Good morning. My name is Jonathan and I will be your conference facilitator today. Welcome to Chevron’s Fourth Quarter 2013 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, this conference call is being recorded. I will now turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corporation, Mr. John Watson. Please go ahead. John S. Watson: Thank you, Jonathan and welcome to everyone to Chevron’s fourth quarter earnings conference call and webcast. On the call with me today are Pat Yarrington, our Chief Financial Officer and Jeff Gustavson, who is our General Manager of Investor Relations. We will refer to 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 detailed cautionary statement on Slide 2. Turning to Slide 3, I want to begin by highlighting some of our strategic accomplishments for the year. We had our lowest ever days away from work rate continuing our improvement over several years now. We’ve been the industry leader on this metric since 2010. Our financial performance in 2013 was solid. Once competition results are fully analyzed we expect to once again post the highest upstream cash and earnings margins per barrel compared to a broad set of peer competitors. Our strong cash flows and balance sheet allowed us to fund our capital program and capture new resource opportunities while maintaining competitive shareholder distributions. In our downstream business we started commercial operations of a 53,000 barrel per day vacuum gas oil FCC unit at the 50% owned Yeosu Refinery in South Korea. We made significant progress on the construction of a 25,000 barrel per day premium base oil plant at the Pascagoula, Mississippi refinery here in the U.S. We expect to reach mechanical completions toward the end of the first quarter and we will then ramp-up to full capacity during the second quarter. In addition, we’ve also advanced our Oronite expansion project in Singapore. Our CPChem affiliate, our 50% owned chemicals joint venture announced final investment decision on a $6 billion US Gulf Coast Petrochemical project. In our upstream business we achieved startup and first shipment from Angola LNG, production began at the Papa-Terra project in Brazil; we also start up North Rankin-2 in Australia, which maintains production capacity at the North West Shelf LNG project. We made substantial progress on our major capital projects at the end of January. Gorgon is currently about 76% complete while Wheatstone is about 27% complete. Similar to prior quarters we have posted a number of photos highlighting our construction projects on these two important facilities on our Chevron Investor webpage located at chevron.com. We also continued construction activities for our projects in the deepwater Gulf of Mexico. The Jack/St. Malo is now moored at its offshore location and is on schedule for startup later this year. Big Foot is expected to be towed to location in the third quarter with expected startup next year. We reached final investment decision for the Alder developments in the U.K. North Sea as well as for Moho Nord in the Republic of the Congo. We had a very busy year from a resource capture standpoint, successfully acquiring an interest in a discovered resource opportunity in Argentina to develop and explore the Vaca Muerta Shale and we also closed our entry into the Kitimat LNG project in Western Canada where the resources will come from new positions in the Horn River and Liard basins. We acquired additional shale and tight resource acreage in the Cooper Basin in Australia and the Duvernay Basin in Canada, the Permian Basin in the U.S. as well as in the Ukraine. We also grew our exploration portfolio by acquiring positions in the Kurdistan Region of Iraq, Australia, Brazil, Morocco, and in the deepwater Gulf of Mexico. Our one year reserve replacement was 85%, bringing our three year replacement ratio to 123%. We are proud of our performance this past year. With that I’ll turn it over to Pat, who will take you through the financial results, Pat? Patricia E. Yarrington: Hi, thank you John. Slide 4 provides an overview of our financial performance. The Company’s fourth quarter earnings were $4.9 billion or $2.57 per diluted share. For the year earnings were $21.4 billion, this equates to $11.09 per diluted share. Return on capital employed for the year was 13.5% and our debt ratio at year end was 12%. 2013 marks our 26th consecutive annual dividend increase with 11% growth in the quarterly rate. This demonstrates our confidence in our future performance and is consistent with our priority of rewarding shareholders with sustained and strong dividend growth. In the fourth quarter, we repurchased $1.25 billion of our shares, bringing the full year share repurchase total to $5 billion. In the first quarter of 2014, we expect to repurchase the same amount. Finally, Chevron’s 2013 total shareholder return was 19.2%. We continue to lead our peer group on total shareholder returns for the three year, five year and ten year period. Turning to Slide 5. Cash generated from operations was $10.5 billion during the fourth quarter; this was the strongest cash generation quarter of the year. For the full year, cash from operations totaled $35 billion reflecting the continued cash generating strength of our portfolio. Cash capital expenditures were $11.6 billion during the quarter and $38 billion for the full year. We had a very successful year on our resource acquisition efforts as John just mentioned. At year-end our cash balances totaled $16.5 billion giving us a net debt position of $4 billion. The Company continues to move towards a more traditional capital structure. Turning to Slide 6, I’ll compare results for the fourth quarter 2013 with the third quarter 2013, as a reminder our earnings release compares fourth quarter 2013 with the same quarter a year-ago. Fourth quarter earnings were $4.9 billion, $20 million lower than the third quarter results. Upstream earnings were down $240 million, reflecting lower liquids realizations and higher exploration and operating expenses. Partially offsetting were favorable foreign exchange movements of $490 million. Downstream results edged up $10 million between quarters, higher margins and favorable inventory effects were mostly offset by the absence of gains on asset transactions and higher operating expenses. The variance in the other bar largely reflects the favorable swing in corporate tax items during the quarter. On Slide 7, our U.S. upstream earnings for the fourth quarter were $223 million lower than third quarter’s results. Lower realization decreased earnings by $165 million consistent with the decline in U.S. crude oil price indicators. Lower production volumes reduced earnings by $35 million mainly due to planned maintenance activity in the Gulf of Mexico and cold weather disruptions in the Mid-Continent region. The other bar reflects a number of unrelated items including higher operating expenses and unfavorable tax impact partially offset by lower exploration and DD&A expenses. Turning to Slide 8, international upstream results were just $17 million lower than last quarter’s results. Realizations decreased earnings by $60 million consistent with the decline in Brent prices between quarters. Higher exploration expenses mainly driven by the write-off of an exploration well offshore Canada and higher geological and geophysical expenses across multiple areas decreased earnings by $190 million. A combination of higher operating expenses and DD&A lowered earnings $150 million between periods. The other bar reflects a number of unrelated items including the absence of asset sale gains and favorable tax effects from the prior quarter. A favorable swing in foreign currency effects increased earnings by $490 million. The fourth quarter had a gain of about $300 million compared to a loss of about $190 million in the third quarter. Slide 9 summarizes the quarterly change in Chevron’s worldwide net oil-equivalent production. Production declined 9,000 barrels a day between quarters. Our shale and tight assets contributed 7,000 barrels a day, mainly from new production in the Marcellus region in the U.S. and Vaca Muerta in Argentina. External constraints lowered fourth quarter production by 12,000 barrels a day, reflecting lower demand in Thailand and in Bangladesh, as well as weather-related disruptions in the U.S. The base business and other bar include the impact of normal field declines, which are partially offset by higher production from Agbami in Nigeria. Slide 10 compares full year 2013 net oil-equivalent production to that of 2012. Production declined by 13,000 barrels per day in 2013. Production averaged 2.6 million barrels per day for the year, 98% of our original guidance. This is driven primarily by the slower ramp up at Angola LNG, more expensive turnaround activities and lower gas demand than anticipated in several countries. Base business declines and asset sales reduced production by 49,000 barrels per day between years. Our base business operation delivered strong performance for 2013. Our base decline rate was lower than our target of 4% providing significant barrels and value. Growing volumes from our shale and tight resources in the Permian and in the Marcellus regions in the U.S. contributed 25,000 barrels per day. Our shale and tight production grew more than 15% in 2013. Incremental production from our major capital projects contributed 11,000 barrels per day driven by the Angola LNG startup, First Oil from Papa-Terra in Brazil and the ramp up of production at the Usan field in Nigeria. Turning now to Slide 11, U.S. downstream results were up $16 million between periods. Stronger margins increased earnings by $95 million, mainly due to lower crude costs. West Coast refining margins also benefited from the completion of plant maintenance activity in the third quarter at our El Segundo, California refinery. Gains on asset sales contributed about $90 million less in the fourth quarter than the third quarter. The other bar reflects a number of unrelated items of smaller impact. On Slide 12, international downstream earnings were nearly flat between quarters. Margins improved earnings by $20 million. Higher refining margins in Canada on lower crude cost and improved marketing margins in Australia were partially offset by lower refining margins in Asia, where we’ve seen weaker demand and ample supply. Higher operating expenses decreased earnings by $60 million principally for maintenance, repairs and transportation. The other bar includes a number of unrelated items including favorable year-end LIFO impact partially offset by lower trading results and an unfavorable swing in foreign exchange impact. Slide 13, covers all other, fourth quarter net charges were $312 million, compared to $522 million in the third quarter, a decrease of $210 million between periods. A favorable swing in corporate tax items resulted in a $162 million benefit to earnings while corporate costs were $48 million lower this quarter. For the full year, this segment had net charges of $1.6 billion, putting us in the lower end of our $400 million to $500 million guidance range per quarter. We believe this quarterly guidance range for the all other segment is still appropriate going forward. With that, I’m going to turn it back over to John for a few comments on 2014. John? John S. Watson: Thanks Pat. Turning to Slide 14, in December you recall we announced a $39.8 billion capital program for 2014, $2 billion lower than 2013. We expect 2013 to be a relative peak spending year, and 2014 to represent the peak year for LNG spend as our two Australian LNG projects move closer to production. This program also supports our large deepwater Gulf of Mexico developments as well as ongoing development and ramp up activities in the Permian Basin in the U.S. We’re also investing in longer term projects in Kazakhstan, Canada and West Africa which will drive profitable growth for many years. Importantly, planned spending is directed towards our profitable base business assets throughout the world and well, this includes significant activity across several producing regions in North America as well as in Thailand and Indonesia, amongst others. Our downstream investments for 2014 are geared toward enhancing reliability and energy efficiency, feedstock flexibility and the production of cleaner transportation fuels. We’re also funding major capital projects related to our chemicals business. Our Oronite expansion project in Singapore is planned to startup in 2014 and we’ll begin ramping up construction activities on the U.S. Gulf Coast petrochemicals project which recently reached FID and is planned to startup in 2017. We have an attractive portfolio of investment opportunities, which will continue to fund in a disciplined fashion to grow enterprise value and fund shareholder distributions. On Slide 15, our net production outlook for 2014 is 2.61 million barrels oil equivalent per day based on average Brent price of $109 per barrel, which was the same average price as 2013. This outlook does not assume OPEC curtailments, material and security or other market impacts. Our full year estimate for 2014 includes modest production ramp-ups at Angola LNG, Papa-Terra and in the Permian Basin. These are expected to be partially offset by declines from our base producing assets, where we continue to assume an average decline rate of approximately 4%. Our focus is on managing the decline rate related to our base business, which is performing very well and on executing with excellence those developments which are expected to add material production volumes in the years ahead. Our long-term production growth outlook is compelling, profitable and will add value. It is driven by five large projects; Angola LNG, Jack/St. Malo, Big Foot, Gorgon and Wheatstone, which in total will add over 500,000 barrels per day of net new production to Chevron at full capacity. In 2015, we’ll see the start-up of Gorgon and Big Foot and additional ram up of Jack/St. Malo. We look forward to providing more details on our key projects and production outlook at our upcoming Security Analyst Meeting. Thank you. That concludes our prepared remarks. I appreciate you listening in this morning and your interest in the company. We’re ready to take some questions. Keep in mind that we do have a full queue. So please limit yourself to one question and one follow-up if necessary. I will do our best to get all of your questions answered. Jonathan, please open the line for questions.

Thank you. (Operator Instructions) Our first question comes from the line of Doug Terreson from ISI Group. Your question please.

Good morning, everybody. John S. Watson: Hey, Doug. Patricia E. Yarrington: Good morning.

My question is about capital discipline and specifically the decline in returns on capital to around 14%, which I think places that result at its lowest level in many years. And on this point, John, you talked about the importance of value creation, and you always do actually, but also making hard choices in capital allocation when you were in New York recently. And so while I recognize that you have to complete investment in these megaprojects, I want to see what the Company is doing to address this issue from a corporate planning perspective, or whatever you deem relevant to ensure that this value creation process is optimized. John S. Watson: Sure. Good question, Doug.

Thanks. John S. Watson: We did enough capital program as I said of $39.8 billion. It’s a significant program and it largely reflects the good queue that we have. When I reflect on our company and our capital discipline you know we have a wide lead in profit per barrels, some $5 a barrel, not just over the majors, but over independents and others. So we have had discipline over the years and the projects that we have in the queue, we think will also add to earnings going forward. Now it’s true that the cycle time for some of the projects that I mentioned those big five that I mentioned is long and so there is capital that is not yet on production in the queue. Notwithstanding that, we actually expect our upstream business to have the second highest return on capital employed this year despite that high level of pre-productive capital. So I think we’ve got good discipline on these projects. We got a good record of doing it. Now inside the company we’re cognizant that there has been a significant increase in the cost of goods and services across the industry. Since the middle of last decade costs have more than doubled and there is some hotspots around the world. So we’re looking very closely at the projects that are in our portfolio. Naturally we’re going to continue with the projects that are under construction, but you’ve seen a couple of areas where we have made some choices. The Rosebank project in the North Sea, we think that’s a good project, a good resource, but cost came in just higher than what we felt were appropriate. So we’re taking a hard look at that project, reviewing it, seeing if we can make the economics more attractive. The Vietnam gas project, we worked – we and frankly Unocal before us worked for more than a decade to try to make that project a success, haven’t been able to do that just yet. So I think that we’re really doing what we can. I’d tell you also in the U.S. we’ve scaled back our spending on gas as you might expect. So the volume that you’ll see from gas in the U.S. will be less than we might have planned a few years ago. The only area where we’re spending on gas in any appreciable amount is in the Marcellus where we have a carry that enables us to continue to spend. So all of those things plus outreach that our employees are making with vendors and contractors and frankly just belt-tightening in general, which is a big focus for us right now and will be a message that I’ll be sending in my worldwide conference call with employees in a couple of weeks, are the kinds of things that we’re working on.

Okay, those are all great points. And so let me just ask one more. So have you guys quantified what your level of pre-productive capital is, however you guys define it, and how that compares to normal today, John? John S. Watson: We do and I’ll make you a promise that Pat Yarrington will show you a fair amount of information on that when we come back in March. But, Doug, it’s at a high level right now.

Sure. Okay, great. Thanks a lot. John S. Watson: Okay.

Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please.

Thanks. Good morning, guys. If I could take one and my follow-up please. John S. Watson: I can’t hear you, Doug. Patricia E. Yarrington: Doug, you've cut out.

Hi. Can you hear me now? John S. Watson: If you speak up.

Yes, I will try and speak up, sorry. So John, your production trajectory for 2014 I think has taken some folks by surprise in terms of the – [the price is] [ph] basically flat year-over-year. Has something slipped or changed there or are Street expectations just wrong or can you basically give us an idea when you expect the inflection point in production? And I've got a follow-up, please. John S. Watson: Sure. As I indicated, our production guidance for 2014 is 2.61 and really there’s couple of things to talk about. One, our base business has been performing very well. So we’re continuing to invest in the base and frankly we’ve seen some declines that are less than we’d expect, but we do use our standard 4% decline estimate for the base business, the underlying business for 2014. Beyond that it’s a function of ramp-ups that we have on major capital projects and there are really a couple that fall into that category. One is Angola LNG and the other is Papa-Terra in Brazil that Petrobras operates. We’ve got a couple of wells on in Papa-Terra, but the ramp-up takes place. It’s really a two-part project that will take place over the course of this year and we take operator guidance in setting that estimate. Angola LNG ramp-up is less than we would have expected a couple of years ago and this might be a good time for me to talk about that project. Our share of production from Angola LNG is 60,000 barrels a day net at full capacity. We’ve had about five cargoes last year. I think we've had a couple that we've lifted this year, but we’ve been working on some technical issues on the front-end of the plant with the dehydration unit. Remember this is an associated gas project, meaning there is variable feed coming from different facilities. We’ve had some technical issues on the front-end of that plant. And so our expectation is it will not ramp up to full capacity this year. It will likely be more like 30,000 barrels a day if we run it about half capacity this year with the full fix in the first part of 2015 and then ramp up to full capacity after that. So that is probably one of the factors that might be influencing the estimates that are out there. Beyond that we’ve got Jack/St. Malo which we’re very pleased with, which we’ll be starting up late in the year. Obviously you only get a partial year’s production from a later in the year start up, but that will start up nicely. So I think it’s more likely that the inflection point will come next year than this year. I don't think that’s inconsistent with the guidance that we gave. If you go back to 2010, in the sense that we said that we would grow roughly 1% between 2010 and 2014 and then 4% to 5% a year thereafter ramping up to our larger target. But understanding the performance of LNG has impacted 2014 to be sure.

Thanks for the answer, John. My follow-up very quickly to Pat is, a move to a normal balance sheet structure, Pat, it looks to us that your cash burn is about $10 billion a year. Is it realistic that you add $30 billion by the – to your balance sheet by the time you hit your targets in 2017? And I will leave it there. Thanks. Patricia E. Yarrington: Doug, that will all be a function really of what realizations are, what’s happening from the crude market standpoint fundamentally. But I mean, if you assume no significant change from where we are today from a realization standpoint and acknowledge what the production growth will look like and what cash from operations could look like, we would expect to add additional borrowings to our balance sheet of reasonable size over the next couple of years. So we are starting with a very low leverage rate, 12% right now and there’s a lot of capacity that we can utilize to not only fund the business activity, reinvest in the business, but also continue on with strong shareholder distributions. John S. Watson: Let me offer a couple other comments, if I could on that one. Our cash C&E this last year in 2013 was about $39 billion. That included some acquisitions. We expect fewer this year and the cash spend is about $35 billion this year. In addition, asset sales were relatively low last year. We expect modestly higher asset sales going forward. We’re doing some rationalizing in the midstream business, part of the ordinary course of business and we have a few things we’re looking at in the upstream portfolio. Remember most of the cash drain you’re referring to is planned orderly to restore balance sheet back to a more leveraged structure and is largely a function of share repurchases that we're putting in place. Our intention as we start ramping up production of course is to get to a point where we not only cover C&E, but also cover the dividend. Our policy on dividend has been to grow that dividend commensurate with the ongoing pattern of earnings and cash flow over the long-term. So we’re in this period where we have relatively high spend. We’re generating good cash, but we expect cash generation to increase and as we go forward we expect the cash consumption to attenuate as we roll into higher levels of production.

Thanks. I appreciate the answers. John S. Watson: Yes.

Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please. Ed G. Westlake: Yes. Good morning and thanks for your time. Just coming more I guess back to the U.S. I mean your CapEx in the upstream and your outlook is sort of relatively flat. I mean I appreciate there are some really big projects in the Gulf of Mexico. But you have this emerging shale position not just in the U.S., also obviously up in Canada. Maybe talk about why you are not getting after that more aggressively? I actually saw some really good well results from you guys down in the Permian this morning? John S. Watson: Well, you want us to spend more Ed? Ed G. Westlake: In that area potentially, but what stops you or…? John S. Watson: Well, a couple of facts. I don't know what, we’ve got a couple of different shale plays going on in Canada. One is in Duvernay, which is liquids oriented and we’ve drilled it. I think we’re on our 13th well up there and have had some good success and we are looking to develop that at a good pace. Our approach to the shale is to make sure we understand what we got and to plan in orderly fashion so that we can keep cost in line commensurate with the production that we can generate. So I do agree with you. We had some good results from those wells. The second of course is the Horn River and Liard Basin, which is gas to support the Kitimat project, which – well, there will be additional drilling in the Liard this year to delineate those holdings and of course that production would be associated over time with an LNG project at Kitimat. Ed G. Westlake: And I was also referring to the Permian obviously where you have got a huge acreage position. It just feels that if that was in the hands of an independent they’d be gung ho after it, whereas it feels that perhaps due to corporate CapEx constraints you guys or maybe delineation are going a little bit slower. John S. Watson: Well, I know that’s what the independents tell you. What I would tell you is we work very hard to put together a really sustainable and capital-efficient plan over time. Having said that, we drilled some 460 gross wells in 2013, which is more than we had planned. We got 26 rigs working in the basins there. About half of those actually are non-op rigs as well as our own rigs. And I think you’ll see that we are ramping up activity pretty nicely. In March George will show you some charts that will give you a better feel for that, but I think you’ll see a nice ramp up both in the number of rigs and in production that will come from that area. Remember, one thing, we do try to be efficient with our capital. We are focused on making good returns and so we do want to be sure that we can do it in a low-cost fashion and do it in a way that will generate the kind of financial results overall that will keep us leading. I mentioned earlier that we lead in earnings per barrel relative to the majors, but we also have a big lead in return on capital and return per barrel relative to a lot of the independents as well. So we may not go as fast as some of the independents, but I think it’s the right way for us to move forward. Ed G. Westlake: Thanks, John. John S. Watson: Yes.

Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question please.

Thanks. Good morning. Patricia E. Yarrington: Good morning.

John and Pat, maybe I have two questions, both of them is somewhat higher level. One is from a capital allocation standpoint. Obviously the last several years, the Company has been going after a lot of the legacy long-term megaprojects, which is great once that they compete. But from a portfolio management standpoint is there a point that you want to say maybe balance the portfolio a little bit between whether from a production standpoint or capital standpoint between the megaprojects, which obviously have a higher risk in terms of the underlying execution and also somewhat binary in nature comparing to a more steady maybe shorter-term projects? That’s the first question. John S. Watson: Okay. Well, certainly we do quite a bit of work, Paul, on portfolio management to do just as you described. In fact, we tried to balance the portfolio in many ways, but certainly one is the balance between the investments in long-term projects and short-term money. We consciously took on some projects that we felt were opportunistic and ready to go with Gorgon, Wheatstone, Jack/St. Malo and Big Foot. And so, we knew that we had a heavy period of spend for those projects, but at the same time we’ve really maintained a very strong base business spend program. About 30% of our spend goes into smaller capital projects and you make a good point because I just, for example, just happen to review our performance on small capital projects within the last couple of weeks and the returns are quite good. These are typically incremental projects, incremental drilling projects to existing assets. And so, we do maintain that spend. In fact the discretionary spend that we have is in that area and we have announced the strong capital program for 2014, and my alternative was largely to cut those base business spend and we decided not to do that. So we tried to balance both those factors so that we get strong returns on capital over time and get good growth and we’ve been able to do that. Despite all the capital that’s in the queue we still, from the numbers that we have, we think we’ll maintain our second position on return on capital employed.

John, on [indiscernible] is there a ratio over the next five or 10 years that you want to have 50% of the capital on the legacy megaproject and 50% on the smaller and the base business? Or there is not even a ratio that you guys consider or look at? John S. Watson: Well, we will have a higher – I think we’ve advertised before that we are moving toward a higher percentage of legacy, what we call, legacy or very low declining project, so that as we get toward the end of the decade we’ll be at about 60%. So things like Gorgon, Wheatstone, Tengiz, Angola LNG and the like, even some of our low decline assets such as California heavy oil activity is very low decline and we’re moving to a higher level. The plus side of that is as you get those on line the amount of spend that it takes to maintain them tends to be fairly low. So we are moving to a higher level of what you’d call legacy spend projects and I think they will deliver a lot of cash and stability for years to come once we get them all on line.

Okay. The second question is that over the last couple years that you have been borrowing – or actually now since you have been borrowing money to fund a buyback, and as the balance sheet return to more normal, at what point, what would you say, fixed financial ways such as net debt to capital or interest cap [ph] ratio the company will start to reconsider the buyback whether or that you would continue to borrow money to fund it? John S. Watson: I’ll let Pat talk a little bit about our philosophy on debt and the rating agencies and how much capacity we’ve got. Patricia E. Yarrington: Right. And Paul, we said for a long time now that obviously from a cash distribution standpoint the priority is on dividend. Secondly, we invest in the business and cover up the strength of our balance sheet from a pension funding standpoint and that kind of thing, so the third priority. And then finally, it’s share repurchases that become kind of the surplus use of cash and we have also said several times here now that we were in an unusual net cash position for several years now. We will be moving into a net debt position. We have now done that. As I look forward we still have a tremendous amount of borrowing capacity available to us. We believe that we’re very confident in the future cash generation from these projects once they come on line. And so we can see our steady state here from a share distribution standpoint on share repurchases for a while. We also see intensions to continue to grow the dividend. We have a lot of flexibility in our balance sheet and I don’t think that there is a consideration at least in terms of steady macro condition that would suggest that we would be turning our share repurchases at this time.

Thank you.

Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley. Your question please.

Hey. Good morning, guys. John S. Watson: Hey, Evan.

John, on the CapEx, I know that the organic cash CapEx exceeded your guidance by about $2 billion. As you assess that 2014 CapEx budget what gives you confidence that you won’t experience similar inflation? I mean, is there anything different, any protections, conservatisms versus what happened as you – versus how you asses 2014? And then I have a follow-up. Thanks. John S. Watson: Our number – taking out the money for acquisitions that we had last year, the amount that went over the budget I think was lower than that. So I don’t know that we disclosed the exact dollars of those acquisitions, but it’s somewhat lower than that. So I don’t think we’d be having the conversation about capital had we not had those one-time acquisitions. But candidly, if we have a supplement to a project we’re going to fund it in that year. In general we manage our budget pretty tightly and I have no reason to believe at this point that we’ll exceed the $39.8 billion that we put out there. We’re sensitive to it, you’re sensitive to it. So we will be watching it very closely.

Similar and maybe this is something for the Analyst Day. As obviously organic CapEx, cash CapEx trend here is flat and you mentioned a peak LNG spend in 2014. There are a lot of your peers that are forecasting a peak CapEx. So do you see a similar overall trend based upon your current slate of projects? And then maybe secondly, this is the other side of the question. It’s unclear what the world looks like in two, three, five years let alone the opportunities in the asset market, M&A market, resource market, et cetera. I mean do you see any real ability to forecast a longer-term CapEx figure? And I will leave it at that. John S. Watson: Well, it’s a good question. One of the reasons – and I’ve told you and others before, one of the reasons we haven’t put out long-term capital forecast is because it’s very hard to predict oil prices, foreign exchange, local content requirements, cost of goods and services. What we have been fairly good at understanding is the competitive nature of our project. So when we put out long-term production forecast we’ve had a view that – we know the world is going to need energy, we know that we got projects that will compete because of the resource and general nature of the project. And so, we’ve been – frankly we stepped out quite a bit in putting out a seven-year production forecast and I feel pretty good about that. It was harder to predict what the exact spend would be. And that’s part of the reason I’ve been reticent to give a lot of guidance going out beyond two or three years. I know directionally the level of our activity and we do balance that, but I don't know what the macro environment will bring fully. And once we get projects that are under construction we’re obviously going to continue them. So I have a pretty good feel obviously for what spending will be this year and I have a pretty good feel for what spend is going to be in 2015 and 2016 and that’s why we’ve given you this flattening comment where $40 billion this year will be in that same range give or take for the next couple of years. Beyond that the macro conditions could dictate something different. We do try to be opportunistic when it comes to bringing resources into the portfolio. Last year, I think we brought in some terrific resources into our portfolio at a good price. As you know, we supplemented our acreage in New Mexico in the Permian area. We brought in some good high-quality assets that we referenced earlier in the Duvernay. We think the Kitimat resource is a terrific one for the long-term. Argentina, as far as we know, it’s the best shale outside of North America. So we took the opportunity to bring those into the portfolio and we don’t see as many opportunities in that space this year, for example. That’s why I made the comment I did earlier about spend, but over time we are in depleting resource business and you do need to add to the portfolio. We’re careful how we do that. That’s how we got to our leading position in earnings per barrel and we’ll continue to be careful in how we do that going forward.

Maybe I could slip in just one last one on the asset disposal side. I know you mentioned in a response or your comments the midstream sale process monetization. I mean any update or any change in your thoughts there given you’re growing unconventional base and a likely associated midstream CapEx over time? Any change or whether that would be an outright sale or potentially forming an MLP? And I will leave it at that. John S. Watson: Yes. In fact I will say there is a little bit of a shift. Let me be clear. We’re not in shrink to grow mode, we’re not resetting the base, we’re not doing anything like that. That’s not what we’re doing. But just as we’ve done in the downstream, where we pruned the portfolio, I think Mike and his team has sold some $8 billion in assets over the last six, seven years and those have been done in a very nice pace way to get good value. We’re in the process right now of making some sales in our midstream business for example. You referenced MLPs, our approach – we’re not fond of the MLP structure as a way for us to hold assets, but we can sell into MLPs and get that value. And so we have been selling pipelines and we’ll continue to do so for pipelines where they’re not critical to our upstream or downstream business, n other words more merchant type lines. We are selling lines. You’ve probably seen some commentary in the press to do that. We think we can get good value there. Similarly, we do have a lifecycle for asset sales in the upstream and so there are some sales that are possible there. Our approach is not to talk a lot about the specific assets for commercial reasons, but I would say you’ll see more asset sale activity over the next two or three years in the upstream than you’ve seen over the last few years. Certainly there’s been a lot of chatter about some leases that we’re selling in Nigeria. Those we think will bring to a closure later this year and get good value for those. And I would say overall in the context of some of the big headline numbers others have said, our sales will be modest. But we will have a little bit more in the area of asset sales going forward.

Appreciate. Thanks, guys. John S. Watson: Sure.

Thank you. Our next question comes from the line of Pavel Molchanov from Raymond James. Your question please. Pavel S. Molchanov: Thanks very much for taking the question. You mentioned the ongoing reduction in domestic gas drilling and yet ironically that’s the one part of your domestic production that’s actually been up for the last, I guess three, four quarters. Why do you think there is this disparity where domestic gas is rising, but oil and liquids have been in decline? John S. Watson: Well, the only – the area where we’ve been investing in the U.S. has been in the Marcellus and it’s a function of the carry. So the volume increases that you are seeing, you recall we acquired Atlas Energy and some other tuck-on and we came in with $1.3 billion carry where one as we go forward we’re funding a disproportionately low percentage of the cost for the revenue that we’re getting. That carry is now down to $500 million. And our strategy has been to really build up a factory model, get our full costs in line so that as we end that carry three or four years from now that we’ll be in a good competitive position on a cost per MCF basis once we get through that carry. In the meantime, we can afford to do the drilling. We obviously – wells that are drilled when you are funding 25% of the cost and getting 60% of revenue, I think that the ratio is pretty good. Pavel S. Molchanov: Sure. And then a follow up on Kitimat, I think you’ve said in the past year your aim is to reach FID this year. Is that still the case and what are the key question marks that would impede that from happening? John S. Watson: Well, we're doing site clearance now. One of the things we’ve learned on big land-based projects is get your infrastructure in order and housing and things of that sort. So that's what we are doing. We are pacing this project very carefully as you would expect and what we have said is that FID will be entirely a function of gas contracts and that allow us to develop the opportunity and provide energy to Asian markets at a fair price. And it's no secret that there is a lot in the media on that subject right now. We are actively working with gas customers today. My view hasn't changed since the view Joe Geagea described to you last year, which is LNG projects are expensive whether in West Canada, West Africa or East Africa or the Gulf Coast of the U.S. or Australia. And we're going to need robust pricing in order to make those project go, and so there are some projects that may be built on existing facilities in the Gulf Coast of the U.S. that have gone to FID and we’ll add some capacity that may be slightly lower cost. But once you get to Brownfield, whether it’s Gulf Coast or elsewhere, I think we're going to need either oil link pricing or pricing that very clearly will give us the kind of return we need. So I guess what I am saying is FID will be a function of gas contracts. Pavel S. Molchanov: All right. I appreciate it. John S. Watson: Sure.

Thank you. Our next question comes from the line of Allen Good from Morningstar. Your question, please.

Good morning, everyone. John S. Watson: Good morning.

John, you mentioned a little bit on the Downstream sales and restructuring. Just a question on that. Is that business currently sized right for Chevron and do you see any other opportunity there to potentially reduce capital employed on the downtown side? John S. Watson: Well, our downstream business if you look at the direction we’ve gone, we actually have done quite a bit of pruning over the last two years. We’ve basically gotten out of the disconnected marketing or marketing is disconnected from our refining system and then we did get out of our refinery in Europe that we think was very well timed. And so what’s that left us with is a strong U.S. business with good positions along the Gulf Coast and through the West Coast of the U.S, and then a strong business in Asia. We think – we always take a look at the portfolio, but in general, I think our Downstream portfolio is in pretty good shape. I might have told you a few years ago that inland refineries, small refineries would be tough, but frankly those have been some of the most profitable with the one in Salt Lake and Burnaby, British Columbia. So I feel pretty good about the portfolio overall in the Downstream. The capital that we are putting in the Downstream business is really geared towards the chemicals business now. We’ve got a base oil plant that’s coming up in Pascagoula that will make us the largest top tier base oil producer in the world. We’ve got our share of the petrochemical complex that we're building with Phillips 66 through Chevron Phillips Chemical Company, that’s a $6 billion project. Our share is $3 billion. We think that is going to be a terrific project. As far as we know we are ahead of other projects in the area. We have got the permits and have gone to FID. Overall, we think we can generate mid-teens kinds of returns in this business and so we think it is a good one.

Yes, I guess on the chemicals, I mean you mentioned a product upcoming and certainly that is a very good portfolio there. But I guess relative to the size of Chevron total it's still relatively a small piece. Do you think the market is accurately crediting you for that business? And if not, do you think there is way potentially to monetize that through – I don’t know as with Phillips 66 or spinning that off separately or is your plan really just to hold out for the long-term and then continue to build that up? John S. Watson: Our plan is to hold that. It’s about 15% of our capital. We disclosed the segment information. I think you guys have sharp enough pencils to be able to figure out what it brings to us. But more importantly the math there is some linkages in the business that I think are very important. I don't think splitting up the business makes you an independent. We have some very significant linkages to the downstream business, and I’ll give you just a couple just as for instance. Southern California, our El Segundo Refinery, we’ve got heavy crude going out of San Joaquin Valley. We’ve just augmented some facilities at the El Segundo Refinery specifically so it can take more San Joaquin Valley crude. We think that's a good synergistic type of investment. Over the years we've had high mercury crude in Asia and we’ve put in specific facilities to be able to capture value benefit associated with that. I think when you look in the middle of the country today I think it makes all the sense in the world to be an integrated company. You’ve had tremendous volatility in crude pricing and you’re either capturing the refinery or you’re capturing on the upstream side, just depending upon how infrastructure moves and we’re capturing that in Salt Lake. So I frankly think that the integration story for us is pretty straightforward.

Okay. Great. Thanks for the comments. John S. Watson: Sure.

Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question, please. Roger D. Read: Yes. Good morning. John S. Watson: Good morning. Roger D. Read: I guess a lot of this stuff has been hit. I just wanted to kind of follow-up on, I guess, Q4 in the upstream in the U.S. and if that had any implications for how we should look forward, I understand on the production side as we modeled it. The realization for prices looked okay. I know as I went through the – or as you went through the presentation it showed realizations down. I was wondering is that a cost issue realization, sort of a net realization as opposed to just a price realization and if so, what kind of occurred in the fourth quarter, is that one-time issue or recurring issue? Any help you can provide there.

So Roger, I can help with that. This is Jeff. It's not a net realization. It's a price realization and it was consistent with the markers that you see in the market for the fourth quarter. Roger D. Read: Okay. So I mean more or less what occurred in the fourth quarter we should look at as being an issue going forward, I mean as crude prices move around that will change, but just the market conditions.

That's exactly right. Roger D. Read: Okay. And then as we look forward into 2014, especially at the end of the year, say, Jack/St. Malo starts up, you got continued growth probably in California. Should we look at that as helping out the realization story in the U.S., North America?

Again I guess it depends on your view of prices. So we are out of our U.S. production, we're about a third weighted to California prices, which is obviously separate from what’s going on in the mid-continent. We’re about a quarter weighted to Mid-continent or WTI prices and about a third weighted to the Gulf of Mexico. So I mean as Jack/St. Malo comes on, as Big Foot comes on, the weighting in the Gulf of Mexico may increase somewhat. There's not a lot of growth in the California business and at the same time we have the ramp-up in the Permian. So it really goes back to what your view of the different markers are in those three separate regions. Roger D. Read: Sure. Okay. That's helpful. And then, any additional update you can provide as you look at the Vaca Muerta kind of the drilling plans 2014 and 2015, when would we potentially see anything on the production side. I know you made the comment it’s a great shale. Just wondering when would we maybe see something tangible that we can start to fix on? John S. Watson: Well, I think you’ll start to see it going forward from here. We’re producing 16,000 barrels a day gross. That’s 100% number. And so, one of the reasons I made the comment about it being a good investment is there’s lots of oil infrastructure there now. So it’s right in the middle of an oil producing area. YPF is doing a nice job. We’re sending in some technical and other people to support them, but we got 15 rigs running. We think over time that it will get up to 19 and so we’re optimistic that we’ll see continued growth. I’ll just say we just recently closed the transaction. So it’s very early days at this point, but it’s a – there’s probably more to come, but you should start to see benefits in production here before too long. Roger D. Read: Okay. Thank you. John S. Watson: All right. Next question?

Thank you. Our next question comes from the line of Peter Hutton from RBC Capital Markets.

Good morning. Good afternoon from London. Actually my first question is a follow-up from the last one, which is about these liquid realizations in the U.S. and you mentioned that these are in line with the benchmarks. Well, from what I can see when I follow the trend, that is right, when you’re looking against the third quarter, but the third quarter have the highest discount between your average realization and WTI since the 2008 peak. So is it two quarters when we've had discounts of the order of something like $10 shortfall. And so I guess I'm asking the same question in a different way. Is that something we should also expect to see during the course of 2014 until you start to get more production out of the Gulf of Mexico from Jack/St. Malo? And then I had a follow-up which is actually my original question. John S. Watson: I don’t know we got anything fundamental for you. Maybe right for Jeff to follow-up with you offline to see if there is something in the markers that we’re not covering here, but there are some lags in pricing that take place in the U.S. But if you wouldn’t mind, Peter, maybe we’ll follow-up offline and see if we can get to those specifics.

Be glad to. In that case can I just – the question I was going to ask originally, which is on the reserve replacement rate and exploration. I think you mentioned 85% this year, which is down on the full year and one year is not a trend. But were there any areas where you have been focusing and didn't come in the way that you had expected? And realistically sort of where the focus is for this year and can you give a figure of the budget for exploration spent in 2014? Please. John S. Watson: Yes, actually the irony, this is a very good year for reserve replacement relative to what we had in our plan because we have sort of base business type activity, infill drilling and the like, developments and additions, revisions off the existing field and we had a very good year in that area. What we didn’t have was a significant number of major capital projects that went to FID and that’s why this number tends to be lumpy in any given year. So, well, on an ongoing basis it was less than replacing 100% of production. That’s why we quote the three year and five year numbers, which are 100% or higher. So I think that’s really my thought for you on reserves. Exploration this year is about $3 billion to $3.2 billion type of number this year. I’ll tell you one of the challenges we’ve had last couple of years is getting all our high impact wells drilled. We’ve got a great queue, but we frankly in the Gulf of Mexico we’ve been drilling so many development wells that we got to queue that’s built up there and so we’re looking forward to, I think we’ve got 14 or so high impact wells which we define as 100 million barrel or more prospects and we look forward to getting them drilled here over the next few years. But little over 3 billion is the target for the year. Thank you very much. Patricia E. Yarrington: I think we have time for one more question? John S. Watson: One more question Robert.

Our final question comes from the line of Robert Kessler from Tudor, Pickering, Holt. Your question please.

Hi, thanks for fitting me in and I look forward to the Analyst Day where I am sure we will go through more detail. But in the meantime I wanted to ask you for kind of an update on your Australia LNG cost and exposure to exchange rate. We still see volatility there. I know you are of course further through the spend on Gorgon at 76%, which would imply less exposure to the exchange rate on the surface. But I imagine more of the spend now is local labor, which I am assuming is priced in Australian dollars. So just the latest sort of leverage to that exchange rate if you don't mind and then any rethinking of your plans not to I guess hedge foreign exchange going forward? John S. Watson: Yes, interesting question. Maybe the comment I will make, we have had a rollercoaster on foreign exchange in Australia, as you point out. When we went to Final Investment Decision back in 2009, the exchange rate was roughly $0.86 and it ramped up as high I think 105 or so. And that was part of the reason that we supplemented the project. Our view at that time was not to hedge foreign exchange because we felt there have been a pretty strong correlation between oil prices and their currency and so we felt that our overall portfolio was pretty well hedged. And I think that proved to be a pretty wise decision. When we went to FID on Wheatstone, we did so and have assumed a parity exchange rate. So that’s a $29 billion project when we assume parity. This year our spend on the two projects is roughly $10 billion and we estimate that 70%, 75% of that spend is in Australian dollar. So with the Australian dollar tracking under $0.90 now that’s a positive for us going forward. We’re out a little something on this, so we’re benefiting from it right now and we don’t do any hedging and I don’t anticipate that we will going forward.

Great. Nice to see it swing the other way and thanks for the update. John S. Watson: You bet, thank you. Okay, thank you all. In closing, let me say we appreciate everyone’s participation today on the call. I would like to thank the analyst for asking the good questions in this morning session. We’re looking forward to seeing you in March and I’m sure you’ll have lot more questions and we’ll enjoy the material we’ll be presenting then. Thank you very much.

Ladies and gentlemen, this concludes Chevron’s fourth quarter 2013 earnings conference call. You may now disconnect.