康菲 (COP) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q1 2010 ConocoPhillips earnings conference call.

My name is Chris and I will be your operator for today.

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

We will conduct a question-and-answer session towards the end of this conference.

(Operator Instructions) As a reminder this conference is being recorded for replay purposes.

I would now like to turn the call over to Mr.

Clayton Reasor, Vice President of Corporate Affairs.

Please proceed.

Thanks, Chris, and thanks everybody for participating in our first-quarter conference call.

I am joined today by Jim Mulva, our Chairman and CEO, and this morning we will be discussing the Company's first-quarter results and status on the strategic initiatives we shared at our March 24 analyst day.

A summary of key financial and operating results for the quarter will be provided as well as our outlook for the remainder of 2010.

As in the past you can find the presentation materials on the IR section of the ConocoPhillips website.

In addition to the presentation material, we plan to use our website to provide information that was part of our quarterly interim update prior to discontinuing its issuance earlier this year.

Please refer to our Safe Harbor statement in the appendix of this presentation on slide 17.

It's a reminder that we will be making forward-looking statements during the presentation and Q&A.

Our actual results may differ materially from what we present.

Also in the appendix are non-GAAP reconciliations footnoted throughout the presentation for your reference.

Moving to slide two, summary of our results and highlights for the quarter.

You will see adjusted earnings for the first quarter were $2.2 billion or $1.47 a share which excludes the charges of $110 million for ending our participation in the Yanbu and Shah projects.

Cash from operations was $3 billion.

Our company's capital efficiency increased as annualized cash return on capital invested improved to 21%.

Our E&P production, excluding LUKOIL, was 1.83 million BOE per day and in spite of the challenging downstream environment, the competitiveness of our refineries allowed us to run at 88%.

I am going to now turn to slide three.

Total earnings for our company were $2.098 billion, up $1.3 billion compared to last year.

The majority of our earnings were generated by our exploration and production business.

Our E&P segment improved by $1.132 billion primarily due to the increase in crude prices.

Compared to the first quarter of last year R&M income fell $209 million.

Weaker refining and marketing margins more than offset lower operating costs.

Our equity earnings for LUKOIL investment were up $379 million compared to the first quarter of 2009.

As I mentioned earlier, this quarter we had charges of $110 million for exiting the Shah and Yanbu projects.

So adjusting for that you can see this quarter's earnings were $2.208 billion.

Total company controllable costs were lower by about $40 million year-on-year and $110 million sequentially if you eliminate the impact of foreign exchange and higher utility and fuel costs.

Moving to slide four, total company cash flow.

You can see in the first quarter we generated $3 billion in cash from operations.

This included a $979 million negative impact from an increase in working capital.

This increase in working capital is driven by the growth in seasonal operational inventory levels and in support of our commercial business consistent with what we have done in the past.

We expect a substantial portion of this inventory to be worked off by year-end.

Our capital program totaled $2.48 billion for the quarter, in line with our 2010 budget of $11.2 billion.

And while debt-to-cap ratio remained flat our absolute debt level increased slightly due to the increase in working capital I mentioned earlier.

We paid $744 million in dividends compared to $696 million paid in the first quarter of 2009.

Our first quarter 2010 cash position ended at $855 million.

Now let's review our total company production for the first quarter on slide five.

As expected first-quarter 2010 E&P production was 1.83 million BOE per day, down 5% or 97,000 BOE per day from the first quarter of 2009.

Compared to last quarter E&P production was virtually flat.

Looking at the sources behind the year-over-year decline 29,000 BOE per day can be attributed to market factors including production and sharing contracts in Indonesia and royalty impacts in Canada.

Portfolio changes mainly due to the expropriation of our assets in Ecuador decreased production by about 9,000 BOE per day and higher planned maintenance, primarily in Australia, decreased our production by 3,000 BOE per day.

The remaining decrease of 56,000 BOE per day was due to normal field decline, primarily in the UK, Lower 48, and Alaska, mitigated by new production from Phase 2 of our Bohai Bay project in China and our Foster Creek, Christina Lake SAGD developments in Canada.

Production from FCCL Oil properties increased nearly 50% on a net after-royalty basis in the first quarter of 2010 compared to the same period of 2009.

The Foster Creek project achieved payout for royalty purposes in the first quarter.

It's the industry's largest SAGD project to reach payout to date and is leading the way in implementing innovative technologies that lower operating costs and reduce our impact on the environment.

In the Bakken shale we spud three wells during March bringing our total 2010 well count to six.

Three of those wells were placed on production in March with each having initial flow rates of approximately 2,000 BOE per day.

As we gain experience in this area drilling productivity continues to improve which we hope to replicate as we increase investments in this region.

In the Eagle Ford play we continue to have -- we currently have three rigs drilling and have completed the drilling phase of four horizontal wells this year.

The first of these wells was placed on production in late March and flowed at an initial rate of 3.8 million cubic feet of gas and 1,200 barrels a day of condensate.

This well and related industry results reinforce the potential of our 240,000 net acre position in the liquid rich core of this play.

Now turning to page six.

Unadjusted E&P earnings for the first quarter were $1.832 billion, up from $700 million last year.

Higher prices and other market impacts contributed $1.5 billion of increased earnings.

The increase was partially offset by $104 million due to the impact of lower sales volumes and operating costs were $23 million higher mainly due to the adverse effects of foreign exchange of about $50 million.

Excluding the impact of FX, operating costs were down around $25 million to $30 million from a year ago.

The $219 million in other includes $83 million in costs associated with the Shah Project exit, increased DD&A due to foreign exchange impacts, and increased export taxes related to our equity affiliates.

As stated, when excluding the $83 million charge for the exit of Shah adjusted earnings are $1.915 billion.

You can see the realized prices table at the bottom of slide six.

On the right-hand side you can see realized oil and NGL prices reflect a 78% increase compared to last year and global gas prices increased by approximately 11%.

Both US and international earnings improved significantly from the prior year and the Lower 48 business unit had solid earnings this year compared to a loss a year ago.

Although North American natural gas prices remained challenged, our financial performance in the Lower 48 benefited from liquids which represent more than a third of its production.

Moving on to slide seven, our unit metrics for E&P.

You can see our E&P income per BOE was nearly three times higher in the first quarter of 2009, reflecting the increase in realized prices.

And although we currently lag the largest competitors in our industry on an income per BOE basis, we expect to close this gap as we allocate more of our capital to liquids production.

Our E&P cash contribution per BOE has been consistently above average compared to our peer group for more than a year.

And if prices continue to increase we expect to outperform our peers on a cash flow per barrel basis due to our large OECD-focused portfolio.

The R&M segment discussion begins on slide eight.

Market conditions for R&M were challenging during the quarter and much weaker than the first quarter of 2009.

However, we did benefit from wider light/heavy crude differentials, better margins on the production of feedstocks used by the chemical industry, and improved clean product yields.

We were able to increase our US refinery utilization to 88% this quarter from 80% a year ago and 83% sequentially.

The year-over-year earnings variance was driven primarily by lower global refining and marketing margins.

Over 85% of the $213 million reduction in income is related to refining margins.

In the US distillate margins have dropped about 40% while internationally distillate margins have fallen 30%.

Lower global volumes impacted earnings by $24 million.

These volumes were primarily caused by our Wilhelmshaven refinery, which was shut down for the entire first quarter, as well as planned turnaround activity at both our joint venture refineries, MiRO in Germany and the Melaka refinery in Malaysia.

The $88 million improvement in operating costs was due primarily to lower turnaround activity and other operating costs.

We remain focused on items we can control including cost management and optimizing our operations.

11 of our 17 refineries are ranked in the top tier of the Solomon Operating Cost Peer ranking and this creates competitive cost advantages.

$60 million in other was caused by foreign exchange impacts and includes a $25 million impairment resulting from our decision not to participate in the Yanbu refinery project.

Adjusted earnings for R&M were $21 million for the quarter.

A table at the bottom of the slide provides US and international earnings as well as realized margins.

Now let's move to slide nine which shows year-over-year variances for other segments.

Results in our midstream segment were $77 million, $46 million lower this quarter compared to a year ago.

The decrease was primarily due to an $88 million gain on shares issued by a subsidiary of DCP Midstream in the first quarter of 2009 partially offset by improved margins due to higher NGL prices this quarter.

Our 50% share of CPChem generated $110 million this quarter, $87 million higher than the first quarter of 2009 due to higher ethylene and benzene margins.

Finally, LUKOIL earnings were improved $379 million compared to the same quarter last year partly as a result of the restatement due to lagged reporting.

As we disclosed on our analyst day, beginning in January of 2010 we changed the method we used to determine our equity share of LUKOIL's earnings.

Under this new method the Company records our equity share of LUKOIL's actual earnings on a one-quarter lagged basis rather than using an earnings estimate for the current quarter.

Prior periods have been recast to reflect this change.

Corporate expenses were $310 million after tax for the quarter compared to $259 million last year.

The increase was primarily due to increased interest expense and foreign currency losses.

Turning to page 10, our return on capital employed.

Cash return on capital invested have improved each quarter since the beginning of 2009.

This has been primarily driven by better earnings and cash flows resulting from higher commodity prices.

So that completes my review of the first-quarter 2010 earnings.

What I would like to do now is turn to an outlook comments on slide 11 before asking Jim to give us a few of his comments and then opening the phone for Q&A.

So first I would like to provide some guidance on operating expectations for the second quarter and the remainder of the year.

We will begin with E&P.

Over the next couple of quarters production is expected to be lower.

Areas that will contribute to the decrease include North American natural gas, Western North Slope, and Prudhoe Bay due to seasonal maintenance and normal decline.

We also have some planned shutdowns being conducted in Norway with Ekofisk and Eldfisk being down between 22 and 26 days.

In the UK, Britannia and J-Block will be down between 10 and 20 days, and in Australia Bayu-Undan and the Darwin LNG facility will be down close to a month.

As we said last quarter and during the analyst meeting, we are targeting 2010 production levels to be flat with 2008 normalizing for the impact of asset dispositions.

New production is expected to partially offset these declines and will come from our ramp up of Canadian oil sands, Bohai Bay, Australia, North America liquids, and Qatargas-3.

Regarding refining, we expect increases in utilization rates, especially internationally due to the restart of our Wilhelmshaven refinery and the completion of turnarounds at both MiRO and Melaka.

In the United States capacity is expected to improve given our expectations for higher refining margins.

And as for the remainder of the year, we expect average quarterly turnaround costs of about $125 million pretax, in line with previously provided guidance.

We continue to take steps to control costs while ensuring the safety of our employees, integrity of our assets, and conducting planned maintenance at all our refineries.

In 2009 we exceeded our cost reduction expectation target of $1.4 [billion] by reducing costs almost $2 billion and in 2010 we plan to achieve our cost savings of $400 million.

At our March 24 analyst day we provided details regarding our plans to enhance returns and outlined our asset disposition program.

We recently announced an agreement to sell our Syncrude interest to Sinopec for $4.65 billion pretax.

The 2009 production and reserves associated with our interest in Syncrude was 23,000 BOE per day and almost 250 million BOE in reserves.

Our expectation for the after-tax proceeds are in excess of $4 billion.

This is an early estimate and could possibly change on the completion of the final transaction.

The government approval process is underway in both Canada and China and we anticipate closing in the third quarter.

Data rooms for our North America asset disposition programs will be open in the next couple of months.

We have selected our financial advisors and expect closing for these packages to start in the second half of 2010.

The buyer for our Conoco Flying J travel centers has been selected.

We estimate after-tax proceeds to be approximately $350 million.

We are still waiting for the Federal Trade Commission's approval and hope to close mid-year.

We have engaged Citibank as the advisor of our interest in the REX Pipeline.

We have a 25% interest in REX Pipeline and marketing efforts are expected to begin in the second quarter with closing of a potential transaction expected by year-end 2010.

We remain confident that we will reach our $10 billion target for asset dispositions during 2011.

Regarding the increase in shareholder distributions, in March we announced a quarterly dividend payment of $0.55 per share, 10% increase over the previous rate.

The dividend is payable June 1 to shareholders of record on May 24.

And we started selling LUKOIL shares this month in small, open market transactions and commenced purchasing ConocoPhillips shares simultaneously.

These amounts and the amount of LUKOIL shares sold and the amount of ConocoPhillips bought will be disclosed in the upcoming 10-Q.

As stated at the analyst meeting, we expect to complete the sale of our half of LUKOIL equity during 2011.

Moving to exploration, 2009 was a good year with discoveries at Browse Basin and the Gulf of Mexico lower tertiary trend as well as entries into several new areas.

While we are constraining capital in some parts of our business, spending in exploration has remained fairly consistent which should strengthen our portfolio for future organic reserve replacement over time.

In April drilling and logging operations were completed on our Laurentian Basin wildcat and the well was subsequently plugged and abandoned.

The cost of the well incurred through March 31st are included in our first-quarter financial results as dry hole expense.

A significant amount of data was collected and is being analyzed and no decision has been made regarding any potential future activities in this area.

Kronos in the Browse Basin off the northwest coast of Australia is still drilling toward its planned target depth.

Given the extensive coring, testing, and analysis that is planned for this well we are unlikely to have significant updates regarding the overall prospect for several weeks.

In general, most of ConocoPhillips' significant exploration wells will begin during the second half of this year.

Some will reach their objectives in the fourth quarter while others will roll into 2011.

For example, in the Gulf of Mexico the Chevron-operated Coronado prospect will spud early in the third quarter, potentially conclude before year-end.

As mentioned at the analyst meeting, we expect that a Tiber appraisal well could also spud prior to the year-end.

In the Caspian current plans are to spud the Rak More well in the third quarter and achieve TD by year-end, and we expect Nursultan to follow sometime in the second half of 2011.

As for our Poland shale play we expect to spud our initial well in the second quarter.

And in China coal bed methane we continue to drill and analyze cost and the reservoir performance with the results interpreted near the end of 2010 or early 2011.

With regard to Eagle Ford we are aggressively pursuing exploration and development opportunities based on the promising results we have encountered to date.

Our APLNG project is moving forward as planned.

APLNG reserves and resources are considered the best in their region and our upstream is making progress daily.

Our target is to secure sales agreements to support two 4.5 million metric tonne per annum trains.

So that concludes my comments.

Now I will ask Jim for a few closing statements before we open the call for your questions.

Thank you and appreciate all those who are participating in our conference call this morning.

Thought it might be of help to spend a few moments to talk about some of the steps we are taking to create shareholder value.

I refer to our March analyst meeting in New York when you heard me indicate that the opportunities for profitable investments for the large, international, integrated majors has changed pretty dramatically in the last several years.

Resource access is an issue as is fiscal take and commercial terms.

The question for our company is how do we create value for our shareholders in this type of environment given the assets, the resources, and the opportunities we already have in our existing portfolio.

Our approach is not just to get bigger in upstream volumes, but to ensure that we have better than cost of capital returns and not do projects that are at just cost of capital or have limited upside potential.

We think the way to create shareholder value for our company is for us to convert our extensive resources into proven reserves and to do this at competitive metrics.

And while we will grow the absolute volumes in the latter period of our five- and 10-year period of time of strategic plans, we are stressing to annually increase the per-share metrics of reserves and production as we go through this period of time.

Creating value means more and more focus on improving the returns of the portfolio, strengthening the balance sheet with significant increases in distributions to our shareholders in the form of annual increases in dividends and share repurchases.

We are executing on this plan and we have seen support from our shareholders and the financial community.

As Clayton said, we have reached agreement to sell our 9% in Syncrude and that transaction, along with the others that we have told the marketplace that we intend to sell, will go a long way toward meeting our $10 billion disposition objective.

There were very difficult decisions for our company regarding participation in the Yanbu and Shah project but we believe the decisions that we made were consistent with the execution of our plan.

Clayton also said we have commenced sale of a portion of our LUKOIL shares and simultaneously we have started the purchase of ConocoPhillips shares.

We are doing this in rather modest amounts and doing this in an appropriate way.

Capital spending is being constrained to doing our highest return projects while not -- while deferring some of the other projects that we may be doing at a later point in time when we can improve the metrics associated with those opportunities.

We expect to accomplish our debt and balance sheet objectives really by the end of this year so things are going quite well in that regard.

So those are the comments I would like to make, Clayton, and I think it probably is time now we opened this up for questions from those participating in our conference call.

Great.

So, Chris, could you line up some questions for us please?

(Operator Instructions) Doug Terreson, ISI.

Good morning, guys.

Jim, execution on the return enhancement plan has obviously been positive this far especially with the recent decisions on Yanbu and Shah, I think, underscoring your commitment to higher returns.

And on this point if free cash flow continues to rise by $1 billion-plus per quarter and proceeds from Syncrude and Flying J exceed $4 billion, then the cash position is going to build significantly in Q2 and Q3 of 2010.

So you have talked about -- you just mentioned debt and equity reduction as clearly being priorities and it seems like the equity reduction component, share repurchases, have already commenced.

So could you talk about how you plan to segment the two?

Is debt reduction necessarily more important than equity reduction or how are you guys thinking about that part of the plan?

Thank you.

First, what I would like to say is, yes, the cash generation looked quite positive.

We are quite pleased with the slow development of the economy around the world and that can be helpful to our businesses.

And we are executing on our plan.

With respect to our investment opportunities, I would say that there is a likelihood that our capital program would be more than $11 billion, but may be closer to around $12 billion.

We want to do our very best project so we might see a little bit of expansion in our capital spending this year, but may be in the neighborhood of about $1 billion.

When we talk about our debt reduction that will come primarily through some cash flow from operations but also asset dispositions.

We see the debt, taking it down into the low $20 billion levels.

It could be at somewhere between $21 billion, $23 billion, somewhere in there.

Debt and the cost of the debt is certainly very manageable.

The debt ratios will be coming down closer to our 20% so somewhere in the low $20 billions we think we have done all we need to do on debt reduction.

Don't need to do any more than that.

It doesn't have to go to $20 billion but in the low $20 billions somewhere.

So with the cash coming along developing quite nicely and funding the capital opportunities in the Company we would see annual increases in dividends.

So we have already increased the dividend this year so the additional cash will go towards share repurchase.

That is really what the plans are.

Okay.

Jim, one more question on E&P.

Norway has always been a significant, steady performer for you guys and on this point there seems to be a movement on new investment phases which will probably extend the life of that position in a financially attractive way.

So could you provide a little color on activities in that area and updated expectations for your position in Norway in E&P?

Well, as you know, we have already rebuilt Ekofisk a second time.

We are looking at doing Eldfisk and extending the opportunities of capturing more out of the fields associated with the Ekofisk greater area.

It's a field that has already gone for about 40 years and it's going to go for another 40, 50 years.

So it's just a great opportunity for us.

Every time we can capture another 1% that is in the neighborhood of a find of about 100 million barrels oil equivalent.

That is on a gross basis.

So we are working our plan so that we are going to be redeveloping and redoing Eldfisk and Ekofisk to create opportunity for us because it has very good returns.

The fiscal environment has been very consistent and steady so we are going to do this another time again in Norway.

So we have a great presence there and we look forward to two, three, four more decades in Norway.

Great.

Thanks a lot.

Jason Gammel, Macquarie.

Good morning.

Just wanted to ask you about some of the activity on shore in North America, you are seeing very strong liquids production coming out of both your Bakken and Eagle Ford acreage.

Jim, you had mentioned there was the potential to expand the capital program a little bit this year.

Would that be an area that you might want to pick activity levels from the current three rigs or so that you are running?

Absolutely.

When I talk about some expansion on capital programs from $11.2 billion, maybe closer to $12 billion, a lot of that will go towards those type of projects.

So we are very pleased with our position that we have and, yes, that would be an area we would direct more capital towards.

(multiple speakers) some background on that, Jason.

Bakken first quarter produced 32,000 a day of oil.

Permian actually we produced quite a bit of liquid there; that is 31,000 a day.

And people are surprised that San Juan actually produces liquids; we have 45,000 a day of NGLs out of San Juan.

Those are kind of our core liquids producing areas in the Lower 48 with those three representing about 70% of our Lower 48 liquids production of around 150,000 or 160,000 a day.

Terrific.

Maybe one more if I could, guys.

On Wilhelmshaven I think you mentioned that it is currently operating.

Is that operating on what you consider normal utilization rates and have you done anything to lock-in margins in Germany at this point?

Well, we had Wilhelmshaven shut down for maintenance and then for market reasons shutdown for the whole first quarter.

And we are looking at the essentially the hydroskimming margins.

You have to make these decisions weeks in the past and we felt it was an opportunity for us to start Wilhelmshaven up.

We have -- the hydroskimming margins have backed off pretty dramatically so I don't think you can expect that we are going to continue to operate Wilhelmshaven in the current market environment.

It also gives us an opportunity to talk about Wilhelmshaven and of course this is a decision in front of us.

We are evaluating every single alternative with respect to what we should and will do with Wilhelmshaven.

I think you will hear more from us as we go through this year on Wilhelmshaven.

Thanks very much, guys.

Doug Leggate, Bank of America Merrill Lynch.

Good morning, a couple of questions.

On the exploration expenditure, Clayton, I think in your prepared remarks you talked a little bit about some of the things you are going to be doing this year, but exploration and expenditures fell off a little bit in the US or at least the expense did a little bit.

Can you just guide us towards how we should be expecting this split between US and international?

And maybe a little bit more on the activity levels, what basically was going on in the first quarter in the US?

I think guidance remains the same, Doug, at $1.3 billion for the year in exploration.

I will have to get back to you on a US/international split but that shouldn't be a problem.

I think a lot of our exploration activity is expected during the second half of 2010 and that may have been what was behind the -- kind of coming in below what guidance would have suggested.

Okay.

I guess the only other one I have is -- I guess it's kind of an accounting question really to tax.

As you have shifted your, I guess, your capital towards liquids in the Lower 48 it looks like you are getting some tax benefits from mix effects.

Can you maybe talk a little bit about -- last year your run rate was running in the low 50%s and if we were going to see a more permanent shift down to a lower level of run rate tax?

If you could talk a little bit to that both in Q1 and as we go forward?

Sure.

Effective tax rate was lower this quarter due to the higher proportion of income from areas with lower tax jurisdiction.

So it would be Lower 48 and Canada had earnings improvement so therefore you saw a reduction in the effective tax rates.

E&P tax rates fell from 60% in the first quarter of 2009 to 51% in the first quarter of 2010.

Does that help?

Is that what you are looking for?

Sure.

Is that largely the US mix effects, Clayton?

Correct.

So we would expect that kind of run rate to continue so long as we continue to see the liquids do well in the US?

Well, I guess that is right.

As long as you are seeing -- really I think the impact on the reduction in effective tax rate came from improvement in liquids prices.

Also you would -- natural gas prices were slightly higher than they were a year ago.

So Lower 48 just had a much better quarter this quarter than the year-ago and I think that was the big reason behind it.

Got it.

Thanks a lot.

Arjun Murti, Goldman Sachs.

Thank you.

You mentioned the APLNG projects progressing.

Do you have an update on what the timing might be on signing up the sales contracts there for buyers of the gas?

And on a related question, do you think it makes sense for -- I think it's three or four projects down there, yours is the largest -- but three or four projects to be combined?

Or is that for any number of reasons not practical and so they will all be forced in lone developments in that area?

Thank you.

On APLNG we said our objective is this year to sign MOUs with gas purchasers to take two large trains in total, 4.5 million metric tonnes each train.

Get these MOUs signed this year.

We are working very hard on this.

It's a priority objective of the Company because this is so important to the investment and the value creation of APLNG.

We think we are making progress, but of course it remains that we have got to demonstrate and get those MOUs signed as we go through this year.

Just want to be sure that we pass along, as we said, that is our intent and our objective.

In terms of and for competitive reasons really we would rather not go into specifically who and how we intend to do this.

But we are working and have been for quite some period of time.

It would be directed towards obviously the Asian markets.

The three or four projects in Queensland will obviously -- they are different kinds of projects in terms of participation by the many different companies.

Our view is that the way really we are looking at is collaboration, how can we work together.

Not necessarily changing ownership or anything like that, but how can we collaborate to more efficiently execute our capital spending in the projects because many of us are doing these at the same time as you are aware.

We can do this with respect to how we are gathering pipelines from the upstream part, how we can be working in terms of the liquification facilities, shipping, all of that.

But particularly at Gladstone how do we build the liquification facilities.

And so we have had discussions with the other participants, other projects.

It's difficult, but on the other hand we know that this makes a lot of sense for all of us so as to execute well with respect to capital spending and schedule.

We know that Queensland and the federal government want to see collaboration and so we are very open to it.

It's difficult to do but I think you are going to see collaboration.

We are quite willing to do this in a way that creates value for everyone.

That is not just the participants of the project but also for the government as well.

They also know that it has impact with respect to availability of labor and the contractor, so it's important to do this well.

So we are very open to collaboration.

I see, Jim.

So it sounds like the collaboration is more on coordinating the CapEx and labor as opposed to necessarily reducing the number of actual LNG sites and/or coordinating the gas purchase contracts or the gas sales contracts from your perspective.

It seems more on the labor and CapEx.

Yes, I think it's more collaboration of how we do the capital spend.

With respect to coordination on sale of LNG, I don't think you -- each company will do their own thing, that is what has been happening.

In terms of whether there is a possibility you could -- of sharing a train or something like that, I guess that is possible in collaboration but that doesn't necessarily change in terms of ownership or participation on what each company may be doing.

That is great.

And then totally unrelated question, I appreciate the Bakken and the Eagle Ford well data in the press release, which is nice to see.

The 2,000 barrels a day from a well certainly sounds like a very solid, if not high, number.

Can you comment on whether that is a dual lateral well?

It's certainly a much higher flow rate than I think some other companies are reporting.

And then to the extent you can say, is that a 30-day initial production rate of 2,000 barrels a day a single-day or any other period of time?

I think, Arjun, we are going to have to come back to you on that specifically.

But I know on these wells we -- I will just say generically I think the 4 million or 5 million cubic feet a day of gas and then liquids is somewhere between 1,000 and 2,000 barrels a day.

It varies by well but that is sort of what we have been experiencing in our early wells.

We put them down with experience better all the time.

Completion techniques get better all the time.

I think we will just come back to you and tell you how that has done, but they are long distance, multilateral wells.

As we have talked, we are going to provide more granularity on this part of our business in the future, Arjun.

And appreciate your interest in this.

That is great and we look forward to that.

Thank you very much.

Jacques Rousseau, RBC.

Good morning.

Just wanted to follow-up on the share repurchase program.

At your analyst meeting there was a slide that pointed towards $6 billion in 2010 and $6 billion in 2011 of buybacks.

I assume most of this will happen in the second half of the year as your asset sale program kicks in.

My question is do you think there will be upside to that program given that your asset sale program is off to a pretty good start?

Well, I go back to share repurchase and the first question that came from Doug Terreson.

Our share repurchase is tied to the sale of our 10% of LUKOIL and you just say for market purposes let's say that is around $5 billion.

So as we sell our LUKOIL shares in the marketplace and we buy ConocoPhillips shares there is $5 billion there.

But Doug Terreson asked, he said it looks like there is going to be more free cash flow after you fund your capital spending program and your dividends.

You already get debt reduction going towards share repurchase.

For illustrative purposes using consensus numbers, when we had our March analyst meeting it showed that it was in the neighborhood of about $12 billion and we said about $6 billion each year for share repurchase.

That is kind of the plan.

To the extent how that materializes a little bit more, a little bit less is going to depend upon not so much we will meet our debt objectives and annual increases in dividends.

It's going to be does the marketplace develop the commodity prices like we would expect.

And so the flywheel then would be share repurchase.

Okay, fair enough.

Thank you.

Paul Cheng, Barclays Capital.

Thank you.

Good morning.

A number of quick questions.

Clayton, earlier you were talking about the E&P tax rate.

I understand how the overall division tax may change because of the stronger results from the US.

How about in the international?

In 2009 you were roughly about in the 67% or so.

In the first quarter it is 59%.

I don't think that maybe a change between the gas and liquid so is there any particular things that we should be aware?

And is that 59% on the international is a good proxy going forward?

I don't know.

I am going to have to get back to you on that, Paul.

I just don't know.

I am sorry.

And I presume that on Bakken and Eagle Ford that in terms of what is the per barrel total we saw as recovery or the total development cost, those call more detailed information that we will have to wait until you can come back to us?

Yes.

We are early days on development at Eagle Ford.

Bakken, we have been there for quite a while, but as far as the reserves in each of those areas or the production growth that we expect to see, I would expect us to provide more of that type of information later this year.

Just too early to say right now with Eagle Ford with where we are, and I think the development plans around Bakken are coming together, so stay tuned on those.

Okay.

Two other questions.

One, Jim, you guys are going to redevelop the Ekofisk.

Any kind of rough cost estimate how much is that going to be on that redevelopment on a per barrel basis?

Well, I thought we indicated that at our March analysts meeting.

Maybe we didn't.

But I would assume that the finding and development costs are somewhere probably in the mid teens.

The rates of return are well in excess of cost of capital and that means rates of return probably in excess of mid-teen returns.

So that is what we are really looking at in terms of money to be spent on redoing Eldfisk as well as some of the satellite fields and going and continued replacement wells all to recover more of Ekofisk.

Jim, should we assume the project will be FID this year so you can book reserves this year, or it is going to be a next year event?

No, I don't have that -- I think that is a later period of time.

Not this year.

It's not going to be this year?

I could be wrong on that, but we will check that out.

Something tells me it's not this year.

Okay.

Final one, on page 10 on the presentation that you gave the return on capital employed for the last several quarters, Clayton, do you have a rough estimate that between the first quarter 2009 to the first quarter 2010 the 5% improvement how much is related to market condition?

Most of it is -- the majority of the improvement comes from higher oil prices and better gas prices.

There is some cost reduction but the majority of the improvement comes from better earnings from higher prices.

Capital employed has moved up a little bit.

One of the ways that we are going to improve ROCE is slow down the growth of capital employed.

In fact, parts of our business we are going to see capital employed fall as we invest less than DD&A.

But the majority between first quarter of 2009 and first quarter of 2010 is due to commodity price improvements.

Well, that is true but I think also, Clayton, we have done a nice job on managing and constraining our costs.

It's quite a challenge as we go forward.

As Clayton said, we expect $400 million or $500 million of lower costs this year than what we actually achieved in all of last year in absolute terms.

The challenge is, whether it's currency or it's the suppliers and contractors, they are coming at the industry pretty hard.

And so to hold on or more than hold on to what we have already accomplished last year is quite a challenge.

But that is why we think we are doing pretty well as we have gone so far this year and that helps with respect to returns.

I will follow-up with you on that one, Paul, just to make sure that there is -- to give you the breakout between the self-help and what came from market help.

Mark Gilman.

Guys, good morning.

One operationally-oriented question if I could and then one relating to Yanbu and Shah.

Operationally any shut in gas volumes in the US and Canada underlying the first-quarter production in either of those areas?

There is a little bit, Mark.

There is some stuff that was not brought back on in the first quarter due to some severe weather but it's less than five a day.

Okay.

So essentially first-quarter gas volumes both countries at field capacity?

Call it 98%, but I think there is somewhere around 30,000 MCF a day that didn't come back on.

So a small amount.

On Shah and Yanbu, can I safely assume that your feasibility studies indicated returns below cost of capital levels?

And can you give me any idea where your feasibility study indicated the comparative return between the two?

One greater than the other, one less than the other, any clarification on that would be helpful.

Very different projects and of course people can argue what is the cost of capital within one firm or another.

As you know, Mark, people can say the cost of capital -- technically if you look at the cost of debt and whatever is in single digits.

Then you can look at what you must provide and have provided to your shareholders and you get into double digits.

So what is the cost of capital?

Very different kinds of projects; have different risk associated with them.

And even though the numbers maybe -- one looks a little bit higher than the other, they have a different risk/reward profile.

So I think it's really, for many different reasons, not appropriate for us to get too involved in to how we analyze the projects and which one might have been ahead of the other.

The important thing is that we worked this very, very hard for several years with both ADNOC and with Saudi Aramco.

We did this always with the best of intentions and we just felt that given the direction of our company it was important for us these decisions are consistent with emphasizing returns over growth.

Thanks, Jim.

Neil McMahon, Sanford Bernstein.

Yes, it's an interesting pronunciation.

But anyway, Neil McMahon from Sanford Bernstein.

Two things.

One, basically around the Arctic, the first one is really on the Chukchi Sea well and how contingent is the drilling of this well on rig availability with Shell because they were sort of undecided what they were going to drill first between their Beaufort Sea and Chukchi Sea.

Secondly, just on the Alaskan pipeline, that is obviously an absolutely huge project and sort of needs to get off the ground pretty quickly given the construction timing with the two competing projects with yourself and BP versus the Exxon proposal.

Can you give us an update on that because it seems to have stalled somewhat in recent times?

Why don't I try Chukchi and give Alaska pipeline to the Jim?

So we have had a couple special interest groups bringing some lawsuits up in Alaska.

Even though the Department of Interior affirmed the 2008 sale in late March we still have -- there is a time for public comment through the early part of May and then we expect a final court decision around our ability to drill Devil's Paw in late 2010.

So we are doing some progression around drilling an exploration well but we don't see that happening before 2012.

Then just kind of an add-on on Chukchi, in January we exchanged about 25% working interest on 50 of those leases for some Lower Tertiary leases in the Gulf of Mexico and some cash consideration.

So did I help you with Chukchi or is there anything else on that one?

No, that is fine.

Just getting some timing.

It's 2012 at the earliest.

And then maybe Jim on Denali.

Good morning.

We are with BP in the Denali project.

The Alaska gas pipeline they filed an open season in early April with FERC and that is in an open season and remains to be seen whether our company, we participate and how.

Denali, while we anticipate FERC approval to go forward with our open season, we are expecting doing this in July, I believe, this year.

That is going to last for about 90 days or so and we will simultaneously do the same open season in Canada.

Really the decisions for the companies to participate in the open season for the two competing projects will be made by our company as we go through the next several months.

I do expect, though, that the open season for both of the projects would have probably rather conditional participation or acceptances because we really don't know with any certainty what really are not only the commercial but the fiscal rules and regulations associated with the pipeline.

So this is a process that is going to go for the remainder or a good share of this year and so I think we just wait and see as we go through these months.

We will give you more information as it develops.

And, Jim, are there any ongoing discussions with ExxonMobil around this at all?

And feasibly can you have two projects coming out of this or one is eventually going to win?

Well, I think first both projects are going at the same time, not really a discussion between the two.

It's a very upfront competition between Denali and the other competing project.

Obviously when executed it will be one project, not two.

How that comes together remains to be seen.

And then the other thing is that we can't underestimate the challenge with respect to the cost and execution of the project.

The cost is I can't recall exactly but it's probably somewhere between $30 billion and $40 billion.

And then as I said, what are the fiscal terms and certainties associated with that.

Then we also -- I know you start a project like this, it's 10, 12 years before first cash flow and you got to be looking out what do you think the marketplace is going to look like.

Of course that marketplace has changed pretty dramatically over the last three to five years.

So a lot of really challenging significant decisions need to be made before this type of project goes forward and executed.

Great, thank you.

Ed Westlake, Credit Suisse.

Good morning, everyone.

Just on refining and CapEx, you are saying you are evaluating every alternative for Wilhelmshaven.

Can you just confirm now that you have walked away from Yanbu that you are not going to turn that into a fully upgraded refinery by spending money?

And then on the US refining, obviously economic recovery and data was improving.

Are you seeing any more interest in the potential purchase of your refinery assets?

It probably feels a bit early.

And can you comment a little bit on the progress you are making it terms of the $500 million of organic program to improve downstream returns?

First on Wilhelmshaven, when I say we will evaluate all opportunities obviously one of the opportunities is to go forward and do a full-scale upgrade of Wilhelmshaven.

Well, that is not really a realistic alternative.

What we are looking at is all the way from shutdown and writing off to how can we bring in a partner, how we can participate, and how we could dispose.

But the plan is not to do -- it's not consistent with the execution of our plan and emphasis on returns to spend billions of dollars to do a full-scale upgrade.

In terms of interest in the downstream opportunities for this disposition sale of refineries or assets, I think -- it looks like and not directed to ourselves necessarily, but it looks like some of the assets are being moved or sold from one owner to another owner.

And that is good to see in the marketplace but I think it is good to see that the market is recovering some returns in the downstream.

We would expect that to occur with the strength in the economy.

Some rationalization of smaller, less sophisticated refineries will give us opportunities to move on our portfolio possibly a little sooner than what we said in our March analyst meeting.

So that remains to be seen, but it's encouraging to see what is taking place.

Then I think the last was (multiple speakers) on our $500 million cost reduction program that was outlined in the March analyst meeting.

Yes, actually it was business improvement I think is the way Willie had characterized it.

That was focused not only on cost reduction, I think there is a hundred or a couple hundred million dollars of cost reductions in refining but it's also looking at how to optimize these facilities.

If there are some things that we could do within the portfolio, if there are capital avoidance opportunities for us, and I would say those are moving forward.

Actually our operating expenses were down about $100 million sequentially, a big part of that was turnarounds.

But I know that Willie and the downstream guys are focusing on looking at every refinery every day on continuous optimization of what they have.

And then maybe there are some portfolio things that we could do that would help us as well.

And perhaps one follow-up on healthcare costs, just because you have seen obviously a charge taken at Exxon.

Where is the status with respect to your own healthcare costs and the adjustment to the legislation?

It's hard for me to -- I am not as well versed in all of how to explain this, but essentially the either incentive that was available we didn't do.

And so essentially our programs are consistent with the way other companies are changing or adapting to.

We did this sometime in the past and we don't have charges upfront as adopting or adapting to the new rules.

So we don't expect a significant increase in costs associated with that?

No, no.

Not for the implementation of the new healthcare proposals.

On the other hand, there is no doubt that the cost of healthcare is continuing to be a real challenge.

I am not saying that is not a challenge, but the implementation of the new healthcare proposal passed does not result in an upfront charge for our company.

Thank you.

Blake Fernandez.

Good morning.

My question is on the divestiture program.

The Syncrude transaction price was quite impressive; I think probably well above what most people were expecting.

I am just curious if that changes your thinking with regard to the $10 billion target.

Any thoughts on potentially either increasing that or potentially exposing fewer assets to the market?

Well, it doesn't change our objective of $10 billion.

Potentially that could be more, it could be a little less but we are really thinking about $10 billion.

What is good about the 9% sale of Syncrude is, yes, we are quite pleased with the price but if you look at the metrics of assumptions going forward of oil prices and discount rates you get to that number.

What is our objective?

Our objective is to define the assets that aren't that strategic to our company that we can sell at a very favorable price that is tax efficient.

And to the extent we do that well then we minimize the amount of assets that we need to sell and we can retain in the portfolio.

Quite frankly, what we are trying to do is get the maximum for whatever we sell to minimize the impact in terms of our E&P portfolio.

Obviously, oil assets are more of interest than our natural gas assets.

And so to the extent that we do each asset disposition well that takes off the pressure with respect to reaching the $10 billion program of what we ultimately need to be selling.

But on the other hand, if you look back over the last several years we haven't done too much in the way of dispositions.

And if you look at the size of our company and portfolio we should be pruning and doing a couple billion dollars of asset dispositions every year by saying what no longer is that strategic, maybe a little bit more mature that is more valuable to someone else.

If it's tax efficient then we could sell it and redeploy the funds to upgrade the portfolio is something we should be doing every year.

All right, that is great.

Thank you for the comprehensive answer, Jim.

And then just the final question for me.

Clayton, you had mentioned the Eagle Ford and aggressively pursuing that.

I just wanted to confirm, I assume that means not only increasing the drilling program there but also potentially adding to acreage in the area?

I don't think that acreage addition makes sense for us at the kinds of prices that we are seeing for acreage.

I think my comments on aggressively pursuing around Eagle Ford had more to do with adding number of rigs and number of wells drilled and the amount of capital and expense we were going to invest in that business.

But I don't see our acreage in Eagle Ford increasing.

But, Jim, I don't know --?

I think it's the work activity associated with the 240,000 acres that we see really good opportunities to really go after it.

That is where we are going to allocate and spend more money.

We got into Eagle Ford a couple of years ago at (inaudible) purchase and got the acreage at a very reasonable price.

We looked at the prices now of many of these plays and, frankly, it's hard to show what people are paying you can see a reasonable return.

Maybe that changes in the future but our allocation of capital and spend is more to get out of what we already have.

Thank you for the clarification.

That concludes our Q&A session.

Great.

Why don't I just take a second and close up?

Again, thanks everybody for participating.

Find this information on our website and certainly Vladimir and I are available for follow-up questions.

Thank you again.

Thank you for your participation in today's conference.

This concludes the presentation.

You may now disconnect.

Have a great day.

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