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Chevron Corporation (NYSE:CVX)

Q3 2007 Earnings Call

November 2, 2007 11:00 am ET

Executives

Stephen J. Crowe - CFO

George Kirkland – EVP, Upstream and Gas

Mike Worth – EVP, Global Downstream

Jim Aleveras - General Manager, Investor Relations

Analysts

Dan Barcelo - Banc Of America Securities

Doug Leggate – Citigroup

Paul Sankey - Deutsche Bank

Mark Flannery - Credit Suisse

Mark Gilman – Benchmark

Neil McMahon - Sanford Bernstein

Paul Cheng - Lehman Brothers

John Herrlin - Merrill Lynch

Michael LaMotte - JP Morgan

Presentation

Operator

Welcome to Chevron’s third quarter 2007 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.

Stephen J. Crowe

Thank you, Matt. Welcome to Chevron’s third quarter earnings conference call. Today on the call I’m joined by George Kirkland, EVP, Upstream and Gas; Mike Worth, EVP, Global Downstream, and Jim Aleveras, General Manager, Investor Relations. Our focus today is on Chevron’s financial and operating results for the third quarter of 2007. We’ll refer to the slides that are available on the web.

I remind you that today’s presentation contains estimates, projections and other forward-looking statements and ask that you review the Safe Harbor statement on slide 2.

Turning to slide 3, the company reported earnings of $3.7 billion in the third quarter compared with $5 billion in the third quarter 2006. Earnings of $1.75 per diluted share were down from $2.29 per share reported for the same quarter last year.

Both periods reflected about $400 million or approximately $0.19 per share of net charges associated with non-recurring items. The main driver for the earnings change was a decline of over $1 billion in downstream profits. Escalating costs for crude oil feedstocks could not be fully recovered in the market. This impact was global, but it was especially significant on the US west coast. Overall, third quarter results were $1.7 billion lower than our record second quarter 2007, which Jim will discuss shortly.

Return on capital employed for the trailing four quarters was 22%. During the quarter, we retired about $2 billion of debt, reducing the debt ratio to about 7.5% at quarter end.

Third quarter share repurchases totaled $2 billion, reflecting an accelerated buyback pace. As we projected in last quarter’s conference call, we completed the December 2006 buyback program during the third quarter. In September, we announced and initiated a new repurchase program of up to $15 billion over a period of up to three years.

Jim will now take us through the quarterly comparisons.

Jim Aleveras

Thanks, Steve. My remarks compare third quarter results to those of the second quarter 2007. As a reminder, our earnings press release compared third quarter 2007 with the same quarter a year ago.

Turning to slide 4, third quarter net income was $1.7 billion lower than the record level of the second quarter. Lower downstream margins were the most significant component of the change. Upstream realizations increased, but the benefit was partly offset by lower international liftings due to the timing of cargoes.

Additionally, the second quarter included the $680 million gain on the sale of Chevron’s investment in Dynegy, while the third quarter reflects a smaller, $265 million gain on the sale of the company’s Benelux Fuels marketing assets.

Separate from these major asset sales, there was a further $300 million adverse effect between the sequential quarters due to net non-recurring charges. The most significant factor was the difference in tax items, contributing to a $230 million variance between quarters. Addition non-recurring items, along with other factors in the aggregate, were responsible for a negative variance of about $130 million as shown on this slide.

Except for large discrete items, it has not been our practice to identify smaller non-recurring charges and credits. We did so this quarter because of the large swing in these smaller items between the second and third quarters.

Just to recap, the third quarter included $415 million less in gains on major asset sales and $300 million more in smaller, non-recurring net charges than did the second quarter. This amounts to an adverse swing of more than $700 million between sequential quarters of more than $0.33 per share.

Turning to slide 5. Slide 5 summarizes the results of our US upstream earnings which fell by about $90 million between quarters. Higher realizations benefited earnings by about $135 million between quarters. Higher liquids prices contributed $250 million to earnings, but lower natural gas realization had a $115 million offsetting impact.

Chevron’s domestic crude oil realizations were up about $9.80 per barrel between quarters, around $0.50 per barrel less than the increase in average WTI spot prices. This partly reflects Gulf of Mexico production that is priced on a lagged basis. This is a benefit when prices are falling, but a headwind when prices are rising.

Our natural gas realization fell by a little over $1.10 per thousand cubic feet, which is in line with the average changes in bid week pricing at Henry Hub in California and in the Rockies.

Our volumes were slightly lower due to storm-related shutdowns in the Gulf, maintenance work and natural field declines. These were partly offset by one more producing day in the third quarter.

Asset retirement obligations were higher by $60 million mainly due to an adjustment to the abandonment provision for offshore California properties that were previously sold. The other bar on this slide reflects higher exploration expense, asset impairment and the absence of gains on some small operations we sold in the second quarter.

Turning to slide 6, this slide compares upstream international earnings, which fell about $120 million between the second and third quarters. Stronger liquids realizations benefited earnings by almost all of the $285 million impact shown on this slide. Natural gas effects, while positive, were essentially negligible. Liquids realizations improved by about $5.80 per barrel, in line with the rise in spot BRENT prices.

Lower liftings spread across multiple countries reflected the timing of cargos and reduced earnings by $240 million. We were in a net under-lifted position in the third quarter, which brings the year 2007 to a balance liftings position.

Tax adjustments reduced earnings by about $80 million between periods. The variance in the other bar includes asset impairment charges.

Turning to slide 7, slide 7 summarizes the change in worldwide oil equivalent production including volumes produced from oil sands in Canada. Daily volumes were down by 39,000 barrels between quarters. Maintenance-related shutdowns in the UK North Sea were the largest factor in this change. George Kirkland will discuss production volumes in more detail in a moment.

Turning to slide 8, our US downstream results in the third quarter fell nearly $900 million from the prior quarter. Margins were down $680 million. Both refining and marketing margins fell, but the decline was particularly large for west coast refining margins. Breaking out the $680 million, over 90% of that amount was refining margins, and over two-thirds of that amount, in turn, was related to the west coast. Crude prices rose more rapidly than product prices during a period when product inventories were ample.

West coast margins also include an unfavorable variance in final pricing adjustments for long haul crude. Lower refining volumes reduced third quarter earnings by $90 million, primarily due to a fire at our Pascagoula, Mississippi refinery in mid-August as well as other planned maintenance there. The unfavorable variance in the other bar on this chart includes employee termination benefits and provisions for litigation. Both the second quarter and third quarter included environmental remediation charges in this segment.

Turning to slide 9, international downstream earnings of $487 million were $30 million lower than the second quarter. Released downstream margins dropped by about $275 million, in line with the change in indicator margins. Asian refining margin indicators fell by one-third and indicator margins were sharply lower in Europe as well. As was the case in the US; the price of crude rose more rapidly than the price of refined products during the quarter. These lower margins fully offset the gain on the sale of our fuels marketing business in the Benelux countries. The other bar on this slide includes asset impairment charges, lower shipping earnings and employee termination benefits.

Looking at slide 10, this slide shows the chemical operations earnings in the quarter were $103 million, essentially unchanged from the prior quarter. The results for oil sands improved due to higher ethylene margins and reduced utility costs. Aromatics benefited from improved styrene earnings reflecting higher margins and increased volumes. Aromatics also benefited from the absence of an asset writedown we mentioned in the second quarter. The other bar includes an environment reserve provision in the third quarter.

Slide 11 covers all other. Second quarter results included the $680 million gain on the sale of our interest in Dynegy, which was partly offset by $160 million of charges related to the early redemption of Texaco capital bonds. Similar to the second quarter this segment includes about $70 million of environmental remediation expenses for legacy Texaco and Unocal sites that have been closed or sold. Third quarter net charges for this segment fell at the high end of our standard guidance range of $160 million to $200 million as we advised in our interim update.

That completes a brief analysis of the quarter. Back over to you Steve.

Stephen J. Crowe

Thanks, Jim. We wanted to use a portion of today’s teleconference to give George Kirkland and Mike Worth and opportunity to update you on our upstream and downstream business developments respectively. We’ll start with George. He’ll turn things over to Mike and then we’ll open it up for your questions.

George Kirkland

Thank you, Steve. I’ll start on slide 13. Before I provide you with an update of our major capital projects, I would like to review our 2007 production results. This slide compares our net OEG production through the first nine months of 2007 versus the first nine months of last year. Although we are down 50,000 barrels a day this year, we can point out 90,000 barrels of losses in 2007 that are attributable to our contractual change in OPEC curtailments in Venezuela.

Our production efforts this year have been focused on managing our base business declines and capturing gains from major capital projects that have recently come online. The low base business decline is a positive indicator of our base business efforts.

However, there are many moving parts in the base business -- workovers, development wells, reliability and so on -- and it’s too early to say that our typical 4% to 5% base decline rate has changed.

Now I’ll update you on some of our key projects. Please turn to slide 14. Let’s start in the Gulf of Mexico deepwater with our Tahiti project, where we have a 58% net working interest. As a reminder, Tahiti is designed to have a production capacity of 125,000 barrels of oil per day and 70 million cubic feet of gas per day.

We have continued to progress this project by completing installation of export pipelines, completing five of the six development wells, and installing a significant portion of the sub sea production system and flow lines. The spar hole is complete and the top sides are near completion. The hole and top sides will be ready for offshore installation once replacement mooring shackles and components are delivered and the rescheduling of the installation is finalized.

A metallurgical problem with the original shackles was identified in June and installation activities were deferred in order to insure that the facilities would be put in a safe and reliable operation.

Installation of the truss spar is now scheduled to begin in the first quarter of 2008. The top side installation, the mating with the spar, is targeted for the third quarter of 2008. First production is now expected by the third quarter of 2009, approximately 12 months later than originally planned due to the shackle replacement and the installation rescheduling.

Now let’s turn to slide 15. We also continue to progress our Blind Faith project, located in the deepwater Gulf of Mexico. In July we purchased an additional 12.5% working interest in this project, bringing our total interest up to a 75% share. The top sides have been lifted onto the hole and all three development wells have been drilled. Positive results from the development drilling supports the future drilling of a fourth well by 2009.

Off shore installation and well completions are scheduled to commence in November of this year, with first production expected by the second quarter of 2008. Blind Faith has a production capacity of 45,000 barrels of oil per day and 45 million cubic feet of gas per day.

Now onto slide 16 where I will update the status of the Agbami Deepwater Nigeria project. It’s floating production, storage and off-loading vessel has left the fabrication yard in South Korea and is being towed to the offshore Nigeria location. This FPSO is the largest of its type in the world and will be moored and ready for hook-up in the first quarter of 2008. It has a processing capacity of 250,000 barrels of oil per day and a storage capacity of 2.1 million barrels of oil. We have already drilled 11 producers and seven injectors. We have two rigs working on the completions of these wells. We are on-track for first oil by the third quarter of 2008. We expect to be at full capacity within one year of start up. As a reminder, Chevron has a 68% interest in this project.

Now turning to slide 17, I’ll cover the Tengiz SGI/SGP project. We anticipate that sour gas injection and the first production will begin in the fourth quarter of 2007. As a reminder, Chevron has a 50% working interest in TCO and the expansion start up, which we call Staged Oil, will enable us to increase production by about 90,000 barrels a day gross. The second generation plant which is pictured here should be fully operational by the second half of 2008. This will add another 160,000 barrels of production per day.

The labor disruption of 2006 extended the construction period but we have made great strides in keeping this project moving forward. The combined SGI/SGP project has been one of the most complex and challenging, multi-billion dollar projects that Chevron has ever led, and we are glad to see this project nearing its completion and start-up.

In the interim period between project start-up and the Caspian pipeline expansion, alternative rail export routes ensure we can export the full plant output.

Now let’s turn to slide 18. Production growth in the near term is all about the start-up and ramp-up of these highlighted major capital projects. Before I finish this morning, I wanted to cover other key milestones that occurred during the third quarter.

The first two bullets further illustrate that our large queue of opportunities are moving forward. Gorgon has passed a couple of very important milestones recently. We received environmental approval from the Western Australian Minister for the Environment in September, and Federal Minister for the Environment in October. Our engineering efforts are focusing on the permit conditions, modularization opportunities and execution planning.

In Indonesia we started up the Darajat III geothermal project in July. This facility adds 110 megawatts to the West Java power grid. The Darajat facility now has a total capacity of 260 megawatts.

The next two items are examples of how we replenish our development queue. In August we announced the Malange oil discovery in block 14 deepwater offshore Angola. This well encountered more than 200 net feet of oil sands. The well was tested at a rate of over 7,500 barrels of oil per day of high quality crude. Future drilling is planned to assess potential reserves and assist in the development design.

In July, we reported the successful prevention test of the Rosebank appraisal well, located some 100 miles Northwest of the Shetland Islands. This well, in approximately 3,700 feet of water, flow-tested 37 degree API light oil at restricted rates of 6,000 barrels of oil per day. The appraisal and evaluation program should be completed by November of this year and will allow us to determine the future work program and development of this discovery.

We also recently announced our extension of the production period for Thailand blocks 10 through 13. By securing this production extension we will now be able to move major investments forward on the Platong II project. Platong II is the planned expansion of the existing Platong assets, which are currently producing 250 million cubic feet a day and 40,000 barrels a day of hydrocarbide liquids. Platong II will add gas processing capacity and enable our oil and gas projects to be accelerating.

Now I’ll turn it over to Mike.

Mike Worth

Thanks, George. Moving to slide 19, I would now like to update you on key downstream initiatives beginning with operational excellence. Improved reliability continues to be our top priority. We have resolved many high-risk conditions which have caused unplanned downtime. Despite these improvements, we experienced significant crude unit fires this year at Richmond and Pascagoula. These incidents remind us that we still have work to do, and have further strengthened our resolve to improve reliability to enhance capabilities, processes and equipment.

While the fire at Pascagoula was unfortunate, our incident response was swift and effective, limiting the impact and preventing any injuries. We expect to complete repairs during the first quarter 2008. The demolition phase is proceeding safely. Critical equipment orders have been placed, and delivery is scheduled. We’re taking steps to optimize conversion unit utilization while the crude unit is offline.

As the left chart shows, lost utilization from unplanned downtime this year has been slightly greater than in 2006, due to the two fires. However, we continue to drive down the number of unplanned outages, as shown on the right. Incidents per quarter at our largest operated refineries have fallen more than 50% since 2005.

Since the first quarter turnaround, crude unit utilization at Richmond has been consistently strong, averaging 101%. Our UK refinery has also operated very well the entire year, also averaging 100% crude utilization. Conversion unit utilization at these facilities has also been very strong.

Turning to capital projects on slide 20, we are progressing well in terms of achieving the major milestones we committed to earlier this year. During the quarter, our South Korean joint venture refinery completed construction of its [reside] upgrade project ahead of schedule and on budget. We expect the upgrade to lower crude costs by about $1 per barrel, increase light product yield by 33,000 barrels per day, and add 15,000 barrels per day of new lubricant base oil production. A new vacuum column, among the largest in the world, and a new hydrocracker, lubricants base oil plant, and other conversion units have begun commercial operations.

On the west coast, we are currently modifying our El Segundo coker during a planned turnaround, to enable a shift to heavier and higher sulfur crudes and to improve coker reliability. We expect to meet our product supply commitments during the turnaround and to have the heavy crude enhancements online by year end.

We completed the Caspian blend integration product at our UK refinery ahead of schedule and on budget. We now have the ability to feed Caspian blend crude at rates up to 40% of total feed. This will provide an economic outlet for growing equity production.

Finally, we announced sanctioning of the Continuous Catalytic Reforming project at Pascagoula. The new CCR will improve utilization and optimize product yields. Gasoline production at the refinery is expected to increases about 10% with completion anticipated by mid-2010. In summary, we are ahead of schedule, or on track to complete the significant capital projects we committed to bringing online this year.

Moving to slide 21, we are also making significant progress in high grading our portfolio. As you can see from the map, we have made a number of divestments in the past two years on top of ongoing efforts to reduce the capital intensity of our branded retail network.

As you recall, back in March we announced our intent to pursue divestments in Europe and Latin America. We have followed through and succeeded in monetizing assets in businesses we no longer considered strategic. In March, we sold our 31% interest in the Nerefco Refinery in the Netherlands and other assets there, generating $1.1 billion in after-tax proceeds. During the third quarter, we closed the sale of our fuels marketing business in Belgium, the Netherlands and Luxembourg for about $500 million in proceeds excluding a final adjustment expected by year end.

We also reached agreements to sell our proprietary, consumer and commercial credit card businesses. We believe these arrangements will enhance the payment products we offer our customers, while enabling us to maintain the strong brand loyalty associated with our cards.

More portfolio improvement opportunities are being evaluated and we’ll share progress on these in the future. We are working to create a more focused footprint for our marketing businesses. Fewer markets, but stronger positions in those markets will help us reduce costs and further improve returns on divested capital.

Now I will turn it back over to Steve.

Stephen J. Crowe

Thanks, Mike. That concludes our prepared remarks. We’ll now take your questions, one question per caller, please. Matt, please open the lines for questions.

Question-and-Answer Session

Operator

Our first question comes from Dan Barcelo - Banc Of America Securities.

Dan Barcelo - Banc Of America Securities

Good morning, gentlemen. Thank you for the update, particularly on the projects, it was quite useful. I wonder if you could spend a little bit on Gorgon. Having received a lot of the environmental approvals, could you talk a little bit about maybe the costs you are looking at now? I know it may be premature as you’re still trying to cost and phase that, but any thoughts about how you’d phase the development, and particularly on the costs for Gorgon? Thank you.

George Kirkland

Dan, let me start off. I think you’ve highlighted a lot of the points that we’ve still got to address. In my comments I mentioned that we need to go back and look at the permit conditions. We have a significant number of permit conditions that we’ve got to have mitigations fully vetted and understood how we would handle where we don’t get into a cost issue during the construction stage.

So we are presently back looking at all those conditions, and I would add one other area that we’re really spending a lot of time on is the modularization. Remember we’re building this on Barrow Island. We’ve got the ability to do a lot of modules and bring them in to minimize the actual work on the island. That in many ways helps us, because the situation at the island, the constraints we have about moving equipment in there. We need to have a really good plan, and modularization will really help us there.

Those are the items that we’re really focusing on at this point in time. I expect I’ll be able to talk quite a bit more about schedule and where we are at our March analyst meeting, and at that point in time I will try to really give a lot more details around the plan forward on Gorgon.

Operator

Your next question comes from Doug Leggate - Citigroup.

Doug Leggate - Citigroup

Steve, the one-off items this quarter, I guess I’m thinking specifically about refining marketing. You’ve given us some breakdown on the larger items, environmental mediation and so on, but it seems that there were quite a number of fairly significant items, particularly on the US downstream. Could you go into a little bit more detail if you can on just to quantify that?

Stephen J. Crowe

Sure, I’ll ask Jim to handle that. We anticipated that might be a question, since we kind of foreshadowed on our October 9th interim update that there would be a fair number of non-recurring items that affected the results this quarter. So Jim?

Jim Aleveras

Doug, your question was with respect to the US downstream?

Doug Leggate - Citigroup

Well clearly across the businesses would be useful, but that was the one specifically where we saw a bit of a gap.

Jim Aleveras

Well in the US downstream again, the effects were primarily margin-related. If we look at the non-recurring charges between the second and third quarter, there was not a significant difference in that particular segment, in the US downstream segment.

Doug Leggate - Citigroup

Then the absolute number this quarter is what I’m trying to get, the absolute impact.

Jim Aleveras

The absolute number in the third quarter was about $50 million negative.

Doug Leggate - Citigroup

Okay. Do you have that for the other divisions?

Jim Aleveras

In terms of our segments?

Doug Leggate - Citigroup

Yes.

Jim Aleveras

For the third quarter the US upstream, the non-recurring charges in aggregate were about $100 million negative. For the international downstream, the net non-recurring charges were about $250 million negative. As I mentioned, for US downstream it was about $50 million negative.

For the international downstream, because of the gain on the Benelux assets, the change or the impact was a favorable $165 million. I should point out that’s $100 million less than the gain on the Benelux assets. So there was the gain on the Benelux assets of plus $265 million and there were net non-recurring charges of negative $100 million.

In the chemical segment, the impact was negative $40 million; and in the all other segment, the impact was about $100 million for a total of $400 million that we quoted in our earnings press release.

Doug Leggate - Citigroup

The 121 employee termination and litigation, you’re not terming that a one-off item in the U.S.?

Stephen J. Crowe

Yes we are, Doug, and it’s not a large item but the severances that were recognized in third quarter results were both in the United States as well as international.

Thanks very much for your question. May we have the next question please?

Operator

The next question is from Paul Sankey - Deutsche Bank. Your question, please?

Paul Sankey - Deutsche Bank

I want to ask a question about India but if I could just make an observation further to Doug’s point -- I’ll not phrase it as a question -- you have in the earnings supplement a table of special items and other adjustments by quarter with nothing in it; but you’re identifying $400 million of specials.

Again, I don’t want to use up my question on that but I do find it slightly odd that there’s zero reported within that table and I was wondering why that is, but if we could just...

Jim Aleveras

We won’t count that as a question. So in the post Reg G world we live in, which goes back a few years now about making pro forma adjustments to GAAP earnings, these items were properly recognized in the third quarter. They’re event-driven as in the case of sales or the recognition of impairments or severances and the like.

We don’t view them, these happen for all large companies in varying degrees from period to period. We just felt there were enough of them that occurred in the quarter that we should highlight it for the analyst community in the interim update and in the press release.

It’s really, then, left up to the individual analyst to determine whether or not those should be taken out in order to get more of a clean earnings from your perspective. So, it’s only that, Paul.

Paul Sankey - Deutsche Bank

I just found it strange that. In terms of India, could you just update us please, in that you haven’t mentioned it here amongst your major initiatives, could you just talk a little bit about the status of the expansion that you’ve got going on there, firstly?

Secondly, the timing and potential for you to expand your position. Finally, a progress update on how you’re getting on with the upstream elements of that whole move that you made there. Thanks.

Stephen J. Crowe

Thank you, Paul. I think I’ll ask Mike to talk a little bit about the progress that we’re seeing on the downstream side.

Mike Worth

I think there were three parts. I’ll take the first two and I’ll hand the upstream one off to George. The refinery construction is progressing very well. Over 97% of the engineering work is done and the construction is well underway. I think the announced start date for that refinery is 2008, and I fully expect that start-up to occur next year.

Relative to our investment position, as you know we have a 5% stake and subject to a number of other agreements being negotiated, the opportunity to increase that to 29%. We have not concluded those other agreements and no decisions have been made as to the ultimate decision relative to our equity share in that refinery.

I’ll ask George to comment on the upstream.

Paul Sankey - Deutsche Bank

Could I just ask you the timing next year -- you mentioned ‘08 obviously for the refinery -- that’s presumably a first-half event. Secondly the timing, if you could just remind us on the increase on the stake when we’ll get an answer on that would also be interesting. Sorry to interrupt. Thanks.

Mike Worth

I think the announced start date for the refinery is actually second half ‘08. The timing for our final decision on our investment position is subsequent to the refinery start-up.

Paul Sankey - Deutsche Bank

Thanks.

George Kirkland

On the upstream issue, I would say we still have interest in the KG Basin. But, Paul, there’s really not been much progress in really developing that opportunity. So really it’s nothing really to report at this point in time.

Paul Sankey - Deutsche Bank

Are there any initiatives that there might be something, George, that you could talk about? Or we can have more of an idea? Thanks.

George Kirkland

Really nothing to talk about at this point in time. Paul, it’s just not ready and there’s a lot of other people besides us that are interested in that. So I really don’t have anything to report.

Operator

Our next question is from Mark Flannery - Credit Suisse.

Mark Flannery - Credit Suisse

Yes. My question is to George, and it concerns the decline rates. You said that it’s too early to say whether or not the base decline of 4% to 5% is to be changed. Could you just expand a little on that, and tell us what kind of things specifically you’re doing presumably to get that rate down obviously? When do you think it would be appropriate to talk about a new decline rate in the upstream?

George Kirkland

I’ll answer the last part of that question first. I want some run time to see exactly how we are influencing it. Specifically we’ve got I think great processes where we in effect do base business audits around the world and we audit from the reservoir through all the facilities. We look at reliability. We look at reservoir performance. We look at the interactions between the surface facilities and the subsurface facilities to make sure we don’t have any bottlenecks. We’ve been on that process, for now about three years.

It continues to turn up opportunities for us to optimize our production around the world. We are seeing some influence. This first nine months of this year we’ve had some great successes in South Texas with some development wells, which we used good seismic technology there, and had some good results there. We’ve got some other places where we’ve focused on our water floods and we’ve seen some decline rates shallow out.

We’ve got a lot of history of multiple years where this 4% to 5% decline rate is what we’ve been typically seeing. So I’m encouraged by the first nine months, but I want a lot more run time and I am confident that the processes that we’ve put in place are going to help us for the long period improve our recovery and reduce our decline rates in greatest sense, but I think it’s a little bit too early and that’s why I made those comments that way.

Mark Flannery - Credit Suisse

George, would you characterize this as mostly EOR type stuff, or I mean are you spending more money on enhanced oil recovery or is a sort of mix of things?

George Kirkland

It’s a mix of things. It is not one focus. We have four to five areas that we really focus on; and in some places, we get it out of just system reliability, raising the reliability, the run times. Some places it’s hey, we find a facility that we can push more barrels through and we see that we’ve got reservoir capability to match to it and not have to spend a lot of monies on facilities.

So we’re doing all those type things like, once again, from the reservoir through the sales point to try to optimize the system in all our business units around the world.

Operator

Your next question comes from Mark Gilman - Benchmark.

Mark Gilman - Benchmark

Relating to Pascagoula, could you give an idea as to the size of the crude unit that is down?

More generally, I guess I was a little surprised to see the sanctioning of the CCR project, and I’m assuming that in having done so the distillation expansion at Pascagoula which had been under evaluation is now no longer on the table. Could you comment on the validity of that observation?

Mike Worth

Yes, on the crude unit it’s about 160,000 barrels per day and on the CCR, that is an independent project. We’ve got old fixed-bed reformers that need to have the catalyst regenerated so we’ve got to pull reformers offline for catalyst regeneration, and it significantly impacts our ability to get the utilization at the facility up. So this is a reliability project that has a very strong economic pay out, and frankly, there are not many of these fixed-bed reformers still in operation in the industry. So it’s really upgrading the technology to the current state-of-the-art.

The evaluation of other alternatives for Pascagoula continues. I think I’ve indicated that we would reach a final decision on that next year. Certainly, you’re seeing project economics challenged in the refining sector on the Gulf Coast as well as the rest of the world by the cost environment, by the questions about the margin environment, uncertainty about biofuels penetration and future demand, etcetera. So we’re factoring all those into our evaluation of alternatives, and we’ll have more to say about that next year as that work is complete.

Mark Gilman - Benchmark

Mike, if I could just follow up on that. If you’re considering an expansion, I don’t know how you go about properly sizing what the replacement reforming capacity ought to be.

Mike Worth

Well on the reforming, it fits into a refinery that is configured with a number of other facilities that has streams that create feed for the reformer. What we’re doing is taking existing intermediate streams and we are installing facilities that essentially you can look at as a de-bottleneck or a capacity creep kind of a project that enables us to more fully utilize the streams available within the refinery and increase the utilization.

Operator

Your next question comes from Neil McMahon - Sanford Bernstein.

Neil McMahon - Sanford Bernstein

Maybe this is a quick one you don’t have many answers for, but most of the impact on the refining in the US, the negative impact as you said was on the west coast. Just wanted to go into maybe walking through some reasons for that, and did you have hedges in places there that could have caused some of those losses?

Mike Worth

As Jim showed earlier, when you compare the third quarter to the second quarter, our US earnings were down nearly $900 million. More than two-thirds of that decline was due to industry margins, and really the balance for the US was due to lower volumes, and that is primarily Pascagoula.

So I think the quarter-to-quarter comparison is pretty straightforward on those two pieces. We have some pricing effects on our crude oil into the refining system that we see most acutely at times of rapid change in crude prices, and our foreign crude that we purchase that is long-haul crude gets provisionally price while it’s on the water, and so we’ll see the effect of those increases before we actually capture the margin for running that crude.

So we do have some paper effects that you see in an environment like this that are exacerbated by the amount of long-haul crude that we run and the way that we price crude into our system.

Neil McMahon - Sanford Bernstein

So you don’t really do hedge accounting then on those long-haul crudes or in the west coast?

Mike Worth

We mark the pricing to current period pricing, and we run our refineries to capture the margin of the day, so we convert the pricing to run-month pricing, and so what that does result in is some open paper that is price conversion off the feed stock to the run month.

Jim Aleveras

Let me just add on that point, again, as Mike said, those are part of the contractual provisions. They’re not hedging, per se, so when a cargo is lifted it has a contractual term as to when it’ll be priced so many days after lifting. In a rising market, as we’ve seen here in the third quarter, that works adversely against us. Thank you very much for the question and the follow-up.

Operator

Your next question comes from Paul Cheng - Lehman Brothers.

Paul Cheng - Lehman Brothers

Mike, if I look at the third quarter market conditions, Gulf Coast 3 to 1 crack spread is roughly in the $11 to $12 per barrel and the California crack is probably about $13, $14. While they advanced sharply from the second quarter, but they are really not that bad from a historical standards standpoint. If you look at your earnings, I mean adjusting for the $50 million in environmental remediation charges and also the $90 million loss related to Pascagoula, you earned $30 million. Is there a structural problem with your asset there then that your hardware just needs to be revised sharply in order for them to be more sustainable in a more normal pricing environment?

Mike Worth

No, I don’t think there is a structural problem in the market or in the refinery. I think the indicator margins did decline more sharply on the west coast than on the Gulf coast and with a skew to our downstream where we have more than half of our US refining capacity on the west coast, that sharper decline will affect us to a greater degree.

Paul Cheng - Lehman Brothers

Mike, I’m talking about on an absolute level that the crack is still topping out in the $10 to $15, which is not really that bad.

Mike Worth

Let me take another shot at building on the question that Neil was asking. We have these non-ratable pricing effects related to the change in crude prices which are most significant because the amount of long-haul crude that we bring into the west coast. And so if you look at 3Q07 versus 3Q06 you would see that the margin declines are not especially severe and the absolute level of margins, as you say, are not as extreme as the earnings delta might indicate; but if you look at 3Q06, we saw crude prices drop by about $11 a barrel over the quarter. In 3Q07 we saw crude prices increase by $11 per barrel in the quarter, and so those non-ratable pricing effects have significant knock-on accounting effects that get unwound subsequently as we actually run the crude, but in the quarter they create pronounced effects on our west coast downstream performance.

Paul Cheng - Lehman Brothers

Mike can you quantify it for us?

Mike Worth

I don’t have the numbers in front of me to quantify that, Paul.

Jim Aleveras

You know, Paul, you’re talking on average maybe 15 million barrels of long-haul crude on the water, and as Mike said in the earlier period a year ago, we saw crude prices from beginning to end of the quarter drop by $11 a barrel, and just the reverse effect that occurred here in the third quarter. That is going to be a material impact on the comparison between adjacent years on a variance. it’s one of the reasons why sometimes the indicative margin doesn’t become realized for our company. Thanks for your question.

Operator

Your next question comes from John Herrlin - Merrill Lynch.

John Herrlin - Merrill Lynch

With Thailand you said that you extended the contract. Are the terms still similar, or are they higher for the country?

Stephen J. Crowe

Do we have similar terms? It’s still the Taiwan terms. We do have some issues with related to how we extended it, but overall the terms are basically the same.

John Herrlin - Merrill Lynch

You were pretty active at the last Central Gulf sale. Could you give us a sense on how many of the leases were Miocene versus, say Paleocene?

Stephen J. Crowe

I think my memory of the major targeted prospects, I believe it was nine or 11 in total that we really captured major new prospects. All of them but one was the lower tertiary.

Operator

Your next question comes from Mark Gilman - Benchmark.

Mark Gilman - Benchmark

George, if you could, on Block 14 in Angola, could you tell me whether or not there are separate PSCs for each of the fields, and the extent to which there are rate of return thresholds built into those production-sharing contracts, pursuant to which profit barrels and profit percentages would step down once the threshold was reached?

George Kirkland

Mark, I’m going to limit my comments a little bit, I will tell you that we have different development areas around each field. Our development areas have typically in block 14, been larger than what we had seen in the past and in some cases, they have been more or less brought together to allow cost recovery to be moved from one development to another. So we have had larger development areas than in the past. I’m not going to speak about the contractual pieces beyond that.

Operator

Your final question comes from Michael LaMotte - JP Morgan.

Michael LaMotte - JP Morgan

A question related to upstream cost pressures, as your spending is shifting more towards completion and production, are you seeing any changes in the rate of change of cost there? I would think that completion inflation is probably not as high as drilling in rigs, offshore rigs in particular.

George Kirkland

Let me take a shot at this one in a couple of ways. First off, remember we are operating in 25 to 30 countries around the world, we’ve got a whole portfolio of projects that are in anything from the early phase, engineering to just about to start up and actually a lot of them in start up.

The ones that are late in phase, we know contractual costs very, very well. Those projects are not seeing and have not seen the same movement in costs as projects in the early phases.

I would tell you whether a project is an onshore project in North America or if it is an offshore project or a deepwater project, all of those in effect, change the outcome of the cost increases.

I’ll give you a couple of examples of what we’ve seen and maybe that will help you get a little bit of context. We had a project in Angola, we brought online in deepwater project in Angola that we brought online a little over a year ago, we’re doing a very similar project that’s in the fabrication stage at this point, so we understand contractually what the cost is going to be for drilling, for building of all the facilities, the installation, so we have got the contracts really nailed down.

There’s a five to seven-year difference in the life cycle of the two projects and when you compare project A to project B, we see almost a 100% increase in the cost of doing the similar work. So that’s very typical in the deepwater where you’ve seen rig rates go up. Deepwater rig rates have gone up two to three times over a five-year period.

Other areas we are not seeing the same, and once again every project we look at individually because you’ve got a different mix of contracts that are either in place, and we have some period at a different rate than what we see in the future so we look at everything on a specific project-by-project basis.

I would tell you one of the best areas to look at, maybe to give you a view of what the cost in the general industry what’s happened there in the last probably five to seven years, is to look at the CERA, the Cambridge Energy Research report that was published, I believe in the last year. What it basically shows is over the period from early 2000 to late ‘06, about 180% to 190% increase in their index. So they’ve shown a significant move in that index, and I think it’s very indicative of the general industry.

Michael LaMotte - JP Morgan

Is there anything in the component cost that is leading you to think about redirecting capital on the margin? Anything inflationary in the components side that would lead you to rethink project or redirect capital to better return?

George Kirkland

We do that. I would tell you the one that’s probably been impacted the most is shelf Gulf of Mexico where we made some decisions on changing how much capital we were spending on some of our delineation and development wells there. Rig rates had moved way, way up very quickly. If you look at the pricing side of Henry Hub gas and you see the gas price has not moved; as a matter of fact, gas has moved down and oil has moved up. So we would have a bias there at this point in time to be oilier if we have a choice. We’ve got some projects because of the cost run-up on the services and the downturn on the gas price, that they are not really projects that are viable. So they are put back on the shelf.

Jim Aleveras

In closing, let me say that we appreciate everyone’s participation on today’s call. I especially want to thank each of the analysts on behalf of all the participants for their questions during this morning’s session. Matt, back to you.

Operator

Ladies and gentlemen, this concludes today’s third quarter 2007 earnings conference call.

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Source: Chevron Q3 2007 Earnings Call Transcript
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