Good morning. My name is Jonathon and I will be your conference facilitator today. Welcome to Chevron’s Fourth Quarter 2014 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session, and instructions will be given at that time. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corporation, Mr. John Watson. Please go ahead.

Well, thanks Jonathan. Welcome 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, the General Manager of Investor Relations. We’ll refer to the slides that are available on our Web site. 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. Turning to Slide 3, I'd like to highlight some of our key accomplishments for the year, starting with safety environmental performance. We had our best year ever and virtually every measure of personal safety, process safety and environmental performance. We expect to lead the industry again. Although commodities prices fell sharply late in the year, our overall financial performance was strong, upstream and downstream had solid years overall and both ended the year with very good reliability. We had excellent progress on our asset divestment program with significant well-timed upstream sales in Chad and in Canada and high valuation mid-stream transactions. In the first year of the program we finalized just under $6 billion in investments versus the $10 billion three year target for the period 2014 to 2016, we'll update this target at our March meeting. Looking at our downstream business, we completed important liability investments at several of our key refineries, which contributed to high utilization rates in the second half of the year. We became the world's largest premium base oil producer with the start-up of a 25,000 barrel per day plant at our Pascagoula, Mississippi refinery. We continued to make progress on our U.S. Gulf Coast petrochemicals project through Chevron Phillips Chemical Company our 50% owned affiliate. It is now 50% complete. Moving to the upstream business, we started Jack/St. Malo which is ramping up ahead of plan and Tubular Bells in the Gulf of Mexico. In Bangladesh we successfully expanded production at the Bibiyana field. On our LNG projects in Australia, Gorgon is now 90% complete, we're targeting first gas into the system around the middle of the year and first LNG sales this year. Wheatstone made excellent progress and it's 55% complete and on-track for late 2016 start-up. We've posted a number of photos highlighting our construction progress on these two important projects on our investor webpage. We progressed development of our shale and tight resource holdings, notably in the Permian. We had one of our best years from an exploration and resource capture standpoint with 35 discoveries at a 66% success rate. We added 1.4 billion oil equivalent barrels with significant conventional and unconventional adds. We had two potential hub class discoveries in the deepwater Gulf of Mexico and we announced the transaction yesterday to consolidate holdings around one of them. Our one year reserve replacement ratio was 89% taking our five year replacement ratio to 96%. With that I'll turn it over to Pat, who'll take you through our financial results. Pat?

All right, thanks John. Slide 4 provides an overview of our financial performance, the Company's fourth quarter earnings were $3.5 billion or $1.85 per diluted share. For the year earnings were 19.2 billion this equates to a $10.14 per diluted share. Return on capital employed was 11% and our debt ratio at year-end was 15%. 2014 marked the 27th consecutive that we’ve increased our dividend payment. Given the change in market conditions, we are suspending our share repurchase program for 2015. Turning to Slide 5, cash generated from operations was 6.5 billion for the fourth quarter. For the full year, cash from operations totaled 31.5 billion. Cash capital expenditures were 9.7 billion for the quarter and 35.4 billion for the full year. At year end, our cash and cash equivalents totaled more than $13 billion giving us a net debt position of about 15 billion. Slide 6 compares current quarter earnings with the same period last year. Fourth quarter 2014 earnings were approximately $1.5 billion lower than fourth quarter 2013 result. Upstream earnings decreased to 2.2 billion between quarters. Lower crude realizations and asset impairments driven by the sharp decline in crude oil prices during the second half of the year and higher DD&A charges were partially offset by higher gains on asset sales and lower exploration expenses. Downstream results increased by 1.1 billion driven by stronger international refining and marketing margins, higher gains on asset sales and favorable timing effects. The decrease in the other segment primarily reflected higher corporate charges and tax items. Turning to Slide 7, I'll now compare results for the fourth quarter of 2014 with the third quarter of 2014. Fourth quarter earnings were $2.1 billion lower than third quarter results. Upstream earnings decreased by approximately 2 billion reflecting lower realizations and asset impairments partially offset by higher gains on asset sales and more favorable foreign exchange effect. Downstream earnings increased by 130 million driven by favorable timing effects and gains on asset sales partially offset by higher operating expenses and a one-time economic buyout of a legacy pension obligation. The decrease in the other segment largely reflected higher corporate charges. Moving to Slide 8, our U.S. upstream earnings for both the fourth quarter were about 500 million lower than third quarter results. Lower liquids realizations decreased earnings by 600 million consistent with the approximate 25% decline in the U.S. liquids prices indicators between periods. The decline in prices also triggered impairments of several smaller assets which negatively affected earnings by 90 million. Higher gains on asset sales improved earnings by 160 million. The other bar reflects the number of unrelated items including unfavorable tax effects which were more than offset by the absence of the economic buyout of a long-term contractual transportation obligation in the third quarter. Turning to Slide 9, international upstream earnings were about 1.5 billion lower than last quarter's results. Lower crude oil prices negatively impacted earnings by $1.4 billion. Our average international crude oil realizations were down $25 per barrel between quarters consistent with the decline in Brent prices. The significant drop in prices triggered impairment for several late-in-life assets decreasing earnings by 570 million between periods. Higher operating cost reduced earnings by 110 million. Gains on asset sales increased earnings by 670 million, mainly driven by the farm-down of a 30% interest in our Duvernay shale interest in Canada as well as the sale of our upstream business in the Netherlands. Slide 10 summarizes the change in Chevron's worldwide net oil equivalent production between the fourth quarter and third quarter of 2014. Net production increased by 14,000 barrels per day between quarters. Major capital projects start ups and growth from shale and tight resource developments contributed 13,000 barrels per day. Project start-ups included the expansion of the Bibiyana field in Bangladesh as well as the start up of Tubular Bells and Jack/St. Malo in the U.S. deepwater Gulf of Mexico. Jack/St. Malo achieved first production in December on-time and on-budget. Entitlement effects increased production by 13,000 barrels per day between the quarters. Lower crude prices increased volumes under production sharing and variable royalty contracts partially offset by lower cost recovery volumes. Higher plant turnaround activity at TCO's Tengiz SGI/SGP facility in Kazakhstan early in the quarter and turnaround activity in Thailand and in Australia decreased production by 19,000 barrels per day. Asset sales in the Netherlands, South Texas and Norway negatively affected production by 11,000 barrels per day between quarters. The increase of 18,000 barrels per day in the base business in other bar reflects primarily higher reliability from Tengiz following the previously mentioned turnarounds completed earlier in the quarter. Slide 11 compares the change in Chevron's worldwide net oil equivalent production between 2014 and 2013. Net production declined by 26,000 barrels per day during 2014 compared to the prior year. Shale and tight production increased by 41,000 barrels per day driven primarily by growth in the Midland and Delaware basins in the Permian as well as the Vaca Muerta in Argentina. Ramp up associated with Papa-Terra in Brazil and the expansion of the Bibiyana field in Bangladesh increased production by 13,000 barrels per day. Production entitlement effects decreased production by 14,000 barrels per day. Price effects were positive due to the decrease in crude oil prices of almost $10 per barrel between years. This were more than offset however by negative entitlement effects in Kazakhstan and lower cost recovery volumes in Bangladesh and Indonesia. Assets sales decreased production by 12,000 barrels a day due primarily to the sale of our Chad asset earlier in the year. The base business in other bar principally reflects normal field declines partially offset by base business investments in Nigeria, in the San Joaquin Valley and in the Gulf of Mexico. Our base business continues to perform well with a managed decline rate of less than 3% per year. Turning to Slide 12, U.S. downstream results increased $80 million between quarters. Realized margins decreased earnings by 190 million. Refining margins were weaker on both the West and the Gulf Coast as the decrease in product prices outpaced the decline in crude oil prices. This reflected abundant supply, high inventories and lower seasonal demand. Timing effects represented $195 million improvement in earnings between the quarters largely driven by year-end inventory effects and marking to market on derivatives tied to underlying physical positions. Higher gains on mid-stream asset sales improved earnings by 210 million. The other bar consists of several unrelated items mainly unfavorable tax effects and higher operating expenses primarily associated with planned shutdown activity. Turning to Slide 13, international downstream earnings increased by $51 million between quarters. Higher margins particularly in Asia increased earnings by 280 million. Refining margins benefited from falling crude prices while marketing margins were supported by favorable price lag effects for naphtha and jet fuel. Inventory effects represented $100 million improvement in earnings between quarters mostly reflecting favorable year-end LIFO impacts. A one-time charge related to the buyout of a legacy pension liability decreased earnings by 160 million. The other bar reflects a number of unrelated items including higher operating expenses and unfavorable foreign currency effects. With that I'll turn it back to John for a few comments on 2015.

Okay, thanks Pat. Turning to Slide 14, earlier today we announced the $35 billion capital program for 2015. This is $5 million or 13% lower than last year, excluding expenditures by affiliates the cash component of this program is 31 billion. This program is lower than we signaled last March and is responsive to current market conditions. It funds key projects where we've taken final investment decision and are already under construction. In the upstream this amount is approximately $14 billion representative of the dark blue on this chart. It includes monies for Gorgon, Wheatstone, Jack/St. Malo, Big Foot and others. This category of spend will decline in the future as projects are completed. Base business and shale spending in medium blue on the chart is about 12 billion. A portion of this base business spend includes critical and maintenance reliability work which has limited flexibility. The majority of the base spend, including shale and tight is being screened at current prices. We have increasing flexibility in this component of spend as the year progresses. Spending on Pre-FID projects and exploration work is being high graded, paced and significantly reduced in response to market conditions. Downstream spending of $3 billion is limited to key projects under construction such as the Gulf Coast chemical project which by the way is 35% complete I think I said 50% earlier, 35% complete. And also the spending in the downstream is also limited to critical reliability and maintenance work. Turning to Slide 15 we've reduced our capital budget for the year conserving cash and preserving value. We also are reducing the costs of goods and services and operating expenses. We enter this period of lower prices with a very competitive cost structure. We routinely show you a chart that tracks total cost per barrel in our upstream business relative to our competitors. You've seen we are industry-leader and we have significant cost reduction efforts underway. This chart shows the IHS upstream cost index, industry costs have more than doubled in the last decade. Market conditions will create surplus capacity in most key supply chain categories and drive rates lower. We are actively engaged with all suppliers and have enjoyed early success. We expect the opportunity will grow with time and particularly so if prices remain low. We're also taking action to reduce internal costs. You may have seen press coverage of staffing adjustments in the UK and Pennsylvania. We have other reviews under way in multiple other operating and corporate units. Managing cost aggressively is not new to us Mike Wirth was quite successful in making significant reductions in the downstream in recent years and if you go back and look at our financial statements in 2008 and 2009, you'll see that we took operating and administrative cost down $4 billion or about 15% between years in response to that brief price excursion. We know how to manage costs. Our production guidance is the range of flat to 3% growth the uncertainty is the reflection of market conditions. I'll highlight several of those uncertainties. First, we've had great success in the base business area limiting decline in mature fields to 3% or less in many years. Our shale programs in the Permian and elsewhere continued, but I have indicated we're screening the spend at current prices. I have also indicated we're active in our efforts with vendors and suppliers to reduce costs. The uncertainty in prices and the costs of goods and services creates some uncertainty in the amount of base business investment and the decline rate and growth from our shale resources. Second, we've had success in our asset sale program. The full year effect of last year's sales reduces production 22,000 barrels a day from 2014. There is uncertainty in the timing and precise composition of this year's asset sale program creating uncertainty in the additional volume impact. Remember we're driven on all sales by value and this can influence timing. Finally, the contributions from major capital project ramp ups and start ups this year is significant but relatively small movement in the timing of deepwater development wells at Jack/St. Malo, Tubular Bells or Papa-Terra can make a significant difference in annual production. Similarly, small movements in restart dates for Angola LNG or start up of Gorgon and other new projects can cause variation. Finally, production sharing contract and other entitlement effects are sensitive to prices and spend levels. Our 3.1 million barrel a day target for 2017 remains on-track as the major projects under construction drive that outcome. That concludes our prepared remarks. I appreciate your listening in this morning we're now ready to take some questions. Keep in mind that we do have a full queue, so please try to limit yourself to one question and one follow-up if necessary. We'll do our best to get all of your questions answered. So Jonathan please open up the lines and we will take some questions. Question-and-Answer Session

Thank you. [Operator Instructions] Our first question comes from the line of Jason Gammel from Jefferies. Your question please.

John, I just want to ask about taking FID in the current price environment. You spoke about how you were beginning to see cost savings from your providers and is that something where you would probably just try to delay making an FID to see how that type of negotiation goes with suppliers, or do you expect that you will actually have some fairly significant FIDs this year? And I am really thinking Tengiz’s expansion as much as anything else here?

And I think that's the key one to focus on, if you look -- we have many projects that are in concept development and frontend engineering and design. And so the overall economics of some of them are impacted by the current price environment but the project at Tengiz is a good project and that project will ultimately go forward. And we've made significant progress and have good line up with our partners on that. But we're taking the opportunity in the current price environment to take a look at contracts, take a look at spend and see if we can bring costs down further. Now we have in the plan and expectation that we will take final investment decision later in the year in 2015. Other than that I can't think of too many significant projects where we're likely to take FID this year.

And then just as a follow-up, John do you have any deflation built into the capital budget for 2015 or is it all reduced activity levels?

Well it's a little bit of both Jason, we do have -- I think for example we've dropped over 20 rigs, which is about 15% of our worldwide rig count. So as I said we're screening projects based on the current level of prices if the return is near at hand. So if you have short cycle based business or shale investments and they don't meet investment hurdles at current prices which is the revenue you're likely to realize, we're pulling them from the program and we've cut rigs all over the world. Now many things continue to pass the hurdle and so we’re continuing with our development. For example our work in the Permian passes is the hurdle. And so we're continuing that and have had good success. But we're also taking on costs in a fairly big way, if you look around the world. Rigs get a lot of attention, but that's actually not the biggest category of spend. EPC cost, well construction services, transportation, the fab yards are going to empty out here and rigs. We're taking on all of these things and we have a centralized procurement organization as well as a lot of people in our unit that are taking advantage of the opportunity in spare capacity and the supply chain. It varies considerably depending upon the category of spend that we're talking about and the precise timing. On rigs, we had one offer in one location around the world of a 50% reduction in rig rate. We've already captured retroactive January 1, rig reductions in some areas. So we're taking this on a big way and we have targets. We've baked in a little bit into our numbers but this is a very fast moving market and the longer this downturn persists the more we’re likely to capture and the more it will be reflected in the major categories of spend like EPC cost and major fab yard spending that we might make on projects. Sure. Sir, Ed Westlake.

Our next question comes from Ed Westlake from Credit Suisse.

John, so I mean, just the high level picture and yes-no answer probably, has anything changed to your view that oil demand is growing? And has anything changed about the decline rates that you feel the industry has to overcome?

Yes. Overall the general picture that I've laid out here before and we've talked about is that, as long as the world economy grows, there's a reasonable correlation between world economic growth and growth in energy demand. If the world economy grows 3% to 4%, we tend to see 1% to 2% growth in energy consumption. In our view, maybe 1% for oil, 2% for gas over that time period, so that general picture hasn’t changed. Now it can be influenced in the short run by macro events and prices and things of that sort. One of the things that we're trying to get a handle on and that others are looking at is how responsive will global demand be to the price reduction. If you look at some of those who follows very closely, they could see increases from 3,000 to 5,000 barrels a day from lower prices, but you've also got countries around the world that are reducing demand side subsidies and things of that sort. So it's a function of economics and it depends how long this persists. Truck sales in the U.S. are doing pretty well right now, so I think we get a bump from lower prices and I think we'll see growth of perhaps a 1 million barrels a day in demand worldwide in 2015, but that number can move around a little bit.

And then specifically Gorgon, you've kind of reiterated the timetable I mean can you give us any nuggets to give you confidence that we will get that first gas in Gorgon mid-year and the first LNG cargo this year?

Well I'd tell you that there's nothing at the higher priority for us right now than that Ed. And as I said we're 90% complete. We've got 8,000 people on the site right now, that's a little more than we might have thought in the past. We've brought in a bigger combination vessel and so we have put more people on site. We've made terrific progress on the upstream side basically all 18 wells have been drilled all upstream subsea infrastructure is in place, pipeline installation is complete. You can see a lot of this on the Web site, so those things are good. So we're working all those things really hard. We've got really mechanical electrical instrumentation work that's in high gear right now and we're basically milestone driven and commissioning and starting up systems right now. And that's really our focus. We're monitoring very closely contractor performance and productivity on the Island we're working with the unions on contracts and industrial relations. We've been able to manage through those things fairly well and we're planning for a flawless start up commissioning and start-up process. We've got risks of adverse weather that are there, but look we're shooting to get gas into the system in the middle of the year timeframe and get some cargos out this year. That's our focus. George and Jay Johnson are heading down there here in February so when we come back in March at the Analyst Meeting we'll have some very fresh information for you.

Thank you. Our next question comes from the line of Alastair Syme from Citi. Your question please.

Can I just come back to the chat on CapEx, I'm just trying to get a feel for how the different buckets of CapEx are moving year on year so the base business and the projects under construction, where the big revisions are?

Spending has come down $5 billion overall some of that is in LNG spend. It was a little over $10 billion in 2014 in total, it's a little over $8 billion planned in 2015, so that's a little bit of the spend. Deepwater spend is relatively flat. Shale and tight spend is a little bit higher, but some of our other base business spend is down. We've got about 10% to 15% reduction in exploration expense between years. And of course we also have those mid cycle projects those that are in concept design or engineering that there are fewer of those there's little less spend in those categories this year than in the past, so we're working very hard on all of those costs. And of course you may be asking about how do those categories look going forward? And we do expect growing flexibility in our spend as we move forward. One of the things we'll show you in March when we get there is that that bottom bar those projects under construction the $14 billion that number comes down in time. The LNG spend this year and next will continue to be significant, but as we get to 2017 it’s under $100 billion, so I expect you'll see some reduction in that category. Now we may take FID on some projects, so you may have some additional spend in that category, but in principal there's a very high roll-off rate from that category of projects under construction. The base business spend is a function of both economics and how much we can wring out of the system from a cost point of view so there's activity and there is the cost of that activity and I commented on some of the sort of trends that we're seeing in that category. I will say exploration we're going to continue to explore. We had fabulous success particularly towards the end of 2014 in the Gulf of Mexico where the couple of discoveries and the transaction we had with a couple of other players in the business. So we'll continue to high grade that activity but we have growing flexibility in all categories is I guess the comment I’d like to leave you with.

Could you give us some sort of sense of about as you droll down that base versus payments in 2015, what impact that might have on underlying decline rates in the business?

Yes I think that it is a risk for the industry I think I've commented earlier I think that is a growing risk for the industry. If you go back to 2008 and 2009 period and this is a hard number to get at but we saw an increase worldwide in decline rates for all companies, basically for the entire industry. Increase by a 1% or 2% and that’s very significant. We've done a good job of keeping decline rates to 3% or less I think we’ve got a good chance to do that but obviously when you cut some rigs you have some risk of a higher decline rate in 2015 relative to past years.

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

My question is just to follow-up on CapEx and I appreciate that it is a fluid process yet on your current guidance today, where do you expect the production impact? I mean it doesn't appear to impact the guide for 2015 at least in the high-end? I mean is it altering that 2017 guide or is it really much more long dated impact given being in a longer cycle time of a lot of your resource?

Yes Evan you just said the impact is predominantly over the longer term because we're continuing with the projects under construction and we're deferring some projects and spend that will have some impact on production but it's generally outside the window the window that we're talking about. For example the Tengiz project will be a good project but it’s not going produce volumes inside the 2017 window. Similarly when you cut make reductions in exploration spend you're not going impact a production inside the window. So I would think of most of it as being a long dated impact.

And the 3%, the ’15 production guidance, that's on current prices, I presume? Assuming no asset sales is I guess how I read the sensitivity. Obviously there is PSC effect there in asset sales? Is that correct? That is based on current prices, current strip?

It is I think it really governs the full range it's a pretty good range frankly normally we've given point estimates but there are a lot of moving categories this time. So it really encompasses the range of outcomes that are possible based on where we are today. For example as you point out at lower prices you do get a benefit in some of our PSC agreements from those lower prices where you spend money it takes more barrels to repay cost for example on cost barrels. But the flip side is that you may spend less and so there will be less to recover for example, we are reducing spend and have cut some rigs in Indonesia in response to economic. So you do have some offsets in these categories and of course depending upon when you make asset sales that has a direct impact on volumes.

And just a follow-up if I could, you mentioned you continue to monitor and be responsive to market conditions so I presume that further cuts would be responsive to a deterioration in market conditions. And then I guess you gave -- I like the classification on Slide 14. I guess how much of the $12 billion base is being spent in ’15 on shorter cycle that may be more controllable if conditions warranted?

Well virtually everything in that category is shorter cycle activity there are some critical maintenance and reliability investments that we will continue to make same thing in the downstream. You need to keep your facilities running and in good shape. So there is a category that I would say is inflexible that is in the base business. Although the cost of delivering those goods and services may go down during the period, the activity itself will continue from an activity point of view as time goes by and rig contracts roll off we have growing flexibility in this category. I mean ultimately you have a great deal of flexibility in this category of spend. But as I say and we'll be responsive to market conditions and screen activity out if it doesn’t meet our thresholds.

Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question please.

If I could follow-up with a question on pricing in the current environment, between the changes in the LNG market that we've seen in terms of where LNG is coming from in particular potentially a ramp in U.S. supply and then the reduction, the collapse that we've seen in oil price, are you seeing anything in potential LNG market pricing either for existing projects or for future projects, any change in the trends?

Any change in trends, well the trend has been a very fluid environment and a very frankly there has been a lot pressure on LNG pricing both in response to immediate conditions and response to the projects that have gone to FID around the world. So there is pressure on LNG markets. Notwithstanding that, we did signed a contract during this period that's an oil linked contract with a reputable company for a medium term slice of volume towards the end of the decade which gets us up into the range where we feel pretty good about the projects Gorgon and Wheatstone where we will basically be at our target for sales will be between 75% and 80% on Gorgon and 85% for Wheatstone. So we’re feeling pretty good shape. We obviously need good contracts that to underpin new developments. So one of the projects that we’re pacing until we can see conditions that will support a project is at Kitimat in Canada, we’re continuing with some of the work we have underway to delineate the resource and reach agreements with First Nations people and permitting and things of that sort. But we’re significantly pacing the spend of that project and we’ll get alignment on it and have good alignment in early days with Woodside which is replaced Apache. Other than that I think there is, I think people are pretty cautious right now in the LNG market. Our view is it’s not clear that all the Greenfield projects that are being contemplated can meet economic hurdles at some of the prices we’re seeing. And demand is out there.

Maybe speaking of Kitimat, that's a good transition to a second question, which is from a high-level strategic view, when you look out from here over the next 10 years, has your view of the future changed at all in the sense that when you look back I guess over the last 10, are there projects, business models, efforts that have been part of your business model in the last five to 10 years that when you look forward over the next 10 you think just may not work anymore whether it's large-scale gas projects or oil sands or any type of -- I guess your views at high level on changes in the industry over the next 10 versus the last 10?

My basic view that in fact was referenced in the question which was asked earlier is energy demand continues to grow and if you look at the decline curve that’s inherent in our business and let’s talk about the oil side for a moment. Oil fields decline worldwide roughly 15% a year without investment. The industry works very hard with base business investments to attenuate that decline every year but still you do get declines of 3% to 5% industry-wide. So you need new oil fields to meet demand. The 3% to 5% decline on 90 plus million barrel a day base is significant. So you need investments in new fields and $50 does not support large new field developments and what I would call the big volumes that are going to contribute to meeting demand whether it’s oil sands, deepwater aren’t supportive of the 50 bucks. So that’s why you’re seeing forward prices and most in the industry expecting to see some rebound in prices because we simply won’t be able to support those projects at those kinds of prices. Now there in the short run when you have supply that is exceeding demand in our business short run supply and demand are not very responsive to prices so it takes that decline kicking in or action by OPEC or a stronger economic growth to close that gap and that’s what it will be required here over the next period of time to get prices into a range where they can support the sorts of projects that you’re referencing. Our view is those forces are at work right now and we can debate when that gap will close but the forces are working with every announcement of C&E cuts it’s more likely to happen sooner. So my basic view is the world needs energy and the prices have to support the activity and of course we monitor the cost environment that we’re in. We can see short run reductions in costs that can make projects more economic but in general the projects that are going to meet demand going forward are more complex than 20 or 30 years ago and so the cost of those projects will be higher and require higher price than we’re seeing today to meet the volume targets. Probably a long explanation but that’s how we think of it.

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

John, often times that risks also come opportunity and especially that you foresee maybe longer that potentially that you could have distressed assets out there in the U.S. and maybe also overseas. So from a high level, how do you guys look at under that circumstances I mean how much are you willing to use your balance sheet or perhaps that risk in your balance sheet a little bit and also that to use perhaps your currency not necessary at the best point that you want but will you be willing to also use it in a decent sized transaction?

Well, we -- old times Paul you and I've talked many times over the years, we're a depleting resource business, so we have to acquire leases discovered resource and frankly companies overtime. And we're very targeted in how we do that and we have tried to be commercially smart and take advantage of the opportunities when there's less competition for those assets. So we are actively screening the opportunities that are out there and we'll take advantage of opportunities that we see, I mean a one that's on the smaller end of the scale, but just a couple of days ago we did announce a consolidating transaction in the deepwater Gulf of Mexico with a couple of partners. And we think we've acquired resource at a competitive cost relative to exploration costs and so -- and there are benefits to all parties from working to develop a common set of assets together in one hub, but that's -- so we do take a look at the opportunities that are before us. Now I have to tell you, our priority right now isn’t acquisitions. Our priority at the moment is completing the projects that are under construction. And we do have balance sheet parameters that we work within to do that, but you point out on a relative basis, we've got a pretty good currency and we're mindful of the opportunities that's there.

Can I just follow-on a quick question, that in your supply costs, any rough idea of what is the percent of your supply contract whether it is rig EPC, those have a duration longer than two years. So in other words what is the percentage of your cost base both in capital and operating costs that potentially we could see the benefit from the deflationary environment that expecting over the next 12 to 18 months?

We have a number of contracts that roll-off during that period. I would say by the time you get to 2017, almost all spend becomes variable if you will, so in fact a lot of it this year rolls off. Now we do have deepwater rig contracts that have been staggered and go out a few years. We do have fabrication contracts that have already been led they can go out several years, but the vast majority of the spend going forward if you look out to say 2017, the vast majority of that spend will be reflective of current market conditions.

Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question please.

John, from this level are you saying that you expect CapEx to go lower and do we now say that the 3.1 million barrel a day 2017 target for volumes is gone? And one query I would have about that is it was previously lowered because of an assumption that oil prices would be higher. If you recall your previous planning assumption had been I think $79 and it was the move up to a higher price that caused you to lower the target. Wouldn't that be a reverse effect down here? Thanks.

Yes well I did reaffirm the 3.1 in my comments earlier, so I have reaffirmed that target. And I will say there are quite a few moving parts in getting to the 3.1. First, most of the growth between now and then in underpinned by Gorgon, Wheatstone, Jack/St. Malo, Big Foot, Mafumeira Sul and others that are under construction. And I've indicated we're continuing to fund that spending. We have had over the years some changes in the composition of the remainder of the volumes that contribute to the 3.1 for example, we've previously flagged in response to U.S. gas prices, we had reduced spend in that area. On the other side, the Permian wasn’t in our plans when you go way back to 2010 and volumes coming from that area or higher. There has been a big change in prices and price effects as I indicated earlier can impact volumes. Other things being equal there is a contribution if we get to 2017 and prices are much lower, there will be a positive contribution that's inherent in that 3.1. The other side as I also commented is that we have fewer -- we have less impact from that, if our spend goes down in places like Indonesia and finally we have asset sales that can influence that target, but as we see it today with all those effects some that are positive some that are negative, we still see that 3.1 target.

John, just I guess what I am driving at is that based on the 35 would you think you could come lower on the 35 billion of spending and still make the 3.1 and would you manage towards the 3.1, is that what you are saying because I guess you do have a view…

No that's specifically not what I'm saying. What I'm saying is that we have always -- the volume has always been an outcome. It's always been an outcome. We make decision based on economics. What I'm telling you is that I see the outcome being 3.1 because 80% to 90% of the volume increase between now and then are the projects that are under construction. And we make the investment decisions on our best view of go forward economics and in response to the best value propositions that we can see. The precise level of spend going forward the only thing I'll flag as you know I've been reticent to talk about C&E going forward and this last year is a perfect illustration as to why. We have a lot of moving parts many of which I have described. We also have currency movements and uncertainties, we have growing flexibility in our spend going forward. And if the kind of price environments we see the day persists you will see lower spending absolutely.

I mean guess what I was driving at is that you had previously guided towards the flat CapEx from the previous 40 level in order to meet the 3.1. I think what you're now saying is you can still meet the 3.1 and we could even then still see lower CapEx again in meeting the 3.1. Or do I think about it that you are potentially not going to meet the 3.1 and bring down CapEx appropriately with the oil price?

I think the outcome is a function of spend that is largely already committed as one of the questions earlier commented is there much volume effect for some of the cuts most of the volume effect will be after 2017 because there are these longer cycle projects where we're taking a pause and trying to work the costs spend. So you know very well Paul we are in a long cycle business and so if you defer longer term projects now it will mean lower production than you might otherwise have seen beyond the target date of 2017. So there is an impact beyond 2017 of the decisions that we're making today but because we have all these projects in flight we don’t see a significant impact to our target beyond the fact as I talked about before of base business spend, timing of asset sales and quantity of assets sales cost barrel effects and things of that sort.

And a very quick one, could you indicate how high you think that can go in order to then allow you still to maintain your targeted credit rating? Thanks.

I'm going to let my CFO talk about the balance sheet and credit ratings.

Yes, and Paul we have a lot of borrowing capacity still available to us we ended the year with a 15% debt ratio and there is a lot of appetite in the capital markets for our debt and under the scenarios that we're talking about here in this price range with this capital program we anticipate still being very nicely within the double A band and after you get through 2015 really and you look ahead obviously we're going see more production growth. John talked about the flexibility that we've got as time rolls on with our capital program we talked about and we do believe that there will some recovery in oil price we don’t know at what level or exactly how quickly and there will be adjustments to our cost structure. So we feel very comfortable with the position that we're in and John referenced earlier managing within certain constraints and one of the balance sheet constraint is maintaining a strong AA.

Is there a rule of thumb for how much that you can have and still be AA?

I don’t think there is rule of thumb because the rating agencies take into account not only what your financial parameters are but also what's your operating parameters are and what's your prospects for future cash flow generation really are, so it's a combination of what the overall business plan so to speak for the enterprises if the rating agencies take into account. But suffice it to say we have incremental borrowing capacity of several-several 10s of billions of dollars there.

Our next question comes from the line of Phil Gresh from JPMorgan.

First question is just kind of following up. In terms of trying to achieve dividend coverage and how you think about when you can get there full 100% dividend coverage, any color you can provide about how you kind of bridge to that? Because it looks like this year kind of the shortfall in the free cash flow and then the dividend, you add that up it's maybe $15 billion to $20 billion, so anything you could n provide around that. It sounds like operating costs you've highlighted maybe $4 billion of opportunity but just generally how you are thinking about that?

Sure, our plan is to cover the dividend in 2017. And we won't do it this year in all likelihood and in fact we flagged that if you go back two or three years or three to four years we have said in fact it was in response to questions around our balance sheet at that time where we had more cash than debt on the balance sheet and a lot of you were encouraging us to repurchase more shares and to really take advantage of the lower cost of debt and we said look our primary case may not be falling oil price. But we've got a lot of projects under construction and we're in a commodity business and we need to be able withstand the ups and downs of our business and so what I said at that time is that we would be restoring our balance sheet to something that might be a more normal level for AA credit rating as time goes by and these projects roll off. So when you get the reason I say 2017 is our production will grow between now and then by about 20% and so at whatever price level we're at we'll see benefits to free cash flow from that I have talked about the flexibility in the activity level that we have which can moderate spend and bring us back into balance. And then of course as you mentioned the cost reduction efforts that we have underway both in the supply chain and internally will help us attenuate that. Finally bridging us and helping us on the balance sheet are the contributions from assets sales and you saw we got off to a pretty good start in the program this year but we've flagged and indicated that even at higher price that we were going to use our balance sheet and we were going to use a little of it this year than perhaps would have been the case with higher prices but we’re able to attenuate that over a couple of years.

So just a clarification on that then, with the strip in the low 60s is it fair to say that your production growth later in the strip take out 4 billion cost you would actually plug the CapEx to get to a level that carries within that?

I’m not going to give you a specific price forecast, I’ll just say that the boundary conditions that we’re operating under and these are things Pat has talked to you many times the boundary conditions, the dividend is the highest priority of spend for us and we want to keep sufficient flexibility on our balance sheet to withstand the ups and downs in the commodity market. So we will work very hard on CapEx and OpEx in order to get balanced in a couple of years.

Okay. And just my follow-up question, is there anything in the production guidance for 2015 for Gorgon and for Angola LNG at this point or would execution on that timing wise be upside to the guidance just how to think about and the update on the Angola LNG in general?

Well, there is a scenario where we can be to the upside of the range that we’ve indicated, but frankly I’m a little gun-shy on that sort of thing given the kind of the operating environment that we’re in right now given oil prices are and potential adjustments to spend. So yes, we expect to see volumes from those assets this year. The exact timing brings in some variability but our plan is to have both of those contributing volumes this year.

Thank you. Our next question comes from the line of Iain Reid from Bank of Montreal. Your question please.

Just a question about your onshore drilling activity, you seem to be maintaining or increasing your drilling in the Permian whereas some of the other companies seem to be deferring it on the basis that it will be worth more in a couple years time by leaving it in the ground. Just kind of interested in your take on that versus what you are planning?

Well, we have about 30 rigs running in the Permian and we continue to screen the economics of both I think what I said is our spend on unconventionals will be, in shale will be higher this year than last. But that encompasses our worldwide activity that we expect to see. So we’re still, by the way we’ve had some terrific performance in the Permian, and part of the reason we’re able to do that is we’ve been able to dramatically reduce cost. When we get ahead to March at our Analyst Meeting we’ll give you a fair amount of information on how we’re doing some of the horizontal pad drilling programs that we’re putting in place we’re seeing very-very good early results. But we need to see good returns on these things to make investments. And so I’ll just say we do expect some recovery in prices as the year moves on but if we end up in a depressed environment we can make adjustment to that. Remember a lot of our volume in that area, we benefit from no royalty and that’s a big competitive advantage, as you get down where others might be at the margin more than we are. We’re in pretty good shape because we don’t have royalty and we’ve got a long-long queue available to us.

Okay, just one other thing, I heard what you said on Wheatstone in terms of schedule. I just wonder though where you are in terms of budget and CapEx. Is there any update you can give us on that relative to the original budget because we haven't had a project update for that one?

No, we’re still operating under the current appropriation request that we approve which is the -- the Wheatstone project was a $29 billion U.S. project and we’ve had some ups and downs frankly right now we’re benefiting from currency movements if you -- the Australian dollar I think is around $0.78 so we’re benefiting from that. We’ve had some ups and downs there but -- and have used some of the contingency in the project but we’re still operating within that same appropriation request.

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

John, you've done a -- you've obviously got a tough job of trying to manage through the cycle and if you look at the near-term growth I think you've been pretty clear that that is pretty much prefunded with the commitments you've got going on. But once you get to 2017, once you've delivered your target, assuming an oil price range which is lower than we have had in the last five years, how do you think about the trade-off between continued growth versus other uses of cash like a return to buybacks? And what's on my mind is over the last 10 years before the growth phase, the share prices did just fine in a relatively flat production profile over that 10-year period? So that's my first question. I've got a related follow-up, please.

Well, I guess I’d say volume has always been an outcome of our views about the quality of the investments that we available to us and that will continue to govern our decisions. If we wind up in a lower price environment in 2017 that we might have thought we would be in a year ago I think there will be contributing factors to that, one will be costs. And so, we don’t make decisions to invest based on our volume target, we make decisions to invest based on our perception of the value that's available to us. There were confluents of events that resulted in several significant projects coming together at the same time. We had lease retention issues we had good gas contracts available to us for example on Wheatstone. We've had a moratorium in the Gulf of Mexico which is good things. And so -- and you had lease commitments and things of that sort, so you would not only choose to have all those projects be together, but we've felt individually they were good and we felt we had the capacity to handle them. And we're starting to see them deliver today and frankly if you look at our -- for all the talk about these projects, Gorgon and Wheatstone are 30 year to 40 year projects, and didn’t come online yet. And when they come online and over the cycle, I'm very comfortable that the economics will be just fine and they'll be prolific contributors to the Company for years to come. And all these new projects also have follow-on opportunities to them, because we typically -- first phases of projects don’t result in all the resource being developed and the incremental economics are better. Our priority around spend has been pretty clear. One, we're going to pay the dividend and we're going to increase it as the pattern of earnings and cash flow permit. And we'll invest to do that. And we'll do that within the parameters of our balance sheet. We have viewed share repurchases at the Flywheel and the Flywheel is -- was available to us. We have cautiously spread out share repurchases over time, so we've tried not to just be in for a short period of time, we were in for a longer period of time. But obviously with the price environment we're seeing, we're discontinuing that program. But if we get to a circumstance where we're generating cash flow, we don’t see the opportunities we get no reticence at all to repurchase shares if we think that's a better opportunity for us.

My follow-up, and I will be quick I realize we are at the top of the hour, but it's kind of more of a macro question. It's going to be a tough one to answer. But when we think about Chevron's role as a global player, 1.9 million barrels a day of oil and the operated obviously is a lot bigger than that, do you think that Chevron has been representative of big oil and non-OPEC, meets a certain oil price environment to maintain flat production, what would that number be for Chevron? In other words to hold production flat close to the start-up of the major projects, can you hold flat at 50 or 60 or 70? What do you think that number is now? I will leave it there.

Well Doug you're right it is a tough question. If we're in a $50 world, there will not be -- just as I said at a macro level around the world I don’t see many investments that are going to go with the fiscal terms we see in place today with the cost levels we see today. I see very few major oil projects going forward. There will be incremental investments on existing projects to mitigate the decline there will be some shale investments that maybe economic, but I don’t know for example around the world of full cycle of economics deepwater projects that go at $50 at the current cost structure. I don’t know of new oil sands volumes that can come on at $50 and there are oil fields in decline everywhere so I just don’t see that. Now cost can adjust, fiscal terms can adjust and so it's hard to speak definitively for a very long period of time, but it is very clear that the incremental barrels are coming from more complex developments overtime. With all the enthusiasm around shale I think it's important to remember it's 4 million barrels a day out of a 92 million barrel base. And you're going to see the rate of growth in that volume was due to slow and you're going to see a reduction in that rate of growth in response to current prices. I think we're at the end of our time I thank you very much for the questions. That -- and in closing we’d just say we appreciate everyone's participation. I especially want to thank the analysts on behalf of all participants. We look forward to seeing you at our March Security Analyst Meeting, so Jonathan thank you.

Thank you. And thank you ladies gentlemen. This does conclude Chevron's fourth quarter 2014 earnings conference call. You may now disconnect. Good day.