Chevron Corporation (CVX) Q1 2012 Earnings Report, Transcript and Summary

Good morning. My name is Sean, and I will be your conference facilitator today. Welcome to Chevron's First Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.

Good morning, and thank you, Sean. Welcome to Chevron's first quarter earnings conference call and webcast. On the call with me today is Jeanette Ourada, 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 on Slide 2. Slide 3 provides an overview of our financial performance. It was a strong quarter financially, among one of the best we've ever had. The company's first quarter earnings were $6.5 billion or $3.27 per diluted share. Comparing the first quarter 2012 to the same quarter a year earlier, our earnings were up 4%. Upstream benefited from higher crude prices, while Downstream improved on gains from asset sales. Return on capital employed for the trailing 12 months was 21%. Our debt ratio at the end of March was just under 7%. 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 4. On Wednesday, Chevron's Board of Directors approved a $0.90 per share common stock quarterly dividend. This is an 11.1% increase in the quarterly rate. This is our 25th consecutive year of higher dividend payments. Also, 2012 is an important milestone for us, as it represents a remarkable 100 years of uninterrupted dividend payments to our shareholders. Turning now to Slide 5. Cash generated from operations was $8.4 billion during the first quarter. At quarter end, our cash balances totaled nearly $20 billion. Jeanette will now take us through the quarterly comparison. Jeanette?

Thanks, Pat. Turning to Slide 6. I'll compare results of the first quarter 2012 with the fourth quarter 2011. As a reminder, our earnings release compares first quarter 2012 with the same quarter a year ago. First quarter earnings were $6.5 billion, over $1.3 billion higher than the fourth quarter. Upstream earnings were up $434 million, driven by higher crude oil realizations and lower operating expenses, partly offset by lower volumes. Downstream results improved by $865 million between quarters, resulting from lower operating expenses, better margins and gains on asset sales. The variance in the other bar reflects lower corporate charges. On Slide 7, our Upstream earnings for the first quarter were $76 million lower than the fourth quarter's results. Realizations lowered earnings by $20 million. A 31% drop in natural gas realizations reduced earnings by about $70 million. This was partially offset by a 3% increase in liquids realizations, which improved earnings by $50 million. About 2/3 of our U.S. crude sales are in the Gulf of Mexico and California, where heavy Louisiana sweet, Mars and Midway Sunset crude markers experienced only modest increases in the quarter. The remaining 1/3 of our U.S. crude sales are in the Midcontinent, where West Texas crude markers increased more dramatically. Lower sales volumes decreased earnings by $15 million between periods. We had one fewer day in the first quarter and lower production resulting from the sale of Alaskan assets, partly offset by higher production in the Gulf of Mexico. Lower operating expenses improved earnings by $125 million between periods, primarily due to reduced maintenance activities and employee costs. The other bar reflects a number of unrelated items including the absence of gains on several small asset sales and higher depreciation expenses. Turning to Slide 8. International Upstream earnings were up $510 million relative to the fourth quarter. Higher realizations benefited earnings by $555 million. Average liquids realizations increased 9%, in line with the increase in average Brent spot prices. Natural gas realizations rose 8% between quarters, contributing about $100 million to the positive earnings variance. Lower liftings across multiple countries decreased earnings by $195 million. Lower operating expenses increased earnings by $250 million, driven by -- primarily by a decrease in employee expenses. Moving to the next bar, an unfavorable change in foreign currency effects lowered earnings by $205 million. The first quarter had a loss of $208 million, compared to a loss of $3 million in the fourth quarter. These foreign exchange effects are primarily balance sheet translation effects, for which there are no direct impacts on cash. The other bar reflects a number of unrelated items, including a net favorable tax effect, partly offset by higher exploration expense, including dry holes in China. Slide 9 summarizes the quarterly change in Chevron's worldwide net oil-equivalent production. Between quarters, production decreased 10,000 barrels per day. Higher prices reduced volumes under production sharing and variable royalty contracts, decreasing production about 7,000 barrels per day. Average Brent spot prices increased about $9 between quarters. Base business, combined with external constraints, decreased production 17,000 barrels per day. The decrease was largely due to the sale of our Alaska Cook Inlet natural gas properties, a planned turnaround in Angola and adverse weather conditions in Australia and Kazakhstan. The Alaska sale reduced production by 17,000 barrels oil equivalent per day. Offsetting these negative variances were the absence of planned turnarounds in Trinidad and at Tahiti and the Gulf of Mexico. Contributions for major capital projects increased first quarter production by 14,000 barrels per day, primarily driven by the ramp-up of Platong II in Thailand and improved reliability at Perdido, partly offset by well shut-ins at Frade in Brazil. In total, Frade reduced quarterly production by about 10,000 barrels per day. As we called out in the interim update, the incremental impact to the quarter as a result of shutting down the field mid-March was about 5,000 barrels per day. Also reducing production in the quarter was the drilling ban and shut in of one producing well required by Brazilian regulators in late 2011. Since the field -- since the full field shut in, the ongoing impact to net production is estimated to be about 33,000 barrels per day. We are progressing with a comprehensive technical study to better understand the geological features of the field. We will resume production in the Frade field only when we are completely satisfied we can restart production safely and when we have obtained the full support of our partners and the Brazilian regulators. Excluding impacts from Brazil, the remainder of our portfolio remains on pace to meet the production guidance we gave in January. We'll give you an update on the second quarter call. Turning to Slide 10. We've had a number of questions recently about the PSCs in our portfolio. We wanted to take a few minutes today to explain exactly how we define PSC-related terms and how changes in price impact our net production. PSCs currently account for about 25% of our net production. In addition, we have contracts with variable royalties that make up about another 12%. In PSC and variable royalty contracts, production can vary as a result of changes in commodity price, level of investment and operating costs. Some contracts also have triggers that reduce our net entitlement when certain rate of return or production thresholds are reached. Each quarter, we give you a price effect variance and a sensitivity to Brent comparing to the prior period. When we say price effect, we are only including the impact on production due to changes in commodity prices. We do not include in this price effect variance other items that may impact net production, such as changes in investment or operating costs. If a nonprice driver were material, we would call it out separately, for instance, as higher or lower cost recovery. We would also call out the impact of triggers if they were material. Under a PSC or variable-royalty contract, the barrels we are entitled to typically decline as prices increase. As illustrated on the chart, this is because fewer barrels are required to recover costs at higher prices. Moreover, as costs are recovered, the split of profit oil typically declines for the IOC participants. We measure this price sensitivity relative to Brent and the relationship is not linear. Each year during our planning cycle, we create price sensitivity curves and evaluate the potential impact of price across the portfolio. The curve changes slightly year-to-year, but the relationships shown have been fairly consistent over the last several years. We're currently in the $110 to $130 per barrel range, and our sensitivity is around 700 barrels per dollar change in Brent. During the planning process, we also review potential triggers. Based on our last review using average 2011 price levels, we do not foresee any material triggers in the next few years. While rising prices do slightly reduce our production volumes, the positive impact on our earnings is much more significant. For our portfolio at current price levels, there is a 40:1 relationship between the impact of higher earnings across the portfolio compared to the reduction in earnings due to price effects. Let me give you an example, and to keep it simple, let's start with a Brent price of $110. A $10 increase in Brent results in about a $3 per barrel increase in earnings margin. We produce roughly 1 billion barrels per year, so that generates about $3 billion in additional annual earnings. The same $10 increase in Brent reduces our production by 7,000 barrels per day because the sensitivity in this range is 700 barrels per dollar change in Brent. The 7,000 barrels per day, valued at our current earnings margin, is worth about $70 million. So at the portfolio level, we gain $3 billion in annual earnings due to higher prices and lose $70 million due to price effects. Or thinking about it as a ratio, we gain $40 of earnings to every $1 we lose to price effects. Governments benefit even more. Higher taxes on our increased revenue, higher revenue from their share of production and additional volumes from the impact we just discussed. All of this is built into our peer-leading earnings margin, which for this quarter is $26.79 per barrel. Based on available competitor results, we maintained our #1 ranking, continuing to outdistance our nearest competitor by over $7 per barrel. Next, let's move to Downstream. Turning to Slide 11. U.S. Downstream earnings increased $663 million in the first quarter. Margins improved earnings by almost $300 million, driven by better refining margins in both the Gulf Coast and West Coast. Refinery maintenance in both regions, plus continued product export demand on the Gulf Coast, drove stronger crack spreads. Lower maintenance activity in the Chevron system across multiple refineries was the primary driver for higher produced volumes, which increased earnings by $100 million. Lower operating expenses increased earnings by $200 million, resulting from lower employee costs and the lower maintenance activity I just mentioned. Chemical earnings increased by $90 million due to higher ethylene margins and stronger sales volumes. The other bar consists of several unrelated items, including lower trading results. On Slide 12, international Downstream earnings were $202 million higher this quarter. Refining and marketing margins fell, reducing earnings by $55 million. This resulted from planned turnaround activities, causing changes to crude slates and marketing margins being squeezed as prices rose. Lower operating expenses increased earnings by $130 million, resulting from reduced employee maintenance and environmental costs. Gains from asset sales in Spain and Canada improved earnings by $195 million. The other bar reflects a number of unrelated items. Timing effects represented a $225 million negative variance due to unfavorable inventory impacts during a period of rising prices. This was offset by a favorable foreign currency effect, net positive tax items and higher chemicals and shipping results. First quarter's foreign exchange loss was about $15 million, compared to the fourth quarter loss of about $85 million. Slide 13 covers all other. First quarter net charges were $504 million, compared to a net $553 million charge in the fourth quarter, a decrease of $49 million between periods. A favorable swing in corporate tax items resulted in a $4 million benefit to earnings. Corporate charges were $45 million lower than in the fourth quarter. You will note we exceeded the upper end of the guidance range we provided in January. If you look back over several years, you will see this is a typical pattern where first quarter net charges have often been 30% to 35% of the full year cost. Thus, we believe our quarterly guidance range of $300 million to $400 million for net charges in all other segments is still appropriate going forward. Now I'd like to turn it back over to Pat.

Thank you, Jeanette. Turning now to Slide 14. Last month at our Security Analyst Meeting in New York, we presented our financial results and gave you a competitive perspective based on information then available for our peers. We now have complete information to fully assess our performance on a relative basis and I want to share the updated slides with you. Our overall ROCE was stellar in 2011 and was also very strong on a segmented basis. In the Upstream, our ROCE was 29%, so we moved into a #1 position relative to our peers. This is a tremendous achievement. In the Downstream, we also delivered a strong performance with an ROCE of 14%. Here, we continue to narrow the gap with the top ROCE peer performer. For the Upstream, we have updated peer results for both realizations and costs as depicted now on Slide 15. Our realizations have exceeded those of our peers for the second consecutive year and are now more than $5 higher than our nearest competitors. Our Upstream costs increased last year, largely driven by higher oil prices and the resulting impact from royalties, taxes and fuel costs. Our cost structure is very competitive. Even with the oiliest portfolio, where costs of producing oil are higher than the costs of producing natural gas, we improved our relative ranking and are now at #2 in our peer group. Slide 16 shows the updated cash margin comparison. With a leading position in realization and a competitive cost structure, we've delivered an unmatched cash margin. Our 2011 -- Chevron's cash margins were nearly $39 per barrel and our #1 position remains intact, outperforming our nearest competitor by 40% or over $10 per barrel. This performance is as a result of the strength of our portfolio and our focus on selecting and executing well on the right projects. Turning now to Slide 17. I'd like to share a few highlights of Chevron's strategic progress during the quarter. In the Upstream, both the Usan project offshore Nigeria and the Caesar/Tonga field in the Gulf of Mexico achieved first production. Both deepwater projects are expected to ramp up to peak production within 1 year. We recently announced the signing of a Heads of Agreement with Chubu Electric to deliver 1 million tons per annum of LNG from our Wheatstone Project. With this agreement, Chevron now has over 70% of our equity LNG from Wheatstone covered under long-term offtake agreements. In the Downstream, we sanctioned a multiyear expansion of our Singapore additives plant. The first phase of the expansion is targeted to start up in 2014. We also continued our Downstream portfolio rationalization efforts, completing asset sales in Spain and Canada. And finally, we signed an agreement for the sale of our Perth Amboy terminal, which we expect to complete later this year. Turning now to Slide 18. Looking ahead, we are keenly focused on executing our major capital projects. We have line of sight on many of the significant milestones planned for this year. We're off to a good start and we intend to keep you updated on our progress throughout the year. In summary, we started the year with strong earnings and healthy cash flows. We are focused on safe and reliable base business operations and progressing our major capital projects. We continue to be disciplined in our investments and in managing our cost structure. And as we just demonstrated with our dividend announcement, we're committed to sharing our success with our shareholders. That now concludes our prepared remarks, and we welcome your questions. So Sean, I'd ask that you open the lines for questions.

[Operator Instructions] Our first question comes from Evan Calio with Morgan Stanley.

And my first question is, since we have Pat on the call, my first question is on the large cash position that you oversee. Net cash is growing again in the quarter. And first, on the dividend with the 11% raise versus a 6% CAGR that drives a higher dividend yield and a more publicized raise by one of your peers. So is this a onetime increase or a design to draw down some of your excess cash position over time? Can you kind of provide some color on why and how you made the relatively higher raise in this quarter? And then secondly with a larger portfolio of capital projects and our view of a higher capital budget in '13, should we expect you to run a relatively higher cash position through 2014, when the free cash flow usually jumps and the new project queues begin to come onstream?

Okay, Evan, let me take a shot at that. First, with respect to our dividend, the 11% rate we felt was fully in-line with the cash generation capability of the firm currently and also as we look out. We have strong confidence in our cash flows coming forward. And also, if you look at our history really since oil prices began to appreciate back in 2004, we've had a CAGR on dividends that has been just about at the 11%. So I think of it as being fairly typical with our previous patterns. Last year, you'll recall that we had 2 dividend increases, that combined, gave us a 12.5% quarterly rate increase. So we feel we've been very competitive on the dividend. I don't want to get into a position of having to step out in front of our Board of Directors on this, so I can't provide any future guidance as to what the remainder part of the year might look like. But suffice it to say that dividends are a very important priority in terms of our uses of cash. It is our, in fact, the #1 priority, so we'll look carefully at that every quarter. In terms of the second part of your question about our cash balances and as we look out in terms of funding needs, I think we have been pretty specific in saying that 2012 is really it's the high C&E year. We've got significant LNG commitments. We've got significant deepwater commitments. And as we get further along into having some of these projects move into -- past the 50% mark on their construction phase, I think we will feel better about relinquishing some of our cash cushion. We really think of that cash cushion as being a risk mitigator to be able to handle commodity price swings and margin swings. These are really important projects that we keep completely on track from a funding standpoint, and so having a little bit of cash cushion as we're on this heavy investment phase seems to make a great deal of sense to us.

Great, I appreciate that. And second, if I may. I know you recently signed a Chubu -- the Japanese power company in long-term offtake for Wheatstone. I mean, maybe have you seen any changes here in this slope or the oil price linkage versus other offtakes signed for Gorgon and Wheatstone, and any comments just on maybe general demand levels? I know you're going to market an additional 10% to 20% of that gas.

Actually, we've been very heartened by discussions that we've had most recently with potential buyers of LNG, whether it be Wheatstone or Gorgon. I would say in a post-Fukushima environment, we haven't had seen any degradation of terms on these contract and discussions that we have had. Our objective for both of the projects really is to get into an 85-ish percent of the offtake under secure long-term agreements, and we're really well on path for both of those major projects.

Our next question comes from Doug Terreson of ISI.

And my question is -- has to do with Slide 15, I think, indicates that operating costs increased by around 10% to 15% annually during the past 5 years. So my question is that with your global perspective, I want to see how you envision this trend evolving in coming years? Or what you're seeing over maybe a term when using the Chevron oil price deck?

Well, actually, Doug, I think the way we look at this is over time, there's been a fairly steady pattern between an increase in the overall cost structure as associated with an increase in the overall revenue structure. So we have not seen any discontinuities of any -- in any way, shape or form to show that. And so I think it would be reasonable if you're thinking about how to project out using your own oil price forecast. I think keeping a somewhat common relationships in that profile would make sense.

Okay, okay. So -- and secondly, I wanted to see if we could get a kind of a summary update or brief update, to the degree possible, on the situations in Brazil and Ecuador? There's been movement on both and just any color or next steps that you can provide on these 2 situations, please?

Sure. Let me start. I'll start with Ecuador here. I think the most important thing that has happened of late is that The Hague has accepted jurisdiction and -- for the case, and has basically reiterated their requirement that Ecuador do -- take all means that it can through the judiciary, through the executive branch, through the legislative branch to prevent enforcement of the judgment anywhere in the globe. So that has been a positive step. In terms of the local Lago Agrio case, it has been remanded or is sent to the equivalent of the Supreme Court in Ecuador, but has not yet been accepted there. So I can't give you any more color there. I can't speak to timing. And I do encourage everybody to continue to look at our website, because we put everything that's happening out there on that website. In terms of Brazil, the criminal case against our employees and the 2 civil cases against the company have been sent or remanded to the Rio de Janeiro court out of the Campos court. And we are still very confident that a transparent and an impartial review of the facts will demonstrate that Chevron and its employees acted very responsibly, acted very appropriately to the incident, that we didn't violate any laws or regulations. We will continue to defend our employees to the fullest extent. And as Jeanette said, we have a technical review of the Frade field underway to better understand the entire geology there. And we won't restart production until we have a complete confidence ourselves in the reliability and the safety and the ability to do so, and we are working lockstep with the regulators and with our partners on that.

Our next question comes from Arjun Murti with Goldman Sachs.

I was wondering if you had any update in terms of cost inflation trends in some of your major Gulf of Mexico projects? You've obviously got Jack/St. Malo, I think Tubular Bells, Big Foot, Buckskin, in various stages of progression. I think Hess on their call alluded to potentially some inflation on Tubular Bells. I'm just seeing if you're seeing that across your Gulf project portfolio?

So, Arjun, actually, we're -- I don't have any specific information to point to. I don't -- there's nothing that's come to mind that is material at this point.

So you're feeling good about the estimates you provided for those projects?

Yes, we are, and we're feeling good about the schedule for them.

Excellent. Can you provide a -- just an activity update on the Marcellus and the Utica? Obviously, gas prices are very low. You do have the carry there. Can you just provide any color on how you're thinking about drilling plans in the Marcellus? And any thoughts on how the Utica's progressing for you, if you have any results you can talk about there?

Sure, Arjun. Okay, I'd say the Marcellus, all of our activities are going according to plan. And in fact, we are ramping up, we will continue to ramp up as the year progresses. We're seeing some efficiencies some cost efficiencies as we had expected. Safety is going well, and as I said, production will ramp up. In terms of the Utica, we're really just doing site preparation, pad preparation at this point and drilling will begin a little bit later in the year, And we'll have to report on that in the second and third quarter calls, but it's really just site preparation at this point in time.

Our next question comes from Ed Westlake of Credit Suisse.

Just a question on the cash statement. Obviously, $8.4 billion cash from operations. Were there any sort of negative effects like working capital in that? Can you quantity that?

Yes, Ed, certainly, I can. Inventory was a big effect in the first quarter here. And actually, as you look at the variance compared to fourth quarter, it's an even bigger variance. So we had a drawdown in inventory in the fourth quarter that released cash of about $0.5 billion dollars, and we had a build of inventory in the first quarter that consumed cash by about $1.8 billion. So you have over a $2 billion swing there in just inventory alone on cash.

Right, okay. So I mean, if I add that back -- cash flow probably before working capital would be somewhere over $10 billion?

Yes, be close -- very good.

Yes, just on the -- the CapEx run rate seems a bit low at the -- just at the beginning of the year. Is that just the usual timing?

Actually, it is. We look at this every year and we have a typical pattern. And first quarter 2012 looks just like the first quarter of the last 7 years in terms of its rate of spending relative to the full year spending.

Right. And then just to follow up on our operational side, any update in terms of activity rates as you perhaps start to delineate some of the shale that you have in the Permian?

I don't know that I've got anything more than what we said just a month ago or so. The overall activity level, our expectation was to have about 200 wells, participation in 200 wells over the course of the year and that is exactly where we exactly where we sit.

Our next question comes from Robert Kessler with Tudor, Pickering & Holt.

Can I ask for a little bit more color around the variability in your operating expense? It just strikes me as interesting that basically both key segments in both the U.S. and international swung the same direction, both last quarter as a negative and this quarter as a positive. And you seem to mention in all cases employee cost as a variable there. It seems to imply that there's some sort of common central variance that's allocated as an overhead to the segments. Severance, for example, or something like that. Is that in fact the case? And if so can you speak to any underlying cost trends unique to the segments on OpEx as opposed to a corporate-level allocation?

Sure. You picked up exactly on some of the messaging that we had there. We've got a compensation system where we have pay at risk for a large part of our employee population. And so the payment is awarded based on performance against targets and also relative competitive performance. So we make an assessment in the fourth quarter of each year as to how well we've done, and 2011 was a strong performance year for us. And that's really what you see as the variance between the costs incurred in the fourth quarter and then the absence of those costs really here in the fourth quarter. That's really one of the primary drivers that you see. In terms of the overall cost structure around the globe, they're really -- other than this one particular variance that I've talked to, there hasn't been anything of significance that is noteworthy or different.

Would you characterize your Upstream kind of global lease operating expenses relatively steady over the last couple of quarters?

Yes, I think it has been fairly steady over the last couple of quarters. If you recall, in 2011, we did call out -- it's about a $1.3 billion increase in operating expense due to a gas for oil swap agreement, and it was replaced with a purchasing agreement in Indonesia. So if you're looking at year-over-year, that may be what you're seeing.

Our next question comes from Jason Gammel of Macquarie.

I had 2 actually, if I could, please. First, Angola LNG. Would you say you're still on schedule to potentially lift the cargo from the project in June? And would you expect that you would be sending most of these cargoes into Asia rather than the original plan of moving to the Gulf Coast? And also, how should we think about production from Angola LNG? Are you guys actually able to recognize equity gas here or is this gas that actually belongs to Senegal?

Okay. So in terms of the cargo, our expectation is that the first cargo would be available and lifted in sort of the middle of this quarter here, certainly by the end of the second quarter. In terms of ownership of that cargo, we believe the first offtaker will be one of the partners, but it's not clear yet. I don't think the decision has been made yet as to who that necessarily will be. And in terms of the gas ownership, it's ours.

And we will recognize production as LNG is produced.

Okay, that's great. And then I'm just trying to think about second quarter volumes at this point. The liftings difference that you showed in the variance chart, were you actually underlifted in 1Q and would expect to make up those volumes in 2Q? And do you have any significant maintenance activity that we should be thinking about for 2Q?

So remember when we showed the liftings, really what that is, is a variance of sales between quarters. So if you just want to look at the under/overlift within the quarter, we had a very slight overlift in the first quarter. It's about 0.5%.

Okay, great. And any planned maintenance?

Well, we won't -- we don't forecast for the second quarter, but we did have about 50,000 barrels a day. Well, that's a variance between -- we had a substantial amount in the first quarter and quite substantial at TCO.

Our next question comes from Paul Cheng with Barclays Capital.

Two questions, if I could. One, Pat, can you talk about whether any of your investment program in Argentina, either in your thinking or that the actual spending level may or may not have changed after the recent nationalization announcement of YPF? The second one in Venezuela, you have, I think, a couple of years ago signed a new agreement with PDVSA on a heavy oil upgrading project, Carabobo 3. I think that you may actually have pay some upfront fees for that or a bonus for that. I want to see if there's any status update on that one.

Okay, sure. First of all in Argentina, I would just say that any time you see an expropriation of assets like has occurred and you're an IOC and you go in under certain contract terms and places all around the globe and you see that happening in a location, it does give you pause. I mean, we do believe in contract sanctity and so it makes you certainly sit up and take notice. In terms of our particular activity, there hasn't been any change. In fact, we did just extend our concession extension in the El Trapial concession for an additional 10 years now. We have a concession now to 2032. So work continues apace there, but we do certainly take notice of it, that's for sure. In terms of Venezuela, both in our Carabobo and our Delta creek project stay, under the evaluation phase, we're working hard to identify appropriate kind of commercial development opportunities there.

So you don't actually have any actual spending or major spending in those project yet?

We don't have any major spending on those projects at this point.

Our next question comes from Paul Sankey of Deutsche Bank.

Back to the balance sheet, Pat, you've got 6.9% debt ratio presented here, which obviously is the gross debt right? So the net debt is closer to over 8% cash positive?

Correct.

And there's $19 billion of cash on the balance sheet. Firstly, I was wondering about the debt paydown. What was the rationale for that, given -- I would have thought it's better to carry more, not less, in this interested rate environment?

Right, and that was just an internal operational event for us. We happened to move from a proprietary issuance of commercial paper to a dealer issuance. We just decided that it wasn't a business we needed to be in. We made the transition at the end of the first quarter here. And while we were doing that transition, we just wanted to get the balances down low just to make sure we didn't have any glitches anywhere. So that's just strictly an internal Chevron operational thing, so I wouldn't read anything into that.

Okay. The -- to retain the AA rating, which I know you've repeated many times, is a key aim, I guess you could probably carry about $10 billion of net debt without threatening that?

Well, actually, Paul, the way I look at it is it really depends on what you're using the borrowing for. If you have significant commercial opportunities or M&A opportunities or whatever, I mean, the substance of the increase in the debt is really important for evaluating for the rating agencies, how they view your creditworthiness. And they take into account a lot more than just the financial parameters as you now know. They look at a lot of our Upstream and Downstream operating performance parameters and assessing that rating. So I think we have a tremendous amount of borrowing capacity under the right circumstances and still have the ability to maintain the AA.

Yes, I guess, what I'm driving at is the scale of the safety cushion you've got here does seem to be kind of extreme with $19 billion of cash. I would have thought that you could be very, very safe and not have to carry quite so much, unless this is going to be the mother of all CapEx overruns.

No, we're not anticipating -- using your [ph] terminology here, I don't want to even use that phrase again, but we're not anticipating overruns on our capital program. It really is a circumstance for keeping some cushion now while we're in this heavy investment period and acknowledging that you've got the opportunity. It may be a very low opportunity or very low probability for excursion south on crude prices or real deterioration in margins, but we want to make sure that we've got enough to live through this heavy investment phase.

Yes, okay, because I was just thinking that kind of more buyback, because you haven't -- the buyback's basically unchanged, right? So...

That's right. And we will look at the buybacks every quarter. We do it every quarter. This quarter, we were focused on the dividend here, which I think was a tremendously strong message about our confidence in future cash flows. Obviously as we go and as every quarter goes by and you've got reasonably higher oil prices, we continue to move the projects through to a higher stage of completion, then obviously, our requirements around cash lessen. And we will evaluate the share repurchase program as we do every quarter with our Board of Directors.

Yes, and I think -- you stated, if I recall, at the Analyst Meeting that you felt that it was going to be kind of end 2013 that you would be, if you like, more confident about CapEx, final CapEx numbers in the safe?

I don't recall giving a 2013 date. I just -- we just know that we've got these significant projects, Gorgon, Wheatstone, Jack/St. Malo, Big Foot, Deepwater, Nigeria, et cetera, where we've got a large profile here for 2012, and certainly, the LNG continuing here into 2013.

Got you. And my second question would be on volumes for this year. Forgive me if I missed this, but is there a guidance? I mean, you had a -- previously had a, if you like, a target for the year. Is there a reset number for that for 2012?

At this point, we're sticking with the guidance that we gave at the very beginning of the year. We did acknowledge here as much information as we have about Frade. George will be on the call here in the second quarter, and we'll update you at that point in time. I'll just say as we look forward, the things that are important to us here, the portfolio is performing on plan, outside of Frade, so we feel good about the number that we gave, again, outside of Frade. Frade, we don't have enough information to be able to say how that will play out here in the second quarter, third quarter, et cetera. The ramp-up of ALNG is an important parameter for us. The ramp-up of Usan is an important parameter for us, and the TCO, SGI/SGP turnaround is an important parameter, and all of those will be important factors in 2012 production.

Our next question comes from Pavel Molchanov with Raymond James.

Just 2 quick Upstream ones. First, U.S. gas production was down about 10% from the fourth quarter. Was that a price-related shut-in?

Well, U.S. gas would be the Alaska Cook Inlet sale. That property alone -- that property sale alone was worth about 17,000 barrels a day on a BOE basis.

Okay, so no shut-ins in your existing assets there?

No, I mean, I will say that we are -- we already have our portfolio and we have been working our portfolio to as minimal dry gas as we possibly can. The only exception that we've got going there would be Marcellus, and Marcellus has got the $1.3 billion carry. I guess it's actually now about a $1.2 billion carry because we've used some of it now since March. But we are definitely focused on liquids-rich plays.

Okay. And then on Liberia, can you just confirm that the first prospect is in fact spudding this week, and maybe provide a time line for results from that?

Well, we -- I can tell you that its spudding is imminent. I hate to go out further on a limb than that, and I really don't have any more information as to how long it will be and what the evaluation period will be, et cetera. So...

[Operator Instructions] Our next question comes from Faisel Khan of Citigroup.

On your -- could you give us a little bit of an update on your exploration -- the exploration wells you drilled in the first quarter? I believe you were still looking for results from Bear's Hump and then you were drilling a well in the Duvernay and the Pearl Mouth Basin in China. And also if you can give us a little bit of an update on what you will try to drill in the second quarter?

Okay, so Bear's Hump is -- the drilling results are basically are still being evaluated. In the Duvernay, we are on our third well, and we are, I guess I would say, encouraged from that standpoint. And what was the third area?

China.

Oh, China. So China, we did have our third dry hole. That was -- the quarter recognized 2 of those dry holes here. And so we've had our third dry hole, 1 each in the 3 blocks. But I will say we have significant acreage there and some of the results were encouraging, and those results will be used then to help us do the next site selection for the follow-on drilling program.

Okay. And then your future lineup here for the second quarter? I believe you're going to spud Coronado or have you already spud that well?

No, Coronado would be later in the year. I don't have a definitive time for Coronado. And most of our drilling rig activity right now in the Gulf of Mexico are focused on development wells. We've got 4 rigs drilling on development wells for the Jack/St. Malo and Big Foot properties. And we have the Santa Ana coming, which actually is in the Gulf of Mexico now and will be soon available for drilling operations.

Okay. Can you give us an update on North American onshore rig activity? How many rigs are you running in North America, and how many of those are devoted to kind of liquids-rich or oil-rich plays?

Yes, I don't have specific rig activity in North America. I can just tell you that in the Marcellus, we continue to execute the evaluation and development plan that we laid out. You'll see a gradual ramp-up in Marcellus production over the course of the year. And Wolfcamp, we were pretty specific in saying we expected to participate in 200 wells there. Those are liquids-rich plays. And I guess I would say from a -- going back to the natural gas versus crude or liquids component there, I mean, all of the gas that we've got here really is liquids focused. Everything that we're producing is cash breakeven or better on the natural gas side.

Our next question comes from Iain Reid of Jefferies.

Can I come back to your production, your PSC sensitivity guidance? This is very useful, actually. And on the trigger part of it, I think you said that there's no triggers coming from rate of return or production thresholds over the next few years. Is it possible to say what oil price you assess that at?

Yes, we used the 2011 average prices, so around $110 per barrel for that sensitivity.

Okay, and that includes fields which have just started up, such as Usan, I presume?

Yes, that included the whole portfolio. We create a curve for each PSC and then combine them together and test each one and then test at the portfolio level.

Okay. And on cost oil -- cost recovery, is it possible to say -- is there any kind of major fields coming out of the major part of cost oil, which is the CapEx recovery over a similar period?

Over that same period, not a lot, I would say. So if you would have asked me 2 years ago, we probably would have talked about Agbami. But I think we've talked about -- we pushed Agbami 2 back a little bit, because the first set of wells were performing exceptionally well. And pushing Agbami 2 investment back a bit has really muted any type of decline you see in cost oil.

Okay, and nothing in Angola?

Nothing material in Angola, no.

Okay, okay, interesting. And on a different topic, could you tell us what the status is of the Nigerian gas blowout?

Yes, actually. So we continue at this point to drill the relief well and to set ourselves up to permanently plug and abandon it. We haven't had any gas detected from the well since the fire stopped burning in the very early part of March. The relief well is fairly close to the intersection point. And our expectation at this point would be that if we're successful there, then we would a permanently abandoned well by the end of May.

Okay. And what sort of production has been shut-in due to this? A few thousand barrels a day, huh?

It's very, very, very modest. It is just 2,000 barrels a day.

And there's been no knock-on effect from regulators, those Brazilian style labor [ph] reaction?

No, we have been working very closely with the Nigerian government and the regulators, the local communities to move this along constructively.

Our next question comes from Kate Minyard of JPMorgan.

Just a quick point of clarification. On Slide 9, you walked through the variability in production versus the prior quarter. And if I caught you correctly, I believe you said the Alaska sale was about a 17,000 barrel equivalent per day impact. But then you also had mentioned the Angola turnaround. So it looks like the Alaska sale might have accounted for the entire block of net production constraints or the impact on the base business? Or am I -- was it a timing issue with the Alaska sale?

Thanks, Kate. There's certainly a lot embedded in that 17,000. So we also called out the negative additional impacts. We had a planned turnaround in Angola, and then we also had some cyclones in Australia and some pretty severe weather in Kazakhstan through the quarter, so those were both negative. But offsetting those, we had turnarounds in the fourth quarter in both Trinidad and then in the Gulf of Mexico, we were installing the water injection module on Tahiti. So both of those were positive impacts for the quarter that kind of offset each other.

Okay, got it, that's clear. And then just one other question on the -- just looking at the tax rate, was there anything about the geographic distribution of the overlift that resulted in maybe a variability in the tax rate? It looks like your tax rate was coming in just a little bit lower than what we would have previously modeled. So is there anything about the mix shift based on the overlift that might have driven that? Or is this kind of the right run rate, kind of all else equal?

Actually, our tax rate came in for the quarter at about a 46% rate, and it's a little higher than we have seen here. And what we really had is just jurisdictional mix effect between -- within international operations as well as within the Downstream. In the Downstream, too, we also had the asset sales, and those came through with essentially a very low effective tax rates. And so by default, that, in fact, makes our overall worldwide income more internationally Upstream-oriented here from a tax rate standpoint, and so that tends to boost the number. If you look forward, I would say our best guidance would be in the mid-40% range on a go-forward basis for us.

Our final question comes from Allen Good of Morningstar.

I just had a couple of questions surrounding your comments on domestic drilling and the preference for liquids over dry gas. Was that in reference just sort of drilling activity or were you referring as well to acreage additions? And if so was there any acreage additions in the first quarter that would be material compared to what the -- I guess, the acreage breakout you gave us during the Analyst Day that would have changed in those allocations significantly?

All right. We haven't had any material acreage additions here in the first quarter. So what we provided back in March is the latest update that we have there. And I was really talking about drilling activity and our focus on production and trying to ensure that we are value-focused in our production efforts and our drilling efforts.

So as far as acreage additions and I don't even want to go as far as saying maybe potentially acquisitions, but as far as dry gas, I mean, is there any more interest here given the level of prices and potential attractiveness of assets? Or is that just something that's completely off the table at this point?

I don't think we want to -- I don't think we ever take anything off the table. I think we're -- I just would emphasize our value approach here. And if there is a combination of opportunity where we can see value down the line, then that's something that we would take a look at, but it has to be able to compete in our portfolio. We've got a very strong portfolio and so the hurdle is already very high for any sort of additions to it.

Okay, and then can you just give us an update on the Downstream assets that were currently being marketed, if there's any sort of progress there or there's any additions to the list that you provided about a month ago as far as what you're looking at to dispose of?

Yes, no additions to the list. The real changes that have happened we called out with Spain and the Envirofuels in Canada and then also the Perth Amboy terminal, but nothing additional other than what Mark presented at the Security Analyst Meeting.

Okay, thank you. I think that's kind of run through the queue here. So I'd like to close off here. Let me just say that I appreciate everybody's participation on the call, and in particular, your interest in Chevron. I want to thank all of the analysts for putting your questions forward because it helps everybody's understanding of the company. Thank you very much, everyone. Goodbye.

Thank you, ladies and gentlemen. This concludes Chevron's First Quarter 2012 Earnings Conference Call. You may now disconnect.