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 a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, this conference call is being recorded. I 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, and Jeff Gustavson, General Manager, Investor Relations. We will refer to the slides that are available on Chevron’s website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. We ask that you review the cautionary statement 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-day basis, earnings were $10.2 million 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-day earnings after netting gains, impairments and foreign exchange impacts was $10.1 million 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 are 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 distribution. We repurchased $1.25 billion of our shares during the second quarter and in the third quarter we expect to repurchase the same amount. Finally, Chevron’s five-year total shareholder return at the end of the quarter was 18.4%, which continued to lead the peer group and also was in line with the S&P500 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 negative affected earnings by $232 million during the quarter representing a negative swing of over a $0.5 million between periods. As a reminder foreign exchange movements for us are largely book translation effect with minimal cash flow impact. Upstream earnings increased by $315 million. Gains on assets transaction of approximately $610 million in absolute terms and higher realization were partially offset by unfavorable foreign exchange impact 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 million higher than first quarter results. Upstream earnings were up $957 million reflecting gains on asset transactions, higher lifting, modestly strong realization 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 variants in the other bar largely reflects the absence of the impairment and related charges for our 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 Basin and the Permian and in San Joaquin Valley increased earnings by $115 million.` Higher exploration expenses mainly associated with the deepwater Gulf of Mexico, decreased earnings by $95 million. The second quarter included gains on several separate assets transactions worth approximately $180 million in total. The other bar reflects a number of unrelated items including lower natural gas realization 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 interest 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 9 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 Basin in the Permian. We are 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. Plan turnarounds in Kazakhstan, Australia and in Denmark among others reduced production by 57,000 barrels per day. Absence of first quarter external constrains largely weather related disruptions in Kazakhstan as well as lower demand in Thailand, increased volumes by 27,000 barrels per day. The base business in 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 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 in titanium 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 cost 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 cost that could not be fully recovered in the marketplace. Foreign exchange losses were approximately $55 million higher compared to 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 would 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 delivers 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 grown 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 margins was $20.32 per barrel. The suggested 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 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 a $1.42 per barrel. This combined with higher exploration expansions and DDNA have been the primary contributors to this decline. We are cognizant of the current microenvironment, increasing cost of goods and services coupled with relatively flat commodity prices and we remain focused on managing controllable cost. Looking forward, we are 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 six months of the year, we have maintained a base decline rate of less than 3%. We also continue to see strong growth from 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 all scheduled 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 product entitlement effects are anticipated to continue and we don’t expect any LNG 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% to 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 would 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 the startup of our major capital projects. For the last several years, we’ve 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 are excited about the value creation. While many projects contribute to our growth, the majority of our new volume is generated by aid of our largest MCPs. Gorgon and Wheatstone in Australia; Mafumeira Sul and ALNG in Angola, Papa-Terra in Brazil and Jack/St. Malo, Tubular Bells and Bigfoot in the deepwater Gulf of Mexico. Now I will review progress on six of these projects. Moving to Slide 17. In early April, Angola LNG experienced a failure in the flare blow down 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 down string work of 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 5 are now on site. On the Gorgon upstream, hydrotesting has been completed on all 660 km of offshore pipelines. The well flow back and clean up operations on the eight Gorgon wells is ongoing and drilling has been completed on the tenth 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, build and piling work is progressing on schedule. The shore pool of the main 44-inch trunkline through the microtunnel was completed safely and as planned. Shipments from fabrication yards have commenced with the delivery of the first slug catcher components two side. The Wheatstone platform and topsides are now more than 63% complete and we anticipate the sailway of the platform’s zero gravity structure in August. Wheatstone remains on track for a late 2016 startup. Now I will review progress on our deep water 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 come -- to commence in the third quarter. The remaining work on Jack/St. Malo is progressing well and the project remains on track for late fourth quarter startup. Overall hookup 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. Bigfoot shipyard related construction is over 90% complete and preparations are being made for a fourth quarter sailway. Fabrication work on the tension leg platform tendons is now complete and whole 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 the slide. Bigfoot 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. Now I will 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 and developed 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 eight to 10,000 more. Since we are not in a drill or drop situation our approach has been to allow others to derisk acreage surrounding our own. This enables us to focus our capital on development wells rather than exploration and appraisal. In the Midland basin of the Wolfcamp play, industry drilling today has been predominantly via vertical wells. Earlier this summer, we spotted 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 please 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 blow 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 our longer term plans for this asset. Moving to Slide 20. I will 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 Elphin 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 stayed at our target to deliver 10 billion in asset sales over the 2014 to 2016 time period and 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 in that. We anticipate continued ramp-up in 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’s choke at one of our wells in the emerging southern trend. We anticipate this well will be turned into line this fall. And finally we’re also very encouraged with the initial results in the Kurdistan region of Iraq. Exploratory drilling and logging has indicated multiple play zones in a large structure. We have begun initial drillstone test and the formations have demonstrated the ability to deliver high liquid blow rates. On one of the two wells, we plan to test upto nine different zones. We’ll continue with our KRI testing program over the months ahead. Now I will turn it back to Pat.

Okay, thanks George. Turning to Slide 21. I would like to close with just a few thoughts. Global energy demand continues to grow and satisfying 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 drive future value growth for our shareholders. We continue to focus on executions. You just heard from George that our base business in the upstream continues to perform well and that we’re 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 rampup to full production ended July. We are now the largest producer of premium base oil 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 share holders. We have a broad, balanced and deep queue of investment opportunities and take a highly disciplined approach to capital allocations. 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 sell proceeds at total $1.6 billion now are 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 inflexion point. Indeed, two of the projects George highlighted are set to startup in the second half of this year and two more in 2015. Along with this sizeable 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. I short we are very excited about what lies ahead for the company. So 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 followup if necessary. We’ll do our best to get all of your questions answered. Jonathan, please open the lines for questions.

(Operator Instructions) Our first question comes from the line of Ed Westlake from Credit Suisse. Your question please.

Yes, good morning and thanks, George, for your time on the upstream as well. Maybe just firstly a question on cash flow. Last year about $36 billion, this year sort of $33 billion if you annualize the first half and obviously oil prices have state higher. 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.

Ed, we still feel good about our cash flow projections going out 2015, 2016 and 2017 and again it is obviously predicated on the production growth that George went through on major capital projects growth in the Permian and then 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 have -- we talked about on the slides are in the rear-view mirror so to speak at this point and 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 and of course you are slightly lower on production this year. But if you add up the turnaround production entitlements and base business you are losing some volumes, but even without major capital projects the volume trajectory is relatively flat. And then as I look at the slide that you put out, helpfully, on MCPs getting up to 900,000 barrels a day from the big projects and the other stuff that you are doing. And then I think about shale, it feels like something has to get worse to miss the 3.1 million barrel a day sort of 2017 guidance, which is a good position to be in. But I am just wondering what is it that gets worse in your assumptions as you look out?

Ed I just don’t have any things to get worse on 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, so there is a buffer in there. The only and part of the reason we had that buffer in there was always the forecasting ability but recognize that we’ve talked a lot more about asset sales and we have asset sales in our plan. We don’t always know exactly what assets sales will actually occur. We are very focused always on the value proposition of those and that’s really what we’ve got to focus on, creating the greatest value on those asset sales and it is 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 and then of course we look at some of our assets that are on the front that don’t compete for funds. So we’ve got a little bit of latitude in there to cover some of the assets sale losses that occur when we sell these properties but 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.

And very sneakily at the end, just in terms of three questions, it is 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 change in there and this probably heads off a question 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’ve all kinds of assumptions 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 TCO and in Bangladesh. The TCO 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 tells us what we’re going to -- gives us a really good indication of royalty net back that the well has. That gives us net back that the well heads, 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 in TCO was 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 sulphur and sulphur sold at a higher price translates to a higher net back for us that the well had also. And that reduces net production. It’s a really good thing for all of us. So that’s really positive. So if the value decision, right value decision. Similarly in Bangladesh, we’ve had an agreement on how we would look at that. That is now going to be reimbursed and the reimbursement will not will in effect reduce our cost barrels. There is a impact on that. It’s good for us to clear up the bad issue. It’s good from a profit gas or profit oil basis going forward that removes that cost out of it. So that’s another value creator for us not nearly as big as the TCO one but it’s a positive for us and those two items made 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, so -- and I’ll tell you we’re always going to go after the piece that makes the most value sense. Maybe that will 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.

Good morning

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 plan on 10% towards 20% recoveries. What is the path towards us -- and the timeframe I guess, towards us 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% to 10% range and then 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 onto 20%. We do believe we are on track for that. I am 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’ll tell you I am encouraged that 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 on the little bit of impact on our recovery view and of course we’ll have a much stronger view on production volumes as we get to the end of the year end March as we get a little bit of runtime on these wells. I feel good about what we’ve seen on the cleanup though and I’ll just leave it there qualitatively.

Okay. Interesting. And then the follow-up I had was on Gorgon start up. 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’ve a target to see gas introduced into the plant this year because we need the gas introduced into the plant to start commissioning activities. So one of our early activities is getting gas introduced in the plan getting the turbine generators running, get the power support for the operations. That utility piece is very critical to the startup and it’s actually a milestone that we’ll be talking about more in the next quarter’s call.

Cool and then the actual sale of LNG. When would that be?

I am not going to go that next step. I am going to leave it till we have the first LNG in the tank, which we will announce and once we have first LNG we’ll be announcing our target for first lifting.

Interesting. Thanks. And you are still trying to sell more contracts there, aren't you? Is there any reason why we haven't heard more about that given you have shown modeling of a shortage of LNG long-term? I'm just surprised we haven't heard more about contracts. And I will leave it there. Thank you.

Paul. We are still looking at opportunities so to sell more gas. We really don’t have a lot more to sell. Remember on the Wheatstone side, we already stood at 85%. so we are fully sold out there. As a reminder, we have some ability to move gas in our contracts from different assets we own. So 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 price.

And 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 there -- 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 will leave it there. Thank you.

Thank you. Our next question comes from the line of Doug 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 because this is something we have been kind of wrestling with. It may be overly simplistic, but you gave us cartoon at the Analyst Day that showed how the cash margin improves let's say in a $110 oil environment, so let's call that same-store sales with last year at $36 billion. But when we take the delta on production growth and the delta on the margin, it only adds about $8 billion to the cash flow, so that gets you to $44 billion, you are spending a little under $40 billion, the dividends are $7 billion and your buybacks are $5 billion. So can you help me with what else are you assuming in that inflection in cash flow that you talked about in your prepared remarks because your offstream guidance doesn't really seem to get us there.

Are you talking about 2015 or 2017?

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 2.7 million barrels a day last year would generate the $36 billion. So I'm trying to understand how big do you think the delta is, because according to your cartoon it is only about $8 billion.

Let me just start. So we -- 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. So 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 and 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 -- 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 in 2013 and what we’re expecting in 2017. On top of that, there will be we believe higher contributions in cash flows from our downstream sector. Obviously it's not as significant growth element there but there will be contributions on the chemical side and on the lubricant side and some of the R&M side. So when you put those components altogether we feel comfortable about saying under those set of assumptions particularly price and volume we’re going get to $50 million cash generation figure. And I think the point that’s really important here is the margin accretion that George has -- we've talked it for a couple of years here is not just on the incremental barrels, it's on the full portfolio and 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. I will take it off-line with Jeff because, like I say, I am using your numbers and the delta looks like $8 billion, but I will 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? Because obviously -- you are obviously familiar with the charter that has been out there constantly while this project has been moving forward, but 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 will leave it there?

Historically what we’ve said, we said we saw six months between train startups. So I’ll try to give you a little more context to what’s happening on train 2 and train 3 and I think very frankly it’s very good news on the train 2. Modules we expect we’ll have almost -- well, I'll just say most of the modules we’re trying to own Barrow Island by the end of the year and we will even have a few we think of the train 3 modules. So the module piece of the work is going quite well, so it’s moving forward very well. We don’t see any of the module work at this point on the critical path. So all of that puts us in a strong position to say we’re not seeing any slide on time between the startup of train 1 and train 2 and if anything, we may even see that tighten up a little bit but it’s a little early to go there so but it looks good at this point and that’s a real positive. Critical for us to get – get we'll try to get it offline.

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 Evan Calio from Morgan Stanley. Your question please.

Hey, good afternoon guys. The position on free cash flow is clear. A question for George. Staying with LNG, one of your partners, Apache, yesterday announced plans to execute on that LNG and Wheatstone for that matter. Any update on that project and does Apache's exit change any as how you think about the risk profile of that potential project?

Let me on -- we're -- 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 already can check off our confidence level on the other resource, the Horn River resources is already high. We’ve really done that appraisal so the focus on the resource side is really drilling in Liard, some appraisal work there and getting some production work. We think we’ll have those actually those wells -- 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. So that’s really important step for us. The other pieces that we’re spending money on only aren’t related to Liard. There’s a little bit of money on how we’re going to actually handle the upstream initial production and then of course we’ve to focus on the pipeline and the pipeline quarter. That’s important for us. We’re putting some money into that to try to finalize a pipeline, rounding it all in clearances and then we’ve got work at this point going on field work. Some field 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 am sure for -- in the terms of 100s of millions of dollars. Now it’s critical for us to have all of that where we can deal knowledgably with buyers. We have to understand cost. We have to understand resource where we can deal with the particulars of pricing, but we are not going to do a project unless it’s economic. We’ve always told you we’re not going to go to FID one project till we have 16% of the gas sold. We’ve to understand the project in a good sense to do that. So we’ve got to understand project. We’ve 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 there 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. So I think we’re in good shape but we need to get clarity, we need to cope, we need to get the closure on the partnership and this work. I’ve 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 and do a project until we have gas sales and we understand the economics of that sale.

Great, thanks. And my follow-up is 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? And 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 will rather ramp at a appropriate speed where we are very cost efficient on drilling and on our infrastructure. So 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 in from the Permian area that was good. We’re right now running I said 27 rigs. We’ve 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 and 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 take it’s related to some efficiency we’ve seen in the rig operations. We’ve got a grand focus on reducing cost. This business out there is frankly about two things. It’s drilling cost, getting your drilling cost down and getting your recovery up. We’ve got great focuses on both of those and like we’re seeing the response. We’re getting a few more wells and we’re getting more barrels. We like what we’ve seen. The more we continue to see that of course we are 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.

Hi guys. George, two questions if I could. On both Wheatstone and Kitimat, can you talk about from Chevron's position whether you have any interest to further increase your existing interest?

Paul, I’ll be happy to and maybe I’ll for everyone on the phone I’ll put in perspective a little bit. Wheatstone and our interest is relative but 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 Brunello 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 but we have a joint project from a central platform, a trunkline and into an LNG plant and at that point when you look at the LNG portion of it downstream, that portion of it -- we are 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% to 60% range. So our working interest is at the high end of that and 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 on 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 to run the projects and run operations. What we’ve told the street in the past and I will reinforce this, we actually hold 50% of it and I don’t want any more than the 50% and we do have available some small amount of working interest that we would provide to an LNG buyer and there’s always been plan for us and Apache to have some volumes that we could -- some 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 and I am not looking to increase our working interest beyond the 50%.

Second question, if I am looking at page 16 of the presentation, next year the major projects, the current expected increase is 150,000 barrels per day. Your base operation previously assumed is at 3% underlying decline curve, I assume that has not changed. That translated to roughly about an 80,000 barrels per day job year over year. So that means that based on this particular graph it would suggest this seems to imply your expected production growth for next year about 2% to 3%, get to about 2.65. I don't know whether you can give us a number what is your current projection for 2015 or if not can you tell us whether there is any other things that we should take into consideration in this calculation?

Paul you are good with numbers. Okay, let me speak qualitative to this. First up, we give you our commitment number guidance in January each year. So in January 2015, we’ll give you our guidance. I’ll 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 and 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 have got investments going in shale and tight and the Permian. That’s not in this number. How well is Vaca Muerta going to actually perform? So we’ve got those two that are significant and we’ve got to identify those as we got through our business plan process and of course we’ve got another one that we haven’t told anyone and we haven’t ourselves haven’t decided on which assets we’re going to sell. So we’ve got some sells that are going to occur. We are once again value drive. Actually I don’t know which ones are the ones that we’re going to end up and sell. What’s the whole value open for us versus what will someone else pay on these late life assets. So those are the two aspects that I can’t really answer at this point in time. But we will be able to give an answer in January.

Thank you.

Thank you. Our next question comes from the line of Jason Gammel from Jeffries and 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 1 would be more delivering first gas on the island and commissioning work on the train itself and also the utilities. Can you confirm that is correct? And when you think about the risks towards meeting that mid-2015 objective, where would you put labor amongst those and what is your labor contract situation? I am just thinking in light of what is happening on Curtis Island right now?

Let me start off on the critical path items going for us. ME&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&I piece of it/ And 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 and we don’t ever know that until we get them all done. The good news is that every day you get closer, you eliminate more and more of them and being an 83% we’ve already eliminated a lot of them like logistic we know is not a critical path. We were worried about the jetty. It’s not the critical path. So we’re eliminating those every day. Some big milestones that we’ll report out in the following quarters. An example of big one that we don’t have the tank. We want to make sure we got LNG tank 1 ready. Often on LNG projects the tanks are the critical path. We’re just about to the point to say LNG tank 1, with it being complete, it’s not going to be in the critical path. I mentioned ME&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 and that’s something we’ll talk about on our next call, so we’ll keep giving you this information as we click them off and I do encourage everyone since this being brought up again is -- take a look at some of those photos that we have. They are -- I think they really give you a flavor of what work is being completed.

And George, where do you set in terms of labor contracts -- or excuse me, where do some of the contractors set in terms of their labor contracts? And do you have any changes to cost estimate? I think I know the answer to that one. And would 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 industry relations piece. We do have some contracts that have to be renegotiated and 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 herland from Societe Generale. Your question please.

Thank you. I have got a couple of 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 are 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. So 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 place of the completion.

Great, thanks. Then with the Permian, you are talking about drilling a lot of wells. Any issues with basin evacuation in terms of fluids or gas -- in terms of infrastructure.

I think it is becoming a little more challenging for the industry in total. We feel very good about where we are and 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. So we’re in a good position on that. I would tell you the other real positive, the industry in Texas moves darn quick in 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. If I could follow-up on an earlier question in terms of the pace of the onshore. If we look at your performance, I think over the past 12 months these biggest bar on the growth side was from your tight and shale assets. You have got extremely high quality positions in the Permian and Argentina and a number of other places. And given the volatility of performance in some international 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 had 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. We 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 business around. We would like to keep our rig counts if they are growing. We would like to keep them growing in a gradual manner not a big spurt. We’re more efficient when we do that and of course we have to balance all that with our capital programs. We don’t have an infinite amount of capital spend. So we try to get our capital focused on how we can get the best returns. So we’re going to I guess high grade our view going forward of how we want to spend our money in our business plan each year. We told you at our Analyst Meeting that in the next three 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 grow, go the Permian Basin but 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 and 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. So it’s going to give us a little more flexibility as we go forward.

Okay.

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’ve two quick ones. You’ve highlighted the production uplift from the Vaca Muerta but given the headlines from Argentina this week are you reconsidering or just doing any investment?

We believe our contract and the terms we have and have them negotiated provide us appropriate cover and I am 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 actually continuing to watch the performance of the asset and I am particularly interested in these two new sweet spots where we’re drilling more wells and what I want to see there is I want to see a production kick-up and then I’ll feel better but I feel contractually with what we’ve established.

Okay, that is helpful. And 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 when we -- and we’re running our business there to be able to get to FID shortly after having 60% to 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. So irrespective of what happens with Apache?

Irrespective of what happens with Apache. We’re driven by once again having a sales contracts or sale contracts that give us 60% to 70% of the gas committed and for an economic price.

Okay. Thanks very much.

Okay thank you. Before we close the call, I would 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 and 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 call and our 10-Ks and our 10-Qs and in all of our other investor outreach activities. I would 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.