Good morning. My name is Matt and I will be your conference facilitator today. Welcome to Chevron's first quarter 2008 earnings conference call. (Operator Instructions) I will now turn the conference over to the Vice President and Chief Financial Officer of Chevron Corporation, Mr. Steve Crowe. Please go ahead, sir. Steve J. Crowe: Thanks, Matt. Welcome to Chevron's first quarter earnings conference call and webcast. Jim Aleveras, General Manager of Investor Relations is on the call with me today. Our focus is on Chevron's financial and operating results for the first quarter of 2008. We will refer to the slides that are available on the web. 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 2. I’ll begin with slide 3, which provides an overview of our financial performance. The company’s first quarter earnings were $5.2 billion, or $2.48 per diluted share. Our first quarter 2008 earnings were up nearly 10% from the first quarter 2007, reflecting higher crude oil and natural gas prices, which more than offset weaker downstream results. The first quarter of last year included a $700 million gain on the sale of our interest in a refinery in The Netherlands. First quarter 2008 earnings rose 6% compared to the fourth quarter 2007, which Jim will discuss shortly. Return on capital employed for the trailing 12 months was 23%. The debt ratio was about 8% at the end of the quarter. As we announced Wednesday, we increased our quarterly dividend by $0.07 per share, or 12.1%. This marks the fourth consecutive year we’ve raised the second quarter dividend by a double-digit amount. Stock buy-backs were $2 billion in the quarter. Jim will now take us through the quarterly comparisons. Jim.

Thanks, Steve. My remarks compare results of the first quarter 2008 with the fourth quarter 2007. As a reminder, our earnings release compared the first quarter 2008 with the same quarter a year ago. Turning to slide 4, first quarter net income was almost $300 million higher than the fourth quarter. Starting with the left side of the chart, higher crude oil and natural gas realizations benefited the company’s worldwide upstream results. Partly offsetting this was the impact of lower upstream volumes. The largest component here was international liftings. Liftings were lower than production in the first quarter. Downstream results were up slightly from the fourth quarter, reflecting improved refinery operations in the United States. The variance in the residual other bar is the net of everything else. Slide 5 summarizes the results of our U.S. upstream operations, which improved by about $220 million between quarters. Higher crude oil and natural gas realizations benefited earnings by $335 million. Chevron's average U.S. crude oil realization was up about $8 per barrel between consecutive quarters. This is more than the $7.25 per barrel increase in WTI’s spot prices, since much of our Gulf of Mexico crude oil production is priced on a lagged basis. Production volumes were down 2% between quarters, largely due to operational and weather related downtime, as well as normal fuel declines. This impact reduced earnings by $85 million. The $85 million DD&A reflects higher rates and higher accretion charges for abandonment. Exploration expense fell $90 million between periods. The primary factor was lower well write-offs in the first quarter. The other bar reflects miscellaneous gas marketing and income tax items. Let’s turn to slide 6. International upstream earnings for the first quarter were about $70 million higher than the fourth quarter’s results. Higher oil and gas prices increased earnings by $370 million. Our unit realization for liquids rose by $5.70 per barrel, significantly less than the $9.30 per barrel increase in brent spot prices. Comparing average prices for the first and fourth quarters, we found that worldwide benchmark crudes did not move consistently. For example, Malaysia’s light sweet tapas crude was up $3.20 per barrel between quarter and Sumatra Light rose $7.70 per barrel. WTI’s spot prices increased $7.25 per barrel, $2 less than the change in brent. Our realizations therefore reflected geographic market prices which were not in line with brent movements during this particular comparison period. Lower first quarter liftings, particularly in Azerbaijan, the U.K., Nigeria, and Australia, reduced earnings by $195 million. As I noted earlier, we were under-lifted in the first quarter, an issue we referenced in the interim update. Partially offsetting this under-lift is a one-time benefit from the retroactive effect of the unitization agreement in Indonesia we also mentioned in the interim update. Tax items reduced earnings by $230 million between quarters. These were spread among several countries and included the absence of favorable fourth quarter items we discussed on our last conference call. Operating expense was down $130 million from the fourth quarter due to lower seasonal activity levels in several international areas. The other bar reflects the net of many unrelated items. The largest components were adverse foreign exchange effects, offset by lower exploration expense. Slide 7 summarizes the change in worldwide oil equivalent production, including volumes produced from oil sands in Canada. Production fell by 14,000 barrels per day, or about half of 1% between consecutive quarters. United States production fell 15,000 barrels per day, about 2% due to operational down time and normal field declines. Outside the United States, overall production was flat between quarters. Kazakhstan benefited from the ramp-up of staged oil from the TCO expansion project. Offsetting this were reduced entitlements in Azerbaijan. Comparing the fourth and first quarters, the increase in international liquids realizations reduced our volumes by about 25,000 barrels per day, due to cost recovery and variable royalty provisions of certain production contracts. As we noted at our March analyst meeting in New York City, each contract is different and there are non-linear points when certain thresholds are reached. Looking at our 2008 production guidance, our general rule of thumb is unchanged. A $1 per barrel increase in crude oil prices will reduce our production entitlement by roughly 2,000 barrels per day. We caution that this is only an estimate and results will vary, especially for individual quarterly comparisons. In the context of our production, I would like to briefly summarize our upstream project status. As we discussed at our March meeting, the Tengiz expansion is on track with the first phase of staged oil meeting all of its targets and full facility start-up on schedule for the third quarter of this year. First oil at Blind Faith, our Gulf of Mexico project, forecasted for the late second quarter is now projected to occur in the second half of 2008 due to an issue with the mooring lines. The exact timing of startup is dependent on weather in the Gulf. As we mentioned at the March meeting, a fourth well was added to the initial development plan for Blind Faith. The acceleration of the fourth well reflects higher than anticipated reservoir quality. This well has now been drilled, completed, and is ready for production at the time of facility startup later this year. As indicated in March, gross peak production for Blind Faith is now expected to be 70,000 barrels of oil equivalent per day. Also in March, we said we expected first oil from Moho Bilondo offshore of the Republic of Congo in the second half of this year. This project has now started up ahead of schedule. In Nigeria, we expect our Agbami project to remain on track for a third quarter start-up. Overall, our upstream projects are moving forward. While we will provide an update later in the year, we are optimistic that when adjusted for price effects, our 2008 production will be on track with the guidance we provided in march that was based on $70 oil prices. Let’s turn to slide 8 -- our U.S. downstream operations moved from a loss position in the fourth quarter to break-even results in the first quarter. Industry refining and marketing indicator margins on the west coast weakened in the first quarter. Although refining margins improved somewhat on the Gulf Coast, marketing margins declined. On balance, especially given Chevron's west coast weighting, industry margins were an adverse $55 million impact between quarters. With the completion of our El Segundo refinery upgrade project at the end of 2007, the coker was back in operation and we were able to run heavier crudes. That helped to improve first quarter results by roughly $100 million. The swing in timing effects, such as the impact of provisionally priced foreign crudes, was $50 million better in the first quarter, since crude prices did not rise as much from the beginning to the end of the first quarter as they did in the fourth quarter. Sales of motor gasoline and jet fuel were down by 2% and 3% respectively. While diesel fuel sales strengthened between quarters, lower first quarter volumes resulted in an adverse impact of $50 million. Turning to slide 9, international downstream earnings fell about $10 million from the fourth quarter’s results. Refining indicator margins were lower while marketing margins were mixed across our international geographic areas. On balance, margins reduced earnings by about $30 million between quarters. Volumetric effects were a $70 million adverse variance. This reflected planned shutdowns at refineries in Canada, South Africa, Singapore, and South Korea. Additionally, marketing volumes were affected by seasonal factors in Asia and Africa. Higher charter rates resulted in a $70 million increase in international shipping earnings. The $19 million benefit in the other bar is the net of many items, including adverse tax effects and favorable OpEx variance. Slide 10 shows that earnings from chemical operations were $43 million in the first quarter compared with $69 million in the fourth quarter. Results for olefins improved on higher margins and volumes, especially for polyethylene. Aromatics were essentially unchanged as volumes and margins were mixed. Included in the other bar here is an approximately $40 million environmental provision we mentioned in the interim update, as well as the absence of favorable tax items we discussed on last quarter’s conference call. Slide 11 covers all other. First quarter results were net charges of $255 million compared to net charges of $237 million in the fourth quarter. Corporate tax adjustments had a $100 million adverse impact between quarters. Corporate charges shown were a favorable variance of $85 million. This largely reflects lower advertising and employee related expense. As we mentioned in the interim update, our current guidance for all other activities is a charge of $250 million to $300 million. Because of irregularly occurring accruals and other charges that affect corporate and other activities, we continue to expect volatility in this area and the possibility that actual results will lie outside the guidance range. That completes our brief analysis of the quarter. Back over to you, Steve. Steve J. Crowe: Thanks, Jim. And now a brief recap of our strategic progress in recent months. Please turn to slide 12. Jim touched on the Moho Bilondo deepwater project in the Republic of the Congo. We confirmed start-up ahead of schedule of this 31% owned partner operated project. It is expected to reach maximum total crude oil production of 90,000 barrels per day in 2010. With our partners, we made the final investment decision to construct Platong Gas II natural gas project in Thailand. The $3.1 billion project will add 420 million cubic feet a day of processing capacity. Chevron is the operator and holds a 70% interest. Start-up is anticipated in 2011. We began front-end engineering and design work to develop an LNG project at our 100% owned Wheatstone discovery in Australia. We estimate that Wheatstone holds 4.5 trillion cubic feet of natural gas resource. In Nigeria, along with our partners, we made the final investment decision to develop the deepwater Usan Field. Chevron Nigeria Limited holds a 30% interest in this partner operated project. Usan is expected to have first production in late 2011 with peak production of 180,000 barrels of oil per day. Finally, as I mentioned, earlier in the week our board approved a 12% increase in the quarterly dividend. We’ve raised our quarterly dividend by a double-digit amount in each of the last four years and our shareholders have benefited from 21 consecutive years of higher annual dividend payouts. That concludes our prepared remarks. We will now take your questions, one question and one follow-up per caller, please. Matt, please open the lines for questions. Thanks.

(Operator Instructions) Your first question is from Paul Sankey of Deutsche Bank.

A couple of things; firstly a high level question, if I could, and then secondly a more detailed one. In terms of the cash management, Steve, if you could just talk about firstly your expectations for CapEx this year, given what we’ve seen so far in Q1. I guess you are still on target for your original guidance. And secondly, the sensitivity to buy-backs -- should we just keep with a ratable $2 billion? Thanks. Steve J. Crowe: Thanks, Paul. At this point, we confirm that our capital expenditures for 2008 are still at the budgeted amount, which is just shy of $23 billion. As far as our cash management, I think under the current conditions you can expect a buy-back pace comparable to what you’ve seen in the first quarter. We’ve had a $2 billion per quarter buy-back pace in the third and fourth quarters of last year and now again in the first quarter of 2008. So I think that’s a reasonable expectation at this point in time. We certainly have worked into our cash management the higher dividend that was announced a couple of days ago.

Great, and if I could on the detail question, it didn’t come up on the slide but in Indonesia, you are down quite hard in oil and up in gas. Is there something going on on the oil side that we should know about? And if you could make any other observations about the dynamics of Indonesian growth, that would be great. And a cheeky follow-up -- is Bangladesh, is that peeking now in terms of its volumes or is there more growth to come? Thanks. Steve J. Crowe: With respect to Indonesia, one of the things that we had noted in the interim update is in the first quarter gas, as it affects OEG production, was benefited by a unitization and the retroactive benefit of that unitization. As far as liquids production in Indonesia, I am not aware of anything that is systemic, Paul, that would result in the change in terms of our longer term profile. As regards Bangladesh, that operation has been running very well and there’s been increased demand on the Bangladesh operation so I don’t see any change in the intermediate term here. Thanks very much for your questions. May we have the next question, please?

Our next question is from Paul Cheng with Lehman Brothers.

Steve, in the past, you were talking about the underlying decline curve I think in your assumption that you are using 4.5% for the whole corporation. In the first quarter, is the number showing any substantial difference from that? Steve J. Crowe: Paul, I don’t have a number for the first quarter for that short a period as to what the decline rate is for our base operations, but as George Kirkland mentioned at the analyst meeting in March, we did have a lot of success in 2007 with a decline rate much below the guidance that we are still confirming in that 4.5% to 5% range. As George mentioned, one point doesn’t make a trend and while we were very pleased and optimistic as to the success in 2007, at this stage we’d still advise the analyst community to use the guidance of 4.5% to 5%. Paul, did you have a follow-up question?

Yeah, somewhat unrelated, I think Jim talked about the underlifting in the quarter. How much has the underlifting in the quarter actually cost you in terms of earnings? And at the end of the first quarter, are we from an inventory standpoint already balanced or are we still underlifted?

We were underlifted by about 5% in the first quarter, so that’s about 50,000 barrels, a little over 50,000 barrels a day.

Jim, do you have how much it cost you?

The impact of a 50,000 barrel a day reduction is shown in our international upstream volumes because it is lifting, not production, that affects earnings.

Okay, so it is $195 million.

If you look at our international upstream income, that $195 million or roughly $200 million impact is largely because liftings in the first quarter were lower than in the fourth quarter. In the fourth quarter, we were about balanced. We were about 1% underlifted.

Okay, so we are, as of the end of the first quarter, we are underlifted so in theory, we should see an overlifting in the second quarter?

Not necessarily in the second quarter but over time. These things are related to the timing of cargos but we don’t always see them come back each quarter, but over time that is a good item. I would like to emphasize that the volume, the $195 million on slide 6 for international upstream income reflects not just the liquids underlift but also affects the favorable impact of the gas unitization agreement that we mentioned. Steve J. Crowe: Paul, the only other thing that I would mention to you, when you look at the quantification of the OEG barrel underlift, is that not all barrels carry with them the same degree of profitability. So there can be circumstances where you have comparable underlifts in two periods but the P&L effect would be very different because it depends on where those underlifts occur.

Certainly. Very good. Thank you. Steve J. Crowe: Thanks, Paul. May we have the next question?

Our next question is from Doug Leggate of Citigroup.

Thank you. Thanks for taking my question. First question is a follow-up to Paul -- the 50,000 barrels per day that Jim mentioned as the underlift from the international upstream, can you quantify the gas unitization benefit? What was the volumetric effect of that, is my first one. Steve J. Crowe: As I recall, the effect of the unitization was about 25,000 barrels a day in terms of OEG production. Again, that will get ratably smaller as you take it out through all four quarters of this year.

Okay, great, thanks. The second one is actually a downstream question -- Jim mentioned the $100 million impact on earnings as a result of the coker being back up and now you are running heavy oil. Can you give us some idea -- that’s an earnings impact; give us some idea of what the margin benefit was, or perhaps to put it another way -- what kind of volumes and what kind of [grade] of crude are you now running there and how has that changed relative to let’s say before the project was completed?

Doug, the volumes in crude we are running are not substantially different. What is different is that we are no longer running lighter sweeter crudes. We are running less expensive heavier crudes. I don’t have the exact split-out of what our crude slate was, and we wouldn’t disclose that, for the first quarter relative to the fourth quarter but you can see the financial impact in the bar there. Steve J. Crowe: And Doug, I would point out that the magnitude of that impact again is influenced by the fact that while the coker was down in the fourth quarter, we were by necessity buying lighter, sweeter, and more expensive crudes and feedstocks.

So not all of the $100 million was margin benefit -- some was lower cost?

It’s primarily lower cost.

Sorry, I mean operating costs as opposed to costs accrued, because you were not buying the other products in the fourth quarter.

Well, it’s primarily the cost of feedstock, which is more expensive crude. There were some intermediates purchased but it was primarily in the fourth quarter we purchased lighter, sweeter crudes.

Okay, that’s great. Thanks very much. Steve J. Crowe: Thanks, Doug. Did you have another follow-up? Okay, may we have the next question, please?

Our next question is from Mark Flannery of Credit Suisse.

I’ve got two questions; the first one is can you give us an idea of what’s going on same-store sales just on the west coast in terms of volumes? I know you mentioned a couple of numbers there during the call, about 2% drop in gasoline and distillate doing well. But could you just run through them again and include a number for diesel? And then I have a follow-up. Steve J. Crowe: Mark, I don’t have a Chevron same-store sales comparing first quarter ’08 say to first quarter of ’07 in front of me, but I can tell you that if you look at motor gasoline demand industry wide in the United States using DOE implied demand data, through April demand is down about seven-tenths of a percent. But the interesting component from a portfolio perspective is in pad five, we’re down nearly 7% whereas in pads one through four, we’re up about a half a percent during that four month period. So we are seeing a greater demand impact here out on the west coast where Chevron's portfolio is proportionately larger than some of our competitors. Now on the distillate side, and covering all the distillates, U.S. demand for the first four months is down a little less than 3% compared to the comparable period a year ago.

Just specifically on your own operations, are you exporting distillate right now, either from the west coast or the Gulf? Steve J. Crowe: Not that I’m aware of at this juncture.

Okay. Maybe I could just jam this one in as the follow-up -- Steve J. Crowe: And in fact, we’ll try to get back to you with the specifics on that if we have any different information.

Okay, I’ll call Jim later but I guess the follow-up, which is not really a follow-up, is do you have any update on Gorgon maybe to give us right now? Steve J. Crowe: Nothing different than what George and Dave would have described to you at the March analyst meeting. We are pressing ahead with revised compliance for the environmental permit to reflect three rather than two trains on barrel island, but we are committed to the project. We are looking for ways to make it economic and take out costs, but the three partners are aligned with respect to the strategy, so it’s essentially a confirmation of the information that was provided back in mid-March. Thanks very much. May we have the next question, please?

Our next question is from Mark Gillman of Benchmark. Your question, please.

Good morning. Guys, I’m having trouble understanding the overseas downstream earnings. It almost looks to me, and perhaps you guys can clarify it, as if there was some kind of step-down that occurred about mid-year in ’07, impacted both the fourth quarter and first quarter. If you were to try to reconcile first quarter against year-ago first quarter, just looking at the margin comparisons you wouldn’t get anywhere near close. And I guess I am further puzzled by the comment Jim made regarding the shipping component of such earnings, which up significantly in the first quarter versus the fourth, where it would appear to me tanker rates were down sharply 4Q versus 1. Any help? And I’ve got a follow-up.

Well, let’s take the first part of your question with regard to margins. The margins that we are quoting are very specific to Chevron's marketing areas internationally, so Mark, as you are familiar with, we are marketing in certain areas and we use the indicator margins to try to match where we are located. And margins have been a little weaker but have been mixed overall. You’ll recall that last year in this quarter, we had the benefit of the sale of our interest in a refinery in The Netherlands --

I took that out, Jim. That’s not a factor.

-- and later in the year, we had the benefit of the sale of our refining and marketing assets in the Benelux countries. But if you remove those, yes, margins have been a little bit weaker and volumes have been a little weaker in the second half of the year than they were in the first half. But as to your comment about shipping, we’re just looking at the freight rates that are charged for the particular routes and the particular vessels that we use. And of course, shipping charges are an expense to the rest of the downstream. We broke it out here partly because we wanted to show from a transparency standpoint what the components were.

Okay, let me try my follow-up, if I could please; the comment in the U.S. upstream regarding DD&A, I did some rough math, probably not very good at this point in the week but nonetheless, I’m coming up with about 2 to 2.50 an equivalent barrel increase in the DD&A rate in order to justify that variance. Given the absence of any negative year-end ’07 U.S. reserve data, I don’t quite understand what it is with virtually no change in producing projects, if you will, could generate a DD&A increase of that magnitude and I’m interested in whether it is sustainable going forward. Steve J. Crowe: Mark, that’s a good question. One of the things that we did in the latter part of 2007 was a full review of the abandonment provision for all of our operations, the so-called ARO liability. And we accrued at year-end 2007 an additional abandonment provision that through the workings of the ARO get accreted as part of the DD&A charge as production occurs through those fields that are so affected. So there would be some discontinuity as you look at fourth quarter on into the first quarter of this year as a result of that, and I suspect, Mark, that’s the missing piece that you can’t find.

Is that sustainable, Steve? Steve J. Crowe: Well, it’s sustainable to the extent that we’ve increased the abandonment provision for those fields and that higher charge will be taken through DD&A over the life of the fields, and that abandonment provision will be higher then in 2008 than it would have been in earlier periods.

Okay. Thanks very much. Steve J. Crowe: You’re welcome, Mark. May we have the next question, please?

Our next question is from Erik Mielke of Merrill Lynch.

Good morning, gentlemen. I have a couple of questions on the upstream production. Firstly on Asian gas, which was stronger for Bangladesh, Indonesia, and Thailand than what we’d model. I know you already touched on this but I just want to make sure we understand what we should expect for the remainder of 2008, whether the first quarter production level is a good guide for those three specific countries on natural gas. Steve J. Crowe: I don’t have any information to suggest they aren’t other than the item that I alluded to with respect to the unitization of our gas field in Indonesia. That obviously would have a -- because of the retroactivity would have a greater affect in the first quarter than the other three quarters of the year. Jim, do you have anything else to add to that?

No, I don’t. Steve J. Crowe: Erik, do you have a follow-up?

I do. I have two follow-ups, if I’m able. Let me try one first -- first in Kazakhstan, you mentioned that Tengiz will be the next step change for Tengiz is in the third quarter. Should we expect a further increase in the second quarter? Is there an element of ramp-up taking place there? And is there any maintenance at Karachaganak that we need to be aware of?

Well, let’s take Kazakhstan -- we’re seeing about a 90,000 barrel a day improvement in production as a result of the first phase, the sour gas injection. That was ramping up in the first quarter and is now fully ramped up, you see 34, which is half of a 70 mbd increase reflecting our 50% share. That increase ought to be a little higher in the second quarter but you won’t see a substantial change until we get into the third quarter and we have full production facilities. Erik, you asked about another location? Steve J. Crowe: Karachaganak.

Oh, Karachaganak.

Whether there is maintenance in Karachaganak.

I don’t have anything on that of substance that I am looking at here. If there was, it was not something that was terribly dramatic. Steve J. Crowe: Erik, did you have one more question?

If I can try a cheeky one, just on Nigeria with the outages that other operators have had there, have you had any impact on your second quarter volumes that we need to be aware of? Steve J. Crowe: No, in talking to our operational folks in Nigeria, the impacts that some of the others have faced in the first quarter and here in the early second quarter, we haven’t experienced to the same degree. We’ve had very, very nominal shut-ins for very short durations in our operations. I would also point out, Erik, too as Jim and I have mentioned, we’ve got a Agbami coming on here in the third quarter and Agbami, unlike some of the other operations that are on-shore, is a deepwater project and it is 70 miles offshore, so it is quite a ways away from where some of the unrest has occurred. So we expect that the Agbami project will come on as advertised in the third quarter. Thanks very much, Erik, for your questions.

That’s great. Thank you.

Our next question is from Neil McMahon of Sanford Bernstein.

Just a quick question on the exploration wells that are sort of the high profile ones that are getting drilled -- any update on the Jack and Saint Malo appraisal wells? And also, could you give us some sort of guidance as to when the drilling of the Orphan Basin well is going to take place? Steve J. Crowe: With respect to the Orphan Basin, I recall that the next well would be drilled in 2009 and as far as the follow-up wells for Jack and Saint Malo, they are -- one is underway now, as I recall, and another a little bit later in the year. And then decisions will be made following those evaluations as to whether or not Jack and Saint Malo will be kept as separate projects or conceivably combined.

Okay, maybe as a loose follow-up in the upstream, just in terms of the whole Caspian Basin and the CPC pipeline, how much are you guys involved in looking at a bosphoros bypass pipeline in Turkey as a way of making sure that the increase Tengiz volumes, especially as we go forward over time, can find a decent route to market?

Neil, all I can say is that we are looking at all of our options because obviously optionality is very important to us in terms of expansion of our existing pipeline. But right now we have rail capacity to handle all of the exports in addition to the pipeline capacity that would result from an expansion of the Tengiz project. But in terms of what specifics we are looking at over and above rail, we’d rather not discuss that. Steve J. Crowe: I would say that the discussions with the partners to expand the capacity of CPC is as it has been is ongoing and there are various conditions that each party has tabled that we are looking at but we will still continue with the negotiations for the expansion of CPC. As Jim said, we otherwise have mechanisms to move Tengiz crude and just as we had done before the CPC pipeline was completed, we are using rail and other means to move the crude. Thanks very much for your question.

Our next question is from Jerry Gunn of BlackRock. Steve J. Crowe: Hello, Jerry?

Jerry, did you have a question? You may want to check your mute button. Steve J. Crowe: Okay, let’s try the next question, please.

Our next question is a follow-up from Mark Gillman of Benchmark.

Steve and Jim, are there any rate of return or cumulative production thresholds on block 14 that would be encountered -- block 14 in Angola -- that would be encountered this year at current price levels? Steve J. Crowe: Not that I’m aware of. Hang on one sec here, I’ll see if I can see anything. In terms of price levels, looking at objective -- no, there is nothing substantive that is associated with the African operations.

Okay, if I could just sneak a follow-up; Steve, I wasn’t clear what you meant by that roughly 25,000 a day characterization of the impact of the Indonesian unitization on the gas side. I thought that there was a one-time retroactive element which is benefiting the first quarter and then a considerably smaller positive impact going forward. What was the 25 equivalents a day supposed to represent? Steve J. Crowe: That was the retroactivity piece that I was alluding to that would be non-recurring obviously in other quarters. So your understanding is correct, Mark.

Okay, fine. Thank you.

Matt, do we have other callers?

At this time, I am showing no further questions. Steve J. Crowe: Thank you. I am presuming that we’ve been able to cover your questions in the time allotted and I think in large measure because our interim update provided a lot of information that’s proved to be consistent with the earnings release that you saw today. So in closing, I want to express my appreciation to everyone’s participation on the call and I especially want to thank each of the analysts on behalf of the participants for their questions during this morning’s session. Matt, I’ll turn it back to you.

Ladies and gentlemen, this concludes today’s 2008 earnings conference call. You may now disconnect. Good day.