Good morning. My name is Sean and I will be your conference facilitator today. Welcome to Chevron's First Quarter 2009 Earnings Conference Call. At this time all participants are in a listen-only mode. After the speaker's remarks there will be a question-and-answer session and instructions will be given at that time (Operator Instructions). As a reminder, this conference call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead. Patricia E. Yarrington: Thanks Sean. Welcome to Chevron's first quarter earnings conference call and webcast. Jim Aleveras, General Manager of Investor Relations is on the call with me. Our focus today is on Chevron's financial and operating results for the first quarter of 2009. We'll refer to the slides that are available on Chevron's website. Before we get started please be reminded that this presentation contains estimates, projections, and other forward-looking statements. We ask that you review the cautionary statement on slide two. Slide three provides an overview of our financial performance. The company's first quarter earnings were $1.8 billion or $0.92 per diluted share. Our first quarter 2009 earnings were down 64% from the first quarter 2008. First quarter 2009 fell 62% compared to the fourth quarter of 2008 which Jim will discuss shortly. Return on capital employed for the trailing 12 months was 22%, the debt ratio was about 12% at the end of the quarter and Jim will now take us through the quarterly comparisons. Jim.

Thanks, Pat. My remarks compare results of the first quarter 2009 with the fourth quarter 2008. As a reminder our earnings release compared first quarter 2009 with the same quarter a year ago. Turning to slide four; first quarter earnings were down $3.1 billion from the fourth quarter. Starting with the left side of the chart, lower crude oil and natural gas realizations reduced the company's worldwide upstream earnings. Additionally upstream results were adversely affected by our foreign currency variance of about $600 million and the absence of a $600 million asset exchange gain recorded in the fourth quarter of last year. Partly offsetting was the benefit of higher upstream volumes in the first quarter. First quarter downstream results were also sharply lower than the fourth quarter, largely due to the absence of favorable fourth quarter timing effects. The first quarter included $400 million benefit from asset sales. The other bar primarily reflects lower corporate charges. Slide five, summarizes the results of our U.S. upstream operations, which declined to breakeven in the first quarter. Lower crude oil and natural gas realizations reduced earnings by $480 million. Chevron's average U.S. crude oil realizations were down about $14.60 per barrel between consecutive quarters, somewhat less than the nearly $16 per barrel drop in the average price of West Texas intermediate. Of the $480 million total variance shown on the chart $100 million was due to lower natural gas realizations, which fell about $1.10 per 1000 cubic feet between quarters. The absence of the $600 million gain on our fourth quarter asset exchange transaction was responsible for more than half of the earnings decline between quarters. Lower operating expenses benefited first quarter earnings by $130 million. The other bar reflects lower gas marketing earnings, along with write-offs associated with exploration activities and higher DD&A rates. Turning to slide six; international upstream earnings for the first quarter were about $750 million lower than the fourth quarter's result. Lower oil and gas prices reduced earnings by $465 million. Our unit realizations for liquids fell by about $7.40 per barrel, somewhat less from the $11 per barrel decrease in brand spot prices. Higher first quarter lifting's particularly in Kazakhstan, Nigeria and Republic of the Congo, improved earnings $105 million. Operating and exploration expenses were down $210 million from the fourth quarter, the OpEx reductions were spread among all major geographic areas and multiple cost categories. The FX and other bar is essentially all related to foreign currency effects which were a $644 million gain in the fourth quarter compared to a $33 million gain in the first quarter. Slide seven, summarizes the change in world wide oil equivalent production, including volumes produced from oil sands in Canada. Production rose 123,000 barrels per day or nearly 5% between quarters. Volumes were up 52,000 barrels per day in the United States and 71,000 barrels per day internationally. Lower prices lead to a 46,000 barrel per day increase in our production. More than half of this amount reflected higher cost recovery entitlements and there are Indonesian production sharing agreements. Restoration of production in the Gulf of Mexico after last year's hurricanes increased OEG volumes by 41,000 barrels per day. At the end of the first quarter about 35,000 barrels per day remained off line and are expected to be restored as third party pipelines and facilities are repaired. External constraints reduced production between sequential quarters. Reduced production in OpEx member countries was partly offset by higher natural gas sales in parts of Asia. Our worldwide base business decline of 13,000 barrels per day represents an annualized 2% decline versus our guidance for 2009 of a 7% base business decline. The 7% estimate for the full year is still our expectation. There's just a lag between reduced investment and reduced production. Ramp-up of production at our major capital projects added 65,000 barrels per day to first quarter volumes. Blind Faith, which started up last November and Agbami which is continuing to build to its 250,000 barrel per day target were the two largest components of the increase. Higher volumes from the Tengiz expansion were also a contributor. Last quarter, I provided a general rule of thumb that we expected that each dollar change in crude prices would inversely affect production by 1200 barrels per day. You may have noticed that the volumetric impact of price shown on this chart was a larger amount in the first quarter. The difference reflects the non-linear nature of price effects and reinforces the need for caution using rules of thumb, as I've mentioned before. We'll provide an update on the price volume relationship next quarter. Turning to slide eight, U.S. downstream earnings declined $900 million in the first quarter. The overall impact of lower marketing and refining indicative margins was $160 million. On the West Coast refining margins strengthened somewhat between quarters. But the impact was more than offset by weaker marketing margins. Lower sales volumes reduced first quarter earnings by $80 million. This reflected some plant maintenance at our El Segundo, California refinery along with lower lubricant base oil sales. The variance in timing effects between quarters was $760 million. On an absolute basis timing effects were a loss of about $16 million in the first quarter consistent with the direction projected in our April interim update. The comparable fourth quarter timing effects were $700 million gain. The first quarter absolute timing effects were much smaller due to the phasing out of provisional pricing for our major supply contracts, reduced use of derivatives to lock-in margins as well as the lower volatility of crude oil and refined product prices in the first quarter. Moving to operating expenses; they were a favorable variance of $225 million between quarters, reflecting lower fuel and marketing expenses. The other bar on this chart is a variety of miscellaneous items including trading losses, and an adverse product mix compared to that assumed in the indicated markets. Turning to slide nine; international downstream earnings fell about $360 million in the fourth quarter's results. Unbalanced refining and marketing margins reduced earnings by $80 million between quarters. Margins were down in all regions except Latin America. Timing effects represented a $990 million variance between quarters. On an absolute basis they added about $850 million to fourth quarter results in this segment, while they reduced first quarter earnings by about $140 million. The timing effects in the first quarter were mainly associated with derivatives used to lock in margins and long haul crude oil and refined products. We closed the previously announced sales of our fuels marketing in Nigeria and Brazil which added about $400 million to first quarter earnings. Operating expense was lower across most regions in cost categories for a favorable variance of $170 million. Previous tax items and trading profits made up the majority of the $143 million shown in the other bar. Foreign currency effects were partly offsetting. Slide 10 shows that earnings from chemical operations were $39 million in the first quarter compared with $28 million in the fourth quarter. Results for olefins fell on lower margins. Aromatics earnings increased due to the absence of the fourth quarter impairment charge and some improvement in volumes in OpEx. Chevron's Oronite additives subsidiary had lower earnings due to weak demand. The other bar is due to a favorable swing in foreign exchange effects. Slide 11, covers all other; first quarter results were net charges of $294 million compared with net charges of $365 million in the fourth quarter. Lower expenses within corporate departments and a favorable change in foreign currency effects were partly offset by adverse swing in tax items. The result for all other was within our guidance range. Before turning the call back to Pat, I'd just like to briefly recap the first quarter. First upstream earnings fell significantly due to the absence of prior period gains and lower commodity prices, although production volumes increased, all in line with the interim update. Second, downstream results saw adverse timing effects in contrast to sizeable gains in the prior quarter. These were partly offset by asset sales gains also mentioned in the interim update. Pat will now summarize our operational and strategic progress. Pat. Patricia E. Yarrington: Thanks, Jim. Turning to slide 12, I'd like to update you on our operational performance so far in 2009. We projected upstream production growth and you saw the 65,000 barrel per day contribution from our major capital project ramp ups in the earlier production chart. We set an objective for reliable refinery operations. For our major operated and affiliate refineries first quarter crude unit throughput was about 94% of capacity, higher than any quarter in the last two years. As we described in our March Analyst Meeting, we're driving for lower costs across the enterprise. We've had well over 1000 individual meetings with key suppliers at the local, regional, national and global levels in pursuit of lower cost. In addition to focusing on cost sourced from third parties, we're aggressively managing down our internal costs. We're driving our own activities to be more cost effective and efficient. Some savings are already being seen. As shown on the prior chart OpEx was down in the first quarter in each segment. In first quarter 2009, before tax operating and SG&A expenses were nearly $0.5 billion lower compared with first quarter 2008. We're also managing our capital and exploratory expenditures. I mentioned our industry leading global procurement processes at our March meeting, we're using these processes to ensure that our capital projects benefit from a declining input cost environment. And we're adjusting the pace of our capital investments to ensure the best returns in the current market. Now a brief recap of our strategic progress in recent months; please turn to slide 13. Our major upstream capital projects are on track to meet our growth targets. Offshore Nigeria, our Agbami project continue to ramp-up on schedule, achieving 175,000 barrels per day by the end of the first quarter and currently at almost 200,000 per day. We're on plan for Agbami to deliver 250,000 barrels per day peak production by the end of this year. In the Gulf of Mexico, Blind Faith started production in November of last year. Production ramped up to its full target of 70,000 OEG barrels per day in March. Also in the Gulf, Tahiti remains on schedule for first oil shortly. Final hookup and commissioning are essentially complete. All six producing wells have been completed and are expected to ramp-up to peak production of 135,000 OEG barrels per day by the end of the year. Offshore Brazil, Frade is on schedule for first oil by the latter half of this year. The FPSO is moored onsite with sub-sea installation and facility hookup underway. Production is expected to reach 90,000 barrels per day in 2011. Offshore Angola, Tombua Landana remains on schedule for first oil in the second half of this year. All top fives (ph) are in place and hookup and commissioning are continuing. Peak production of 100,000 barrels per day is expected to be reached in 2011. In the Gulf of Mexico our Jack and St. Malo project is progressing and it's projected to enter front-end engineering and design soon. Our industry leading exploration program has continued its success with the Buckskin discovery in the Gulf of Mexico Lower Tertiary trend. We also announced the successful completion of a seven well exploration and appraisal program for the Wheatstone, Iago field's offshore Australia. And yesterday the Environmental Protection Agency of Western Australia said that our Gorgon project could meet the EPA's objective conditioned on certain criteria's. We welcomed the decision as we work towards the final investment decision later this year. In the downstream our portfolio rationalization continues to move forward. And as Jim mentioned we recorded a gain of 400 million on the sale of our fuels marketing businesses in Nigeria and Brazil. We're also continuing to focus on refinery reliability. In summary, we're executing our plans to position Chevron for both current earnings and long-term growth. That concludes our prepared remarks and we'll now take your questions. I'd ask that you please try to limit your follow-up questions so that everyone has an opportunity, to ask what's on their mind. Sean, please open the lines for questions. Thank you.

(Operator Instructions) Our first question comes from Mark Gilman with Benchmark.

Pat and Jim good morning to you. I wanted to talk a little bit about the timing on the ramp-up on Frade and Tombua Landana. Any particular reason that the plateau won't be achieved until 2011, with the second half 2009 start up. Is this a development drilling and rig constraint or something else?

No, I think it's really just the scheduling around when the producing wells are planned for startup Mark. It's a scheduled plan.

There's been no changes in that Pat?

There's been no changes in that. We've been very consistent on those schedules for several months.

Okay. If I can just add one other follow-up. The $100 million after tax charges the write-offs in U.S. upstream, could you talk just a little bit about what that is more specifically? And I'm assuming -- please correct me if I'm wrong that it's not included in the report of exploratory expense in the quarter?

Mark, it's a combination of things that are primarily exploratory in nature but some of them runs through DD&A. They have to do with write-offs and write downs of exploratory wells, as well as things that are related to that, that we went through DD&A.

Jim, that's not usually clear.

Well. I can't be a whole lot more clear than that Mark. That what we have is fairly straight forward here. This is the sort of thing that we see regularly. We have increased dry hole cost quarter-over-quarter. We had things like an unproved property write-down, which runs through the DD&A rate and it's just a number of small items.

Okay. We will take it offline. Thanks folks.

Our next question comes from Jason Gammel with Macquarie.

Thank you, good morning everyone I had a couple of questions on Western Australian Gas. The first is with the Gorgon environmental approval process now essentially complete is there anything that stands in the way of final investment decision other the final partner approval and would you expect to be able to reach the final investment decision this year?

Well, it's a good question Jason thanks. What will happen now is that there will be a period of public commentary. A short -- relatively short period of opportunity for public commentary; we then will need to respond to those issues that are raised in that. We actually believe that by having the Western Australia EPA announcement now and the ability to move through the public comment period and the response period that we are -- we'll be able to stay completely on track with final investment decision before the end of the year.

Terrific. That's what we were hoping to hear. And then if I could turn to Wheatstone and Iago, you mentioned that the exploration and appraisal program is complete can you talk about next steps? Will you be moving the project into feed this year, marketing LNG volumes et cetera?

We do -- because of the successful appraisal program; we do expect to be able to move into feed in the second half of 2009.

Great, thank you very much.

Our next question comes from Paul Cheng with Barclays.

Hey guys.

Good morning.

Good morning. Pat and Jim; when you were talking about the cost saving, can you give us a number that how much is yield per year, first quarter '08 to first quarter '09, your total cost saving may be and what is that as a percentage to your total controllable cost. I'm more interested in the cost saving if we're excluding the effect from the FX and the energy cost saving?

Yeah Paul, I mean I appreciated the question completely and I can understand why you want to have as much segregation as you can. But let me just talk broadly about our emphasis on driving cost lower both from an OpEx standpoint and a capital outlay standpoint. We've met with as I said with thousands of suppliers in these one-on-one meetings all around the global. The meetings are having successes. But as you can imagine, with the contract renegotiations it's not everything starts on March 1st or April 1st or May 1st. So there is a bleed in time to when these new contractual and lower negotiated rates will take effect. So there's not an easy way to get to an absolute number for you. Secondly not everything is moving in this -- in a uniform manner. It really depends on the cost category that we're talking about and how that cost category is linked to economic growth, commodity price levels, supplier concentrations, the amount of backlog that they have in there, fabricating yards et cetera. So on land rigs it's very fluid we've seen reductions of anywhere from 35 to 50% versus a year ago. Major service providers; we've seen contract renewals that are 15 to 20% lower. Obviously any piece of major equipment that's requiring steel will have significantly lower cost. You know as well as I do that steel prices are down 60% from their peak and the same is true for other commodities as well. The fabrication or engineered units are really dependent upon the degree of commoditization of the unit. If it's a unique piece of equipment with strong demand and there aren't very many manufacturers then we're not seeing tremendous amount of price break at the moment. But if it's a more standard more commodity type, engineering requirement and there is flat capacity or -- then we're seeing a high degree of cost pressure is evident we're able to take advantage of that. I think we mentioned at the Analyst Meeting that offshore the deepwater rigs are rig rates are much stickier. And that's due to sustained offshore demand and for some extent capacity constraints near-term. I mentioned in our analyst meeting that we have indexed a number of our contracts. And we also have global master agreements that allow us to really secure procurement leverage. So depending upon the cost category we've seen contract term reductions anywhere from 50 to 60% down to five to 10%.

Pat can I have a follow-up question? In your 2009 CapEx of 22.9 billion the actual is number is more (ph) like 20.6, because you have 2.3 billion is on the on the sign on bonus upfront? What's the -- can you give us a rough idea what's the percentage of that spending that you talked is already a locked in and fixed price contract or that in other words what is the percentage that may be subject to the benefit as the day rate or that the raw material spot rate continue to come down?

Yeah, I mean I think a majority of that spending certainly is under contract terms with the contracts having been laid (ph) several months ago. So I think you need to think of a majority of that as not being spot determined. But having said that I mean we are having these discussions with these key suppliers, as we speak and so we're working very hard to pay a secured lower cost.

Very good, thank you.

Our next question comes from Paul Sankey with Deutsche Bank.

Yeah hi everyone. Good morning. I just -- looking at your cash balances, with back into a number of around $4.7 billion of cash from operations, if I add the DD&A to the net income and aligned for the $400 million of asset sales. I end up about $1.7 billion below your CapEx number. It doesn't quite jive with the way your debt moved, which seemed to go up more than that over the course of the quarter. Is that a working capital movement or am I missing something completely? Thanks.

Yeah that's a good question Paul. I mean we did have an increase in our net debt of about $3.5 million here. This obviously did reflect the poor operating cash flows related to commodity prices. But also importantly there is the capital program amount which did include a significant bonus payment, which is not a ratable sort of thing. But in addition to that we did have a working capital increase. And that principally or there was a significant piece in there that was a non-ratable item that related to a crude purchase and sale agreement that was started a long time ago -- years and years ago, where we had very favorable credit terms on the purchases composed to the sale and -- as it relates to the sale and then that contract terminated in the first quarter. So that is something that you won't see again repeated in subsequent quarters.

Okay I think I understand. Are you expecting, can you remind me what you've been saying about pension contributions for the year in terms of cash?

Yes. We've said in our -- its not out yet, the number that we've used is $800 million. And that's the number that you will see in our 10-Q when it's reported as the expected contribution for 2009. We're not in a position of having to make a U.S. contribution at this particular point in time, but we're estimating 800 million for both U.S. and non-U.S. contributions.

And just jumping back to working capital the two elements you described to me, the bonus payments and the non-ratable crude contract; would those account for the difference? Did you just give me a working capital number, sorry I...?

Working capital was up $1 billion.

I've got you.

In the quarter, and a significant piece of that related to this crude buy-sell that I mentioned.

What -- do you think you'll move back towards the its -- say your crude stays at 50 bucks and we stay at 3.50 nat gas, would you expect your finances to get back in cash balance towards the end of the year allowing for your expected cost savings? Or you think this would still be a debt increase year for the remainder?

I think it's a more likely than not that there would be a modest increase in the debt over the course of the year. But I will have to caution that that it's highly dependent on the cost structure changes that we see coming forward in the last three quarters of the year. I don't think you've seen the you've seen the beginning of that but we expect that to accelerate in the remaining three quarters.

Is there any reason to specific to volumes to think that your 7% number. You mentioned I believe that the implied decline rate you had was 2% for Q1, but you expect it to hit 7%, I guess as a full year number. Which means you're going to go to, by the end of the year beyond 7% decline; if I'm thinking straight and how much variation is there around that element?

Paul, that would obviously hurt cash flows a little bit, but offsetting them is the ramp up of major capital projects. So if you look at our full year production profile you wouldn't really see a decline or the base decline being as big a factor in total as you would if you just look that at it in isolation.

Yeah. I get that because you've given us a full year volume...

That's right.

Expectation (ph) which includes that right?

Yes. That's correct. 2.63 million barrels of oil equivalent what we're expecting for the full year.

So effectively the major uncertainty is regarding the cash balance not the volumes as far as you are concerned, regardless of what you tell about decline rates accelerating?

The decline rates wouldn't be a big impact on cash simply because...

It's offset.

It's offset by growth in major capital projects.

No. what I meant is the uncertainties surrounding the costs that you're going to have to pay is a greater uncertainty than the volume uncertainty?

At this point, yes.

Yeah. I've got you. If I could and I don't think you're going be happy with me for asking this question, but it's a question I'm being asked a lot. Can you just got through the timing on the Ecuador decision. What the potential risk is there to the company and to shareholders? Thanks.

No, sure it's a very topical question so I can understand why you want to ask the question. First of all let me get the facts out as we see them here, we don't think the lawsuit has any legal or factual merit we did complete -- Texaco did complete a $40 million remediation program and the Ecuadorian government signed off on that that the sites were properly, remediated and they granted Texaco a full release from this liability. The evidence that we have suggest that the remediation was properly conducted and the remaining environmental claims and damage really are the responsibility of Petroecuador. It is possible that we could see a judgment come down any day now, I wish could be more specific about the timing but, I don't think it's necessarily immune from political influences as to when that timing will occur. But it could be any day; it could also be several months from now. We will appeal that judgment, whatever it turns out to be and we have courses of appeal to a sort of a panel of judges in the superior quarter of Lago Agrio and if necessary then all the way up to the Supreme Court of Ecuador. So I think that you could expect that this litigation aspect of this suit can go on for quite sometime. I don't think that there is merit in the case and we have a very strong legal as well as scientific data behind that. So from a shareholder perspective I think it's interesting to pay attention too certainly and be on top of it, but I don't see that there is financial impact coming as a result of this; significant financial impact coming as a result to this.

But, the judgment could be -- the number seems to be $27 billion?

Well. That is what the court appointed so called expert has laid out there, but there really is not much factual data behind the 27 billion nor is the individual an expert in any sense relative to the task he's been asked to do.

Yeah I guess okay, so I think I understand that what you are saying is we are not sure. There could be a decision any day. It is likely to be a very big number and you'll automatically appeal it which will then extend the process essentially for, probably years?

That's exactly right. And we think that the large number that's being bantered around is really very politically driven.

Okay. Thank you. I leave at that.

Our next question comes from Robert Kessler with Simmons & Company.

Hi, good morning. Just a couple of questions for me on the, one on the downstream timing effects; I know you've taken steps to reduce the volatility of the downstream earnings eliminating the preferentially priced foreign crude deliveries to U.S. and what not. I still saw some timing effects in the quarter though. I'm curious if you have any rough expectation going forward as opposed to a significant negative correlation between timing effects and movements in crude prices? Should we just model zero benefit or detriment going forward regardless of what crude prices do, or do you have any rough indication on the order of magnitude and direction going forward there? And then just a quick question on the -- any benefits in the downstream associated with the Contango ship (ph) that the crude stripped (ph) over the course of the first quarter? Thanks.

Robert let me just address those two real quickly for you here. In the U.S. downstream we pretty much wrung out a lot of the impacts as we have talked about in prior quarters. So the provisional price (ph) foreign crude is going to be pretty -- very-very minor only on some minor contracts that aren't necessarily ratable like our major ones. And there would be from time-to-time some derivative activity only if we get outside of a typical band. So I'd say that for purposes of looking forward the timing effects should be in the U.S. downstream, fairly minor and not something that I would internally project to be significant. Now in the international downstream, we still use as I've described in past quarters derivatives to lock in margins on long haul crude sales from the partition neutral zone as well as long haul product sales from our Pembroke refinery in the UK which is an export refinery. This is where we sell the product on a deliberate basis. It's priced in a deliberate basis but the buyer takes the title. So effectively we're selling it FOB. So we do use derivatives to lock in margins on those sales. So in the international downstream you will see a modest timing effect that will be related in virtually to product and crude prices on a going forward basis. But again it should be more modest than what we've seen in the past, but not as significantly reduced as in the U.S.

Okay. Thanks.

Is that helpful?

It does. Thanks.

Now you had a second question...

On the Contango (ph).

That really isn't a great big factor for us. Our trading activities compared to some of our competitors is much smaller in overall size.

Okay. Thank you.

Our next question comes from Erik Mielke with Merrill Lynch.

Hi good morning. I have question on your production guidance for 2009. Would it be fair to say that that's looking increasingly conservative, given the pace of development and the ramp up at the various major capital projects that you have coming on in 2009?

I think it is the number that we want to standby at this particular point in time. I mean, the one thing that you'll recall I mean I think we feel very confident about our ability to execute on these major capital projects and to have the profile that we outlined back in March. The one area that's slightly different this first quarter than what we had expected was that we had expected in putting that forecast together earlier on, that there would be demand curtailment, OpEx on one hand but also market forces on the other for pipeline gas particularly in the Asia-Pacific region. We haven't seen that through the first quarter, from Chevron standpoint and so we've got an uptick there. I think that really depends going forward on our ability to supply those markets versus some of the competitions ability to supply some of those Asian gas markets.

Okay. That's useful. Can I ask it specifically on Tengiz, there was a story in one of the interesting journals a couple of weeks back, that TCO is looking at a potential boost to production from existing capacity, from existing synergies this summer. Is there any creditability to that story, the numbers were not immaterial?

Right no, I actually saw that as well and all I can tell you is that we do expect to hit full capacity in the second half of the year. Ramp up is continuing there.

Okay, thanks I'll leave with that.

Our next question comes from Mark Flannery with Credit Suisse.

Hi, sort of got two questions. One on cost; on slide 12 when you say you're targeting both operating expenses and capital expenses, can you give us an idea of what you're target is? In other words, are you going for 5% reduction over the full year or 10% reduction or other things being equal, just give us a sense of where do you think you can get to?

Mark, I don't have a target that I want to give you. I think I tried to explain before about how we're going after it, how it's different by cost category, how the ramp up period depends on -- it's going to be very sequential over the remaining months of the year. So I don't have a particular target. I will say that we're down 8%, quarter -- first quarter over first quarter on the SG&A and Op expense line and we do expect that to accelerate. So I would expect that pattern to continue to improve as the year progresses. But I don't have a specific percentage target to layout for you. We do have -- I will say we do have line-by-line items in our business units and in our staff group about cost reductions, opportunities and commitments that are being made, all around the globe. So there is huge effort in the company and huge specificity in the company about what those opportunities for cash conservation are.

Okay.

And we we'll track them and expect them to be realized.

Okay. Maybe I could then shift over to the dividend. You kept the dividend flat this quarter. Do you intent to grow the dividend this year or how should we think about the progress of dividend payments in the lower part of the cycle?

Right, it's a good question Mark. We do have a strong history of dividend growth. We've been having increasing payments in each of the last 21 years. The dividends so I -- are by the Board and I don't, in any way want to step in front of that call. But we do know that dividends are priority for our shareholders. We did hold it flat in the second quarter here and we got competitive deals and competitive payouts. But we think holding it flat was sort of consistent with and prudent in uncertain economic environment that we're in the low commodity prices. All I can tell you is that the Board will look at this every quarter. And we're proud of the record that we've had. We understand the prioritization and they will move it when they feel that it's a prudent course of action when it comes.

Okay. Thank you very much.

Our next question comes from Doug Leggate with Howard Weil.

Good morning Pat and Jim.

Good morning.

Hi, Doug.

Hi guys. My question -- I'm going to start off with DD&A. It's up about 30% year-over-year. I know though obviously there has been some new projects come on line, but can you just walk us through why such a significant move and may be split the international upstream and the U.S. upstream out of that number, so we can get an idea of what's going on there, any clarity on that would be helpful?

But Doug, I don't have the details in front of me. The increase in DD&A is partly related to accretion expense and to a number of other things that you see in the first quarter when we do a DD&A rate review. And we also have a situation where there are lot of impairments and charges that run through the DD&A line when they are taken, such that they are more or less discreet items and they tend to distort what people perceive as DD&A being a flat thing which would be the case in a in an industry that didn't have unit of production DD&A. I don't see the trend being dramatically different, I look at that DD&A rates and the impact of rates which have changed just a little bit but, they are not that dramatic. Instead what you are seeing in the year-over-year comparison is more or less the impact of the discrete items going back to what I was talking to Mark Gilman about in response to his question, the fact that we take for example, some unproved property write-downs those hit the DD&A line. So that can be a little misleading in periods when we're taking charges of unproved properties and other things that tend to run through DD&A, they're shown there but that's not a reflection of the underlying depreciation and depletion that would be ongoing.

So, Jim just may be you can spell it out for me then, what is the if your DD&A this quarter was 2.87 billion, so we're up about 600 and change over last -- over Q1 last year and up about 300 from Q4. What would you define then as the clean underlying DD&A, in other words what should our run rate be going forward because that's heck of a move?

Very-very good question and one I'm a little...

It also relates to higher volumes in the quarter as well though.

Yeah. Right.

The absolute number -- the absolute number you just quoted relates to absolute volumes as well.

Okay. So production was up 2.5% but DD&A was up 30%?

I would need to break out the components of that, I don't have the pieces in front of me. We'll be prepared to address that question in more detail and I think you'll have a better basis of comparison next quarter when we're comparing six months to six months.

Okay so generally...

But I'll make sure I have those pieces in front of me on the next call.

All right thank you, I don't want to labor (ph) the point but what I'm reading from what you are saying then is you would expect that DD&A absolute number to come down quite a bit in second quarter. Is that a fair interpretation?

I would expect six months of 2009 to be not dramatically different from six months of 2008 adjusting for the factors that Pat mentioned such as, as volumes and so forth.

That's sounds pretty clear.

And we would have to then look then at what the discrete items hitting DD&A were in each year; both credits and debits and pull those out and I'll be prepared that next quarter on a six month basis.

Great, thank you. My follow-up if I may is, still got a decent amount of productions shut in the Gulf of Mexico. Something you don't talk about any or not recently has been the ongoing semi-permanent shuts in Nigeria. Can you just give us an update on what you expect the -- as your best guess anyway the likely timing of any recovery in Gulf or for that matter in Nigeria, or in any others that I've missed in my question?

Well, let me address the timing in the Gulf first. That we're running a little slower than what we had been projecting in terms of restoration. We're basically right now where we had hoped to be at the beginning of the year. And that's really a function of things that are not under our control, such as the recovery of third party gathering alliance pipelines and processing facilities. What we should be looking for in Nigeria is probably something more or less similar in the future with the increase in Agbami being the big swing. But we don't see any significant production disruptions in Nigeria. Obviously there are parts of Nigeria where we have production that we probably aren't going to be bringing back on line in the near-term. But on the other hand, the onshore Nigeria is not a big contributor to our earnings.

Got it I understand. Forgive me, if I could jump right very quickly to the DD&A question, it might be related or might be me squeezing in the third question here, but the two...

We're no longer limiting questions expect to a prudent few. But it's no longer one per.

I appreciate that. Well the $2 billion concession extension, where was that -- was it any reserve additions associated with that? And is that maybe part of the DD&A explanation and that's it for me. Thanks.

I don't believe it will be part of the DD&A explanation. I would be unable to tell you where it occurred. We described in our CNE press release what the two onetime bonuses were; this is the larger of the two hitting. But because of contractual commitments we can't be more specific than that.

You know what Doug, just as a final thought I'd ask you, I know you're focused on DD&A here but I'd ask you to go back and pull up the slide that we showed in the March analyst meeting where we talked about our advantage downstream cost structure which takes into account the DD&A as well as production operating costs et cetera. And you can see we're very competitive on that. So DD&A is one component of the cost structure, but certainly there's other things that going into that and from a competitive standpoint we looked very good.

Okay thanks Pat.

Our next question comes from John Levin with Levin Capital.

Could you outline the Jack Malo fuel in the Gulf sort of both the economics and the size, there've been various estimates on it. Could just help to find that, your best estimates at the moment please?

Well I think, we have said that we're in the process of entering feed. The production capacity is expected to be between a 120 and 150,000 barrels of oil equivalent per day. George talked in our analyst meeting about the need to have significantly sized opportunities here and that you need a reasonably large sized reservoirs that will have a long lifed production profile to them.

Right and what economics is sort of baseline price you need to have a margin of safety?

You know I think it's really hard for us to say at this particular point in time, we're just entering feed, the cost structure is very much influx. Obviously we feel comfortable going forward at this stage, into feed with this project. We'll have a much better idea once we get information from that part of our project management process done with.

And when would that be...?

As far as I can say.

When would that be you think, in timing?

I think that's probably 12 to 18 months.

Got you, thank you.

Our next question comes from Mark Gilman with Benchmark

I wonder if I could talk or you guys to talk a little bit more about the foreign downstream numbers. If we add back Jim the 140 million in timing differences, it takes that number on an adjusted basis, if my math is correct which might a leap of faith, up to nearly $500 billion. Which I guess in my mind, in light of the environment in light of the very weak shipping earnings components which I'm sure is in there, very weak or in chemicals component which I know is in there. It just seems very-very strong in the context of the environment. Are there other drivers associated with that?

No there aren't Mark. I think you have to look at the impact in the international downstream obviously we had assets sales this quarter.

Yeah, I've taken that out?

Right. If you pull that out and look at the operations that's pretty much a baseline result. There wasn't a whole lot of unusual noise there. Obviously we were running our refineries very well. We moved a lot of product. But there wasn't anything there that was in the first quarter that I can point to that was very unusual.

No LIFO or inventory effects?

Not significant.

Yeah. And continued emphasis on operating expense reductions.

Okay. Guys, thank you.

Our next question comes from Neil McMahon with Sanford Bernstein.

Hi, just a few that probably haven't been covered yet. First of all, just looking at olefins, can you give us your cash breakeven for your olefin operations? And obviously with your portfolio which has expanded pretty rapidly over the last few years there. And what are your views specifically on the cost of developing that asset base up in Canada?

Yeah. I think we should leave the cash breakeven question to the operator. But as what we've seen across all development opportunities here, the cost structure is moving down. I would also say that the light heavy differential probably moved in terms of favor for a tar sands olefins type of opportunity here in the first quarter. That's not good for other parts of our business. But I think it was appropriately positive for the olefins activity. Does that address your question, but I'm really -- I really think we need to leave it to the operator to address the cash breakeven. Tremendous emphasis on cost containment, cost structure improvements that are going on there; we're not going to go forward, the joint venture has decided not to expand on the second phase of that. And so the efforts to-date are really on improving the cost structure and the reliability of the operation that we currently have.

So I am presuming like Shell and Myers (ph) you also met a loss in that business in the first quarter?

Yeah. I think it's important to understand that we have a 20% non-operated interest in the Athabasca project. And we aren't going to disclose the financial results; we're going to see those in the international upstream segment. But you make a reasonable assumption about that given the prices.

Just may be on your you've talk a bit about dividends maybe just switching to buybacks, one of your larger peers made a reduction in their buyback guidance yesterday. Just looking at yours going forward what could you say for the rest of this year in terms of buybacks and what would trigger you to go either plus or negatives on the buybacks going forward?

We suspended our share buyback program for the first quarter and we're not continuing it in the second quarter. And I think if you've got commodity, price conditions as we have currently; I think it would be unlikely that we would reinstate that share repurchase program for 2009. We do have a strong capital program and so that's where our priority really is. We've already talked about the dividend, that's a priority as well. And so we look at the share repurchase program as being the most discretionary element of our cash use.

Given that decision which was made when you're looking forward, do you have a particular -- having run the financials in your business, do you have a particular oil price that or a blended oil and gas price that it seems to make sense where your generating enough cash to step out or to go back into the buybacks again?

I don't think I want to go down that path with you there. I think you just need to -- on your own set of models; with your own set of commodity prices and all production growth increases that we've outlined, capital program that we've outlined; I think come up with your own estimates on that. I just need to reemphasize that the share repurchases come after the dividend and they come after the capital program and our capital program we've got a long queue of projects here, a lot of opportunities for organic development that are important to us and that are legacy building assets and that's really where our prioritization is.

But maybe just to summarize this, well if your, your self (ph) not in control looking forward of the financial situation what is -- the philosophy hasn't changed then in terms of what it had been over the last few years in terms of priority?

No, in fact the philosophy has not changed. I mean we put a high priority on maintaining financial strength and flexibility, maintaining our double A rating, funding our projects and paying sustained and growing dividend that's really our priority.

Okay so...

And that hasn't changed and I think you saw going back to the analyst meeting, I put up a chart that talked to -- what we have done, how we have managed our balance sheet over through thick and thin times from commodity price cycle standpoint.

Okay.

So I think our posture has been very consistent.

May be just a very quick last one, anything any update on interest Iraq?

Obviously we are interested in Iraq, it could have -- could turn out to be a real opportunity for us. But that depends really on the terms and conditions. The Iraqi's did just put out new kind of bid around terms. We're in a process of evaluating those. We do believe that they have made some improvements. But I don't want to comment any further than that. We know the bids were due and that they will be opened up at the end of June, I believe it is. And so we'll wait and see what comes of that. But obviously it's a prospective area. But it really will depend on the fiscal terms that are to be realized.

Okay. Thank you.

Okay. I think that -- pretty much -- we have one more question.

Our final question comes from Paul Cheng with Barclays.

Hey guys, I will be real quick. Jim, if I look at page nine, in the international downstream you have other policy of 143 million of the benefit. And you are saying that it was trading profit. To assume -- if I looked at and also foreign exchange I suppose. So if I look at that it seems to suggest your trading profit is roughly about 118 million for the quarter, is that on the ballpark, correct? And secondly on the DD&A increase sequentially from the fourth quarter are they all in the upstream or that some of them you see in the downstream also?

Okay. Let's take that one other time. We are talking international downstream other and what I said there was we had tax items and trading profits, made up the majority with foreign currency effects offsetting. So in order of size, favorable tax items relative to the fourth quarter were the largest in that swing. Trading profits for next and of course foreign currency is what you see in terms of the 84 million adverse change.

So the tax item is a bigger impact than the trading profit?

Yeah. I always give you the impact in the order of size.

I see. And can you -- seems that some of your competitors like Shell and BP they make a huge killing in the first quarter from trading. Any kind of rough number you may be able to share?

No. Again we did not make a huge killing simply because we don't have large trading activities from book. The trading and derivatives that I talk about in conjunction with the downstream are used to lock in margins. We don't use hedge accounting, so we talk about them as derivatives, but they really are meant to be risk management tools. So trading for our own book relative to some of our competitors is very small. One of our larger competitors does virtually none. So we're pretty small in terms of trading for own book.

Okay.

Except that I mean, we did see the commercial opportunity and we did have some positives associated with the Contango market. But it's much more modest than what you might have been reading on the part of others.

Okay, fair. How about DD&A?

DD&A was not a big factor here I mentioned

No, I was saying that DD&A increased, is it all the its close to 300 million, is it all related to the upstream or they're just in downstream or chemical or corporate debt (ph), also have?

No I mentioned it in the context of the U.S upstream. The impact in the international downstream was not as significant in terms of quarter-over-quarter change.

Okay, would do. Thank you.

Okay. That...

All right that's the end of the call.

Okay, so in closing let me say that we appreciate everyone's participation in today's call. I certainly want to thank each of the analysts on behalf of all the participants for their questions during the morning session. We do appreciate your interest in our company and we hope you share our enthusiasm. Our projects are ramping up well or executing well, we're on plan. We're operating very well. We are aggressively managing our spend, whether that's OpEx or CapEx. And we feel that we've got the flexibility to manage well in this environment, to achieve low unit costs, grow the business and put up very competitive returns. So thank you all. Sean, I'll turn it back to you.

Thank you ladies and gentlemen. This concludes Chevron's first quarter 2009 earnings conference call. You may now disconnect.