Good morning. My name is Sean, and I’ll be your conference facilitator today. Welcome to Chevron's Second Quarter 2013 Earnings Conference Call. At this time all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, this conference call is being recorded. I’ll now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.

Hey thank you, Sean. Welcome to Chevron’s second quarter earnings conference call and webcast. On the call with me today is George Kirkland, Vice Chairman and Executive Vice President of Upstream and Gas, and Jeff Gustavson, General Manager for Investor Relations. We will 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 $5.4 billion, or $2.77 per diluted share. Return on capital employed for the trailing 12 months was about 16%. Our debt ratio at the end of June was approximately 12%. In the second quarter we repurchased $1.25 billion of our shares and in the third quarter we expect to repurchase the same amount. Turning to slide 4, cash generated from operations was $8.5 billion during the second quarter and $14.2 billion year to date. On last quarter’s call, I noted adverse working capital effects which reduced first quarter cash generation. In the second quarter, we saw some but not complete reversal of these effects. We expect further working capital release as remainder of the year unfolds. In June, the company executed a $6 billion bond offering taking advantage of historically low borrowing costs. Capital and exploratory expenditures were $8.6 billion during the second quarter and $16.8 billion year to date. The year to date amount includes incremental resource acquisition outlays associated with Kitimat in Canada, Cooper Basin in Australia and Kurdistan. George will speak to the value drivers behind these additions a little later. At quarter end, our cash balances exceeded $22 billion giving us a net cash position of approximately $2 billion. As we indicated to you in March and as you saw in the first quarter, the company is moving toward a more traditional net debt structure. Jeff will now take us through the quarterly comparison.

Thanks Pat. Turning to slide five, I'll compare results of the second quarter 2013 with the first quarter 2013. As a reminder, our earnings release compares second quarter 2013 with the same quarter a year ago. Second quarter earnings were $5.4 billion, about $800 million lower than first quarter results. Upstream earnings were down $967 million, reflecting lower liquids realizations and higher operating expenses associated with increase maintenance activities, partly offset by a favorable swing in foreign currency effects. Downstream results increased $65 million between quarters. The increase was driven by higher downstream volumes following heavy maintenance during the prior quarter, which was partially offset by an increase in operating expenses in lower chemical earnings. The variance in the other bar largely reflects favorable corporate tax items during the quarter. On slide six, our U.S. Upstream earnings for the second quarter were $49 million lower than first quarter's results. Lower realizations decreased earnings by $25 million, driven by decline in crude oil prices, partially offset by an increase in natural gas prices. Higher production volumes, primarily from our San Joaquin Valley, California and Delaware Basin, New Mexico operations increased earnings by $40million. The other bar reflects a number of unrelated items, including higher operating expenses related to maintenance and other production related activities, as well as slightly higher exploration expenses. Turning to slide seven, International Upstream earnings were $918 million lower than the first quarter. Realizations decreased earnings by $550 million, average liquids unit realizations declined by 8% in line with the decrease in average current spot prices between quarters. The timing of lifting in Kazakhstan and across multiple other countries decrease earnings by $60 million, higher operating expenses due to increase maintenance activities in the startup of the LNG plant in Angola, decrease earnings by $195 million between periods. A favorable swing in foreign currency effects improved earnings by about $105 million. The second quarter had a gain of about $275 million, compared to a gain of about $170 million in the first quarter. The other bar includes the absence of favorable tax effects during the first quarter and higher exploration expenses. Slide eight; summarizes the quarterly change in Chevron’s worldwide net oil equivalent production. Production decrease 63,000 barrels per day between quarters. Lower prices increase volumes under production sharing in variable royalty contracts during the second quarter by about 5,000 barrels per day. Plan turnaround activities in Kazakhstan and Australia have the largest impact reducing production by 45,000 barrels per day. The base business in other bar includes normal fuel declines in lower natural gas demand primarily in Thailand. Turning to slide nine, U.S. Downstream earnings were essentially flat between periods. Higher volumes increased earnings by $245 million at several refineries came back on line during the second quarter, following a particularly heavy maintenance period during the first quarter. Stronger margins increased earnings by $50 million due to lower crude prices, as well as tighter product inventories, operating expenses increased by $180 million largely due to higher fuel consumption, transportation and environmental related expenses. Lower chemicals results reduced earnings by $110 million, primarily due to lower ethylene margins and reduced volumes on planned and unplanned downtime at two separate plans. On slide 10, International Downstream earnings improved by $63 million between quarters. Higher volume increased earnings by $80 million primarily on the absence of maintenance activities at the Cap Town, South Africa and Burnaby, Canada refineries. Higher operating expenses decreased earnings by $50 million reflecting higher fuel usage and employee cost. The other bar includes a number of unrelated items including an unfavorable swing in foreign exchange impacts and weaker refining margins, partially offset by positive inventory evaluation effects driven by following prices during the second quarter. Slide 11, covers all other. Second quarter net charges were $350 million, compared to $439 million in the first quarter, a decrease of $89 million between periods. Favorable corporate tax items resulted in $145 million benefit to earnings, while corporate charges were $56 million higher this quarter. In part, higher corporate charges reflected an asset impairment as noted in our interim update. Year-to-date net charges in the All Other segment were 789 million at the end of the second quarter. We believe our quarterly guidance range of $400 million to $500 million for the All Other segment is still appropriate going forward. George is now going to provide an update on our upstream operations. George?

Thank you Jeff and good morning. To begin, I’d like to note the progress of our Jack/St. Malo and Big Foot projects for the Gulf of Mexico. This photo shows the hulls of both platforms at the yard in Ingleside, Texas. The topside modules and hulls of the projects are currently being integrated. Since this photo was taken, additional modules were set on top of the Big Foot, which is pictured on the left. The Jack/St. Malo towed to its location is scheduled for year end. Jack/St. Malo and Big Foot remain on schedule for 2014 startup and these are important contributors to our 2017 production target, supporting our profitable growth. Now let’s take a look at our financial performance on slide 13. Our 2013 year-to-date upstream earnings margin was $23.88 per barrel. Based on first half results for the peer group, we continue to lead the competition by a considerable margin. We are almost $6.50 per barrel ahead of our nearest competitor. We have now held this top position for 14 consecutive quarters. This result flows from the quality of our investment decisions, the strength of our portfolio and the strong execution performance of our base business and projects. I’m also very pleased with our upstream return on capital employed which is almost 20%. I expect this to rank at the top of our peer group. Now I’ll cover our 2013 production on slide 14. Production in the first half of the year averaged 2.61 million barrels a day, at an average year-to-date Brent price of $107.50 per barrel. The first half results are near our forecast, giving our planned turnaround and maintenance activity. We anticipate an increase in production in the second half of the year. Our 2013 production guidance remains unchanged at 2.65 million barrels a day at an average Brent price of $112 per barrel. I’m pleased that Angola LNG has achieved startup and has now loaded two cargoes to date with another preparing to load. This significant milestone is the result of the hard work of many individuals in Angola and around the world. For the second half of the year, we anticipate Angola LNG will be ramping up and will be a large contributor to our production. We plan to load at least 13 cargoes by year end. Remember, at peak rates, ALNG should contribute about 60,000 barrels per day to our production. We will have additional production rampups from our other major capital projects including Usan and Tahiti 2. We restarted Frade in Brazil at the end of April and currently have 3 production wells online. As seen in the graph production growth in the second half also comes from our base operations. This includes additional cost recovery from production sharing contracts, additional production out of the Marcellus and an increased drilling activity in the Permian. These increases are partially offset by the planned turnarounds. Overall in 2013, we expect to have a similar level of turnaround activity as we had in 2012 and relatively heavy for both these years. We continue to have confidence in meeting our 2017 growth target as we bring on new projects and other key developments. I would like now to update you on the status of a few key projects. Turn to slide 15. Gorgon is now almost 67% complete. Barrow Island construction has achieved major milestones including the installation of the second gas turbine generation for Train 1. The third of five generators for the site will arrive later this year. Seven major process modules are on their foundations and now 11 of the 51 modules are on Barrow Island. The remaining 10 Train 1 modules are schedule for delivery by year end. We also recently completed the installation of the 20-inch domestic gas pipeline. The Gorgon team has resolved the logistic challenges they faced earlier, additional lay down areas on Barrow Island were established and material handling has significantly improved. Increase transportation capacity has allowed the project to exceed material delivery targets. Construction productivity has improved in some key areas and our team is focused on increasing productivity across the Broad for Barrow Island construction. Gorgon module fabrication is progressing and we are managing it closely. We also continue to carefully monitor labor costs and weather impacts. In the Upstream, the first five sea -- subsea wellheads were set. We have finished the lower completion of all the Gorgon wells and 50% of the [Jens Iago] wells. As one of our key legacy assets, with over 200,000 barrels a day of production net Chevron share, Gorgon will be a major contributor to our future financial performance. We have posted several updated photos of progress made at both Gorgon and Wheatstone on our Investor website located at chevron.com, and I’ll encourage you to go there and look them. Next, I will review progress on some of our other key developments. Wheatstone made significant progress in 2013, with the team focused onsite infrastructure and upstream fabrication. We now have over 2,200 people onsite at Onslow. The offshore platform fabrication began in South Korea with erection of the seller deck. Offshore dragging began for the pipeline. The first phase of the construction village has been completed and the new runway at Onslow airport is nearing completion. The remaining activities for 2013 focused on site work to prepare for module deliveries in 2014. Wheatstone remains on target for a late 2016 startup. Kitimat marked an important milestone on July 1st, with the transfer of operatorship for LNG plant in the Pacific Trail Pipeline development to Chevron. Front-end engineering is progressing on plan. Early earthworks continue at the LNG plant site were a total of 6.5 million cubic yards of earth and rock have to move. LNG marketing activities and engagement with potential foundation customers are underway. We are focusing on Asian markets and aimed to have 60% to 70% of the LNG volumes under long-term commitment prior to a final investment decision. In mid-July, we entered into an arrangement with YPF to facilitate the development of a section of the Vaca Muerta Shale Basin, which has a significant potential for both liquids and gas production. This initial program includes 100 wells in a Pacific portion of 96,000 acre development area. This development provides a new opportunity that we believe will be competitive with other projects in our portfolio. Above ground risk, have largely been mitigated through government decrease and the financial structure, all in all we are pleased with the deal and the opportunity to participate in the development of this world-class resource. The projects that I’ve just been reviewed provide legacy growth and production, and cash flow. Now I’ll provide an update on our exploration activities. Please turn to slide 17. We have another active year of exploration, where we all plan to invest over $3 billion. We're making great progress in our key focus areas of the Gulf of Mexico, West Africa, Australia and North America unconventionals. Outside of those areas, we have a mixture of conventional and unconventional exploration enhanced by key acreage additions. We have drilled or currently drilling 10 of our 14 plant impact wells for 2013, including the second well in the Kurdistan region of Iraq which spud on Wednesday. Now I will highlight a few areas of new activity for 2013. We are maintaining our emphasis on the Permian portfolio and we are increasing drilling activity in exploration, appraisal and development. We’ve enhanced our position in the liquid rich Delaware basin and are now the largely leaseholder with significant potential in undeveloped acreage. We drilled our first two wells in the Utica in Ohio and are encouraged by the preliminary results, and we will provide more details on this later this year. We’ve added another block in Kurdistan -- in the Kurdistan region of Iraq and our plan is to complete and begin testing two wells this year. Our Australian portfolio has increased with the addition of acreage in the Cooper Basin tight gas [point]. Exploration and appraisal wells are in progress. We’ve also acquired new acreage in China, Brazil, the US Gulf of Mexico and Morocco. Finally we just announced an agreement for the acquisition of additional acreage in the liquids rich region of the Kaybob, Duvernay basin. This complements our existing acreage position where we had drilled 10 of our 13 well program. Results for these stage fracs are positive with significant condensate yields. These portfolio additions demonstrate how we continue to selectively capture future growth opportunities remaining focused on value, adding assets that can sustain our strong financial performance. Now I’ll turn it back to Pat.

Turning to slide 18, George just provided an update on recent upstream activity, three milestones were met in the quarter in our downstream business. First, the Richmond refinery successfully restarted. By quarter end, the refinery was fully operational and running at planned utilization rate. Second, GS Caltex’s Yeosu refinery began commercial operation of the heavy oil upgrading unit which now makes Yeosu one of the largest heavy oil upgraders in South Korea. This unit came online three months ahead of schedule. Third, our chemical joint venture Chevron Phillips Company announced plans to expand its ethylene production at its Sweeny Complex in Texas. I will close by highlighting our continued strong performance on total shareholder return as shown on this slide. We continue to lead the peer group by a significant margin which shows we are executing well against the right strategies. I would also like to point out the balanced manner in which our returns were achieved. We know the importance of not only providing returns via a competitive and growing dividend but also from disciplined reinvestments in our business to generate future value. We are fully committed to delivering disciplined growth and shareholder value and our objective is to continue to lead the peer group on total shareholder returns for a long time to come. We appreciate you listening in this morning and your interest in the company. And now I would like to open the microphones for questions. We do have a full queue, so please limit yourself to one question and a single follow-up if necessary. We will do our best to see that we get all your questions answered. Sean, please open up the lines for questions.

(Operator Instructions) Our first question comes from Paul Sankey of Deutsche Bank.

On the recent acquisition commitments in Argentina, it was at a time when your CapEx is very elevated, and additionally I think there has been some legal issues around, can you just underline for us why you are making a move like that at a time, as I said, when your CapEx is still elevated and (inaudible) the legal complexity that you probably really don’t need?

Well, Paul, it always starts back at what’s the opportunity set out there and how does it compete in the future, we’d like the opportunity from a technical point of view. When you look at it technically, this opportunity, much of the shale is in 1000 foot range of thickness. So it’s very attractive that way. We’ve been in Argentina a long period of time. So we understand, I think, Argentina quite well. So we feel comfortable that way. And we always have within our portfolio some ability to spend our money in different ways. We have the ability because of our base business programs that we can move some moneys around. I go back, the other point would be that opportunities are there when they are available and this one is available. On the legal side, I would start off and say, first-off, we really don’t believe there is any legitimate legal claim against us. So that’s -- we're pretty confident about that. We think we’re in a good position there. Back home, the development itself we see this very much as a stage development over a long period of time. The initial work is 100 wells and depending upon that success, we will move forward from there. We also see Argentina as a country that’s got a large resource potential. We really believe that over the long period of time, they can move from an importer potentially, an exporter accrued. And once again, the time for the opportunity was now.

Okay. So it’s….

Go ahead.

So I was just going to follow-on with -- on reference, your sales reference, this is a high-intensity period of CapEx with the two Australian LNG projects above all, simultaneously in your Q. Can you talk about your longer term CapEx and the potential to bring that down with a view to generating more free cash flow or are you intending to push through to try and grow the company beyond the existing 3.3 million barrel equivalent target that you have for 2017? Thanks.

First, Paul, we’ve got to disconnect those two. They are not necessarily they are totally connected. At our March meeting when we met in New York, we told people that we see our growth beyond 3.3. We did not disclose what their growth would be. It’s a little premature to go there but we do see growth beyond that. One of the points that we talked about it that time was the growth that we saw that would be coming from a future growth project and the low pressure management project in Tengiz. When we originally committed to our 3.3, about 80,000 barrels a day of our growth to 2017 was related to the Tengiz expansion. And that project is not going to be on line in 2017. So it contributes to significant growth. And remember the Tengiz project in total will add -- the expansion will add about 130,000 to 140,000 barrels a day of net production for Chevron. So we do see growth beyond 2017. But likewise, we always see some projects that tend to move a little bit to the right, move a little bit later. So we take that money and invest it in other opportunities because we have a very strong portfolio. I would tell you as we get Gorgon and Wheatstone completed those investments, we do not have anything as large in our portfolio on a capital expenditure basis as large as those. So from that perspective, we will see some decline in our capital program in a relative sense. But remember, we’re also going to be a lot bigger in the barrel side. We will have a lot more barrels to our cash flows. Our cash flows will be high. We got very strong margins. So we’ve got that combination to go forward. So it’s a combination of things that move around but remember portfolio, lot of barrels, lot of barrel growth, 25% growth. We’re looking at holding our margins, our margins which are industry leading we think we will hold them. So we’re going to have cash flow growth and a flattening and I would call it more a flattening of a capital program going forward.

Thanks George and thanks all of you, thanks also for taking the time to come on the call.

Thanks Paul. Okay, next one?

Our next question comes from Evan Calio with Morgan Stanley. Please go ahead with your question.

Good morning everybody and George, thanks for the update on the upstream projects and clear on the free cash flow. My first question is on the Permian. Now there has clearly been a lot of exciting industry results, you entered the Cimarex joint venture. I know you’re building a technology center there. I mean can you quantify at all for us the activity ramp or potential organic growth there in the basin and how Chevron is building or expanding its Permian capabilities to run a bigger organization? And I have a follow up.

Maybe I’ll start back with what we said in March of this year. We expect to drill over 300 wells in the Permian Basin, in the Midland Basin itself we see growth in the Delaware Basin. Remember we added the Chesapeake acreage in New Mexico to acreage we’d already had there. This recent Cimarex deal in the Permian is really is bringing together a checkerboard of acreage of ours and Cimarex. Why do we do that? Well we do that to increase efficiency and effectiveness of the dollars we spend. We reduce geographic acreage loss if you will. We can drill longer laterals, so it’s just a much more efficient way to develop that acreage. As we said in March, we are going to see our rig count grow considerably over this period. I don’t think we’ve done anything post-March that doesn’t fit with the plans that we showed at the March meeting. Our plans are pretty consistent in that growth profile both in acreage and in barrels. We do expect that our net production to grow towards in the Permian Basin into that 200,000 barrels.

But I mean just any color…

So -- go ahead.

Yeah, I didn’t know, there was any color on the technology center that you’re building or people addition or just what investments you are making to build an infrastructure that would support more significant organic growth there.

We will. We have committed to a tech center there. We have -- we are starting a building, a significant building project there, [harness] project. We’ve purchased land and moving forward we are building that. And I would also tell you, remember, we’ve got a big support function for that unit also out of Houston. So we’re -- I think we’re in good shape on what we have in Midland and we have a strong commitment, we have lots of acreage and Midland and the Permian Basin and the Delaware Basin are long-term assets for us. But I don’t really have anything that’s new beyond what we presented in March.

That’s fair. And if I could a second on just quickly on Gorgon. Can you provide any update on cost trends or color since your guidance earlier in the year or when or what key milestones will trigger any cost update there?

Well I would tell you we’re always looking at the cost and watching the cost. We review the project once every month from my level and John Watson, we both take a -- have a project review once a month. We look at progress, we look at costs, we look at issues, we look at mitigations that our project team are putting in place. And as you know, a big project like this there is always issues that people are solving problems. And our people are very good at that. I mentioned today that we really think we have solved the issue around the logistics; that was important for us. We are not going to know a lot more on costs till we get really much further in. we don’t see any major disconnects at this point. We see, as an example, the first half of the year exchange rates are really pretty close to what we assumed in our plan. It’s -- the first part of the year, the rates were higher than parity, the second quarter they were down but for the year they are pretty close. And now we’re seeing a shift in exchange rates that are -- in our -- positive for us with exchange rates coming down and we are in a period where we got major expenditures in Australia. We’ve got a lot of moving parts there, so we can always tell where we've been a lot better than where everything is going and any issues once again we try to mitigate those as they go. But I don’t see anything major on the costs side. It’s still back to productivity and I’ll emphasize it’s critical to get productivity on Barrow Island and it’s important for us to have good weather. Weather is an extremely important part of our success there and we’re in the good part of the year right now, between now and December we are outside of major weather impacts. So we’re in a period that we get to December. We will know and offer lot more. We are 67% now and every time you get little bit closer towards 100% you can do a lot better forecasting.

Great. Always helpful, George. Thanks.

Thank you.

Thanks Evan. Next caller.

Our next question comes from Arjun Murti of Goldman Sachs. Please go ahead with your question.

Thank you. My thanks for the E&P update as well. Just a follow-up question on Kitimat, where you have now had sometime to look at the project? And I know the two pieces our progressing the feed and then I think you mentioned you want to get 60%, 70% of the deal sold to long-term customers? On that later point, you now have Exxon with the big project in the area. I think Shell’s get one. I’m sure you don’t want to give a bunch of specifics, though we’d certainly welcome them? But can you at all talk about, how it’s going in terms of marketing this. I know there is a question us to whether they’re might be some linkage to Henry Hub? How are you feeling about Kitimat and it position and your ability to get that gas sold? Thank you.

Well, first off, I’d say, I think, we have a considerable time lead versus any of the other developments in the BC region. This project has permits and plays for export. It has approval and permits in place for the site. We’ve got most of the agreements for the pipeline route with the First Nations. Matter of fact, I think 15 or 16 of the groups of First Nation have already agreed. So I think we are in quite lead on the early part of a project. We’ve also done a feed, one Train and we are now moved into a two Train feed to build two Trains there, we’ve been involved in that. So we do have more work on feed but we are moving quite well on the feed work. So, we’ll go back, once again, we are in a great competitive spot on schedule. That should help us a lot in dealing with those that want to buy gas that puts our project in many ways ahead of others, so for the buyers that need gas sooner in a very positive position. We do not plan to have Henry Hub linkage. We expect the Henry Hub equivalent value will come through some equity sell-down. We do plan to have a partner as buyers, we are going to offer volumes, some volumes and interest in the plant as a combination. We think that’s a big advantage. We frankly think that’s better than Henry Hub pricing. Henry Hub like any index has variability, variability means it goes up or it can go down and we believe that we can get the same or a better situation for a buyer through their participation, equity participation in the Kitimat project. We can do that because the two partners in us and Apache each hold 50%. We hold very strong working interest in the plant and in the resources. So we have that ability to move that way. So our goal is, of course, to maintain advantage, first mover advantage in that. But at the same time, move the project at the right speed, having done all the appropriate technical work. And once again having all the commercial work done to gets us to 60% to 70% position with regard to sales. We’ve had some initial discussions with Asian buyers. We will not disclose the ones that we’re talking with at this time. But we are moving that forward.

That’s just very darn helpful. Just a very quick follow up in terms of the appropriate speed, we’ve always thought that this is more likely to be a 2014 FID versus ‘13 which I think at one point had been talked about -- I don’t know if you can comment on that.

I wouldn’t disagree that it's more likely to be a 2014 FID. Once again we’ve got to have all the right work done and what's critical for us and we’re not progressing the project through FID until we have these agreements at least at a HOA level for 60% to 70% that will take us into 2014, to get those completed.

Our next question comes from Ed Westlake of Credit Suisse.

Yes, thanks very much for all of the information this morning. Just coming to the offshore, I mean it feels as if with a loss position in the Permian and some of the LNG projects that you have, the write on offshore regrets and subsea costs might mean a shift in the portfolio. So I guess two questions, one is how are you mitigating the rise, what are you views on those offshore costs? And how much flexibility do you have to sort of shift capital around to avoid that inflation?

Well, everything depends upon the economics of the projects and our portfolio which is nice and large, we can move monies around. I will you each one of these investments look a little bit different. If you look at a deepwater development we end up with large wells on production sands, high production rates and because of that huge upfront cash flows, these projects come in, they have relatively high DD&A rate, would you look at their operating expense, they are extremely low and they have very strong margins. And it’s back to economics. So now I will tell that the cost structure in the deepwater Gulf of Mexico post Macondo is higher. We have seen a 20% to 25% rise in the cost of wells. I will tell you we’re trying to offset that in many other ways. Technology is one way. If you remember at our presentation in March this year and more recent press release of just around -- I think also in the March period where we talked about the performance of our multi-zone, the single -- our multi-frac single trip frac pack, we had great success with that. It saved us anywhere from 20 to 50 days in the completion operations of our deepwater Lower Tertiary wells. This multi-zone frac pack is a huge benefit for us in the cost side and our original -- in our initial test of the well after that we had very high rates. So I want to take you back this back to what do we think we can get on value proposition, we’ve got the people to do the work in the deepwater Gulf of Mexico. We had the oil capability also onshore. And we will make choices on that but it comes heavily back to the technical quality of the asset.

I mean now that some people have deferred projects but at the moment the rig rates in subsea are they expensive enough given technology for you to do the same, is that what I am hearing?

Our view of Jack/St. Malo today on economic basis is stronger than when we went to FID. Our project view has improved, as we learn more and more particularly about the Lower Tertiary and our ability to change the recovery rates in the Lower Tertiary, we see this as a better and better opportunity. Remember Jack/St. Malo we talked only of about a $500 million barrel tight recovery for those two fields and that was on 8% to 10% recovery rate. We’re focusing on those technologies that can change that recovery rate and potentially raise it up to over 20%. And when you have the infrastructure in place already that additional production and additional recovery is frankly very economic.

Thank you very much.

But each one of them is a decision into itself. We have to have to confidence in how much we are going to produce and we have to also have confidence -- when we reach up there, we do have confidence in how much we will spend to get that return.

Very clear. Thanks George.

Okay and thank you.

Next caller?

Our next question comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead with your question.

Thanks. Good morning everybody. Good morning George.

Good morning.

Question for you George. I want to ask you about portfolio capital intensity and I guess what I’m really trying to understand is when you set the original target for 2017, the CapEx numbers have been creeping higher but there is lot of stuff coming into the portfolio and the margin anyway that wasn’t in the original plan, for example, the Permian Basin. So I’m trying to understand, our things -- good thing for the right as you mentioned in your prepared remarks and the spending basically making up the difference and maybe just in order of magnitude, you’re spending about 20% more than I guess your largest peer on a per barrel basis, I’m just curious if you can just give us some flavors as to that whether or not you think that as a sustainable level of spend?

Well, let me go back and say there are things that we had talked about and I gave the example of the future growth, the expansion in Tengiz as moving to the right. When I move to the right, when I moved later, it did move capital that way also. We look at these portfolio additions on the strength of them. And we don’t only think about our investment ratios in per barrel basis. We are influenced heavily by the cash flow that these barrels give us. That’s back to -- I don’t believe we would be investing for this much growth if we did not have the strength of portfolio to generate the cash. Our earnings per barrel and our cash flow per barrel that we are generating, allows us on a cash flow basis to actually be investing much lower than many of our competitors. So we are investing on a cash basis less than most. It’s heavily influenced of course by the quality and the amount of cash that we’re generating from these barrels. I do believe that you’re going to see our capital investment rate flatten with time. And it’s really a function of the LNG projects that we’re in today. We’ve got Gorgon and Wheatstone which are very large. They build huge infrastructure and capacity for the future. They have very flat long lives. So we’re building for them with them. I always tell people remember when Gorgon and Wheatstone together are on, that’s over 400,000 barrels net per day for Chevron. Those are company side assets.

Maybe I could ask my follow up with Pat is a related question. Pat, you obviously hold a lot of caps in balance sheet that’s not generating earnings .What is your expectations for that trend as a proportion of capital rise or fall over the next several years non-producing capital, I mean, when you get there. Thank you.

Right. I think consistent with where George was going, I mean you are absolutely right. We are sustaining a relatively high proportion of pre-productive capital we call it at the present time. You would expect that rate to be sustained high until you get projects like Gorgon and Wheatstone coming on line. Both of those two projects combined, represent about $45 billion Chevron share of spending over this seven-year period of time if you look at the construction period for both projects. So that’s obviously a significant component and until you get those projects online, we’re going to have relatively high preproductive capital. Once those projects become online, then of course we anticipate that that proportionality will decline.

Ed, I’d just like to make one additional addition to that. I’d take you back to the ROCE we have in our upstream segment. Yes, we do have a large capital employed that is not yet returning revenues and earnings. But even with that, you look at the return on the capital employed in total, we are leading in our segment. So that tells you where we’ve invested and the performance of that portfolio is very strong. So it’s back to our ability to invest is driven heavily by the quality of the existing portfolio to generate cash flow where we can invest in these large growth projects which are going to give us a 25% volume growth between now and 2017.

Thanks for your answers folks.

Our next question comes from Paul Cheng of Barclays Capital. Please go ahead with your question.

Hey guys, good morning.

Good morning.

Good morning Paul.

George, maybe a little bit of this, from a strategic standpoint that we are looking at Kitimat in order for this to become a really great project, you probably look beyond just Train 1 or 2, I don’t know whether that you really have sufficient gas resource up there yourself. So logistically then how share volume you look at here, so you will be just essentially saying okay, I have gas resource for the first two train and get it going and then subsequently I would be just be the owner of the train and not necessarily to be the owner of the natural gas and just process other people’s gas or that you actually think that is important for you guys to be fully integrated?

Well the second point first, I think it is very important to be fully integrated and to have the resource. Our view is being tempered at this point in time because we haven’t been in the project as long as Apache has. But I take you back to the view that Apache is on the press with and what they view Liard and Horn River, their view of Liard alone is approximately 50 Tcf of gas. So if you take 50 Tcf of gas and you take Horn River and Liard, you’ve got something greater than that. That is much more gas than is needed for a two train plant. A two train plant is more likely to be in the 15T of gas required. Bottom line, we are not short of gas at all in the Kitimat development. Our issue is to get foundation customers and the foundation project in place and then find a way to -- the next step is to look at the expansions. I don’t want to spend a lot of time on the expansions yet until we get -- we really get past having the first 2 trains once again sold from a market point of view and then get them post FID.

Right. But I think I guess my question is that in the event if that those huge numbers that talked by Apache did not materialize and end up to be smaller, you still won’t willing that you have to integrate model that including the ownership in the resource?

Yeah I think we need that -- to have surety of the supply to feed the plant. So we’re quite confident at this point for the first two trains. We’ve done enough work that are confidence is high that there is a large volume of gas there. We have lots of appraisal work that will be done in Liard to confirm those volumes as we go forward. But I will tell you, all my engagement with our partner is quite confident in the quality of this resource.

Second one, George, can you give somewhat idea that the base on your drilling result and how is the [metric] whether its Brent oil, condensate or NGL, what’s our split we are talking about in the Permian Basin that you’re drilling right now as well as Utica?

I can give you a lot more on what we’re seeing in the Permian Basin. We’re focusing on the portion of the basin that we see greater than 50% liquids and I say 50% liquids looking at really the oil and condensate side, LNGs, pardon me -- LPG is not what I’m speaking of. So it’s really -- it’s over 50% OEG in liquid with oil and condensate side. That’s why we like it so much that that really carries a lot of value. In the Utica, I’m not really prepared to give you those numbers, I would just simply take you back to what I said in my prepared comments for today that we are pleased with what we see. We’ve had about 30 days of production test, production run actually on the first two wells. It’s a little early to speak on that and we should be prepared in a little bit later in the third quarter to give a little bit more information on the Utica. But flexes just a little bit early, I would also tell you probably same time we would be prepared to speak a little bit more about the Duvernay in Canada because it is once again also a liquid play. And we’ve just closed this -- closed on this additional 67,000 acres up in the Duvernay. I would tell you also maybe as the general comment, what we try to do every quarter is to have a big anchor position, like in the Permian Basin and then build additional acreage around it before we disclose all our results. It only make sense for us not to get our disclosures out in front of where we’re trying to move from a commercial point of view. So we feel very good what we are in the Permian Basin. And my expectation is that we have other opportunities like Cimarex, we will make those happen to. But we like very much to get a nice position, build that position and it’s particularly nice to build that position after you, truly understand the subsurface. So you understand how the rocks are and really how much of the volume is going to be oil or gas.

George, is Permian is a primary frac oil or just primary condensate for you?

The Permian is primarily oil.

Frac oil for you.

Thank you.

Thank you.

Thank you, Paul.

Light oil.

Our next question comes from Jason Gammel with Macquarie. Please go ahead with your question.

Yeah. Thank you. I just want to follow up on LNG marketing which has been raised by few others. When you think about putting Kitimat into the marketplace, how do you contrast that with the potential for brownfield expansions at your Australian projects. How do you prioritize getting one into the market versus the other? And then just related to that, what’s you sense of urgency in getting volumes into the market right now, given that there are projects moving forward pretty quickly in both East Africa and on the U.S. Golf Coast?

Lot of question there Jason I’ll try to hit those. I’ll start of with contrasting maybe our Gorgon trains for versus what we have at Kitimat. First difference is scale and to the buyer we have a bigger offering of volume. We have 11 million tons with two trains, and we are doing the joint marketing. So we have 11 million tons there on offer that we will be available and once again we want to have 60% to 70% and we would be willing very much to move up to the 80% at the time of start up. In the case of Gorgon train for its 5.2 million ton per annum additional train, the difference there is also the gas coming out of Gorgon is marketed by each of the partners. We -- we're remarketing about 47% of the gas in Exxon Mobil and Shell, each have about 25%. So it’s a much smaller volume to move for us, the plus for Gorgon is you’re brown -- you’re brownfield. So you’ve got an advantage on the plant side, depending upon on where we are going in Asia, there is no difference in transportation from in distance and cost from going to Kitimat or coming from Australia. It actually depending on where you’re going in if it’s in North Asia, there may be a slight advantage for Kitimat. So it could be positive for us there but volumetrically it’s positive. We do think from a development cost that -- the development cost at Kitimat on the upstream may end up being less than in the case of Gorgon. Gorgon has the benefit of the brownfield on the plant side. We have we think more control on the Kitimat project because of the partnership. We have 50% there and I think a very aligned partner and we are jointly selling the gas that I mentioned. In the case of Gorgon Train 4, three companies are selling the gas. So there is a different alignment there. We’re happy to see both of them move. They are a little bit of a horserace between them at this point in our own shop. East Africa I didn’t mention and I think people here reminded me, I actually see East Africa behind both of these projects. I don’t believe East Africa from my perspective yet has an operator that’s in place or a unit that’s been created to move that project forward. So I think we do have a timing advantage on both of those projects to first gas. Gorgon we know we’ve got all the gas, Kitimat we’re confident of we’ve got all the gas for two trains. So I think we have a little bit of an advantage there. And we do know our fiscal regime and regulatory regime in both the locations in which we operate very clearly.

Okay, thank you Jason. Next question? I think we have time for a couple more questions.

Okay. Our next question is all set from Iain Reid with Jefferies. Please go ahead with your question.

Yeah hi there. Pat, could I ask you a question actually about the share buyback. You said earlier you’re moving into more of a kind of net debt position going forward. You’re obviously spending both on CapEx and dividend significantly more than you’re generating cash flow at the moment and the buyback is kind of accelerating that process into net debt. What sort of point do you think the buyback has done its job in terms of that process? Have you got a kind of target level of gearing which you are aiming for? And when can we think about you perhaps scaling this back over the next several quarters? Thanks.

It’s a good question. I think I’ve explained before how we look at share buybacks and it really is we try to take a medium-term point of view, we take a look at what’s happening to commodity prices, we look at what our opportunity for reinvestment in the business in, we look at obviously a growing dividend profile that we want to make sure comes right off the top. We want to maintain flexibility in our financial structure and after we’ve done that, sort of equation, if there are funds left over, that’s when we fall into the share repurchase category. We do want to take -- we have tried to take a more medium term point of view here and not be in and out of the market just depending upon instantaneous circumstances in a given quarter. We do not have a targeted leverage ratio for the corporation. We look at the leverage ratio really as being an outcome of these other decisions that we have made. And we have tremendous additional leverage capacity as you well know. We’re sitting here today with a 12% debt ratio; we have a long way to go before being overlevered becomes one of our problems. So I think you can consider when you look out and forecast your own commodity prices and take a look at the development stream that we’ve got available to us and you look at our past practice on dividend streams, you can put together a cash flow model. We have a long way to go before net debt becomes a challenge for us.

Okay, thanks for that. And can I just ask one very quick question for George? On Brazil, George, you talked about Frade coming gradually back on stream. But in that kind of growth profile you’re showing for the second half of the year, is Papa Terra in that and also I wonder if you could also comment on Chevron’s view of the pre-sold round coming up from Brazil?

Frade, as you said is part of that addition in second half. We had no production in Frade in the first quarter -- second quarter, an average about 5,000 barrels a day. Our share at the month of June, we were closer to 10,000 barrels a day, our share. So there is some expectation there that we will go grow in the second half or we will have more volume in the second half in our project, not too far off from our original plan, the field is performing at this point pretty well. So that’s a plus. On the case of Papa Terra, Papa Terra may come on production this year but it’s not going to be a significant mover on production. Petrobras is still talking about bringing it own this year but it’s late in the year. So we do not believe that it will -- it will be significant mover on our production for the year. With regards to the deepwater round, all our exploration opportunities, we review the opportunities set and we never disclosed upfront what we think of it, we always talk about what we did afterward and give more color at that point in time.

Okay, George. Thanks very much.

Thank you.

Okay. Thank you. I think we’ve got one more -- time for one more question.

Okay. Our final question comes from Faisel Khan of Citigroup. Please go ahead with your question.

Thanks. Thanks guys. Good afternoon. Just on the key exploration around acreage traditions, it seems like you guys definitely had a good amount of acreage during the year and a few bolt-on acquisitions. Can you give us an idea of what the -- how much of that is your capital budget that made up and what’s your appetite going forward. And I have a follow-up on downstream side.

Faisel Khan, I’d like to do a little bit of work because I think about 25% of 30% of our moneys are outside of our focus areas on the drilling side. So it’s in that range. We like to keep -- in the past, we tried to push usually as much as 80%. So we’re more in the 70% this year in our focus areas. And that’s -- once again, I have kept the numbers exactly where we are for the year but the plan was we were going to be a little bit lighter in our focus areas this year. Our appetite is driven by a couple of things. It’s of course the amount of money we have to spend and also the scale in the quality of the opportunity. It starts very much with quality of the rock that rock doesn’t work we don’t view the risk and the scale of the opportunity to be attractive. We don’t go there. So it’s not about acreage, it’s about quality. Preferentially, if possible, we like to be in a low-cost option situation. We like to get a nice piece of acreage with a seismic obligation and minimal or low numbers of wells to drill. And that’s particularly the case in these test areas, these areas outside of our focus areas. We don’t want to get saddled with a really large program and then draw high risk well and find out it’s not very attractive. So we tend to try to do that everywhere around the world and a lot of these opportunities that we moved into recently are very much structured that way, not a large amount of calls on upfront entry. And they have seismic obligations and small drilling obligations to answer really the geological question.

Okay. Got it. On the downstream earnings -- focus on the U.S., the U.S. downstream results, if I extract out the chemical earnings, which I guess we can get that to Phillips 66, it seems like U.S. downstream earnings are basically breakeven, even first quarter and second quarter and given the refining position and marketing position you guys have, I would have thought that there would be a lot more profitability out of these assets. So can you give us an idea of how these assets are going to deliver that level of profitability? I know you’ve talked about Richmond being down, I know some of the environmental expenses associated with that. But can you talk about how this -- taking out chemicals, how does U.S. sort of downstream perform in a way it probably should?

Right. Faisel I think the key item is one that you already mentioned for our performance in the first half and it does have to do with unit downtime. If I look at the first six months of this year and look at what our utilization rates were for our -- this will be worldwide but it’s obviously heavily influenced by the assets that we have in the U.S. If I look at our operated utilization rate for the first half, it’s running a good 10 points or so below what would have -- you would have seen on average for the 2011 or 2012 time period. And that is a big penalty to absorb from an earnings standpoint. As we go forward and we look at the second half the year, I did mention that Richmond is up and fully operational. But as we look at the second half of the year, the vast majority of our downtime is already in the rearview window at this point. So I think going forward, if we can run reliably, then you’ll have a much better outcome.

Okay great. Thanks for the time. Appreciate it.

Okay. Well I think that concludes the call for the day and I appreciate everybody’s interest in listening today and I particularly appreciate the questions that came in from the analysts. Shawn I’ll turn it back over to you.

Thank you. Ladies and gentlemen, this concludes Chevron's second quarter 2013 Earnings Conference Call. You may now disconnect.