due to lower dry hole costs or recent experiments(?). Other factors that improved our Q1 net income compared to Q4 2005 which included lower hurricane related charges from insurance mutuals, and reduced impact of foreign exchange. I’m going now to slide 10, we’re moving to Refining & Marketing comparisons of Q1 2006 versus Q4 2005. You can see our worldwide R&M margins were significantly lower than the previous quarter. In the US, our Q1 realized US crack spread declined $2.53 per barrel to $10.28 per barrel. Our international realized crack spread declined $3.72 per barrel to $5.01 per barrel. Our US refining system ran at 83% of stated capacity, so that’s down 2% from the 85% in Q4 last year. This is a result of heavy turnaround activities and unplanned down time. We’re going to talk more about this in a moment. Our international refining system ran in Q1 94% of stated capacity, so that’s down 8% from Q4 and that’s primarily due to unplanned down time. So we’ll discuss the turnaround activity and this unplanned down time on the following slide, but before I leave, the turnaround expense in Q1 amounted to $163 million pretax for the quarter, and that’s higher than we expected. It’s $77 million higher than we had in Q4 2005. I’m moving to slide 11. As you can see, our R&M net income was significantly lower than Q4 2005, down $583 million or 60% to $390 million in Q1 2006. We experienced lower worldwide crack spreads, lower marketing margins along with other market 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. As a result, the (phase fire up?) of certain processing units caused the majority of Alliance production in Q1 2006 to be lower value intermediate volumes, rather than the higher value clean products. The lower volume is primarily due to turnaround activity and unplanned down time at our refineries. We reduced our net income $100 million. 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 turnaround of Bayway which was originally scheduled for later this year, but we had to accelerate it into Q1 2006 to address operational issues. Then we had unplanned down time at Lake Charles, Bayway, Trainer, Ferndale and the Humber Refinery in the UK. The results of all this planned and unplanned down time was a utilization rate worldwide of 85%. Operating costs were lower than the previous quarter, and helped us $99 million, driven by lower maintenance costs and normal maintenance costs, including those that are hurricane-related and by lower utilities. This was offset by higher turnaround costs and earnings in the quarter were further improved compared to the previous quarter by $83 million as 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 have 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 US but to some extent in other parts of our system. I’m going to move now to page 12, going from R&M to our LUKOIL investment. You can see we increased our equity ownership by 1%, in the quarter up to 17.1%. As a result our average ownership for the quarter was 16.6%. Our estimated equity earnings for Q1 for LUKOIL were $249 million, that’s up from $189 million in Q4. The increase is mainly attributable to higher realized crude prices and increased ownership. I’m going to slide 13 now, which addresses the Midstream and chemicals, joint ventures and emerging businesses. You can see that earnings from Midstream in Q1 was $110 million, a decline of $37 million from Q4, and this is primarily due to lower natural gas liquid prices. Turning to our Chemicals joint ventures, the earnings improved $35 million in Q1, up to $149 million. That’s primarily attributable to higher polyolefin margins, partial settlement of a business interruption claim, in addition to olefins and polyolefin sales volumes recovered from the prior quarter hurricane impacts. Emerging Businesses have a relatively small impact to the company’s performance. They were slightly positive improved compared to Q4 2005. This is primarily attributable to domestic and international power operations. Moving to slide 14, which is the corporate element, you can see the corporate segment impact on net income was a loss of $168 million in Q1, and interest expense was $37 million lower than Q4. Corporate overhead was $11 million higher, mainly due to benefit related charges in Q1. All the other factors which compare Q1 results generally relate to issues that favorably impacted the corporate segment in Q4 but did not recur in Q1. Having looked at the corporate side, the presentation so far is our normal presentation, it’s focused on our performance operating and financial performance in Q1. What I would really like to do now on 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. So what I’m going to do is I’m going to start on this next slide with our ROC analysis. You can see, we have made some changes in our presentation of the ROC analysis, and this is to reflect and better represent the performance and the impact of ultimately, going forward, the Burlington Resources 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 loss of the highest peer group – and we say the peer group, as you know in the past it’s the largest publicly-traded, integrated companies, and that includes Chevron, Total, Shell, BP and Exxon. So looking at this slide, you can see we 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. Going forward, in subsequent quarters and annual presentations, we’re not going to make purchase accounting adjustments for ConocoPhillips. In the shaded area for our peers, we will make adjustments for our estimate of the pooling benefit they received from past major business combinations in determining and representing their ROCE. So the barchart reflects ConocoPhillips ROCE without adjustments for purchase accounting. We have, for presentation purposes, excluded the impact of Burlington Resources acquisition from capital employed since no income from Burlington Resources is included in our Q1 net income. Remember, that transaction was completed the very last day of Q1. So you can see the adjustments that we made for major business combinations to arrive at an ROCE of our peers, and this is further reflected, if you want to look at the numbers, (inaudible) table one 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. If you look at the right bar, the annualized ROCE for ConocoPhillips, Q1 2006 was 20%. In that 20%, I’ll just give you what the various segments are: E&P is 22%, R&M about 8%, Midstream Chemicals about 31%, LUKOIL 17%, a combination of all this is 20%. If we go on to the next slide, 16, we’ve made some changes to our executive management team, and this comes really as a result of retirements and also the Burlington Resources acquisition. As you can see, Randy Limbacher who was formerly COO 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 a Senior Vice President, that’s far more focused on leadership and management of our large capital projects around the world as well as the technology to support upstream and downstream. So now I’m going to go on to page 17, which talks about the synergy associated with the Burlington Resources transaction. When we announced it back in December 2005, we said our estimate of synergies was $375 million pretax. Integration has gone very well. We were very organized, worked very hard and all of the Burlington Resources, ConocoPhillips employees have been identified, we’re well on our way with all the implementation, who’s going to do what. Synergies were certainly not the primary driver for the acquisitions, but they’re important to us and we have the accountability in place as we have done with prior transactions to capture them. Earn estimates is now $500 million pretax. You can see on the right hand side of the slide, the areas where we expect to capture these synergies. I’m going to move on from the synergies slide to page 18, transaction costs. Our latest estimate of non-recurring transaction costs associated with the Burlington Resources transaction include $176 million capitalized as part of the purchase price. These costs are generally employee-related costs incurred by Burlington Resources such as severance, benefits, out placement and relocation. Then we expect to incur a restructuring and transition cost, totally $60 million in 2006 and $20 million in 2007. These will be reflected in our reporting in future quarterly periods in our corporate segment. We expect our E&P segment to incur an additional $34 million in 2006 and $12 million in 2007, and this represents our estimate of employee retention costs. What I’m going to do on the next two slides is go back and look at the Burlington Resources transaction from two different perspectives. First, we’re going to look at the breakeven, for the acquired resource base, then we’re also going to look at the net income breakeven, and it’s based on what we expect to see in our future income statements going forward. First, on slide 19, this is Burlington Resources acquisition. If we use the year end 2005 book reserves, along with Burlington Resources having probable unproved drilling inventory, which was about 5.6 Trillion Cubic Feet, Burlington Resources base then is approximately 18.1 TCF. Based on a full purchase price of $34 billion, that translates to a unit acquisition cost of about $1.88 MCF equivalent, which is at the top of the slide. Then we add to that a future estimated capital cost of about $2 MCF equivalent, that we assume will be spent to develop both the proved and the unproved drilling inventory which approximates to 9 TCF equivalent. Spread over the full resource base of 18.1TCF equivalent, that represents about $1.00 MCF equivalent. Then operating costs and taxes other than income tax add about $1.40 MCF equivalent and $0.32 MCF equivalent respectively. 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 breakeven acquisition cost for Burlington Resources proved reserve at known inventory available prospects is 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 $2.32 MCF equivalent. To this you should add operating transportation costs, $1.40 MCF equivalent, and taxes other than income tax of $0.32 and assume a full year run rate of our synergy estimate of $0.46, the results is a net income breakeven for the Burlington Resources transaction: about $3.58 in MCF. The prior slide and this slide are two different ways to evaluate the cost competitiveness of this transaction and its retorches(?). They’re basically in a relative range of $3.50-4.50 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, you can see that this is the corporate strategy slide that we presented last November at the New York analysts meeting. There’s 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 Resources transaction, but update our operating, investment and 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 Resources, we are a leading natural gas producer in North America. Our portfolio is comprised mainly of high quality, long life natural gas reserves. Our North America 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 there’s a lot of upside. North American production includes conventional gas, unconventional gas, conventional oil, oil sands and thin crude. Let me just point out, when you look at this slide, you can see here 1.15 million BOED of production. This represents about half of our anticipated 2006 worldwide production. We 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. Let’s go to slide 23 to see how the improvement of all these investments and transactions on our E&P presence in North America supports also our natural gas strategy in North America. Our capital budget reflects this. We expect to stand about $5 billion in North America E&P in 2006. When you combine this with $2 billion in our domestic R&M capital budget, here is half of our total worldwide corporate spending program, being invested in North America. Let’s go now 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 Resources, that is from April through December of 2006 – all this adds up to approximately 2.4 million BOED. In longer-term, we expect growth of around 3% a year and this is consistent with our previous communications. What I’d like to do is transition our presentation now to give you an update on our financial plans. Slide 25, you can see our financial strategy. This strategy slide was used in our analyst presentation, it’s 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 there is no change in our plans. 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 Resources. Now with an asset base, after the Burlington Resources 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 12-18 months. These dispositions are not long life, vitacy(?) strategic assets. That reduction will continue to be a high priority, and we have commenced deduction on our debt from what we experienced at the end of Q1 2006. Beyond debt reduction, we want to have a better balanced financial strategy which includes share repurchase. In fact, so far this year, between ConocoPhillips and Burlington Resources, in Q1 we repurchased about $250 million worth of shares. I say in Q1, but so far this year we have 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 with annual dividend increases and this was evidenced by our most recent increase in Q1 of 16%. I’m going to page 27, you’ll see the price sensitivities. This slide shows our price sensitivities. It has been updated after the Burlington Resources transaction and their (quarters are on a?) quarterly basis, along with related EPS impact. You can take a look at this and I’m going to move on now to page 28. We call this the John Carrig slide, this slide shows you and gives you an update of the drivers that John shared with you in the prior analyst meeting, 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 Resources transaction, our annual corporate expenses $660 million. We see in 2006, there’s still integration costs of $60 million over the next number of quarters. You see our effective tax rate. On the right hand side of the slide, it shows turnaround expenses for the year, pretax for our downstream, $385 million, exploration a little over $1 billion, and 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 price scenarios, so this slide represents our response to that question. As you can see on this, before we go through and explain all of this, the vertical bars, the gold bars, represent cash flow from operations. 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. 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 and our capital structure, and over the right hand side is a 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%, after funding our dividends, our expanded capital program reducing debt by $3 billion, completing our purchase or getting up to 20% ownership in LUKOIL and planning a $1 billion share repurchase program. In addition, you can see the middle bar, a scenario that leads to a 2006 cash breakeven, then the bar on the left is 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 from the sale of assets. Remember, I said several billion dollars that we would sell non-strategic assets over the next 12-18 months. Now to conclude the presentation, I’m going to go to the last slide. I’ve got some closing comments, then we’ll go on to the questions you might have. As we’ve 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 to our completion of two large strategic transactions, and integration efforts are progressing well, according to our expectations through the results of the commitment of our dedicated global workforce. Key aspects of the integration plan will be to improve our financial results by capturing synergies, as well as optimizing our portfolio. It also will continue to emphasize the importance of operating excellence and discipline in our capital spending. As anticipated, we commence production and we completed our initial deliveries of LNG from our Darwin, Australia LNG facility in Q1. We expect deliveries of approximately 2 million metric tons of LNG in 2006. This is consistent with our plans. Then in subsequent years we go up to 3 million tons a year for quite a number of years thereafter. As previously communicated, we anticipated recording our share of production from the Waha concession in Libya in late April and we expect to substantially recover our under-lift 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 Q2 is expected to be in the mid 90% range and we’re 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 Q2. Then also in Q2 we expect to complete our transition to ethanol-blended gasoline and complete preparations to comply with the new ultra low sulphur diesel regulations. Our 2006 capital program, excluding the acquisition of Burlington Resources, but including the Burlington Resources remaining 2006 capital program, in other words Q2, Q3 and Q4, 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. This includes loans to affiliates of $1 billion associated with the capital program and the estimated investment necessary to bring our ownership in LUKOIL to 20% by the end of the year. Based on first call consensus, 2006 EPS estimates as of April 18th, our capital program of $18 billion including these loans to affiliates, increasing our ownership in LUKOIL, effectively represents a reinvestment rate of 119% of net income. This concludes the prepared remarks, 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.

OK, we’re ready for questions.

Operator instructions.: Q - Douglas Terreson, Morgan Stanley: Hi, Jim, and congratulations on your record results.

Thank you, Doug. Q - Douglas Terreson, Morgan Stanley: You’re welcome, but 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, than that which would be the case when using the first call scenario slide on the right part of page 29. On this point, while debt repayment is obviously an important priority post the Burlington Resources transaction, and you mentioned that share repurchases would be at least a billion dollars per year, my question is, in that more positive scenario, whether the balance between debt and equity reductions would change and if so, why or why not? A - James Mulva: Well, I think given that situation that you posed, Doug, what we’d like to communicate is I think our preference as we go through Q2, Q3 and Q4 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 reflective with a stronger balance sheet, less debt we see reflected in a better share price. But as we go through it, 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’ll do primarily more toward debt reduction, get Q2 and Q3 behind us, give consideration to accelerating above one 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. Douglas Terreson, Morgan Stanley: Sure. OK. Thanks a lot and congratulations again.

Q - John Herrilly(?), Merrill Lynch.: Hi, two quick ones. Burlington Resources obviously was natural gas leveraged, Rockies gas prices have been suffering from wider basis differentials. You discussed, kind of, 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’re number two in gas marketing? A - James Mulva: First of all, with respect to hedging, we really haven’t changed our position on hedging. We look, and we have looked, and quite a number of people – buy and sell side analysts and investors – have asked us to look at hedging. Normally we historically have not done that. When 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. Third, the basis differential. So therefore, we look at our breakevens in all and we look at what we expect the natural gas pricing environment would be, and for these reasons, we’re not interested in doing hedging. With respect to basis differential, we’re working pretty hard on how we can evacuate and move our natural gas production into the marketplace. Obviously we do have experience historically on basis differential, but we are participating on ‘no, it doesn’t take place immediately’. Evacuation routes, new pipelines, in all we think over the medium to long term we’re going to really narrow that basis differential, such as what we have experienced. The experience to date won’t be that going forward over the medium and the long term. Q - John Herrilly(?), Merrill Lynch.: OK, thank you. The next one for me is on the asset dispositions. Burlington Resources didn’t have a lot of short life assets, other than the North Sea. So it this going to be a combination of upstream assets that will be monetized, or will it be more Conoco in derivation? A - James Mulva: Well, I think as I tried to say earlier, what we are looking at, both upstream and downstream, are very mature, late-life, non strategic, 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, 18 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 monatize. So it’s more several billion dollars – that type of assets. Nothing, if we look at it, that fits into our medium-long term legacy strategic assets. John Herrilly(?), Merrill Lynch.: Thanks.

Your next question comes from Doug Leggate with Citigroup. Q - Doug Leggate, Citigroup: Thank you, good morning, gentlemen. You’ve shown us these very detailed cash breakeven scenarios, and I appreciate the help on that. However, there are a number of fairly significant projects that potentially lie ahead: Stockman, I wonder if you could possibly comment on how you see your chances there, but also Brass LNG and of course Mackenzie Delta gas. Could 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? A - James Mulva: Yes, the cash breakevens that we were showing were attributed directly to the Burlington Resources transaction. Or – what are you saying? A - John Carrig(?): He really means cash scenarios. Q - Doug Leggate, Citigroup: The cash scenarios, sorry, yes. A - James Mulva: OK. So what you’re saying, what happens to those cash scenarios given Stockman, Brass and Mackenzie Delta? Q - Doug Leggate, Citigroup: Sure. A - James Mulva: Well, in terms of Stockman, your first question was how do we evaluate our position with respect to one of the short-listed companies. We’re very interested, we feel that we submitted a competitive proposal, we’ve met with Gazprom leadership, we’re 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, we’re quite hopeful and this is an important project for our company. We’d like to participate, but I have nothing really more that I could add to that, other than we’ve submitted a competitive proposal. With respect to Brass LNG, it’s another project that we’re 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’d have to factor all of that in to 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 that hopefully we can be moving this project along with the Alaska Gas pipeline to fruition. In other words, these are all – these will probably take a lot of time to develop and to build, but these are important. We need to be studying them, both Mackenzie Delta and our gas pipeline from Alaska(?) as quickly as possible. In terms of our cash flow, a lot of what we have been spending over the past several years, we can see that as we bring those projects on, we then have the free board, or 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 show that with you at our annual analyst meetings, but as we complete some of our heavy oil projects, like Stormount(?), as we complete London LNG(?), as we complete some of our refining investments, we find that we certainly have the room to do these things like Stockman, Mackenzie Delta, Alaska Gas pipeline and other investments. The impact in terms of our operating costs and metrics – all these projects have different metrics, but we still are looking at finding development costs and competitive operating costs, compared to assisting operations as well as competitors. Q - Doug Leggate, Citigroup: OK, Jim. Maybe one brief follow up, in previous calls you suggested that you were very happy with the ConocoPhillips portfolio prior to the Burlington Resources acquisition. Is the only thing that’s changed there the price environment? A - James Mulva: We’re still happy with the portfolio we have, all we are saying and I don’t know if this is your question, but $160 billion in assets, we see that there’s several billion dollars what we can use, redeploy, in our capital program, debt reduction, share repurchase, we just think it’s 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’ve had and what we expect to be spending on and creating the portfolio of tomorrow, and you know, five years and ten years from now. Doug Leggate, Citigroup: Great. Thanks a lot, Jim.

Your next question is from Arjun Murtie with Goldman Sachs. Q - Arjun Murtie, Goldman Sachs: Thank you. I have two questions related to North American E&P. 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 Resources, which is obviously very large, but should we expect some amount – you know, $500 million or $1 billion – of ongoing North American-oriented E&P acquisitions? A - James Mulva: OK, Arjun, thank you. One of the things that we have indicated with the Burlington Resources transaction is that we will continue to fund the capital spending. Part of that capital spending in Burlington Resources is lease acquisition, some small acquisitions, some production – in many cases it’s land. So we will continue to do that. In other words, continue the program that Burlington Resources 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 Resources transaction, you’ve seen the metrics by which we’ve shown breakevens. We will look at everything, but I think what we’re finding is that the cost of these things – we’ve even been looking at a number of things based on what we would be willing to pay, we have not been competitive. So I think you’ve seen a new base on what we’re willing so spend, but I think it’s kind of doubtful for us to go higher than what we’ve done with respect to the Burlington Resources transaction. Q - Arjun Murtie, Goldman Sachs: Great. That’s very helpful. One other question: on the future capital related to the Burlington Resources acquisition, for the 9 TCF of billing inventory you mentioned a $2 MCFe development cost. Burlington Resources’ historic drill bit S&D was more like a $1.25. Last year’s jumped up to $1.60. But still, well below the $2 kind of number. Clearly there’s 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 the development costs as conservative as you’re highlighting here? A - James Mulva: We expected to be as competitive as they have been in the past. There is inflation, but that is a quite conservative estimate. We erred on the side of conservatism rather than get challenged on a number that was too thin. Q - Arjun Murtie, Goldman Sachs: That’s great. So down the road, we shouldn’t be surprised if CFND(?) is actually below this implied $2 number? Clearly you’re not committing to that, but it could very well be? A - James Mulva: That would be our goal. Q - Arjun Murtie, Goldman Sachs: That’s very helpful, thank you.

Your next question is from Neil McMahon with Sanford Bernstein. Q - Neil McMahon, Sanford Bernstein: Hi. 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 Resources 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? Then I’ve got a few follow-ups. A - John Carrig: I don’t have the numbers in front of me, Neil, but we filed an 8-K with the SEC on April 3rd, I believe, and the pro forma adjustments as of year end were in there. At $7 an MCF, we would not expect any exposure to a write-off of goodwill. Q - Neil McMahon, Sanford Bernstein: OK. Just on looking at your CAPEX going forward, it’s 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 Resources, or is your CAPEX for Burlington Resources this year pretty much locked and loaded and for maybe 2007 as well? Then just a final question for Jim, just some comments on Venezuela and issues surrounding the commentary coming out on the heavy oil taxation? Thanks. A - John Carrig: Jim may have some additional comments on the capital, but our approaches to Burlington Resources and other transactions is we’re in this for the long term. Obviously each investment needs to stand on its own, but we would not expect a material reduction in the capital spend in response to a gas price like you said of around $7. We want to be able to spend through a variety of pricing conditions and markets. Jim? A - James Mulva: Well, to expand on that, we have the drillable prospects so we certainly expect that capital program that’s associated with the Burlington Resources properties will continue to be essentially locked in as we go through 2006 and 2007 as well. With respect to Venezuela, certainly we read and all the media comments regarding Venezuela, and our investments in Venezuela, along with other companies in the industry. As I 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 the ministry?), in fact here in the next week or two I believe I’m going to be seeing and meeting with Minister Ramirez, so we’ll be talking about our investments. Hopefully the opportunities to expand our investments, because we have capability for Hamaca and Petrozuata to add capacity. So said, Hamaca and Petrozuata are first and foremost on our agenda to talk about, and we will, and also the Corocoro development continues to go quite well, and we’re right on schedule with respect to bringing that production on screen. But I don’t really have anything more to offer, other than to say we’ve good operating, good relationships, we are talking and I plan to see the minister in the next one or two weeks. Neil McMahon, Sanford Bernstein: Great, thanks a lot.

Your next question is from Jennifer Rowland with JP Morgan. Q - Jennifer Rowland, JP Morgan: Thanks. A question on the capital program with the presentation for the Conoco Burlington transaction, you have that 2006 CAPEX would be just over $17 billion, so just wondering, what’s 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 reevaluation of the costs that you may have to spend on Burlington Resources projects? A - James Mulva: Well, first, we’ve added in to recortize(?) the capital spend for three quarters of Burlington Resources. We’ve also added a few opportunity projects that have come forth that I’ll just say are in the neighborhood of just a billion dollars, that we would like to add to our program, which are good returns. Then with the strong appreciation of the share price at LUKOIL, the acquisition of the remaining 4% at the end of last year with 16%, and we’ve been doing about a percent a quarter. Just on 4% it’s costing us more to get the 20% than we thought. It’s costing us more to buy that, but the value of ownership in LUKOIL has at least doubled – more than double what we acquired the shares for. So that’s primarily it. We do have some cost inflation in our capital program upstream and downstream, but primarily recognition adding for the Burlington transaction, adding about another $1-1.5 billion of opportunity projects that we want to add to our capital program and the additional cost to get to 20% LUKOIL. Q - Jennifer Rowland, JP Morgan: OK, great. Then just a quick question on LUKOIL actually. Is it safe to assume that once you reach the 20% level, that will be it as far as your ownership stakes? A - James Mulva: 20% by agreement is the maximum we can have, so we get to 20% and that’s by agreement, that share. Jennifer Rowland, JP Morgan: OK, great. Thank you.

Your next question comes from Paul Sankey, with Deutsche Bank. Q - Paul Sankey, Deutsche Bank: Hi, good afternoon, gentlemen. Regarding the way you’re looking at your return on capital employed and pooled accounting, does that mean that for future acquisitions you’ll be using that methodology as your hurdle rate, if you like, for the attractiveness of future acquisitions? A - James Mulva: Yes, we have to use purchase accounting. Q - Paul Sankey, Deutsche Bank: So we should consider that your methodology from now on, if you like? The further question I have is on the capital budget again. 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 breakeven slide, that your breakeven will now be around the $47 (inaudible) mark? And 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. A - James Mulva: OK. First of all, I think your assumption going forward in subsequent years of something around $15 billion is a good assumption. Then when you look at it you say, well, breakeven, in different scenarios of capital, all this looks about – on slide 29 - $47.30 crude, gas $6.66, and crack spread. Well, a lot depends, you know? You may have a stronger or weaker upstream or downstream. But we obviously have a lot of latitude there where we could, if we looked at a lower price environment – say the mid-$40 oil price, if we say it’s going to last for some extended period of time, we can adjust our capital program. We can also defer some projects. We’d have to take a look at what we think is taking place upstream and downstream, but I think in terms of dividends, we were very strong in discipline of annual increases in dividends. We expect by the time if we were to see a lower pricing environment like this, we would have gotten our balance sheet set down dramatically over the next 6, 12, 18 months. We have a lot of optionality with respect to how to respond and adapt to a lower pricing environment. Q - Paul Sankey, Deutsche Bank: Jim, 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? A - James Mulva: Well, no. We’re moving the debt down. We’d like to see the debt moving down to the low 20s, then medium to longer term we’d like to see our debt be between $15-20 billion. Debt race is going to be down in the mid-teens by then. Q - Paul Sankey, Deutsche Bank: And just to be very clear, then, so you’re 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+ type environment? A - James Mulva: That’s correct, because – a rather unique situation – we have the projects over the next 5-10 years that we see spending at that level with good returns on that kind of a spend program. Paul Sankey, Deutsche Bank: Great, thanks. I’ll leave it there. Thank you.

Your next question is from Nicki Decker, with Bear Stearns. Q - Nicole Decker, Bear Stearns: Hi, good afternoon. My question is on your synergy as 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 already pretty low cost, and that you’ve talked about possibly applying Burlington Resources operating excellence at ConocoPhillips sales, just elaborate if you would on where you envision the realization of this 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 timeframe for realization of these synergies? Thank you. A - James Mulva: OK, Nicki, we don’t have a specific breakdown by category of those cost centers as it were, that we’re 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 activities by being a lot more highly concentrated in different basins would help us achieve operating expense reductions, and we intend to focus on operating excellence. And then you’re right, to the extent that you viewed the Burlington Resources 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’s going to come through application of best practices and in certain cases through say in a place like San Juan, where we’re able to optimize the positions of both ourselves and Burlington Resources to add volume enhancements. Then finally, for the time frame, we would expect to have the full run rate of this available to us in 2008. So you know, it’s going to ramp up to this number between now and then. Nicole Decker, Bear Stearns: Thank you.

Your next question is from Mark Gilman with the Benchmark Company Q - Mark Gilman, Benchmark Capital: Good morning, guys. I got a couple of things. First on the synergy thing also, I wonder if you can give me an idea of the level - the quantifiable level – of workforce reductions and office closings that were part of the initial estimate and how that’s been revised with respect to the new estimate? A - James Mulva: We see workforce reductions – I don’t have a headcount 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 with initially the systems part of the business in parallel, and when it gets converted over we would expect to realize more synergies. I think a good proxy for that, Mark, is on page 18, we had the capitalized purchase price for those items as well as the corporate segment extent. The corporate segment, you can see, trails down. And the capitalized purchase price would take a similar pattern. The synergies would get captured in greater amounts in more of a reciprocal pattern. Q - Mark Gilman, Benchmark Capital: No number on office closings, John? A - John Carrig: Q - Mark Gilman, Benchmark Capital: OK. Let me try something else if I could. John, can you help me understand how you’re booking the LNG revenue associated with Vioux(?)? I mean, 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? A - John Carrig: It doesn’t get reported as MCF sold, it’s LNG revenue. It’s a separate item of revenue. Q - Mark Gilman, Benchmark Capital: So it’s not reported at all in your gas price realization? A - John Carrig: No, it is not. And neither is Timor. Q - Mark Gilman, Benchmark Capital: OK. So it’s not reflected in any of the upstream realizations anywhere? A - John Carrig: In LNG realizations, Mark. I think there’s an LNG realization somewhere, but I’d have to go through the – Q - Mark Gilman, Benchmark Capital: There’s a Kenai LNG realization, but if there is one on Vioux(?) I didn’t see it. A - John Carrig: It may not be in this quarter, but it will be. A - Gary Russell: I’ll call you later and show you where it’s at, Mark. Q - Mark Gilman, Benchmark Capital: OK, that’s fine. And one final one. Give me an idea, if you could, the production level on Magnolia, and whether it’s at plateau? A - Gary Russell: Can I get back with you on that? I’ll call you after the call. Q - Mark Gilman, Benchmark Capital: Thanks a lot. That’s all I have.

Your next question is from Mark Flannery, with Credit Suisse. Q - Mark Flannery, Credit Suisse First Boston: Hi, I’ve 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? A - James Mulva: OK. I think, Mark, what we’ll do is – I don’t have it right in front of me, but you should go to the New York analyst presentation, and that’s a very good approximation of just what it is, because what we’ve done is we’ve added on the additional cost for the LUKOIL getting up to 20%, then we’ve added on let’s say about $1-1.5 billion of additional opportunities and I think you can split those somewhere roughly half upstream, half downstream. And you get a pretty good number then, even though the additional capital for Burlington Resources is all upstream, and so that’s how I’d respond to it. But I think Gary can come back to you with the detail on the numbers. A - Gary Russell: Yes, I can get you the actual make up of the $15 billion, Mark, I’ll give you that. Q - Mark Flannery, Credit Suisse First Boston: OK, that’s great. Just one quick follow up, at consensus earnings estimates, or consensus oil price forecasts, or whatever, just for the consensus case, what would you expect stock-based compensation to run at in 2006? A - James Mulva: Are you going to tell me the multiple? Q - Mark Flannery, Credit Suisse First Boston: Well just say now. Say if this was the end of the year and nothing much had changed? A - James Mulva: The stock based compensation is dependent upon obviously to some extent the stock price. And there’s some accretion numbers that are applied to a variety of factors, including the demographics of the participants. I don’t have that number in my… Q - Mark Flannery, Credit Suisse First Boston: I guess what I’m trying to get to is an idea of what net share repurchase is going to be. I assume the billion dollars that we’re talking about today is a gross number which will be somewhat offset by increases in shares for compensation purposes? A - James Mulva: Yes, sure. We can get that for you. Q - Mark Flannery, Credit Suisse First Boston: OK, great. Thank you.

Gentlemen, your final question comes from Bruce Lanni from AG Edwards. Q – 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 carryover for R&M – the turnaround cost – is going to be so high in Q2? Then I had a follow up on the comments Jim talked about on the asset sales and divestitures. I understand in the scheme of things they’re not meaningful to the overall size of the company, but are the numbers for the production and the 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? A - James Mulva: First of all, we don’t really know. We’ve got a number of assets that we’re going to test the market on. We know that the market’s pretty good, but I would say this: that it’s a very nominal amount of production and impact on reserves. And to say anything more than that is not really fair, I’d be saying more than what we ultimately will do. It’s not fair with respect to the company itself internally, because we are just trying to communicate that we’d see several billion dollars of upstream/downstream and cumulative asset dispositions. So it’s going to have a very minimal impact on reserves, production and a very modest impact on net income. I think the other question was the turnaround costs, Bruce. They were $163 million in Q1 and we increased the total turnaround costs for the year from $350 million to $385 million, by about $35 million. That in part would do some – the costs in the first quarter were higher than we expected. And we do expect some increase through the balance of the year. Q2, I don’t recall, but it’s not materially higher than what we previously forecast. A - John Carrig: No, it’s exactly what we forecast. In fact, it’s not unusual to have a heavy Q1 and then a semi-heavy Q2 which is exactly what we have. Bruce Lanni, AG Edwards: OK. 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.

Thank you, and 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 the replay of the webcast of this teleconference, will be available on our website, 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.