Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's second quarter 2014 earnings conference call. At this time, all participants are in listen-only mode. After the speakers' 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 call, please press star then zero on your touch-tone telephone. As a reminder, this conference call is being recorded. I would now like to turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Pat Yarrington. Please go ahead.
Hey, good morning, and thank you, Jonathan. 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, Upstream, and Jeff Gustavson, General Manager, Investor Relations. We'll refer to the slides that are available on chevron.com. 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 two. Turning to slide three, the company's second quarter earnings were $5.7 billion, or $2.98 per diluted share. On a year-to-date basis, earnings were $10.2 billion, or $5.34 per diluted share. Included in this quarter's earnings were gains on asset sales of approximately $750 million and foreign exchange losses of $232 million, which together equate to a positive $0.27 per share.
Year-to-date earnings, after netting gains, impairments, and foreign exchange impacts, was $10.1 billion or $5.29 per share. Return on capital employed for the trailing 12 months was approximately 12%. This reflects both the strength of our underlying producing assets and the fact that we're in the midst of a heavy construction period for a few key capital projects. Our debt ratio at the end of June was approximately 13%, similar to last quarter. Our financial priorities are unchanged, and we continue to reward shareholders with competitive distributions. We repurchased $1.25 billion of our shares during the second quarter, and in the third quarter, we expect to repurchase the same amount. Chevron's five-year total shareholder return at the end of the quarter was 18.4%, which continued to lead the peer group and was also in line with the S&P 500 over the same time period.
Turning to slide four, cash generated from operations was $7.9 billion during the second quarter and $16.3 billion year to date. Cash capital expenditures were $8.9 billion during the quarter and $17.5 billion year to date. At the quarter end, our cash balances exceeded $14 billion, giving us a net debt position of $9 billion. Slide five compares current quarter earnings with the same period last year. Second quarter 2014 earnings were $300 million higher than second quarter 2013 results. Foreign exchange effects negatively affected earnings by $232 million during the quarter, representing a negative swing of over a half a billion dollars between periods. As a reminder, foreign exchange movements for us are largely book translation effects with minimal cash flow impacts. Upstream earnings increased by $315 million.
Gains on asset transactions of approximately $610 million in absolute terms and higher realizations were partially offset by unfavorable foreign exchange impacts and higher exploration, DD&A, and operating expenses. Downstream results decreased by $45 million. Higher U.S. refining, marketing, and chemical earnings were offset by lower international refined product margins, along with adverse foreign exchange effects. Movement in the other segment reflects an absence of a 2013 second quarter impairment and lower corporate expenses, largely offset by higher corporate tax charges. Turning to slide six, I'll now compare results for the second quarter of 2014 with the first quarter of 2014. Second quarter earnings were approximately $1.2 billion higher than first quarter results. Upstream earnings were up $957 million, reflecting gains on asset transactions, higher liftings, modestly stronger realizations, and favorable tax effects.
Partially offsetting were higher exploration and operating expenses, in addition to an unfavorable foreign exchange movement between quarters. Downstream results were essentially flat. The variance in the other bar largely reflects the absence of the impairment and related charges for a mining asset from the prior quarter, partially offset by higher corporate expenses. Jeff will now take us through the comparisons by segment.
Thanks, Pat. Turning to slide seven, our U.S. upstream earnings for the second quarter were $142 million higher than first quarter's results. Higher production volumes at the Perdido and Caesar Tonga fields in the Gulf of Mexico, in the Midland and Delaware Basins in the Permian, and in San Joaquin Valley increased earnings by $115 million. Higher exploration expenses, mainly associated with the deep water Gulf of Mexico, decreased earnings by $95 million. The second quarter included gains on several separate asset transactions worth approximately $180 million in total. The other bar reflects a number of unrelated items, including lower natural gas realizations and higher operating expenses. Turning to slide eight, international upstream earnings were $815 million higher than last quarter's results. Higher realizations and higher liftings increased earnings by $280 million. Our under-lifted position in the first quarter was essentially neutralized.
Gains on the sale of our interests in Chad and Cameroon increased earnings by $430 million. Lower impairments compared to the prior quarter resulted in an earnings increase of $140 million. An unfavorable movement in foreign currency effects decreased earnings by $95 million. The second quarter had a loss of about $150 million compared to a loss of about $55 million in the first quarter. The other bar reflects a number of unrelated items, including favorable tax effects offset by higher operating and exploration expenses. Slide nine summarizes the change in Chevron's worldwide net oil equivalent production between the second quarter 2014 and the first quarter 2014. Production decreased by 43,000 barrels per day between quarters. Shale and tight resources growth contributed 6,000 barrels per day, driven primarily by production increases from the Midland and Delaware Basins in the Permian.
We're also seeing continued growth from the Vaca Muerta Shale in Argentina. Major capital projects decreased volumes by 13,000 barrels per day due to the shutdown of the LNG plant in Angola, partially offset by the ramp-up at Papa-Terra in Brazil and Caesar Tonga in the Gulf of Mexico. Planned turnarounds in Kazakhstan, Australia, and in Denmark, among others, reduced production by 57,000 barrels per day. Absence of first quarter external constraints, largely weather-related disruptions in Kazakhstan, as well as lower demand in Thailand, increased volumes by 27,000 barrels per day. The base business and other bar reflects normal field declines. Slide 10 compares the change in Chevron's worldwide net oil equivalent production between the second quarter 2014 and the second quarter 2013. Production was 37,000 barrels per day lower than the same period a year ago.
Growing volumes from our shale and tight resources, primarily driven by the Permian in the U.S. and the Vaca Muerta in Argentina, increased production by 33,000 barrels per day. Major capital projects contributed 13,000 barrels per day, driven by Usan in Nigeria and Papa-Terra in Brazil, partially offset by the shutdown of the LNG plant in Angola. Higher turnaround activity, mainly in Kazakhstan, reduced production by 21,000 barrels per day. Lower production entitlement effects due to lower cost recovery, higher prices, and higher royalties reduced production by 37,000 barrels per day. The base business and other bar principally reflects normal field declines. Turning to slide 11, U.S. downstream results increased $95 million between quarters. Stronger margins increased earnings by $140 million, driven by tighter product supply due in part to industry refinery maintenance, combined with higher seasonal demand. Higher operating expenses decreased earnings by $130 million.
About half of this was due to higher costs related to shutdown and maintenance activities at the El Segundo refinery during the quarter. The turnaround was completed at the end of June, and refinery operations have returned to normal. The remainder reflects higher maintenance and repair expenses at our other refineries and incremental costs from the startup of the Pascagoula Base Oil Plant. Gains on midstream asset sales improved earnings by $40 million between quarters. The other bar reflects a number of items, including stronger chemicals results. Turning to slide 12, international downstream earnings decreased $84 million between quarters. Increased volumes improved earnings by $75 million following the completion of turnarounds at our Thailand and South Africa refineries last quarter. Lower refinery margins decreased earnings by $15 million, reflecting higher crude costs that could not be fully recovered in the marketplace.
Foreign exchange losses were approximately $55 million higher compared to the prior quarter. The second quarter had a loss of about $85 million compared to a loss of about $30 million in the first quarter. Higher operating expenses decreased earnings by $30 million. The other bar includes a number of unrelated items, including minor asset transactions and lower trading results. George will now provide an update on our upstream operations. George?
Thank you, Jeff. First, I'd like to highlight the progress on our Gorgon project. This photo shows the LNG plant in the foreground with the jetty in the distance. We continue to make excellent progress in the module fabrication yards and on Barrow Island. Module deliveries are continuing on schedule, and we are achieving our key milestones. Gorgon remains on track for a startup next year and will be a key contributor to our production growth in 2015 and beyond. I'll share a bit more on Gorgon later. Consistent with prior quarters, we have posted additional progress photos for both Gorgon and Wheatstone, which can be found on our investor page at chevron.com. Now let's take a look at our upstream financial performance on slide 14. Our 2014 year-to-date upstream earnings margin was $20.32 per barrel.
This adjusted margin does not include gains from any of our recent asset sales in this quarter. Based on the results for our peer group through the first half of the year, we lead all our LTIP competitors by an average of over $3.50 per barrel. Relative to the first half of 2013, our earnings margins have softened. Foreign exchange swings reduced our margin by $1.42 per barrel. This, combined with higher exploration expense and DD&A, have been the primary contributors to this decline. We are cognizant of the current macro environment, increasing costs of goods and services coupled with relatively flat commodity prices. We remain focused on managing controllable costs. Looking forward, we're expecting strong contributions from our new MCPs as they come online. Now I'll discuss our 2014 production results and outlook on slide 15.
Production in the first half of the year averaged 2.57 million barrels a day at an average year-to-date Brent price of just under $109 per barrel. The first half results are 43,000 barrels per day, or 1.7% below our guidance. Relative to our guidance, production entitlement effects reduced production by approximately 20,000 barrels a day, and the unplanned outage at Angola LNG reduced production by a further 15,000 barrels per day. Our base business performed well. Over the first six months of the year, we have maintained a base decline rate of less than 3%. We also continue to see strong growth from our shale and tight assets. During the second half of 2014, we anticipate further production ramp-up at Papa-Terra in Brazil and our two Gulf of Mexico developments, Tubular Bells and Jack/St. Malo, as these are on schedule to come online.
During the second half of the year, we will perform the second of two planned turnarounds at TCO, as well as execute large turnarounds in Thailand and in the North Sea. The production entitlement effects are anticipated to continue, and we don't expect any ALNG production in the second half of the year. Completed asset sales in the first half will, of course, affect second half production. We forecast 2014 production will average 98%-99% of our January guidance. Our 2017 growth to 3.1 million barrels per day remains on track as we bring on our new projects and progress our shale and tight resources. I'd like to provide you with a little more detail on the production growth, which we anticipate will occur over the next several years. Turning to slide 16. Our peer-leading growth to 2017 is largely driven by the startup of our major capital projects.
For the last several years, we have been in a period of high investment while our MCPs progress through the construction phase. As these projects now transition to operations, beginning with our Deepwater projects, Tubular Bells and Jack/St. Malo, we forecast significant volume and earnings growth. We remain focused on executing our industry-leading queue of projects with excellence. We have the right people and processes to deliver these projects, and we're excited about the value creation. While many projects contribute to our growth, the majority of our new volume is generated by eight of our largest MCPs: Gorgon and Wheatstone in Australia, Mafumeira and ALNG in Angola, Papa-Terra in Brazil, and Jack/St. Malo, Tubular Bells, and Big Foot in the Deepwater Gulf of Mexico. Now I'll review progress on six of these projects. Moving to slide 17.
In early April, Angola LNG experienced a failure in the flare blowdown piping system. At the time of our first quarter earnings call, the investigation was still underway. Following a thorough analysis, a number of design issues have been identified which will require modifications. In addition to the piping repairs, the LNG team will utilize this shutdown to perform capacity and reliability enhancements to the plant. Following completion of repairs and testing, the plant will restart, and it is expected to achieve sustained production in the second half of 2015. The Gorgon project is now more than 83% complete. All Train 1 and common modules required for LNG operations have been delivered to Barrow Island and installed on foundations.
Other downstream work on Barrow continues to progress well, with the jetty now 97% complete, and the commissioning beginning this month on LNG Tank 1. Delivery of Train 2 modules has begun, and five are now on site. On the Gorgon upstream, hydrotesting has been completed on all 660 km of offshore pipelines. The well flow back and cleanup operations on the eight Gorgon wells is ongoing, and drilling has been completed on the 10th and final Jansz-Io development well. The next major milestone is the completion of LNG Tank 1, which is targeted for the end of this quarter. Wheatstone is now 40% complete. Dredging, fill, and piling work is progressing on schedule. The shore pull of the main 44-inch trunk line through the micro tunnel was completed safely and as planned.
Shipments from fabrication yards have commenced with the delivery of the first slug catcher components to site. The Wheatstone platform and topsides are now more than 63% complete, and we anticipate the sail away of the platform steel gravity structure in August. Wheatstone remains on track for a late 2016 startup. Now I'll review progress on our Deepwater Gulf of Mexico projects. Moving to slide 18. The Tubular Bells project is nearing startup. All key tie-ins have been installed and tested, and the wells are ready for production. Production operations are anticipated to commence in the third quarter. The remaining work on Jack/St. Malo is progressing well, and the project remains on track for a late fourth quarter startup. Overall hook-up in commissioning and startup progress is now 73% complete. Tie-in spools for the steel catenary risers have been installed, and gas pipeline pre-commissioning is complete.
Jack/St. Malo will be a key contributor to our production growth in 2015 as production ramps up. Big Foot shipyard-related construction is over 90% complete, and preparations are being made for a fourth-quarter sail away. Fabrication work on the tension leg platform tendons is now complete, and hull and topside integration is nearing completion. The project team marked a major milestone with the heavy lifts of the drilling modules this quarter, and as you can see in the picture on this slide. Big Foot remains on track for a 2015 startup. We are pleased with the progress on our key deepwater Gulf of Mexico projects. As these three projects ramp up during the next year, we will see a significant uptick in production as we move towards our 2017 goal. At peak capacity, these projects will deliver Chevron approximately 100,000 net barrels per day.
I'll provide an update on our shale and tight activities. Please turn to slide 19. Chevron is the largest producer in the Permian and has an enviable acreage position. We have the largest undeveloped leasehold, and 90% of our acreage is either low or no royalty. We have over 17,000 well prospects identified and the potential to add 8,000 to 10,000 more. Since we are not in a drill or drop situation, our approach has been to allow others to de-risk acreage surrounding our own. This enables us to focus our capital on development wells rather than exploration and appraisal. In the Midland Basin Wolfcamp play, industry drilling to date has been predominantly via vertical wells. Earlier this summer, we spot our first horizontal Wolfcamp well.
We now have 17 rigs operating in the Midland Basin and 10 rigs operating in the Delaware Basin, where we added two rigs this quarter. We are on schedule to drill more than 500 wells this year in the Permian Basin. Turning now to Argentina. Chevron is pleased with our initial results in the Vaca Muerta. Drilling results have helped us identify two sweet spots where we are focusing our activity. In one of these areas, we have commenced a horizontal program. We have seen a production uptick, which gives us confidence that we will deliver the growth we anticipated when we entered this play. Good progress is being made on our Duvernay program in Canada. Our wells have demonstrated good flow rates and high condensate yields, and we are confident of the quality of our acreage.
In the third quarter, we anticipate spotting the first of 16 wells as part of our expanded appraisal program. Also in Canada, we are continuing with the appraisal campaign in the Liard Basin. Results continue to indicate very favorable ultimate recoveries and high IPs, which will support plans for this asset. Moving to slide 20. I'll now highlight a few additional ongoing activities. We continue to have good success on our exploration program in the Carnarvon Basin in Australia. Since our announcement of Elfin-1 in April of last year, we have made four additional discoveries. This provides us with additional gas resource and optimization alternatives for our Gorgon and Wheatstone LNG facilities. In March, we stated a target to deliver $10 billion in asset sales over the 2014 to 2016 time period, we are on our way to meeting that goal.
Our recent divestiture of the Chad assets is one example of our focus on monetizing a mature, declining business, which allows us to generate cash for potential reinvestment in other growth areas. We are also progressing the sale of several other mature assets, including the Netherlands, our non-operated interest in Draugen in Norway, several leases in Nigeria, as well as several smaller assets from our conventional North American portfolio. We recently achieved a major milestone at our Escravos Gas-to-Liquids plant with the production of GTL diesel and naphtha. We anticipate continued ramp-up and first product lifting later this year. Our exploration and development program in the Utica is yielding good results for both liquids and gas. Industry results in the Utica Shale have been encouraging from Ohio into West Virginia and Pennsylvania.
We recently achieved a test of more than 32 million standard cubic feet per day on a 22/64 choke at one of our wells in the emerging southern trend. We anticipate this well will be turned into line this fall. Finally, we are also very encouraged with the initial results in the Kurdistan region of Iraq. Exploratory drilling and logging has indicated multiple pay zones in a large structure. We have begun initial drillstone tests, and the formations have demonstrated the ability to deliver high liquid flow rates. On one of the two wells, we plan to test up to nine different zones. We'll continue with our KRI testing program over the months ahead. Now, I'll turn it back to Pat.
Okay, thanks, George. Turning to slide 21, I'd like to close with just a few thoughts. Global energy demand continues to grow, and satisfying that demand growth is a great business opportunity for us. We've had the same basic strategies for a long time now. We believe they remain relevant and that they will continue to drive future value growth for our shareholders. We continue to focus on execution. You just heard from George that our base business in the upstream continues to perform well and that we are making significant progress on our major capital projects. In the downstream, we can also report success. The Pascagoula Base Oil Plant, or PBOP, as we call it, is now online. First commercial production began in June, and the plant ramped up to full production in mid-July. We are now the largest producer of premium base oils worldwide.
Focus on execution also means operating safely and reliably. Through six months, our personal and process safety performance has been strong across all the measures we typically share with you: the days away from work rate, Tier 1 loss of containment, and spills. Sustained value creation requires reinvestment in our business. This is necessary to meet future energy demand and is vital to sustaining growing rewards for our shareholders. We have a broad, balanced, and deep queue of investment opportunities and take a highly disciplined approach to capital allocation. We are actively managing our portfolio and are on track to meet our stated target of achieving proceeds from asset sales of $10 billion over the 2014 to 2016 time period. Through six months, asset sale proceeds have totaled $1.6 billion, and we're making good progress on a number of other planned transactions.
We have the best growth profile amongst the peers between now and 2017. Every quarter, as project milestones are checked off, we get one step closer to the inflection point. Indeed, two of the projects George highlighted are set to start up in the second half of this year and two more in 2015. Along with this sizable growth in volume, we expect will come significant growth in cash flows. We expect free cash flow to grow as well, thereby enabling higher shareholder distributions over time. In short, we are very excited about what lies ahead for the company. That concludes our prepared remarks. I certainly appreciate you listening in this morning. We are now ready to take some questions. Please keep in mind that we do have a full queue, so try to limit yourself to one question and one follow-up if necessary.
We will do our best to get all of your questions answered. Jonathan, please open the lines for questions.
Thank you. Ladies and gentlemen, if you have a question at this time, please press star then one on your touch tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound 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 a question at this time, please press star then one on your touch tone telephone. Our first question comes from the line of Ed Westlake from Credit Suisse. Your question, please.
Yes, good morning, thanks, George, for your time on the upstream as well. Maybe just firstly a question on cash flow. Last year, about $36, now this year, sort of $33, if you annualize the first half, and obviously oil prices have stayed high. It looks as if your turnarounds are in high margin areas, but is there any other deterioration in the cash flow relative to your expectations? Obviously, you have given us some guidance on the Analyst Day of relatively strong cash flow growth from the 2013 basis as these major projects come on stream.
Right. Ed Westlake, we still feel good about our cash flow projections going out 2015, 2016, 2017. Again, it is obviously predicated on the production growth that George Kirkland went through on major capital projects, growth in the Permian. Also, of course, oil prices will be quite impactful there. If you're looking at the first half of this year relative to the second half, I think one of the comments I would make would be downstream. Downstream has not been as cash prolific perhaps as certainly we would like. Many of the turnarounds that we talked about on the slides are in the rearview mirror, so to speak, at this point. So the second half of the year, we believe, should be a better cash generation from a downstream standpoint.
Okay. Then a question on the upstream, just generally. I'm looking at slide 10. Of course, you're slightly lower on production this year. If you add up the turnaround production entitlements and base business, you're losing some volumes. Even without major capital projects, the volume trajectory is relatively flat. As I look at the slide that you've put out helpfully on MTPs getting up to 900,000 barrels a day from the big projects and the other stuff that you're doing, then I think about shale, it feels like something has to get worse to miss the 3.1 million barrel a day 2017 guidance. Which is a good position to be in, I'm just wondering, what is it that gets worse in your assumptions as you look out?
Ed Westlake, I just don't have any things to get worse in our assumptions. If you remember when we came through at the SAM meeting and gave you our forecast of 3.1, we showed a 50,000 barrel a day buffer. There is a buffer in there. Part of the reason we had that buffer in there was always the forecasting ability. Recognize that we've talked a lot more about asset sales. We have asset sales in our plan. We don't always know exactly what asset sales that will actually occur. We are very focused always on the value proposition of those. That's really what we've got to focus on, creating the greatest value on those asset sales. As a reminder, when we look at asset sales, we're looking at two pieces. We're looking end-of-life assets. Do they have continuing investment opportunities?
Of course, we look at some of our assets that are on the front end that don't compete for funds. We got a little bit of latitude in there to cover some of the asset sale losses that occur when we sell these properties. I can't give you the details on those because we are very value driven. We're going to make the best decision on getting the greatest value for anything we sell.
To very sneakily at the end, just in terms of three questions, it's not an entitlement change as you go forward? The pace of current entitlement changes stays flat through the forecast, do you think?
Let me explain a little bit about the entitlement changes there, and this probably heads off of questions that we're likely to get from others. Each year when we give you our production forecast, we have modeled, and we have all kinds of assumptions on production entitlements. We do our very best job to try to nail those entitlements. We have a 20,000 barrel a day impact in our entitlements that are greater than what we had anticipated. We've shown that in that section for me. You have to understand, when we model this, we have all kinds of assumption there. I'll just deal with two of those, the two biggest ones that make up most of this 20,000 barrels a day. The two of them are in Tengizchevroil and in Bangladesh.
The Tengizchevroil one, we make assumptions of how much crude we're going to move via rail versus how much crude we're going to move on the CPC pipeline. We have that assumption, that comes up and gives us a really good indication of royalty net back at the wellheads. That gives us net back at the wellheads, which impacts our royalty assumptions. This year, we have moved more barrels on the CPC because it was available. Actually, about 80,000 barrels a day, Tengizchevroil has moved more than was in the plan. That's great for us, that's great for Kazakhstan, great for the partnership because we get higher net backs. We've also had higher prices on the sulfur, and sulfur sold at a higher price translates to a higher net back for us at the wellhead also, and that reduces net production. It's a really good thing for all of us.
That's really positive. It's a value decision, right value decision. Similarly, in Bangladesh, we've had an agreement on how we would look at VAT. VAT is now going to be reimbursed, and the reimbursement will, in effect, reduce our cost barrels. There is an impact on that. It's good for us to clear up the VAT issue. It's good from a profit gas or profit oil basis going forward. That removes that cost out of it. That's another value creator for us. Not nearly as big as the Tengizchevroil one, but it's a positive for us. Those two items made up most of the difference on this entitlement. Good things, right way to run the business, but we didn't have it modeled that way in our plan. I'll tell you, we're always going to go after the piece that makes the most value sense.
Maybe that'll help.
Thanks so much.
Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question, please?
Hi. Good morning, everyone.
Morning
Hi, Pat. The first question I had is for George, relating to the startups in the Lower Tertiary. George, you said in the past that the key to really good returns there would be increasing recoveries from, I think you planned on 10% towards 20% recoveries. What's the path towards this and the timeframe, I guess, towards this getting a better idea of how those recoveries will play out? Thanks.
Paul, thanks for the question. Historically, what we had actually said is we looked at recoveries initially would be in the 8%-10% range. That we saw technologies, either completion technologies, reducing back pressure on the reservoir, items such as those technologies that would increase the recovery towards the 15% and then on to 20%. We do believe we're on track for that. I'm going to feel a lot more confident as we get the first Jack/St. Malo wells on, and we see our new completion technology, how successful we are there. We'll be watching production rates. I would tell you, I am encouraged at. We've done the cleanup on a number of those wells already, so when the facilities are ready, we'll be able to turn them on, and we'll initially get a quick look, of course, at production rates.
If our production rates are at the high end of our assumption, that's going to give us confidence that we're going to get a little bit more recovery. We should actually have some pretty good confidence in that, a little bit of impact on our recovery view. Of course, we'll have a much stronger view on production volumes as we get to the end of the year in March, as we get a little bit of runtime on these wells. I feel good for what we've seen on the cleanup, though. I'll just leave it there qualitatively.
Okay. Interesting. The follow-up I had was on Gorgon startup. When you say mid-2015, is that the first production of gas, the first production of LNG, or the first sale of LNG? Thanks.
It is the first production of LNG. It's not gas introduced into the plant. We have a target to see gas introduced into the plant this year because we need the gas introduced into the plant to start commissioning activities. One of our early activities is getting gas introduced in the plant, getting the turbine generators running, get power support for the operations. That utility piece is very critical to the startup and is actually a milestone that we'll be talking about more in the next quarter's call.
Cool. Then the actual sale of LNG, when would that be?
I'm not going to go that next step. I'm going to leave it till we have the first LNG in the tank, which we'll announce. Once we have first LNG, we will be announcing our target for first lifting.
Interesting. Thanks. You're still trying to sell more contracts there, aren't you? Is there any reason why we haven't heard more about that, given you've shown modeling of a shortage of LNG long term? I'm just surprised we haven't heard more about contracts, and I'll leave it there. Thank you.
Okay. Paul, we are still looking at opportunities to sell more gas. We really don't have a lot more to sell. Remember, on the Wheatstone side, we already sit at 85%, so we're fully sold out there. As a reminder, we have some ability to move gas in our contracts from different assets we own. We have some flexibility there. We are still, once again, looking to increase that, but we are value driven, so we need to get a price that we think is appropriate. The spot market has been good on a seasonal basis the last year, so we feel pretty good about the volumes if we had to move them into the spot side. Preferentially, we would move them to a longer-term sales contract if we get the right kind of pricing.
Paul, I would just add that with the degree of uncertainty that there is about U.S. exports and the size of U.S. exports, I think you can understand why buyers might want to wait a little bit to see how that all lands out before going forward to secure longer term contracts.
Okay. I'll leave it there. Thank you.
Thank you. Our next question comes from the line of Douglas Leggate from Bank of America Merrill Lynch. Your question please.
Thanks. Good morning, everybody. Thank you for taking my questions. Pat, I wonder if I could follow up on Ed Westlake's question. This is something we've been kind of wrestling with. It may be overly simplistic. You gave us a cartoon at the Analyst Day that showed how the cash margin improves, let's say, in $110 oil environments. Let's call that same store sales with last year at $36 billion. When we take the delta on production growth and the delta on the margin, it only adds about $8 billion to the cash flow. That gets you to $44 billion, and you're spending a little under $40 billion, your dividends are $7 billion, and your buybacks are $5 billion. Can you help me with what else are you assuming in that inflection in cash flow that you talked about in your prepared remarks?
Your upstream guidance doesn't really seem to get us there.
Are you talking about 2015 or 2017?
No, in the cartoon, it shows the post 2016 portfolio, which I assume is, if we look at 2.1 million barrels a day in 2017 and the current portfolio at, I guess, 2.7 million barrels a day last year, which generated $36 billion. I'm trying to understand how big do you think the delta is? According to your cartoon, it's only about $8 billion.
Let me just start and say, if you start from a 2013 base and you look out to 2015, let me just be clear on the assumptions that we have in there. We're moving from the 2.7 million barrels a day last year to the 3.1 million barrels a day in 2017. The assumption on price in that slide was $110 a barrel Brent.
Right.
When you get the increase in volume and you also get an accretion on the cash margin, and that accretion is coming from, significantly, the major capital projects that George has just run through, predominantly Gorgon and Wheatstone are huge contributors to that. That is really what gives you an underlying increase in upstream cash flows between what we saw at the base of 2013 and what we're expecting in 2017. On top of that, there will be, we believe, higher contributions and cash flows from our downstream sector. Obviously, it's not as significant a growth element there, but there will be contributions on the chemical side and on the lubricant side and some on the R&M side.
When you put those components all together, we feel comfortable about saying under those set of assumptions, particularly price and volume, you're going to get to a $50 billion cash generation figure. I think the point that's really important here is the margin accretion that George we've talked to for a couple of years here, is not just on the incremental barrels, it's on the full portfolio. That's really what is the compelling point here, is that those projects coming online have the capacity to pull up the entire cash margin over the whole portfolio.
I appreciate the answer, Patty. I'll take it offline with Jeff because like I say, I'm using your numbers, and the delta looks about $8 billion. I'll talk to Jeff offline. My follow-up is really a Gorgon question, George, and thanks for getting on the call this morning. You talk about start-up on train 1, but can you talk to the ramp-up to train 3? You're obviously familiar with the chatter that's been out there constantly while this project has been moving forward. Start-up is one thing, but what about the ramp beyond that? Can you give us some comfort level on the pacing of trains 2 and trains 3, and I'll leave it there. Thanks.
Historically, what we've said, we said we saw six months between train start-ups. I'll try to give you a little more context of what's happening on train two and train three. I think, very frankly, it's very good news on the train two modules. We expect we will have almost, well, I'll just say, most of the modules for train two on Barrow Island by the end of the year. We will even have a few, we think, of the train three modules. The module piece of the work is going quite well. It's moving forward very well. We don't see any of the module work at this point on the critical path. All of that puts us in a strong position to say we're not seeing any slide on time between the start-up of train one and train two.
If anything, we may even see that tighten up a little bit, but it's a little early to go there. It looks good at this point, and that's a real positive. Critical for us-
Thanks. Sorry, George
to get train one up, and then we'll answer a lot of questions. Okay?
Thanks very much indeed. Appreciate it.
Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley. Your question, please.
Hey. Good afternoon, guys. Just on free cash flows clear. A question for George. Staying with LNG, one of your partners, Apache, yesterday announced plans to exit Kitimat LNG and Wheatstone for that matter. Does Apache's exit change how you think about the risk profile of that potential project?
Well, let me start out on we need to get our partnership resolved. That means Apache needs to move through the issues, and we need to get a new partner in. That needs to happen. That's, I think, quite obvious. As long as we keep moving forward in the assessment of the resource in Liard, I feel very good about the resource assessment. I think we've already can check off our confidence level on the other resources. The Horn River resources is already high. We've really done that appraisal. The focus on the resource side is really drilling in Liard, some appraisal work there, and getting some production work. We think we'll actually have those first wells that we need to get some production data. We're going to be complete with them somewhere near the end of the year. That's a really important step for us.
The other pieces that we're spending money on Liard, related to Liard, is a little bit of money on how we are going to actually handle the upstream initial production. Of course, we've got to focus on the pipeline and the pipeline corridor. That's important for us. We're putting some money into that to try to finalize the pipeline routing, get all our clearances. We've got work at this point going on feed work, some feed work on the plant itself. We have to understand cost and schedule on that plant. Those are the important things. We're not spending huge money, but it is a lot of money in the sense, I'm sure, in the terms of hundreds of millions of dollars now. It's critical for us to have all of that where we can deal knowledgeably with buyers.
We have to understand cost, we have to understand resource, where we can deal with the particulars of pricing, because we're not going to do a project unless it's economic. We've always told you we're not going to go to FID on a project till we have 60% of the gas sold.
We have to understand the project in a good sense to do that. We got to understand project, we got to understand resource. I think we're moving quite well on answering the resource issue. I am not concerned with if Apache leaves that, I think we could easily step in and be operator of the upstream. Quite confident there. Apache has been very good to work with in this early stages of the assessment at Liard. I think we're in good shape, but we need to get clarity. We need to get to closure on the partnership. This work I mentioned, we need to do all of that where we can deal with buyers and understand cost and understand economics. We are very value driven.
We're not going to go to an FID onto a project until we have gas sales, and we understand the economics of that sale.
Great. Thanks. My follow-up is on if you could discuss Permian production in the quarter, and just how much did that contribute to the sequential 5% increase in U.S. volumes? Then as you think about 2015 and really bridging to the major project volumes in 2016 through 2018, do you see a scope and ability to further ramp Permian more significantly to bridge, like I said, the other major projects? Thanks.
Let me start with the last part of that a little bit. Permian for us is an area we can increase investment and increase production. We'd rather ramp up at an appropriate speed where we are very cost efficient on drilling and on infrastructure. From that perspective, it is a little bit of an asset that we can gauge and move to speed. Specifically in the quarter, I think we had a 5,000 barrel a day plus, and from the Permian area, that was good. We're right now running, I said 27 rigs. We have 14 verticals and 13 horizontals, so that's really good. I gave you the numbers on the slide of how many wells that have been drilled this year. I believe that was 265. We had told you in March this year that we were going to drill 500.
You can see that we are ahead of schedule on that. I think it's related to some efficiency we've seen in the rig operations. We've got a grand focus on reducing costs. This business out there is frankly about two things. It's drilling cost, getting your drilling costs down and getting your recovery up. We've got great focuses on both of those. Like I said, we're seeing the response. We're getting a few more wells and we're getting more barrels. We like what we see. The more we continue to see that, of course, we're going to be more willing to push more money there.
Great, George. I'll leave it there. Thanks.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question, please.
Hey, guys. George, two question, if I could. On both Wheatstone and Kitimat, can you talk about, from Chevron's position, whether that you have any interest to further increase your existing interest?
Paul, I'll be happy to. Maybe for everyone on the phone, I'll put in perspective a little bit Wheatstone and our interest relative to others, and I'll try to do that on Kitimat. At the Wheatstone asset level, so this is Wheatstone and Iago, the upstream piece of it, we hold 80% of that. Remember, you have a partnership that's between Apache and KUFPEC that is bringing Julimar online into a common facility offshore, and that our investments in the Wheatstone project, and the LNG portion of it is unitized, if you will, after that. The fields are not. We have a joint project from a central platform, a trunk line, and into an LNG plant. At that point, when you look at the LNG portion of it, downstream, that portion of it, we're investing 64%. We've got all the interest we really want.
It's a high end of our interest that we would normally have in any operation. I typically like to be, when I operate, in this 40%-60% range. Our working interest is at the high end of that. We're quite comfortable. We don't see any reason to have any more working interest in Wheatstone or other assets there. Now, speaking on Kitimat, and I'll build off of some of those earlier comments. We hold 50% of the interest in Kitimat, Liard, Horn River assets. That's right in the middle of the sweet spot where we like to be on working interest, where we're committing people to run the projects and run operations. What we've told the Street in the past, and I'll reinforce this, we actually hold 50%.
I feel I don't want any more than the 50%. We do have available some small amount of working interest that we would provide to an LNG buyer. There's always been a plan for us and Apache to have some volumes that we could, some working interest that could be sold down to buyers where they would be a part of the development and they would be in the full value chain. That has not changed. I'm not looking to increase our working interest beyond the 50%.
Second question. If I'm looking at page 16 of the presentation, next year, the major project, the current expected increase is 150,000 barrel per day. Your base operation previously assumed is at 3% underlying decline curve, assume that have not changed. That translate into roughly about 80,000 barrel per day drop year-over-year. That means that based on this particular graph, it would suggest it seems to imply your expected production growth for next year about 2%-3%, get to about 2.65. Don't know whether you can give us a number, what is your current projection for 2015, or if not, can you tell us that whether there's any other things that we should take that into consideration in this calculation?
You're good with numbers.
Try to.
Let me speak qualitative to this. First off, we give you our commitment number or guidance in January each year. In 2015, January 2015, we'll give you our guidance. I will only give a few qualitative comments about you've done the numbers right relative to the MCPs. Our base decline is running in this 3% or less. That's true. We haven't yet given you guidance on two other items. I will tell you, we're working that at this point in time. How many barrels are we going to have on our shale and tight? We've got investments going in shale and tight in the Permian. That's not in this number. How well is Vaca Muerta going to actually perform? We've got those two that are significant, and we've got to identify those as we go through our business plan process.
Of course, we've got another one that we haven't told anyone, and we haven't even ourselves haven't decided on which assets we're going to sell. We've got some sales that are going to occur. We're once again value driven. I don't know which ones are the ones that we're going to end up and sell. It's what's the whole value of them for us versus what will someone else pay on these late life assets. Those are the two aspects that I can't really answer at this point in time, but we will be able to give you an answer in January.
Thank you.
Thank you. Our next question comes from the line of Jason Gammel from Jefferies & Company. Your question, please.
Thanks, everyone. I wanted to come back to Gorgon, if I could. George, if I was interpreting your comments correctly, it seems that critical path on train one would be more delivering first gas on the island and commissioning work on the train itself and also the utilities. Can you confirm that's correct? When you think about the risks towards meeting that mid-2015 objective, where would you put labor amongst those, and what's your labor contract situation? I'm just thinking in light of what's happening on Curtis Island right now.
Let me start off on the critical path items going for us. ME and I is critical for startup. That is heavily dependent on labor productivity. We've got over 5,000 people working on the island. It's all about, for us, getting as much of that effort focused on the ME and I piece of it. I guess I would add one other thing, and we don't find any unknown problem. As we get closer and closer to startup, and this is true for every project that everyone does in the world, it's these unknowns that you just frankly don't know what's going to come up, and is it something that is easily mitigated or is it something not? We don't ever know that until we get them all done. The good news is every day you get closer, you eliminate more and more of them.
Being at 83%, we've already eliminated a lot of them, like logistics we know is not a critical path. We were worried about the jetty. It's not the critical path. We're eliminating those every day. Some big milestones that we'll report out in the following quarters, an example of a big one, the tank. We want to make sure we got LNG tank one ready. Often on LNG projects, the tanks are the critical path. We're just about to the point to say LNG tank one, with it being complete, it's not going to be on the critical path. I mentioned ME and I. One of the big next ones for us is the startup of our turbine generators. We've got all five of our generators there on the island. The next big step, and a big important step for us, milestone, is, of course, power.
We get the power running, that puts us in a great position on the commissioning. That's something we'll talk about on our next call. We'll keep giving you this information as we click them off. I do encourage everyone, since this has been brought up again, is take a look at some of those photos that we have. I think they really give you a flavor of what work is being completed.
George, just where do you set in terms of labor contracts, or excuse me, where does some of the contractors set in terms of their labor contracts? Do you have any changes to cost estimate? I think I know the answer to that one. When you expect to do a Wheatstone cost evaluation at the 50% completion mark, like what you did with Gorgon?
That's a yes. We always do that on all our projects, Jason. Labor is very important. We never take that for granted. We always have a strong focus on the industrial relations piece. We do have some contracts that have to be renegotiated. Of course, we're going to focus on making sure we deal with them where they don't become an issue.
Thanks a lot, George.
Thank you. Our next question comes from the line of John Herrlin from Société Générale. Your question, please.
Yeah. Hi, thank you. I've got a couple quick ones for you, George. With Jack/St. Malo, are you going to ramp those wells up the way you would a Miocene well, since they're different? Just curious.
I would actually think that we're going to probably see a little bit slower ramp-up on those. Remember, these are very high-pressure wells. The last thing we want to do is do any damage to the completion. We're going to be very focused, and I would say probably a little bit on the cautious side on the ramp of these and make sure we really understand what's happening at the face of the completion.
Great. Thanks. With the Permian, you're talking about drilling a lot of wells. Any issues with basin evacuation in terms of fluids or gas, in terms of infrastructure?
No, I think it is becoming a little more challenging for the industry in total. We feel very good about where we are in our position. That's one of the huge benefits for being a company that's been a large producer there for the long history of the basin. We're in a good position on that. I would tell you the other real positive, the industry in Texas moves darn quick at solving infrastructure problems.
Great. Thank you.
Thank you. Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question, please.
Great. Thanks, everybody. Given the volatility of performance in some international and offshore assets on timing and the smoother profile and the returns on the onshore side, is there a case to be made, not just over the next 12 months, but over the next five years to reallocate more capital in that direction and away from some of the other projects?
We have to look at it on a portfolio basis, and that's what we do each and every year as we build a new three-year business plan, and actually a longer strategic plan. When you have a portfolio that has lots of options out there, you can move things in and out quite easily, but it takes a portfolio that's got these options available. We do that each and every year. We don't like to jerk any of our businesses around. We like to keep our rig counts. If they're growing, we like to keep them growing in a gradual manner, not a big spurt. We are more efficient when we do that. Of course, we have to balance all that with our capital programs.
We don't have an infinite amount of capital spend, we try to get our capital focused on how we can get the best returns. We're going to, I guess, high grade our view going forward of how we want to spend our money and our business plan each year. We told you at our analyst meeting, the next 3 years, we're going to be really capital flat, pretty capital flat. That means we're going to be looking at how we get the most value out of that capital we spend. My anticipation is that we'll continue to see a little more money continuing to go to the Permian Basin, the Permian Basin or these other shale plays cannot offset the impact of these big projects either. We need all of that in our portfolio to grow.
We must have all the big projects, frankly, what the continuous plays give us, they give us another piece that's more continuous in growth and a nice part to have in your portfolio, and we're going to grow that a little bit over time. It's going to give us a little more flexibility as we go forward.
Okay. I think we've got time for just one more question here.
Certainly. Our final question comes from the line of Pavel Molchanov from Raymond James. Your question please.
Thanks. I have two quick ones. You've highlighted the production uplift from Vaca Muerta, given the headlines from Argentina this week, are you reconsidering or adjusting any investment?
We believe our contract and the terms we have and have negotiated provide us appropriate cover, I'm just going to leave it there. We feel good about our investments, the way it's set up. We're frankly pleased with the progress that we're making there. We're making good progress. The next big thing for me is continuing to watch the performance of the asset, I'm particularly interested in these two new sweet spots where we're drilling more wells. What I want to see there is I want to see a production kick up, then I'll feel better. I feel good contractually with what we have established.
Okay. That's helpful. On Kitimat, given the pending Apache exit, are you still likely to be able to reach FID by the end of this year, or are we looking at 2015 at this point?
We will reach FID. We're running our business there to be able to get to FID shortly after having 60%-70% of our gas committed to an SPA, a sales and purchase agreement. That is the critical decision maker on both timing and the investment decision.
Okay. Irrespective of what happens with Apache?
Irrespective of what happens with Apache. We're driven by, once again, having a sales contract or sale contracts that give us 60%-70% of the gas committed at an economic price.
Okay. Thanks very much.
Okay. Thank you. Before we close the call, I'd like to mention that going forward, we will no longer be issuing an interim update. For those of you who have followed us for some time, you will know that we have modified the format of our update over the past few years in an effort to have it be a clear and effective document. I have to say that that effort has not met with 100% success. Rather, many investors have suggested that it has not been all that helpful or insightful, and at times has added confusion rather than clarity. That's not a good place to be, and hence our decision to stop the practice. We do remain committed, though, to full disclosure and transparency.
As we have in the past, we'll strive to be very candid and clear in describing company performance in our earnings releases and our earnings calls, and our 10-K and our 10-Q, and in all of our other investor outreach activities. I'd like to thank everybody for your time today. We truly appreciate your interest in Chevron. Jonathan, back to you.
Ladies and gentlemen, this concludes Chevron's second quarter 2014 earnings conference call. You may now disconnect.