Chevron Corporation (CVX) Q4 2010 Earnings Report, Transcript and Summary

Good morning. My name is Shawn, and I will be your conference facilitator today. Welcome to Chevron's Fourth Quarter 2010 Earnings Conference Call. [Operator Instructions] I will now turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corp., Mr. John Watson. Please go ahead.

Okay. Thanks, Shawn. Welcome to Chevron's fourth quarter earnings conference call and webcast. On the call with me today are Pat Yarrington, our CFO; and Jeanette Ourada, the General Manager of Investor Relations. Our focus today is on our financial and operating results for the fourth quarter of 2010, and we will refer to the slides that are available on our website. Of course, before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements, and we ask that you review the cautionary statement on Slide 2. I'd like to share some of our strategic accomplishments for 2010, which are located on Slide 3. I'll begin with our safety performance. This past year, we achieved our safest year ever, again, I might add, our safest year ever with both our Upstream and Downstream operations setting new records. We're very proud of our world-class safety performance, and it will continue to underpin everything we do. In the Upstream, our achievements were many. We exceeded our production growth guidance, delivering 2% growth for the year. We progressed a number of key projects. We sanctioned three Deepwater projects in the Gulf of Mexico, along with the Papa-Terra project in Brazil. We also sanctioned the expansion of the Caspian Pipeline, a critical step forward for our next Tengiz expansion in Kazakhstan. We continued our Australian exploration success with five discoveries. This brings us to a total of nine discoveries since we sanctioned Gorgon 18 months ago. These additional volumes will support expansion opportunities at both Gorgon and Wheatstone. Finally, we added a significant amount of new Deepwater and shale acreage to our portfolio. We're currently in the early phases of evaluating and planning for these new opportunities. Looking at our Downstream business, we made truly great progress in the first year of a three-year plan to improve returns. A new organization is now in place and focused on tactical plans to improve performance. In 2010, we sold the Colonial Pipeline, exited seven countries and most U.S. East Coast markets. We received good value for these assets. These exits lower costs and capital employed in the Downstream, allowing us to focus on markets of competitive strength. We also made progress on our capital projects with start-ups in the U.S., Korea and Qatar. In all 2010 was an excellent year, both operationally and financially. Pat will now take you through our fourth quarter financial results. So I'll turn it over to Pat.

Okay. Thanks, John. Slide 4 provides an overview of our financial performance. The company's fourth quarter earnings were $5.3 billion or $2.64 per diluted share. Comparing the fourth quarter 2010 to the same quarter a year earlier, our earnings were up over 70%. Upstream benefited from higher prices and sales volumes, and Downstream benefited from higher refined product and chemical margins and asset sales. For the year, earnings were $19 billion or $9.48 per diluted share. Return on capital employed for the year was over 17%, and our debt ratio at year end was 9.8%. We paid $5.7 billion in dividends, and 2010 marked the 23rd consecutive annual dividend increase, with an annual average growth rate over the period of 7%. In the fourth quarter, we resumed our common stock repurchase program, repurchasing $750 million of our shares. In the first quarter of 2011, we expect to repurchase another $750 million. Finally, Chevron's 2010 TSR, total shareholder return, was nearly 23%. Over a five-year period, we continue to hold the number one ranking in our peer group and have outpaced the S&P 500 by over 10%. Now on Slide 5, underscoring Chevron's financial strength, our cash balances exceeded debt by $5.6 billion at the end of the year. In the fourth quarter, cash from operations exceeded $8 billion. For the full year, cash from operations exceeded $31 billion, a record for the company. And this is after nearly $1.5 billion in pension contributions. Along with proceeds from our assets and divestments, our cash flow provided excellent support for our capital expenditures, our dividend payments and our share buyback program. Our previous investments are generating strong earnings and cash flow, allowing us to reinvest in our project queue, while sustaining meaningful dividend growth and a share buyback program. Certainly, our strong cash flows and our solid balance sheet continue to be a competitive advantage. Turning to Slide 6. I'll compare results of the fourth quarter 2010 with the third quarter of 2010. And as a reminder, our earnings release compares fourth quarter 2010 with the same quarter a year ago. Fourth quarter earnings were $1.5 billion, higher than the third quarter. Results for all of the segments improved between periods. Upstream earnings were up nearly $1.3 billion, driven by higher oil prices and higher liftings. Downstream results were nearly $200 million higher. Gains on asset sales and favorable timing effects were partly offset by higher operating expenses. The variance in the other bar reflects the favorable swing in corporate tax items. On Slide 7. Our U.S. Upstream earnings for the fourth quarter were $16 million lower than the third quarter's results. Realizations increased earnings by $180 million. U.S. crude realizations rose over $7 per barrel between consecutive quarters, about $1 less than the increase in the average spot price of our WTI. Natural gas realizations fell between quarters, in line with Henry Hub spot prices, offsetting about $30 million of the liquids realization benefit. Higher operating expenses decreased earnings by $30 million between periods, primarily due to higher maintenance costs associated with multiple assets. Inventory effects had a $60 million unfavorable impact between quarters, primarily due to year-end LIFO drawdowns. And the other bar is comprised of a number of unrelated items, including higher abandonment expenses and lower gas marketing earnings. Now on Slide 8. International Upstream earnings were up $1.3 billion compared with the third quarter. Higher oil and natural gas realizations increased earnings by $600 million. Average liquid realizations rose 14% between quarters, slightly higher than the increase in average rent spot prices. Natural gas realizations increased 2% between quarters. Higher lifting, particularly in Kazakhstan and Indonesia, increased earnings nearly $400 million. Operating expenses decreased earnings by $120 million. About half of that total was due to a new Indonesian agreement, where we sell oil and purchase natural gas. Previously, we had handled this through a volume exchange. And with the new arrangement, the natural gas purchased shows up in operating expense. With an identical offset in liftings from the oil sale, there is no bottom line earnings impact and no impact on production. As a result of this new agreement, we expect the 2011 full year increase in reported operating expense to be approximately $1 billion. Moving to the next bar, a favorable change in foreign currency effects benefited earnings by $190 million. The fourth quarter had a small loss of about $50 million compared to a $250 million loss in the third quarter. These foreign exchange impacts have no direct effect on cash. They are primarily balance sheet translation effects. The other bar reflects a number of unrelated items including lower tax, exploration and depreciation expenses. Slide 9 summarizes the quarterly change in Chevron's worldwide net oil-equivalent production. Production increased 48,000 barrels a day in the fourth quarter. Higher prices reduced volumes under production sharing and variable royalty contracts during the current quarter, decreasing production about 18,000 barrels a day. The average WTI spot price increased about $9 between quarters. For the fourth quarter, each dollar increase in WTI resulted in a 2,000 barrel a day volume reduction. Base business production increased 32,000 barrels a day between quarters. It is unusual to see a positive variance for this bar. The absence of third quarter planned turnarounds in Europe and Karachaganak more than offset normal Base business declines and planned maintenance in Thailand. Contributions from major capital projects increased fourth quarter production by 34,000 barrels a day, primarily driven by the ramp up of the AOSP [Athabasca Oil Sands Project] expansion in Canada and higher volumes in the Gulf of Mexico. Slide 10 compares full-year 2010 net oil-equivalent production to that of 2009. Production rose 2% or 59,000 barrels a day. On a price-adjusted basis, we achieved a 3% production increase in 2010. Price impacts from production sharing and variable royalty contracts decreased production by 38,000 barrels a day. The average WTI price increased about $18 in 2010. And for the full year then, each dollar increase in WTI resulted in about a 2,000 barrel per day volume reduction. Base business combined with external constraints lowered production by 73,000 barrels a day. Record Base business reliability and system optimizations limited our decline rate to about 4%, in line with the guidance we provided earlier in the year. Also included in this bar are the favorable production benefits from fewer security disruptions in Nigeria and higher natural gas demand in Asia. Incremental production from our major capital projects contributed 173,000 barrels a day to 2010 oil and gas production, reflecting debottlenecking at Tengiz, SGI/SGP in Kazakhstan and a full year of production from Tahiti in the Gulf of Mexico and Frade in Brazil. Now on Slide 11. Compared to the third quarter, U.S. Downstream earnings improved $126 million in the fourth quarter. Indicator margins reduced earnings by $85 million. We saw a stronger Gulf Coast refining indicator margin, in part driven by seasonal heating demand. However, West Coast margins fell by 11%, reflecting the end of peak driving season and high inventory levels. Marketing indicator margins continued to weaken in the fourth quarter. Fourth quarter turnaround activities were also a major driver in the quarter of negative $140 million earnings impact. This came about because of lower volumes and higher operating expenses. In the fourth quarter, we sold our interest in the Colonial Pipeline Co. and in seven terminals, realizing a combined gain of nearly $400 million. The other bar consists of several unrelated items, including lower trading and Chemicals results, offset by lower turnaround-related feed stock costs. On Slide 12. International Downstream earnings were also higher, increasing $51 million from third quarter's results. Weakened Asian refining and marketing margins lowered earnings by $35 million. Operating expenses increased between quarters negatively impacting earnings by $90 million, reflecting small increases across a number of multiple expense categories. Timing effects represented $120 million positive variance between the quarters, reflecting a swing from a negative $85 million in the third quarter to a positive $35 million in the fourth quarter. The primary drivers were favorable year-end LIFO effects and lower volumes of open paper associated with underlying physical positions. Put another way, we simply had fewer cargoes and, therefore, less paper exposed to the higher prices. A favorable swing in foreign currency effects benefited earnings by $65 million. Fourth quarter's foreign exchange loss was about $55 million compared to the third quarter loss of $120 million. And the other bar there includes a number of offsetting items. Now on Slide 13. Fourth quarter net charges were $294 million compared to a net of $361 million charge in the third quarter, a decrease of $67 million between periods. A favorable swing in corporate tax items resulted in $150 million benefit to earnings. Corporate charges were $83 million higher in the fourth quarter. For the full year, this segment had net charges of $1.1 billion. We believe our quarterly guidance range of between $250 million and $350 million for net charges in this All Other segment is still appropriate going forward. And so with that, I'd like to now turn it back over to John for a few thoughts on 2011.

Okay. Thanks, Pat. Let's turn to Slide 14. We recently announced our capital program for 2011 at $26 billion. This is about a 20% increase from our 2010 investment of $22 billion. 85% of the program is for Upstream activities, primarily related to our large multiyear projects and consistent with our well-articulated Upstream growth strategies. These include our legacy LNG projects in Western Australia and projects in the U.S. Gulf of Mexico, Africa and the Gulf of Thailand. About 11% of the planned investment is earmarked for Downstream, mostly related to maintenance and capital projects at our larger refineries. As Pat mentioned earlier, we grew production over 2% in 2010 and exceeded both our original and interim guidance despite higher crude prices. Slide 11 shows our production outlook for 2011. Our full year outlook for production in 2011 is 2.79 million barrels of oil equivalent per day, about a 1% increase over 2010 levels. The outlook assumes $79 per barrel, the same average price as 2010 and does not assume OPEC curtailments, material security or market impacts. The 1% increase comes from a combination of sustained performance from our base business and continued ramp-ups from some major capital projects. Turning to Slide 16. Heading into 2011, our strategies remain very consistent and are serving our shareholders well, we believe. In the Upstream, we're on track for start-up of two major capital projects, the Platong II project in Thailand and the Agbami 2 project in Nigeria. We expect to sanction three other major capital projects, the Wheatstone LNG project in Australia, the Vietnam Block B gas project and the Clair Ridge project in the U.K. We will continue to progress our major capital projects with keen focus on Gorgon and our Deep Water Gulf of Mexico projects. During the fourth quarter, we announced the acquisition of Atlas Energy. We look forward to the results from the Atlas stockholders meeting on February 16. We're currently working on integration planning. We look forward to welcoming this highly skilled team to Chevron's family and adding these assets to our portfolio. In the Downstream, we will continue on our path to improve returns and building on the solid foundation that we achieved in 2010. We expect to complete a number of divestitures and market exits consistent with our strategy to focus on Downstream operations, where we have competitive strengths. We also expect to sanction our Pascagoula Base Oil project shortly and start up our Saudi JV chemical project this year. Underlying all of our efforts will be a continued focus on safe, reliable operations, project execution, capital discipline and cost structure vigilance. 2011 will be another year where we continue our disciplined growth, continue maintaining our financial strength and continue to reward our stockholders, and we look forward to further discussing our plans at our Security Analyst Meeting on March 14 in New York City. That concludes our prepared remarks. We now welcome your questions. So Shawn, please open the lines for those questions.

[Operator Instructions] Our first question comes from Ed Westlake with Crédit Suisse.

Firstly, as you look at your portfolio, I mean, housecleaning's always a good practice. What kind of level of disposals are you thinking for 2011?

Sure, Ed. In terms of divestitures, most of the efforts that you'll see in 2011 are really following up on the work we've been doing in the Downstream area. We have been pruning our portfolio, chiefly, of marketing assets that aren't directly linked or supplied through our refining networks. So we've announced a series of sales, and those will continue. In addition, we've made no secret of the fact that we were going to test the market around our U.K. Refining and Marketing business. And as Mike Wirth mentioned to you in the third quarter call, we've had considerable interest. And so, we've said that we'll dispose of those assets if we get a fair value. I don't have anything to talk about specifically today, other than to say that we have had a very strong interest in those assets. And so, we'll be continuing to work that opportunity. Beyond that, most of the divestitures that you see in the Upstream tend to be routine disposals for assets that are at the end of their useful life. Our general view is absent a very compelling strategic move. There's a lot of leakage when you sell Upstream assets through tax consequences and other. And so we tend to make decisions for the long term, but I think you could see some pruning that would be sort of in the ordinary course of business.

I mean, obviously, you're positive on the U.S. gas demands and the position you picked up in the Atlas, and frac-ing is also helping to unlock some of the onshore oil potential in North America and elsewhere. I mean, you've got strong sort of international exploration credentials and cash flow per barrel. What's stopping you, I guess, being more assertive, given the cash you've got on the balance sheet in the nonconventional area, maybe thought for your plans?

Well, we talked about unconventional last year at our meeting in New York, we had indicated that we thought the price prices were, frankly, a bit high at that time, and that we have had a fairly active interest in shale gas properties. And so, we have been accumulating opportunities overseas. We've done so in Poland and Romania and Canada, and we have said we that we were looking in the United States, too. We haven't seen the value proposition. Well, as we progress through the year, we saw values improve. And so, we did make what we think is a good offer for Atlas Energy. And that's the kind of low-cost entry that we're looking to make. Now our first order of business is to close that transaction, and we look forward to the shareholders' vote next month. Having said that, we're in the business of acquiring assets. We do so through leases. We do so through discovered resources, and we do so through companies periodically. And so that effort will continue, including in shale areas, if we see the right commercial opportunities. We try to either be ahead of the game, so that we get low-cost entries or we try to wait for the right opportunity, given market effects for discovered resource or companies, as the case may be.

Our next question comes from Doug Terreson with ISI Group.

John, my question is on the Upstream. Globally, your production growth was impressive in 2010 when you consider that your output in whatever is in 4% before prices effects, and that it did rise by 2% with price effects. And that's after the 7% gain in 2009. And as you pointed out both of these numbers were well ahead of expectations. And so, I want to see why you believe the Upstream segment has been able to consistently surpass expectations in recent years, meaning, for the past couple of years, price effects were kind of a neutral factor, which implies that external effects, stronger base business and/or better performance on new projects drove the surprise in relation to expectations. And so, I just wanted to see if you could provide any additional insight into some of the things that might be driving this performance?

I think we have had a very good run, as you point out. Actually over the last five years, we hit the target that we laid out for the financial community for production growth, and we recognize that that's helped our credibility. And we're focused on doing the same thing again. In terms of why that's happened, I think it's a combination of things. I think I'd start with the people and the leadership that we've got. George Kirkland and his leadership team are simply terrific and do a great job. They're supported by a technology organization, a project execution organization, that works very well. Our business model has strong leaders on the ground, supported by functional groups. And we think that, that works very well. Now it helps to have good assets in our portfolio, and of course, we think we have those as well. You saw that we had some nice gains in Kazakhstan, the Deepwater Gulf of Mexico and elsewhere last year. The final thing, maybe one other thing I would mention, is we talk a lot about our base business work that isn't quite as glamorous as perhaps some of the major capital projects. But the blocking and tackling around well reliability, maintenance, facilities, debottlenecking, et cetera has really been outstanding, and that initiative really moved forward in the middle part of this last decade. And George and his team was supported, many throughout the organization have just done an outstanding job. And I give them a lot of credit for the work that's going on. And we have really made progress by production efficiency or other internal measures that we use to track that, and we're looking forward to sustaining and finding new ways to do even better. But those would be the things that I'd highlight.

Our next question comes from Evan Calio with Morgan Stanley.

A question on reserve bookings, and I know that it has been and will remain lumpy, and we should see a significant impact in 2011, when Wheatstone reaches FID. But I was wondering if you could give some color on the bookings and whether you booked anything on the gone projects that were sanctioned D D, Big Foot and Jack/St. Malo and whether those bookings were influenced by either inactivity or SEC technical definitions, particularly regarding Jack.

Yes, that's a good question on this technical subject. I think that your premise is pretty good. The previous five years, we had more than replaced reserves, and it is lumpy and it's a function of a couple of things. It's a function primarily of major capital project timing. I mean, there are price effects. So our reserve replacement rate was 24%. It would have been something like 37% without price effects. But beyond that, it's really the timing of major capital project bookings. Now if you go back some years, it was quite common that when you went to FID, you had major bookings. In this instance, we had three Deepwater developments: Jack/St. Malo, Big Foot in the Gulf of Mexico and Papa-Terra in Brazil that, based on the economics that we run that sanctioned the projects. And remember, these projects are shares of about $8 billion. So we felt confident enough in the resource that was there that it would be recoverable to make those investments. But the volumes that we premised those projects on, which are close to 600 million barrels, we didn't book any of them. And we didn't book them for the reason that you described. There's an economic producability test that the SEC has, under our interpretation of the rules, that, first, you start with the technical qualifications for what can be booked early. And typically, that limits the number of barrels, and then those barrels alone are not what you ultimately expect to recover. You have to cover all the capital costs, which may include infrastructure for future expansions and the like. And so you get into this situation where you have to get enough, some costs behind you, before you can book the reserves. And that's just the SEC rules, and we live by them, but we think it contributes to the lumpiness that you described. And you can go back over the last 10 years, and we've had periods that were low and periods that were very high. And this happened to be a low year, but it's not impacted by the moratorium. I'm saying it's more impacted by the SEC rules. And as you say, as we press forward with these, we'll expect to record bookings in future years.

Maybe a somewhat related question in the 1% production guidance for 2011. I know the tricky part is forecasting the base. And I believe last year, you were at 6% base decline underlying those numbers. I was wondering if what you're assuming there in the Gulf of Mexico, activity-wise, and how we can think about incremental risks either way on that guidance or even future production growth?

Yes, I'd make a couple of comments. First, in a broad sense, we have seen a reduction in our Base business decline rates. And from 6% or so in past years now into the 3% to 4% range. So I think that reflects a number of things, including the progress that we've made on our Base business work. Now as far as the Gulf of Mexico, going forward, maybe I'll take a minute. This may be a little bit longer answer than you wanted, but I would like to comment on the subject. The progress in getting back to work has been slower than we would have expected. There's some maintenance work going on. But fundamentally, the moratorium's up, but they're not issuing permits. And I think they're trying to get it perfect, in terms of some of the regulations that they're putting in place. And so we keep getting more thrown at us. If you reflect back on the last year, the industry and regulators have done an enormous amount of work to try to raise the bar, if you will, on standards for all operators. I've made it very clear that Chevron has operated at a high standard, but enormous progress has been made to include prevention. So that in the very unlikely event that has been well-documented, it doesn't happen again. And we think that prevention steps have improved. In addition, containment and cleanup is far better than it was. So we're in much better position as an industry than we were previously, and no company, based on the comments I've had from administration officials and regulators, no company has done more to engage the government to try to improve these standards and get us back to work. And my comment here is that time's about up. We can operate very safely. Our industry has an outstanding safety record, notwithstanding the terrible incident of last year. Our days away from work rate in the industry is lower than the federal government's. The fatality rates for serious incidents in the Oil and Gas business is lower than most other manufacturing businesses that you could name. And we just think that the unprecedented step of just shutting down a business has reached the point of diminishing returns, and it's time to get back to work. The administration wants to create jobs. We can create thousands of them. I'm very concerned about energy security for the country, going forward. Independent experts have said that already 300,000 barrels a day have been lost, if you look out three or four years, and that number's going to grow. And that's going to represent a sizable chunk of the spare capacity that the industry expects to see. And that will impact prices, and that will retard economic growth. So we can operate safely. We can create jobs. We can reduce dependence on imports, and I think it's time to get back to work. But I can't tell you how fast this is going to proceed. We seem to take a step forward and then take a step back with difficulties in interpreting the new NTLs that are out there, and we engage heavily. We try to be of assistance, but the bottom line is they're not issuing permits and until they issue permits, Deepwater development, both exploration and development wells, for the most part, won't be drilled. And I wish I could give you a precise timing, but I can't. So that's a long-winded answer to your question, but that's the best I can give you.

Does your guidance assume activity in 2011?

It does. It does assume that. We've made assumptions about when we might get back to work. That's in there, and there are development wells that we expect to drill. There's activity on the shelf that we have some expectations for. More importantly, exploration wells won't be drilled. We suspended wells that were in progress last year. We'd like to finish those and move on to others. In the grand scheme of things, Chevron can deal with this. It cost us about $100 million or so after tax last year. We can deal with this in the short run, but it's very difficult on small companies. It's very difficult on service providers. We're seeing rigs leave the area, and we just think that time's about up. We need to get back to work. It's the right thing for the country.

Evan, I just want to add. The $100 million is really the op-expense-only impact. If you include Gorgon revenues, Gorgon production, obviously, it's much larger than that.

Our next question comes from Doug Leggate with Merrill Lynch.

The absolute tax benefits, please, Pat, by division, if you have them in the quarter? I'm trying to understand what the underlying tax rate was. And while you figure that out, John, the question I have is really a follow-up on Evan's question about production. Obviously, we've got a much higher oil price than any of us really expected internationally, I think, is part of your comment. I'm not so much looking at the PSC sensitivity, I'm thinking more about cost recovery cliffs on some of the new projects, how quickly you actually move through cost recovery such that your underlying production, obviously, after a period of time is moved to the production share. At the same time, given what you said to Evan, what if you don't get back to work in the Gulf, can you give us an indication how that might impact what the range would be, perhaps, in your production outlook? And finally, what's going on with the base decline? And are you're putting money back into gas projects now, which I think was originally what George had deferred capital from before. So if you could kind of round out the production question and then maybe giving a tight sense? That would be great.

First, the base decline, as I indicated, company-wide is in the 3% to 4% range. As far as gas investments go, in the United States, once we close the Atlas acquisition, there's a favorable carry in that agreement. So activity in the Marcellus would ramp up as had been the work that's being done by Atlas and planned to be done. So that will ramp up. So we will see more drilling activity there. As far as the Gulf of Mexico goes, we've made some assumptions about when we'll get back to work this year, and I'm not going to go into a lot of detail on that. Now what I would say is if we went the whole year without activity, the number would be lower than what we have put forward. We've exceeded our guidance this year for several reasons. One, the base business results were very good. We've had a little bit higher market demand than we might have expected, and we also didn't have the hurricane season that we thought we'd have. So we factor some of these things in and a few other items, and so we've had good performance. Tengiz performed better than expected last year. So there's some ebbs and flows here that we take into account. In the Gulf of Mexico, it will be important for us to get back to work, for us to continue drilling on the Deepwater projects, we're non-operating position at Perdido there are additional development wells to be drilled there, and we have our own activity. So it's important to us. We have assessed that in providing the guidance that we've put forward, and we'll continue to update it as the year grinds on. So I'm hopeful we'll be back to work. We've been keeping a lot of people and equipment busy doing maintenance and other work, but the Deepwater progress has been slowed significantly. I think I got most of your items there.

The PSC cliff, John, is there anything we should be aware of?

I mean, we do have PSCs out there. Of course, if you hit a cliff sooner that's because you're making more money because prices are higher, and you're recovering your costs faster. But I'm not prepared to talk about any particular cliff or impact here with you today. Pat, do you want to talk a little bit about taxes?

Yes, on taxes, I mean, the effective tax rate for the quarter was about 39%, and you're right. It's more favorable this quarter than last quarter. A big variable that impacts the effective tax rate for us is the foreign exchange movement, because those really are balance sheet translation effects. They are not taxed, and so depending upon the size of the loss or the size of the gain that you have in any particular quarter, it obviously moves the effective tax rate. So I would just say I'm not -- that really is the primary driver between the quarters. The other thing that has occurred here is, as we earn more out of our Downstream segment, typically, it is coming from lower tax jurisdictions and so you get a mix effect.

So basically does that get allocated to any particular division? And sorry, John, very quickly, can you qualify the expected contribution from Atlas this year? And how do we get their effects?

Yes, I mean we booked the taxes in accordance with the segment where the earnings are accrued, the taxes are accrued there as well. Foreign exchange is also in the segment.

I'm not going to say much about Atlas. We're in a very sensitive time period right now, leading up to their shareholder vote. With the successful shareholder vote, we'll close the transaction, and we'll be happy to give you more information at that point.

Our next question comes from Paul Cheng with Barclays Capital.

John, I want to follow up on the Gulf of Mexico. To the event, unfortunately, that if the current impasse continues, at what point, let's say, a year from now, two years from now, your development cycle time for the Jack/St. Malo, Big Foot off in this current year, assumed to be 2014 start-up, at what point that you start to have a question mark on that start-up date?

Paul, the impact on the big projects, I mean, construction we've gone to FID. The facility's work is proceeding. The issue really isn't that it will impact start-up date. The issue is really how many wells will come online at start-up. Because we have three Deepwater rigs, and we use those rigs for exploration and development. And so we'll have to prioritize once we get back to work, which wells we drill. And we'll make those choices. But obviously, the fewer wells you drill, some of those could be development wells, and so it would push off the ramp-up not so much the first oil date. So Jack/St. Malo's on track for the 2014 start-up, and I don't expect that to be impacted. Only the drilling schedule ramp-up would be the impact.

So you don't think any of the changes in the regulation will impact your design work and you'll have to go back and redo and correspondingly that you don't think that's any real impact on the start-up. It's just that at what pace you can ramp-up or at what we pace you start up at?

Well, we're incorporating some design changes now that have come about. I wouldn't advertise these as being material. We've been operating at a very high standard already, and so we have not been significantly impacted. But there are some changes. We can give you a lot more granularity on schedule and information on some of these at our meeting. Jeanette wants to add something here.

Paul, we have said before that in 2011, the development drilling that we have planned in the Gulf of Mexico, it's towards the end of the year, and we did that intentionally.

John, on the Atlas Energy, what is your overall trend that you look at in the nonconventional play in the U.S. I mean, do you get a sort of like a bridge halfway now and how aggressive do you think you want to increase the exposure in there? And also when we're looking at some of your peers in the recent year, pretty aggressively moving into the nonconventional liquid play, whether it's in the Eagle Ford or Bakken, in some way, that I think Chevron is noticeable or may be left behind or missing in there. So do you think there is a bit too late for you guys to go into those or that you think that you just have to wait, and maybe opportunity will show up?

I think you're first talking about unconventional gas, and we feel good about the Atlas acquisition. It's a low-cost resource base, and we'll continue to -- once we get that transaction closed. We feel very good about it, particularly, good about the economics, given the carry that's in place. So we'll continue there, and we continue to look for other opportunities. Up to now, we haven't been as big on the liquids side. But in general, if you look at the unconventional business in the United States, it's been developed by the independents and smaller companies. The reason for that is that there's a great deal of land work that has to be done. And so you're going farm to farm or property owner to property owner. It's a very labor-intensive process. And so you've seen small companies make those moves. In due course, Chevron has the opportunity to come in. We do think we have something to offer from a technology point of view, and we'll continue to evaluate the opportunities that we see on either gas or liquids. I would note that we've been pretty active internationally, as I commented earlier, adding acreage and we continue to look for new opportunities.

In the U.S. Downstream, excluding the asset sales gain you earned of $75 million, Chemical earning is up, and based on what your partner Conoco report, it seems to suggest the U.S. power and [indiscernible] lost quite a bit of money in the quarter. In some way, that is surprising because the market condition, quite frankly, is not really that bad in the fourth quarter. I understand you have downtime, but looking at your total throughput, it's not necessarily much worse than the other quarter in the last two years. So does it mean that your operation in the refining, basically, that will lose money in the kind of market condition we saw in the fourth quarter?

Let me add a couple of comments, and then I'll let Pat offer a few things. The first comment I'd make is we've been very pleased with our Chemical business. It was a decade ago that we put together Chevron Phillips Chemical Company, and it's far exceeded the expectations that I had at that time. So it has been profitable. We also have an additives business that's been successful as well. And we did put these businesses together in the last year so that Mike Wirth and his team really can make the right manufacturing and marketing decisions for all the molecules together in the Downstream and Chemicals business, and that's gone quite well. I'll let Pat comment a little bit on profitability, noting that margins were different on the Gulf Coast and West Coast.

Right. I mean, I think the primary thing you want to take into account here for the fourth quarter were the impacts of turnarounds. It was a significant turnaround quarter that is not unusual in the fourth quarter of the year. Actually, it's not unusual in the first quarter of the year either. That significantly impacted the segment results for the basic R&M.

Mike and his team has done a fantastic job this year, this last year, of delivering on the things that he outlined last year. We've gone through some difficult times with employees, but we've really exceeded our expectations in that regard, capturing benefits. And we've, as I noted earlier, made some of the portfolio moves. Mike will give you a lot more update on this, but our Downstream business is doing well and on track to deliver the improvements in returns that he outlined. We've got a three-year plan to do that, and we're ahead of pace for the first year.

Our next question comes from Jason Gammel from Macquarie.

I wanted to ask about a couple of the capital projects that will be coming up in the Final Investment Decision. First of all, on Wheatstone, John, do you think you have enough contracted offtake already to be able to move forward with the project or are incremental offtake contracts still necessary for FID? And are you seeing any cost pressures at Gorgon that would potentially cause you to go back and look at your estimates again or even to delay the Final Investment Decision, so as not to be competing with your own project?

On the offtake, we've been really pleased with the marketing that we've been doing for both Gorgon and Wheatstone. In fact, we announced another agreement very recently. We're at the 80% and 90% level for both projects in terms of agreements that we have in place, and we certainly don't view sales agreements as an impediment to a Final Investment Decision for Wheatstone. In terms of cost pressures, we're going through the engineering work now, and we expect, based on what we're seeing, they will have a good handle on costs sufficient to make a Final Investment Decision later in the year. We're, obviously, very close to what's happening in the markets because of our position in Gorgon. Gorgon is a $37 billion project, but we've let contracts totaling about $25 billion so far. So we have a good idea what's in the marketplace. We're monitoring it well, and I don't expect that those cost pressures, which are real, will impact Final Investment Decision, since we've got a pretty good idea of where they come from and how to mitigate them.

And then with the decision now to extend the Caspian Pipeline and given that you're seeing just tremendous reservoir performance at Tengiz, when would you envision that you would be looking for sanctioning the next phase of Tengiz expansion?

A couple of comments. First, it's both reservoir and facilities performance at Tengiz that has been very good. In terms of sanctioning it, I think the first thing's first, we'll make a fee decision in 2011. And we'll give you a little more detail in March, when we come back on maybe what the timing would be. I will say this, we learned a lot from the first expansion project. The technology is now proven. It's actually a simpler project than the expansion we just completed, and I won't say it's a simple project. But it is simpler in scope, given what we've learned about injection technology during that time period. So feed very soon and then FID following.

Do you think Tengiz eventually gets to 1 million barrels a day?

I'll just say that we have another nice expansion coming, and I'll let George give you a little bit of update on that. But certainly, there's more there than the over 600,000 barrels a day that we've been producing on 100% basis recently.

Our next question comes from Mark Gilman of Benchmark Group.

John, can you give us a number for non-PSC variable royalty-related revisions implicit in the reserve numbers?

No. Mark, I'm not trying to be cagey. We just don't give out that level of information. We talked about the price effect taking about 13 points off the replacement rate, but we haven't gotten into the specifics of the PSCs.

Pat, in your comments you referenced I think on several occasions in terms of PSC sensitivity this 2,000 equivalents per day per dollar kind of number. Would you expect that to change in 2011, at all, one way or the other?

The reason we give you the numbers, Mark, relative to the previous historical period is so that you can see what the relationship has been. I don't know what prices are going to be, going forward. We tried to give you that number. It's been in that 2,000, 1,800 to 2,000 barrel per WTI dollar for quite some time. I think that's a reasonable assumption, a reasonable planning base for you going forward.

Give me an idea of any negative impact of rig contracts on U.S. Upstream results, both in the fourth quarter and full year '10?

Well, we said earlier that the operating expense on an after-tax basis was $100 million or so. But that's predominantly the rig impact. On a full P&L basis, of course, we have the loss production, really thinking something a couple of hundred million dollars or so.

So the $100 million is rig cancellation charges and things like that?

No, it's really just idled rigs, costs associated with idled rigs.

And you expensed that?

Yes.

What would be the number if there were no activity in 2011, Pat?

Well, I'm not going to go there. I'm just giving you the impact of the moratorium for us here, both from an op expense and the total P&L standpoint.

We've got three Deepwater rigs under contract. One of them is drilling an injection well in Tahiti right now. This market will depend upon the degree to which we can quickly put these rigs to work.

Our next question comes from Faisel Khan with Citigroup.

First on exploration. Can you just give us an update of how exploration went in the fourth quarter? I believe you were drilling the Lagavulin well and any other wells you were drilling in the quarter?

Yes, we don't have anything to say on the Lagavulin well, just yet but you're correct. It is drilling. We did announce a discovery in the Republic of the Congo. Our partner, our non-operating partner there, that's certainly encouraging. And then Australia, the progress has continued with additional discoveries there. We don't have any news, obviously, from the Gulf of Mexico because we weren't able to conduct any activity there.

And then just on the liftings, you've mentioned you have higher liftings in Indonesia and Kazakhstan. I take it those were -- what was the quantity of overlifts you guys had in the quarter?

Yes, in the third quarter, we were underlifted in excess of 3%. In the fourth quarter, we were underlifted just about 1%. And for the year, we were underlifted about 1%.

Our next question comes from Pavel Molchanov with Raymond James.

First regarding Australia, kind of following up on the earlier question about cost escalation, anything that is happening in terms of project delays that is labor shortages, et cetera, that is perhaps shifting timelines for either Gorgon or Wheatstone as you currently see it?

No. It hasn't. In the Australian press, you'll see things reported from time to time, and we do adjust the schedule of work. For example, right now, we've got cyclones that are going through the area. So that, obviously, impacts work. So you read about these adjustments, but we managed that in the context of an overall critical-path set of activities, and we're on that critical path. Labor is certainly a significant issue to be monitored in Australia. As it is, frankly, with all big onshore projects around the world. We've got good relationships with the unions. I think the best thing we can do to maintain those relationships with unions is to communicate well and to keep the outstanding safety record that we have, because that's certainly a priority of the union. But at this point, we haven't seen any significant shifts in activity and certainly not because of issues involving labor.

Let me turn to Poland. Given that you will now have the in-house expertise from Atlas, is that going to change your Polish shale gas program at all in terms of moving personnel over or just transferring that skill set overseas?

Well, it's a little early to tell. As I say, once we close the Atlas transaction, we'll be in a better position to talk about that. But certainly, the expertise we're picking up, well first, Chevron has expertise. We've drilled hundreds of wells in the peons-type gas wells. We've been active in the Haynesville. So we do have expertise. But certainly, with the acquisition of Atlas, that will help us. Now we expect to drill our first well later this year, actually, in Poland. So as we close that transaction, we'll assess the people that we have, and I think one advantage for the people of Atlas will be the opportunities that will be available elsewhere in the Chevron system, including Poland and overseas. So I'm hopeful that it will help us.

And where is your current Polish acreage position at? Is it still at 1.1 million, I believe.

Yes, it is.

Our final question comes from Iain Reid of Jefferies.

In Angola, there's quite a lot of excitement about the pre-salt of having some blocks were awarded recently. But as far as I'm aware, I didn't see Chevron in that group of companies. I just wondered whether you could talk about what you think about the pre-salt, and Angola, and are you going to drill that from your existing acreage?

Well, you're correct, basically, in the recent lease round. We're very prudent in what we did, and if we're unable to capture some of it because of prices, so be it. I would tell you over the last few years, we have participated in some of the lease rounds, this time we didn't capture anything. Beyond that, I probably don't have a great deal to say other than we continue to ramp up Tombua-Landana there and have had a long and very good relationship there. Our focus right now, frankly, is on Angola LNG. That project is progressing very well toward first gas. And that's been the big focus for us recently.

So you don't have any plans to drill any deeper wells in the basin, so below the tertiary to test the pre-salt?

I don't have anything for you right now in that. If we've got more to say about the pre-salt, I'll be sure that George covers that in March.

In Kazakhstan, you're a partner in Karachaganak, where there's been dispute over taxes and also issues of the state company trying to push their way into the license, are you seeing anything of the same issues in Tengiz at the moment?

Well, you're correct. There have been some concerns that have been voiced by the government, and the partners are working through that with the government. I'm confident we'll get to some resolution. At Tengiz, from time to time, we have issues that are raised, but we have rigidly adhered to the contract. We've performed very well, and we've always been able to work through any issues without a material impact. And I would say the same thing is true today. We're held up in Kazakhstan as the company that has best delivered on what the government has expected. So in my visits with the President and in our relationships there, they've been very good. Recognizing that from time-to-time, there are differences of opinion, but we've been able to work through them well. We're in a good place in Tengiz would be my comment.

So there's no issues of that nature that would stop you further expanding Tengiz?

No. We appreciate the very good questions. Thanks, Shawn. Let me just say that we appreciate your participation in the call. I'd like to thank the analysts, and I'd like to remind you that we do have our Security Analyst Meeting in March, and we look forward to seeing you there. Thank you very much.

Thank you. Ladies and gentlemen, this concludes Chevron's Fourth Quarter 2010 Earnings Conference Call. You may now disconnect.