Exxon Mobil Corporation (XOM) Q1 2010 Earnings Report, Transcript and Summary

Good day, and welcome to this ExxonMobil Corporation First Quarter 2010 Earnings Conference Call. [Operator Instructions] At this time for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir.

Good morning, and welcome to ExxonMobil's teleconference and webcast on our first quarter 2010 financial and operating results. As you are aware from this morning's press release, ExxonMobil's first quarter earnings and operating performance were solid, reflecting the strength of our business model during this period of slow and uncertain economic recovery from the global recession. Lower economic activity is impacting near-term supply and demand balances, resulting in weak natural gas prices and downstream margins. Crude oil prices however, are well above levels of a year ago. Chemical performance was strong and continues to reflect the value of our industry-leading integration, scale and geographic diversity. Before we go further, I would like to draw your attention to our cautionary statement. Statements of future events or conditions are forward-looking statements. Actual results, including resource recoveries, volume growth and project outcomes could differ materially due to factors I discussed and factors noted in our SEC filings. Please see factors affecting future results and the Form 8-K we furnished this morning, which are available through the Investors Section of our website. Please also see the frequently used terms and the 2009 financial and operating review on our website. This material defines key terms I will use today and shows ExxonMobil's net interest in specific projects. Now I am pleased to turn your attention to the first quarter results. ExxonMobil's first quarter 2010 earnings and earnings excluding special items were $6.3 billion, an increase of $1.8 billion from the first quarter of 2009, reflecting an increase in crude oil prices and strong chemical results, partly offset by lower natural gas realizations and continued depressed downstream margins. Earnings per share were $1.33, up $0.41 from a year ago. These results include a charge of about $200 million or $0.04 per share, associated with the U.S. healthcare legislation signed into law in March of 2010. During the first quarter of 2010, ExxonMobil distributed nearly $4 billion to shareholders, including dividends of $2 billion and share purchases to reduce shares outstanding of about $2 billion. Again, demonstrating our commitment to return cash to shareholders. With regard to the current status of the XTO transaction, we continue to work cooperatively with the regulatory agencies involved in reviewing the proposed transaction. On March 9, the Dutch competition authority provided regulatory clearance of the pending merger. The applicable waiting period provided under the Hart-Scott-Rodino Act expired on March 15 without the issuance of the second request. On April 20, ExxonMobil filed amendment number two to the S-4 Registration Statement and we continued to progress the SEC review process. Closing of the transaction remains subject to final regulatory clearance and approval by the shareholders of XTO Energy. We continue to anticipate completion in the second quarter. Turning now to our business line results and some of the milestones we have achieved since the last earnings call. First, in the upstream. During the quarter, ExxonMobil completed the remaining sales and purchase agreement and financing arrangements associated with the Papua New Guinea LNG project. The investment for the initial phase of the project is estimated at $15 billion, and first LNG deliveries are expected in 2014. Over its 30-year life, PNG LNG is expected to produce over 9 trillion cubic feet of natural gas. During the quarter, we completed the start up of RasGas Train 7. This is the fourth 7.8 million ton per year LNG Trains brought online by our joint ventures with Qatar Petroleum in the last 12 months. ExxonMobil now has an interest in 12 LNG trains in Qatar with a combined capacity of 62 million tons per year. In total, we expect three major startups in 2010, including RasGas Train 7 in Qatar, the Sakhalin-1 Odoptu project in Russia and the Golden Pass to LNG terminal in Texas. In January, we announced the completion of two-out-of-seven planned extended-reach wells, associated with the Sakhalin-1 Odoptu field. Construction of the Golden Pass LNG regasification terminal continues to progress. Both projects are expected to start up in the second half of 2010. ExxonMobil continues to progress plans to redevelop and expand the West Qurna-1 field in southern Iraq. The agreement with the Iraq Ministry of Oil took effect on March 1. We have completed initial testing to establish the baseline production rate. Our team has been in-country to begin working with our counterparts at the South Oil Company to develop the initial work programs. We are very excited about this significant new opportunity, and look forward to working for the government of Iraq and the South Oil Company to implement this important project. Moving to exploration. We are pleased with our recent drilling results in the Gulf of Mexico and plan an appraisal well on one of our two discoveries on our Keathley Canyon block. As part of our 2010 exploration program, we recently completed our second deepwater well in the Mediterranean Sea, offshore Libya. In Indonesia, we continued drilling in the Mandar block in the Southern Makassar Basin and are planning to drill an additional wildcat well in the Philippines this year. Moving to our unconventional gas exploration, I would like to give you an update on some recent activities across our global portfolio. In the Horn River shale gas play, we continue to evaluate our significant acreage position and have drilled 10 wells over the winter. We are currently preparing to complete and test the two horizontal wells. We are also progressing further shale gas drilling in the Haynesville where we are now drilling our second well. In the Eagle Ford shale gas play, we are preparing for drilling operations and in the Piceance tight gas play, we are continuing Phase 1 development drilling. Drilling also continues on our Marcellus acreage. And finally in Indonesia, we have acquired interest in the prospective coal bed methane acreage in the Barito Basin and are developing our evaluation program. With regard to our deepwater portfolio, in the Black Sea, ExxonMobil completed a farming agreement with Petrobras and the Turkish National Oil Company, TPAO, to explore for hydrocarbons offshore Turkey. Under the terms of the agreement, ExxonMobil will hold a 25% interest in three sub-blocks covering over 7.4 million acres. Together with our partners, we are currently drilling to Samsun [ph] line exploration well. Including our existing expiration licenses in Turkey and Romania, where we have a 50% interest, this brings ExxonMobil's total acreage in the Black Sea to over 16 million acres. In Africa, ExxonMobil farmed in to Statoil's deepwater Block II offshore Tanzania. As a result to the farming, ExxonMobil will receive a 35% interest in the 2.7 million-acre block. This block is considered a frontier exploration area with 2D seismic acquisition completed in 2008. Currently, a 3D seismic survey is being acquired in the block. Turning now to the upstream operating results. Upstream earnings into first quarter were $5.8 billion, up $2.3 billion from the first quarter of 2009. Upstream after-tax earnings per barrel were $14.81 in the first quarter of 2010. Higher crude oil prices, partly offset by lower natural gas realizations, increased earnings by $2.5 billion. Worldwide liquids realizations were up $33 per barrel in the quarter, while natural gas realizations were down $1.56 per kcf from first quarter of 2009. Higher natural gas volumes increased earnings by $190 million, while other effects reduced earnings by $380 million, due primarily to increased exploration and operating expense reflecting higher activity level. In total, first quarter 2010 oil equivalent volumes increased 4 1/2% from the first quarter of last year, driven by major project ramp up. Entitlement volume effects, including price and spend impacts and PSE net interest reductions reduced volumes by 123,000 barrels per day. While lower OPEC quota impacts increased volumes by 70,000 barrels per day. Excluding the impact of lower entitlement volumes, quota effects and divestments, production was up nearly 6%. Project ramp ups in Qatar and Kazakhstan more than offset net field decline. Liquids production decreased 62,000 barrels per day or 2.5% from the first quarter last year. Excluding impacts related to lower entitlement volumes, quota effects and divestments, production was down about 1%. Net field decline was partially offset by the project ramp ups in Qatar and Kazakhstan. Gas volumes increased 1.5 billion cubic feet per day or nearly 15%, versus the first quarter of 2009, driven by new project volumes in Qatar and higher demand in Europe, partly offset by net fuel decline. Turning now to the sequential comparison. Versus the fourth quarter of 2009, upstream earnings increased by just over $30 million. Overall, realizations increased earnings by $310 million due to higher natural gas and liquids realizations. Volume and mix effects were positive $30 million, as the benefit of higher natural gas volumes was partly offset by lower liquid sales volumes. Other items reduced earnings by $310 million, primarily due to negative foreign exchange impacts and the absence of fourth quarter favorable tax items. Liquids production increased 1%, mainly reflecting the impact of new project volumes. Natural gas production was up over 9%, driven by seasonally higher demand in Europe and new project volumes in Qatar. In total, oil equivalent volumes were up almost 4.5% from the fourth quarter. Moving now to the downstream. ExxonMobil continues to progress plans to increase the supply of cleaner burning diesel at our Baytown, Baton Rouge and Antwerp refineries. High-pressure hydrotreater equipment is being delivered to our Antwerp, Belgium refinery and we anticipate projects start up by year end 2010. We also continued our activities to optimize refinery operations by expanding our crude flexibility. This quarter, ExxonMobil ran 30 crudes that were new to individual refineries. Finally, in our Lubes business, the Mobil 1 technology partnership with Vodafone McLaren and Mercedes introduced a new lubricant and fuels package for use in the 2010 season. ExxonMobil also extended its partnership to provide Mobil 1 lubricant technology and engineering support to the Corvette racing team. ExxonMobil works closely with Corvette racing to develop and test new technologies to optimize powertrain performance, improve fuel economy benefits and increased horsepower without sacrificing engine durability. Turning now to the downstream operating results. Downstream earnings in the first quarter were $37 million, down $1.1 billion from the first quarter of 2009. Lower margins decreased earnings by $1.1 billion, driven primarily by significantly weaker industry refining margins. Volume and mix effects increased earnings by $130 million, including the benefits from our refining optimization efforts. Other effects decreased earnings by $80 million, mainly due to negative foreign exchange effects. Turning now to the sequential comparison. First quarter downstream earnings increased by nearly $230 million compared to fourth quarter 2009. Higher margins increased earnings by $610 million due to improved industry refining margins. Volume and mix effects decreased earnings by $370 million, reflecting higher planned maintenance and turnaround activity, as well as lower seasonal fuel demand. Other factors decreased earnings by $10 million. Turning now to our Chemical business. During the quarter, ExxonMobil's japanese affiliate TonenGeneral, announced the successful formation of a battery separator film joint venture with Toray Industries. The joint venture began operating on February 1 and combines ExxonMobil's Lithium-Ion Battery Separator Film business and technological expertise with Toray's plastic film processing precision and polymer science technology, in order to accelerate the development of battery separator films to a greater degree than either company could do alone. In our Polymers business. ExxonMobil announced the introduction of four new Vistamaxx grades. These products offer high performance for flexible film applications, allowing film manufacturers and end-users to achieve sustainability objectives with lower energy usage, reduced material consumption and improved ability for recycling. These new grades are another example of how ExxonMobil's premium products deliver value to both our customers and our shareholders. Turning now to Chemical operating results, first quarter Chemical earnings were $1.2 billion, up $900 million from the first quarter 2009. Stronger margins improved earnings by $480 million, reflecting higher realizations and our continued feedstock advantage. Volume and mix effects increased earnings by $180 million. Sales volumes were up nearly 20%, as volumes recover from the low level seen in the first quarter of 2009. Other effects improved earnings by $240 million, mainly due to asset management activities and the absence of hurricane-related costs. Sequentially, first quarter Chemical earnings increased by $530 million, higher margins increased earnings by $340 million, primarily in our Commodities business. Positive volume and mix effects increased earnings by $30 million. Other effects were a positive $160 million due to Asset Management activities and lower operating expense. Turning now to our Corporate and Financing segment. Corporate and Financing expenses were $800 million during the quarter, compared to $436 million in the first quarter 2009. This includes the charge of about $200 million or $0.04 per share associated with the U.S. healthcare legislation signed into law in March of 2010. These results also reflect the absence of favorable tax effects in the first quarter of 2009. Compared with the fourth quarter of 2009, Corporate and Financing expenses increased by about $540 million, reflecting the expense associated with the U.S. healthcare legislation and the absence of favorable tax effects in the fourth quarter of 2009. The effective tax rate for the fourth quarter was 50%. At the end of the first quarter, our cash balance was $13.7 billion and debt was $9.5 million. The corporation distributed nearly $4 billion to shareholders in the first quarter through dividend and share purchases to reduce shares outstanding. Of that total, about $2 billion was distributed to purchase shares in excess of dilution. Share purchases to reduce shares outstanding are expected to continue at a pace of about $2 billion in the second quarter of 2010. Total purchases for the quarter may be less due to trading restrictions related to the XTO Energy transaction. Yesterday, our board announced an increase in the quarterly dividend of nearly 5% to $0.44 per share. ExxonMobil has paid a dividend each year for more than a century and has increased its annual dividend payment for 28 consecutive years. CapEx on the first quarter was $6.9 billion, an increase of 19% from first quarter 2009. We continue to invest in robust projects through the business cycle to help meet global demand for crude oil, natural gas and finished products. In summary, these results reflect the strength of ExxonMobil's business model. We remain confident that our long-term perspective, financial strength and disciplined investment approach will continue to deliver superior, differentiated results and positions us well for the future. That concludes my prepared remarks. But before I take your questions, and as you can appreciate, I will not have any further comment at this time related to the ExxonMobil and XTO Energy agreement. I would now be happy to take your questions.

[Operator Instructions] We'll take our first question from Jason Gammel of Macquarie.

I just wanted to ask you, we're starting to see now the volumetric effect of the Qatar LNG trends ramping up, and as we think about how that LNG is going to flow, do you have any limitations or expectations for how much volume you'd want to put into the U.S. market versus the European market? And then on a related question, have you taken any cargoes in the Golden Pass yet or can you let us know what the timing on the start of the Golden Pass would be?

As we look at our LNG volumes, we don't have any particular constraints on where that volume goes relative to Europe. As you know, most of our volumes coming out of Qatar, about 2/3 of them, go into the Asia-Pac area under term contracts index to oil. The rest of it does go into liquid markets, primarily in Europe and the U.S. And as you know with the diversion capabilities that we have associated with those volumes, we were able to place them into whichever one of those markets yields the best of value. As we look into volumes specifically into the U.S. Gulf Coast, the LNG regas facility at Golden Pass, it is progressing on the construction. It's expected to start up in the second half. So of course, we haven't taken any cargoes into Golden Pass, but we are looking forward to getting that project up and online later in the second half.

If I could continue on the natural gas theme, you've accumulated a massive position in acreage that's potential for shale in both Germany and Poland. Can you talk about any activity levels that are going on there? Are you shooting this seismic currently? Do you have plans on when you could potentially drill some first wells in those areas?

Sure, we continue to view the European shale acreage that we have is having great potential down the road for shale gas production. And across Europe as you know, we have a very large position in Germany, in both the shale gas, as well as coal bed methane. On the shale gas front, we have drilled three wells already. We continue to drill a number of core holes in the area and we also have some new seismic data that's being evaluated. And again, we're doing lots of core drilling, again, large acreage position, very long holding period. And we are really taking advantage of both of those aspects of that shale acreage to really understand what we've got through very thorough evaluation and then put a development program forward. We also in Germany have significant coal bed methane acreage and we have a long-term multi-year program in place to review, really starting with the existing data that's out there on the acreage, drill several core holes and then analyze what we have and get to work on that. But again, another large position, long holding period and we're really going to go about it in a disciplined pragmatic approach. In Poland, as you know, we have five exploration concessions there in the Podlasie and Lublin basins. Combined, we have over 1.3 million net acres. And here again, we're just getting started. The initial work programs that are underway include geologic studies, and within that, we are reprocessing some existing 2D seismic that are in the process of acquiring new seismic data. So early days across Europe, large acreage position, long holding period and a lot of exploration and analysis to go on in the next several years, but we remain very optimistic on the capability and feel real good about what we have.

We'll next go to Eli Bauman with The Benchmark Company.

I'm wondering what your utilization rates at Al-Khaleej Phase 2 was during the quarter? And then same question for RasGas 7. And did you ramp to full capacity at Qatargas by the end of the quarter so that you actually basically book that?

Let me take those in order. As we look at AKG-2 and we're in the process of ramping that up, we are not at full capacity just yet, but we are filling all of the local demand that's necessary and that project is going very well for us, and we continue to have the ability to ramp that up again to meet demand. If we look at RasGas Train 7, we did bring that up in the first quarter successfully. We did have some -- then go and take some downtime, really as part of the conditioning. But I'm pleased to report today that the train is back online and ramping up. If we look at the trains that started up last year, those trains, four, five, six are all performing very well. They are performing a full capacity and we are very pleased with the progress. In fact, I might make an overall comment on the projects that we started up in 2009. You might recall, we said that for a full year 2010, we would expect the new projects to contribute about 400 kbd year-over-year, and I can tell you we are up to about 370 today. So very pleased with the performance, very pleased with the strong volumes overall in the first quarter. Look forward to getting Train 7 ramped up and heading through the year and continuing with the production growth that we've seen.

And next we'll go to Paul Sankey with Deutsche Bank.

David, firstly, if I could ask something of a technical question, just about the special -- which overolled into question about cash flow, if I could. Just a bit -- I felt into some way you declare no special items in the front page of the report, but then highlight that the $200 million healthcare legislation cost as the highlight of the first quarter, I was just wondering why that wouldn't comprise as special when you highlight it? I know it's a technical question but I'm just perplexed.

Let me see if I can give you a technical answer to that. From an overall materiality standpoint in terms of size, it really doesn't get up to the level of being a special item in our release. We did think it was important to note it upfront in the comments simply because it was probably an item that the investment community was not aware of, and we wanted to make sure that you are aware of that impact on us.

Kind of follow on, on specialties you like is that you clearly had extremely strong cash flow generations here. Almost a quite remarkable number. I was wondering if there was anything in there that you would highlight that isn't simply cash flow from the normal course of operations? Is there any other items that we should be aware of that will, for example, related to asset sales, legal issues or anything else that would have inflated that cash flow working capital as another obvious potential candidate?

Paul, you really hit the nail on the head with your last comment. If you look at the earnings and the asset sales, those as we showed in the press release and supplement, if you look at the first quarter of '09 relative to first quarter of '10, we were up almost for $4.5 billion on cash, about $2.1 billion of that came directly from earnings and asset sales. About another $0.5 billion from depreciation. But really, the balance of about $1.5 billion or so was without a working capital, and just reflected the net impact on payables and receivables from the crude price impacts, so it's really working capital. And then if you're looking sequentially at notionally $4.5 billion there, cash flow, other than the earnings item, it's all working capital. And again, it's all crude payables building across the quarter.

I think you're telling me that the majority this side was the $1.5 billion working capital movement?

In the first quarter relative to the first quarter last year.

Nevertheless, the cash position is strengthening. You've retained the buy back at $2 billion. A technical question regarding that. What are the precise limitations regarding the proxies? If you could just clarify that for us exactly. And then secondly, I'm assuming that you don't intend to continue building cash on the balance sheet. Your CapEx run rate is in line with previous guidance. I guess there's no reason to think that, that changes. You had a very large exploration expense here. I'm not sure that you'll be stepping up exploration spend but that would be interesting if you could address that. And then again, do we fall back to the old idea, given that even now some dividend increase that you've going to the flywheel of buyback later in the year?

Paul, let me see if I can digest all of that in order. Let me hit the -- first of all, let me step back and reconfirm our cash utilization. Of course, it's the same. It's unchanged. We fund the investment plan first. We funded growing dividend after that and then as you said, the additional cash becomes the flywheel for T share purchases and that has not changed. If we look specifically at the T share program, there's actually a couple of restrictions associated with the pending agreement with XTO. As you mentioned, there is a restriction of course once the proxy goes out for -- and then approval by the shareholders. But the other one that you may not be as well aware of is there are restrictions associated with the absolute number of shares that you can purchase, and you are limited to the number of shares you can purchase in the first quarter relative to the average of the run rates from prior periods. And I can tell you, during the quarter, we remained within those limits but did purchase all of the shares that we were allowed to. As we head into the future, and we talk about uses of cash, the guidance for overall CapEx remains at the $28 billion mark for the year. I don't have any updated or different number for you. We did see, as you would expect, with our very active and robust exploration program. That's ongoing. We did see some exploration expense in the quarter both related to drilling as well as other G&G activities and we continue to do that. I think overall though, what we're seeing is strong cash flow results from our operations. The impact of successfully ramping up these projects and getting the production growth. And then as we go forward, as always, we'll maintain our prudent disciplined approach to cash management, not make any mistakes and then use that cash to maximize shareholder value. But no changes in signal or approach.

The buyback is basically held at the same level more for technical reasons than for any cash management reasons. Is there anything more you can say about the exploration expense just in terms of where the dry holes were and whether there's a rate of change there given that you're stepping up your activities that we should consider a run rate?

Let me come back to the exploration program as we ramp that up across the fourth quarter last year and certainly into the first quarter of this year. That program remains robust and active. We did have a couple of dry holes that in the first quarter, one in Libya and one in the Philippines and those did flow through to results. But again, we have a lot of other G&G and seismic related activity going on as we work through our very large acreage position, working on the drillable prospect inventory and certainly getting ready to sustain a very active drilling program across the rest of this year.

And next, we'll go to Paul Cheng with Barclays Capital.

Dave, in the international R&M, I'm still a bit perplexed why we did not see sequentially an improvement in earning from the fourth quarter. Given the European refunding margin may be up about $2, in Asia like Singapore or Japan, our margin is probably up $2 or $3 and you also have used quite a lot of heavy oil in your refining system, which is up about $2 sequentially. When you talk about the mix and margin impact, when I look at the refinery throughput from the fourth to the first quarter, they are down about 31 million barrel or $317 million net impact. That is a $12 per barrel after-tax impact per barrel. Is it awfully high? Is there any other things that we should be aware why we did not see the improvement?

Let me provide some clarity on our overall downstream result, in particularly, as you mentioned, sequentially. What we saw in the first quarter was we had a very large turnaround refinery load that was planned, a lot of planned maintenance. That way, you see the impact on that on our throughput volumes. And additionally, as you mentioned a lot of positive vectors on the margin front in the downstream in various geographies around the world. As you know, those margin improvements tended to trend up over the quarter and actually the best month of the quarter was in March. As it turns out, March was also the peak for us in terms of downtime and capacity that was online again for this maintenance that we had. And of course, given how skewed the timing was of both our capacity being offline for maintenance, as well as the margin improvement, that did impact our ability to capture those rising margins in the quarter. Now I can tell you that all of that maintenance and turnaround activity is going as planned and scheduled. It's going very well. We're in the process of finalizing that as we speak today, given the units are all buttoned up. Looking forward for a successful, safe restart of those units and taking advantage of whatever the market has on offer here in the second quarter.

Dave, can you give us some rough idea then how much is your facility or what is your run rate in March, for your system?

I don't have any specifics on the rates. I can tell you though if you're looking sequentially across the quarter on average, we were down about 225,000 barrels a day on throughput, a big piece of that was in the Asia Pacific area. As you mentioned, things are improving there, but also in the U.S. and Europe. So about on average 200-and-some thousand barrels a day in the quarter. I don't have a specific rate for March versus the other quarter -- the other months, but I can tell you qualitatively, as we brought these units down, March was our biggest month for downtime across the quarter and that leads to the impact that you're seeing or better said the impact that you are expecting.

Can you give some comments about the exploration expense in the first quarter? Do you have a breakdown between the dry hole expense and the G&G in the first quarter?

Let me just mention -- I can tell you on a before-tax basis in the first quarter of 2010, that the total exploration expense was just under $700 million, and now it's up about $350 million on an expense basis from the first quarter of last year. If we flow through to the after-tax effect, it was the bulk of that $380 million impact that we showed in the earnings reconciliation quarter-on-quarter.

So that means that the bulk of the increase is in the dry hole?

The dry hole was certainly a piece of it, but we also again, very active in the seismic area...

Dave, I was just wondering out of that $689 million of the pretax exploration expense, is it possible that you breakdown between the dry hole expense and the G&G?

Well, we don't normally provide that level of detail, but I'll tell you, order of magnitude, somewhere dry hole expense notionally a third, a quarter to a third, somewhere around that level.

A third of the dry hole? You mentioned about the foreign exchange impact versus the fourth quarter, I'm using the fourth quarter as the base, can you give us what is the FX impact? Any tax impact, inventory impact or the price finalization impact by segment?

If we're looking at the downstream results, let me hit the forex for you first. If we're looking in total for the corporation, first quarter of this year versus first quarter of last year...

I can use -- versus first quarter, Dave, do you have that number?

If we look fourth quarter to this quarter, total for the corporation is about $200 million equally split between the upstream and the downstream negative.

$200 million, $100 million for upstream, $100 million for downstream?

Yes, notionally.

How about any tax adjustment differences that we should be aware versus the fourth quarter also?

As we look from the fourth quarter to the first quarter across the company, we did have some positive tax items that I've mentioned in last quarter's earnings call. We did see some of those in the fourth quarter and we don't have any tax effects of any significance this quarter. So you do have the absence of those, but again, it's normal for us to have tax items every quarter. They tended to be positive in the fourth quarter and as we look in the first quarter this year, we didn't have a lot. I can tell you just in the Corp and Fin [Corporate and Financial] area, if you look at the change we had, say sequentially, from the fourth quarter to the first quarter and that number was just over $500 million. And that was basically the tax items and then the healthcare item were the two major contributors there.

How about inventory and also the price finalization impact?

Sure, let me hit price finalization first. Probably interested in sequential mostly or...

Yes.

If I look at sequentially, there's really not much of an impact, about $40 million positive. So again, not a big impact sequentially.

A final one on the cap rate. If we strip out the healthcare reform bill charge, that's about $600 million. I think, historically, you guys more in the $300 million to $500 million. Should we look at -- because you're not doing more activity, so your cap rate expense is going higher in the future or that this is just one of those quarter that you have a higher overall in the future that is still $300 million to $500 million is still on the ballpark a good proxy?

Let's talk about Corp and Fin. And actually, Paul, the prior guidance that we've given is to be between $500 million and $700 million in the Corp and Fin segment. And if you take out the healthcare impact, we'd have been right about $600 million, so we'd have been spot on in between that $500 million to $700 million. And I would say going forward, we would continue to go with the $500 million to $700 million. Obviously, excluding down the road any impacts of XTO, but on an ongoing basis, we would expect to be in that $500 million to $700 million range.

We'll go next to Doug Terreson of ISI.

I just had a couple of questions on, first your Venezuelan assets. Are you guys still on the jurisdictional phase or has the situation moved towards arbitration at the World Bank? Is there any update on that situation or next steps will be appreciated.

Sure, if we look at Venezuela, we are progressing down the path of arbitration. That process is continuing. I don't have any specific update other than that, other than the arbitration process continues.

And also, in Eastern Canada activities seem to be getting a little momentum between Hebron, Sable, Deep Panuke, Orphan, et cetera. And so I wanted to see if you guys could provide an update on this area and whether the effectiveness has changed for ExxonMobil during the past couple of years?

Sure, I think if you're really looking at that part of the world, the biggest impact for us this year is going to be drilling of the next Canada Orphan Basin well. We'll have that -- we would expect to have that down later this year.

We'll next go to Doug Leggate of Bank of America Merrill Lynch.

David, the project ramp ups, can you kind of tell us where we are in terms of how much you've actually got on stream now and what the remainings of ramp up in capacity is likely to be and perhaps a timeline that goes with that please?

Sure, let me start with the projects that came on last year and of course, the first quarter this year. As I mentioned earlier, all of the trains , all of the projects that we started up last year have ramped up and they're achieving their full production rates, Train 7 of course, is the next big one for us. And as I mentioned, that's starting up and moving on AKG Phase 2 is up. As we look later on down the year, we have the Odoptu Project scheduled to start up, sometime looks like in the second half of the year and that project is progressing. Again, though, I think the key metric for you is we talked about getting 400,000 barrels a day year-on-year out of the big projects. We had about 100,000 of that in last year. As we look at the first quarter, we're at 370,000. And I can tell you that in addition to the projects, our operations in the upstream are performing very well. When we look at our work program, we look at our uptime, when we look at the productivity of our heritage assets, everything is performing well. That yielded the very fine performance that you saw in the first quarter. And we would maintain the guidance that we gave in the analyst meeting in terms of full-year production outlook.

I guess the issue which is kind of been, I guess, a favorite of mine over the years is that again when we look at your capture rate despite the increases in production, it's still showing a fairly substantial deterioration compared to your historical trend. Is it a very big change in DD&A that you can maybe share with us, to help us understand what's driving the net income level?

Yes, let me offer a couple of comments on net income. First, I have to say we are very pleased with how the earnings came out in the first quarter. It came in right about we expected just under $15 a barrel overall. We're getting strong contributions from our investments in cutter and elsewhere. So on that part of the business, we're very pleased. If we look at the overall drivers or some of the other drivers of earnings per barrel, we have seen over the last several quarters and this quarter, really the upfront cost of the large projects that we're bringing on stream and we've seen that of course throughout last year and into this year. We've also seen, as I mentioned, the impact of the major exploration program we have underway. And I think as we talked at the analyst meeting, this program, in addition to the unconventional plays that I had talked about, is really focused on several very high potential, high-risk plays in the deepwater. And that activity has been very robust last year and this year, and of course, you do see the impact of that flowing through. If we look at D&D, of course with the ramp up in CapEx, as well as some of the industry specific inflation we saw over the last couple of years, we have seen an impact on D&D but when we look at our projects relative to others, and we look at the capital efficiency of those projects on a competitive basis, we still remain very confident that our projects are advantaged and will do just fine. But again, I think you really have to look at the impact of the high level of activity and the project start ups but not allow that near term or short-term impact overshadow what is truly a successful long-term project development and the buildup we're getting from that and will benefit from that down the road, as well as over the long-term, the benefits are our exploration programs. So if we look across the whole upstream portfolio, and the lifecycle of that portfolio, very active across the board from acreage capture to exploration, to project development, to production, we're very pleased with how that's going and look forward to the long-term results that we'll derive from that.

We'll go next to Evan Calio with Morgan Stanley.

Number one, on the buyback, I know that since Exxon's always in the market and provides a 1Q forward outlook on the buyback rather than announcing a large plan than some of your peers, is there any consideration to a broader release following the XTO transaction? Particularly since you have been limiting your ability to be in the market or potentially to offset any dilution effects from that transaction?

Sure, let me hit the buyback. First of all, Evan, thank you for noting that we are still in the market. I believe we are the only integrated oil company that is still in the market buying shares back, but I'll also confirm your other comment about we only give a one quarter look ahead and I mentioned the $2 billion. I really wouldn't want to comment on anything that we might say down the road other than we'll continue to follow the cash disposition strategy that I've mentioned earlier, and we'll see how that progresses across the year but as we sit here today, no change in signal.

Is your $2 billion that you got it to, that's assuming a close on June 30?

It's assuming a close in the second quarter.

On the LNG side, generally, can you guide on the amounts of volumes that are under long term contracts. I know you've mentioned before but we've had four trains in the last 12 months? Has that changed at all post-RasGas 7? Or whether there's any effort to contract any portion, at least in the post-2015 period, there's going to be a lot of trains that will be marketing gas in the back half of this year?

Sure, let's step back and take a look at that LNG business. As we've said before, if we wrap our arms completely around our LNG business in cutter. About 2/3 of that is going out under term contract. The rest of it is going spot into liquid markets. As you've seen the recent trains startups the big trains that we've started up, that ratio flips around a little bit and you end up on the last few trains of about 2/3 of that going into the spot markets, the more liquid markets and about a third going at term. We don't have any, and again, the big terminals in the U.K. and then down the road in the U.S. We're very pleased with how that portfolios looks and the optionality and divertability that we get from that. We think over the long term, of course, as we have historically, we'll see fluctuations in prices and spreads between oil and gas and prices between various regions. But we like where we're sitting. We like where we are and we don't have any plans to try to change that. We kind of like the mix of contracts and markets that we have now.

We'll go next to Ed Westlake with Credit Suisse.

Chemicals, good results, obviously benefiting from the recovery in the low nat gas prices well as it's oil field portfolio. I mean is there any outlook sentence you can make for the remainder of the year? I'm sure people are talking about weakness given your capacity coming on stream. And then the second question is around tax rates, which seemed a little high in Q1. I'm just wondering if there are any fundings in there or give us some guidance again for how you see the tax?

Sure, let's hit the Chemical business first. As you noted, we had a very strong results in the Chemical business, not just on the earnings side but you saw our volumes were up quite a bit, margins are up quite a bit and as we step back and look at the industry itself, in chemicals, we are seeing some demand recovery in most of the geographies. We benefited particularly well in the first quarter, as the industry particularly in North America saw a lot of downtime and so a number of producers particularly along the Gulf Coast were down for some planned and unplanned maintenance. That tightened up the market a bit and we were able to run our facilities flat out and capture the benefit of that. As we look globally across some of the other markets and as you know with our global footprint, we're kind of located everywhere -- the really growing markets are and the strong markets for our premium products. There again, there is industry tightness in the supply/demand balance because of the lower refinery throughput, but because of our integration and all of these major markets, we were able to optimize across the refining and chemical circuit and then again benefit greatly from the market and what it had to offer. So, very pleased with the results of the business but I think more to the point -- it really demonstrates the benefits that we have in the Chemical business with the scale with the integration, with the premium products, feedstock flexibility, regardless of geography and you kind of saw all of that hitting home at the same time. So we're very pleased. As we look out over the balance of the year, of course, the number one driver of any chemical results is going to be the pace and breadth of any economic recovery globally, particularly in North America and Europe and we'll see how that plays out. We know there is, of course, some new capacity coming on in Asia. The timing and extent of that, we'll see how that plays out. But we're very well-positioned and very pleased with the portfolio we have and are looking forward to benefiting again from our advantages and hopefully, continuing strength and growth in the global economy. If we come back to the tax, the two really big factors, one was the healthcare impact that I mentioned, had an impact on the tax rate both sequentially and year-to-year and the rest of it is just that mix of our businesses, upstream versus downstream, non-U.S. versus U.S. And as you know, that can be very variable quarter to quarter, and that drives those tax rates. And we'll drive them in the future and of course, they're hard to predict given the variability in prices and margins as we watch the business over time. But those are the two main factors for the first quarter change.

So nothing unusual except the healthcare?

No, nothing unusual. We probably have time for one more question.

And that will be from Robert Kessler with Simmons & Company. Robert Kessler - Simmons & Company: This kind of ties back to an earlier question about upstream profitability per barrel but you saw it at higher operating expenses in the upstream year-on-year of about $380 million. Naturally with higher production of 4.5% year-on-year, you'd expect an aggregate increase in cost there. So I'm curious if you could speak to the kind of unit increase, if any, that occurred between periods?

Let me just reiterate, when we looked at that $380 million impact on earnings quarter versus quarter, the biggest effect there well over half was the impact of exploration expense and we also had some unfavorable forex in there given what's going on with currency rates. As we look at our unit OpEx, in the first quarter, relative to the fourth quarter of last year, we haven't seen a really big change. In fact, if we look at the first quarter relative to all of last year, we've actually seen a decline in our unit OpEx rates and again, it gets back to, you go a number of quarters where you're starting up and ramping up projects and you're booking at expense before you get the volumes, you get the volumes ramped up and you get the effect of that. The one thing that I would like to highlight as we look at OpEx overall, of course, everybody saw an impact from higher energy prices and unfavorable forex rates and that certainly had an impact on our business. But as we look across the ExxonMobil portfolio of businesses, we were able to achieve about $400 million inefficiency and other cost management savings in the quarter. So both ending upstream, the benefit of the project starting up and in the downstream and Chemical, as well as the impact of our ongoing programs seem to reduce cost there, which in the downstream in particular is important given the margin environment. I'd have to step back and say across the board, we're pleased with our operating expense performance and pleased with our profitability given all the dynamics that we found in the market. Robert Kessler - Simmons & Company: Do you -- another element that can be quite volatile of course is taxes, other than income? Do you include that opponent in the unit OpEx figures?

Yes, if we look -- there are a number of taxes that we pay and there are some that are included in unit OpEx but I wouldn't have any major impact or anything out of the norm to mention along those lines other than the impact that higher prices have on severance taxes and that sort of thing.

And then I'd like to turn the call back to David Rosenthal for closing comments.

Thank you. I'd just like to briefly conclude and thank everyone for your time and your excellent questions this morning. Appreciate the opportunity to talk about the business and the strong results that we had in the first quarter. And I look forward to talking to you again next quarter. Thank you very much.

And that does conclude today's conference call. Thank you for your participation.