Good day ladies and gentlemen, my name is Jonathan and I will be your conference facilitator today. Welcome to Chevron's First Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker’s 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'll now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington, please go ahead.

Okay, thank you Jonathan. Welcome to Chevron's first quarter earnings conference call and webcast. On the call with me today are Jeff Gustavson and Frank Mount who are currently transitioning the General Manager of Investor Relations role. 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 first quarter earnings were $2.6 billion or $1.37 per diluted share. Excluding gains from asset sales, foreign exchange effects and other special items, earnings were $0.76 per diluted share or $1.4 billion. This is a better outcome than the decline in commodity prices would have implied. This is because operationally, it was a very solid quarter for both upstream and downstream. Production volumes were strong and downstream asset utilization and reliability were high, plus operating cost control was evident throughout the enterprise. Return on capital employed for the trailing 12 months was approximately 10% and our debt ratio at quarter end was 18%. During the first quarter, we paid $2 billion in dividend. Earlier in the week, we announced a dividend of $1.07 per share payable to shareholders of record as of May 19. We currently yield about 3.8%. Turning to slide 4. Cash generated from operations was $2.3 billion for the first quarter. This reflected lower upstream results due to the sharp decline in commodity prices as well as negative working capital effects of approximately $2 billion. The majority of the working capital effects are temporary in nature and we expect these to reserve in future quarters. These impacts were only partially offset by strong cash generation from our downstream and chemicals businesses. In the quarter, proceeds from asset sales totaled approximately $950 million, the majority of which related to the sale of our interest in multiple offshore and onshore leases in Nigeria. In February, the Company successfully executed a $6 billion bond offering. Cash capital expenditures were $7.6 billion for the quarter, a decrease of approximately 11% from first quarter 2014 and over 20% lower than fourth quarter. At quarter-end, our cash and cash equivalents were approximately $13 billion and our net debt position was about $21 billion. Slide 5 compares current quarter earnings with the same period last year. First quarter 2015 earnings were approximately $1.9 billion lower than first quarter 2014 results. Upstream earnings decreased $2.7 billion between quarters; significantly lower crude realizations were partially offset by positive foreign exchange effects, higher gains on asset sales and favorable tax items. Foreign exchange gains in the first quarter were substantial, $580 million in total. As a reminder, most of our foreign exchange impacts stem from balance sheet translations and do not generally affect cash. Downstream results increased by over $700 million, primarily driven by stronger worldwide refining and marketing margins. Operationally, first quarter results were amongst the very best we've had in several years, a perfect combination of margin strength and improved refining reliability. The variance in the other segment was primarily associated with the absence of an impaired recognized in first quarter 2014 following sustation [ph] of certain mining operations, primarily offset by higher tax and other corporate charges. Turning to slide 6, I'll now compare results for the first quarter 2015 with the fourth quarter of 2014. First quarter earnings were approximately $900 million lower than fourth quarter results. Upstream earnings decreased by approximately $1.1 billion between quarters, reflecting lower realizations and assets on gains partially offset by lower impairments and operating costs. Downstream earnings were lower by $95 million, stronger U.S. margins and lower operating expenses across the global systems were more than offset by the absence of gains on asset sales recognized in the fourth quarter and an unfavorable swing and timing effects between quarters. The variance in the other segment largely reflects lower corporate charges. Jeff will now take us through the comparisons by segment.

Thanks Pat. Turning to slide 7. Our U.S. upstream earnings for the first quarter were about $900 million lower than fourth quarter's results. Sharply lower liquids realizations decreased earnings by $735 million, our crude and liquids realizations all dropped by approximately 35% between periods. Gains on asset sales were lower by $330 million. In the fourth quarter, we recognized a gain following the sale of our interests in certain LPG pipeline assets, which are associated with the upstream segment. The other bar reflects a number of unrelated items. Lower operating and exploration expenses were partially offset by higher depreciation charges, including impairments for several smaller assets. Turning to slide 8. International upstream earnings were about $200 million lower than last quarter's results. Significantly lower crude prices impacted earnings by $1.3 billion. Our average international crude realizations were down over 30% between quarters, consistent with the decline in Brent prices. Lower operating expenses across multiple countries increased earnings by $335 million. In March, the U.K. government implemented a change in the petroleum tax law retroactive to the beginning of the year, which resulted in a one-time deferred tax benefit of $350 million. The absence of impairments from the prior quarter increased earnings by $570 million, while lower gains on asset sales this quarter decreased earnings by $360 million. The other bar included multiple components. Two notable drivers for this positive variance were stronger liftings and foreign exchange effects. Slide 9 summarizes the change in Chevron's worldwide net oil equivalent production between the first quarter of 2015 and the fourth quarter of 2014. Net production increased by almost 100,000 barrels per day between quarters. Price effects increased production by 55,000 barrels per day as lower crude prices increased cost recovery and other volumes associated with production sharing and variable royalty contracts. Major capital project ramp ups at Jack/St. Malo and Tubular Bells in the Gulf of Mexico and from the expansion of the Bibiyana Field in Bangladesh, increased production by 42,000 barrels per day. Plant turnaround activity was heavy in the fourth quarter, particularly at our SGI/SGP facilities in Kazakhstan as well as in Thailand and Australia. First quarter by contrast was much lighter in planned maintenance and this accounted for higher production of 36,000 barrels per day between periods. Growth from shale and tight assets, primarily in the Permian contributed 10,000 barrels per day. External constrains, primarily lower gas demands in Southeast Asia as well as weather-related impacts decreased production by 18,000 barrels per day. The remaining variance in the base business and other bar reflects greater unplanned downtime in other non-related items. Slide 10 compares the change in Chevron's worldwide net oil equivalent production between the first quarter 2015 and the first quarter 2014. Net production increased by 93,000 barrels per day between periods. Price effects increased production by 71,000 barrels per day due to the roughly 50% drop in crude prices between periods. Last year, Brent averaged $108 per barrel in the first quarter. This year Brent averaged $54 per barrel in the first quarter. Shale and tight production increased by 43,000 barrels per day due to growth in the Midland and Delaware Basins in the Permian as well as in the Vaca Muerta Shale in Argentina. Major capital projects increased production by 35,000 barrels per day. Production ramp-ups in the deepwater Gulf of Mexico, Bangladesh, Trinidad and Brazil were all positives. The shutdown of Angola LNG which occurred subsequent to last year's first quarter partially offset these increases. Asset sales resulted in loss production of 34,000 barrels per day, principally driven by divestments of our assets in Chad and in the Netherlands. The decrease of 22,000 barrels per day in the base business and other bar primarily reflects normal field declines, partially offset by lower turnaround activity and unplanned downtime. Our base business continues to perform well with the managed decline rate below our existing guidance. First quarter net production rate of 2.681 million barrels per day is a strong start to the year and is above the flat to 3% growth range we indicated in January as our production guidance. While this is above our guidance, it is important to remember that we have maintenance turnarounds and asset sales plans for later in the year. I would also like to comment on an issue we mentioned in our 10-K about our operations in the Partitioned Zone between Saudi Arabia and Kuwait where we produced 76,000 barrels per day net in the first quarter. It now appears more likely that our future production levels in the Partitioned Zone could be negatively impacted due to our inability to secure work and equipment permits. The potential for a shutdown of production was not anticipated in our flat to 3% guidance range. We do not know for sure how production impact will occur and if does occur, we cannot estimate its duration. In any case, we estimate that the 2015 financial impact from a potential shutdown would be minimal. Turning to slide 11. US downstream results decreased $183 million between quarters. Importantly, the operational results noted in the green bars were over $500 million stronger between periods. Margins increased earnings by $435 million driven by unplanned industry downtime and tight product supply on the US West Coast. US Gulf Coast margins were also strong reflecting industry refinery maintenance patterns and strong seasonal demand. Lower operating expenses increased earnings by $110 million primarily associated with reduced turnaround in maintenance activities. Timing effects represented a $250 million decrease to earnings mainly due to the absence of positive year-end inventory effects recognized in the fourth quarter and unfavorable mark-to-market swings between quarters on derivatives tied to underlying physical assets. The absence of gains on asset transactions from the prior quarter decreased earnings by $460 million. Turning to slide 12. International downstream earnings improved by $88 million between quarters. Lower margins decreased earnings by $70 million. Marketing margins fell, largely the result of product pricing lag effects evident in both Asia and Australia. Reduced operating expenses increased earnings by $120 million. Timing effects represented a $215 million decrease to earnings. As in the US segment, this represented the absence of favorable year-end inventory effects booked in the fourth quarter and adverse swings between the quarters and mark-to-market valuations on derivatives tied to underlying physical assets. The absence of one-time charge in fourth quarter related the economic buyout of a legacy pension liability increased earnings by $160 million. The other bar reflects a number of unrelated items. The largest single component was favorable foreign currency effects. With that, I’d like to now turn it back to Pat.

All right, thanks, Jeff. Turning now to slide 13. In response to the downturn, we are aggressively pursuing cost savings. Excluding fuel, operating cost in the first quarter are down 13% from the average 2014 quarter. To-date, we have completed more than 2,200 supplier engagements with 700 more in progress. We’re working across all spend categories to negotiate supplier reductions and to rebid contracts when sufficient reductions have not been offered. The results have been encouraging with over $900 million of contract savings already negotiated. The pie chart shows upstream spend categories, [00:00:57] our supplier cost reduction effort and the $900 million quoted is enterprise-wide. This represents cash savings we expect to capture in 2015. We’ll see it show up as the year unfolds in multiple ways; lower operating expenses, reduced capital outlays, and decreases in cost of goods sold. Spend categories closer to the Wellhead and activities with the shorter term contracts as well as shorter cycle times from order date to delivery date are seeing the sharpest declines. We’re also seeing more immediate responsiveness from suppliers supporting our US operations. Looking externally for improvements is only part of addressing our cost structure. We’re also reengineering our internal work processes, initiating organization reviews, rightsizing our work teams to better match spend and activity levels and all of this to align with current market conditions. Our objective is a simpler, more efficient, more productive and affordable organization that directly supports our business priorities. Finally, we are pursuing capital and operating efficiencies throughout the organization, getting more for each dollar of spend. In the upstream, we are applying our experience with running manufacturing type operations to our shale and tight developments in the US and elsewhere. This is driving significant efficiency improvements and lowering the costs of our horizontal well programs in both the Midland and Delaware basins. In the downstream, we are using tools like Lean Six Sigma to improve efficiency throughout our operations and one specific example, we’ve shortened the downtime by 30% associated with terminal and tank inspection and maintenance activities, which should lead to sizeable cost savings over time. Turning to slide 14. You recall a key commitment from our March presentation related to covering our dividend in 2017 from free cash flow. We outlined how we intended to do that and I like to put a few of our accomplishments into that context. Cash flow growth is a near-term priority. While absolute prices in the first quarter were not favorable, our production was. Base business performance was strong and our base decline rate was less than 2%. We also continue to ramp up at Jack/St. Malo in the Gulf of Mexico. The fifth well is now online and growth production is up to over 70,000 barrels per day of oil equivalent, exceeding initial expectations. We completed some critical milestones on the Gorgon and Wheatstone LNG projects in Australia. At Gorgon, we started up the first gas turbine generator successfully, an important step in the overall plant commissioning process. At Wheatstone, we successfully installed the topside for the offshore platform -- production platform. We have posted new pictures today and a video of both projects will be posted early next week. I encourage you to look at these on our investor website at chevron.com. And finally, our downstream and chemicals business is performing very well. We do think spend is our second priority. I’ve already talked through the cost structure savings we’re pursuing. In addition to that, we’re on a clear path to reduce capital spending over the next several years as our major capital projects come online and our spending flexibility increases. Budgeted capital spending is planned at $35 billion this year, a 13% reduction from 2014. Cash spending is down -- this quarter is down 11% from first quarter a year ago. By 2017, we expect to have over $8 billion in additional C&E flexibility compared to 2015. And finally, we’re making excellent progress on our asset sales. We realized almost $6 billion in proceeds last year and will be adding nearly $4 billion to that in the first four months of this year with a recently completed lease sales in Nigeria and the divestiture of Caltex Australia. In 16 months, we’ve achieved almost $10 billion in total sales proceeds versus a $15 billion 48-month target. We will continue to sell assets when we can generate good value. Moving to slide 15, I would like to close by reiterating the near-term value proposition that Chevron offers. We expect to deliver industry-leading volume growth between now and 2017. That growth is sourced from Gorgon and Wheatstone in Australia, Jack/St. Malo and Big Foot in the Gulf of Mexico and Mafumeira Sul and Angola LNG in Angola. In addition, we are poised for a significant growth in our shale and tight resources, particularly in the Permian in the US. On top of the pure volume growth, we also offer margin expansion. The cash margins associated with these projects, primarily in the orange portion of the shaded bar, are projected higher than our cash margins today and many significant leasehold. By 2017, we expect our cash margins on our overall portfolio to increase by approximately 35% from where they are today assuming $60 average Brent price this year and $70 average Brent price in 2017, which is consistent with current futures prices. We believe that our outsized volume growth combined with outsized margin should lead to outsized value growth for our shareholders. That concludes our prepared remarks, and I appreciate you listening in this morning. We are now ready to take some questions. Please keep in mind that we already have a full queue, so try to limit yourself to one question and one follow-up if necessary and we will do our best to get all of your questions answered. So Jonathan, please open the lines for questions.

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

Good morning, Pat and congratulations Jeff on the move, and welcome to Frank. Just I guess the question around cash flow to start with. Thanks for shouting out the working capital, I think the market would have had kittens if it was a $2 billion CFO number. I mean obviously, if you have net income and DD&A, you get a high number, but I presume some of the deltas or things like dividends from associates being less than net income and the timing of tax payments, if there is any color on that? But my general question is, how does this cash flow stack up against your internal expectations for the quarter appreciate, obviously the oil price is very low. And has anything changed in terms of your cash flow projections going forward in what you see as a more normalized oil price?

Okay, yeah, thanks, Ed, appreciate the question and I appreciate everybody’s interest in cash. You’re right. So it was a low cash from operations quarter, but we did have $2 billion of adverse working capital effects, so if you added those back, we would be at about $4.3 billion. What I would say is, if you looked at our sensitivity on oil price relative to prior quarters and look at it this quarter, this very much is in-line and in fact, it’s actually a little bit stronger than just a pure sensitivity would suggest. I’ll just mention the number again for everybody, it’s somewhere between $325 million and $350 million per dollar Brent change. So we’ve had a significant drop in Brent prices, and therefore a significant drop in earnings as well as cash flow. You’re absolutely right, Ed, that there were some decrements relative to normal quarters in terms of the amount of affiliate distributions that we received. This quarter was, I would say, pretty minimal in terms of that. We do expect that to turnaround in the subsequent three quarters, so that’s just a timing issue. In terms of how this looks relative to our plan going forward, if you recall the numbers that we showed you in March, the slides that we showed you with financial projections, all assumed a $60 world for Brent, and I think we’re exactly in that phase. And so I look at our profile this year in terms of how earnings have come in and cash have come in and assuming we end up at a $60 world for Brent, which looks very reasonable given where the futures markets are than I think we are exactly on plan and very consistent with the cash profile that we showed you back in March. And you’ll recall, for everybody, that we did have a significant deficit anticipated in 2015 and then we showed you the pattern of how we would move out of that deficit out to 2017, getting full coverage of our dividend by 2017. I mentioned the asset sales that we have, the first quarter was nearly $1 billion and here in April already, we have the sale as well. So already through four months, we've got a significant contribution of about $4 billion. So asset sales are a key component there as well.

Thank you. I think I asked three questions in one. So I will defer to the next in line.

Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question please.

Good morning, Pat, Jeff.

Good morning.

Good morning.

So Pat, I wanted you to talk through the dividend here and just how we're thinking about dividend growth, historically, you’ve raised the dividend in the second quarter earlier this week. You kept it flat, so want to see if this represents the departure from the views on dividend growth or maybe just the change in the timing on when you evaluate it?

It's a good question, Neil and let me just start by saying that maintaining a competitive and growing dividend is our number one priority. That has not changed. Our financial priorities have not changed, but what has changed is our immediate financial environment, the near-term environment has changed and so the board chose not to increase the dividend this quarter. It is similar to what we did back in 2008 and 2009, when prices last fell significantly. We are supporting a 3.8% yield, but clearly, we are not running very strongly on earnings or cash flow at the moment due to commodity prices. I think it’s fair to say that the first quarter was not a very stable financial environment, it was very fluid in terms of both revenues and costs. And so I think our overall decision is going to be based on what we feel is affordable and supportable in perpetuity, because we don't want to get into a position where we are having to cut the dividend or trim the dividend in anyway. And therefore, the timing and the size of an increase will be a function of how cash and earnings and asset sales or major capital projects execution and frankly, future commodity prices, I mean that is a significant factor, how those all play out in the coming quarters. And really how we see commodity prices playing out over a longer sweep of time. All of those factors will influence that decision.

Thanks, Pat. And then want to come back to your point on the neutral zone. And I think Jeff, you made the point that the financial impact would be limited or immaterial. The number you shadowed out there represents about 3% of your volumes, so curious as to why earnings impact could be immaterial, is that because the margins associated with those barrels could be lower and just a broader status update on the [indiscernible] field would be helpful as well.

Yes. So essentially you are right. The financial impact is minimal because of the relationship to margins essentially. And then on the steamflood status, it was our -- we did have steam breakthroughs, so we did have success in that pilot. It was our expectation, it is our expectation to go into feed later this year, perhaps around the third quarter, but obviously depending upon circumstances and how they unfold over the next few weeks and these discussions between Saudi and the Kuwaitis on the partition zone. It could be – there could be somewhat of an impact there. I will say that there are discussions that are ongoing underway because this is obviously a very serious circumstance and it's being taken seriously. So we put a lot of could and potential and words like that in our language, because we really don't know and the hope is that this can get solved, we are optimistic that this can get solved.

Thank you, Pat. And Jeff, congratulations.

Thank you, Neil.

Thank you. Our next question comes from the line of Phil Gresh from JPMorgan. Your question please.

Hey. Good morning, Pat. Congrats, Jeff and Frank. First question is just on the OpEx. Thank you for the helpful color on that front. I guess what I'm wondering is as we think about how the first quarter progressed on a year-over-year or a quarter-over-quarter basis and what you called out relative to I believe it was John’s commentary last quarter, I think the last cycle you talked about a $4 billion saved number, kind of where do you think you are in those structural sales opportunities and how we should sequentially be thinking about this as we look at 2Q and the second half?

Right. I think that our profile at least what we've seen so far in the first quarter with all of the concerted and systematic effort that we've got underway throughout the entire enterprise, I feel that we should have really good operating expense trends as we move through the remaining three quarters of the year. We are seeing cost reductions over a whole series of cost categories anywhere from 10% to 20% and some of that of course will end up in OpEx spend, some of that will end up in capital expenditures, lower capital outlays, but I would just say from the response on the part of suppliers, the intensity with which we are pursuing this, the fact that if we are not getting the cost reductions that we are anticipating from a given supplier that we are willing to move market share and have done so, all of that I think bodes very well for our bottom line and our cash spend really over the course of subsequent periods here.

So just a clarification. If you were to maybe put it in terms of innings like what you actually realized in the first quarter because I think the OpEx is down $600 million year-over-year, so I am just trying make that for with $4 billion number and think about how far along you are versus are you actually in the early stages?

I think we're in the very early stages in terms of what has been recognized in the first quarter results. So I think there is a lot of potential still to come.

This is Jeff. Just to be clear, the $4 billion was a 2009 number. What we saw back in 2009, nothing that we put out here recently.

Understood. Just on -- my second question is on CPChem. I think there has been some discussion out there about the potential to maybe officially leverage that balance sheet. So maybe you could just talk about your thoughts on that and whether there's any potential of that in 2015?

Okay, sure. In the past, CPChem has held debt. And then they've gone through a period here where they were generating tremendous amounts of cash and dividending that to their parents. Now they are in a position where they have investment opportunities through that US Gulf Coast cracker project and so it would not be unreasonable to think that they would go into the debt market in order to fund some of their investment opportunities.

Okay, great. Thank you.

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

Hey, good morning, everybody.

Good morning.

Yeah, thanks for the comment on the dividend and maybe I will kind of try further there. I know in 2009 you raised the dividend in July of your typical kind of April-May period for the raise after a moderate commodity recovery. I know there are many factors and the board ultimately sets the dividend. What's the key metric that’s your focus when you are looking at that decision and does it differ today at all because you are in a kind of bigger project ramp-up period? Thanks.

So I really think it's important to take a long-term view on the dividend and the outlook on cash and earnings over a longer sweep of time. So I think that is really morphed. Fundamentally the issue then will we happen to sit on our capital program at this particular point time. And I think it is fair to say that with what's happened in oil markets in the last six to nine months, there is a complete reshaping of what's going on, a rebalancing of what's going on. And I think it's reasonable to think that taking sometime to understand where things shake out for the long-term is a very important and prudent step. I don't want to get ahead of what the board's views on this might be, so I can't really comment any further. The dividend is very important to us. We want remain competitive on it. We pay attention to our yield, we pay attention to our payouts on earnings and our payouts on cash flows. We want to be competitive on this, we want to continue to grow it. So all I can say is, it’s got high priority and this is something that gets looked at every single quarter and profiles on out in terms of earnings and cash flows gets looked at every quarter by the board.

Great. That's fair. I appreciate that. And then a follow-up on the – particularly, congratulations on the Caltex sale. On the downstream, can you give us any idea of how you expect that asset sale, those assets sales have affected your returns in the downstream portfolio. So as we roll forward with international, I know it was in non-consolidated, but how they compare relative to the rest of your portfolio and how that portfolio may look absent Caltex? Thank you.

Yeah, so, I think you -- we should commented as it had a positive contribution, obviously, but I don’t think it’s going to be noticeable in any meaningful way. Its absence will not be noticeable in any meaningful way.

Okay, yes, fair enough, thanks.

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

Hi, good morning everybody, and Jeff, thank you for everything, it’s been a pleasure.

Thanks.

Can I just ask about the Neutral Zone again, how much did you see in for volumes in your targets for this year and for the 2017 3.1?

So, this year would have been in the neighborhood of what we produced in the first quarter here, which was around 76,000 barrels a day. We would have been anticipating a decline between 2015 and 2017 to something a little around 60, maybe 62,000 barrels a day in 2017.

Good. And so, Pat, you’re saying that basically that margins are so low there that regardless of losing whatever it is, 70 -- 60 -- 70,000 barrels a day, the financial impact will literally be minimal?

Yes.

Well, okay. That was the -- that was the volume question. Is there anything to add on the California downstream market and I’ll leave with that? Thanks a lot.

So, I think in California, we had the fortunate position of having high reliability at a time when the overall industry market was very tight and it was tight for a couple of operational reasons related to other industry -- other industry players. As those get resolved and I think one has been resolved and one is going to take a little bit longer to resolve, but as those get resolved and I think you would anticipate that the margins would move towards a more normal -- a more normal level. Of course, second quarter is typically a reasonable margin period because of gasoline demand pickup. So, there is seasonality factors there, but in general, I think it’s fair to say that the West Coast margin was impacted significantly here in the first quarter because of these industry factors and Chevron ran well, operated well and was able to take advantage of that.

Pat, it’s totally obscure, but I was wondering was that part -- was California part of the working -- why was the working capital movements so enormous in the quarter I guess is what I should have asked. Thanks.

It’s a good question. It was really a function. When you look at our working capital elements here, the biggest drivers really just related to a disproportionate movement in the way our accounts payable and our accounts receivables moved over the quarter’s period of time. Normally, when you are in a more stable price environment, then you expect whatever happens and your receivables and payables to offset. That did that happen in this particular period. And so, we had a net cash consumption of size related to accounts payable, receivables net and this is where I said and I feel very comfortable saying that we expect this to unwind as the quarters progress.

I guess what I’m driving at is, the history of that typically is the California operations have a lot of long distance crude, is that what we’re talking about here or is there dollar effect or something?

No, it’s not what we’re -- it’s not what we’re talking about and in the past, when we talked about, we’ve had working capital effects related to the California. In many of those circumstances in the past that has been related to the operations, the specific operations or lack of operations at Richmond. That is not the scenario that we’re talking about this year.

But I’m still not to why it’s so big, I mean, you say it’s payables, receivables type move, but I just wonder, is it the dollar or is it, what is it?

I mean, it’s just the rate of activity change between what’s happened on your revenue side and what’s happened on your cost side.

Okay, I will leave at that. Thanks a lot.

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

Hey, guys. First, Jeff just want to say thank you for all the help over the last couple of years and best of luck with your new assignment and Frank, welcome aboard to the IR lane. Pat, on the first quarter, the cost saving realization in the P&L, I think you mention talking about $600 million. How much of [indiscernible] in many of the area that you operate as much weaker than the US dollar, so as a result, in US dollar term, the cost is down?

So, your question is about foreign exchange, the 600 -- roughly $580 million.

No, I am not talking about the $580 million, which is related to currency translation. I am talking about the actual operating cost, because let’s say, you pay your employee in UK with the pound and then get translated into your US dollar, even if the cost base will remain the same in local currency in US dollar is much lower, so that’s the amount that I am just curious, how -- of the 600, how much is related to that?

So the – it’s really – they’re not related. I mean, our operating expense, the influence of foreign exchange on our operating expense is really pretty minimal through the quarter. It’s more significant in terms of capital spending, but on an operating expense base it has not – it is not a significant component that has led to the decline in operating expense between periods.

Interesting. So given that in many of your major operating area, the dollar have strengthened against their local currency, but is not much of an impact in USA?

That’s correct.

I see. Okay. All right, that’s fine. A final one that’s real quick, over-lifting and under-lifting in the quarter?

Yeah, we’re about 1.7% under-lifted for the quarter.

And Pat, at the end of the quarter, do you still under-lift or do you upper-lift or over-lift?

I don’t know, Frank. I just know for the quarter, it was 1.7% and I don’t know –

No, at the end of the quarter, Paul, it was – we were 1.7% under-lifted, that’s at the end of the quarter.

At the end of the quarter, okay.

And how about for the quarter your sales?

Within the quarter?

Yes, means that the quarter sales comparing to the quarter production, are we over-lift or under-lift?

I’ll have to follow-up with you that. Paul, I don’t have that number with me, but the 1.7% is the number that you should focus on.

Okay, perfect. Thank you.

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

Thank you. Good morning everyone. And Jeff, let me also say thanks to all your help. Welcome Frank. I got to say, I am optimistic on a better Q position with Frank. I want to see how it goes. On asset sales, you are two-thirds of the way through the $15 billion number. One can, you help thinking with maybe some upside yet again to that target. Could you frame for us how you’re thinking about that. And if could [indiscernible] this year. One of your competitors in your backyard in California seems pretty keen on asset sales, I am just curious on the other side of the ledger, if you have taken a hard look at bolt-ons to your existing California position? And then I do have a related follow-up.

Yeah, so we did just increase the target back in March moving to the $15 billion over the four years. We are only six weeks later than that approximately now. And even though the CAL sale is a significant transaction and we’re happy to have it behind us, I am not in a position to change the overall target. I feel very comfortable about our ability to conclude the $15 billion over the next year and a half or so that are remaining, actually it’s more than that, more than two and a half years, two and a half years that are remaining. So I don’t want to up that target, but I feel comfortable about our ability to hit that target in the timeframe that we have set. CAL will be booked in the second quarter, it was not a first quarter item. And then in terms of any sort of bolt-on activity, obviously we look at circumstances of assets and opportunities around the globe. We evaluate that all the time. I am not going to speak specifically about anything that’s under consideration or not under consideration. It has a pretty high hurdle is all I would say in order to move into our portfolio at this time. Any sort of additional portfolio move like that would have a pretty high hurdle because it would need to compete post acquisition for capital against the assets that we already have in queue.

I appreciate. And my follow-up is, I am afraid I am going to label the working capital issue, just to leave that more, if I may. My sense is at least when you have such a massive move than the oil price at least, a slow down on activity levels, the payables that you would have as a source of working capital, as you pay those, in other words, as cash goes out the door, the subsequent payables that would replace those would be substantially lower assuming your activity level was reduced. So, what I'm trying to understand is, where is your confidence or can you help us walk through why that after a such move in the oil price that working capital position would reverse out if your activity level is moved to a lower level, just your view on that. [ph]

Well, I think it's really the combination, I mean; I look at these on a net basis, right. I look at the movement in your receivables and the movement in your payables and as I say, as you get into a stable environment, any sort of price impact that you get, typically moves through both of those in a relatively synonymous way or a synchronized way. And so, when you’re in a discontinuous situation like you had in the first quarter, I think, when you get into a stable environment, if prices have come down, and cost structure has come down, then you get into a matching there, and so I think that is what I'm really trying to imply is that, as you move into that matching phase, that's where you will get the reversal and you'll return to a more normal relationship between receivables and payables.

Is that through the course of the year, Pat, or you would expect a more quicker resolution for that or is it going to kind of ramp higher or going to be balanced over time?

Accounts payable receivables, I would expect to begin reversing relatively quickly here. I think it's a trend, a change in the pattern that you will see in the second quarter.

Great, I will leave at that. Thanks very much indeed.

Thank you. Our next question comes from the line of Blake Fernandez from Howard Weil, your question please.

Folks, good morning and I would also offer congratulations to both Jeff and Frank. I had two questions, one, could you give an update on the recently formed JV you did in the Gulf of Mexico with Keathley Canyon, any status update or game plan as you kind of take over operatorship there?

Well, I think you know, I think I'd like to leave a lot of that for our second quarter here, because our plans are to have Jeff -- Jay Johnson on the line with us in second quarter, and I think we'll let the opportunities go there. But we're pleased with the joint development opportunity that we've got here, this really builds on our Anchor discovery and our Guadalupe discovery and it combines the Tiber and Gila discoveries where BP had success there and so we feel like it's a very good development opportunity potentially for hubs where you can get scale assets, economic assets and going forward, we have a lot of continuing appraisal work to do though. So I don't really want to say much more than that.

Fair enough, we can follow-up next quarter with Jay. The second question Pat is really kind of on the U.S. in particular, where we saw negative earnings, I guess, I viewed the Gulf and Permian as key growth areas where we would expect fairly high margins, I realized there were some impairments kind of one-off in the quarter, but you highlight DD&A being elevated, is it fair to believe that DD&A kind of remains at an elevated level until we book additional reserves over time? And if I could may be just sneak in a -- finally a follow-up on the Partitioned Zone. You mentioned the financial impact being minimal, I presume that applies to both earnings and cash flow, but if you could please just confirm that, I would appreciate it. Thanks.

Yeah, so just sticking with the upstream loss position, I think we have to look at what the driver was here for the loss position, obviously very poor realizations, only $43 a barrel and liquids realizations, gas overall was $2 in the quarter roughly. So, the significant decline in revenues. I talked about what's happening on our cost structure side of things but we're going to see the cost structure come down with lag effects, you're not going to see that in a first quarter period of time, so the cost structure is continuing to evolve and so first quarter again was not a particularly pretty picture from a margin standpoint. On depreciation, you're right, we are seeing elevated depreciation and you would expect that depreciation to remain elevated and particularly for some of our deepwater assets until we have time to do, we get response time and we can see what the full recoverable, we can document kind of the full recoverable opportunity of that development play is. And back on PZ, it is the same earnings and cash.

Great, thank you so much.

Thank you. Our next question comes from the line of Jason Gammel from Jefferies, your question please.

Thanks very much, hi everyone. Just wanted to come to the milestones that you've achieved in Australia over the course of the quarter. The first question related to the first gas into turbine at Gorgon, that's obviously a huge milestone, is that being accomplished with gas from your hydrogen [ph] offshore or you’re getting that from third-party sources and if it's not hydrogen, you still expect first gas somewhere around mid-year?

It's coming from domestic gas sources and yes, our expectation really is to have, we are on schedule for our Gorgon startup in the third quarter of this year and first gas, before the end of the year.

And do you mean, first commercial cargoes, is that –

First commercial cargoes, sorry.

Okay, great.

First LNG before the end of the year.

Got it. And then obviously another major milestone you achieved at Wheatstone with the top side placement, but I guess from a schedule standpoint, I would expect that the onshore has got the most potential for slippage, just from a risk standpoint, can you talk about where you are at relative to schedule in terms of the onshore at Wheatstone?

Yes. So we are on schedule for Wheatstone. Obviously, the installation of the top sides on the steel gravity structure was a major milestone. But we've got seven of 24 process modules, major process modules that have been delivered on site. The trunk line is installed and hydro tested. The dredging is complete, the piling activities are completed, the roofs are on both of the LNG tanks, so we continue to make good progress both onshore and offshore and I do encourage you to take a look at the pictures that are on the website, because you'll be able to see the progress there.

Okay. Very good. Thanks, folks.

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

Thanks for taking the question. As you are getting into 2015, presumably there was a lift of FIDs the company had on deck, are there any of those other than perhaps Kitimat that have been pushed out or suspended since January 1?

So, I would say the most significant, in fact the only really significant FID that’s on plan for this year relates to TCO and the future growth project and we continue to work that through to FID obviously, it's an opportunity for us to take advantage of a lower cost structure, so we continue to do more detailed engineering and work through the cost estimates of this, continue to work with our partners and the government on this, so our expectation is fourth-quarter FID on that one.

Okay, understood.

And in terms of the other FID projects, I mean part of the reduction that we took in our capital spending from 2014 to 2015 really did relate to the pacing of other major capital projects. Kitimat is a primary one there. We've moved that, I guess, I would say the spending on that out considerably. We are really only limiting ourselves here to appraisal work and continuing to look at the design and the cost structure of that. Indonesia deepwater development would have been another one. That has moved out. So there several other FIDs or pre-FID projects that we have pushed to see any monies into future years.

And if I can ask a follow-up about the downstream segment, you've been pretty vocal in the past about the frustrations with California policy on carbon emissions in particular, given the decision last week to extend those rules out to 2030, does that change your view about perhaps retaining any of the California refining assets?

Well, I would just say that we are in a very advantaged California position. We've got two very strong world-class -- very competitive assets at Richmond and El Segundo. We've got a very good market position, very good brand strength. So, it’s a quality asset that we have here and our expectation is that we will be able, over time, to work with whatever the regulatory framework is. At the same time, we do still think it's important to alert customers and alert government officials as to what the cost of compliance is for some of these programs. The AB32, the cap and trade portion, fuels under the cap came in to effect in January of this year and there are costs, new costs associated with being a refiner in the state as a result of that. Now, it does get passed on to consumers and so as that continues to move forward, then of course that cost increase could be something that consumers and regulators will be increasingly aware of.

Okay, I appreciate it.

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

Great. Thanks. Good morning, everybody and let me be one of the last to wish you good luck, Jeff, in the next assignment and welcome Frank. If I could just go maybe with a couple of specific ones, Angola LNG I think at the Analyst Day you updated, you expected it to come on stream during the fourth quarter of this year back on stream. Any update on progress there that was maybe a little bit earlier than some of our expectations and maybe what all did you end up having to do to the project to get it ready for this year?

Okay. So work is still underway, significantly underway and the overall plan is to still have Angola LNG restart with LNG to the tank in the fourth quarter of this year, probably late in the fourth quarter of this year and then begin to ramp-up to about 75% of capacity by the first quarter of 2015. As is common, the plant will run for a period of time and then ALNG will make a decision as to whether or not they need to take the plant down to perform any sort of shut down, drain removal, that kind of cleanup activity. And they all decide at that point in time whether or not they want to do that early in the first part of 2016. In any case, we would expect ALNG to reach maximum capacity in the second quarter of 2016 if they decide to do those drain removals.

Great. And I appreciate that. And then maybe just one general one, wondered if you can give couple of comments in your release, but I would appreciate any clarity as we've got varying views from different companies over in recent times. Any view on general product demand globally, both in the US and globally what you are seeing across your system? Any demand sort of weak or strong in different parts of the system as well?

I would say that going forward here and I'm thinking really globally here that product demand -- there are some leading indicators that would suggest the product demand as strengthening, I guess I would say modestly. And overall, probably have an overall demand profile for 2015 that would be somewhat stronger than 2014 from an oil consumption standpoint.

And in the US, I think in your release it said that the product sales were, I can’t remember, they were flat year-on-year versus 1Q14. Is that US gasoline, is that kind of same-store sales across your system or what number is that?

I'm not sure, which number are you talking, are you looking in the release itself?

Yeah. I think it said branded gasoline sales were essentially flat with 2014, is that – so I am guessing that's kind of the same-store sales?

Well, it really is networks, it's our total network sales. Total network sales. It's really just a function of our branded distributions, right. I mean, our network hasn't changed significantly between periods of time.

That's helpful. Alright. Thanks a lot.

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

Yeah, good morning.

Good morning.

I guess I would like to follow-up, it hasn't gotten much here this time around. Permian, kind of give us an update maybe what you are doing there, maybe your progression on rig count and then also how the cost deflation is flowing through there?

Okay. So our current outlook really for the Permian is to have about 21 rigs running. Currently in the March meeting we said it was something closer to 25. We expect to have about 325 gross wells this year. And that's down a little bit from what we said just a few week ago. Some of the reduction in the wells is due to a shift to horizontal drilling programs versus vertical drilling programs. And some of it also relates to joint venture arrangements what our joint development partner has reduced their activity levels compared to plans. We are transitioning more and more to horizontal work as opposed to vertical work. Horizontal wells obviously work better in this kind of a price environment. And I would just say that we are seeing very good well by well improvement in costs in each of these wells going forward. I think the cost reduction efforts are finding their way through to our overall drilling and completions cost, and we will be happy to give you a larger update, more in-depth update on our second quarter call.

Okay. And then the other question I had is we could get back to – it was chart 14, you talked about flexibility in your spending going forward. I didn’t catch the number, but I was just wondering if we should think about that as kind of – one, give us the number. Number two, can we think about that as ratable as we work through or is it very much going to be chunky as, for example, Gorgon gets going at the end of this year and obviously the CapEx drops off. And then how that may change the way the future FID process will work its way through as well?

Right. So the number that we provided between 2015 and 2017 is $8 billion cumulatively. And I think it’s reasonable for you to think about that as reasonably ratable. I mean, it does really depend and it is forced heavily by the Gorgon and Wheatstone spend follow-up. But I think for purposes of what you’re most likely doing I think thinking about it as being reasonably ratable make sense.

Okay. That’s it from me. Thanks, and Jeff and Frank, good luck in new ventures. And Frank, I guess we will be talking together quite a lot more.

Thank you.

Thank you.

Thank you. Due to time constraints, our final question comes from the line of Brad Heffern from RBC Capital Markets. Your question please.

Hey, good morning, everyone. Thanks for taking my questions. I was just wondering if you could talk a little bit about how cost savings that you’ve realized today have aligned with what was contemplated by your original CapEx budget, if you are seeking cost deflation happen more quickly than you would have expected. I'm just looking at the international CapEx number for the first quarter, hence down $2 billion, is that good cost savings or is that just normal inter-quarter [ph] volatility?

All right. So I would say in general, the cost savings that we are seeing and that we anticipate seeing would probably be somewhat stronger than what we had baked into our $35 billion budget. And that's really just a function of when we were doing the budget and what we were anticipating versus what we are -- we believe being able to secure going forward. I don't think you will have seen much of that in the quarter-to-quarter comparisons as of yet, so what you're seeing quarter-to-quarter comparisons really has more to do with the pattern of actual spending from fourth to first.

Okay, understood. And just thinking about that, if you prorate the first quarter for the full year, you are already below the $35 billion number. How should we think about the CapEx trajectory throughout 2015?

Yeah, I think you should think about it as being relatively evenly paced. The $35 billion target is what we expect to hit at the end of the year.

Okay, thank you.

Thank you. Ladies and gentlemen, this concludes Chevron’s first quarter 2015 earnings conference call. You may now disconnect. Good day.