Good morning. My name is Jonathan. I will be your conference facilitator today. Welcome to Chevron's first quarter 2014 earnings conference call. At this time, all participants are in listen-only mode. After the speaker's remarks, there will be a question and answer session. Instructions will be given at that time. If anyone should require assistance during the conference, please press star then zero on your touchtone telephone. 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'll 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 two. Slide three 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 four, 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 billion, giving us a net debt position of $6.9 billion. On Slide five, 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 group. 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 place 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-on-year comparisons consistent with our earnings press release. The first, shown on Slide six, 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 realization 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 approximate $265 million absolute impact during the quarter and was offset to a large degree by lower corporate expenses. Turning to Slide seven. I'll now compare results for the first quarter 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 liftings was a second significant contributor to upstream's 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 eight. 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 nine. 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% under lifted, 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 and other bar reflects unfavorable tax effects, many of which were non-income related. This quarter's results include several non-operational items, namely 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 and 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 and 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 of 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 2014 and the first quarter 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 U.S. Permian and the Marcellus regions 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 lightning strike, which damaged the customer's gas processing plant in the third quarter of 2013.
The base business and 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 mogas and fuel oil. 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 exchange 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. 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 trended lower in 2013, consistent with the rest of the industry. We delivered a 10% return and held a number 2 rank in the peer group, our sustained position for the last four years. Turning to slide 15, updated information on 2013 upstream cash margins. During 2013, with a $38 per barrel cash margin, 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 position. 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.
We have 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 years' 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. 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 its final location earlier this year. We continued installation and commissioning activities, including final testing of flow lines and export lines.
The project is on budget and is on track for late start-up in the fourth quarter of this year. For Tubular Bells, which is operated by Hess, hookup and commissioning is nearly 40% complete and start-up is expected before year-end. We also made significant progress at Bigfoot during March. The oil export pipeline has been installed and we are preparing to lift the drilling module to the topsides later this month. We expect start-up to occur mid-2015. Moving on to our LNG projects. 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 tank, jetty and other related infrastructure on the island. All major 2014 milestones are on track, and we expect plant start-up 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 start up in late 2016. Gorgon and Wheatstone are critical contributors to our future growth plans, and we are pleased with the steady 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 continue 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 shale in Argentina, progressing this year's development program. We recently signed additional agreements for incremental exploration acreage in the play. On slide 17, I'd 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 production in the Chirag oil project in Azerbaijan and acquired new exploration acreage in Myanmar. In the downstream, we achieved mechanical completion of our new base oil facility at our Pascagoula, Mississippi refinery.
Once fully ramped up, this increases our capacity in premium base oils by over 70%, making Chevron the largest premium base oil producer in the world. In addition, Chevron Phillips Chemical's 1-hexene project, as well as Oronite's Singapore expansion project, recently achieved mechanical completion. Lastly, CP Chem started construction on its new Gulf Coast petrochemicals project, which capitalizes on advanced feedstocks sourced from shale gas in North America. This project is expected to start up in 2017. 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.
Thank you. Ladies and gentlemen, if you have a question at this time, please press star then one on your touch-tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. If you're listening on a speakerphone, we ask that you please lift your handset before asking your question to provide optimum sound quality. Again, if you have a question at this time, please press star then one on your touch-tone telephone. Our first question comes from the line of Evan Calio from Morgan Stanley. Your question, please.
Hey. Good morning.
Hey, Evan.
Hi, Pat. Thanks for the comments on the impairment as it clearly affects a clean comparison of your quarterly upstream profitability. Maybe I missed it. I know your interim update identified $400 million to $500 million of upstream impairments. In your reconciliation, I see $150, and I thought I heard you mention $265. Can you just talk me through those numbers once again, please?
Sure. The interim update did talk about a total of $400 million-$500 million in additional negative charges, and that included foreign exchange and impairments. We did reference strongly in that total the mining component. That mining component is $265 million.
Okay.
In the appendix slide that you'll see, there's also $150 million worth of upstream-related impairments in the international segment.
Oh, I see. I got you. I got you on the total. Thanks. I guess my second question, just net debt increased to $3.2 billion in the quarter, small working capital increase. I know you intend to bridge to 2015 and beyond when productive capital begins to drop and cash flow from new projects commences. Yet, where do you see the debt limit? Is it at double A level at the mid-20s? 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, you 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, you're right, net debt did increase, and that's related to distributions to shareholders. We're very comfortable with that pattern. It's a pattern that we've had for the last few quarters. It's a pattern that we could see continuing on here in 2014. 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 double A 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. By a lot, I mean several billion dollars worth of additional borrowing capacity. We do test our own plan against a low price 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 price environment and maintaining the AA.
Can you tell us, share what low price means?
No, don't want to go that far. We do look at the overall capital position and financial position of the firm, we tested against oil prices and we feel comfortable, Evan, with where we are. The other thing I would mention is that we do have, you'll recall from the March presentation, we are anticipating asset sale proceeds of $10 billion over the next three years.
That's great. I appreciate it. Thanks for taking my question.
Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please.
Yes. Good morning, thanks for the extra disclosures in the presentation. Just a question on cash flow. I think after working capital, you said $8 billion. It's been running higher than that. Volume's flattish in the macro environment, you've shouted out underlifts and some extra tax, were there any other things that may have contributed to a slightly lower cash flow this quarter?
Nothing of any substantial nature. With the underlifting circumstance, it was not a particularly strong U.S. downstream quarter. I think there are some operational factors that really lead to the $8 billion of cash generation. $8.4 billion.
Good. Thanks very much. Then Gorgon, you've said 80% complete. You've obviously just had the analyst day and said mid-2015. Other people have, perhaps even partners, are saying perhaps more later in the year, sort of 2016. I don't want to get into a debate, he said, she said, 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. It really becomes a process of the hookup and commissioning. I think that is, we've just come through kind of a weather period, so we're moving into good weather. I think weather continues to be a risk, and I think labor productivity continues to be a risk. Both of those are aspects of this project that we have been managing now for four and a half, five years. Those are clearly on everybody's mind, Ed, in terms of managing through this. I want to reiterate that the project's 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.
Hey.
If I could, kind of a big one and a small one. The big one is you have an interesting number, Pat, which is unproductive 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? The follow-up is on Zakum/Wafra, and I'll ask you that in due course. Thanks.
Okay. Well, basically, we just look at, it really is just assets under construction. Definitionally, it's assets in our work in progress account as a percentage of our total capital employed. The information that we provided back in March suggested that we're at a pretty high level predominantly because of the LNG projects that we have underway, as well as the couple of Gulf of Mexico deepwater projects. We indicated that we saw that stepping down significantly over the next three-year period of time. I also said verbally that we saw a pretty important stairstep going from 2013 to 2014, then again to 2015 and 2016. 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.
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 recollection was that there was an actual number of unproductive capital. I guess you could update us on capital employed or at least the last available number?
Well, year-end capital employed was about $171 billion. The information that we gave in the slide was a three-year average there for 11-
Okay, what was the unproductive number?
Paul, the three-year average, 2011 to 2013, was in the low 40% range.
Right.
Moving down to the mid-30% range for 2014 to 2016. That's the average 2014 through 2016. As Pat said, it steps down in each of those years. Our historic average here is maybe the high 20s.
Yeah, that's right. It was percentages, wasn't it? I recall now.
It was percentages. We use the averages, and 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. The three-year average there was that low 40s. What we're saying is 2014, 2015, and 2016 will reverse that pattern.
Yeah. Understood. Okay. That's helpful on that calculation. Back on my thing, can you do a little bit more to strip out Argentina, you've kind of bundled it with Permian.
Okay.
The extent to which that's sort of acquisition growth as opposed to organic growth. Thank you.
Yeah. Well, 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 results, both on cost and productivity. It's early days there, still a long way to go, but we're encouraged so far.
Okay. I think I'll take it offline on the breakout in terms of volumes year-over-year. It's just I was saying that on the variance, you've bundled Vaca with Permian.
Oh, I see. I misunderstood the question.
No, thanks for the answer. Absolutely. That was just the follow-up, really.
Year-over-year, Paul, we hadn't booked production in the first quarter of last year. We started booking production in the fourth quarter. There is a contribution, fourth quarter to first quarter, but over quarters, it is acquisition related. If you want to talk more specifically about it, just talk to 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 also got one big and one small one, if that's okay. On the impairments, Pat, is that the reason for the high DD&A number? If so, can you give us an idea what the run rate should be?
It certainly is a contributor to the high DD&A rate. Absolutely, that's a factor. In terms of general DD&A, I think that it's fair to say that overall corporate DD&A is going to go forward, move up. Our expectation would be that it would move up in 2014, relative to 2013. We see upstream DD&A per barrel rising for the next couple of years, but then flattening out over time. The pattern on both the absolute and the per barrel is something that you would absolutely expect because of recent investments and our future investments. It obviously is also impacted by reserve add timing and the mix of our projects, et cetera. Our PPC, our pre-productive capital, as we talked about, is going to come down.
I think the thing you've got to keep in mind here, too, is that for this investment that is evidencing itself and will evidence itself in our DD&A rate, we are giving the investment audience the largest growth rate of the peer group, a 20% growth rate in volumes between now and 2017. Significant investment, but generating significant volume growth.
Thanks, Pat. 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 margin trajectory is fairly well understood. What certainly we've observed over the years is that really gets paid by the market when it's accompanied by strong debt adjusted growth, if you like. The balance sheet's not expanding at the same time. I'm just kind of curious, when you look at your, you say you're delivering the best 20% growth, how do you think about the trade-off that's a $10 billion annual burn rate on the balance sheet? I'll leave it there. Thanks.
I guess I think that if you've got the project queue, a strong project queue, and you've got a balance sheet that allows you to invest for that. 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. If you've got the 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.
Hey, guys. Good morning.
Hey, Paul.
Pat, don't know whether you want to answer that. I think a lot of people is asking that for CPC, your joint venture, strategically, is there any particular reason you need to own it so that you can have synergy with your other operations? If not, if you look at it as a financial investment, does it make sense for you to own a minority interest and put it up as a publicly traded entity together with your partner, Phillips 66, and put it into the market so that you can recognize a much higher value given right now they're trading at a higher multiple than, say, both your partner and yourself?
Yeah. I understand the question there. I'll just start back with, when we put the two companies together, we had two, I guess I would say, sort of middling performing chemical companies. We put them together, and it's been a wonderful marriage. The partners are very much aligned on how to run this business, where to extract value from this business. It's a joint venture that has worked very well and has been very successful. We're very pleased. There's no catalyst that's out there necessarily to say that we need to be doing something different. It is a part of the portfolio that has growth opportunities available to it. We appreciate that with this change in the U.S. gas production and advantage feedstock opportunities here.
I think CP Chem calls on the technical expertise of both of its parent companies, we're able to, and happy to, assist them in that capacity. We think it fits nicely in our portfolio. The chemical business is highly cyclical, more so than our portfolio, we're able to withstand the adjustments that are there that we think that's an advantage as well. We don't really see that there's a huge catalyst for us to do something different, it's not always clear that the PE multiples in these petrochemical commodity companies are always trading at multiples better than ours. We like the joint venture. We think it's well run. We're happy to assist in its growth projects and providing expertise and technical capability where we can.
We're very satisfied with it, I dare say that our joint venture partner would be feeling much the same.
Okay. Very good. Second question, can you give us a quick update whether Angola LNG right now is running at 50% capacity? Also in the Permian with the 25 rigs, do you have a number how many of them is currently running in the unconventional?
Okay, let me start.
Another fact, they are in the pad drilling already. Thank you.
Okay, let me start with Angola, then you might need to help me again on the second question. 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, in fact, that root cause analysis should be completed within a few days here, is my understanding. The plant is currently shut down, 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 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? Of which, how many of them is in the pad drilling already?
Okay. All of the 25 rigs in the Permian right now are in the unconventional. We have only one rig drilling in the conventional. I think you're asking about pad drilling?
That's 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.
Yeah. Hi, guys. Thanks very much. Can I get back to the impairments and asset divestments you put in the reconciliation at the back? I didn't understand some of the stuff you were talking about earlier. You've got $150 million of E&P impairments, it looks like, in the first quarter, and also $100 million gain on dispositions. You've also got this mining write-down as well. Can you just put those together for me again?
Sure. 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.
Okay.
That asset from a segmented reporting basis is in our other segment. In Upstream, we noted $150 million of impairment. It's in the international sector for us. These are assets where we feel there are better opportunities in other portfolios, basically. The third element that was noted there was an asset sale gain. This is in our midstream, quote-unquote, midstream sector. It's really pipeline related, and that showed up in the Downstream external segment.
Okay, thanks very much. The second thing was, is it possible to update us on when we're likely to see the Tengiz future growth FID?
Our target 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 latter part of last year, which really is the stage-setting document to get all the partners aligned on the go-forward process. We're in the process now of going through and working the cost estimates, et cetera. All I can say is towards the end of this year.
We should expect a kind of overall CapEx for this, gross CapEx for this project, along the lines of some of your major things you're doing in Australia. Is that correct? Is that kind of ballpark, the right sort of number?
I'm sorry. Tengizchevroil is Kazakhstan, right? I guess one last thing there on Tengizchevroil. The FID is not critical path. What was the question on Australia? I didn't quite understand.
Sorry, I just wanted to get an overall ballpark idea of 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, Ian. We don't have a cost estimate. We won't have a cost estimate until we go to FID. That will be later and attached to the FID timing.
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 until the startup to get that project going? Meaning if there's an active hurricane season, have you built in that sort of weather into the startup at the 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 weatherproofing as we possibly can. Obviously, when you're investing at the size of these facilities, that's an important consideration. Clearly, having it moored is an important step. Our expectation is that we would be able to handle any weather complications that might arise.
Okay, fair enough.
Can I just add, Faisel.
Yeah.
If there are hurricanes, you have to demobilize the folks that are working on it. That could slow things down a little bit, but 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? Each year is a different degree, if you know what I mean.
Sure.
There's obviously a base load that we include in our plans, yes.
Okay. That's fair. I understand. Then just on the underlift, you guys talked about the sequential quarter-over-quarter change of $235 million. Is that also fair to say that that's the absolute number too?
I'll give you the absolute for the quarter is about $100 million, about half of that. The rest of that is swing between the two quarters, Faisel.
Okay. All right, Jeff, 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 the question. 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, Faisel, are sitting 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 with, for example, Cimarex, where we have partnered with similarly situated partners. 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 your fracking can really go from our property to their property. We will continue to look for those opportunities for synergies. We've got a very active program scheduled for this year, over 500 wells and 25 rigs. We've done 120 drillings so far. The activity level is at or perhaps even a little bit better than planned at this point.
We'll continue to look for opportunities like that, but we're proceeding ahead on our own as well.
Okay. Pat, just quickly, can I get an update on the exploration program in Liberia? I haven't heard about that in a while.
Yeah. We're not in a position to say anything more at this point.
Okay. Fair enough. Thanks.
No.
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. 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 influences you battled 1Q, the unplanned downtime at Angola LNG, and then 2Q and 3Q typically being heavier maintenance quarters. Just wanted to better understand how you guys are feeling about that internally and any cushion you might have 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 3 months in here. There have been some positives. Jeff mentioned a figure about base business decline being at the 3% or a little bit less than 3% level. That's a very good positive. One thing we haven't mentioned that's 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've talked about the Permian ramp-ups and the Vaca Muerta ramp-ups that are occurring. Those are all working in our favor. Clearly, weather has been a negative for us in the first quarter. On an absolute basis, we'd estimate that that was worth 20,000 barrels a day or so, absolutely negative in the quarter.
I mentioned the ALNG operational issues that we have there. You put those all together, you got some pluses, you got some minuses. In the back end of the year, we've got Tubular Bells and Jack/St. Malo, both of which are scheduled to come online. Our production ramp-ups are kind of back-end loaded. Both of those projects are on track. The best I can say is, and I'll go back and say, we build 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 positives and negatives out there. We feel that the guidance that we gave at 2610 is the best guidance that we have at this particular point in time.
As we do every year on the second quarter, we'll update you with how things look at that point in time.
My follow-up was on one of your three primary growth themes, the deepwater. I'm more focused on your next generation of projects, looking beyond the near-term startups that you have lined up as we start thinking about potential reserve additions and then longer-term growth potential. You all have a number of potential FIDs this year, that you have an interest in. I think Stampede, and then your Indonesia development at Bangka, and then you're also reevaluating Rosebank.
Understanding that every project is unique, I was just hoping you could provide some more commentary on just how conducive the overall environment right now is to pushing forward deepwater FIDs, just in light 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 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 and portfolio, you mentioned a number of projects, but I think the most strategic basin continues to be the U.S. Gulf of Mexico. We've got a 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 18 months. That continues to be an area of strategic focus. We think we're competitive there on facility structure as well as drilling costs, completion costs. That's important area for us. If I look at IDD, it's a complex project. It's multiple fields. Right now, we're in the position of waiting for government approval.
On Rosebank, we did really, as the operator, put that into a recycle mode because the costs that had come through didn't make it compete for capital within our portfolio. That's somewhat in a recycle mode. 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 plays 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.
Yep, good morning.
Good morning.
I guess to come back to the Permian a little bit, if I understood correctly, you are 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. Thinking about how production from horizontal wells has typically been a little more, let's just say higher IP rates and leave it at that. We should think about the shale and tight production accelerating, I don't know, call it Q4, certainly into 2015. Would that be consistent with how you're looking at things?
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 quarter after quarter. Our real focus has been on getting capital efficiency maximized and getting a strong execution efficiency as well. It's really been on optimizing the value creation. We've been spending time to understand where the best areas are, and what the most efficient rig pad and overall development plan is. Frankly, a lot of the other producers there have been allowing us to de-risk this play by the work that they have done, and that's, in a sense, advantageous to us. We think we can get, over time, the same kind of synergies and efficiencies that the smaller operators have.
One of the slides that we had put out in the security analyst meeting gave a good indication of what we see as year-over-year net production increases in the Permian Basin. It's a pretty significant growth rate. We also talked to essentially a doubling of our rig count over the next several years from where it is currently.
Right. Well, I guess we now have a couple of quarters here where you're breaking out shale and tight from everything else, so we can start to get a feel for what that quarter-over-quarter and year-over-year performance is.
Exactly.
I just want to make sure I was understanding the way it should progress here.
Right. We're hopeful for quarter-over-quarter improvements going forward.
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. If you think about, and I know sometimes you don't get too granular, but the impact on it from a cash flow standpoint, 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 quarters?
Yeah, I think you will see it'll be more noticeable, clearly, in the production side than the cash flow side, clearly. I don't have, as I mentioned, we need to have the root cause analysis done before we have an indication of what that 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 at 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 questions, so I appreciate your time and interest today. I especially want to thank all the analysts who, on behalf of all the participants, for the questions that they asked in this morning's session. Jonathan, I'll turn it back to you, and thank you, everybody. Have a good day.
Thank you. Thank you, ladies and gentlemen. This does conclude Chevron's first quarter 2014 earnings conference call. You may now disconnect. Good day.