Good morning. My name is Sean, and I will 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 speaker's remarks, there will be a question and answer session, and instructions will be given at that time. If anyone should require assistance during the conference, please press star then zero on your touch-tone telephone. As a reminder, this conference call is being recorded. I will now turn the 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'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 two. Slide three 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 four, 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 the 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 towards a more traditional net debt structure. Jeff will now take us through the quarterly comparisons.
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 increased 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 chemicals 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 a 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 $40 million. 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 Brent spot prices between quarters. The timing of liftings in Kazakhstan and across multiple other countries decreased earnings by $60 million.
Higher operating expenses due to increased maintenance activities and the startup of the LNG plant in Angola decreased 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 decreased 63,000 barrels per day between quarters. Lower prices increased volumes under Production Sharing and variable royalty contracts during the second quarter by about 5,000 barrels per day. Planned turnaround activities in Kazakhstan and Australia had the largest impact, reducing production by 45,000 barrels per day.
The base business and other bar includes normal field declines and 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, as several refineries came back online 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 plants. On slide 10, international downstream earnings improved by $62 million between quarters.
Higher volumes increased earnings by $80 million, primarily on the absence of maintenance activities at the Cape Town, South Africa, and Burnaby, Canada refineries. Higher operating expenses decreased earnings by $50 million, reflecting higher fuel usage and employee costs. The All Other includes a number of unrelated items, including an unfavorable swing in foreign exchange impacts and weaker refining margins, partially offset by positive inventory valuation effects driven by falling 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 a $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-$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. Good morning. To begin, I'd like to note the progress of our Jack/St. Malo and Bigfoot 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 Bigfoot hull, which is pictured on the left. The Jack/St. Malo tow to its location is scheduled for year-end. Jack/St. Malo and Bigfoot 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're almost $6.50 per barrel ahead of our nearest competitor. We've 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, LNG should contribute about 60,000 barrels per day to our production. We will have additional production ramp-ups from our other major capital projects, including Usan and Tahiti II.
We restarted Frade in Brazil at the end of April and currently have three 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 increased drilling activity in the Permian. These increases are partially offset by 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. We'd 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 generator for train one. 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 one modules are scheduled for delivery by year-end. We also recently completed the installation of the 20-inch domestic gas pipeline. The Gorgon team has resolved the logistics challenges they faced earlier. Additional laydown areas on Barrow Island were established, and material handling has significantly improved. Increased 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 board for Barrow Island construction. Gorgon module fabrication is progressing, and we're managing it closely.
We also continue to carefully monitor labor costs and weather impacts. In the upstream, the first five sub-sea wellheads were set. We have finished the lower completions of all the Gorgon wells and 50% of the Jansz-Io 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'd encourage you to go there and look at them. Next, I'll review progress on some of our other key developments. Wheatstone made significant progress in 2013, with the team focused on site infrastructure and upstream fabrication. We now have over 2,200 people on site at Onslow.
The offshore platform fabrication began in South Korea with the erection of the cellar deck. Offshore dredging 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 focus 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 the LNG plant and the Pacific Trail Pipeline development to Chevron. Front-End Engineering is progressing on plan. Early earthworks continue at the LNG plant site, where a total of 6.5 million cubic yards of earth and rock have to be moved. LNG marketing activities and engagement with potential foundation customers are underway.
We're focusing on Asian markets and aim to have 60%-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 specific portion of a 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 risks have largely been mitigated through government decrees and the financial structure. All in all, we're pleased with the deal and the opportunity to participate in the development of this world-class resource. The projects that have just been reviewed provide legacy growth in 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 are on plan to invest over $3 billion. We are 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 are currently drilling 10 of our 14 planned impact wells for 2013, including the second well in the Kurdistan region of Iraq, which spud on Wednesday. Now I'll highlight a few areas of new activity for 2013. We're maintaining our emphasis on the Permian portfolio, and we're increasing drilling activity in exploration, appraisal, and development. We've enhanced our position in the liquid-rich Delaware Basin and are now the largest leaseholder with significant potential in undeveloped acreage.
We've drilled our first two wells in the Utica in Ohio and are encouraged by the preliminary results. We'll provide more details on this later this year. We've added another block 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 play. Exploration and appraisal wells are in progress. We've also acquired new acreage in China, Brazil, the U.S. 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 have drilled 10 of our 13-well program. Results for these multistage 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 rates. Second, GS Caltex's Ulsan Refinery began commercial operations of the heavy oil upgrading unit, which now makes Ulsan one of the largest heavy oil upgraders in South Korea. This unit came online three months ahead of schedule. Third, our chemicals joint venture, Chevron Phillips Chemical Company, announced plans to expand its ethylene production at its Sweeny complex in Texas. I'll 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 reinvestment in our business to generate future value. We are fully committed to delivering disciplined growth and shareholder value. Now 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. Now I'd 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.
Thank you. Ladies and gentlemen, if you have a question at this time, please press *1 on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, press the # key. If you are listening on a speakerphone, we ask that you please lift your handset before asking your question to provide optimum sound quality. Again, if you have an audio question, simply press *1 on your touchtone telephone. Our first question comes from Paul Sankey of Deutsche Bank. Please go ahead with your question.
Yeah. Hi, everyone.
Good morning, Paul.
Morning. Additionally, I think there's been some legal issues around the move. Can you just underline for us why you're making a move like that at a time, as I said, when your CapEx is so elevated and where you're going to add some legal complexity that you probably really don't need? Thanks.
Well, Paul, it always starts back at what's the opportunity set out there, and how does it compete in the future? We like the Vaca Muerta opportunity from a technical point of view. When you look at it technically, this opportunity, much of the shale is in the 1,000-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. We always have, within our portfolio, some ability to spend our money in different ways. We have the ability, because of our large base business programs, that we can move some monies around. I go back to the other point would be that opportunities are there when they are available, and this one's available.
On the legal side, I would start off and say, first off, we really don't believe there's any legitimate legal claim against us. We're pretty confident about that. We think we're in a good position there. Back on the development itself, we see this very much as a staged development over a long period of time. The initial work is 100 wells, 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 to potentially an exporter of crude. Once again, the time for the opportunity is now.
Okay, George, if I could ask a follow-up?
Well, go ahead.
Sorry, I was just going to follow on with a reference, and yourself as a reference, that this is a high intensity period of CapEx with the dual Australian LNG projects above all simultaneously in your queue. Can you talk about your longer term CapEx and the potential to bring that down with a view to generating more free cash flow? Are you intending to push through to try and grow the company beyond the existing 3.3 million barrel oil equivalent target that you have for 2017? Thanks.
Well, first, Paul, I'm going to try to disconnect those two. They're not necessarily totally connected. At our March meeting when we met in New York, we told people that we see a growth beyond 3.3. We did not disclose what that 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 at that time was the growth that we saw that would be coming from our Future Growth Project and the Wellhead 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. That project is not going to be online in 2017. It contributes to significant growth.
Remember, the Tengiz project in total will add, expansion will add about 130,000 to 140,000 barrels a day of net production for Chevron. We do see growth beyond 2017. Likewise, we always see some projects that tend to move a little bit to the right, move a little bit later. 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. From that perspective, we will see some decline in our capital program in a relative sense. Remember, we're also going to be a lot bigger in the barrel side. We will have a lot more barrels, our cash flows will be high.
We've got very strong margins. We've got that combination to go forward. It's a combination of things that move around. Remember, portfolio, a lot of barrels, a lot of barrel growth, 25% growth. We're looking at holding our margins, which are industry leading. We think we will hold them. We're going to have cash flow growth and a flattening, and I would call it more a flattening of our capital program going forward.
Thanks, George, and thanks all of you. Thanks, George, for taking the time to come on the call.
Okay. Thanks, Paul. Okay, next one.
Our next question comes from Evan Calio with Morgan Stanley. Please go ahead with your question.
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. There's clearly been a lot of exciting industry results. You entered the Cimarex joint venture. I know you're building a technology center there. Can you quantify at all for us the activity ramp or potential organic growth there in the Permian Basin and how Chevron is building or expanding its Permian capabilities to run a bigger organization? I have a follow-up.
Well, 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 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. It's just a much more efficient way to develop that acreage. As we said in March, we're 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.
Mm-hmm. Just any color?
Go ahead.
Sorry. Yeah, I didn't know if there was just any color on the technology center that you're building or people addition or just what investments you're making to build an infrastructure that would support more significant organic growth there.
We will. We've committed to a tech center there. We are starting a building, a significant building project there, an office project. We've purchased land and moving forward with building that. I would also tell you, remember, we've got a big support function for that unit also out of Houston. I think we're in good shape on what we have in Midland, and we have a strong commitment. We got lots of acreage, and Midland and the Permian Basin and the Delaware Basin are long-term assets for us. I don't really have anything that's new beyond what we presented in March.
That's fair. 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? 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 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. As you know, a big project like this, there's 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're not going to know a lot more on cost till we get really much further in. We don't see any major disconnects at this point.
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're pretty close. Now we're seeing a shift in exchange rates that are positive for us with exchange rates coming down. We are in a period where we've got major expenditures in Australia. We've got a lot of moving parts there, we can always tell where we've been a lot better than where everything is going. Any issues, once again, we try to mitigate those as they go. I don't see anything major on the cost side.
It's still back to productivity. I'll emphasize it's so critical to get productivity on Barrow Island. It's important for us to have good weather. Weather is an extremely important part of our success there. We're in the good part of the year right now. Between now and December, we're outside of major weather impacts. We're in a period that we get to December, we will know an awful lot more. We're 67% now. Every time you get a little bit closer towards 100, you can do a lot better forecasting.
Great. Always helpful, George. Thanks.
Thank you.
Thanks, Evan.
Our next-
Next caller.
Our next question comes from Arjun Murti of Goldman Sachs. Please go ahead with your question.
Thank you, and my thanks for the E&P update as well. Just a follow-up question on Kitimat, where you've now had some time to look at the project. I know the two big pieces are 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 latter point, you now have Exxon with a big project in the area. I think Shell's got 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's a question as to whether there might be some linkage to Henry Hub. How are you feeling about Kitimat and its position in 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 B.C. region. This project has permits in place 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 Nations have already agreed. I think we're in quite a lead on the early part of a project. We've also done a FEED, a one-train FEED, and we're now moved into a two-train FEED to build two trains there. We've been involved in that. We do have more work on FEED, but we're moving quite well on the FEED work. I'm going to go back once again. We're in a great competitive spot on schedule.
That should help us a lot in dealing with those that want to buy gas. It puts our project, in many ways, ahead of others. For the buyers that need gas sooner, we're 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 partners as buyers. We're going to offer 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 equity participation in the Kitimat project.
We can do that because the two partners, us and Apache, each hold 50%. We hold very strong working interest in the plant and in the resources. We have that ability to move that way. Our goal is, of course, to maintain our 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 that gets us to a 60%-70% position with regards to sale.
George, just a very quick.
We have-
I'm sorry, go ahead.
We have had some initial discussions with Asian buyers. We will not disclose the ones that we're talking with at this time. We are moving that forward.
George, that's a very thorough and helpful update. Just a very quick follow-up in terms of the appropriate speed. We've always thought of this as more likely to be a 2014 FID versus 2013, 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. It will take us into 2014 to get those completed.
Thank you very much.
Our next question comes.
Hey, sorry. Go ahead.
Thank you. Our next question comes from Ed Westlake of Credit Suisse. Please go ahead with your question.
Yes, thanks very much for all of the information this morning. Just coming to the offshore, it feels as if, with a large position in the Permian and some of the LNG projects that you have, that the rise in offshore rig rates and subsea costs might mean a shift in the portfolio. I guess two questions. One is, how are you mitigating the rise? What are your view on those offshore costs, and how much flexibility do you have to sort of shift capital around to avoid that inflation? Thanks.
Well, everything depends upon the economics of the projects in our portfolio, which is nice and large. We can move monies around. I will tell 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 a production sense, high production rates, and because of that, huge upfront cash flows. These projects come in, they have relatively high DD&A rates, but you look at their operating expense, they are extremely low, and they have very strong margins. It's back to economics. I will tell you that the cost structure in the deepwater Gulf of Mexico, post Macondo, is higher. We have seen a 20%-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'll remember at our presentation in March this year and our recent press release, just around, I think also in the March period, where we talked about the performance of our single-trip multi-zone frac-pack. We had great success with that. It saved us anywhere from 20-50 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 initial test of the well after that, we had very high rates. I'm going to take you back. It's back to what do we think we can get on a value proposition? We've got the people to do the work in the deepwater Gulf of Mexico. We got the org capability also onshore.
We will make choices on that, but it comes heavily back to the technical quality of the asset itself.
Some people have deferred projects, but at the moment, the rig rates and subsea are not expensive enough given technology for you to do the same. Is that what I'm hearing?
Our view of Jack/St. Malo today, on an economic basis, is stronger than when we went to FID. Our project view is 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 when the Jack/St. Malo, we talked only of about a 500 million barrel type recovery for those two fields, and that was an 8%-10% recovery rate. We're focusing on those technologies that can change that recovery rate and potentially raise it up to over 20%. When you have the infrastructure in place already, that additional production and additional recovery is frankly very economic.
Thank you, George.
Each one of them is a decision into itself. We have to have confidence in how much we're going to produce, and we have to also have confidence, and when we reach FID, we do have confidence in how much we will spend to get that return.
Very clear. Thanks, George.
Okay, Ed. Thank you.
Okay, next caller.
Our next question comes from Douglas 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's a lot of stuff coming into the portfolio on the margin anyway that wasn't in the original plan, for example, the Permian Basin. I'm trying to understand, are things slipping to the right, as you mentioned in your prepared remarks? Is spending basically making up the difference? Maybe just an 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 could just give us some flavor as to whether or not you think that is a sustainable level of spend.
Well, let me go back and say there are things that we had talked about. I gave the example of the future growth, the expansion in Tengiz as moving to the right. When it moved to the right, when it moved later, it did move capital that way also. We look at these portfolio additions on the strength of them. We don't only think about our investment ratios in a 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.
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. 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. 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-wide assets.
Maybe I could do my follow-up with Pat as a related question. Pat, you obviously have a lot of capital on the balance sheet that's not generating earnings at the moment. What is your expectation for that trend? Does the proportion of capital rise or fall over the next several years? Non-producing capital, I mean. Thank you.
Right. I think consistent with where George was going, 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 online. 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. That's obviously a significant component. Until you get those projects online, we're going to have relatively high pre-productive capital. Once those projects become online, of course, we anticipate that that proportionality will decline.
Ed, I'd just like to make one 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. Even with that, you look at the return on the capital employed in total, we are leading in our segment. That tells you where we've invested and the performance of that portfolio is very strong. 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 new bit of this from a strategic standpoint. You've been looking at Kitimat. In order for you to become a really great project, you probably look beyond just train one or two. Don't know whether that you really have sufficient gas resource up there yourself. Strategically then, how sure are you? Look at it, so you will be just essentially say, "Okay, I have gas resource for the first two train, and I get it going, and then subsequently I will be just be the owner of the train and not necessary need to be the owner of the natural gas and just point at other people gas," or that you actually think that it's important for you guys to be fully integrated?
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. 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. 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 two-train plant. A two-train plant is more likely to be in the 15 Tcf of gas required. Bottom line, we are not short of gas at all in the Kitimat development.
Our issue is to get the 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 really get past having the first two trains, once again, sold from a market point of view and then get them post FID.
I guess my question is that in the event if those huge number that talked by Apache did not materialize and end up to be smaller, we need that to have an integrated model that including the ownership and the resource?
Yeah, I think we need that to have surety of the supply to feed the plant. We're quite confident at this point for the first two trains. We've done enough work that our confidence is high and 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. I will tell you, all my engagement with our partner, our partner is quite confident in the quality of this resource.
The second one. George, can you give us some rough idea that based on your drilling result, how's the net rate? Whether it's the black oil, condensate, or NGL, what kind of split we are talking about in the Permian Basin that you are drilling right now, as well as in 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. When I say 50% liquids, looking at really the oil and condensate side. Pardon me, LPG is not what I'm speaking of. It's over 50% BOE in liquid, the oil and condensate side. That's why we like it so much. That really carries a lot of value. In the Utica, I'm not really prepared to give you those numbers. I will 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.
We should be prepared in a little bit later in the third quarter to give a little bit more information on the Utica. Like I say, it's just a little bit early. I would also tell you, probably at the 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 on this additional 67,000 acres up in the Duvernay. I would tell you also, maybe as a general comment, what we've tried to do everywhere 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 makes sense for us not to get our disclosures out in front of where we're trying to move from a commercial point of view.
We feel very good about where we are in the Permian Basin, and my expectation is if we have other opportunities like Cimarex, we will make those happen too. 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. You understand how the rocks are and really how much of the volume is going to be oil or gas.
George, is Permian a primarily black oil or just primarily condensate for you?
The Permian is primarily oil.
Black oil for you.
Thank you.
Thank you.
Yes. 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 wanted to follow up on LNG marketing, which has been raised by a 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, and how do you prioritize getting one into the market versus the other? Then just related to that, what's your 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. Gulf Coast?
A lot of questions there, Jason. I'll try to hit those. I'll start off with contrasting maybe our Gorgon Train 4 versus what we have at Kitimat. First difference is scale, to the buyer, we have a bigger offering of volume. We have 11 million tons with two trains. We are doing the joint marketing, so we have 11 million tons there on offer that will be available. Once again, we want to have 60%-70%, and we would be willing very much to move up to the 80% at the time of startup. In the case of Gorgon Train 4, it's a 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 will be marketing about 47% of the gas, and ExxonMobil and Shell each have about 25%.
It's a much smaller volume to move for us. The plus for Gorgon is you are brownfield. You've got an advantage on the plant side. Depending upon where we're going in Asia, there is no difference in transportation in distance and cost from going to Kitimat or coming from Australia. 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 a positive for us there. Volumetrically, it's positive. We do think from a development cost the development cost at Kitimat on the upstream may end up being less than in the case of Gorgon. Gorgon has a 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, 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's a different alignment there. We're happy to see both of them move. They are a little bit of a horse race between them at this point in our own shop. East Africa, I didn't mention, I thank people here for reminding 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. I think we do have a timing advantage on both of those projects to first gas. Like I say, Gorgon, we know we've got all the gas.
Kitimat, we're confident we've got all the gas for two trains. I think we have a little bit of an advantage there. We do know our fiscal regime and regulatory regime in both the locations in which we operate very clearly.
Okay. Thank you, Jason.
Our next.
Next question. I think we have time for a couple more questions.
Okay, our next question is all set from Ian 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 dividends significantly more than you're generating in cash flow at the moment, the buyback is kind of accelerating that process into net debt. At 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're aiming for? 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, 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 is. 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. 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 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. We have tremendous additional leverage capacity, as you well know. If we're sitting here today with a 12% debt ratio, we have a long way to go before being over-levered becomes one of our problems. 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. Could 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 there? I wonder if you could also comment on Chevron's view of the pre-salt round coming up in Brazil.
Okay. Frade, as you said, is part of that addition in the second half. We had no production in Frade in the first quarter. Second quarter, it averaged about 5,000 barrels a day, our share. The month of June, we were closer to 10,000 barrels a day, our share. There is some expectation there that we will grow in the second half, or we'll have more volume in the second half on Frade. Not too far off from our original plan. The field's 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 on this year, but it's late in the year, so we do not believe that it will be significant mover on our production for the year.
With regards to the deepwater round, as on all our exploration opportunities, we review the opportunity set, and we never disclose 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 time for one more question.
Okay. Our final question comes from Faisal Khan of Citigroup. Please go ahead with your question.
Thanks, guys. Good afternoon. Just on the key exploration wells and acreage additions, it seems like you guys definitely added a good amount of acreage during the year and a few bolt-on acquisitions. Can you just give us an idea of how much of that is your capital budget has that made up, and what's your appetite going forward? I just have one follow-up on the downstream side.
Right offhand, I'd have to do a little bit of work because I think about 25% or 30% of our monies are outside of our focus areas on the drilling side. It's in that range. In the past, we've tried to push usually as much as 80%. We're more in the 70% this year in our focus areas. Once again, I haven't looked at 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 and the quality of the opportunity. It starts very much with the quality of the rock.
If the rock doesn't work, we don't view the risk and the scale of the opportunity to be attractive, we don't go there. It's not about acreage, it's about quality. Preferentially, if possible, we like to be in a low-cost option situation, i.e., we like to get a nice piece of acreage with a seismic obligation and minimal or low numbers of wells to drill. 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 drill a high-risk well and find out it's not very attractive. We tend to try to do that everywhere around the world. A lot of these opportunities that we've moved into recently are very much structured that way. Not a large amount of costs on upfront entry.
They have seismic obligations and small drilling obligations to answer really the geological question.
Okay, got it. Just on the downstream earnings results, first focus on the U.S. downstream results. If I extract out the chemicals earnings, which I guess we can get that through Phillips 66, it seems like U.S. downstream earnings are basically break-even, even first quarter and second quarter. Given the refining position and marketing position you guys have, I would've thought that there'd be a lot more profitability out of these assets. 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. downstream perform in the way it probably should?
All right. Faisal, 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 rates for the first half, it's running a good 10 points or so below what you would've seen on average for the 2011 or 2012 time period. That is a big penalty to absorb from an earnings standpoint.
As we go forward and we look at the second half of 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 rear view window at this point. 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. I appreciate everybody's interest in listening in today. I particularly appreciate the questions that came in from the analysts. Sean, 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.