Chevron Corporation (CVX) Q2 2012 Earnings Report, Transcript and Summary

Good morning. My name is Kevin, and I'll be your conference operator today. Welcome to the Chevron Second Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to the Vice President and Chief Financial Officer of Chevron, Ms. Pat Yarrington. Please go ahead.

Great. Good morning, and thank you, Kevin. Welcome to Chevron's Second Quarter Earnings Conference Call and Webcast. On the call with me today are George Kirkland, Vice Chairman and Executive Vice President of Upstream and Gas; and Jeanette Ourada, General Manager, Investor Relations. 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 on Slide 2. Slide 3 provides an overview of our financial performance. Financially, it was a strong quarter. The company's second-quarter earnings were $7.2 billion or $3.66 per diluted share. Comparing the second quarter 2012 to the same quarter a year earlier, our earnings declined 7%. Upstream was down on lower crude prices and volumes, while Downstream benefited from improved margins and gains on asset sales. Return on capital employed for the trailing 12 months was about 20%. Our debt ratio at the end of June was 7.3%. In the second quarter, we repurchased $1.25 billion of our shares. In the third quarter, we expect to repurchase the same amount. Relative to our peers as of June 30, we hold the #1 ranking in total shareholder return for the 3-year, 5-year and 10-year periods and actually, for every period in between. We believe this clearly demonstrates the long-term value we are creating for our shareholders. Turning to Slide 4, cash generated from operations was almost $10 billion during the second quarter. At quarter end, our cash balances totaled over $21 billion. This puts us in a net cash position of $11 billion. Jeanette will now take us through the quarterly comparison. Jeanette?

Thanks, Pat. Turning to Slide 5. I'll compare results of the second quarter 2012 with the first quarter 2012. As a reminder, our earnings release compares second quarter 2012 with the same quarter a year ago. Second-quarter earnings were $7.2 billion, over $700 million higher than the first-quarter results. Upstream earnings were down $551 million on lower crude oil realizations, partly offset by favorable foreign exchange effects. Downstream results improved $1.1 billion between quarters, driven by better margins and favorable inventory effects. The variance in the Other bar reflects lower corporate charges and a favorable swing in corporate tax items. On Slide 6, our U.S. upstream earnings for the second quarter were $211 million lower than the first quarter's results. Combined liquids and natural gas realizations reduced earnings by $145 million. Chevron's average U.S. crude oil realizations decreased 4% between consecutive quarters, substantially less than the roughly 9% drop in average WTI spot and posted Midway Sunset prices. Gulf of Mexico realizations actually increased between quarters due to the monthly lag on pricing of HLS, Mars and LLS. Natural gas realizations also dropped, decreasing 13% between quarters. Higher production volumes, primarily in the Gulf of Mexico and California, increased earnings by $40 million between periods. The Other bar reflects a number of unrelated items including incremental abandonment costs due to 2005 and 2008 hurricanes and higher exploration expense. Turning to Slide 7. International upstream earnings were $340 million lower than the first quarter. Lower realizations reduced earnings by $525 million. Liquids realizations decreased 10%, in line with the decrease in average Brent spot prices. Partially offsetting were higher natural gas realizations, which increased earnings by $25 million. Lower liftings, mainly in Brazil and Australia, decreased earnings by $130 million. Higher operating expenses reduced earnings by $40 million, reflecting higher costs across multiple categories. Moving to the next bar. A favorable swing in foreign currency effects increased earnings by about $425 million. The second quarter had a gain of $219 million, compared to a loss of $208 million in the first quarter. The total year-to-date impact is a favorable $11 million. The Other bar reflects a number of unrelated items including higher exploration expense. Slide 8 summarizes the quarterly change in Chevron's worldwide net oil equivalent production. Production decreased 7,000 barrels per day between quarters. Lower prices increased volumes as the production sharing and variable-royalty contracts during the second quarter, increasing production about 7,000 barrels per day. Average Brent spot prices decreased about $10 per barrel between quarters, which resulted in about a 700 barrel per day volume increase for each dollar decrease in Brent. Moving to the next bar, our Frade field in Brazil remained shut in for the quarter, reducing production by 25,000 barrels per day. Recall in mid-March, the Frade field shut down as a precautionary measure. It remained shut down throughout the second quarter. Base business production decreased 30,000 barrels per day, largely driven by lower Tengiz volumes due to a planned KTL turnaround, a shortfall in rail cars resulting from railroad repairs at the Russian border and lower processing efficiency. Incremental production for major capital projects benefited second-quarter production by 41,000 barrels per day, primarily driven by ramp-ups at Usan in Nigeria and Caesar/Tonga in the Gulf of Mexico. Next, let's move to downstream. Turning to slide 9, U.S. downstream earnings increased $343 million in the second quarter. Improved margins increased earnings by $275 million, driven by significantly better marketing margins in the West Coast and higher refining margins on both the Gulf and West Coasts. Industry refinery maintenance in both regions and continued strong product export demand on the Gulf Coast, combined with a rapid drop in crude prices, generated higher margins. Higher operating expenses decreased earnings by $35 million, resulting from higher costs across multiple categories. Timing effects represented a $130 million positive earnings variance between quarters, primarily driven by favorable mark-to-market effects on derivative tied to underlying physical positions. The Other bar consists of several unrelated items. On Slide 10, international downstream earnings were $734 million higher this quarter. Refining and marketing margins rose, increasing earnings by $305 million. This resulted from the absence of first-quarter planned turnaround activities in South Korea and from declining crude price impacts across the system. Inventory effects increased earnings by $325 million, primarily due to falling prices in the second quarter, following rising first-quarter prices. Recall in the first quarter, I called out a $225 million negative earnings variance due to unfavorable inventory impacts. The net impact for the year is a $29 million positive impact to earnings. Gains from asset sales were slightly lower, decreasing earnings by $15 million. Approximately $200 million of gains on assets in the second quarter nearly matched first quarter's gains on asset sales in Spain and Canada. The Other bar reflects a number of unrelated item including higher volumes, improved trading results and lower turnaround costs. Slide 11 covers all Other. Second-quarter net charges were $291 million, compared to a net $504 million charge in the first quarter, a decrease of $213 million between periods. A favorable swing in corporate tax items resulted in a $77 million benefit to earnings. Corporate charges were $136 million lower in the second quarter. Year-to-date, corporate charges were $795 million. We believe our quarterly guidance range of $300 million to $400 million for net charges in the All Other segment is still appropriate going forward. George is now going to provide an update on our upstream operations. George?

Thank you, Jeanette. It's good to be back to discuss upstream performance and to provide an update on our operations. I'll begin by looking at our second quarter competitive position on earnings margins. So far this year, upstream margins were approximately $26 per barrel. Although not all our peers have announced second quarter results, we expect to continue to lead our competitors in this key metric. Based on the peers that have reported through the first half, we are almost $7 per barrel ahead of our nearest competitor. We have now held this top position for 12 consecutive quarters, reinforcing the quality of our investment decisions, the strength of our portfolio and the consistency of our performance. Next, let's look at returns. Our investments continue to deliver superior financial performance. For the second quarter, our return on capital employed was 25%. This, too, is expected to rank at the top of our peer group. Now I'll turn to 2012 production. Please turn to Slide 14. Our first half production averaged 2.63 million barrels a day at an average year-to-date Brent price of $114 per barrel. Based on the results to date, we are lagging the full year production guidance we gave you in January of 2.68 million barrels per day. There are 4 key drivers that will impact our full year production results. First, the Frade field has been shut in since mid-March. We are conducting an extensive technical evaluation of the area. Once all the technical evaluations are complete, partner support is in place and we obtain regulatory approvals, production is expected to restart and ramp up over time. Timing of the restart remains somewhat uncertain. Second, we have our first major turnaround at Tengiz SGI/SGP, and this is scheduled to start early in August and last for 6 weeks. The turnaround involves more than 6,000 workers. It includes normal inspections and repairs of equipment to maintain mechanical reliability and integrity. We will also take the opportunity to make improvements that are expected to slightly increase production capacity over the next few years. Next, we had commissioning delays at Angola LNG. We originally planned to start up in the second quarter. Commissioning activities are underway, and we've completed LNG berthing trials and LNG tankers are available for third-quarter cargoes. We are currently expecting the first cargo in September. Also influencing our production this year, and I mean in a positive way, are several MCPs that started up early relative to our plan. We have been pleased with their performance. Currently, we're performing at 98% of our initial guidance. And based on the items we just discussed, enough uncertainties remain so that I expect we will end the year slightly under our target. More importantly, our long-term guidance remains intact. Looking to 2017, we continue to expect production to grow to 3.3 million barrels per day at a Brent price of $79 per barrel. Now let's turn to Slide 15. We have an active year of exploration, and we plan to invest nearly $3 billion. The Gulf of Mexico is a key focus area for us where we continue to build our portfolio of prospects. During the recently sale, we were apparent high bidder on 15 deepwater blocks and 15 shelf blocks. We are currently drilling the Coronado well in the deepwater and the Lineham Creek well and ultra-deep Wilcox gas play on the Gulf of Mexico shelf. In another key focus area, Australia, we recently announced the Pontus-1 Carnavon Basin discovery, the fourth successful discovery out of the last 15 wells. We have several more exploratory wells to be drilled in Australia this year. We are also actively pursuing new test areas. One is South America, West Africa cretaceous play. We have an active drilling program in Liberia where we are on our second exploration well. And we recently acquired additional acreage in Suriname. We made a new entry in the Kurdistan Region of Iraq. This acreage is in the appraisal and exploration phases, which is consistent with our strategy of seeking early opportunities. We are also progressing our unconventional portfolio. We have drilling activities in the U.S., both in the Permian Basin and the Marcellus, the Canadian Duvernay, Poland, Argentina and China. In the Ukraine, we were awarded a tender that gives us the right to negotiate a production-sharing contract for 1.6 million acres. This acreage is on trend with our Poland and Romania acreage. Next, we'll talk about our progress on major capital projects. Please turn to Slide 16. We continue to see good performance from our first quarter start-ups, Usan, Tahiti 2 and Caesar/Tonga. In the second quarter, we achieved start-up of Agbami 2. We have brought online 1 new producer and 1 water injection well. Our plan includes 10 wells in total, 6 of which are producers. We reached a Final Investment Decision to expand our Bibiyana natural gas field in Bangladesh, where we have a 98% interest. This new project will include expansion of the gas plant to process increased gas volumes from the Bibiyana field, additional development wells and an enhanced condensate recovery unit. The project is expected to boost Chevron's total natural gas production capacity in Bangladesh by more than 300 million cubic feet per day to 1.4 billion cubic feet per day. Our start-up is expected in 2014. We entered front engineering and design for the Rosebank Project in the U.K. This is our first operated development in the west of Shetlands basin. This field holds significant potential with estimated total potential recoverable oil equivalent resources of 240 million barrels. Turning to Slide 17, I'd like to give you an update on our Australia LNG projects. Let's start with Wheatstone. We made a Final Investment Decision on Wheatstone last September. We have achieved our key milestones for the year. We have completed the pioneer camp with 100 beds and continue work on phase one of the fly camp, which will add an additional 500 beds. We currently have about 300 workers on site. Just this month, we cut first deal on the platform top sides in the DSME fabrication yard in South Korea. We now have long-term contracts in place for over 80% of our equity LNG volumes. The remaining activities for 2012 focus on detailed design and preparing for plant site works to commence in the fourth quarter of this year. To date, approximately $15 billion in contracts have been awarded including more than $7 billion in local Australian contracts. The contracts are a mix of lump sum, reimbursable time and material and unit rate. During the quarter, we signed a non-binding Heads of Agreement with Tohoku for LNG offtake. We also executed an equity Sales and Purchase Agreement with TEPCO, bringing Chevron's interest in the offshore platform and facilities downstream of the platform to 64% and our interest in the upstream permits to 80%. We do not intend to farm down any further. With this sale, Chevron's net capital investment is expected to be about $20 billion. We're in the process of obtaining final government approvals of this sale. Now let's turn to Gorgon. Please turn to Slide 18. Gorgon achieved FID in September 2009 and is now over 45% complete. We're making good progress on our 2012 milestones. In June, the first 4 pipe rack modules arrived on Barrow Island. In July, construction began on the domestic pipeline. Next month, the first plant equipment module is expected to arrive. And later in the year, we expect to start installation of the Train 1 compressors. I'd like to update you also on a few areas -- additional areas of progress. Through design optimizations, we have upgraded the nameplate capacity of the individual trains to 5.2 million tons per annum for a total of 15.6 million tons. This is a 4% increase in capacity. Fabrication and delivery of modules are on track. We have completed 2 of the 3 main berths at the material offloading facility, allowing efficient simultaneous offloading of modules and other construction materials. Two LNG tanks are under construction, and we've completed all 14 ring sections of the first tank. The roof is now structurally complete and is ready to be floated into its final position. This strong progress on the tanks has taken them off the critical path, which is unusual for an LNG project. We have drilled 8 of the 18 development wells, 7 in Gorgon and 1 in Jansz, and we're pleased with the sub-surface results we're seeing. Progress on the upstream facilities and subsea pipelines are on plan. We posted several photos of our progress at Gorgon on the web page, chevron.com. You will see links on the home page and Investor page called Gorgon progress photos. I encourage you to check in occasionally, as we will periodically update Gorgon project pictures. Moving to Slide 19. We've received many questions about Gorgon cost. We want to be responsive as we can and provide the insights we can with the information we have to date. As you are aware, the project was sanctioned in 2009 at USD 37 billion and at the current exchange rate at the time of USD 0.86 to the Australian dollar. The stacked bars chart shows the budgeted cost at FID and how they were broken down, 30% upstream and 70% downstream. We have now awarded more than $28 billion in contracts with more than half to local contractors. The contracts include a mix of lump sum, unit rate and reimbursable time and material. The contract mix will change over time as contracts are completed and/or converted. Procurement and fabrication, along with the upstream component, are mostly non-Australian-dollar-based. These are the top 2 seconds on the stacked bar. The other component shown on the bar chart are primarily Australian-dollar-based. Overall, about half of the total costs are in Australian dollars. Procurement and fabrication and the upstream components are on plan in terms of both cost and schedule. Regarding logistics, the 5% component, we have 3 primary supply bases. Activities at the Dampier and Perth supply bases are meeting or exceeding plan. However, the Australian Marine Complex at Henderson, which handles transshipment of larger cargo, has not been as productive. To mitigate, we are streamlining our logistics processes and have added additional resources. We have a strong focus on insuring critical materials arrive in sequence and on time to support construction activities. Looking at the construction and labor segment, we have experienced some delays due to weather. We are still in the early stages of our on-island activity, and we'll need several months on Barrow Island to assess labor productivity. Remember that by design, the project is modularized to limit on-island activities. We've also seen Australian labor costs trending higher. This could impact both construction and management services. Because there are a number of variables in play, we currently have a detailed cost review underway. We're evaluating our performance to date and incorporating new information to update our expectations for the remainder of the project. Over the next few months, our assessments will help us gauge movements in costs, which we expect to provide towards the end of the year. I would like to emphasize that our view of the Gorgon project has only been enhanced since FID. I remain very confident in the economics and the value created by this project. While we are seeing cost pressures, in large part associated with a 20% strengthening of the Australian dollar, it's important to note that oil prices, which determine the project's revenue stream, are about 60% higher than at the time of project sanction. Further, the development well results to date are encouraging, which has greatly reduced the reservoir uncertainty. We've increased the capacity of the foundation project by 4%, and we continue having success with our exploration program, providing us with confidence that we will have additional gas volumes to support further expansions at Gorgon. With that, I'd like to turn it over to Pat.

Okay. Thank you, George. I'm turning now to Slide 20. George has provided an update of recent progress on upstream and exploration activity, so I won't comment further on the left-hand side of the chart. In the downstream, CPChem initiated front-end engineering and design on our Gulf Coast petrochemical project. Initial contracts for design of the derivative unit and the ethane cracker have been awarded. We continued our downstream portfolio rationalization efforts, completing the sale of our fuels marketing and aviation business in the Caribbean, along with the power operations of our GS Caltex affiliate in South Korea. And earlier this week, our 50% affiliate, Caltex Australia Limited, announced plans to restructure its supply chain, which will include the conversion of the Kurnell refinery in Sydney to an import terminal. Caltex will continue to operate the Lytton refinery in Brisbane. In support of this restructuring plan, we have entered into a long-term agreement with Caltex to supply transportation fuels at market-based prices. Given the timing of this announcement, the financial impact of this decision will be recorded in the third quarter. We don't expect the impact to be material to our results. Turning to Slide 21. I'd like to close with a few important points. First, 2012 is all about execution for us. We know that and, we're executing well. We continue to progress our major capital projects, both upstream and downstream. Second, our Australian projects remain squarely on track. George gave you more insight on the progress we're making at Gorgon and Wheatstone. I encourage you to view the Gorgon photos on our website. We did not talk specifically this morning about our 2 major deepwater projects in the Gulf of Mexico that are under construction, Jack/St. Malo and Big Foot, but both of these projects remain on schedule and on budget. And it is these 4 projects that form the cornerstone of our production growth mid-decade and beyond. Third, we delivered a strong financial performance in the second quarter. Earnings and cash generation for the quarter were amongst our strongest ever. And if you look at the first 6 months of 2012 as a whole, where foreign exchange and downstream timing effects each largely net out, you will note the quality of our earnings. Both upstream and downstream segments are delivering leading earnings per barrel and ROCE, compared to the peers who have reported so far this earnings season. At the 6-month mark, Chevron's upstream is #1 on both of these measures, and Chevron's downstream is #1 on both of these measures. An investment in Chevron offers many advantages: a very compelling growth story beginning mid-decade; hugely competitive cash and earnings margin; margins we believe will be supported in the future by the quality of investments we're making today; and the sustained growth pattern on dividends, which are yielding 3.3%. We believe we are well positioned for strong cash generation in the years to come, and with that cash generation, our capacity to increase dividends and maintain peer-leading total shareholder returns is enhanced. Now, that concludes our prepared remarks. We'll welcome your questions. [Operator Instructions] We will ensure everyone gets a chance to ask a question even if we need to run over a few minutes. Kevin, please open the lines for questions.

[Operator Instructions] Our first question comes from Doug Terreson with ISI Group.

I have somewhat of a strategic question and specifically one with regard to portfolio management where you guys have had extensive activity during the past decade in the refining and marketing business, and your returns have clearly increased. But at E&P, while, I realize that your returns are already about the highest in peer group, as Pat and George pointed out, it seems like that might be an area of opportunity for the company over the next couple of years. So I just want to see if we could get an update on your thinking or strategy in this area? And whether or not you even consider the opportunity to be meaningful for Chevron given your return level?

Doug, are you asking us about expectations for E&P asset restructuring and portfolio divestment?

Along those lines. I mean there's always areas of underperformance or declining strategic importance. And it seems like you've rationalized a lot more in the downstream than the upstream, and is this an opportunity for you over the next couple of years until the big wave of growth is present?

Doug, let me take that. First off, I would take you to our earnings per barrel and where they stand relative to everyone else and what that means for our portfolio. The average of our portfolio has got a significant shift, if you will, to the right versus what's out there. We always are upgrading our portfolio on a continued basis, looking at the tail end of the portfolio, looking at those pieces that are not performing that well. An example, of course, is Alaska. We sold over 20,000 barrels a day in Alaska that went off our books in December of last year. So that was an opportunity that we took. What we also looked at -- is there anything when we do that, that we can do with that money that gives us better assets? And I would tell you one other thing we look very carefully at, we try to make sure that anything we sell doesn't have future opportunities related to different stratigraphic levels on that acreage. And very importantly, that we -- it doesn't have a technology opportunity to unlock more barrels. We find if you sell out of a place, then you lose that opportunity. It's really tough coming back and buying the same acreage back because you exited too soon. So I would tell you we're cautious, but we do cut off that poor part of our portfolio, and we usually get good prices for it.

Yes, you're clearly in a high-quality position.

Our next question comes from Ed Westlake from Credit Suisse.

Thanks very much for all the details on Gorgon. We're going to be watching that website closely. Just -- you spoke about talking about releasing costs at the end of the year, and we can do some maths given the details you've given. But you've also spoken about weather impacts and logistics learnings. Maybe if you could sort of assess for us the risk of start-up delay at Gorgon as you see it today?

There's, Ed, always risk with every project. I mean, every big project like this is a constant mitigation of things in the project materials, equipment, contracts that could impact the critical path. And I think we do really a good job of trying to mitigate those issues and keeping any problem off of the critical path. We still believe we're going to make the 2014 start-up. We look at it very carefully every month all the way through the chain. I mean, me and John look -- we spend a good amount of time every month on these projects with our team. So we got great focus on it. We got good people -- very good people in Australia on our project teams focused on delivering, and they're very good at dealing with the mitigations to try to move us and hold us to that schedule. At this point, we still think we're on the 2014 -- the late 2014 schedule.

And just a follow-on in terms of Wheatstone. So, say you get to the end of 2012 and you can sort of make an update on costs for Gorgon, would we presume, given the amount of effort that you have to put in, that you might be able to be able to narrow down costs and start up timing for Wheatstone end of 2013? And then you'll have substantially derisked the CapEx and start-up for investors?

First, let me -- where we are on Wheatstone is much earlier in cycle. Remember, Wheatstone's 2 years behind. So in 2013, we are not going to be as far along. We will be telling you every time -- every quarter and every update where we stand on percent complete and how we're doing. We're going to provide similar kind of informational Wheatstone progress and milestones as we are on the case for Gorgon. We will be more knowledgeable at that point in time, but we won't have the same knowledge level since Gorgon is once again 2 years out in front. I will tell you one other item on -- specifically on Wheatstone. Wheatstone, when we authorized that project for the Final Investment Decisions, we had used a different exchange rate. We used parity between the U.S. dollar and the Australian dollar at authorization. So we don't see at this point in time the Australian dollar or the foreign exchange impact hitting us on Wheatstone. Well once again, we have to make the same commitment on Wheatstone we have on Gorgon. We are going to give you very detailed updates at every opportunity.

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

George, 2 questions, if I may. The first one is, you've kept again your $79 oil price assumption when you talk you about your production target on 2017. I'm just curious that if oil prices had to be substantially higher, let's say $100 or something like that, I mean, you could pick a number. I realize that the strategy that you laid out, that it doesn't necessarily impact the PSC production type of an issue. But what I'm particularly curious about is what it means in terms of production cliffs as you work through costs recovery because clearly oil prices already have been substantially higher. I guess my question is, because you've accelerated or realized a lot of revenue much earlier than you would have done at $79, can you give us a road map as to whether there are any major production cliffs on your major PSCs? And I've got a quick follow-up please.

I think we've been consistently saying we, one, would be telling you if we saw cliffs. We have not seen any of those in the near term. We don't see any of those. We have, in our estimate that we give once every quarter of price impacts, we tell you what it is, and any movements in our PSCs are included in that. Most of the cliffs that I think we have seen in the past, we are past and we will give warnings if we see future ones. I hope that answers your question.

Well, if I may, George, what I'm really getting at is that if you're assuming $79 for the next 6 years, and it turns out to be $100, it's the future cliffs I'm really talking about with that $20 difference, is there any meaningful changes vis-a-vis $100 versus, let's say, your $79 assumption?

No, we don't see any meaningful ones at this point in time. And if we do in the future see any, we will give you warning or information on that.

Okay. My second one is really hopefully fairly quick. Unit margins, obviously, continue to be very strong. We monitor, I guess, we kind of call it a capture rate, we monitor your weighted revenues and your unit earnings. And it looked like that actually dropped a fair bit this quarter relative to the recent trend. Is there anything unusual that you can point to? Have you seen the same thing, or any commentary you could offer there? And I'll leave it at that.

Our correlations, it still looks pretty good and consistent with the past history for us. There are always going to be some ups and downs when you look at quarters on -- one quarter may have a well write-off or it may have G&G effects in it that may move it around a little bit. But the early stuff that I've looked at, I don't see anything.

Our next question comes from Arjun Murti with Goldman Sachs.

George, thank you as well for the detailed budget breakdown for Gorgon. My question related to that is, can you talk about what type of contingency was reflected in that original budget? Did you have a 15% to 20% contingency for potential cost overruns? Obviously, the FX movement is pretty straightforward. But I'm wondering if there is some wiggle room either within contingency or some of the other buckets?

Yes, we did have contingency, but we do not ever disclose what that contingency is or was. We'll be able to give you a lot more information about where we think this project is going, I think, towards the end of the year, after we finish our reviews of cost and schedule.

That's great. And maybe a related follow-up is if you've awarded $28 billion of contracts, presumably that's primarily on the facilities and the -- what you call here procurement and fabrication, can we think about that portion therefore basically as being derisked? And then we are kind of just down to the labor productivity and the FX and weather you've mentioned here? Can we think about the facilities and procurement as being derisked now?

Yes, in my statement, I tried to cover particularly a portion of that and particularly looked at even full upstream portion and the equipment and the fabrication area. We have good confidence in that. We think those -- we know a lot about those costs. We feel extremely good about our upstream costs on the well side, the drilling side. And matter of fact, all the upstream costs look to be very much in line with our expectations. What we don't know is we don't know labor productivity. We're getting some indications now because we've got the 2 tanks going up quite nicely. But then, we've got foundation work and a lot of underground. So we've got an awful lot of work before we even get to mechanical piping and instrumentation and electrical tie in. So that piece, we just don't know, and we'll have a better feel for it as we get to the end of the year. But we just don't have enough run time to know that. And a lot of our costs, a lot of our costs are -- as we've mentioned, 50% of our costs are in Australian dollars, and a significant portion of that, once again, is related to on-island work. Now remember, we tried to minimize that as much as we could by bringing in modules. That's what we got big pipe rack modules coming in and big process modules coming in with a lot of work to minimize that on-island work.

Our next question comes from Jason Gammel with Macquarie.

George, I wanted to ask a couple of questions about activity in the U.S., maybe start with deepwater Gulf of Mexico. You did mention that Coronado is drilling and that Jack/St. Malo are essentially on schedule. Do you feel like you're essentially now fully back to work there? And can you maybe talk about the production levels in the Gulf of Mexico? And whether you may be seeing an inflection point and would hope to grow from the levels that you're at right now?

Okay. Jason. We have 5 rigs -- deepwater rigs running in the deepwater Gulf of Mexico. This is the most rigs we've ever run in the deepwater Gulf of Mexico. This is more than before the Macondo incident. Four of our 5 rigs at this point in time are supporting major capital projects. The Discoverer Clear Leader is on the Jack -- on a Jack-producing well. The Discoverer Deep Seas is on the Tahiti -- on a Tahiti development well, the Tahiti 2 development well. The Deep Seas is, like I just mentioned, let me go back in and say, we've got Clear Leader on Jack. We've got Deep Seas on Tahiti. We got the Inspiration, which is another Discoverer -- is another Transocean rig is completing the St. Malo production well. Then we have a rig on the Discoverer India. That's on the Big Foot. So 4 development projects, 4 of our rigs. We have 1 rig, the Pacific Santa Ana drilling on the Coronado exploration well. And this is the second time we've been at Coronado. We had some difficulty with the first well there. So we're at Coronado on exploration. Jason, actually, we have more activity we'd like to do on the exploration side. We're limiting ourselves to 5 rigs. It does take an awful lot of technical people to really push all these permits through the system. So we're -- I think we're close to what we can do on that. With regards to production, down the road, we're going to see production growth because we've got so many of these large projects coming on. Remember, 2014 is our target start-up for Jack/St. Malo and also for Big Foot. And we are -- the work we're doing right now at Tahiti 2 is to get access to more resources and reserves there to hold production and limit decline rates there. So my expectation is growth. Just a reminder, Big Foot is a 60,000 to 70,000 barrel a day type opportunity where we hold 60%. Jack/St. Malo is 120,000 to 150,000 kind of barrel facility, and we hold 50% of Jack and 51% of St. Malo. So all of these projects are very significant. Like Pat said, these are very significant projects and they're 2014. And once again, they look to be on schedule and on cost.

Appreciate all that, George. I realize it was a multipart, but maybe if I could just sneak in one more. You mentioned the Lineham Creek well. Can you to talk about the potential you see in the lower Wilcox ultra-deep from a resource standpoint, and how you're dealing with the technical challenges there?

I think at this point in time, it's a belief for us, like you normally have in exploration, we have existing leases and have acquired in recent lease sales additional leases where we believe that trend on the shelf could be productive. I'm going to hold on how big it could be until we have some results. We are encouraged by what we've seen in the industry, some of the industry wells in that -- for that trend. But once again, we've got to drill the wells to see. And we'll speak more of it -- I'd rather speak more of it after I have some results.

Our next question comes from Robert Kessler with Tudor, Pickering, Holt.

A couple of questions on the numbers for Gorgon. How much have you spent to date on the project?

We don't share that.

Okay. Can I ask for some color then around -- you mentioned the tanks and progress on the tanks taking the team off path, I think you said? Did you mean they were getting faster or slower or what was unusual about that in your sense?

Most LNG projects, the tank readiness for production is one of the critical path items and controls schedule. We've seen that on several projects before that we've been involved with, and the tank work to date has gone well. It's taken all the tank construction off the critical path schedule for the project. So it's a big positive to -- it's -- projects are always about eliminating problems with the critical path item. And we're very pleased where we are on the tanks.

That makes sense. Can I ask, on the 45% complete, if you don't think of that in terms of costs, or is that a cost completion, or is that a time completion? How do you think about that particular percentage disclosure?

It's an activity level completion, which we value certain activities. So I would put it more in the sense of really a schedule, but it really reflects the amount of effort and work that has to be done, activity by activity, and it's weighted that way.

Okay. And then the last component from these -- all right.

[Operator Instructions]

Our next question comes from Paul Cheng with Barclays.

Two questions. One real short. George, have you guys hedged your FX exposure in Gorgon? And also Wheatstone at the time of [indiscernible] how much, if you can share? And the second question...

If it's okay, I'll just answer that. The answer is no, we did not hedge, okay?

Okay. Any plan to change it in the future, or that this will be continue to be the company policy?

I'm going to let Pat answer that one.

Right. No, I mean, we really look at this as -- particularly when you're dealing with a resource country like Australia when the movement in the Australian dollar is really driven by what's happening in the resource sector, we look at the tide and the correlation between that, and what happens to oil prices typically and have found a very strong correlation. So we have made the decision to not hedge. We are -- we really have a hedge in the overall portfolio.

Okay, that's fair. The second question, George, from an organizational -- I mean, you guys are working on a lot of different projects and no doubt have a full plate. So from an organizational capability and limit standpoint in terms of your human resources, your supply chain availability, can you really -- can you increase your current pace, or that this is as fast as you can run? And if you don't really have any more slack and I know that periodically, people are asking that whether you're going to acquire something that's in mix sense, that when you don't have excess or high-dosed spare organizational capability, therefore, you do acquire anything outside what you already have?

Well, that's a -- Paul, it’s a multipart. Let me see if I can take a quick stab at that. First, when you look at the major capital projects we are having around the world and the organization -- the people it requires to do one of those, we could not add another large project in the execution stage at this point. Now we can -- we're always preparing ourselves for the next set of projects. So we have to stage out people in earlier phases to move the next set of opportunities through the pipeline. So we try to do that. But we could not just plunk down another big project in the execution stage. Now we have to plan for people coming off of these big projects, and that's happening, too. So we try to manage that, I think, in a very holistic sense. Otherwise, on our organization, could we do more smaller projects or a little more drilling? Yes, we have some capability to do that. It's not a huge impact on our capital budgets. It would be relatively small monies compared to what we're presently doing. We don't want to get over-extended on that either. So we try to make good choices on that part. But very importantly, we try to time, once again, next set of projects, get the work, the preparatory work for them ready by the time some of these other projects are rolling off. And I guess maybe one final point, the reason for all that is we want to have good execution. And of course, on the front end, we want to make very good decisions on doing the right projects.

Our next question comes from Iain Reid with Jefferies.

George, can I ask a couple of questions about Tengiz? I noticed the future growth FEED hasn't started that. Are there still issues there with the government? And do you still believe that there's going to be volumes from that in your 2017 numbers?

Good question, Iain. Let me give you a little bit of background, where we are on -- at TCO. TCO has received partial funding for partners for future growth FEED. That allows us to move the FEED forward, and we have commenced engineering on that -- on the FEED engineering for future growth. Down the road, we've of course got to finish that. And then another big hurdle on -- for future growth is also funding for partners, in particular funding for our Kazakh partner, KMG. So that is yet to come. When I look at the timing for the expansion of TCO, it is in the 2017 period. That's where it's planned. It's not a full year's worth of production, but we are very focused on trying to move that project to meet that schedule. So I'm convinced we're either going to have it in '17 or it's going to be in '18. And I've got it in my plan that way, and we look at it every quarter to try to make sure that we have it in the schedule at the right time. And I'm also always looking on my 2017, 3.3 million, about other opportunities that I have in queue that I could offset any barrels that would slip out of 2017. So got a great -- we have a great focus on that. I'll bring you back -- we're going to move that project at the right speed to execute it well, to get everything in place to have an excellent project. And for a reminder for everyone that's on the phone, this project is another big project. It's a 250,000 to 300,000 barrel a day expansion. This project is made possible by the CPC expansion, Caspian pipeline expansion, which is moving forward well. We see the first part of additional barrel capacity coming on the CPC actually in 2013, which is good news for us.

That was great. And second bit is the turnaround you're taking over the next several weeks, how many barrels is that going to impact? Is it the whole plant or just a portion of it?

It's the SGI/SGPs, which is round numbers is approaching 300,000 barrels a day. So it's about half of our production at Tengiz. This is the first real big full turnaround for the plant and the compression equipment in total. Like I mentioned, 6,000 workers, a lot of people there. We are also trying to do a little bit of additional work that we think will be improving future capacity, but the real focus at this point is changing out catalysts and increasing reliability and efficiency of the plant.

And that's all built into your full-year production forecast?

That is correct.

Our next question comes from John Herrlin with the Société Générale.

George, you mentioned that the development wells at Gorgon were going -- you were pleased with them. Does this mean that we could see some resource uplift, or greater recoverable reserve potential for Gorgon?

That's possible. Let me make sure I can characterize that. What we've seen to date is -- we look at every well as we're moving forward. And we have a distribution of outcomes between a, if you will, a probabilistic distribution, and we're seeing outcomes that are greater than our mid-value. These are all static results. These are based on logs. Once we really wouldn't move very much off of that until we got performance, so we got the dynamic results when we actually start up. Now we will take some looks at this, net pay counts and looking at actually reservoir quality. But at this point, we feel very good that we feel we are -- we did a good job estimating, and it's come in just a little better than our midpoint.

Our next question comes from Pavel Molchanov with Raymond James.

First one is for Pat. Your referenced, of course, the very large cash balance. What would it take for you to consider upsizing the quarterly share buyback?

Well, Pavel, I think I would just point you to the fact that we had, from a Brent standpoint, a $28 decline in realizations over the course of the second quarter and just point to the volatility there and say -- as I've said in the past, that we keep the cash balance where it is right now while we're in the midst of heavy construction period, particularly on these LNG projects. And that is -- our priority is to be able to fund those projects through the thick and thin of commodity cycles and to be able to weather any sort of downside excursion, which we have just seen. So fundamentally, I think it would take a hugely different and more robust commodity price environment and a sustained environment for us to think at this point in time of moving it beyond the 1.25 billion per quarter.

We are returning a lot of cash.

Yes, we are.

A quick one for George as well. Lots of conflicting comments from your peer companies in relation to shale gas in Europe. What are your latest thoughts on the commercialization prospects, and maybe any sense of timing on when we might see some volumes out of there?

I think we've been pretty consistent on what we thought on timing for shale gas coming out, or gas for shale coming out of Central Europe or elsewhere on the European continent. We've always looked at this as a exploration play. So it's very early days. You have to drill a lot of exploratory wells. You got to understand the resource. You got to understand the performance. We are once again in a very early start of that. My expectations on a success basis, that you're really talking next decade before you get significant volumes. Europe is in a much different situation, and I think actually almost all the rest of the world, on the shale opportunities than the United States. The knowledge level in the U.S. about a shale, I mean, we've -- is high compared to any place else in the world because there is so many wells being drilled in the United States in every region. So your knowledge level going in is high. You're able to more quickly assess the opportunity here, and then very importantly, remember the infrastructure. The North American infrastructure to move the gas is in place. Most cases, you had short tie-ins. You got all these big interstate pipelines. It's a much different situation. And you don't have that in Europe. So there's a lot -- lot of things must happen from the point of discovery, assessment and then moving gas to market. And my expectation hasn't changed. It's really predominantly a next decade, and maybe early in the next decade. But it's the next decade.

Yes, our last question comes from Allen Good with Morningstar.

If I could just try a couple on Iraq. As far as the acreage add there, what is your perspective on the long-term potential there? What's your long-term outlook that you may see that Reliance didn't particularly see there that makes the entry there attractive? And then secondly, were there -- are there any sort of near-term plans for exploration or any other sort of development, or is there a situation we just got to sort of wait out the political situation there until you get some more clarity?

Well, let me start off. We have been engaged in Iraq and trying to find opportunities at Iraq for quite a period. We want to participate in their expansion. We believe what we have in front of us fits with what we'd like to do. It's early exploration. Our preference always is to explore, find, appraise and develop an opportunity. This fits with that. We're there to try to do once again that exploratory work to prove it. We've got wells to drill. We will be drilling a couple of wells in the near term. That was part of the commitment that was made for those blocks. We will be meeting that commitment. So we're encouraged from what we see of the geology. But once again, it's exploration. I don't know what's going to happen until we drill the wells. We feel good about the ability to actually get in there and do the work. We do see the terms -- the economic terms there would be attractive. It would fit in the portfolio with geologic success. So we feel good about it as an exploration play.

Okay. And is this -- do you feel like it's enough of a position for now, or are you continuing to look and potentially add acreage in the future?

Once again, we always are looking for an opportunity to expand, particularly where we have a belief that we have a good technical prospect. So I'd just leave it at that broad point.

Okay. I think that wraps things up for this morning. In closing, let me say that we appreciate everyone's participation in the call today and your interest in Chevron. I especially want to thank each of the analysts on behalf of the participants for their questions during the session. Kevin, I'll turn it back to you. Thank you, everyone.

Ladies and gentlemen, this concludes Chevron's Second Quarter 2012 Earnings Conference Call. You may now disconnect.