Chevron Q3 2007 Earnings Call Transcript

| About: Chevron Corporation (CVX)
This article is now exclusive for PRO subscribers.

Chevron Corporation (NYSE:CVX) Q3 2007 Earnings Call November 2, 0000 11:00 AM ET


Stephen J. Crowe - CFO

George Kirkland – EVP, Upstream and Gas

Mike Worth – EVP, Global Downstream

Jim Aleveras - General Manager, Investor Relations


Dan Barcelo - Banc Of AmericaSecurities

Doug Leggate – Citigroup

Paul Sankey - Deutsche Bank

Mark Flannery - Credit Suisse

Mark Gilman – Benchmark

Neil McMahon - SanfordBernstein

Paul Cheng - Lehman Brothers

John Herrlin - Merrill Lynch

Michael LaMotte - JP Morgan


Welcome to Chevron’s third quarter 2007 earnings conferencecall. (Operator Instructions) I will now turn the conference over to theVice President and Chief Financial Officer of Chevron Corporation, Mr. SteveCrowe. 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 GeorgeKirkland, EVP, Upstream and Gas; Mike Worth, EVP, Global Downstream, and JimAleveras, General Manager, Investor Relations. Our focus today is on Chevron’sfinancial and operating results for the third quarter of 2007. We’ll refer to the slides that are availableon 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 $3.7billion in the third quarter compared with $5 billion in the third quarter2006. Earnings of $1.75 per dilutedshare 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 chargesassociated with non-recurring items. Themain driver for the earnings change was a decline of over $1 billion indownstream profits. Escalating costs forcrude oil feedstocks could not be fully recovered in the market. This impact was global, but it was especiallysignificant on the USwest coast. Overall, third quarter results were $1.7 billion lower than ourrecord second quarter 2007, which Jim will discuss shortly.

Return on capital employed for the trailing four quarterswas 22%. During the quarter, we retiredabout $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 theDecember 2006 buyback program during the third quarter. In September, we announced and initiated anew 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. Myremarks compare third quarter results to those of the second quarter 2007. As a reminder, our earnings press releasecompared third quarter 2007 with the same quarter a year ago.

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

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

Separate from these major asset sales, there was a further$300 million adverse effect between the sequential quarters due to netnon-recurring charges. The mostsignificant factor was the difference in tax items, contributing to a $230million 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 thisslide.

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

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

Turning to slide 5. Slide 5 summarizes the results of our USupstream earnings which fell by about $90 million between quarters. Higher realizations benefited earnings byabout $135 million between quarters. Higher liquids prices contributed $250 million to earnings, but lowernatural 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 theincrease in average WTI spot prices. This partly reflects Gulf of Mexico productionthat is priced on a lagged basis. This isa benefit when prices are falling, but a headwind when prices are rising.

Our natural gas realization fell by a little over $1.10 perthousand cubic feet, which is in line with the average changes in bid weekpricing at Henry Hub in Californiaand in the Rockies.

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

Asset retirement obligations were higher by $60 millionmainly due to an adjustment to the abandonment provision for offshore Californiaproperties that were previously sold. The other bar on this slide reflects higher exploration expense, assetimpairment and the absence of gains on some small operations we sold in thesecond quarter.

Turning to slide 6, this slide compares upstreaminternational earnings, which fell about $120 million between the second andthird quarters. Stronger liquidsrealizations benefited earnings by almost all of the $285 million impact shownon this slide. Natural gas effects,while positive, were essentially negligible. Liquids realizations improved by about $5.80 per barrel, in line withthe rise in spot BRENT prices.

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

Tax adjustments reduced earnings by about $80 millionbetween periods. The variance in theother bar includes asset impairment charges.

Turning to slide 7, slide 7 summarizes the change inworldwide oil equivalent production including volumes produced from oil sandsin Canada. Daily volumes were down by 39,000 barrelsbetween quarters. Maintenance-relatedshutdowns in the UK North Sea were the largest factor in this change. George Kirkland will discuss productionvolumes in more detail in a moment.

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

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

Turning to slide 9, international downstream earnings of $487million 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 byone-third and indicator margins were sharply lower in Europeas well. As was the case in the US;the price of crude rose more rapidly than the price of refined products duringthe quarter. These lower margins fullyoffset the gain on the sale of our fuels marketing business in the Beneluxcountries. The other bar on this slide includes asset impairment charges, lowershipping earnings and employee termination benefits.

Looking at slide 10, this slide shows the chemicaloperations earnings in the quarter were $103 million, essentially unchangedfrom the prior quarter. The results foroil sands improved due to higher ethylene margins and reduced utilitycosts. Aromatics benefited from improvedstyrene earnings reflecting higher margins and increased volumes. Aromatics also benefited from the absence ofan asset writedown we mentioned in the second quarter. The other bar includesan environment reserve provision in the third quarter.

Slide 11 covers all other. Second quarter results included the $680 million gain on the sale of ourinterest in Dynegy, which was partly offset by $160 million of charges relatedto the early redemption of Texaco capital bonds. Similar to the second quarterthis segment includes about $70 million of environmental remediation expensesfor legacy Texaco and Unocal sites that have been closed or sold. Third quarter net charges for this segmentfell at the high end of our standard guidance range of $160 million to $200million 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. Wewanted to use a portion of today’s teleconference to give George Kirkland andMike Worth and opportunity to update you on our upstream and downstreambusiness developments respectively. We’ll start with George. He’llturn 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 Iprovide you with an update of our major capital projects, I would like to reviewour 2007 production results. This slidecompares our net OEG production through the first nine months of 2007 versusthe first nine months of last year. Although we are down 50,000 barrels a day this year, we can point out90,000 barrels of losses in 2007 that are attributable to our contractualchange in OPEC curtailments in Venezuela.

Our production efforts this year have been focused onmanaging our base business declines and capturing gains from major capitalprojects that have recently come online. The low base business decline is a positive indicator of our basebusiness 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 typical4% 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 Mexicodeepwater with our Tahiti project, where we have a 58%net working interest. As a reminder, Tahitiis designed to have a production capacity of 125,000 barrels of oil per day and70 million cubic feet of gas per day.

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

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

Installation of the truss spar is now scheduled to begin inthe first quarter of 2008. The top sideinstallation, the mating with the spar, is targeted for the third quarter of2008. First production is now expectedby the third quarter of 2009, approximately 12 months later than originallyplanned 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 deepwaterGulf of Mexico. In July we purchased an additional 12.5% working interest in thisproject, bringing our total interest up to a 75% share. The top sides have been lifted onto the holeand all three development wells have been drilled. Positive results from the developmentdrilling supports the future drilling of a fourth well by 2009.

Off shore installation and well completions are scheduled tocommence in November of this year, with first production expected by the secondquarter of 2008. Blind Faith has aproduction capacity of 45,000 barrels of oil per day and 45 million cubic feetof gas per day.

Now onto slide 16 where I will update the status of theAgbami Deepwater Nigeria project. It’sfloating production, storage and off-loading vessel has left the fabricationyard in South Koreaand is being towed to the offshore Nigerialocation. This FPSO is the largest ofits type in the world and will be moored and ready for hook-up in the firstquarter of 2008. It has a processingcapacity of 250,000 barrels of oil per day and a storage capacity of 2.1million barrels of oil. We have already drilled 11 producers and seven injectors. We have two rigs working on the completionsof these wells. We are on-track forfirst 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 inthis project.

Now turning to slide 17, I’ll cover the Tengiz SGI/SGPproject. We anticipate that sour gasinjection and the first production will begin in the fourth quarter of2007. 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 picturedhere should be fully operational by the second half of 2008. This will add another 160,000 barrels ofproduction per day.

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

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

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

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

In Indonesiawe started up the DarajatIII geothermal project in July. This facility adds 110 megawatts to the West Javapower grid. The Darajat facility now hasa total capacity of 260 megawatts.

The next two items are examples of how we replenish ourdevelopment queue. In August weannounced 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 7,500barrels of oil per day of high quality crude. Future drilling is planned to assess potential reserves and assist inthe development design.

In July, we reported the successful prevention test of theRosebank appraisal well, located some 100 miles Northwest of the Shetland Islands. This well, in approximately 3,700 feet of water, flow-tested37 degree API light oil at restricted rates of 6,000 barrels of oil perday. The appraisal and evaluationprogram should be completed by November of this year and will allow us todetermine the future work program and development of this discovery.

We also recently announced our extension of the productionperiod for Thailandblocks 10 through 13. By securing thisproduction extension we will now be able to move major investments forward onthe Platong II project. Platong II isthe planned expansion of the existing Platong assets, which are currentlyproducing 250 million cubic feet a day and 40,000 barrels a day of hydrocarbideliquids. Platong II will add gasprocessing capacity and enable our oil and gas projects to beaccelerating.

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 downstreaminitiatives beginning with operational excellence. Improved reliabilitycontinues to be our top priority. We have resolved many high-risk conditionswhich have caused unplanned downtime. Despite these improvements, weexperienced significant crude unit fires this year at Richmondand Pascagoula. These incidentsremind us that we still have work to do, and have further strengthened ourresolve to improve reliability to enhance capabilities, processes andequipment.

While the fire at Pascagoula was unfortunate, our incidentresponse was swift and effective, limiting the impact and preventing anyinjuries. We expect to complete repairs during the first quarter 2008. Thedemolition phase is proceeding safely. Critical equipment orders have beenplaced, and delivery is scheduled. We’re taking steps to optimize conversionunit utilization while the crude unit is offline.

As the left chart shows, lost utilization from unplanneddowntime 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 onthe right. Incidents per quarter at our largest operated refineries have fallenmore than 50% since 2005.

Since the first quarter turnaround, crude unit utilizationat Richmond has been consistentlystrong, averaging 101%. Our UK refinery has also operated very well the entireyear, also averaging 100% crude utilization. Conversion unit utilization atthese facilities has also been very strong.

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

On the west coast, we are currently modifying our El Segundocoker during a planned turnaround, to enable a shift to heavier and highersulfur crudes and to improve coker reliability. We expect to meet our productsupply commitments during the turnaround and to have the heavy crudeenhancements online by year end.

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

Finally, we announced sanctioning of the ContinuousCatalytic Reforming project at Pascagoula. The new CCR will improve utilization andoptimize product yields. Gasolineproduction at the refinery is expected to increases about 10% with completionanticipated by mid-2010. In summary, weare ahead of schedule, or on track to complete the significant capital projectswe committed to bringing online this year.

Moving to slide 21, we are also making significant progressin high grading our portfolio. As youcan see from the map, we have made a number of divestments in the past twoyears on top of ongoing efforts to reduce the capital intensity of our brandedretail network.

As you recall, back in March we announced our intent topursue divestments in Europe and Latin America. We have followedthrough and succeeded in monetizing assets in businesses we no longer consideredstrategic. In March, we sold our 31%interest in the Nerefco Refinery in the Netherlandsand other assets there, generating $1.1 billion in after-tax proceeds. Duringthe third quarter, we closed the sale of our fuels marketing business in Belgium,the Netherlandsand Luxembourgfor about $500 million in proceeds excluding a final adjustment expected byyear end.

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

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

Now I will turn it back over to Steve.

Stephen J. Crowe

Thanks, Mike. Thatconcludes our prepared remarks. We’llnow take your questions, one question per caller, please. Matt, please open the lines for questions.



Our first question comes from Dan Barcelo - Banc Of AmericaSecurities.

Dan Barcelo - Banc OfAmerica Securities

Good morning, gentlemen. Thank you for the update,particularly on the projects, it was quite useful. I wonder if you could spenda 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? Iknow it may be premature as you’re still trying to cost and phase that, but anythoughts about how you’d phase the development, and particularly on the costs forGorgon? Thank you.

George Kirkland

Dan, let me start off. I think you’ve highlighted a lot ofthe points that we’ve still got to address. In my comments I mentioned that weneed to go back and look at the permit conditions. We have a significant numberof permit conditions that we’ve got to have mitigations fully vetted andunderstood how we would handle where we don’t get into a cost issue during theconstruction 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 themodularization. Remember we’re building this on Barrow Island. We’ve got theability to do a lot of modules and bring them in to minimize the actual work onthe 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 areally good plan, and modularization will really help us there.

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


Your next question comes from Doug Leggate - Citigroup.

Doug Leggate -Citigroup

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

Stephen J. Crowe

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

Jim Aleveras

Doug, your question was with respect to the USdownstream?

Doug Leggate -Citigroup

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

Jim Aleveras

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

Doug Leggate -Citigroup

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

Jim Aleveras

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

Doug Leggate -Citigroup

Okay. Do you havethat for the other divisions?

Jim Aleveras

In terms of our segments?

Doug Leggate -Citigroup


Jim Aleveras

For the third quarter the USupstream, the non-recurring charges in aggregate were about $100 millionnegative. For the internationaldownstream, the net non-recurring charges were about $250 millionnegative. As I mentioned, for USdownstream it was about $50 million negative.

For the international downstream, because of the gain on theBenelux 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 Beneluxassets. So there was the gain on the Beneluxassets of plus $265 million and there were net non-recurring charges ofnegative $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 notterming that a one-off item in the U.S.?

Stephen J. Crowe

Yes we are, Doug, and it’s not a large item but theseverances 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?


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

Paul Sankey -Deutsche Bank

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

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

Jim Aleveras

We won’t count that as a question. So in the post Reg Gworld we live in, which goes back a few years now about making pro formaadjustments to GAAP earnings, these items were properly recognized in the thirdquarter. They’re event-driven as in thecase of sales or the recognition of impairments or severances and thelike.

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

It’s really, then, left up to the individual analyst todetermine whether or not those should be taken out in order to get more of aclean 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 usplease, 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’vegot going on there, firstly?

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

Stephen J. Crowe

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

Mike Worth

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

Relative to our investment position, as you know we have a5% stake and subject to a number of other agreements being negotiated, theopportunity to increase that to 29%. Wehave not concluded those other agreements and no decisions have been made as tothe 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 therefinery -- that’s presumably afirst-half event. Secondly the timing,if you could just remind us on the increase on the stake when we’ll get ananswer on that would also be interesting. Sorry to interrupt. Thanks.

Mike Worth

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

Paul Sankey -Deutsche Bank


George Kirkland

On the upstream issue, I would say we still have interest inthe KG Basin. But, Paul, there’s reallynot been much progress in really developing that opportunity. So really it’s nothing really to report atthis point in time.

Paul Sankey -Deutsche Bank

Are there any initiatives that there might be something,George, that you could talk about? Or wecan 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 lotof other people besides us that are interested in that. So I really don’t have anything to report.


Ournext question is from Mark Flannery - Credit Suisse.

Mark Flannery - Credit Suisse

Yes. My question isto 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 justexpand a little on that, and tell us what kind of things specifically you’redoing presumably to get that rate down obviously? When do you think it would be appropriate totalk 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 weare influencing it. Specifically we’vegot I think great processes where we in effect do base business audits aroundthe 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 thesurface facilities and the subsurface facilities to make sure we don’t have anybottlenecks. We’ve been on that process,for now about three years.

It continues to turn up opportunities for us to optimize ourproduction around the world. We areseeing some influence. This first ninemonths of this year we’ve had some great successes in South Texas with somedevelopment wells, which we used good seismic technology there, and had somegood results there. We’ve got some otherplaces where we’ve focused on our water floods and we’ve seen some declinerates 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’veput in place are going to help us for the long period improve our recovery andreduce our decline rates in greatest sense, but I think it’s a little bit tooearly and that’s why I made those comments that way.

Mark Flannery - Credit Suisse

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

George Kirkland

It’s a mix of things. It is not one focus. We have fourto five areas that we really focus on; and in some places, we get it out ofjust system reliability, raising the reliability, the run times. Some places it’s hey, we find a facility thatwe can push more barrels through and we see that we’ve got reservoir capabilityto 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, fromthe reservoir through the sales point to try to optimize the system in all ourbusiness units around the world.


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 thesanctioning of the CCR project, and I’m assuming that in having done so thedistillation expansion at Pascagoula which had been under evaluation is now nolonger on the table. Could you commenton the validity of that observation?

Mike Worth

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

The evaluation of other alternatives for Pascagoulacontinues. I think I’ve indicated thatwe would reach a final decision on that next year. Certainly, you’re seeing project economicschallenged in the refining sector on the Gulf Coast as well as the rest of theworld 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 evaluationof alternatives, and we’ll have more to say about that next year as that workis complete.

Mark Gilman -Benchmark

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

Mike Worth

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


Your next question comes from Neil McMahon - SanfordBernstein.

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 intomaybe walking through some reasons for that, and did you have hedges in placesthere that could have caused some of those losses?

Mike Worth

As Jim showed earlier, when you compare the third quarter tothe second quarter, our USearnings were down nearly $900 million. More than two-thirds of that declinewas due to industry margins, and really the balance for the USwas due to lower volumes, and that is primarilyPascagoula.

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

So we do have some paper effects that you see in anenvironment like this that are exacerbated by the amount of long-haul crudethat 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 thoselong-haul crudes or in the west coast?

Mike Worth

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

Jim Aleveras

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


Your next question comes from Paul Cheng - LehmanBrothers.

Paul Cheng - LehmanBrothers

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

Mike Worth

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

Paul Cheng - LehmanBrothers

Mike, I’m talking about on an absolute level that the crackis 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 thatNeil was asking. We have these non-ratablepricing effects related to the change in crude prices which are most significantbecause the amount of long-haul crude that we bring into the west coast. And so if you look at 3Q07 versus 3Q06 youwould see that the margin declines are not especially severe and the absolutelevel of margins, as you say, are not as extreme as the earnings delta mightindicate; but if you look at 3Q06, we saw crude prices drop by about $11 abarrel over the quarter. In 3Q07 we saw crude prices increase by $11 per barrelin the quarter, and so those non-ratable pricing effects have significantknock-on accounting effects that get unwound subsequently as we actually runthe crude, but in the quarter they create pronounced effects on our west coastdownstream performance.

Paul Cheng - LehmanBrothers

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 millionbarrels of long-haul crude on the water, and as Mike said in the earlier perioda 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 thirdquarter. That is going to be a material impact on the comparison betweenadjacent years on a variance. it’s one of the reasons why sometimes theindicative margin doesn’t become realized for our company. Thanks for yourquestion.


Your next question comes from John Herrlin - Merrill Lynch.

John Herrlin - MerrillLynch

With Thailandyou said that you extended the contract. Are the terms still similar, or arethey higher for the country?

Stephen J. Crowe

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

John Herrlin -Merrill Lynch

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

Stephen J. Crowe

I think my memory of the major targeted prospects, I believeit was nine or 11 intotal that we really captured major new prospects. All of them but one was thelower tertiary.


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 thefields, and the extent to which there are rate of return thresholds built intothose production-sharing contracts, pursuant to which profit barrels and profitpercentages would step down once the threshold was reached?

George Kirkland

Mark, I’m going to limit my comments a little bit, I willtell you that we have different development areas around each field. Our development areas have typically in block14, been larger than what we had seen in the past and in some cases, they havebeen more or less brought together to allow cost recovery to be moved from onedevelopment to another. So we have hadlarger development areas than in the past. I’m not going to speak about the contractual pieces beyond that.


Your final question comes from Michael LaMotte - JP Morgan.

Michael LaMotte - JPMorgan

A question related to upstream cost pressures, as yourspending is shifting more towards completion and production, are you seeing anychanges in the rate of change of cost there? I would think that completion inflation is probably not as high asdrilling 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 to30 countries around the world, we’ve got a whole portfolio of projects that arein anything from the early phase, engineering to just about to start up andactually a lot of them in start up.

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

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 andmaybe that will help you get a little bit of context. We had a project in Angola, we brought onlinein 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 thispoint, so we understand contractually what the cost is going to be fordrilling, for building of all the facilities, the installation, so we have gotthe contracts really nailed down.

There’s a five to seven-year difference in the life cycle ofthe two projects and when you compare project A to project B, we see almost a100% increase in the cost of doing the similar work. So that’s very typical in the deepwater whereyou’ve seen rig rates go up. Deepwaterrig rates have gone up two to threetimes over a five-year period.

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

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

Michael LaMotte - JPMorgan

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

George Kirkland

We do that. I wouldtell you the one that’s probably been impacted the most is shelf Gulf of Mexicowhere we made some decisions on changing how much capital we were spending onsome of our delineation and development wells there. Rig rates had moved way, way up veryquickly. If you look at the pricing sideof 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 wehave a choice. We’ve got some projectsbecause 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’sparticipation on today’s call. I especially want to thank each of theanalysts on behalf of all the participants for their questions during thismorning’s session. Matt, back to you.


Ladies and gentlemen, this concludes today’s third quarter2007 earnings conference call.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to All other use is prohibited.


If you have any additional questions about our online transcripts, please contact us at: Thank you!