Good morning. My name is Jonathan and I will be your conference facilitator today. Welcome to Chevron’s Third 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 would now like to turn the conference call over to Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.

Hey thank you, Jonathan. Welcome to Chevron’s third quarter earnings conference call and webcast. On the call with me today are Joe Geagea, Corporate Vice President and President, Gas and Midstream 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 2. Slide 3 provides an overview of our financial performance. The company’s third quarter earnings were $5 billion, or $2.57 per diluted share. Return on capital employed for the trailing 12 months was about 15%. Our debt ratio at the end of September was approximately 11%. In the third quarter, we repurchased $1.25 billion of our shares. In the fourth quarter, we expect to repurchase the same amount. Though not shown on the slide, I’d like to call attention to our track record on shareholder returns. We are in first place on total shareholder returns for the three-year, five-year and 10-year periods compared to our peer group of global integrated energy companies. Turning to Slide 4, cash generated from operations was $10 billion during the third quarter and approximately $25 billion year-to-date. The third quarter was the strongest cash generation quarter this year. Adverse working capital effects noted earlier in the year continued to abate. Importantly, third quarter also saw stronger operating performance in both our Upstream and Downstream businesses. Capital and exploratory expenditures were $9.6 billion during the quarter and $26.4 billion year-to-date. I would like to make it clear that major resource acquisitions stemming from our business development activities are not included in our annual budget targets. We have found the success rate, timing and pricing for this effort to be too uncertain to effectively include in our annual budgeting and Board approval process for C&E. Because we have been very successful this year in our resource acquisition effort, taking up acreage and project opportunities in Canada, Australia and the Kurdistan region of Iraq, we anticipate we will close the year with C&E outlays above our planned levels. While there are still some large uncertainties on timing, we presently anticipate our 2013 C&E investments will be around 10% or still higher than our original target for the year. At quarter end, our cash balances exceeded $18 billion as total debt balances were identical in size, we ended the quarter in a neutral net cash, net debt position. Confirming what I’ve said previously the company continues to move toward a more traditional net debt structure. Jeff will now take us through the quarterly comparison. Jeff?

Thanks Pat. Turning to slide five, all compared results for the third quarter 2013 with the second quarter of 2013. As a reminder our earnings release compares third quarter 2013 with the same quarter a year ago. Third quarter earnings were 5 billion about 400 million lower than second quarter results. Foreign exchange movements accounted for more than the overall decrease in earnings worth almost 600 million of the decline. The strengthening of the U.S. dollar in the second quarter and the weakening of the U.S. dollar in the third quarter caused a significant swing between the two periods. We moved from a net positive foreign exchange position in the second quarter of 300 million to a net negative position of nearly the same amount in the third quarter. Without this element our earnings performance this quarter would actually be better than the prior quarter. Upstream earnings were up 143 million reflecting higher liquids realizations and liftings mostly offset by unfavorable foreign exchange effects. Downstream results decreased 386 million between quarter’s lower margins and unfavorable foreign exchange effects partly offset by higher volumes drove the decrease. The variance in the other bar largely reflects an unfavorable swing in corporate tax items during the quarter. On slide 6, our U.S. upstream earnings for the third quarter were 57 million lower than second quarter’s results. Higher realizations increased earnings by 90 million driven largely by a rise in crude oil prices partially offset by the fall in natural gas prices. Lower production volumes decreased earnings by 30 million mainly due to maintenance activity in the Gulf of Mexico partly offset by higher production in the Permian. The other bar reflects a number of unrelated items including higher DD&A and higher exploration expenses. Turning to slide 7, international upstream earnings were 200 million higher than the second quarter. Higher realizations increased earnings by 430 million average liquids unit realizations increased by 11% consistent with the increase in average Brent spot prices between quarters. The timing of liftings across multiple countries increased earnings by $90 million. At the end of the quarter we were in a slightly over lifted position. An unfavorable swing in foreign currency effects decreased earnings by 465 million. The third quarter had a loss of about 190 million compared to a gain of about 275 million in the second quarter. The other bar reflects a number of items favorable tax effects, gains on asset transactions and lower operating expenses were partially offset by higher exploration expenses. Slide 8, summarizes the quarterly change in Chevron’s worldwide net oil equivalent production. Production increased 3000 barrels per day between quarters. New wells that are Agbami and Usan projects in Nigeria additional production from the Delaware basin in the Permian as well as volumes associated with Angola LNG increased net production by about 22,000 barrels per day. Plants maintenance activities decreased production by 14,000 barrels per day during the quarter most notably in the UK, Trinidad and Thailand with a partial offset from less maintenance activity in Australia. External constraints hurt third quarter production by 10,000 barrels per day primarily due to a mid-quarter lightning strike in Thailand which severely damaged and necessitated the shutdown of our customers gas processing plant. This in turn curtailed our Thai gas production. The base business in other bar includes the impact of normal field declines, cost recoveries and the impact of price effects on entitlement volumes. Production for the first three quarters of 2013 averaged just over 2.6 million barrels a day, below our initial full year production guidance of 2.65 million barrels per day. Several factors have affected our year-to-date production results, first Angola LNGs ramp-up of production has been slower than anticipated. Second turnaround activity across various locations has been more extensive than originally planned. Our final contributing factor relates to the damage of the gas plant in Thailand. We expect volumes to be higher in the fourth quarter as production is restored following maintenance related down-time during the third quarter and as new production comes online. For the full year, we expect to come in around 98% to 99% of our original production target. Turning to Slide 9. The U.S. downstream earnings improved by $111 million between periods, higher volumes increased earnings by $55 million primarily due to our Richmond, California refinery running at normal capacity for the full quarter. Lower refining and marketing margins decreased earnings by $95 million driven by rising crude cost. Reduced industry crack spreads also reflected improved supply conditions and higher plant utilization rates following the end of second quarter maintenance activity. Lower operating expenses increased earnings by $30 million, primarily due to lower environmental charges. Greater gains on miscellaneous small asset sales improved earnings in the third quarter by $60 million. The chemicals and other variance, primarily reflects the absence of planned and unplanned downtime CPChem’s Port Arthur and Sweeney plants in the second quarter. On Slide 10, International Downstream earnings increased by $497 million between quarters decreased by $497 million between quarters. Higher plant utilization rates boosted volumes and increased earnings by $30 million in the third quarter. Refining and marketing margins were lower by $220 million. Rising crude cost, continued soft product demand and oversupply in the Far East weakens industry crack spreads while price lag effects mainly for jet fuel and naphtha in Asia impacted marketing margins. Timing effects represented a $140 million negative earnings variance between quarters driven largely by the revaluation of inventory. The swing between quarters was primarily due to rising crude prices during the third quarter compared to falling crude prices during the second quarter. Foreign currency swings reduced earnings by about $115 million. Third quarter had a loss of approximately $85 million compared to a small gain of $30 million in the second quarter. The other bar includes a number of unrelated items including various tax items and higher shipping costs. Slide 11 covers all other. Third quarter net charges were $522 million compared to $350 million in the second quarter, an increase of $172 million between periods. Adverse corporate tax items resulted in a $219 million decrease to earnings between quarters. Our overall year-to-date effective tax rate at just around 40% is trending a little lower than in recent years. As you know, in any one period, this overall rate can be influenced by many factors including jurisdictional mix between Upstream and Downstream, jurisdictional mix within Upstream, foreign exchange and asset sales transactions. Corporate charges and other items were $47 million lower this quarter. Year-to-date net charges in the all other segment were $1.3 billion at the end of the third quarter. We believe our quarterly guidance range of $400 million to $500 million for the all other segment is still appropriate going forward. Joe is now going to provide an update on our LNG marketing activities. Joe?

Thank you, Jeff and good morning everyone. I would like to spend a few minutes talking about the LNG market in our LNG portfolio. So turning to Slide 13, I will start by grinding you quickly on the global demand outlook for energy. The world’s economy is growing driving increased demand for all forms of energy and much of this growth is in Asia, where people increasingly aspire for a better quality of life. And achieving this aspiration does require stable, secure and affordable energy supplies. Total world’s energy demand as forecasted increased 30% by 2025 from today’s level. Natural gas demand has projected to grow even more by about 40% by 2025. And LNG demand growth is expected to be even greater. Turning to Slide 14, LNG demand has already doubled since 2000 and it is predicted to double again by 2025. Meeting this demand would require three elements maintaining the reliability of the existing supply, delivering current LNG projects under construction and investing in the construction of new LNG capacity. Even if the first two elements are well in hand this still leaves an opportunity of around 150 million tons per year of new projects to be sanctioned. Now my buyers are counting on the United States to make up the shortfall with pricing linked to Henry Hub. Even if you believe the most optimistic predictions of new U.S. supply available for export, there are still projected short fall of more than 50 million tons in 2025 and more reasonable predictions of U.S. exports suggest a GAAP of around a 100 million tons in 2025. So the U.S. alone will not bridge this forecast demand supply gap. And that’s we believe new supply needs to come from multiple sources. Now developing these supplies will also take time whether that’s for permitting a construction of U.S. LNG export terminals or for exploration, appraisal and development of new producing regions such as East Africa. Building and maintaining LNG facilities is technically challenging, capital intensive and require significant expertise. The last 35 LNG projects developed globally took on average over 16 years to deliver that LNG to market. Although we do acknowledge that completion times are improving. Additional capacity utilization rates for LNG facilities in production have only averaged about 85% in recent years. Geopolitical instability, resource availability and unplanned turnaround have resulted on average in roughly 35 million metric tons of the existing nameplate capacity being unavailable at any given time. Turning to slide 15, well we have seen growth in global energy trading and expect that interregional trade of LNG will continue to increase, we believe that global gas markets will remain regionally distinct over the medium to long term. This is mainly due to the high cost and relatively lack of infrastructure to transport and store gas globally. While 2/3rds of the world’s oil is shipped by tanker only 10% of the world’s current natural gas supply is shipped as LNG and this forecasted increase to 14% by 2025. We believe the majority of this LNG will continue to be delivered under long term contracts. The traditional LNG importing countries of Japan, Korea and Taiwan have no interconnecting pipeline infrastructure and virtually no indigenous energy resources and therefore rely on LNG to meet almost of their gas demand. Only 5 years ago 17 countries were importing LNG, today 26 countries are doing so and this is expected to increase. So let’s move to slide 16, where I would like to focus more specifically on U.S. LNG exports. Many analysts forecast that U.S. LNG export should reach approximately 50 million tons per year by 2025 equivalent of around 11% of the world’s LNG demand and by 8% of domestic U.S. gas demand. At these levels U.S. LNG exports would only represent the small share of the global LNG market. Greenfield LNG projects are unlikely to be developed outside of the United States unless its significant portion of the offtake is committed under long term contracts with robust pricing that underpins the financial investment required to monetize these resources. A common perception is the Henry Hub linked pricing will be landed LNG prices in Asia will be significantly less than other world sources. We think that’s not automatically a given. U.S. Liquefaction cost are likely to rise as more projects compete for resources, including engineering contractors, fabrication yard space and project financing. In addition growing demand in the United States where new petrochemical projects, power plants, exports to Mexico and a transportation segment will mean new demand pull on the same supply base. Coupled with weather and storage effects this could easily increase price strength and volatility for Henry Hub. In order to ensure that sufficient supplies do get developed there needs to be cooperation alignment and understanding between LNG buyers and suppliers. This has helped when buyers diversify to energy mix, maintain a geographically diverse LNG portfolio, recognizing that no one region including the United States can meet all expected demand and finally take equity positions in LNG projects to ensure the right projects are built in the right places for the right price. We have seen this formula work in Gorgon and Wheatstone and we’re confident the same will be true for Kitimat. Turning to Slide 17. I would like to now talk about our LNG sale commitments. From a portfolio perspective, we believe it’s prudent to leave around 25% of volume for placement on the spot market for operational flexibility. However, at the individual project level, this ratio may vary. For example, on Gorgon, we are 65% committed. We are still prepared to increase volumes under contract. However, Gorgon is scheduled to come online at a time when limited new supplies are expected. So we are confident of being able to place uncommitted volumes into the market. On Wheatstone, 85% of Chevron’s equity LNG is now committed on long-term basis. In addition to the Gorgon and Wheatstone Foundation projects, we have made good progress this year with buyers for LNG from our Indonesia Deepwater Development, or IDD. For our unsanctioned projects, including IDD, Kitimat and Gorgon Train 4, we are targeting to have around 70% committed under long-term contracts by the time we will reach a final investment decision. Once achieved, we will end up with our desired portfolio objective of having 75% of our LNG production sold through the long-term contracts. Turning to Slide 18. I would like to close by showing you how Chevron is well-positioned to become a major LNG supplier by the end of this decade based on Wood Mack estimates. With the project under construction at Gorgon and Wheatstone and with our existing equity shares in Angola LNG and Australia Northwest Shelf, we will be one of the top 10 LNG suppliers in the world. If we include Kitimat and Gorgon Train 4, we will potentially move into the top five. In summary, we see strong LNG market fundamentals supporting our growing LNG portfolio, which should allow us to deliver strong future gas generation for many years to come. I will now turn it back to Pat.

Okay, thank you Joe. Now, let’s take a look at the latest updates on our LNG projects. The Gorgon project is over 70% complete. We continue to make good progress on all fronts. In early October, we installed the third of five gas turbine generators. To-date, 14 of the 21 LNG Train 1 process modules have been installed, three are in transit and the remaining are scheduled to follow in fairly rapid succession. Work on the jetty is progressing. We now have 43 of the 56 jetty caissons installed, including those needed to support all key structural elements. We have recently reached mechanical completion of the domestic gas pipeline in preparation for operational readiness by year end. Onshore pipelines are complete on the Io/Jansz 30-inch pipeline. And finally, three wells at the Io/Jansz field are ready to flow gas and seven wells are completed at the Gorgon field. Wheatstone is proceeding per plan and is now over 20% complete. We continue to transform the site with ongoing earthworks and good progress on establishing critical infrastructure. Construction continues on the materials offloading facility and we completed our first permanent foundation in concrete pour in September. Site preparation continues with about 19% of our 23,000 piles driven including commencement of the LNG tank pile driving. Platform construction is over 43% complete and we have received critical platform equipment such as the power transformers and process vessels. We just completed our micro-tunnel boring under the shoreline in preparation for the offshore installation of the trunkline. Now, we posted several updated photos of progress made at both Gorgon and Wheatstone on our investor website located at chevron.com and I’ll invite you to take a look at those. For Kitimat, front end engineering continues on plan. We have remained focused on early earthworks at the LNG plant site, where construction on the office, camp industrial site and service road is ongoing. Key activities for the Pacific Trail Pipeline are obtaining necessary permits, building roads and securing right-of-way access. LNG marketing activities and the engagement with potential foundation customers are underway. The timing of the final investment decision will be determined by our ability to secure sufficient LNG offtake agreements with our customers. Turning now to Slide 20. I’d like to share some highlights of the strategic progress we have made during the quarter. We signed binding long-term sales and purchase agreements with Tohuku Electric Power Company in Japan to supply just under 1 million tons per year of LNG for up to 20 years. As Joe noted this brings total volumes committed to customers in Asia on a long term basis to 85% for our Wheatstone project. Continuing with the Australian scene we recently announced the acquisition of two deepwater exploration interest located in the Bight Basin off the Southern Australian coast. These are very large blocks with significant exploration potential and further reinforces the importance of Australia to Chevron’s global growth strategy. In Canada we successfully completed an initial 12 week exploration drilling program in the liquids rich portion of the Kaybob area of the Duvernay Shale Play. Initial well results were very encouraging with average initial production rates in excess of 1200 barrels of oil equivalent per day. Both of these developments are consistent with our focus on early entry opportunities which have the potential to generate the most value for our shareholders. We also had a major milestone in our downstream chemicals business. CPChem announced our investment decision for U.S. Gulf Coast Petrochemicals project. This project includes construction of a 1.5 million metric ton per year ethane cracker as well as two new polyethylene facilities each with an annual capacity of 500,000 metric tons. This is an attractive project one that takes advantage of existing infrastructure and advantage fleet stock. Plant startup is planned for 2017. Turning now to slide 21, I would like to close by highlighting our continued strong performance particularly in our upstream business. Our 2013 year-to-date upstream earnings margin was $23.33 per barrel. Based on these year-to-date results we continue to lead our direct peer group by a wide margin. We’re almost $5.70 per barrel ahead of our closest competitor. This is a position we have now held for 15 consecutive quarters. We also led on this important metric at the six month mark by over $4.25 per barrel against the wide range of EMP companies. These peer leading financial results are directly related to the quality of our investment decisions and the strength of our portfolio. We appreciate you listening in this morning and your interest in the company, I would like now open up the microphone. Joe and I are happy to take your questions. We do have a full queue so please limit yourself to one question and a single related follow-up if that’s necessary, we will certainly do our very best to see that we get all your questions answered. So Jonathan please open up the lines for questions.

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

I will start with an LNG question, so I mean I’m up late and I keep getting these stories from Australia on my iPad which I will see you know going around the market and you know people are very worried about the LNG (indiscernible) or whatever it is something else with the project. Maybe give us a color on how you’re feeling about the startup date and maybe if there are any penalties if the date back in time what’s the sort of pillar date to get Gorgon on screen. Thanks.

You know I think we have been pretty upfront about acknowledging some of the challenges that we have had earlier, we talked previously about logistic challenges, labor productivity and weather challenges. We have solved for all practical purposes the logistics challenges and in fact we have asked for and received additional lay down space on the island and so we’re able to now kind of build material and inventory on Barrow Island. Productivity I would space is improving on all fronts, but there are still some areas that still needs to improve. We’re still impacted by weather, we had you know heavy rainy period back in June but right now we’re in the good weather period and are making very good progress each month. I think we’re moving into a critical phase from a scheduled standpoint on the project. We talk about getting all the Train 1 modules on to the island. That’s proceeding pretty much as planned. I think they will be here by year end or shortly into the New Year, maybe one that will be mid quarter next year. What’s important next is the mechanical, electrical and kind of instrumentation work and construction or contractor work on those activities is ramping up on the island now, but there are still uncertainties that exist with the projects of our size and our challenge every day is to mitigate the risks, find the risks, mitigate the risks as they arrive, but the jetty I think we are trying to say all the critical elements of the jetty, the main critical elements of the jetty, those that support the structural elements are on plan. Right now, we are in the process of finalizing our budget for the year and should there be any reviews during that, that suggest the material change other than what we said previously will certainly bring that to your attention, but I don’t have anything more to offer.

Thanks Pat.

And let me address your question on the marketing side, I’d like to say that our customers are our partners, so they fully understand the project challenges. I would also say that Gorgon is not coming up all at once is one train at a time. So that gives us time to work with our partners, with our customers on accommodating their needs and we have those discussions ongoing all the time. I cannot address specifically what’s in our contract with respect to kind of these as you can appreciate these are commercial elements and I cannot address those.

Thanks very much.

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

Yes, good morning everybody. And thanks for the LNG commentary as well as addressing that CapEx question. Staying with Gorgon, Joe, I mean can you update us on how the season’s Train 4 is progressing and what is the interplay on Trains 1 and 3, their progress and the ultimate decision upon expansion meaning do your partners need to see more final Gorgon cost estimates before committing to the expansion and albeit at a significantly lower unit cost expansion?

Yes, I think and maybe I will take the question around Train 4. I think we continue to work with our partners. We are all interested certainly in seeing this continue to progress. I think all of the JV partners are interested though in seeing Train 1 come up and seeing progress on 2 and 3 etcetera. Everybody wants to get an understanding of the cost structure. I also think that people want to get certainty around the fiscal and regulatory regime. And as you know, there has been a change of government in Australia and so a little bit of settling down and stability there would be appreciative. Those factors are going to be taken into account. I also think it’s fair to say that the cost structure in Australia is different now than it was when Train 1 was taken, Trains 1, 2, 3 were taken to file investment decision back in 2009. The cost structure has elevated. And I think it’s fair to say that, that has put at risk some of Australia’s kind of global competitiveness. So from a Chevron standpoint, we are going to look at Train 4 and we are going to assess it under those new conditions and we are going to look at that relative to other opportunities that we have got in our portfolio and look for that next investment to compete with other opportunities. Obviously, a Train 4 does have certain Brownfield economic advantages to it, but we need to take those advantages lay in the new macro conditions that we see in Australia and take a look at the whole portfolio activity. Having said all that, we are continuing on with environmental approvals for Train 4.

So maybe I will add a bit of color commentary also, because the marketing is essential to Train 4 and all the reasons that Pat has mentioned, I would also say that the LNG market has different dynamics as well. Our job is to continue to find customer for Train 4, which we continue to do. We believe the offerings of the Train 4 are different than the offering of our other projects like Kitimat. Train 4 is an expansion, is a Brownfield expansion, Train 4 is exposure to Australia. Train 4, however, does not have equity unlike Kitimat where we are offering equity. So it really caters to a different set of customers and in our view from a marketing perspective, it’s truly not competing with Kitimat and I think that’s important for us to say.

So to follow-up does that mean the potential debottlenecking of Trains 1 through 3 is something that could potentially proceed a Train 4, I mean I know there are three different tranches of potential expansion. Does it change, I guess the debottlenecking opportunity move that forward or is that still something that we'd fall if it didn't back follow?

Yeah. I mean I think Evan that we would -- I mean debottlenecking is always something that you would do kind of as an ordinary course of activity and often times it has the very highest economics associated with it. So that will be taken into account in our normal planning process.

Thank you. Our next question comes from the line of John Herrlin from Societe Generale. Your question please.

Yeah. Hi, just two quick ones. With the Duvernay wells Pat, that how much were they running I know it's science times its early days but I am just wondering an approximate cost?

You mean you are talking approximate well cost?

Well cost?

Yeah, that's not a number that we want to give out at this point in time.

Okay, that's fine. Next one is on LNG, are you surprised at all that on the demand side in terms of customers that they haven't built more physical gas storage in Asia and do you think that will change as the LNG market builds up more?

That's a very good question John. This is Joe here. It is going to take time for them to get there clearly there is capacity with the re-gas terminals we are seeing that in Thailand we are seeing that in Singapore but remember that market is huge so significant amount of storage has to be made available for it to really make a difference, I think we may get there eventually, but I see a slow pace to get to that point.

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

Joe first of all can you remind us what the contract resets look like on your base load marketing for Gorgon in particular and maybe when you're addressing the question if you could talk little bit about what are issues around Henry Hub pricing is really more about de-linking and the oil for example went for 150 boxes of course to actually depressing the current price and I've got a follow-up.

I'll start by saying that most contracts that are of that length 20 year for them to be sustainable and to be win, win for both customer for buyer and seller, have reopeners on. We’re not getting into specific, these reopeners are meant to really to make sure that the pricing formula continues to reflect the market. What I can tell you that all of our projects are paced, that we were not going to see major renewal for a big portion of the volume all in one year. We have been very careful in pacing these renewals over time, because again that's in our interest and in the buyers interest to spread that renewal timing over a longer frame than just having all occur in the same time. Back to your questions on Henry Hub there are two elements to it. We have been public in saying that LNG that comes out of the United States made in the United States it's perfectly okay for it to be price off of Henry Hub. LNG that is made in Australia, East Africa or Canada it's a harder proposition to see why you would introduce a regional market reference to those markets. So that's been very difficult. In terms of breaking the oil linkage I will tell you that for the last 40 years the industry has learned to operate within an oil framework that saw oil prices go up to $140 and go down to $20. I submit to you that within these traditional framework you can introduce S curves, you can moderate slops there is a lot of other levers that actually work to prevent LNG from becoming very unaffordable and the regions where affordability is becoming an issue. So I think we can address those excursions that could be harmful from an affordability point of view within a traditional framework without necessarily going to something unproven that could also be a lot more volatile. We've also said that one way for people to get a better attenuation on price for them to get into the equity side. That clearly gives them direct exposure to the Upstream side to the whole value chain and effectively you are getting an attenuation to pricing, because you are getting the whole value chain benefits from that. So hopefully that helps.

It does a lot. Thanks Joe. And my follow-up hopefully also is a bit quicker, but we all watched the unit earnings trends, the very strong earnings trends you guys have had for quite some time now, but whether we want to look at cash, where the focus is earnings. And I guess my question is your DD&A runs about $6 lower than your peer group and it appears to be trending higher, so when you have all this, I guess, non-producing capital coming online from these new projects. Can you give us some feel as to how the DD&A trend is going to look, and I will be going back? Thank you.

Right. So Doug, I think you should expect we have seen and you should expect the trend to continue higher charges for DD&A. Certainly, that’s the pattern we have seen over the last couple of years, it’s the pattern that we see looking at 2013 versus 2012 and it is the expectation that I would have going forward for 2014 and it is a direct reflection of the capital investment programs that we have had underway and as we bring those new projects online, you see rate increases associated with that.

Alright, I’ll leave it there. Thanks Pat.

But Doug, I guess I would say it’s important even with that and we still have the leading earnings per barrel margin and we have the leading cash margin.

I am just trying to figure out what the future trends going to look like when these projects come up flat.

I appreciate that. Okay.

Thanks very much.

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

Hey guys. Good morning.

Good morning Paul.

Two somewhat related question, one for Joe and I think one for Pat. For Joe, when we look at Kitimat campaign, if you can give us some idea that what is the competitive position relative to building a LNG trend in Kitimat again operate there, which is a pretty remote area and (indiscernible) could be unusual comparing to in Australia, whereas you guys have a lot of operation or in the Gulf of Mexico, which you don’t have a lot of operation. So that’s the first one.

Okay.

Pat, do you want to give you the second one first?

Sure. Go ahead.

If I look at, this is not an issue in the near term, but your current cash flow essentially just barely cover your CapEx and so at what point now of course when you have zero net debt is not an issue today, but theoretically that’s a management standpoint at what point you restart questioning whether you want to continue borrow money to buy back stock and at what (indiscernible) that continue once that you enumerate the share buyback that we have to relook at your CapEx program?

Okay, good question.

I’ll go first Paul on the Kitimat question. And it’s a very good question. I will start by talking a little bit about the resource base. If you look at our acquisition of that resource base, we are very, very pleased with the entry price. So we also know that we have a huge resource base in both Liard and the Horn River. And that resource base sits right at the gate of North Asia, where we continuously see increased demand. So strategically, it is very well-positioned for North Asia buyers and our buyers see that and that’s the value proposition would have been communicated to them. They also see in Kitimat two partners that have complementary skills. They are very aligned and very committed to the project. They see a settled government and a provisional government that are supportive and understand the opportunity. They see a country that is very much in favor of exports and coping toward Asia. They see a project with export permits in hand and a clear line of sight on a pipeline and a transportation solution. And I did say something about the labor cost. I will tell you though if we are the first out of the gate, we will have an ability to attenuate that versus being the last one coming in to develop the project. And finally, what we tell our buyers this is a great opportunity for them to participate through equity and the whole value chain. And in doing so, they really get direct exposure to North America gas pricing. All of those are good value drivers for any buyer in North Asia. They are getting it. I think we are getting good reception. And obviously time will tell and our ability to sign contracts, but we are very encouraged by what we see and the value that Kitimat can offer to those buyers. And I will go back to Pat for the capital question.

Still before that, from a cost standpoint, do you from what you can, because you know a lot about Australia and I presume you know quite a lot about Gulf Coast is developing cost and operating cost of Kitimat is going to be competitive with Australia but cheaper than Gulf Coast or any kind of insight that you can provide?

It is too early for us. I remind you that we have signed a transaction in February of this year. We became operator in July of this year. We are really getting out there. There are two things here that we need to be very careful on it is project development and execution which is really we're focused on and secondly the marketing and they have to go hand in hand. I would tell you though the freight advantage that we see in Western Canada clearly is something in favor of Canada compared to Gulf Coast exports.

Okay and Paul just going back to your question. I want to start with the priorities that we've always put out there in terms of uses of cash , dividends first, reinvesting in the business, taking care of our balance sheet and then share repurchases really come at the very tail end of that. And you're right we are in a period. Right now our capital requirements are high just to remind you we've got five LNG trains under construction. That's a very significant component we do not have, we do not see in the forward-look that we will have anything as lumpy as that or as sized as that. So we know 2013 is a high C&E year We have said in the past that 2014 will be a high C&E year. George referenced last time on the call about a flattening that will occur. So we do see that the weakness of our capital spend period right now is not something that we see coming forward in future years. At the same time though we do fundamentally believe our greatest value proposition for our shareholders is finding and investing in the right resources and developing the right projects. And so we will continue to invest in the business and so you see us doing that in terms of resource acquisitions that I talked about earlier. So we try very hard to balance this returns and growth equation here and we've been very successful. The decisions that we have made and we believe the new resource acquisitions that we have made for future for growth 2020 and beyond are excellent projects. So we believe we're putting that equation together quite nicely. I guess the other thing that I would say is when you bring new resource acquisitions like we've done with Kurdistan or Cooper Basin or Kitimat, et cetera. When you're adding those elements to your portfolio, it does mean that you re-prioritize your portfolio and certain things probably fall towards the bottom. These would be more mature assets and less competitive in our portfolio, believe that they have potentially had spot in someone else's portfolio and that's where your asset sale or your portfolio optimization component increases. We've been very good doing that in downstream you've seen us do all that restructuring in downstream. Joe has overseen a fair amount of restructuring occurring in our midstream area and I think you can expect some additional assets sales now coming forward from upstream?

Is there some form of metrics that you look at from a financial net debt to capital or net debt to EBITDA, you would look at say once you reach a certain level, the share buyback will say maybe that come to an halt?

We obviously are interested in maintaining our AA status, credit rating status. We're not interested in infringing upon that at all so we look at that as kind of a limiting factor but frankly Paul we are such a long away from that at this point it's not a limiting component.

Thank you. Your next question comes from the line of Faisel Khan from Citigroup. Your question please.

Two questions, first on the LNG facility in Canada, a potential LNG facility in Canada. Can you discuss the merits of owning the entire integrated asset and why not moving to a more asset like model where utility like company owns the liquefaction facility you own the resource and you market the gas and charter the sheds. I mean it seems like it's a very large piece of invested capital. There is a lot of companies out there especially in Canada and the U.S. that have the ability to finance this stuff at a much lower cost of capital. And then my follow-up is that, it seems like building a pipeline from Liard and Horn River to (indiscernible) or even to Kitimat. It's very expensive. There is a lot of depreciated type all the way from there down to the Gulf Coast that has a lower invested capital base. I mean why not they ship the gas down there and sign up any other facilities that are sort of ramping up. So that’s a little bit less feel, but if you can help me answer this?

That was not a less feel at all, Faisel. Good question. Let me tell you that we are not building a pipeline from the field to the LNG facility. We are clearly leveraging existing frontlines that currently won and they are operated and owned by others. The piece that we are building is the link from the frontline to our facility, I call that out umbilical. And that’s very essential for us to actually control that, to control the feet going into the LNG facility. So where we can we are leveraging other facilities, infrastructures, processing plants could be another place, where we leverage as well. So we are adopting some of which you are suggesting. When we do this, we always look at the strategic fit of the asset. Is it essential for us to control it from a commercial point of view? Is it essential for flow assurance to our facility? Those are normally governing criteria for us to decide whether we want to own the interconnecting framework, same thing by ships. We can sell FOB as well and we don’t have to build ships, but sometimes we have to build ships to ensure flow assurance on the back end of the LNG facility. The name of the game is really to get the molecules that we are just acquiring at a very attractive price in the Horn and Liard to the market and maximize our returns. And we look through that whole thing in details. And the other options also we are looking at from lowering the capital investment, we are asking other equity partners to come in. And by farming in for buyers, clearly, we are lowering the capital exposure. So we are looking all of that to basically address the element of the question that you brought, Faisel.

Okay. And then the pipeline gas as you could pipeline all this gas down to the Gulf Coast on what’s basically all depreciated pipeline, whether it’s alliance or northern border and then down in GPL to the Gulf Coast, I mean, the invested capital of those assets is far lower than these pipelines at TransCanada and Spectra talking by building to supply that gas to the Canadian West Coast. I mean, is that an opportunity, where you can move that resource down to the Gulf Coast and export it out of the Gulf Coast and with the Panama Canal sort of opening up, I mean, it seems sort of like an asset like sort of model, but I don’t know?

[inaudible]. Thank you, Faisel.

Okay, fair enough. Thanks.

Thank you. Our next question comes from the line of Pavel Molchanov from Raymond James. Your question please.

Thanks very much. Two questions on your unconventional gas exposure U.S. gas production was up almost 5% year-over-year, is that primarily legacy Atlas acreage?

I think, there is both an Atlas components as well as a kind of newer Permian Delaware Basin component to that.

Okay, fair enough. And then on to Europe, lots of headlines recently involving countries where you guys are operating or thought about operating in, Lithuania, Romania et cetera. Any status update you guys want to provide on how you are thinking about that?

Yes, I think we are trying to say right from the get-go that this would be a long-term development opportunity and that it would take several years really to understand how the overall play could develop. We do think if it works and if it’s proven up, then there is enough here to potentially build the business, but we are just in the very early stages of exploration and so I don’t want to get – I don’t want us leaping too far too soon with implications here. I mean we are active in Poland. We have drilled four wells there. We have got 3D seismic underway as well there. In Romania, we are picking up seismic activity. In Ukraine, we are still interested in having the PSA in the side we are hopefully getting closer on that. So we continue to make progress. It will be dependent upon the local governments and the local communities wanting to have us be there. And so that’s been a challenge. It is an exploration play and so I think we need to give time to mature.

Right, appreciate it.

Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question please.

Yes. Good morning.

Good morning.

Good morning.

I guess I would like to on the upstream side focus a little bit more on that cost side of things I mean obviously it was a good quarter in terms of realizations on the topline but you talked a little bit earlier about DD&A being an issue. Is there anything else maybe particular to the third quarter from an operating cost standpoint that's not recurring? I mean I know maintenance has an issue sometimes but I was just seeing if you could help us there and maybe think about how that unfolds in '14 and '15?

I think from a cost standpoint exploration was heavier in the third quarter than the second quarter, but if you look on a year-to-date basis it's pretty much in-line with what we have seen previously. We're seeing higher industry costs you referenced that I think that's just a general trend that has been evident but also maintenance in the third quarter was a little bit heavier kind of pre-planned as well as some unplanned as well. So I think those are the factors that I would call your attention to.

And in terms of any thoughts on '14 and '15 I mean are we seeing trends here I mean I agree with you there that the industry is seeing higher cost but are there any trends specific to Chevron that we should think about or even another way of asking it as the LNG projects come on are we going to see that as a significant impact maybe lowering operating cost?

Yes. I don't think there is anything unique in Chevron's operations going forward that I would suggest and I think I'll differ on the LNG operation side of things. I'm not in a position to comment about what op expense looks like in 2015 and 2016 at this point. Okay. I think we've got time for one more question.

Certainly. Our final question comes from the line of Allen Good from Morningstar. Your question please.

Just a couple for Joe on LNG. You've been pretty detailed on the merits of Canadian gas relative to Gorgon and relative to U.S.. Should we go and take it that exploring natural gas out of the Gulf Coast doesn't fit competitively within Chevron's current LNG portfolio?

You're making too many assumptions right there. We are focused on Kitimat for now and again we have opportunities in Australia. We are not ruling anything out at this stage but at the same time I am not prepared to tell you that we won't look at opportunities anywhere else in the world. For now we're focusing on Canada.

And then finally you mentioned the appeal of the equity availability in Kitimat for some of your potential partners. Is there a minimum equity stake that Chevron would like to retain in Kitimat or vice versa of sort of target that you'd like to sell down as a portion of equity in the project?

We have not put any number out there obviously it's up to the buyer also to indicate interest. We kind of like a number in our mind in terms of what end up but it's really a function of where the buyers are. We're flexible and remember we've got a partner as well and we got to consult with them in terms of where they like to end up. The gate is open though for the buyers to tell us what they think I don't know that we have indicated externally what that number is but we're open to entertain the buyer's ideas.

I'll just get one more quick one. If you've been -- you make a pretty convincing case that demand for LNG will be out there. Do you see any threats in the supply side, though, that could potentially disrupt the potential long-term economic for LNG projects?

In fact, I see the threat in the opposite direction, I see the threat as the longer it’s taking us to enable project to reach FID and you fast forward it 4 to 5 years how long it takes to build them. This market can only go up and that is not really where the buyers would like and that's why our plea with the buyers have been we need to enable supply to come to the market because we have not seen anything on the demand side that is managing that carefully we see more subsidy, we see nuclear out of the energy mix. We see shale gas development, a lot of places slower outside the United States all of that point to more need for LNG and I look at how many projects are actually reaching FID outside the United States. I don't see a whole lot and that can only mean problem down the road and we've seen that play out in the past. Back in 2007, there was an estimate of about 75 million tons of LNG that will hit the market in '14. As we sit today it is only 10 million tons that will come in '14. So we've got to crack this equation both from the supply side and the demand side, and the longer we see projects delayed from reaching FID, I think the price equation gets more difficult.

Yes, great. Thanks for that.

Okay, thank you. Before we close off the call, since we didn’t get a question on Ecuador, I would like to provide our investors an update on this matter before we close out here. It’s a very important matter. As you are probably well aware that we are in several recent positive developments related to this ongoing litigation earlier in the year several key witnesses, financiers and other associates including an Ecuadorian judge involved in the case publicly been announced and exposed numerous examples of the blatant fraudulent tactics used by the plaintiff lawyers during the trial. But more recently an International Tribunal convened under the authority of the U.S. Ecuador Bilateral Investment Treaty and administered by the permanent Court of Arbitration in The Hague found that the Settlement and Release Agreements between the Government of Ecuador and Texaco in the mid to late 1990s released Texaco Petroleum Company from any liability for all public interest or collective environmental claims. Now, this was a definitive ruling on the single most important legal issue in the case. And it was made by an impartial Tribunal in The Hague, where Chevron had picked one arbiter, the Government of Ecuador had picked one arbiter and we both had agreed on the third. And it was a unanimous ruling. Importantly, this ruling confirms that the claims against Texaco were not valid and should not have been brought in the first place. And it also signifies that efforts to enforce the Ecuadorian judgment, which the plaintiffs have so far unsuccessfully attempted in both Canada and Argentina that those are in direct violation of national and international laws. Now, separately, couple of weeks back on October 15, the U.S. trial began in New York related to Chevron’s civil lawsuit against the Lago Agrio plaintiffs and several of their lawyers, consultants and supporters alleging legal violations, violations of the Racketeer Influenced and Corrupt Organizations Act. Trial proceedings in this New York lawsuit are expected to last a few more weeks. So we are encouraged by these recent developments, but at the same time, we expect the need to continue to defend our position and defend our assets well into the future before a final resolution becomes available to us. So with that, I will close off finally here. And again, thank you for your interest in the company and your time here this morning. Good day to everyone.

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