Chevron Corporation (CVX) Q2 2010 Earnings Report, Transcript and Summary

Good morning. My name is Sean, and I will be your conference facilitator today. Welcome to Chevron's Second Quarter 2010 Earnings Conference Call. [Operator Instructions] I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington.

Thank you, Sean. Welcome to Chevron's Second Quarter Earnings Call and Webcast. On the call with me today are George Kirkland, Vice Chairman and Executive Vice President of Global Upstream and Gas; Jeanette Ourada, General Manager of Investor Relations. Our focus today is on Chevron's financial and operating results for the second quarter of 2010. We'll refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. We ask that you review the cautionary statement here on Slide 2. Slide 3 provides an overview of our financial performance. The second quarter earnings were $5.4 billion or $2.70 per diluted share. Our second quarter 2010 earnings more than tripled compared with the year-ago quarter. Second quarter 2010 earnings increased 19% compared to the first quarter of 2010, which Jeanette will discuss shortly in more detail. Return on capital employed for the trailing 12 months was about 16%. The debt ratio was 9.5% with cash balances exceeding debt balances by $2.7 billion at the end of the quarter. Jeanette will take us now through the quarterly comparisons. Jeanette?

Thanks, Pat. Turning to Slide 4. I will compare results of the second quarter 2010 with the first quarter 2010. As a reminder, our earnings release compares second quarter 2010 with the same quarter a year ago. Second quarter earnings increased about $850 million from the first quarter. Upstream earnings were $180 million lower due to unfavorable tax charges and higher OpEx, partially offset by a favorable foreign currency variance. Second quarter downstream results saw a significant improvement of nearly $780 million. Earnings benefited from stronger U.S. margins, favorable foreign currency and timing variances, as well as the absence of first quarter charges related to planned employee reductions. The other bar largely reflects a favorable swing in corporate tax items and lower corporate charges. On Slide 5, our U.S. upstream earnings for the second quarter were $66 million lower than the first quarter's results. Realizations in the second quarter were down $95 million. Natural gas realizations drove the decline, dropping 24%, slightly higher than the 20% decline in Henry Hub spot prices. U.S. crude oil realizations were essentially flat between quarters. Lower production volumes decreased earnings by $40 million between periods, primarily due to downtime and normal field declines in the Gulf of Mexico. The other bar represents a benefit of $69 million, which is comprised of a number of unrelated items including lower DD&A rates and exploration expenses. Turning to Slide 6. International upstream earnings were down $116 million compared with the first quarter. Higher realizations benefited earnings by $70 million. Liquids realizations rose 2% between quarters, in line with the increase in average Brent Spot Prices. Natural gas realizations were a slight offset, declining 5% between periods. A favorable swing in foreign currency effects benefited earnings by $210 million. First quarter results included a $100 million loss that was effectively offset by a $110 million gain in the second quarter. An unfavorable swing in tax items across multiple jurisdictions decreased earnings $220 million. Second quarter charges of about $120 million effectively offset a $100 million earnings benefit in the first quarter. OpEx increased $120 million in the second quarter, which included higher turnaround costs in Kazakhstan and Canada. The other bar reflects higher exploration expenses and DD&A rates. Slide 7 summarizes the quarterly change in Chevron's worldwide net oil-equivalent production. Production decreased 37,000 barrels per day between quarters. Price changes had a modest effect on volumes under production-sharing and variable-royalty contracts in the second quarter, about 3,000 barrels per day. Base business production decreased 47,000 barrels per day between quarters, largely due to planned turnarounds in Kazakhstan and Canada, partially offset by higher demand-driven production in Thailand. Incremental production from major capital projects increased second quarter production by 13,000 barrels per day, primarily driven by the continued ramp-up at Frade in Brazil. George will discuss our current year production outlook in a few minutes. Turning to Slide 8. U.S. downstream earnings improved $350 million in the second quarter. Indicator margins strengthened between quarters, increasing earnings by $170 million. Refining margins improved from the depressed levels of the last several quarters. Actual margin capture from advantageous crude mix and product yields increased earnings by an additional $90 million. Chemical results were $50 million higher mainly due to improved margins for olefins and aromatics. The absence of an employee severance charge recorded in the first quarter benefited earnings by $50 million. The other bar is a negative variance of $9 million. On Slide 9, international downstream earnings also improved significantly, increasing about $430 million from first quarter's results. Margins were $45 million higher with improvements in Europe partly offset by declines in Asia. A favorable swing in foreign currency effects benefited earnings by $230 million. First quarter included a $100 million loss compared to a $130 million gain in the second quarter. Timing effects represented a $155 million positive variance between quarters, reflecting favorable mark-to-market effects on derivatives tied to underlying physical positions. WTI prices dropped about $8 per barrel from the beginning to the end of the quarter. The absence of a $100 million employee severance charge recorded in the first quarter also benefited earnings. The other bar is comprised of several unrelated items, including planned maintenance impacts at our Cape Town refinery in South Africa. Slide 10 covers All Other. Second quarter net charges were $108 million compared to a net $368 million charge in the first quarter, a decline of $260 million between quarters. A favorable swing in corporate tax items resulted in a $220 million variance. Corporate charges were lower in the second quarter and included the absence of a $25 million severance charge related to workforce reductions recognized earlier in the year. We believe our quarterly guidance range of $250 million to $350 million for net charges in the All Other segment is still appropriate going forward. George is now going to provide an update on our upstream business. George?

Thank you, Jeanette. It's good to be back to discuss upstream performance and our production outlook for the remainder of the year. I'm very pleased with our progress in the first half of 2010, especially around our safety and production performance. Let's begin by looking at our second quarter competitive position on earnings margins. Please turn to Slide 12. In the first quarter, our adjusted earnings per barrel were $19.50, over $3 higher than our nearest competitor. In the second quarter, upstream margins were $18.74, another excellent quarter, reinforcing the strength of our oil-weighted portfolio and the quality of the new projects we're bringing online. Based on competitor results disclosed this week, we have sustained our competitive advantage. We led our nearest competitor by over $4 per barrel this quarter, and this is our fourth consecutive quarter in the top position on this metric. Now I'll turn to production. Please turn to Slide 13. Our first half production averaged 2.76 million barrels a day at an average WTI price of $78 per barrel. At the fourth quarter call in January, we set full year production guidance at 2.73 million barrels a day based on the 2009 actual price of $62 a barrel. Using the same price basis, our year-to-date production would be 60,000 barrels a day higher than the original guidance. Remember, a portion of our net production is sensitive to price through entitlements. At current oil prices, this is about 2,000 barrels a day for every dollar price change. Our full year production outlook at year-to-date prices of $78 per barrel is 2.75 million barrels a day, almost 2% higher than 2009 levels. At $62 per barrel, this translates to 2.78 million barrels a day or about 3% growth, significantly higher than our original guidance of 1%. The higher growth forecast is driven by stronger base business performance, our focus on reliability and system optimization, as well as increased gas sales in Thailand. Our annual base business decline is now estimated to be in the 4% to 5% range. Incremental production for major capital projects remains close to the original forecast. Most projects are performing as planned. Better performance has been seen at SGI/SGP in Kazakhstan, Frade in Brazil and Mafumeira Norte in Angola. This improved performance is offset by delays at some non-operated projects, particularly Perdido in the Deep Water Gulf of Mexico and the first expansion of the Athabasca Oil Sands Project in Canada. Now please turn to Slide 14. I would like to spend a moment to discuss the Deepwater Horizon incident in the Gulf and the follow-on impact on our operations. First, our deepest sympathies go out to the families of the 11 individuals who lost their lives and also to others along the Gulf Coast impacted by this tragedy. We are very pleased that this well has been successfully capped. The drilling moratorium has impacted our offshore Gulf of Mexico operations in several ways. We expect some lost production in 2010 due to permitting delays on the shelf and a slower ramp-up at Perdido. The full year impact is expected to be less than 10,000 barrels a day. When the moratorium was implemented, we were completing a Tahiti development well and drilling the Buckskin appraisal and Moccasin exploration wells. The Tahiti well is due to come online soon, but other development drilling activity is now on hold. Buckskin and Moccasin operations are suspended, and our other two planned deep water exploration wells are delayed, negatively impacting our 2010 exploration program. We have three deep water rigs on contract. One is currently working for BP to assist in the spill response. The other two are on stand-by, waiting for approval to resume drilling operations. Although the longer term impact of the moratorium remains unknown, we are focused on progressing our projects in the Deep Water Gulf of Mexico. The Tahiti II, Jack/St. Malo and Big Foot projects remain on track to reach FID later this year, assuming the moratorium is lifted. Chevron is a leader in safety performance, and we're very confident in our abilities to safely drill and develop our deep water projects. Our safety and environmental focus is to prevent incidents from occurring. We believe the investigations of this tragedy will show that it was preventable. We are participating in joint industry taskforces, working with the National Commission to determine the appropriate path forward on drilling safety, with particular attention on prevention, containment and spill response. The Gulf of Mexico and other deep water basins remain very important in meeting the energy demands of the U.S. and the world. A continuation of the suspension of operations in the Gulf of Mexico will reduce supply and influence energy prices. We believe the moratorium should be lifted, and we believe that deep water drilling can be done safely and reliably. Turning to Slide 15, I'd now like to discuss some of our significant achievements during the second quarter. First, a short update on Gorgon. We continue to make good progress. Site preparations are under way, dredging has begun, the construction camp is being built and we have awarded over $24 billion in contracts. As a reminder, we have signed sales and purchase agreements for approximately 90% of the equity LNG offtake from the Gorgon trains one through three. We recently signed a Heads of Agreement with KOGAS for delivery of almost 2 million tons per annum of LNG from the Wheatstone project. KOGAS will also acquire a 5% equity interest in the project. This is another successful step in early capture of market share for this project. We now have approximately 80% of LNG offtake from Wheatstone's train one and two tied to long-term agreements. Also in Australia, we have announced two deep water natural gas discoveries in the Carnarvon Basin, Clio-3 and Sappho-1, moving us closer towards our goal of additional LNG trains at Gorgon and Wheatstone. I'm very pleased with our continued exploration success in Australia. In Indonesia, we sanctioned the 13th expansion of the Duri Field, where we have 100% working interest. This latest expansion will leverage existing steam and production facilities to increase production from the field by approximately 20,000 barrels a day. We've made good progress in capturing new opportunities. In the unconventional shale gas area, we have captured 675,000 acres in Romania and almost 200,000 acres in Western Canada. We expect to begin appraisal of the Canadian acreage by the end of 2011. As a reminder, we recently added 1 million acres in Poland. In Venezuela, we have formed a consortium that will work toward developing the Carabobo 3 heavy oil project in the Orinoco belt. And in Russia, we have signed a Heads of Agreement with Rosneft, Russia's largest oil company, to pursue a deep water opportunity on the Shatsky Ridge in the Russian portion of the Black Sea. In summary, I'm very pleased with our accomplishments in the second quarter and the first half of this year. With that, I'd like to turn it back over to Pat.

Okay. Thanks, George. Turning to Slide 16, I'd like to wrap up our prepared remarks with a recap of Chevron's strategic progress through the first half of the year. Strong operational momentum continued in the second quarter and our safety performance remains at record level. The Deepwater Horizon incident in the Gulf of Mexico has heightened investor interest in operators' safety and environmental records. We're very proud of our safety culture and our industry-leading performance in this area. We publish historical statistics annually in our corporate responsibility report, which you can find on our website. Our businesses are continuing to run well. Our major refineries are operating reliably and upstream production efficiency remains at a high level, which contributed to our strong first-half production performance. We are sustaining our cost management efforts. For the first half of the year, excluding one-time employee severance charges, operating and SG&A expenses were up 5% versus the comparable period in 2009. Half was related to higher fuel and transportation costs. The remainder is in line with a 4% production increase over the same period. As George mentioned, our upstream business is growing and growing at an industry-leading level of profitability. He also highlighted several new opportunities that expand our set of portfolio options to continue to grow our resource base. In the downstream, we are executing our restructuring plan. Portfolio [ph] exits (27:54) and market reviews are under way, and specific actions are being taken to de-cost our operations. We anticipate the new organizational structure will be in place by the end of the third quarter. The same drivers expanding upstream earnings margins are contributing to our robust cash position. After paying dividends and funding our capital program, we generated about $2 billion of cash flow in the second quarter. This strong cash flow and a low net debt position, allow us to maintain our financial strength and flexibility. I'd like to close with a few words on capital intensity. It's a frequently heard question that I believe should be laid to rest. We have invested more than $60 billion in upstream in the last four years. We've brought on many major capital projects during this period that grew production 7% last year alone, and production is still growing. And we've had the highest earnings per barrel now for four consecutive quarters and the gap is large. This should be solid proof that our investments are attractive. We're expanding at the right parts of our portfolio. We are making the right choices on individual projects and we have shown that we can profitably grow. Looking forward, we're headed into another period not unlike the last four years. We're taking on world-class projects to reap the production and cash rewards when those projects come online in the middle of the decade. We are very comfortable with this profile as we have proven that disciplined capital intensity is a good thing, if the projects are the right projects and you can afford it. They are and we can. Now that concludes our prepared remarks. I will now take on your questions. So Sean, I'd ask that you open the lines for questions.

[Operator Instructions] Our first question comes from [ph] Robert Kessler (30:18) with Simmons & Company.

Firstly, just a general question for you, George, on your perceptions of the current upstream M&A market, in particular with respect to possible, more substantial additions to the Chevron portfolio. And then, secondly, with regard to your confidence in reaching FID on projects in the Gulf of Mexico later this year, notwithstanding the need for the moratorium to be lifted, I'd be curious on your thoughts on two points. Firstly, even beyond the lifting of the moratorium, it seems we need some confidence in understanding what the new sort of technical-regulatory environment will be, what's required for a development well going forward. And secondly, with respect to your thoughts on the higher cap or an unlimited cap on liabilities in the Gulf of Mexico.

M&A's going to be the standard answer. We always are looking for opportunities that are inorganic, if you will, but they've got to compete, they've got to make economic sense for us. The market's still been very hot. People, I think, are [ph] overpaying (31:36). And once again, it's back to returns. We believe in returns. So it's got to be -- return basis has got to fit with our portfolio. It's got to be a bump on our returns. On the Gulf of Mexico, the technical work, we are moving it forward as if the moratorium is going to be released, removed. We do not know all the changes on the technical requirements. We've been leading a task force that did make recommendations that would raise the industry standards on drilling wells. I will tell you, most all those standard improvements are raising the bar, if you will; we presently do in our drilling operations. Now we don't know the individual procedural changes, engagement with government that will be required. We are waiting to see that but we're drilling wells around the world. We have seen higher engagement with other governments. It does have some minor impact on the time it takes to drill a well but it is not significant. Once again, our confidence is very high at being able to drill these wells safely, just like we've drilled hundreds of other deep water wells. So we think it's going to move forward. Now with regards to the liability cap. It's an issue that we can understand, why governments would want to increase it. But at the same time, if it gets too high, it won't impact companies necessarily like a Chevron except in our decision making. But for our competitor group and the broad span of the competitors, some of them may not be able to participate. We believe competition is good. And if you set the liability cap too high, there's a lot of companies that will not be able to participate and we don't believe that's a good thing. It may be a competitive advantage but we don't believe it is a good thing for the industry, for consumers, so we don't support it.

Our next question comes from Doug Leggate with Bank of America.

I guess, the first one is kind of an upstream and a capital question. George, as it relates to your comments on the underlying decline, I seem to recall several quarters ago you talked about how in the current gas price environment, you would probably slow the base spending and that might accelerate your decline rate a little bit. It doesn't appear that that's happening. Can you give some color around what has changed there that is allowing you to hold the base a little better? And the related question is, given that you've, I guess, the capital spending for the year-to-date looks a little bit on the light side. We're getting into the second half, we're starting to look at FIDs for the longer-term projects. Can you give us an early look as to why your capital is not quite running at the rate you suggested at the strategy day and what perhaps the outlook might be for 2011. That would be great.

Okay. The decline rate, you're absolutely correct, we did I guess say that there was a potential for a higher decline rate as we reduced some of our expenditures in the base business, particularly in 2009. We also pulled back, like you said, on some of our gas investments and preferentially moved more or as much as we could towards oil. Our success on keeping that decline rate in this 4% to 5% has been very good. It really is all related to the reliability and the production efficiency of our operations. We have seen production efficiency -- which really is reliability -- of our operations come up by about 2%. So what we thought we were going to lose on decline rate has been overcome by greater efficiency, greater reliability in our base business operations. And frankly, we are extremely pleased with that. That's great for efficiency of money spent. That's getting more barrels and not spending -- base, when you get it from the base and you're not having to spend much more money for it, it is really good margin barrels. Now on the capital spend rate. In the upstream, we're very close to our typical spend profile for the year. We are almost dead on our target when you look at the last four years of history on how we would spend our money. So my expectation is, we will spend our capital. I think there is even a chance that we will be a little bit higher on spend in the upstream than what we had said initially. Not significantly, but we've added a few opportunities that we mentioned this morning that will require some monies in 2010. And that will likely push our capital spend for the year slightly above what we told you in March.

Can I [ph] risk (37:21) a follow-up for Pat. Just kind of a related but also an adjacent question. The share buyback program has been reloaded to an unlimited number it looks like, and with the amount of cash in the balance sheet I'm curious as to why no share buybacks in Q3? And if you could also address the tax rate, which looked a little light for this quarter. And I'll leave it there.

On the share repurchases, we were facing the expiration of the three-year program. And while we indicated in the press release that we're not looking to inaugurate one at this point in time, we wanted to retain the flexibility for having that option on a go-forward basis. Basically, George, I think, answered your question about why not inaugurating it now because he mentioned about having a higher spend profile, a typical higher second-half spend profile in C&E and that's really what's coloring our view right now. On the effective tax rate, I think the best way to look at this is on a year-to-date basis. And foreign exchange was over, or about half of the variance in the year-to-date 2010 versus year-to-date 2009 time period. So foreign exchange comes through. It's balance sheet translation, it's not cash effect. It is not tax-affected either. So when you have big swings in foreign exchange, you get big swings in your effective tax rate. The other activity going on there really relates to just jurisdictional changes.

Would you give us [ph] a thought (39:07) about a run rate, perhaps, for the underlying tax rate?

I think the best way to look at it is over a long period of time. We've been a little bit lower this year than we were in 2009. So maybe on average for 2010, we may be a little bit lower, but it's not an area I want to get into predicting.

Our next question comes from Evan Calio with Morgan Stanley.

My first question is on Wheatstone. With 80% of the gas under contract, I mean, are you targeting a higher percentage closer to 90% for Gorgon? Is there any sell-down interest in the project contemplated? And with the [ph] HUAs (39:56) closer to done, can you discuss other hurdles for the project here before you reach FID in 2011? And are you trending ahead of schedule? That's the way it would look to me.

There was a couple of questions there where I thought -- I wasn't sure all of them were Wheatstone, or there sounded like there was a Gorgon question, but I think when I answer it if I don't come back and redirect, [ph] I'd (40:19) be happy to get clarification. Our target on Wheatstone on gas on long-term basis sales is 90%, just like what we did in Gorgon. We believe 90% gives us the flexibility to deal with any operational issues and meet our contractual requirements. So we're 80%. At Wheatstone, we're very, very close. That gives us a lot of confidence that we can move forward. What I'm telling you then is the market, where we stand in the market, it will not be the constraint going forward on Wheatstone. So we've fulfilled predominantly our goals on getting gas sold into the long-term market. Now these are HOAs. They only become Sales and Purchase Agreements when we reach FID. I believe the project is moving forward in the FEED process, very much on schedule. We would like to accelerate it, if it's possible. We will not accelerate it, though, unless it is ready. It's back to the discipline. Being ready to execute is absolutely critical for all these big projects. A big hurdle for us is environmental permit. Just like environmental permits were needed on Gorgon, we must have those in place on Wheatstone. We've made good progress on the land tenure piece of it where the plant would be located. So overall we're very, very pleased with our progress. We're clicking off all the milestones that we need to and we're pushing to move it forward as quickly as we can. But once again, with all the discipline in being able to execute.

My second question. Production's been higher, yet I was curious if you could give us more color on the driver of $120 million incremental international OpEx? Is that cost inflation, maintenance or turnaround expense? And does that impact any kind of go-forward thoughts?

I think most of it is related to our turnarounds. We had big turnarounds at Athabasca, we had big turnarounds at the KTL units in, that's our standard, that's a lot of our facilities in Tengiz. So I think it's heavily related to that. Our second and third quarters typically are our biggest quarters on turnarounds. Quarters one and quarters four are not. That's generally related to weather. It's a better time for us typically to do our turnarounds in quarters two and three. So I think that explains most of it.

Our next question comes from Edward Westlake with Credit Suisse.

A couple of upstream questions. On the accident, you said you believed it's preventable. So you could continue drilling and the technical regulations are all within, Chevron's already included. So I guess the question is, is there anything that you're hearing out of Washington that could change your view that once the moratorium is over, that you could go back into the Gulf, [ph] I'm (43:48) thinking requirements to drill relief wells or changes to BOPs.

Once again, I hate to speculate on what the requirements could be. The recommendations made by two of the DOI, from the task force, from the industry task force on improving drilling operations, once again, we do most all of those practices already. We don't know what's going to come out from the government as a requirement. And until we know that, it's really hard to speak beyond that. Drilling and starting a second -- or starting a relief well, when you're drilling the first well, we don't support. We think it increases risk. Here, you're exposing yourself to two drilling operations at once. So we, frankly, from a risk profile and a probability basis, don't understand that concept. We don't think it makes sense. Once again, we can't and I don't think we should speculate on what's going to come out. We've made recommendations. We believe the bar should be raised for everyone in industry and we need to have assurances, and I think the government and the public should have assurances that all operations in the industry are being done safely.

And then a follow-up back to Australia. You've got, obviously, success in your own exploration efforts and you've got two large LNG projects that could be expanded. What's your thoughts in terms of accepting third-party gas because obviously the industry is discovering gas near your own facilities as well?

Well, in the case of Gorgon, we really don't think that we have any additional land availability to build more trains on Barrow Island to accept any gas beyond what the Gorgon partnership will be able to develop. We believe there can be five trains put on Barrow Island. We believe at this point, at least I believe, we have enough gas already for the fourth train. I didn't say I had all the partners on board in that but I believe that. And we still have exploration opportunities in the Gorgon partnership. On Wheatstone, I'll take you back and remind everyone that we have already brought third-party gas into that development. That's Apache and KUFPEC, and their discoveries; they will be a part of Wheatstone development. They have a 25% working interest in the plant there. So in these first two trains, we have already bought third-party gas. We see Wheatstone as a hub. It's a hub to bring in our gas and other industry gas. We've set the commercial arrangements in a way to attract third-party gas. We believe that we have enough area on the site for up to six trains. So we have a, I think, a view that we will make this a hub with our gas and others' gas, and make it attractive.

Our next question comes from Paul Sankey with Deutsche Bank.

George, you mentioned Romania and Canada on conventional gas acreage, but generally speaking, you are underweight I guess in the unconventional gas and [ph] effect (47:34) oil theme, particularly in the lower 48. Could you just talk a little bit about, whether this is sort of you dabbling or how attractive you find the overall theme relative to the rest of your portfolio?

We like unconventional gas where we can make reasonable returns. And I almost would characterize it simply as that. We've got a position in the Piceance in the United States, a position in the Haynesville in East Texas. We've drilled wells there. We know how to get the gas out of the ground efficiently. We know how to drill the wells. So we understand it very well. We would have -- these are good positions. They don't presently make development sense because the gas price and the market conditions with oversupply in the U.S. just doesn't make it attractive. Those developments, our own developments that we presently hold with -- and once again, on both of these, we don't have a royalty we have to pay in the Piceance, and these are held by production acreage in East Texas -- so what we really need is a market that needs the gas. And then we think there will be very good returns there. We don't see in the U.S. in most cases, an opportunity to pay the land rentals, the royalty rates that you see in the U.S. and make a competitive investment. That's why we're looking outside the United States to apply the same technology, to look for an organic exploration-type development opportunity that we can then, with low entry cost, develop and supply gas to market in those locations.

And Pat, if I could to you, I think you pretty clearly stated that you didn't buy back or you decided not to buy back in Q3 because you expect a step up in CapEx, wherefore causing you to have another couple of billion dollars of free cash flow in Q3. Would it be reasonable then to expect, knowing your priorities regarding AA rating and everything else, that you would be buying back shares by Q4, assuming our forecast of the excess cash flow is correct for Q3?

Paul, I'll leave you to do the forecasting and I'm not going to commit here to a fourth quarter share repurchase program. I will tell you that it will look at the whole host of things: the capital program, industry costs, what's happening in the global economic environment, what's happening to downstream margins. We'll look across the whole gamut of variables that we try to manage here. And when we see ourselves in a position where, after the dividend grows and a good, strong capital program, and keeping the balance sheet, if we see ourselves in a position where we've got surplus cash being generated for a reasonably longer term period of time, that's when we will look to reinstate a share repurchase program.

So we shouldn't characterize the cash build as a war chest, then.

No. I wouldn't characterize the cash build as anything other than a cash build.

Our next question comes from Mark Gilman with Benchmark Capital.

I had a couple questions for George, if I could, please. First, with respect to the contracts on Gorgon and the heads of agreement, George, on Wheatstone. Can you give me a rough idea what percentage of those agreements are accrued length in terms of the price structure?

My memory is, all are price-linked to crude. We've indexed everything to crude. And I'll give you a little more [ph] piece (51:43) on what we've said consistently, at very close to oil parity.

Second question relates to the U.S. liquids production number, which, at least to me, even taking into consideration the Perdido delays, looks awfully weak. Is blind fate declining or is there some other reason that we're seeing the fall-off there versus the first quarter in particular being fairly sharp?

Yes, the fall-off in the second quarter is heavily related to Hurricane Alex disruption. It impacted our Gulf of Mexico operations by about 20,000 barrels per day in the second quarter.

Barrels per day or barrel equivalents per day, George?

Barrel equivalents but it's heavily barrels, particularly anything in the deep water. The Deep Water piece is, Tahiti, Blind Faith, all of those projects, once again are predominantly oil.

Blind Faith holding plateau?

Well, Blind Faith is producing. It is coming down. It is coming down as expected. It's in line with what we planned and what we forecasted.

Just one more, George. Duri. Believe it or not, I can recall when the 12-phase steam flood was the target. You're now sanctioning a 13th phase. Is there something new there that you've identified and is there the potential for a whole other set of phases alongst the lines of the program that was in place some years ago?

I would characterize this is more just a further extension to the north end of the field. And we probably will see maybe one, at least, one more area extension. We're looking at another area that we can develop. You always see these big fields get a little bit bigger and you drill some more wells and you find the reservoir looks good, at least good enough to take the next step and do the steam operation. That's what's happening here. Area 12 has been very successful. So it gives us a lot of confidence in stepping out to Area 13. I hope I come back in another year or two and talk about 14.

Our next question comes from Paul Cheng with Barclays Capital.

George, if we're looking at over the last several years, I think, it seems like there's a change in view on the oil sands within Chevron. I think at one point you guys are pretty excited, snap up a lot of land position and then that has been relatively quiet since then, with the exception of the ESOP development, the upgrade, the expansion. Can you share with us then what's your view on the oil sand dunes? Do you think that, stacking up, they are not looking that great comparing to your rest of your portfolio so you are not too interested in dramatically expanding your exposure, or that this an area that you guys looking at?

Paul, I think actually our view on oil sands has been pretty consistent. We did, through some crown-lease acquisitions, obtain some acreage up there and assessed it for in situ steam operations. But we've done that work and our view of the oil sands all along has been that it's kind of the part of the portfolio or the industry portfolio that sets almost the marginal price. It is high cost. We have other opportunities that supersede it. We do expect that we'll be back into what we obtained down the road, it's at Ells River. We've done the assessment and we fit it into the queue. It just sits at the back of the queue in recognition of other opportunities in front of it. And I would characterize all the oil sands projects that way. They are a little bit narrower in margin and they need higher prices to make them economic.

George, since earlier, you're talking about Duri, the steam fronting. Can you give us an update, how's the pilot steam [indiscernible] (56:33) your neutral zone?

Yes, in the partition zone between Saudi Arabia and Kuwait, we've had the steam flood pilot there in operation for about a year now. We are seeing some temperature climb in the reservoirs. We can see that in our observation wells. It's encouraging. It's early. We expect within the next 18 months to have a pretty good read on the reservoir response. So I think we're about 18 months away from really telling you something that's really meaningful. I'll just end and say, we're encouraged. We're encouraged by what we're seeing on temperature response. And of course, we're encouraged because there's 12-plus billion barrels of oil in place that we're looking at there.

Two final questions. One, there's again having some rumor coming out talking about Kazakhstan government going to snap Tengiz with the export tax. This is probably the ten times in the last six or seven years. I'm wondering is there any official communication between you guys and Kazakhstan Government on that? The last question is that, if we look at in the Gulf of Mexico, Jack/St. Malo, the Big Foot look like I think those probably target start-up maybe some time in 2014, 2015. If the memorandum of the Duri [indiscernible] (57:59) extend beyond November, how long then, the Duri [indiscernible] (58:06) extend, up to what day you would start to see there's a risk on those start-up days?

First, let me talk about Tengiz and statements out there. And I'm going to cover a couple items. You've seen a media statement about the mining allotment. The mining allotment for us is very clear in our contract. We have all rights of all subsalt. Everything below the salt in the Tengiz geographical area. We have rights to that, we have contractual rights. It's very straightforward in our contract. The media statement, the media words you've seen out there on the export customs duty, there is reports of that. I will tell you, we've had some communication with the government on that point. Once again, our contract, I think, is very straightforward on custom duties like that. They would be offsetable. And I'll just leave that piece of it at that point, at this point. I had two other things related to Tengiz. First off, operationally, Tengiz is running extremely well. We're very, very happy with SGI/SG performance and the existing facilities. And then maybe one last point, our long-term relationship with the government of Kazakhstan, with our partners there, has been very good. We've been there 18 years. We've had disagreements that we've always worked through very well. I think it translates to our good performance. As a group, we've done well. That doesn't mean we haven't had times where we had discussions and had to work through things. And I believe we will see the same thing here. Our relationships will carry us. Our performance for these 18 years, I think really underscores that we can work there and that we can work together very well with the government and our partners.

George, how about in the Gulf of Mexico?

Sorry. When you give me these multiple questions, it sometimes – Gulf of Mexico, I would tell you, if the moratorium is still held, is still on us post-November or -December, it will start impacting the schedule. We cannot move forward on these projects without knowing clearly what the expectations are. So at some point, it's going to start pushing the startup date of these projects. We think we're in pretty good shape up until November. We've done FEED work. We've positioned ourselves with bids on contracts. So we've done all the engineering and preparatory work to be able to move forward into execution. If this keeps sliding out in the unknowns, it will delay the projects. And frankly, for not only us, but for government and others, it will impact revenue streams, crude availability. These are all very large projects. Remember, Jack/St. Malo is a roughly 120,000 to 150,000 barrel a day oil development. So very significant projects.

Our next question comes from Faisel Khan with Citigroup.

Can you give us a little bit of an update on exploration? Any major discoveries in the second quarter, or significant ones. And what your plans are for the third quarter here and the fourth quarter?

Okay, I tried to give a little bit of that in my prepared statement so I'll try to take that and then maybe expand a little bit. We are, and I'll start off with the impacts. Our program in the Deep Water Gulf of Mexico has been impacted significantly. We were on the Buckskin appraisal well and that was a very significant well for us. We wanted that one drilled, where we could accelerate potential development of that prospect. We really think it's that good, that that appraisal well would define an awful lot if it would go forward. We've had three other deep water wells in the Gulf of Mexico that we wanted to drill. We were actually on the Moccasin well when the suspension of operations occurred. We had two other deep water Gulf of Mexico wells, very large prospects, that have now been delayed. So from that perspective, a big part of our program in exploration was these impact, greater-than-100-million-barrel resource-size prospects. Those have been eliminated from the program this year. So that's worrying, that's delaying, but we don't have any choice. That's where we are on that. Elsewhere in the world, our other deep water drilling is moving forward and other exploration wells around the world are moving forward. We're drilling the [ph] Lona (1:03:43) well up in the East Coast of Canada. That well spudded shortly after the moratorium and after the spill in the Gulf of Mexico started. So that well is getting closer to our [ph] objective (1:03:57) section. We've made good progress there. I hope by the fourth quarter, third quarter call, we will be able to tell you more there. Successes have been strong in Australia. We're drilling a large number of wells in that focus area. We continue to have great success there. We're focused on Australia in the Carnarvon Basin because not only are the discoveries significant, if we have those discoveries then they also move quickly to expansions of the LNG projects that we're doing there. So we have strong focus there. We're putting a lot of money into Australia to try to get to the next step on the expansions of those projects. We've got a well that we'll be drilling west of Shetlands in the second half. Another significant well, we call it [indiscernible] (1:04:53). So we've got several other high-impact wells. But bottom line, the scale of our exploration program has been significantly impacted this year because of the moratorium in the Gulf of Mexico.

And then just one question on the downstream portion. Can you give me an idea of what the absolute timing effect was in the quarter in the International downstream business? I know you gave us the quarter-over-quarter variance, I was wondering if we could get the absolute number in terms of the timing impact.

It's about $100 million.

Our next question comes from Pavel Molchanov with Raymond James.

Let me just press you a little on Kazakhstan. I appreciate the point you're making about sort of the nature of the language of the contract but of course we know from a lot of places, sanctity of contract is not always respected. So my question is, with Tengiz and Karachaganak, both under investigation this year within just a few months, is it your sense that Kazakhstan might be becoming just a more hostile place for Western operators to do business in?

I hate to read into that far. We've had disagreements in the past. We've been there, in the case of TCO, 18 years. We've worked through differences. We have had a very positive relationship with the government. So I am very confident that we will move through this issue. I do look at Karachaganak -- though we're in both of those ventures, I look at them somewhat differently -- I do believe that the claims in the case of Karachaganak, some of the claims that the government's making are things that we have got to deal with in the sense of overexpenditures on projects, as an example. And we are in discussions and negotiations, trying to get to a rational solution there that is appropriate, that recognizes what the issues are from the government side and the issues from the partnership side. So I do, from my perspective, see a difference. I see contractual differences and I see issue differences.

Let me turn quickly to your European shale gas presence. I guess you have about 1 million acres in the Silurian and Poland and then of course you just added Romania. What do you need to see to bring that to full-scale commercialization and, realistically, when might be the timetable for doing that?

Well, the process is going to be a standard process that we use in our exploration. We will go in and shoot seismic. We'll use this to kind of define the areas of interest better. Then we will go in and drill wells. We'll understand the shale. We will frac the shale. We will actually do a fracture test there and we'll put the gas on production where we can understand rates. So it's normal process. The first work with regards to seismic, we should be doing -- we will be doing seismic in Poland this year and next year. And I expect to be in Poland some time next year also to drilling the first wells. And then, after we drill a few wells, I think we'll have a better idea of the follow-on timing.

Our next question comes from Jacques Rousseau with RBC Capital.

Just one question from your presentation. On Page 14, where you talked about the deep water rigs on standby. Do you still have to pay the full rate for them or was there some renegotiation of the contracts there?

Yes, largely, I think it's best to assume that it's largely the full rate. There's a little bit of a discount but it's not a material discount.

Our final question comes from John Harland with SG Americas Securities.

Three quick ones. How much are you spending overall, George, on unconventional resource activities this year?

Right off-hand, I couldn't tell you. It's a combination of lease acquisition. And I probably, frankly, would be very reluctant to tell you exactly that, because you could figure out acquisition cost, and everyone else could figure out acquisition cost. So maybe that's something I can discuss by the time we get there in March, at our March meeting, and we'll portray it in a way that we're not disclosing information that I don't want to, but also we'll kind of give you an idea of how big a bag of money it takes to do what we want to do.

Next one. In Canada, are you in the Horn River? Is that the shale gas?

We're not disclosing the location at this point in time.

Last one for me. Obviously, with the moratorium in the U.S., your exploration expenses have been running a little bit low versus history. Will the second quarter rate kind of continue going forward?

I wish I knew the outcome of wells that I would only drill if we could.

But I'm just thinking in terms of the [ph] biz (1:10:54) risk profile.

The Australia side, the wells we drill in Australia, we continue to have better performance on the risk side than what we come in prior to spudding the well, but it is so hard to forecast that.

George, I was just asking U.S., I wasn't asking globally.

U.S., it's going to make a huge impact. I'm sorry I misunderstood your question. The U.S., we're just not going to have any wells drilled, it looks like, this year.

Okay. I think that we'll close off here now. First of all, let me just say, I appreciate very much your interest in the company. I appreciate everyone's participation on the call today. And I especially want to thank the analysts on behalf of all the participants for their questions during this morning's session. Thanks very much. Goodbye for now.

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