Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron’s First Quarter 2014 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, this conference call is being recorded. I would now like to turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, 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 is Jeff Gustavson, General Manager for Investor Relations. We will refer to the slides that are available on Chevron’s website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. We ask that you review the cautionary statement on Slide 2. Slide 3 provides an overview of our financial performance. The company’s first quarter earnings were $4.5 billion or $2.36 per diluted share. Results are consistent with our earlier guidance, where we highlighted specific negative impacts associated with foreign exchange and selected asset impairments and related charges, which totaled approximately $500 million for the quarter or $0.26 per share. Return on capital employed for the trailing 12 months was 12%. Our debt ratio at the end of March was approximately 13%. Turning to Slide 4. Cash generated from operations was $8.4 billion during the first quarter. Cash capital expenditures were $8.5 billion. At quarter end, our cash balances totaled $16.2 billon, giving us a net debt position of $6.9 billion. On Slide 5, this week Chevron’s Board of Directors declared a $1.07 per share quarterly common dividend payable in mid-June. This represents an 8% annualized payout increase. Since 2004, we have grown the dividend by a compound annual rate in excess of 10%, which leads the competitor groups. In the first quarter, we repurchased $1.25 billion of our shares. In the second quarter, we expect to repurchase the same amount. We are committed to competitive, consistent and growing shareholder distributions. This demonstrates the importance we placed on balancing long-term investor return objectives, achieved through reinvestment in the business, with near-term return objectives achieved through distributions. It also reflects the strength of our balance sheet, our strong portfolio and our confidence in the cash generation potential of our growth projects. Turning to the next slide. We’ve incorporated two new slides into the presentation this quarter, which provide year-over-year comparisons consistent with our earnings press release. The first, shown on Slide 6, compares current quarter earnings with the same period last year. First quarter 2014 earnings were $4.5 billion, approximately $1.7 billion lower than first quarter 2013 results. Adverse foreign exchange movements accounted for $325 million or 20% of the overall decline. You’ll recall that foreign exchange movements for us are largely book translation effects with very little cash flow impact. Upstream earnings were down $1.6 billion. In addition to unfavorable foreign exchange impacts of about $225 million, the deterioration reflected lower crude oil production and liquids realizations and higher tax effects, DD&A and exploration expenses. Downstream results were essentially flat. And the other segment reflected the impairment of a mining asset, which resulted in an approximately $265 million absolute impact during the quarter, and was offset to a large degree by lower corporate expenses. Turning to Slide 7. I’ll now compare results for the first quarter of 2014 with the fourth quarter of 2013. First quarter earnings were $418 million lower than fourth quarter results. Upstream earnings were down $545 million, with adverse foreign exchange movements accounting for two-thirds of this decline. The timing of listings was the second significant contributor to upstream quarter-on-quarter deterioration. Downstream results increased by $320 million with nearly equal improvements noted in the U.S. and the international segments. The current quarter had favorable impacts from lower operating expenses, stronger chemical results and positive foreign exchange movements, all of which more than offset the adverse volume effects of a heavier turnaround schedule. The variance in the other bar largely reflects the impairment of a mining asset, partially offset by lower corporate expenses. Jeff will now take us through the comparisons by segment. Jeff?

Thanks, Pat. Turning to Slide 8. Our U.S. upstream earnings for the first quarter were $109 million higher than fourth quarter’s results. Higher realizations increased earnings by $130 million, mainly due to the rise in U.S. natural gas prices. Overall, liquids realizations also rose in large part reflecting crude pricing strength on the West Coast. Lower production volumes, primarily in the Gulf of Mexico reduced earnings by $50 million. The other bar reflects a number of unrelated items including the absence of year-end LIFO losses and lower exploration expenses, partially offset by higher DD&A. Turning to Slide 9. International upstream earnings were $654 million lower than last quarter’s results. Realizations decreased earnings by $50 million consistent with the decline in Brent prices between quarters. The timing of liftings across multiple countries decreased earnings by $235 million. Year-to-date, we are approximately 4% undirected, which as you know, should reverse in the coming quarters. Lower exploration expenses increased earnings by $190 million, mainly driven by fewer exploration well write-offs and overall lower geological and geophysical expenses across multiple locations. An unfavorable swing in foreign currency effects decreased earnings by $355 million. The first quarter had a loss of about $55 million, compared to a gain of $300 million in the fourth quarter of last year. The tax in other bar reflects unfavorable tax effects, many of which were non-income related. This quarter’s results includes several non-operational items mainly impairments which negatively impacted upstream segment earnings by about $150 million. Adjusting for these effects, our unit earnings for the quarter would have been approximately $20 per barrel. The reconciliation of non-U.S. GAAP earnings can be found in the appendix of this slide presentation. The upstream segment was also negatively impacted by FX effects in the timing of liftings, both of which are normally transitory in nature. Slide 10 summarizes the change in Chevron’s worldwide net oil equivalent production between the first quarter 2014 and the fourth quarter 2013. Production increased by 12,000 barrels per day between quarters. Major capital projects contributed 21,000 barrels per day, related to higher volumes at Angola LNG and the ramp-up associated with the Papa-Terra field offshore, Brazil. Shale and tight resources growth contributed 12,000 barrels per day driven by production increases from the Midland and Delaware Basins in the Permian, as well as continued production ramp up from the Vaca Muerta Shale in Argentina. The base business in other bar includes the impact of normal field declines and weather-related disruptions, primarily due to extremely low temperatures in Kazakhstan, partially offset by lower production downtime related to several assets. Slide 11 is the second to two new slides incorporated into the presentation this quarter, and compares the change in Chevron’s worldwide net oil equivalent production between the first quarter of 2014 and the first quarter of last year. Production was 57,000 barrels per day lower than the same period a year ago. Growing volumes from our shale and tight resources in the Permian and the Marcellus regions in the U.S. and the Vaca Muerta Shale in Argentina increased first quarter production by 37,000 barrels per day. Major capital projects contributed 23,000 barrels per day, driven primarily by production growth from Angola LNG and Papa-Terra in Brazil. Production was impacted by external constraints related to the very cold temperatures in Kazakhstan, as well as lower demand in Thailand, due to a lighting strike which damaged a customer’s gas processing plant in the third quarter of 2013. The base business in other bar includes normal field declines along with other unrelated impacts. Our base decline rate averaged less than 3% between quarters. Turning to Slide 12. U.S. downstream results increased $157 million between quarters. Planned turnarounds at our Richmond, California and Pascagoula, Mississippi refineries lowered volumes and decreased earnings by $85 million compared to last quarter. More than offsetting these volume effects were benefits from lower OpEx worth $95 million and stronger chemicals results worth $80 million. Stronger U.S. chemicals results reflected higher margins for benzene, olefins and polyolefins from our Chevron Phillips Chemical joint-venture. The other bar reflects a number of unrelated items, primarily higher gains on midstream asset sales, partially offset by modestly lower realized margins, particularly on the West Coast, reflecting weak seasonal demand. Moving to Slide 13. International downstream earnings increased $163 million between quarters. Reduced volumes from turnarounds at our Thailand and South Africa refineries decreased earnings by $75 million during the quarter. Stronger Asia R&M margins improved earnings by $70 million. Increased demands drove refining crack spreads higher particularly for low gas and fuel oil. In addition, favorable price lag effects improved marketing margins. Lower operating expenses increased earnings by $85 million, about half of which is related to fuel costs. Reduced foreign exchanges losses contributed about $70 million to earnings. The first quarter had a loss of $28 million, compared to a loss of $96 million in the fourth quarter. The other bar includes a number of unrelated items, including higher chemicals results partially offset by the absence of positive year-end LIFO inventory effects recorded in the fourth quarter. With that, I’d now like to turn it back to Pat.

Okay, Jeff. Thanks. Turning to Slide 14. We hosted our security analyst meeting in early March, where we provided a comprehensive update on the company’s performance, projects and future growth prospects. At that time, full information was not available for some of the competitor comparisons. It is available now and the segment return on capital employed updates are shown here. Our upstream return on capital employed for 2013 was just over 17%. We have led the direct peer group for three years. In addition, our returns in 2013 were nearly twice the average returns of the larger E&P group and 3% higher than the very best company in that group. This speaks to the strength of our portfolio and is especially impressive considering our current levels of reinvestment, which we expect will generate peer-leading volume growth going forward. Our downstream return on capital employed turned to lower in 2013, consistent with the rest of the industry. We delivered a 10% return and held the number two rank in the peer group, our sustained position for the last four years. Turning to Slide 15. An updated information on 2013 upstream cash margins. During 2013, with the $38 per barrel cash margins, we were the best in the peer group by over $10 per barrel. We continue to post the highest realizations in the peer group. Our oil weighted portfolio is providing us with a lasting relative advantage. We’re also competitive on operating costs and have made sound investment decisions, both of which support our strong cash margin positions. Over the past four years, the movement in our cash margin relative to the competition has been remarkable, as shown on the chart on the left. While we’ve gained $15 per barrel in cash margin, our peers have gained only $8 on average. Importantly, we expect to maintain or even increase our cash margins going forward. At our analyst meeting, we used a Brent price of $110 per barrel as the basis for our forward cash flow and production projections. We have received a number of questions around the selection of the $110 per barrel price, and I want to be clear that this is not an internal price forecast, but is simply the actual average Brent price over the 2011 to 2013 time period. Using prior year’s actual pricing is the same methodology we have applied for several years now in our analyst presentations. At this historical three-year average Brent price of $110 per barrel, our cash margin is expected to increase to over $40 per barrel later this decade. This is a critical part of our value proposition, as the combination of strong volume growth and an accretive cash margin is expected to drive significant growth in our cash flow from operations over the next several years. Turning to Slide 16. I’d like to provide a brief progress update on some of our major capital projects and other growth opportunities. These are laid out across three growth themes: deepwater, primarily in the U.S. Gulf of Mexico; LNG, in particular, our two large Australian projects; and shale and tight resource areas, most notably the Permian Basin in the U.S. and the Vaca Muerta Shale in Argentina. Starting with the deepwater. As noted last month, the Jack/St. Malo platform was moored in a title location earlier this year. We continued installation and commissioning activities including final testing of flowlines and export lines. The project is on-budget and is on-track for late startup in the fourth quarter of this year. For Tubular Bells, which is operated by Hess, hook-up and commissioning is nearly 40% complete and startup is expected before year-end. We also made significant progress at Big Foot during March. The oil export pipeline has been installed and we are preparing to let the drilling module to the top sides later this month. We expect startup to occur mid-2015. Moving onto our LNG project. We continue to make excellent progress at Gorgon, which is now, through April, 80% complete. The final two gas turbine generators have been installed and additional progress has been made on the LNG tanks, jetty and other related infrastructure on the island. All major 2014 milestones are on track and we expect plant startup and first gas in mid-2015. For Wheatstone, we are now at 33% complete. Progress continues to be made at the plant site on the Wheatstone platform and with the offshore development drilling campaign. Wheatstone remains on track to startup in late 2016. Gorgon and Wheatstone are critical contributors to our future growth plans and we are pleased with the study progress being made on both of these projects. As in prior quarters, we have posted updated photos of both projects on our investor website. I encourage you to take a look. We also continued to make progress on our shale and tight resource developments, which nicely complement our large major capital projects. We have an active drilling and development program in the Permian Basin and we have drilled over 120 wells so far this year. We continue to focus on capital and execution efficiency, as well as the identification of sweet spots throughout our extensive acreage position in both the Midland and Delaware sub basins. We are also making steady progress in the Vaca Muerta Share in Argentina, progressing this year’s development program, and we recently signed additional agreements for incremental explorations acreage in the play. On Slide 17, I also like to touch on additional progress made elsewhere. We reached final investment decision and received approval from the U.K. government to proceed with the development of the Alder Field in the Central North Sea. We achieved first projections in the Chirag Oil Project in Azerbaijan and acquired new exploration acreage in Myanmar. In the downstream, we achieved mechanical completions of our new base oil facility at our Pascagoula, Mississippi refinery. Once fully ramped up, this increases our capacity and premium base oil by over 70%, making Chevron the largest premium base oil producer in the world. In addition, Chevron Phillips Chemical 1-Hexene project as well as Oronite Singapore Expansion project recently achieved mechanical completions. Lastly, CPChem started construction on its new Gulf Coast Petrochemicals project, which capitalizes on advanced feedstock source from shale gas in North America. This project is expected to startup in 2017. Now, that concludes our prepared remarks. I appreciate you listening in this morning and your interest in the company. We’re now ready to take some questions. Please keep in mind that we do have a full queue, so try to limit yourself to one question and to one follow-up if necessary. We’ll do our best to get all of your questions answered. Jonathan, I’d ask that you open up the lines for questions.

(Operator Instructions) Our first question comes from the line of Evan Calio from Morgan Stanley. Your question please.

Hi, good morning.

Hi Evan.

Pat, thanks for the comments on the impairment, as it clearly affects a clean comparison of your quarterly upstream profitability. I missed it. I know you’ve identified $400 million to $500 million of upstream impairments in your reconciliation. I see $150 million. And I thought I heard you mention $265 million. Can you just talk me through those numbers once again please?

Sure. The interim update we’ve talked about a total of $400 million to $500 million in additional negative charges. And that included foreign exchange and impairments, but we did reference strongly in that total the mining component. That mining component is $265 million.

Okay.

And then in the appendix slide that you’ll see, there is also $150 million worth of upstream-related impairments in the international segment.

I see, I got you on the total. Thanks. And I guess my second question, just your net debt increased. It was at $3.2 billion in the quarter, smaller capital increase. I mean I know you intent to bridge to 2015 and beyond when productive capital begins to drop and cash flow from new projects commences. Where do you see the debt limit? Is it at AA level, at the mid 20s, and then what type of commodity price cushion do you forecast in crossing that bridge and maintaining current shareholder distributions? Thanks.

Okay. Evan, I think you referenced several questions there and we had a couple of really important words in there. One you talked about bridging. That is an important concept for us. Our free cash flow was essentially neutral in this particular quarter. And you’re right, so net debt did increase and that reference that’s related to distribution to shareholders. We’re very comfortable with that pattern. It’s a pattern that we’ve had for the last few quarters. It’s the pattern that we could see continuing on here in 2014, and then when we get into 2015 and you begin to see these volumes pick-up and the cash flows pick-up, then we get into a different state. We do want to maintain the AA credit rating. We have a lot of room between where our debt level is today at 13% and what would be necessary to even call that into jeopardy. And by a lot, I mean several billion dollars worth of additional borrowing capacity. We do test our own plan against a low priced environment. And I can tell you that against the low price environment, even continuing on with the capital program that we have, we are very comfortable with the distributions that we’re making, even in a low priced environment and maintaining the AA.

Can you just share what that low price means?

No, we don’t want to go that far. Don’t want to go that far. So we do look at the overall capital position and financial position of the firm. We test it against the oil prices and we feel comfortable and look where we are. The other thing I would mention is that we do have – you’ll recall from the March presentation, we are anticipating assets of proceeds of $10 billion over the next three years.

Right. I appreciate. Thanks for taking my questions

Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question please.

Yes, good morning, and thanks for the extra disclosures in the presentation. Just a question on cash flow, I mean I think capital you said that $8 billion. It’s been running higher than that and volume is flattish in the macro environment and you’ve shouted out under-lifts and some extra tax but where there any other things that may have contributed to a slightly lower cash flow this quarter?

Nothing of any substantial nature. It was not – I mean with the under-lifting circumstance, it is not a particularly strong U.S. downstream quarter. So I think there are some operational factors that really lead to the $8 billion cap generation, $8.4 billion.

Good. Thanks very much. And then Gorgon, you’ve said 80% complete. You’ve obviously just had the Analyst Day and said mid-2015, other people – perhaps even partners are saying perhaps more later in the year, sort of 2016. I don’t want to get into a debate that, he said, she said, but what’s the critical path that you think in terms of getting Gorgon up mid-2015? What are the risks that you’re now worried about as you get further into the final stages here?

I think we have 20 of the 21 critical process modules for Train 1 and the infrastructure, the common facilities infrastructure on the island. The remaining train is due shortly, will arrive shortly. So it really becomes a process of the hook-up and commissioning. And I think that is – we’ve just come through kind of weather period. So we’re moving into good weather. And so I think weather continues to be a risk. And I think labor productivity continues to be a risk, but both of those, I mean those are aspects of this project that we have been managing now for 4.5, five years. And so those are clearly on everybody’s minds at in terms of managing through this. And I want to reiterate that the project is on track. We’re aiming for and targeting that mid-2015 startup.

Thanks very much.

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

Hi, good morning, Jeff and Pat. If I could, kind of a big one and the small one. The big one is, you have an interesting number, Pat, which is on productive capital. Could you update us on that number and talk a little bit about how you calculate the number so that we can perhaps use it to compare with other companies? And the follow-up is on Vaca Muerta and I’ll ask you that due course. Thanks.

Okay. Well, basically we just look at – it really is just assets under construction, I mean definitionally. It’s assets in our work in progress account as a percentage of our total capital employed. And the information that we provided back in March suggested that we’re at pretty high level, predominantly because of the LNG projects that we have underway, as well as the couple of Gulf of Mexico deepwater projects. And we indicated that we saw that stepping down significantly over the next three year period of time. And I also said verbally that we saw pretty important stair steps going from 2013 to 2014 and again to ‘15 and ‘16. We didn’t give actual numbers, I don’t really want to do that, but that pattern that was on our slide back in March is still one that we hold to. So as you see these projects come online, they move out of that WIP account, that work-in-progress account into a producing asset account.

My other question was that there was an actual numbers on productive capital. And I guess if you could update us on capital employed or at least the last available number?

Well, year-end capital employed was about $171 billion. And what we – right, so the information we gave in the slide was a three-year average there.

Okay. And what was the unproductive number?

So Paul, the three-year average ‘11 to ‘13 was in the low 40% range.

Right.

Moving down to the mid 30s range for ‘14 to ‘16, but that’s the average ‘14 through ‘16, steps down each of those – in each of those years our historic average here maybe the high 20s.

Yes, that’s right. So it was percentages around corner [ph].

It was percentages. And we use the averages and you should – I think it’s fair to say that 2011 was the lowest of the three years. 2012 was the middle of the three years and 2013 was the highest of the three years, but the three-year average there was at low 40s. And then what we’re saying is ‘14, ‘15 and ‘16 will reverse that pattern.

Yes, understood. Okay. That’s helpful on that calculation. And then if I can, can you do a little bit more to strip out Argentina. You’ve kind of bundled it with Permian.

Okay.

And you plan to wish that still acquisition growth as opposed to organic growth? Thank you.

Yes. Well, so I think that in terms of the Vaca Muerta play itself, we’re continuing to make progress there. Our plan is to drill about 140 wells. This year we’ve got about 17, 18 or 19 rigs drilling at this particular point in time in production there. On a growth basis is about 17,000 barrels a day. We’re encouraged by the well we’ve built, both on cost and productivity, but there is still – its early days. There is still a long way to go but we’re encouraged so far.

Okay. I think I’ll take it offline on rig count in terms of volumes year-over-year. You’re just obviously saying that on the variance you’d bundled Vaca with Permian.

I see. I misunderstood the question.

No, thanks for the answer. Absolutely, that was just the follow-up really.

So year-over-year, Paul, we haven’t booked production in the first quarter of last year. We started booking production in the fourth quarter. So there is a contribution fourth quarter to first quarter but over quarters. I mean it is acquisition related, but if you want to talk more specifically about it just talk me offline.

Sure. Thanks, Jeff. Okay, thank you.

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

Thanks. Good morning, Jeff and Pat. I’ve got also the one big and one small one, if that’s okay. On the impairments part, is that the reason for the high DD&A number, and if so, can you give us an idea of what the run rate should be?

It certainly is a contributor to the high DD&A rate. Absolutely that’s a factor. And in terms of general DD&A, I think that it’s fair to say that overall quarter DD&A is going to go forward, move up. Our expectation would be they would move up in 2014 relative to 2013. And we think opportunities in acre bell [ph] rising for the next couple of years, but then flattening out overtime. The patterns on both the absolute and the per barrel is something that you would absolutely expect because of recent investments and our future investments that obviously is also impacted by reserve ad timing and the mix of our projects etcetera. PPC or pre-productive capital as we talked about is going to come down. So I think the thing you’ve got to keep in mind here too is that for these investments, there is evidencing itself and will evidence itself in our DD&A rate. We are giving the investments audience to the largest growth rate of the peer group. A 20% growth rate in volumes between now and 2017. So a significant investment, so generating significant volume growth.

Thanks. But I’ll take the specifics on DD&A offline with Jeff if that’s okay. My follow-up is really your last point, because I think the growth and the cash margins really actually fairly well understood. What simply we’ve observed over the years is that not really gets paid by the market when it’s accompanied by strong debt adjusted tools if you like, so the balance sheet is not expanding at the same time. So I’m just kind of curious, when you look at your – you say you’re absorbing the best 20% growth, how do you think about the trade-off that’s $10 billion annual run rate on the balance sheet? And I’ll leave it there. Thanks.

So I mean I guess I think that if you’ve got the project queue, a slowing project queue and you’ve got a balance sheet that allows you to invest for that. And we do have a balance sheet. In fact you could really argue that for years we were under-levered relative to what might be optimal. So if you’ve got this strong project queue and if you’ve got the balance sheet to support it and the projects are value-accreting for the organization, for the firm, then I think that’s exactly the kind of investment profile you ought to be undertaking.

All right. I appreciate your answers. Thanks Pat.

Thanks.

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

Hi guys. Good morning.

Hi Paul.

I don’t know whether you want to answer that. I think a lot of people are asking that for CPC your joint-venture, strategically is there any particular reason you need to owning that so that you can have synergy with your other operations, if not, if you look it as a financial investment, does it makes sense for you to only minority interest and put it up as a publicly traded entity together with your partner Phillips 66 and putting into the market so that you can recognize a much higher value given right now that you’re trading at higher multiple than say both your partner and yourself?

Yes, so I understand the question there. And I’ll just start back with, when we put the two companies together, we had too I guess I would say sort of the meddling performing chemical companies, if we put them together. And it’s been a wonderful marriage. The partners are very much aligned on how to run this business, where you extract value from this business. And so it’s a joint-venture that has worked very well and has been very successful, so we’re very pleased. So, there no catalysts that’s out there necessarily to say that we need to be doing something different. It is the part of the portfolio that has growth opportunities available to it. And we appreciate that, with this change in the U.S. gas production and advantaged feedstock opportunities here. I think CPChem calls on the technical expertise of both of its parent company and we’re able to and happy to assist them in that capacity. We think it fits nicely in our portfolio. It has – the chemical business is highly, highly cyclical, more so than our portfolio. And so we’re able to withstand the adjustments that are there, we think that’s an advantage as well. So we are really seeing that there is huge catalyst for us to do something different. And it’s not always clear that the PE multiples in these petrochemical commodity companies are always trading at multiples better than ours. So we like the joint-venture. We think it’s well run. We’re happy to assist and its growth projects and providing expertise and technical capability where we can. We’re very satisfied with it, and I dare to say that our joint-venture partner will be feeling much the same.

Okay, very good. Second question, can you give us a quick update where the Angola LNG going out, I just wondering you had 50% capacity. And also in the Permian with the 25 rigs, do you have a number that how many of them is currently running in the conventional and whether [indiscernible] already? Thank you.

Okay, let me start with Angola and then you might to help me again on the second question. So on Angola, we did have recently a technical issue pop-up. We had a piping failure, which did result in an unplanned interruption to production. There was no fire. There were no injuries. It was a pretty localized damage. It was associated with the flare system. We are doing a root cause investigation and in fact that root cause analysis should be completed within a few days here is my understanding. So the plant is currently shutdown and we’ll need to take a look at that root cause analysis to understand what the go-forward operating plan looks like. That failure occurred sort of mid-April, early April, and it therefore was not an impact in the first quarter results.

Permian, the 25 rigs. How many of them is in unconventional drilling and of which how many of them is in the pad drilling already?

Okay. So all of the 25 rigs in the Permian right now are in the unconventional. We have only one rig drilling in the conventional. And I think you’re asking about pad drilling?

Yes, correct.

I don’t have information on that specific at this point, Paul.

Thank you.

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

Yes. Hi guys. Thanks very much. Sorry about this, but can I get back to the impairments and asset divestments you put in the reconciliation back. Because I didn’t understanding some of the stuff you talked about earlier. You got $150 million of E&P impairments. It looks like in the first quarter, and also $100 million gain on dispositions. I think you also got this mining write-down as well. If you just put those together for me again?

Sure. So let’s start with the biggest element, which is the mining element. We have a molybdenum mine in New Mexico. And the impairment charges that we talked about there and other related charges that I talked to at the very beginning, the $265 million relates to that. That asset from a segmented reporting basis is in our other segment. In upstream, we noted a $150 million of impairments. It’s in the international sector for us. So these are assets where we feel there is better opportunity in other portfolios basically. And then the third element that was noted there was a asset sale gain. This was in our “midstream sector”. It’s really pipeline-related and that showed up in the downstream external segment.

Okay. Thanks very much. And secondly was, is it possible to update us on when we’re likely to see the Tengiz hit [ph] to FID?

Our targets for this year – our target is to have that towards the end of the year. I don’t really have any additional information at this point. We were successful in getting the MoU signed back in the later part of last year, which really is a stage setting document to get all the partners aligned on the go-forward process. And so, we’re in the process now of going through and working the cost estimates etcetera, etcetera. So all I can say is towards the end of this year.

And we should expect a kind of overall CapEx – growth CapEx for this project, and along the line just some of your major things you’re doing in Australia. Is that correct, or is that kind of ballpark, right sort of number?

Well, I’m sorry. So I’m sorry, TCO is Kazakhstan, right. I guess one last thing there on TCO. The FID is not kind of critical path. What was the question on Atyrau, I didn’t quite understand?

Sorry, I just want to get an overall ballpark on Atyrau, what the overall cost estimate of the future growth project is going to be? Is it in the same ballpark as what you’re doing in Australia?

I see, Iain. We don’t have an updated – we don’t have a cost estimate until we go to FID. So that will be later and attached to the FID timings.

All right. Thanks Pat.

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

Thanks, good morning. First question on Jack/St. Malo. You said that it was moored on location. I just want to understand a little bit, how much sort of wiggle room do you guys have from now to the startup to get that project going, and if there is an active hurricane season, have you built in that sort of weather into the startup and end of the year for that project?

Well, it’s my understanding that when we’re putting these facilities out in the Gulf of Mexico, we do as much weather proofing as we possibly can. Obviously, when you’re investing at the size of these facilities, that’s an important consideration. So clearly having it moored is an important step. And so our expectation is that we would be able to handle any weather complications that might arise.

Okay, fair enough.

Can I just to add, Faisel too.

Yes.

If there are hurricanes, you have to demobilize. If the folks that are working on it, that could slow things down a little bit, but we don’t – it’s hard to estimate what’s going to happen there.

I guess I’m just trying to understand if you guys have sort of incorporated that into your guidance of the startup?

In a general sense from a planning standpoint, we always do factor in Gulf of Mexico weather activities to a degree, right. But each year is a difference degree, you know what I mean.

Sure.

So there is obviously a base load that we include in our plans, yes.

Okay. That’s fair. I understand. And then just on the under-lift, you guys talked about the sequential quarter-over-quarter charge of $235 million. Is that also fair to say that that’s the absolute number too?

So I’ll give you the absolute for the quarter is about $100 million, about half of that. So the rest of that is swing between the two quarters, Faisel.

Okay, got you. Thanks. I appreciate the detail.

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

Thanks for taking my questions. You’re obviously talking a lot more proactively about the Permian, presumably you’d like to get more value for that asset. Have you considered any kind of financial engineering solution that might unlock that value, more so than simply as one piece of your U.S. portfolio?

Well, we think we actually try for sitting in, kind of in the catbird seat in terms of the acreage position that we’ve got, the long standing acreage position we’ve got, the royalty advantage that we have there. We have done joint-ventures, of a kind of – with for example, Cimarex, where we have partnered with similarly situated partners. And those kinds of things you could see us continuing to do on a go-forward basis. If you get commonality of infrastructure and location and you can get efficiencies of drilling where that you’re fracking can really go from our property to their property. So we will continue to look for those opportunities for synergies. We’ve got a very active program scheduled for this year. It’s over 500 wells. And 25 rigs, we’ve done 120 drilling so far. So the activity level is at or perhaps little bit better than planned at this point. So we’ll continue to look for opportunities like that, but we’re proceeding had on our own as well.

Okay. And just quickly, can I get an update on the exploration program in Liberia? I haven’t heard about that in a while.

Yes, we’re not in a position to say anything more at this point.

Okay. Fair enough, thanks.

Thank you. Our next question comes from the line of Guy Baber from Simmons & Company. Your question please.

Thank you all for taking my question. My first one was on the 2014 production guidance, but understanding it’s still very early in the year, just wanted to get a sense of how confident you guys are in the guidance right now, just considering some of the weather influence that you’ve got in 1Q, the unplanned downtime at Angola LNG, and in 2Q and 3Q typically being heavier maintenance course. Just wanted to better understand how you guys are feeling about that internally and any cushion you might built-in into the guidance?

Okay. That’s a good question. I guess I would just start by saying the year is young. We’ve only had four months or three months in here. There have been some positive. Jeff mentioned a figure about base business declines being at the 3% or little bit less than 3% level. So that’s a very good positive. One thing we haven’t mentioned of a positive nature is at Frade, we now have 10 producing wells on and we continue to make progress to bring on additional wells there. We talked about the Permian ramp ups and the Vaca Muerta ramp ups that are occurring. So those are all working in our favor. Clearly weather has been a negative for us in the first quarter. On an absolute basis, we would estimate that that was worth 20,000 barrels a day or so absolutely negative in the quarter. I mentioned the A-LNG operational issues that we have there. So you put those altogether, you got some pluses, you got some minuses. And the back-end of the year, we’ve got Tubular Bells and Jack/St. Malo, both of which are scheduled to come online, so our production ramp ups are kind of back-end loaded. And both of those projects are on track. So the best I can say is, and I’ll go back and say, we built-in weather contingencies in our Gulf of Mexico plan in particular, for a base load amount. I’ll just go back and say the year is young. We’ve got positive and negatives out there. We feel that the guidance that we gave, the $26.10 is the best guidance that we have at this particular point in time. And as we do every year on the second quarter, we’ll update you with how things look at that point in time.

Okay, great. Thanks for that. That was very helpful. And then my follow-up was on, one of your three primary growth themes of deepwater. And I’m more focused on your next generation of projects looking beyond the near-term startups that you have lined up, if we start thinking about look at your reserve additions and then longer term growth potential, but you all have a number of potential FID this year, which you have an interest in, I think Stampede and then you’re Indonesia development at Bangka, and then you’re also reevaluating Rosebank. So understanding that every project is unique, how would provide some more commentary on just how conducive the overall environment right now is to pushing forward deepwater FIDs just in line of your view of the cost environment and the evolution of project economics and what you might see as opportunity for cost savings. Just given what’s generally appears to be a more disciplined approach to screening these projects for you all and with some of your peers?

Okay. Well, I think I would say if I step back and look at deepwater, I think for Chevron portfolio you mentioned a number of projects, but I think the most strategic basin continues to be the U.S. Gulf of Mexico. And we’ve got number of wells drilling now and we’ll have additional wells drilling over the next 12 to 18 months, a significant number of them, six wells in the next 12 to eight months. So that continues to be an area of strategic focus. And we think we’re competitive there on facility structure as well as drilling costs, completion costs. So that’s important area for us. If I look at IDD. IDD is a complex project. It’s multiple fields. And right now we’re in a position of waiting for government approvals. And then on Rosebank, we did really with the operator kind of put that – as the operator put that into a recycle mode, because the cost that had come through we’re really didn’t make it compete for capital within our portfolio. So that’s somewhat in a recycle mode. So I think the overall impression that you have about the industry stepping back and taking a look at the cost run up for some of these resource place relative to the value capture, I think some of that is being reassessed as you indicate, Rosebank is a good example of that.

Okay, thank you.

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

Yes, good morning.

Good morning, Roger.

I guess to come back to the Permian a little bit, if I understood correctly, you were not or have not to this point drilled any horizontal wells in the Midland Basin. Was that accurate?

We are looking to spud the first one later on this year.

Okay. So thinking about how production from the horizontal wells is typically been a little more, let’s say higher IP rates so that. We should think about the shale and tight production accelerating, I don’t know, call a Q4 certainly into ‘15. Would that be consistent with how you’re looking at things?

So I think it would be fair to say that if you go forward and you look at quarter-after-quarter-after-quarter improvement, we would be looking to see improvements kind of quarter-after-quarter. Our real focus has been on getting capital efficiency, maximize and getting a strong execution of business being well. So it’s really been on optimizing the value creation. And so we’ve been spending time to understand where the best areas are. And what the most efficient rigs had and overall development plan is. Frankly, a lot of the other producers there have been allowing us to de-risk did play by the work that they have done and that’s in a sense advantageous to us. And we think we can get overtime the same kind of synergies and efficiencies that the smaller operators have. And one of the slides that we have put out in the security analyst meeting gave a good indication of what we see as year-on-year net production increases in the Permian Basin. And at the pretty significant growth rate, we also talk to essentially doubling of our rig count over the next several years from where it is currently.

All right. Well, I guess we now have a couple of quarters here where you’re breaking out shale and tight from everything else, so start to get a feel for what the quarter-over-quarter year-over-year performance is.

Exactly.

So just want to make sure I was understanding the way it should progress here.

Right. And we’re hopeful for quarter-on-quarter improvement going forward.

Good. I guess my follow-up question, the Angola LNG obviously going to be offline in terms of volume contribution in the second quarter for some significant period of time, but if you think about – and I know, sometimes you don’t get too granular, but the impact on it from a cash flow standpoint. I mean was this operation given the troubles it’s had so far actually contributing much or should we think about it as mostly a production impact but not a problem for cash flows as we look in the next couple of quarters?

Yes, I think you will see – it will be more noticeable clearly in the production side than the cash flow side clearly. And I don’t have – as I mentioned, we need to have the root cause analysis done before we have an indication of when – what that repair and maintenance – repair activity will look like, and how long that will take and then when we might get back to a producing mode.

Okay. I’ll leave it with that. Thank you.

Thank you. This does conclude the question-and-answer session of today’s program. I’d like to hand the program back to Pat Yarrington for any further remarks.

All right. Thank you, Jonathan. I guess we got through everybody’s question. So I appreciate your time and interest today. I especially want to thank all the analysts on behalf of all the participants for the questions that they asked in this morning’s session. So Jonathan, I’ll turn it back to you and thank everybody. Have a good day.

Thank you. And thank you ladies and gentlemen. This does conclude Chevron’s First Quarter 2014 Earnings Conference Call. You may now disconnect. Good day.