Chevron Corporation (CVX) Q2 2011 Earnings Call Transcript

Good morning. My name is Sean, and I will be your conference facilitator today. Welcome to Chevron's Second Quarter 2011 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.

Okay. Thank you, Sean. Welcome to Chevron's second quarter earnings conference call and webcast. On the call with me today are George Kirkland, Vice Chairman and Executive Vice President of Upstream and Gas; and Jeanette Ourada, General Manager, Investor Relations. Our focus today is on Chevron's financial and operating results for the second quarter of 2011. 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 shown on Slide 2. Slide 3 provides an overview of our financial performance. The company's second quarter earnings were $7.7 billion or $3.85 per diluted share. Comparing the second quarter 2011 to the same quarter a year earlier, our earnings were up 43%. Upstream benefited from higher crude oil prices, and Downstream benefited from improved margins. Return on capital employed for the trailing 12 months was over 19%. Our debt ratio at the end of June was 9.1%. In the second quarter, we had share repurchases of $1 billion. Effective for the third quarter and reflecting the strength in crude prices and of our current near-term outlook, we are increasing the upper end of our target range on share repurchases to $2 billion. In the third quarter, we expect share repurchases of $1.25 billion. Turning to Slide 4. Cash generated from operations was nearly $11 billion during the second quarter. This is a new record for the company, topping last quarter's performance. Year-to-date, we have used this strong cash flow in a manner completely consistent with our established financial priorities. We raised the dividend in the second quarter by 8%. We've funded a strong capital program and made some modest acquisitions. Both the organic and the inorganic components of these outlays are poised to earn attractive returns and drive future growth for the company. We've also continued to strengthen our balance sheet, and we've returned surplus cash to our shareholders in the form of share buybacks. At quarter end, our cash balances totaled nearly $18 billion. This puts us in a net cash position of $6.5 billion. Jeanette will now take us through the quarterly comparisons.

Thanks, Pat. Turning to Slide 5. I'll compare results of the second quarter 2011 with the first quarter 2011. As a reminder, our earnings release compares second quarter 2011 with the same quarter a year ago. Second quarter earnings were $7.7 billion, $1.5 billion higher than the first quarter. Starting on the left side of the chart, Upstream earnings were up $894 million driven by higher crude oil realizations. Downstream results increased $422 million between quarters, benefiting from improved margins. The variance in the other bar reflects a favorable swing in corporate tax items and lower corporate charges. On Slide 6, our U.S. Upstream earnings for the second quarter were $501 million higher than the first quarter's results. Combined crude oil and natural gas realizations benefited earnings by $420 million. U.S. crude realizations increased 17% between consecutive quarters, well above the 8% increase in the average spot price of West Texas Intermediate. As a reminder, our U.S. crude realizations are tied primarily to Mars, Louisiana Light Sweet and San Joaquin Valley heavy crudes, all of which traded at premiums to WTI during the second quarter. Natural gas realizations also improved, increasing 8% between quarters, slightly higher than the 5% increase in the average Henry Hub bid week. Higher operating expenses decreased earnings by $55 million between periods, reflecting higher costs related to maintenance activities across multiple assets, including more workovers. The higher expenses also reflect a full quarter of operations for our new Marcellus assets. The other bar is comprised of a number of unrelated items, including gains on several small asset sales and higher volumes due to an additional day between quarters. Turning to Slide 7. International Upstream earnings were up $393 million compared with the first quarter. Higher oil and natural gas realizations benefited earnings by $875 million. Average liquids realizations increased 12%, in line with the increase in average Brent Spot Prices. Natural gas realizations contributed $70 million of the variance, improving 9% between quarters. This improvement was driven by price increases in our primary Asian gas markets, which have crude-linked pricing components. Higher operating expense decreased earnings $205 million. The increase was spread across multiple geographic areas and included higher environmental remediation expense and higher maintenance and fuel costs. You'll recall that last year on our third quarter call, we highlighted our expectation of a 2011 full year increase in reported operating expense of approximately $1 billion due to a new Indonesian agreement where we sell oil and purchase natural gas. Previously, we handled this through a volume exchange. There is no bottom line earnings impact and no impact on production. Year-to-date, our reported operating expense number is up $1.3 billion. Of that, $900 million is from the new Indonesian agreement. At current year-to-date prices, we would expect the full year impact to be approximately $1.8 billion. Moving to the next bar. Higher exploration expense reduced earnings by $140 million, primarily due to a well write-off in the U.K. and higher G&G cost associated with increased exploration activity. The other bar reflects a number of items, including unfavorable tax effects and higher DD&A, partially offset by a favorable swing in foreign exchange and higher listings. The second quarter had a foreign exchange gain of about $30 million compared to a loss of about $115 million in the first quarter. These foreign exchange effects have minimal impact on cash. They are primarily balance sheet translation effects. Moving to Slide 8, summarizes the quarterly change in Chevron's worldwide net oil-equivalent production. Production decreased 66,000 barrels per day between quarters. Higher prices reduced volumes under production sharing and variable royalty contracts during the second quarter, decreasing production about 8,000 barrels per day. As a reminder, last quarter, we began using Brent to calculate a price effect rate as it is more closely tied to our international realizations. Average Brent Spot Prices increased about $12 per barrel between quarters, which resulted in about a 700 barrel per day volume reduction for each dollar increase in Brent. Recall that over a range of prices, this rate is not linear. As prices rise, the production impact per dollar change in Brent decreases. Moving to the next bar. Base business production decreased 66,000 barrels per day, largely driven by maintenance activity in Kazakhstan, Thailand and the Gulf of Mexico and lower cost recovery in Trinidad. This bar also reflects a positive impact from a full quarter of Marcellus production and absence of first quarter's weather impacts. Incremental production for major capital projects benefited second quarter production by 8,000 barrels per day, primarily driven by less downtime in Canada and continued ramp ups at Perdido in the Gulf of Mexico and Tombua-Landana in Angola. George will discuss our current year production outlook in a few minutes. Turning to Slide 9. U.S. Downstream earnings improved $122 million in the second quarter. Indicator margins strengthened between quarters, increasing earnings by $215 million. Refining and marketing margins for both the Gulf Coast and West Coast improved relative to last quarter, benefiting from higher seasonal demand for gasoline. Refined product margins also showed some strength early in the quarter as supplies in some areas were affected by refinery maintenance. However, both these factors lessened and margins generally slipped as the quarter progressed. Operating expenses reduced earnings by $35 million, driven mainly by higher third-party credit card fees and transportation costs. The other bar consists of several unrelated items, including lower volumes, partly offset by improved chemicals and trading results. On Slide 10, international Downstream earnings were also higher this quarter, increasing $300 million from first quarter's results. Refining and marketing margins rose in all key regions, benefiting earnings by $165 million. Timing effects represented a $155 million positive earnings variance between quarters. First quarter had a negative $195 million impact with a smaller impact of negative $40 million in the second quarter. The primary driver was favorable mark-to-market effects on derivatives tied to underlying physical positions. Negative foreign currency effects impacted earnings by $55 million. Second quarter's foreign exchange loss was about $95 million compared to the first quarter loss of $40 million. The other bar includes a number of unrelated items, including improved trading and chemical results partly offset by lower volumes. Slide 11 covers all other. Second quarter net charges were $183 million compared to a net $388 million charge in the first quarter, a decrease of $205 million between periods. A favorable swing in corporate tax items resulted in a $151 million benefit to earnings. Corporate charges were $54 million lower in the second quarter. Year-to-date, corporate charges were $571 million. 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 operations. 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'd like to begin by looking at our second quarter competitive position on earnings markets. Please turn to Slide 13. In the second quarter, Upstream margins were approximately $29 per barrel, another excellent quarter reinforcing the strength of our oil-weighted portfolio and the high quality of our assets. Based on competitor results disclosed this week, we continue to lead our peers in this key metric. In the second quarter, we are nearly $8 per barrel ahead of our nearest competitor and over $10 per barrel higher than the peer group average. In addition, we have now held the top position for 8 consecutive quarters. As you would expect, I'm very pleased with our leading position and our ability to sustain this performance over the past 2 years. While we are discussing margins, I'd like to make a brief comment on operating expense. Excluding fuel, our year-to-date OpEx is very consistent with our recent historical performance. This is a positive indicator for maintaining our peer-leading margins. Through the first half of the year, our return on capital employed was 32%. We've been making smart investment decisions for a long period of time, and we have now achieved the leading position in our peer group. We continue to deliver superior financial performance and to lead our competition on key operational and financial metrics. Now I'll turn to production. Please turn to Slide 14. The first half production averaged 2.73 million barrels a day, at the Brent price of $111 per barrel. Based on the year-to-date results and a Brent price of $111 per barrel, our revised full year production outlook is 2.73 million barrels per day. Adjusted to a $79 per barrel, this equates to 2.76 million barrels per day, a reduction from our original outlook of 30,000 barrels per day. This revised outlook is a result of 2 primary drivers: first, a recent incident in Thailand caused a key third-party gas pipeline to be shut down; and second, a slower-than-planned ramp up of the Perdido project in the Deepwater Gulf of Mexico. The full year production impact of these 2 items is about 30,000 barrels per day, and they are approximately split between the 2. Outside these items, our major capital projects in total are performing as planned. Agbami in Nigeria, SGI/SGP in Kazakhstan and Frade in Brazil continue to deliver excellent results. Our base business performance has continued to be strong, offsetting the impacts of weather challenges earlier in the year. We have strong momentum entering the second half of the year, and we remain well positioned to deliver long-term growth. Now turning to Slide 15. We first showed you this slide last year. Through 2014, we forecast production to grow by approximately 1% per year. And starting in 2014, as our Australia LNG investments come on line and begin to ramp up toward full capacity, this growth rate is expected to increase to between 4% and 5%. Our long-term outlook remains unchanged. With the strength and scale of these projects and the depth of our portfolio, we expect our production to grow to 3.3 million barrels per day by 2017. Our growth projects are on track. We're advancing the queue. We're reaching critical milestones and are well-placed to deliver consistent growth and performance over the long term. Now let's review our 2011 exploration plans on Slide 16. We have an active year of exploration. We plan to invest over $2 billion, which includes the drilling of about 60 wells. We've returned to work in the Gulf of Mexico. We currently have 3 rigs drilling in the Deepwater, an appraisal well at Buckskin, an exploration well at Moccasin and a development well on the Tahiti 2 project. There is no doubt this past year has been a challenge for the Gulf of Mexico. I'm pleased with the recent progress we've made, which is a testament to the hard work of many people to get both Chevron and the industry back to work. In addition to our Deepwater activity, we're also drilling ahead at Bear's Hump. This is a key test of the ultra-deep Wilcox gas play on the Gulf of Mexico shelf. This well is also noteworthy, as we are drilling it from an onshore location. We think there's still a lot of potential on the Gulf, and it's not all located in the Deepwater. Chevron is well positioned in the lower tertiary play, both in the Deepwater and on the shelf. In Australia, we have 2 more exploration wells planned this year. One of them is an offset to the Acme discovery we announced last year. We've also been active in acquiring additional acreage, picking up 2 new leases near Barrow Island. The Carnarvon Basin is a key focus area for Chevron, with 10 discoveries over the last 18 months. We have an aggressive exploration program plan to underpin future expansions at Gorgon and Wheatstone. In Brazil, we plan to drill a well later this year in the free salt section beneath our Frade Field. If successful, we'll be in a great position to take advantage of our existing production facilities. We also have some exciting prospects in Liberia, China, Poland and Canada that we've discussed before. We plan to start drilling in all of these areas later this year. Next, on Slide 17, I'll highlight some of our recent activities in the Marcellus Shale. In February of this year, we closed on the acquisition of Atlas Energy and are currently working to complete the integration of these assets into our North America business. In May, we announced the acquisition of assets from Chief Oil and Gas and Tug Hill. Through these transactions, we added another 228,000 net acres of high-quality Marcellus Shale to our existing footprint. Largely focused in Southwestern Pennsylvania, the acreage includes over 30,000 acres of rich gas Marcellus in Marshall County, West Virginia. This expansion of our shale gas portfolio gives us additional high-quality resources, as well as strong synergies with existing operations. The acquired assets currently include 22 wells that are on production and an additional 34 wells waiting on completion or pipeline hookup. Combined with Atlas, this acreage is estimated to hold 14 trillion cubic feet of natural gas resources and is aligned with our strategy to pursue opportunities with long-term organic growth potential. Next, let's review progress in other key projects on the next slide. Expansion in the Caspian Pipeline has begun. This project will increase capacity to 1.4 million barrels per day from a current level of 730,000 barrels per day. It is a critical step forward in enabling a further expansion of our Tengiz Field in Kazakhstan. The project will be implemented in 3 phases with capacity increasing progressively from the period of 2012 to 2015. At Gorgon, we continue to make good progress on our critical path items, and they remain on track. We've begun horizontal directional drilling for pipeline installation, and we also started development drilling operations. Gorgon is presently 25% complete. At Wheatstone, we received additional environmental approvals and are selectively appealing certain conditions. In addition, we announced earlier this week that we have executed LNG sales and purchase agreements with Tokyo Electric for delivery of up to 3.1 million tons per annum of offtake. This is a significant milestone as we work toward a final investment decision in the second half of 2011. In the Deepwater Gulf of Mexico, we're making progress at Jack/St. Malo, where we've cut first steel on the hull and the top sides. And at Angola LNG, we're beginning to commission the utility systems and plan to start up subsequent process units throughout the rest of 2011. We're making good progress here and expect first production early next year. In addition, we've acquired more than 1 million acres of shale gas leasehold in Bulgaria. This continues to grow our position in eastern Europe. Around the world, we have now acquired nearly 5 million net acres of shale gas assets since late 2010. In summary, we've had a great quarter and a great first half of the year and are on track to deliver long-term growth. With that, I'd like now to turn it back to Pat.

Okay. Thank you, George. Turning now to Slide 19. I'd like to close out our prepared remarks with some highlights of Chevron's strategic progress during the quarter. George just gave you an update on recent progress in our Upstream business. We are back to drilling in the Gulf of Mexico, and we continue to execute our major capital projects and to add new resource opportunities to our portfolio. In Downstream, we received government approval to proceed with the sale of our refining and marketing assets in Ireland and the U.K., including the Pembroke Refinery. We expect to close that sale next week. We are on track and progressing well with our Downstream restructuring plan. During the quarter, we completed several small asset sales in 3 Central American countries, as well as in China and North America. And finally, I'd like to make a few comments about the current discussions in Washington. Chevron is proud to be a healthy American company. We believe healthy companies are the cure for a sick economy. In the U.S., Chevron directly employs nearly 25,000 people with good jobs and good salaries. Indirectly, we support another 150,000 jobs. We plan to invest over $7 billion in the U.S. this year to expand energy supplies, which creates jobs and generates revenue for federal, state and local treasuries. We're proud to be part of an industry that is indispensable to economic growth and competitiveness. We want the opportunity to compete on a level playing field, both here at home and around the globe. And we look forward to working constructively under stable, predictable fiscal and regulatory policies to build a shared prosperity for America and for our shareholders. So that concludes our prepared remarks. We now welcome your questions. And Sean, I'd ask that you open the lineup. Thank you.

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

Maybe a first one on CapEx. $7.8 billion I guess includes the Marcellus acquisitions. Can you talk about maybe where you see underlying CapEx for the year against your plans and acquisition CapEx as well?

It's a good question. You noted exactly correctly that the uptick we had in the second quarter did relate to some coring up of our Marcellus properties. That wasn't a planned item, but we saw the opportunity and took advantage of it. We don't anticipate being substantially different than where we set as a target $26 billion. We're halfway through the year. We're about 52% spent, and that looks to be in the reasonable range.

And then maybe a question for George. There've been some high-profile cost at runs in Australia. We all know that. You're taking a modular approach to Gorgon, and I think you used the same modular approach on your SGI/SGP successful project in Kazakhstan. I mean, is that modular approach why you think Chevron is going to deliver Gorgon on budget where others have failed? And perhaps when do you think you'll be able to, with confidence, say that you're going to hit that project on budget?

Ed, it is a great question. First, we did not use a modular approach in Tengiz on SGI/SGP. We are moving to a more modular approach for the future growth project in the next Tengiz expansion, and it's related to just what we've seen in Gorgon and what we see to be happening in Wheatstone. It's a wise thing to move ours and use ours in multiple places and the good -- only where you can do that is go to modules. So we are planning modules, significantly large modules on Gorgon. We will be using modular construction to, I think, a little bit lesser extent on Wheatstone but we'll be still driving towards modules there. And future growth will definitely move to modules as best we can in recognition of transportation infrastructure. But great question.

And the second half of the question was really around -- with this modular approach at some point you'll see how productive the Australian workers are, in terms of being able to put these together, and you'll have some idea of where Gorgon CapEx will come in. When do you think that point will be reached?

Well, we've -- so far in the case of Gorgon about -- have about $25 billion in contracts in hand. The ones that are related to outside of Australia, we have a very good handle on them. We think that in itself mitigates the total cost. I don't expect to really have a good feel for productivity in Australia for at least another 12 months. I think at that point in time we'll have a good handle on the productivity situation. We're trying to put, of course, everything in place to guarantee good productivity on Barrow Island. We're doing really quality housing, providing great opportunity for good food. Doing all those things to make sure we have a good workforce that on-site and minimize issues for them, both from a safety, like I say, and a living basis.

Our next question comes from Paul Sankey with Deutsche Bank.

George, on that trip we were chatting about California, and you said you'd go back to your people and ask them for, I think, it's the third or fourth time if you're missing something there. Can you update me on your latest thoughts about California developments, their potential there and so on?

Paul, we have went back. We're always looking at opportunities, particularly around where we have a big position. For those on the phone, we have about 250,000 acres in the southern California area of San Joaquin. We do produce from Monterey in southern California. We produce about 45,000 barrels a day in the Monterey. We are still doing some work, Paul, in that area. We have worked some of it in the upper part of the Monterey in the diatomite, we hold a lot of acreage in that, and we've seen success there. We've seen that in the Lost Hills. We are looking at some of the deeper Monterey, and we'll probably have a test of that in one of the areas we presently hold. At this point in time, we have not changed our overall view of the Monterey relative to our other opportunities in the world.

Which is that it's relatively less interesting than some of the other developments you can see, obviously.

We don't see it yet competing. We're going to do additional work there. We, typically, in all our areas where we have long-standing production, we're always looking for ways to increase the productivity of that resource, increase the recovery. And we see some cases of oil in plays that we're going to test. Now, it's once again, it's going to compete down the road for capital against our other opportunities around the world.

Understood, George. And can you just be specific on why it's less attractive than other opportunities and also mention if there's any permitting issues for you there?

I'll answer the second one first. We have not gone far enough to have the permitting issues, so we don't have any permitting issues. At this point, we just don't see the volumetric production that delivers enough barrels at a rate to make it economically competitive. But we've got more work to do. We're going to do a test that will tell us a little bit more about one of these lower formation areas in the Monterey. So more to come on that. I'm sure we'll have some feedback on that, additional feedback, even in the March time period of next year at our analyst meeting.

Interesting. And then just a follow-up to finish off on the U.S. You've obviously highlighted the expansion in the Marcellus very briefly. Is this any surprise around what you paid? Secondly, if you intend to continue adding acreage, you've highlighted in the past that you are relatively underweight U.S. gas as an advantage. Are you changing that view? And thirdly, if you could briefly comment on whether or not you're interested in unconventional oil in other parts of the U.S. such as the Bakken and the Eagle Ford, and I'll leave it there.

A lot of good questions. I'm going to ask Jeanette to help me or Pat if I don't answer them all. And so I may get a little bit of prompting there. We're trying to put together in the Marcellus a nice-sized portfolio, and we've done a couple of steps on that. I think we're very close to putting together what we want in the Marcellus. There will be additional additions, small additions there where it makes sense synergistically between one acreage we hold in these two and is there something in between. So we'll do that, but I think we have pretty well put together our Marcellus position. My goal is to be able to really lay out what all we have done in the Marcellus and give everyone a really good update in March next year. I think by that period of time, we will have all the pieces pretty well put into place. We'll have our integration well in hand, both integrating Atlas and the Chief piece. So I think at that point, we really will be able to give everyone a full overview of what we see, where we stand, how it all fits together. But I really don't feel comfortable in doing that until probably March. March should be the right time for us.

Understood. Is there a price on the incremental 220s then?

At this point in time, I'm not going to share that. What we will do -- what I am committed to do is we'll provide you a lot more price information when we bring all the pieces together.

And the other question is unconventional.

Unconventional. From a technical point of view, I do like the -- and I've always said I like what we call light shale oil. We like it. I will tell you at this point in time we've seen the pricing of the acreage to be well, frankly, just to be high and impacts the economic viability of buying it. We have done lots of technical work looking for other opportunities around the world that are similar. We're always trying to take knowledge gained in one cloaked location and find similar opportunities around the world. I really don't have any I want to point to at this point. But we are doing work on there. And, Paul, like everything else, it always gets back. We don't just want barrels or MCFs. We want those barrels that deliver strong earnings, strong returns. And if it's inorganic and it's producing, we find it very difficult in most cases to go ante up that money. Our strategy continues to be looking for early entry, looking for exploration opportunities. We think the value, the major value we create is getting it early, using our expertise and from a geotechnical side, from the reservoir engineering side and the project side to create value and then, of course, operate it well. We think that's the way we really create the value for the shareholder.

So you're telling me it's very unlikely you'll make a major acquisition.

That's correct.

Our next question comes from Evan Calio with Morgan Stanley.

I have a few questions. One of the bigger-look question. I know relative to peers, Chevron has a significant investment for future production growth that does not yet contribute to your earnings as would be expected. But can you share with me maybe the amount of your current employed that is not yet generating income or impacting the numerator in your ROCE calculation?

I'd say, I mean a good place to be would be somewhere between 25% and 30% would be a good benchmark for you at this point in time.

Okay. And that's clearly, high over time, if you had a time sequence, that's really a higher percentage. Is that fair?

Certainly, as we move into the 30% range it is. But I would say, typically, if I look over the last 5 to 7 years or so, that 25% to 30% -- low 30% range is typically the bandwidth that we have operated within.

Okay. And a second question for George and maybe more pointed than Paul's. I mean, clearly, excitement's been building on the Utica shale opportunity. And then something that's a bit of a focus this morning with Chesapeake's release and conference call. I know and I believe Chevron has 600,000 acres that you disclosed that has Utica oil shale exposure. But you didn't call that out in Slide 17. Maybe you could discuss how you're thinking about activity there and play potential into 2012?

Okay. Well, let me first say we believe it's a little bit too soon to conclude on the potential of the Utica. We've got a good acreage position in the Utica from the Atlas acquisition. We're going to do what we do everywhere in the world. We're going to evaluate that. And the only the way we can evaluate it is we're going to have to drill some wells and test performance. So it's something for the future, but it's, like you say, too early at this point in time to, I think, hype it.

But it was -- is it a partial driver in your Atlas acquisition, which is largely perceived as a Marcellus gas acquisition?

It was not a major driver in that. It was too unproven at that time to establish a lot of the value.

Our next question comes from Doug Leggate, Bank of America Merrill Lynch.

George, if I may take advantage of you being on the phone with a couple of questions, and I have a follow-up for Pat very quickly. Can you give us an update just generally as to how you see the latest permitting situation in the Gulf of Mexico. And just bolting on to maybe a general update as to when you would expect to really be able to ramp up your activity there. That's my first. I've got a couple of follow-ups, if I may.

Okay. I'll try to give you a little bit more than we gave in the comments. To start off, all 3 of our Deepwater rigs are currently working. We're on Moccasin, which is a nice exploration well, and we're on in Buckskin. We're on Tahiti. Tahiti we are about to get into the development drilling stage there. We've drilled a couple of injection wells, all of which was needed for our second phase development of Tahiti. On the permits themselves, so we've got permits for those, for drilling at those locations. Near-term drilling program will require approval for us of about 10 development and exploration plans and 15 drilling permits. So that's what we're in the process of pursuing. We have received the permit for Coronado, which is our next exploration well. And we have also received an approved revised exploration plan for Oceanographer, as well as for our initial development drilling operations at Jack/St. Malo. And we're continuing to progress approvals for Big Foot development drilling. We've got a lot of applications for permit to drill have been submitted, so at this point in time we seem to be able to move things in there through the permit process to allow us to progress our projects and our exploration plans.

When do you expect [indiscernible] ?

In recognition of that, I'll even give you a little -- we have 2 additional Deepwater rigs expected to arrive later this year. The Deepwater Discovery India and the Pacific Santa Ana. And these 2 rigs really are focused on drilling initial development wells for our major capital projects at Jack/St. Malo and Big Foot. And that will allow us to really start. Maybe a little bit of catch up on what time we lost because we lost over a year in time. So we're trying to -- and you can't recapture time, but we're trying to put ourselves in a position to make sure those projects come on, and we have the developable wells to produce into them as they move into production stage.

Broadly, would you say things are getting -- easier is not the word I'm looking for, but less onerous perhaps in terms of the actual permit? Do you think it's BOEMR is actually starting to move things through a little quicker? Any perspective would be appreciated.

I think the biggest contributor to the improvement in getting permits is really I think people are now better understanding what is required. The requirements to get a permit, the technical requirements, what must be done to make progress to the point of getting the permit is much better determined and understood, and that's big. Once you know what you've got to do, then you can attack it and you can deliver once again a document that meets the needs.

Jumping around the world to this very quickly to Liberia. Can you give us an update as to -- just remind us what you're working interest is there, when you would expect to really start the activity to pick up and just a general kind of update of your expectations.

My memory is working interest is in 80% level for us on 3 large blocks there. I' going to ask somebody to double check that for me as I go on. We're very pleased with that. We see this is the Cretaceous trend that we've seen in West Africa. It's been very successful in Ghana. We're moving forward with our first well to be drilled, to be spudded. And my expectation is it'll be in the fourth quarter. But we are on schedule for that. We've lined up a rig. So we're in, I think, good stead to drill the first well or start drilling the first well this year. Pleased with that. We see, from a geological point of view, we see a large number of prospects. But once again, remember, this is exploration. It's a long ways from any well that's in close proximity where we'll be drilling. So a significant distance, but it looks good at this point from the seismic point. So we'll know a lot more after we drill the first well.

Last one for me is I guess a follow-up to Paul's question. California fairly modest, I guess, overall position the context of Chevron's scale. But my recollection was that you had sold a lot of your Deep rights about 10 years ago to Occidental. Can you confirm if that was the case on and how much running room have you actually have in the deeper Santos Monterey area?

In the Santos area, we do not have a lot of acreage. I don't have that number right in front of me, but that is not where our position is. We'll have to get that as a follow-up either, I guess, next quarter or between our IR folks. I don't have that number right with me, but we are not positioned large there. I just got some help on that, in Liberia, we're 70%. We have a 70% working interest, just to correct that.

My very quick follow-up was for Pat. Pat, your net cash position, your share buybacks are still very modest. Just some context as to why you're not yet just, choosing to get a little more aggressive, and I'll leave it at that.

Yes, Doug, our belief here is, and I think we said this when we reinstated the share repurchase program, we deliberately put flexibility on it in terms of time and in terms of dollars. And we want to be able to sustain the share repurchase program over a long period of time and be able to live through any sort of uncertainties. So our approach is perhaps a little bit more modest than you might think, but our objective there is to be able to have something that we can sustain over time. I think you would agree with us here that there's a fair amount of uncertainty out there. Certainly, what we saw in terms of the U.S. GDP this morning, China GDP has been dampening a little bit, still very strong but dampening a little bit. We've clearly got uncertainty in terms of the U.S. policy environment. And all we are trying to acknowledge is that there can be -- while we're favorably inclined about prices over the medium term and long term, there can be excursions south of that for short periods of time. And we just want to be able to, once we go into the share repurchase program, keep it on track and sustained. So that really is our philosophy.

Our next question comes from Jason Gammel with Macquarie.

George, I had a question about the margin -- Upstream margin and strong capture rate you're getting there. I know that part of the contribution to your move into the #1 position was from a lot of the new projects that have been brought online over the last couple of years. And so my question is are you expecting to move past cost recovery mode in any of these projects that are in PSCs that maybe would ratchet down the margin capture? Or then conversely, would you expect the margin capture to actually continue moving forward?

Jason, it's a good question. It's got an awful lot of moving parts. Let me start there. Yes, we are moving on some cases on the PSCs to the point where we have much of the capture of the initial investments. It's complicated by recognizing that in many cases, as we move to that point, we also move into later phases like in Agbami 2. We moved into a second phase of development, which continues some of that capture. So you have those and recognize we also have new projects coming on. An example and actually in the same area of the world, Usan will come on next year in Deepwater Nigeria. So we've got another one that way. So these ins and outs, I would tell you that the quality of the new assets coming on, they're very strong in their earnings power. They have very strong earnings per barrel. What I can't tell you is I really don't have -- it's hard for me to get a view of my competitors and what's happening in their portfolio, and I wish I could get a better handle on that myself, which I'm sure all of -- as a matter of fact, maybe that's a question, as I see some of you, you'll help me on that.

Maybe if I could shift to the exploration program in Australia. Unlike some of the other operators in the area, you've really kind of kept the drill bit in front of the marketing activity. And I know that your view has been that you have more than enough gas for the 5 trains that are either sanctioned at Gorgon or about to be sanctioned at Wheatstone. If you think about the resource base, what do you actually think you could underpin now in terms of numbers of trains, that 5 million tons per annum? And in a blue sky case, do you think you'd be able to do a train a year for 10 years?

Well, let me start. We've got 3 trains at Gorgon. To get everybody oriented, we've got 3 trains at Gorgon that are a little over 15 million tons. We have almost 9 million tons, 8.9 million tons in the 2 trains at Wheatstone. On the case of Gorgon, my confidence of having resource for the fourth train is high. We still, I think, and we are drilling lots of exploration wells. I think we've got to continue that to have the confidence in additional trains. Barrow Island, we will not be able to put anything on beyond 5 trains, and 5 trains is, like I say, is that's all that's going to fit there. We have a lot more space in the case of the Ashburton North side. Wheatstone can probably handle 6 trains. Confidence level is good in the 2 trains that we're moving close to FID, and we have discoveries in the 205 block there, and that's the Clio-1, 2, 3 discoveries and Acme. And now we're doing Acme follow-ups. So we're trying to prove up a quantity of gas there that would give us a lot of confidence in a third train. Remember, the other one unique thing that we're trying to do and I think are doing and you can see it through our participation in the first 2 trains for the Apache, KUFPEC. We're trying to build a hub there that will allow other third parties to bring in gas and to do it in an economical manner. So we're always trying to provide that opportunity set also. And I think that gives us confidence that, that combination of our drilling plus the more open access will allow for additional trains to be built at Wheatstone, the Antelope site.

Our next question comes from Paul Cheng with Barclays Capital.

I have 2 questions for George and one really quick follow-up for Pat. George, I suppose that when you initially invest in Atlas Energy as partners, you see it as a great resource base partly maybe is that using it as a beachhead to learn about the shale gas technology and how to operate there. But shale gas and the shale oil that they are quite different from one play to another. So do you think that the position data that already allowed you to have sufficient amount of learning experience to fully understand and expand that knowledge base to the rest of your global portfolio or that you may need beachhead in other play?

Okay. Let me -- having access to Atlas for us is very important. It's the process of actually doing makes a lot of difference. We see challenges in the way monies are spent presently in the unconventional gas. One that are -- the first one is we don't believe it takes as many frac stages. You don't have to frac as much of that formation if you truly understand the sweeter spots, if you will, of that formation. So the only way I think we can prove that and really grow that expertise and become better and more economically doing it, is by doing it. So we're trying to do that, of course, and then what we want to do is to be able to apply that technology, that technical ability to other places in the world. We see that as particularly important for us as we move into eastern Europe because we don't see the infrastructure capability by service providers to be nearly as available as what we see in the U.S. So that's how we tie the 2 of those together. So we want to get technically a whole lot smarter, and we want to use what we learn there and be able to apply it around the world.

Sure. I fully understand. But, George, my question is that given that this formation is somewhat different from what we understand. So having a substantial position in Marcellus, is that what you believe already give you sufficient of the learning curve or that you need exposure to other areas? That's my question.

Well, I think the case of Marcellus, the Marcellus was the quality of the Marcellus that took us there and the proximity to market. We had the opportunity on scale, relatively early entry, quality. All of that took us there, at this point in time. Europe is, once again, a combination of that with a lot less geotechnical information being known. We've got to drill some wells. We've done G&G. We will be drilling our first well or first wells in Poland this year, and we'll start answering the questions. Drill the well, get more technical information. We'll eventually have to be frac-ing wells. We've got to go through that, Paul, and that's what's going to answer the question. We're willing to get scale in Europe initially, where if it works, you've got the scale to make up a really nice business. And remember, the entry cost in Europe was much different than what the bets are in the United States.

Okay. All right. The second quick one is that for George is Bulgaria. I presume that you just acquired the acres so you're going to do seismic this year, and we should not expect a first well until late 2012.

I don't expect -- I'm not even sure we're going to get the seismic started this year. I really am looking more at the seismic next year. And this is so recent, I think, it's a little early to even talk about when the first well. But we'll have more on that in the oncoming quarters.

Okay. And then a quick one for Pat. In the past, I think from your accounting standpoint, Chevron, the Gulf of Mexico oil realization is based on a 1-month lag. I just want to -- curious if that's still the case here.

Yes, I mean, I think if I understood that correctly you're asking about the pricing lag out of Mexico, Gulf of Mexico?

That's correct.

Yes, that's correct.

You are still on the 1-month lag.

Yes.

Your next question comes from Kate Minyard with JPMorgan.

Just a quick question on your buyback program. I realized you talk a little bit about it earlier. But when you're looking at buybacks versus dividends and the redeployment of excess cash or that return to shareholders, it looks like your average diluted share count hasn't really declined over the last several quarters despite the buyback program. So I was curious as to what factors you're weighing given that you want the buyback program to be sustainable as well as you look at distributing that cash through buybacks versus through dividends.

That's a good question, Kate. You're right. There hasn't been as much of a reduction in the outstanding shares. And that's simply been a function of the exercises of some stock options by annuitants in their 10-year window. And we've taken a look at that, and it's been obviously driven by how well our share price is done, particularly in the first quarter and second quarter here. When we peg our share repurchase program, we don't really have knowledge to take that other effect into account. So when we talk about our share repurchase program, we really are talking about the amount that we have control over. And therefore, the $1 billion or now upping it at $1.25 billion in the quarter here. And in terms of the dividend play versus the share repurchase play, I think I've been on record many times now in talking about our financial priorities, and the first one really is to sustain and grow the dividend. And we did show a dividend increase here in the second quarter of 8%. So that's the primary distribution to shareholders that we pursue. Share repurchases are a much more discretionary piece, and we peg that to what we consider the short-term, medium-term and longer-term outlook of cash generation -- surplus cash generation for the company.

Okay, sure. And then if I could just quickly ask on the PNZ. It looks like production's kind of come down over the last say, 2, 2.5 years. Just curious as to whether that's entitlement related or if it's decline, and then whether the outlook would be that we'd look for an increase as the flooding program kind of gets more underway.

The PNZ is that the concession there is a tax and royalty. So it's not a PSC, so there's no effect -- price effect there, and it has declined. Existing deals are on a decline, not a lot but a little bit of decline. The upside the future is really about the steam flood where we see opportunities that could be on a gross basis. We could end up with a production gain there on new production up to 500,000 barrels a day. It's a big opportunity there. We have just for those maybe a little bit of information. We just recompleted into the second Eocene -- or the first Eocene V zone recently and should start our steam flood test there on that second zone in the first Eocene.

Our next question comes from Iain Reid with Jefferies.

Got 3 questions. One for Pat and a couple for George. Pat, just looking at your slides on the Downstream. For international you talk about this timing effect, which I assume is the inventory effect, a positive 155. Just curious as to why there wasn't a similar one for U.S. Downstream, given the fact that all prices increased so much and therefore, there must have been some gains in your Downstream inventory.

Right. Actually Iain, that large bar that you see there on international earnings called timing effects, this time is largely a variance between different positions and open paper between the quarters, mark-to-market effects between the quarters. It's not really as inventory driven as it is mark-to-market driven.

Okay. Can you possibly say then what the overall inventory effect was in the Downstream? Just kind of roughly, if you don't have a kind of exact number.

No, I mean, I think that it's not a place we want to go. We don't have a number that's handy like that, and I hate to speculate.

Okay. All right. George, two for you. Can I come back on Ed's question about costs in Australia? I understand you've got a fair amount of Gorgon contracted, so that probably gives a reasonable amount of comfort in terms of the cost there. But I'm just wondering about Wheatstone. Yes, coming out to FID and I presume [indiscernible] for equipment, turbines, et cetera. Just in terms of cost differential between those 2 projects, since obviously, you're going to use some pretty similar equipment and obviously, probably, pretty much the same labor force.

You're absolutely right, Iain. We do have good cost test data. A matter of fact, we're in hand in many cases with contracts, as we approach FID, that we will be able to issue and execute. So we have a pretty good handle on that. That's very typical of our projects when we get to FID. We really have an awful lot of both the purchased equipment and many contracts where we have a pricing-- we have -- beyond a pricing view, we have a contract that we can execute. We have boiled those into our plans for the FID and our request for funds. I can't give you a number at this point in time until we get post-FID. We'll be able to give some of that information. Our expectation is in the fourth quarter that we will be at FID. So that probably sets us up a good timing to do that in the March analyst meeting.

But is it fair to say -- I presume you're seeing some reasonable inflation through from the awards you did on Gorgon a couple of years ago to what you're seeing in Wheatstone now without giving a number.

I would just tell you, we feel we have a very good handle on the pricing. We still believe we are getting some good pricing due to the way we have contracted elements of the project. I really can't go any further than that at this time.

All right. Sorry, I'm not trying extract anything from you. It's about Tengiz. I just got a question about the future growth projects. I think when we were over there you were talking about being in a position to launch FEED. I'm just -- and the government was kind of sitting on it for some reason. I'm just kind of wondering where you are now, or whether you managed to move that one forward at all and what that means in terms of the timing of the project.

I think we are moving forward on it. I still believe that we're on schedule to -- for at least the fourth quarter FEED appropriation to be approved. I think most of our issues, we've covered. And I'm sure hopeful that we're going to make that target date. But we aren't there yet, I'll tell you that. So we're making progress, but we're not there yet.

Okay. At this point, I'd like to wrap it up. I'd like to say that I appreciate everyone's participation on the call today and everyone's interest in Chevron. I especially want to thank the analysts who asked some very good questions. I'm sure they helped everybody's understanding of the company. So thank you very much, everyone.

Thank you. Ladies and gentlemen, this concludes Chevron's Second Quarter 2011 Earnings Conference Call. You may now disconnect.