Good morning. My name is Sean, and I will be your conference facilitator today. Welcome to Chevron's first quarter 2013 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's remarks, there will be a question and answer session, and instructions will be given at that time. If you should require assistance during the conference call, please press star then zero on your touchtone telephone. As a reminder, this conference call is being recorded. I would now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.
Okay, good morning, everyone, and thank you, Sean. Welcome to Chevron's first quarter earnings conference call and webcast. On the call with me today is Jeff Gustavson , General Manager, 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 shown on slide two. Slide three provides an overview of our financial performance. The company's first quarter earnings were $6.2 billion or $3.18 per diluted share. Return on capital employed for the trailing 12 months was 18%. Our debt ratio at the end of March was approximately 9%. In the first quarter, we repurchased $1.25 billion of our shares. In the second quarter, we expect to repurchase the same amount. Turning to slide four.
This week, Chevron's board of directors declared a $1 per share quarterly common stock dividend payable in mid-June. This is an 11% increase and reflects the performance and strength of our current portfolio and our confidence in our compelling growth prospects. Since 2004, our dividend has grown at a compound annual rate of 11%, a growth rate that is well in excess of the S&P 500 and better than our peers. You can see this on the left chart. This pattern demonstrates the priority we place on rewarding our investors through increasing distributions. The chart on the right provides updated information on five-year rolling total return to shareholders through the end of the first quarter. Our strong financial and operational performance and superior growth prospects for both production and value are being recognized by the market.
We have led on this rolling total shareholder return for an extended period of time now, and we are off to a strong start in 2013. Turning to slide five. Cash generated from operations was $5.7 billion during the first quarter, a lower level than it has been in some time. This was primarily the result of working capital impacts. Overall, working capital requirements for the company increased by $3.4 billion in the quarter. This working capital consumption of cash was principally in our downstream operations. This is not an atypical pattern for us for the first quarter of the year, though this quarter's increase in working capital requirements is larger than we have usually seen. The increase reflects the timing and pricing of commodity purchases and sales between quarters, as well as the operational downtime we had at several refineries this quarter.
The vast majority of these effects are temporary in nature, and the impacts to cash flow are expected to reverse in future quarters. Importantly, our upstream business continues to generate strong cash flows. Capital and exploratory expenditures were $8.2 billion during the quarter, including expenditures associated with our buy-in to the Kitimat LNG project. We continue to maintain a strong balance sheet, and at quarter end, cash balances exceeded $19 billion, giving us a net cash position of almost $5 billion. Jeff will now take us through the quarterly comparison.
Thanks, Pat. Turning to slide six, I'll compare results of the first quarter 2013 with the fourth quarter 2012. As a reminder, our earnings release compares first quarter 2013 with the same quarter a year ago. First quarter earnings were $6.2 billion, about $1 billion lower than fourth quarter results. Upstream earnings were down $942 million, reflecting the absence of fourth quarter asset transaction gains, partly offset by higher realizations and a favorable swing in foreign currency effects. Downstream results decreased $224 million between quarters, driven by lower volumes largely associated with seasonal maintenance activity and the absence of fourth quarter asset transactions, partly offset by a positive swing in foreign currency effects. The variance in the other bar largely reflects lower corporate charges. On slide seven, our U.S. upstream earnings for the first quarter were $231 million lower than fourth quarter's results.
Higher realizations improved earnings by $95 million, driven largely by an increase in crude oil prices. Lower production volumes decreased earnings by $80 million, mainly due to increased maintenance activity in the Gulf of Mexico and fewer producing days in the quarter. The net of higher DD&A and lower operating expenses reduced earnings by $85 million. The other bar reflects a number of unrelated items, including the absence of favorable tax effects and gains on small asset transactions in the fourth quarter. Turning to slide eight, international upstream earnings were $711 million lower than the fourth quarter. Earnings increased approximately $130 million due to higher realizations, partly offset by lower liftings. A favorable swing in foreign currency effects improved earnings by about $200 million. The first quarter had a gain of $170 million compared to a loss of $30 million in the fourth quarter.
Lower operating expenses increased earnings by about $200 million between periods, primarily due to reduced maintenance activities and employee costs. The other bar reflects a number of items, including favorable tax effects in addition to lower exploration expenses. Finally, earnings decreased by about $1.5 billion between quarters, primarily due to the absence of the gain on the Browse asset exchange recognized during the fourth quarter. Slide nine summarizes the quarterly change in Chevron's worldwide net oil equivalent production. Production decreased 23,000 barrels per day between quarters. Lower cost recoveries on production sharing contracts spread across multiple countries reduced production by about 16,000 barrels per day. This is an investment timing issue, which we noted in our interim update. The base business and other bar includes the impact of planned turnaround activity, weather disruptions, and normal field declines.
Contributions from major capital projects increased first-quarter production by 9,000 barrels per day, primarily driven by Perdido in the Gulf of Mexico and Platong II in Thailand. Turning to slide 10. U.S. downstream earnings fell $196 million between periods. Lower volumes reduced earnings by $190 million, primarily due to planned maintenance at the Pascagoula, Mississippi, and El Segundo, California refineries. First quarter 2013 was a particularly heavy refinery maintenance period for the company. Maintenance at both Pascagoula and El Segundo has now been successfully completed. We also reintroduced feedstock to our Richmond refinery crude unit earlier this week and will continue bringing the downstream conversion units to full capacity over the coming days. Weaker margins decreased earnings by $65 million. Seasonally weak demand, particularly for gasoline, combined with rising crude costs, pressured refining and marketing margins.
The other bar reflects several miscellaneous items, including lower operating expenses, higher chemical earnings, and the absence of year-end LIFO inventory drawdown benefits that were recognized last quarter. On slide 11, international downstream earnings were $28 million lower this quarter. Lower volumes reduced earnings by $75 million, primarily due to planned maintenance at the Burnaby, Canada, and Cape Town, South Africa refineries. Lower operating expenses increased earnings by $95 million, reflecting lower transportation and environmental expenses. Foreign currency effects represented a $175 million positive earnings variance between quarters. First quarter's FX gain was about $75 million compared to a fourth-quarter loss of $100 million. Gains on asset transactions were $135 million lower, reflecting the absence of prior quarter asset sales. The other bar again reflects a number of unrelated items, including lower shipping results, weaker lubricants margins, and higher withholding and other tax-related charges. Slide 12 covers all other.
This segment broadly consists of corporate administrative functions, our worldwide cash management and financing activities, as well as our mining, power generation, real estate, and energy technology and services businesses. First-quarter net charges were $439 million compared to $538 million in the fourth quarter, a decrease of $99 million between periods. A favorable swing in corporate charges resulted in a $111 million benefit to earnings, while corporate tax items were $12 million higher this quarter. With that, I'd now like to turn it back to Pat.
Okay. Now turning to slide 13. Last month, we held our annual security analyst meeting, where we provided updates on our projects and future growth plans, as well as our financial performance relative to our key competitors. We now have fully updated relative performance data in a couple of areas, segment returns on capital employed, and upstream cash margins. First, our upstream adjusted return on capital employed was 21.5% for 2012, and we can confirm this placed us in the number one position relative to our major peers for the second year in a row. We completed the restructuring of our downstream business, and our adjusted return on capital employed in 2012 improved again to over 18%. Here we rank a strong number two against our peers, and we've been closing the gap versus the leader for each of the last five years.
Slide 14 shows our updated upstream cash margin comparison. We have led the peer group in upstream realizations for several years, a trend which continued in 2012. Combined with our competitive cost structure and the quality of our portfolio, we also continued to lead the peer group on unit cash margins. In fact, our cash margin of just under $37 per barrel exceeded the average cash margin for our peer group by $11 per barrel, or over 40%. This superior performance is a function of the quality of our assets as well as our strong execution capabilities. Turning to slide 15, I'd like to share some highlights of the strategic progress we've made during the quarter. We announced successful well test results at St. Malo in the U.S. deepwater Gulf of Mexico, where oil flow rates, while limited by testing equipment constraints, exceeded 13,000 barrels per day.
With new technology, we saw drilling efficiencies and good reservoir stimulation. This bodes well for improving the recoveries and the economics on our existing and future Gulf of Mexico projects. The Bigfoot hull has arrived in the Gulf of Mexico, and the Jack St. Malo hull is on its way. The picture is of the Jack hull being transported. We announced the signing of a binding long-term sales and purchase agreement with Chubu Electric to deliver 1 million tons per year of LNG from the Wheatstone project. Our Wheatstone LNG project has over 80% of its offtake secured under long-term sales contracts. In the downstream, a new gas oil cracker achieved startup, making the Yeosu refinery in South Korea the largest processor of heavy oil in that country. We continue to be successful with our exploration program, with new discoveries at Coronado in the U.S.
deepwater Gulf of Mexico. In Australia's Carnarvon Basin, where we announced discoveries at Kentish Knock South and the Elphin-1 prospect. The Elphin-1 prospect is our 21st discovery since 2009. We added new offshore exploration acreage in both Morocco and China. We also reached an agreement to enter the Cooper Basin in Australia, another early, low-cost entry opportunity focused on unconventional resources. Finally, we recently sanctioned the Moho Nord development located in the Republic of Congo, the largest-ever oil and gas development in that country. I'd like to close by saying we're off to a great start in 2013. Earnings are strong. Upstream activity is on plan, not only in terms of production, but also in terms of executing well against our major development project milestones. I encourage you to visit our investor website, where we recently posted updated photos of our progress on our Gorgon and Wheatstone projects.
We also continue to pursue future profitable growth opportunities, which will create additional value for our shareholders over time. Our healthy dividend growth pattern remains in place. This marks our 101st year of paying dividends and our 26th consecutive year of growing our annual dividend distributions. We continue to provide the strongest returns to shareholders, offering a good balance between share price appreciation and dividend yield. We truly appreciate you listening in this morning and your interest in the company. I'd like to now open up the microphones for questions. We do have a full queue, so please limit yourself to one question and a single follow-up if necessary. We'll certainly do our best to see that we get all your questions answered. Sean, please open up the lines for questions.
Thank you. Ladies and gentlemen, if you have a question at this time, please press *1 on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the # key. If you are 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, please press *1 on your touchtone telephone. Our first question comes from Ed Westlake with Credit Suisse. Please go ahead with your question.
Hey, good morning, Pat. Just a quick question on the tax rate, if I may. It dropped down to 39.3 and you flagged favorable tax rates in some of the commentary. Are there any sort of structural changes here in terms of shifts, or is this just a tax optimization in the quarter?
There's nothing structural here, Ed. As you probably know that as certain projects mature, and particularly as they get to the FID stage, it's not unusual to have certain tax impacts triggered by reaching that project milestone, and that's really what we saw occurring here in the first quarter. That's what gave us a low effective tax rate in first quarter 2013. We expect this to balance out over the end of the year. I think from a longer-term perspective, thinking back to the 2012 effective tax rate, which is about 43%, that's a pretty reasonable place for you to peg the overall expectation for the year.
Hey, thanks. That's very helpful. Just switching topics on natural gas in the U.S., obviously, a bit of benefit from Marcellus and Atlas over the last couple of quarters, but the gas price, I guess, it's rebounded a little bit. Should we expect that gas production probably trends down a little bit as it started to in the first quarter as you go through the balance of the year?
Well, I think what we have said in the past that we have really restricted all of our dry gas production to minimal amounts, principally in the Marcellus area. Of course, we're being helped there economically by the carry that is still in place. All the rest of our gas production efforts really are geared towards heavy liquids concentration efforts, so we should continue to see those ramp up.
Okay, thanks. Very helpful. Thanks very much.
Okay. Thanks, Ed.
Our next question comes from Evan Calio with Morgan Stanley. Please go ahead with your question.
Yeah. Morning, Pat and Jeff.
Morning, Evan.
Morning.
Yeah. Let me ask maybe a longer-term question, of how you think about the longer-term CapEx and cash return strategy. I ask in the context of, in my view, Chevron's relative free cash flow and flex in 2014, '15 time period, as you begin to see the cash benefit of these relatively heavier and current period of capital investment. The question hence becomes, do you believe that when you likely have incremental cash during this period, the cash returns to shareholders via buybacks or dividends increase, or that you see additional reinvestment opportunities in the portfolio to maybe replicate this '14 to '17
growth period. How do you think about that?
Okay. Well, I would say broadly, first of all, we believe the best way over time that we create value for our shareholders is by making the right investment choices. If we have a strong queue, if we have projects that are very nicely attractive, nicely economic, then obviously that's an important element for us. We have been in a stage where we have had very nicely attractive projects, That is really what has given rise to the heavy investment period of time. We do take our dividend commitment to our shareholders very seriously. That is the first priority of return of distributions to the shareholders. You should expect that to continue to grow as long as earnings and cash flows continue to grow. We, of course, are able to grow earnings and cash flows if we invest appropriately.
We work very hard at trying to get that balance right between attractive projects for reinvestment in the business and then also dividend distributions to the shareholders. If we get into periods of times where we have surplus cash, free cash flow, beyond the C&E requirement, beyond the dividend requirement, that's really what we peg our share repurchase program to distribute. We look at that every quarter. We evaluate what we think the medium-term requirements for the firm are in terms of reinvestment. We obviously have a hypothesis about what our board might do on dividends. We look at what we think is happening from a commodity price standpoint, Therefore what net generation into the firm might be, That's how we peg our share repurchases. It is the most flexible element of our cash distribution formula.
Mm-hmm. Understood. Let me try maybe one different way, if I could. The percentage of CapEx that's invested in the project queue that's not adding to NOPAT today is relatively higher than where it's been historically. I think you gave the 35% number at the Analyst Day. I know there's a lot of variabilities, but under current conditions, would you expect that to normalize back into this 25%-30% range, once you're exiting this kind of peak spending period through, call it, 2015 timeframe? I'll leave it at that. Thanks.
Okay. I think the best guidance I can give you on that would be to have you take a look at the duration of the investment cycles for some of the projects that we have underway. When you're talking about LNG projects, Of course, we've got Gorgon and Wheatstone underway. We have Kitimat, which is just in a very embryonic stage here, but those have very long investment cycles, 60 months plus. That's much different than what you would get in sort of the factory investment types of cycles that you might achieve in, say, a Permian ramp-up, for example. I think you need to look at the kinds of projects that we have in our queue and the overall investment cycle times for those projects in the queue.
That is going to give you an indication of how much pre-productive capital we might have built up on our balance sheet at any point in time. I did say back in March that our pre-productive capital was in the high 30s. That is an abnormally high level for us. All things being equal, once you get through the heavy spend period, we would expect that to come down, as long as we don't have another set of projects moving forward. We do try to balance this all out. In the end, I think, we have certainly demonstrated a history of doing that, being able to do that successfully, because our project queue is very economic and is producing the returns that we're benefiting from a cash flow standpoint, and our investors are benefiting from a distribution standpoint.
Great. Thanks. I appreciate it.
Okay. Thank you.
Our next question comes from Arjun Murti with Goldman Sachs. Please go ahead with your question.
Thank you. A question on the Cooper Basin. When we were over in Perth last fall sometime, Chevron did not sound particularly excited about some of the East Coast LNG opportunities and stuff over in Queensland. Just curious whether this Cooper Basin entry signals any change to that view. Maybe I misread it.
Arjun, I wouldn't read too much into it. I think we were talking very broadly-
Yeah
back in the fall. As a general rule, as a company, we're always on the lookout for what I would consider low cost, early entry opportunities. That's really what the Cooper Basin represents. It's a very new play. I can't really indicate how that may in fact turn out for us. We just think it was an opportunity to expand our unconventional portfolio. There's an awful lot of work that will need to be done to evaluate the basin. We're hopeful that something could turn out there. I think you need to think of it as low cost entry, and very early in the evaluation phase.
Got it. That's helpful, Pat. Thank you. Just a quick follow-up. Any update on the timing of Angola LNG startup and Frade startup? Thank you very much.
Sure. On Angola LNG, our expectation is that we will have first LNG here in the second quarter. Assuming that happens, then we would expect to get to full capacity by year-end. Again, assuming that things move as we think they will, it's probably going to add to us about 20,000 barrels a day for the full year. Obviously, that would just be a partial year contribution for us. It's worth about 60,000 barrels a day net to us when fully operational. From a Frade standpoint, we have received Approval for a production restart for four wells, basically. No injection activity. That should be here in the second quarter as well, but it will be ramping up relatively slowly. The contribution for the year will be relatively modest, only about 5,000 barrels a day.
That's great. Thank you so much.
Okay.
Our next question comes from Paul Sankey with Deutsche Bank. Please go ahead with your question.
Hi, good morning, everyone.
Good morning, Paul.
Good morning.
Pat, just a quick one. Was there some tax changes in Kazakhstan as it relates to exports? This is the first one, and the bigger one, which you may be able to answer or not, is can you talk a little bit about the sensitivity of your CapEx levels to the dollar, to appreciation in the dollar? I assume that an appreciating dollar would bring down your global CapEx. I wondered if you had a sense for sensitivities. Thanks.
Right. The first answer is no, the tax change didn't relate to Kazakhstan. In terms of our capital program, we're really most sensitive to movements from a capital program standpoint to the Australian dollar versus the U.S. dollar. I think we've explained in the past that, yes, it's been a component. We have had higher foreign exchange impacts. That was part of the Gorgon cost increase up to $52 billion. About a third of that increase from the original FID number was related to foreign exchange effects, so that has impacted us there. This year, it has really been much more modest than that. As we've said in the past, we haven't hedged against the Australian dollar or hedged the Gorgon or Wheatstone activities because usually the Australian dollar is moving with commodity prices, and usually that means that we've got a natural hedge.
Yeah, I was just kind of wondering, I guess if the dollar strengthens globally, it would tend to imply that the oil price will come down. Clearly what you're saying is, the main sensitivity by far is the Aussie dollar.
That's exactly right.
Not, for example, the euro wouldn't make a whole lot of difference either way, yeah?
Not from a C&E standpoint, no.
I thought I'd read, by the way, going back to the first question, that Kazakhstan had changed its export tariffs. Was I just wrong?
No, Paul, this is Jeff. That's correct. They did increase the export tax, our assets are not affected by the increase. Our netbacks are not impacted.
Thank you. That's perfect. Thank you.
Our next question comes from Douglas Leggate with Bank of America Merrill Lynch. Please go ahead with your question. Doug, your line is open. Could you try pressing your mute button?
Oh, sorry, I had mute on. Good morning, everybody.
Hello, Doug.
Hi, Pat. We're looking forward a couple of years to some very substantial step-ups in production, but we don't really hear you talk much about portfolio high grading. Is that something that is just really you're very happy with the asset base you have now, or is there an ongoing effort to pare, if you like, the bottom 10% of the portfolio on a regular basis? I'll go off the line, please.
I would say that we have a standard practice of pairing components of our portfolio, and I'm speaking here about the upstream. Pairing components of our portfolio, where we find that it's not going to continue to attract the capital that it needs to perform well, where we feel others might find more value in that asset. We will continue to do that pairing. I think about a year and a half ago or so, I'm a little shy on the timing, but at fourth quarter 2011, the Cook Inlet sale occurred. That's just a good example of continued pairing of the portfolio. I will say on balance, we're very happy with our portfolio because you see it in our earnings margins and you see it in our cash margins. On balance, we like the assets that we have.
Having said that, we obviously look for opportunities to pare if we think the asset has more value to somebody else and it's not going to compete in our portfolio.
Doesn't sound as kind of particularly material, Pat. Is that a fair assessment?
I think that's true. That's fair. Normally, you can expect for the enterprise somewhere between $1 billion and $3 billion of asset sales in a given year. Over the last few years, more recently, we have had a little bit heavier restructuring occurring in our downstream segment. That effort is largely behind us, you wouldn't expect that continuing size to go forward in 2013.
Great. My follow-up is really, I guess it's kind of a related issue. We monitor your, if you like, a capture rate on your upstream business, and for most of the last year it was, I won't give numbers, but let's assume it's relatively low. In Q1 we saw you've seen a big jump in your international margins relative to your weighted revenues, if you like. Has something changed there? Was it an absence of maintenance that's more sustainable going forward? Or to Paul's point, has there been any kind of incremental tax changes that have led to that rebound? I'm just trying to understand how sustainable this might be on a go-forward basis, because it was quite a significant number relative to what we were expecting.
You're talking about our upstream-
International margins
upstream international margins? Right. I think that really when you look at 2012, if you look at the whole quarterly pattern for 2012, we had a significant deterioration in the third quarter, really associated with the downtime at Tengizchevroil. Now we have really just moved back up into what would be a more normal pattern. That impact of the downturn in the third quarter and the reramping back up here in the fourth quarter, you can see in last year's results.
Okay, that's very clear. Thank you.
We're back to a more normal position for us.
That's what I needed. Thank you.
Thanks, Doug.
Our next question comes from Doug Terreson with ISI Group. Please go ahead with your question.
Congratulations on your results, everybody.
Thanks, Doug.
Thank you.
Pat, I wanted to see if you'd provide an update on the situation in Argentina and also the plan or next steps for Kurdistan for 2013, if there are any.
Okay. Well, Argentina, we continue to work with YPF on the Vaca Muerta discussion. We're hopeful that that will be able to be concluded. So far, we've drilled about three shale wells on our existing acreage. We're encouraged by the results that we have there. There are some above ground complications, I guess I would say, that exist in Ecuador as they relate to Ecuador.
Right.
We need to have satisfactory resolution of those above ground complications before we proceed in a material way on Vaca Muerta.
Yeah. Pat, could you just provide a little color on that point?
Okay. Well, basically, Ecuador has
You don't have to go that far back. Just the next steps, I guess, legally that you guys envision. Yep.
On the overall Ecuador case?
Yeah. No, just the Argentina component.
On Argentina?
I'm sorry. Yeah.
Argentina. Okay. Right now there's, I guess I would call it a partial freeze of assets in Ecuador.
Sure.
It really hasn't impacted our liquidity in a substantial way. We've been able to modify our liquidity provisions, and so operationally, we're in good shape. There is a freeze underway.
Right.
We are basically petitioning to the Supreme Court in Argentina to have them review that case. I don't know when the Supreme Court may take it up or if they will take it up. We're certainly hopeful that they will take it up.
Okay.
We don't believe that there's any merit to having the freeze in place. We believe in a country that abides by the rule of law, that justice will prevail on this element as well.
Great. Thanks a lot.
Okay. Thank you.
Our next question comes from Jason Gammel with Macquarie. Please go ahead with your question.
Thank you. I just wanted to ask a couple of follow-up questions on the exploration success in the quarter. First of all, on Coronado. You're obviously in a pretty good neighborhood there. Can you talk about any follow-on drilling plans that you have? I believe that you're about to spud a sidetrack, or maybe you already have spud a sidetrack on the discovery well.
Well, not really sure what I want to be saying here on Coronado. We do like the area. Let's see here.
We're still evaluating that, Jason. We have spud a sidetrack on it.
There's not much more that we really want to say at this point.
No, not right now. It's still under evaluation.
Okay, that's fine. Maybe if I could just shift to the Australian exploration success. Obviously between drilling results and then the swap that you had with Shell, for Carnarvon Basin versus Browse Basin, quite a bit of incremental gas. You've talked about being able to move into a Gorgon feed for a Train 4 relatively soon. Given the gas you've accumulated, when do you think you could actually start evaluating a Train 3 at Wheatstone?
I think that is more distant, certainly. I think we need to get Trains 1 and 2 up and moving forward. We're only the second year into that whole development construction phase here for Wheatstone. I think it will come. It is a hugely prolific area, as you know, and with both the Kentish Knock and the Alpha 1 prospects, we just continue to add. The more that whole region continues to add to our gas holdings, then it gives us more flexibility about which particular gas molecule we send to which particular plant. I think you should think of it as after discussions around Train 4 for Gorgon for any expansion.
Okay. That's helpful.
any further expansion of Wheatstone.
Okay. That's helpful. Thanks very much.
Our next question comes from Paul Cheng with Barclays Capital. Please go ahead with your question.
Hey, guys. Nigeria GTL, are we still on track there for the year-end start-up? Based on your experience with the GTL, I presume that you're probably not interested in a GTL plan in the U.S. natural gas market?
With regard to EGTL, we're in the process here of commissioning the plant. It's a complex plant and the commissioning activity really go on for the bulk of this year, for the rest of this year. I would say GTL would not rank high in terms of our project alternatives for U.S. natural gas.
In Nigeria, Pat, the production dropped a little bit, but we thought Usan should be continued to be ramping up. Is there any PSC effect related to Nigerian production, or is it just natural underlying decline rate?
No, there's no PSC effects there.
Well, I'd say there are some cost recovery effects there, Paul. Investment levels were slightly lower between quarters, and so we had lower cost oil barrels.
That's really a timing issue, not anything more sustaining than that. Timing of investments and therefore the timing of cost recovery barrels.
Okay. Can I just sneak in a real quick one for clarification? On the favorable tax impact for international E&P, do you have an absolute dollar amount in the first quarter? You show in the chart saying that sequentially is a benefit of $214 million.
Right.
What is the absolute dollar amount in the first quarter?
Right, we're not going to disclose that. Again, I think the important point about this is to understand that was a timing event associated with moving some projects through various project milestones and the taxes that are triggered commensurate with that. For the overall year, you should think about the overall effective rate for the company of being in the low 40%.
All right. Thank you.
Our next question comes from Basil with Citigroup. Please go ahead with your question.
Thank you. Good morning. I just wanted to actually get some clarifications on the downstream business. You guys mentioned a lot of sort of downtime between Pascagoula, El Segundo, Burnaby, South Africa, Richmond, the Yeosu refinery upgrader. I'm just actually trying to digest all of that. Could you guys just let us know what was down and what's back up and at full production right now? And maybe give us a little bit more detail on the upgrader here. Was this starting to consume more heavy oil at Yeosu? I just have a follow-up. Thanks.
Okay. I think, what we can say, we really have said already. El Segundo and Pascagoula are back at normal operating level. Richmond crude unit is just now taking feed, and we'll continue to line that out over the next several days. Certainly, as we progress through the quarter, you should expect that to be back to full operations. The downtime at the smaller refineries, the same sort of circumstance has occurred. It was just a very heavy first quarter maintenance period. You should expect that second quarter will be substantially back fully operational. We don't go into specific details about which units we have down at which plants for which duration for commercial reasons, and I'm sure you can appreciate that.
In terms of South Korea here, we did have the new VGO FCC up and online with on-spec product during the first quarter. It's a 53,000 barrel a day plant. It does allow us to process heavier oil.
Okay. Got it. Perfect. My follow-up is just on to Marcellus. Is there any chance you give us how production has grown for you in the Marcellus last year to this year? You talked about it, I guess, in your prepared remarks, but just trying to understand how much growth you've seen out of that particular asset of yours.
I'll take that. There has been production growth between year-on-year quarters, and a lot of that's driven in the U.S. by both the Marcellus and the Mid-Continent for us, which is effectively the Permian and some of the assets we picked up from Chesapeake later last year. Marcellus continue to carry and continue to bring on production.
We would expect the Permian component to continue to grow during the year.
Okay. Fair enough. Thanks a lot.
Our next question comes from Asit Sen with Cowen Securities. Please go ahead with your question.
Thank you. Good morning. Two quick questions, one on Brazil and one on Australia. Just to follow up on Brazil, given Friday's start in second quarter and small contribution in 2013, how should we think about Papa-Terra? Still a 2013 startup or slips into 2014?
Right. We really need to refer you to the operator on this. The operator continues to have a 2013 startup.
Then, secondly on Australia, more strategic question. In a scenario where floating LNG becomes viable, how does it impact your thought process on future LNG trains at either Gorgon or Wheatstone? Any early thoughts on that would be appreciated. Thank you.
Right. I think the floating LNG obviously is a technology that is still yet to be proven, and my expectation would be over time that that will prove out to be a development design that will be appropriate for certain types of reservoirs. In terms of Wheatstone and Gorgon, we're really in a position where we have invested already in the greenfield, and our best opportunity for further expansion obviously will be brownfield. Brownfield, as you know, can be much more economic, particularly on the downstream components of the plant. Certainly, we think maybe 15% or so, 15%-20% more capital efficient on the downstream side. We think the brownfield expansion that we have at Gorgon and Wheatstone, and given the resource size that we have at Gorgon and Wheatstone, will allow those developments, when the time is right, to be attractive and competitive.
Thanks.
Our next question comes from Allen Good with Morningstar. Please go ahead with your question.
Good morning. I just wonder if I could get a follow-up on the Marcellus. I guess in March, you mentioned you had the $850 million left on the drilling carries there and running about eight rigs. At your current level, when would you expect to exhaust that drilling carry? When you do, would you imagine that you continue on with that eight-rig drilling program, or would you reduce activity at that time?
Right. The 850 is the number that we have at this particular point in time. We're not going to continue to provide interim updates on that. That really is a function of the drilling program and the rate at which the investments occur. Our expectation really is, and I think we've said this for some time here, that our expectation is that the drilling carry works through a period of what I'll call relatively low U.S. gas prices. It allows us to understand the reservoir, allow for to build out the development plan for that basin. By the time the carry is over, it's our expectation that we would be sitting in a stronger U.S. natural gas price environment.
At the same time, we've had good success in improving the economics of our drilling program in terms of cost per well, the footprint per well, and also the environmental impacts per well. We're very pleased with the progress that we've been able to make, and we're happy to have the carry, and we'll continue to prosecute the plan over the next 12, 18, 24 months, just as we have in the last couple of years.
Okay. I wonder if I could just get your updated thoughts on the acquisition front. Obviously, you did the deal with Chesapeake last year, a couple of years ago, the Atlas deal. What's your view right now as far as valuations are concerned in U.S. unconventional space, whether it be natural gas and oil? How much opportunity do you see today relative to last year, given, I guess, some of the drop in oil prices and maybe some of the other valuations of some of the smaller E&Ps that are out there that may fit into your portfolio?
Yeah. I don't think I want to have a generic statement on this, because I think it really does depend on the quality of the asset in the unconventional space. As we've seen, there's a big difference between sweet spot areas and non-sweet spot areas. We continue to always be focused on the value proposition first, and that really stems from the quality of the asset. In certain times here, we have seen that the high-quality assets have been very expensive and that our entry point was really too late. In other circumstances, we have found that for whatever reason, and Chesapeake, I think, was a good example of this, there were certain circumstantial above ground issues that were faced that we could get in and get a good value for that.
Kitimat in the unconventional space, we feel very pleased with having the opportunity to buy into that particular project. It's a tremendous resource base, and we like the overall dynamics between the partners now. There's only two partners, and we've got a good partner in Apache with a strong capability on the upstream side. We obviously bring the downstream side. We tend to look at the overall project, and if we can find value in the overall project, we'll go forward. There's not a blanket, gee, everything's overpriced or gee, everything's underpriced right now. It's very resource specific and circumstantially specific.
Okay, great. Thanks.
Our final question comes from Pavel Molchanov with Raymond James. Please go ahead with your question.
Thanks for squeezing me in. Just a big picture question on your overseas unconventionals. One of your European competitors recently made some very downbeat comments on shale development outside North America. You guys have been about as active as anyone in accumulating acreage. I would just like to get your latest thoughts on that.
Pavel, I think we have said that, I know George has said that this is a long-term development opportunity. We have always had the expectation that it would take several years to understand what this play could develop into. You just don't have the same infrastructure in these European countries as you have in the U.S. You don't have the same knowledge of the reservoir. In the U.S., of course, the U.S. had been drilled for decades and decades, and there was an awful lot of reservoir knowledge. That is not the case in Europe. In the U.S., we have a lot of service providers, and a lot of infrastructure. In Europe, that is not the case. We have well-established fiscal and political regimes here. As it relates to hydrocarbons, that's not always the case in Europe.
There are a number of differences between the U.S. environment and the European environment. We have always thought that this would be a longer-term development opportunity.
Just a quick one on Kitimat. Is it still your stance that you will only move forward with the project if you can get crude-linked offtake?
Our belief is that selling Kitimat gas into an Asian market will require, I guess I would say, economic provisioning that will underpin the asset investment. In our belief, the best mechanism for doing that is the oil-linked contract. We believe that that will continue to be the basis that will be needed to spur on the investment for new LNG developments like a Kitimat.
All right. Appreciate it, guys.
Okay. Thank you.
I am showing one follow-up from Paul Cheng with Barclays Capital. Please go ahead.
Hey, Pat, two quick ones actually. One, in page 10 of your presentation, you show in the U.S. downstream a negative bar of $190 million, and you're saying that primarily relate to the downtime. Is that just the repair cost or that's including your estimate of the opportunity cost? And if you not include the opportunity cost, do you have a rough estimate how big that may be?
No, it's an analytical derivation to get you the volume bar. What we're really trying to say there is that compared to last quarter and the volumes that we had running through the equipment and the margins that were achieved back then relative to this quarter and the margins achieved this year, we break that out between the volume and margin analyses here, variance analyses. That's really just trying to say that the primary driver for poor U.S. downstream earnings really had to do with having so much of our equipment down, Pascagoula, Richmond, El Segundo.
That's the estimate opportunity cost to you.
No.
That's fine. I will just follow up with Jeff later. A final one. At the end of the first quarter, from an inventory level, are you roughly balanced or at a normal level, or that you are underlift or overlift? Do you have any underlift, overlifting in the first quarter also?
Paul, we're slightly overlifted, but it's immaterial. It's less than half a % in the first quarter.
Uh-huh. How about at the end of the quarter, are you roughly balanced?
Well, that is the end of the quarter.
That is the end.
Oh, that is the end.
Less than half a %. Yeah.
I see. How about in the first quarter, did you have any overlift or underlift at all?
Well, like I said, we were slightly overlifted, but less than a half a %, so it's not material to our results.
Okay. Thank you.
I'm not showing any other questions. Thank you.
Okay. I'd like to thank everybody for your participation here today, especially for the folks who asked the questions. With that, again, I'll reiterate my appreciation for your interest in the company, and I wish you well for the day. Thank you.
Thank you. Ladies and gentlemen, this concludes Chevron's first-quarter 2013 earnings conference call. You may now disconnect.