Exxon Mobil Corporation (XOM) Q4 2010 Earnings Report, Transcript and Summary

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

Good morning, and welcome to ExxonMobil's Fourth Quarter Earnings Call and Webcast. The focus of this call is ExxonMobil's financial and operating results for the fourth quarter of 2010. We will refer to the slides that are available through the investor section of our website. Before we go further, I would like to draw your attention to our customary cautionary statement shown on Slide 2. Moving to slide 3, we have provided an overview of some of the external factors impacting our results. The global economy appears to be stabilizing, with signs of modest growth in the United States and Europe and continued strong growth in the developing world, mainly in the Asia-Pacific and Latin American regions. While crude oil prices remain well above the levels of a year ago, natural gas prices have shown only a moderate increase relative to 2009. Downstream, chemical margins have improved relative to 2009. However, some chemical margins have weakened recently as a result of new industry capacity coming online. Turning now to the fourth quarter financial results as shown on slide 4, ExxonMobil's fourth quarter 2010 earnings excluding special items were $9.3 billion, an increase of $3.2 billion from the fourth quarter of 2009. Earnings per share for the quarter, excluding special items, were $1.85, up $0.58 from a year ago. The corporation distributed more than $7 billion to shareholders in the fourth quarter through dividends and share purchases to reduce shares outstanding. Of that total, $5 billion was distributed to purchase shares. Share purchases to reduce shares outstanding are expected to be $5 billion in the first quarter of 2011. Cap ex in the fourth quarter was $10.1 billion, up $1.8 billion from the fourth quarter of 2009, primarily due to the addition of XTO. We continue to invest in robust projects through the business cycle to help meet global demand for crude oil, natural gas, and finished products. The effective tax rate in the fourth quarter was 43%. Moving now to the full year results, as shown on slide 5, ExxonMobil's full year 2010 earnings were $30.5 billion, up $11.2 billion from 2009. ExxonMobil's full year 2010 earnings, excluding special items, were also $30.5 billion, up $11 billion from 2009, which included a charge of $140 million for interest related to the Valdez litigation. Earnings per share for the year, excluding special items, were $6.22, up $2.21 from 2009. The corporation distributed $19.7 billion to shareholders in 2010 through dividends and share purchases to reduce shares outstanding. Of that total, $11.2 billion was distributed to purchase shares. Cap ex in 2010 was $32.2 billion, up $5.1 billion from 2009, mainly due to the addition of XTO and continued progress on our world-class project portfolio, including the Kearl Oil Sands project. Our cash generation remains very strong, with $51.7 billion in cash flow from operations and asset sales. At the end of 2010, our cash balance was $8.5 billion and debt was $15 billion, which reflects the impact of retiring $7.3 billion of XTO debt. We will now provide a review of segmented earnings, starting on slide 6. ExxonMobil earnings increased $3.2 billion from the fourth quarter of 2009, with strong results across all business lines. Upstream earnings increased $1.7 billion, while downstream earnings improved by $1.3 billion and chemical earnings grew by $350 million. Corporate and financing expenses were about $450 million during the quarter, up $190 million versus the fourth quarter of 2009, due mainly to financing activities. As shown on slide 7, ExxonMobil earnings increased $1.9 billion from the third quarter of 2010, mainly due to higher earnings in the upstream, partly offset by slightly lower chemical earnings. Looking now at the full year comparison on slide 8, ExxonMobil's full year 2010 earnings excluding special items were $30.5 billion, up $11 billion from 2009, reflecting strong results in each of our businesses. Upstream earnings increased $7 billion while downstream and chemical earnings were up $1.8 billion and $2.6 billion respectively. Corporate and financing expenses, excluding special items, for the full year in 2010, were $2.1 billion, up $340 million from 2009, due mainly to a charge related to the U.S. healthcare legislation and financing activities. The average quarterly corporate and financing expense in 2010 was $530 million, consistent with our continued guidance of $500 million to $700 million per quarter. Moving next to the upstream results, and beginning on slide 9, ExxonMobil continues to make excellent progress on its global portfolio of high quality liquids projects. Our recent startup at Odoptu performed extremely well during the quarter, averaging more than 50,000 barrels per day of liquids production. We also recently set a new world record for extended reach drilling on the Odoptu OP-11 well. Employing ExxonMobil's proprietary drilling capabilities, this well reached a total measured depth of 12,345 meters, or over 7.5 miles, with a horizontal reach of 11,475 meters, and was completed in only 60 days. In addition, we sanctioned the Arkutun-Dagi project. This project will be developed via a new concrete gravity based structure, which will be located 25 km offshore and will be tied into the existing onshore processing facility. The development will require approximately 45 wells, and is anticipated to have peak production of 90,000 barrels per day gross. Startup of the Arkutun-Dagi project is anticipated in 2014. In Iraq, we have awarded contracts for drilling, well workovers, maintenance services, and early project activity. Our production is ramping up as a result of production optimization, well work, and facility tie-ins. There is currently one drilling rig operating and mobilization of additional rigs is progressing. We are also working with the South oil company to form a new field operating division, which will manage the planning, surveillance, and day-to-day activities of petroleum operations in the field. In Canada, ExxonMobil continues to make strong progress at our Kearl Oil Sands project, which is on schedule for a year-end 2012 startup. Turning now to our gas portfolio, on slide 10, in Papua New Guinea, project execution is underway, including infrastructure development. Contractors for the major worksites have been mobilized, and we are currently commencing pipe lay operations. The pipeline will be approximately 450 miles long, including both the onshore and offshore sections. The pipeline route traverses some extremely challenging terrain on its path from the Southern Highlands to the LNG facility located near Port Moresby. Earlier this month, we signed a joint venture agreement with Qatar Petroleum to progress the Barzan project. This project is expected to supply 1.4 billion cubic feet per day of natural gas, beginning in 2014. The Barzan project will be located in Ras Laffan Industrial City, and will be operated by RasGas Company Limited. The project will produce and process gas from Qatar's North Field, supplying natural gas to local industry in Qatar, and associated hydrocarbon liquids to local and international markets. During the quarter, ExxonMobil announced the completion of an expansion to the carbon dioxide capture plant at our La Barge facility in Wyoming. The expansion has increased the amount of CO2 captured by the plant for third party use by 50%. On any one day, the facility is now capable of capturing a CO2 volume equivalent to the emissions of more than 1.5 million cars. Turning now to our North American unconventional portfolio, on slide 11, we have approximately 70 rigs working across the United States unconventional plays. These rigs are selectively deployed to the highest-priority locations from our large drilling inventory of over 20,000 wells. For example, in the Fayetteville, strong drilling results have doubled gross operated production between the beginning and end of 2010. In the Haynesville, gross operated production has quadrupled over the same period. During the quarter, we acquired Petrohawk Energy's Fayetteville shale assets, which include 150,000 net acres and 95 million cubic feet per day of net production. This represents an attractive addition to XTO's existing position in the Fayetteville play, which now comprises approximately 550,000 net acres. In the Haynesville, we are progressing our joint venture with EnCana across our 108,000-gross acre joint venture area. In both the EnCana joint venture and legacy XTO acreage, we are also drilling and testing the prospective Bossier reservoir in selected wells. We also continue to increase activity in our liquids-rich opportunities in the Eagle Ford and Bakken plays. During 2010, we drilled 15 wells in the Eagle Ford, with 5 wells drilled in the fourth quarter. In the Bakken, we drilled an additional 19 wells during the fourth quarter, bringing the total wells drilled in 2010 to 63. We are also continuing to expand our acreage position in other key North American unconventional plays. For example, in Canada, we added approximately 18,000 net acres adjacent to our core area at Horn River. Turning now to unconventional activities outside of North America, on slide 12, we are actively evaluating our captured, unconventional opportunities in Europe, Indonesia, and Argentina, while also continuing to pursue other global opportunities. In Germany, we completed drilling our first coal bed methane well in the lower Saxony area. In mid-November, we moved the drilling rig to a second location, which is also targeting coal bed methane. The data recovered from these and other planned wells will be used to assess the coal bed methane resource potential in the region. In Indonesia, we hold prospective coal bed methane acreage in the Barito Basin totaling approximately 290,000 net acres. We plan to conduct pilot tests to evaluate the viability of Indonesian coal bed methane as a gas resource and expect to initiate exploration drilling in February of this year. In Argentina, ExxonMobil and YPF acquired 2 blocks in the third Neuquen tender round covering approximately 48,000 net acres. In 2010, we captured a total of 132,000 acres in the Neuquen basin and look forward to the opportunity to work with our partner to evaluate the potential of this acreage to produce unconventional natural gas. Next, I would like to give you an exploration update on slide 13. Starting with our active program in the Gulf of Mexico, evaluation of the Hadrian North oil discovery is ongoing, and we plan to drill the Hadrian-5 well as soon as the permits are granted by the Bureau of Ocean Energy Management. We have submitted all the required permit applications. The Deepwater Champion drill ship is currently being mobilized to Turkey and is on track to arrive in the March-April timeframe. We will utilize the Deepwater Champion for our drilling campaign in the Black Sea, which will include wells in both Turkey and Romania. We have also recently entered into an agreement with Rosneft regarding joint development of oil and gas resources off the Russian coast of the Black Sea. We continue to have success in our established exploration program. We drilled a successful well in the Cepu block in Indonesia, and plan to drill another well this year. We also participated in a successful well near the Jansz field offshore Western Australia. This is the fifth gas discovery in this area in which we have participated during the last 18 months. Turning now to the upstream financial and operating results, starting on slide 14. Upstream earnings in the fourth quarter were $7.5 billion, up $1.7 billion from the fourth quarter of 2009. Stronger worldwide realizations resulted in an increase in earnings of $1.4 billion, as crude oil realizations increased $10.84 per barrel and gas realizations increased $0.29 per kcf. Volume and mix effects increased earnings by $560 million, driven mainly by project startups in Qatar. Other items, primarily higher operating expenses and unfavorable foreign exchange impacts, decreased earnings by $240 million. Upstream after-tax earnings per barrel were $16.37. Moving now to slide 15, oil equivalent volumes increased 19% from the fourth quarter of last year, as a result of the addition of XTO and strong project performance in Qatar. Turning now to the sequential comparison, starting on slide 16. Versus the third quarter of 2010, upstream earnings increased by $2 billion, with stronger global realizations resulting in an additional $1.2 billion in earnings as crude oil realizations increased $9.81 per barrel and gas realizations increased $0.71 per kcf. Higher volumes increased earnings by $870 million as a result of higher seasonal gas demand in Europe and strong Qatar project volume performance. Moving to slide 17, oil equivalent volumes increased almost 12% from the third quarter of 2010, due primarily to stronger seasonal gas demand in Europe. Turning now to the full-year comparison, and starting on slide 18, upstream earnings were $24.1 billion in 2010, an increase of $7 billion from 2009. Higher global realizations, primarily liquids, led to an increase in earnings of $6.5 billion. Higher volumes, mainly from Qatar projects, added another $1.2 billion to earnings. All other items, including unfavorable foreign exchange impacts and higher operating expenses, decreased earnings by $690 million. Moving now to slide 19, volumes grew by 13%, or 515,000 oil equivalent barrels per day compared to 2009. Excluding the addition of XTO, volumes increased a robust 6%, or 250,000 oil equivalent barrels per day, due to strong project performance in Qatar and strong operational results across our global upstream portfolio. For further data on regional volumes, please refer to the press release and IR supplement. Moving now to the downstream and starting on slide 20, during the quarter we continued to demonstrate our commitment to maintaining best in class operations. Recently, our Rotterdam refinery in the Netherlands marked two significant milestones. First, the site marked 50 years of operation and second, it achieved four years without a single lost-time incident, sustaining an impressive safety performance trend. The site also continues to achieve industry-leading energy efficiency performance, consistently placing in the first quartile in the Solomon benchmark studies. Rotterdam continues to be an important hub in the global refining and petrochemical industry, and ExxonMobil has contributed to the economic success of this uniquely positioned international port within Europe. As shown on slide 21, our lubricants business was selected as the preferred supplier of engine oil products for Nissan North America. As a result, Nissan and Infinity dealers in the United States will recommend Mobil branded engine oil products for all dealer-based vehicle service and will have access to ExxonMobil sales and marketing support. ExxonMobil is a market leader in synthetic oils and our global brands continue to grow in this high-value sector of the market. Technology leadership, supply reliability, and customer trust underpin the commercial success of our brands. Turning now to the downstream operating results, starting on slide 22, downstream earnings in the fourth quarter were $1.2 billion, up $1.3 billion from the fourth quarter of 2009. Higher industry refining margins were the main contributor, increasing earnings by more than $1.2 billion. Volume and mix effects decreased earnings by $10 billion, while other factors improved earnings by $130 million, primarily due to lower operating expenses. Moving to slide 23, sequentially, fourth quarter downstream earnings decreased by $10 million. Favorable margin factors increased earnings by $220 million, while volume and mix effects had a positive contribution of $30 million. Other factors decreased earnings by $260 million, including unfavorable foreign exchange effects and higher maintenance activity. The full year comparison for the downstream is shown on slide 24. Downstream full-year 2010 earnings were $3.6 billion, up $1.8 billion from 2009. Higher margins increased earnings by $1.2 billion, reflecting stronger industry refining margins. Volume and mix effects improved earnings by $420 million due to positive mix effects and benefits from our refining optimization activities. Other effects increased earnings a total of $210 million, mainly due to lower operating expense. Turning now to our chemical business and starting on slide 25, ExxonMobil Chemical completed two projects in the fourth quarter of 2010 that support the demand growth of butyl polymers, one of our key specialty businesses. ExxonMobil Chemical has a long history of developing premium butyl polymers used in tire inner liners that help keep tires properly inflated. Our products add value through enhanced performance in areas such as energy efficiency, longer product life, and greenhouse gas emission reduction. In Kawasaki Japan, our joint venture, Japan Butyl Company, has implemented new proprietary process technology. A conventional butyl reaction occurs at cryogenic temperatures, but ExxonMobil has developed new technology that allows the reaction to occur at warmer temperatures, saving significant energy and capital investment. In November, this new technology was awarded the Thomas Alva Edison Patent Award in recognition of its innovation. Leveraging this new technology, the Kawasaki site capacity was increased by more than 20%. During a planned fourth-quarter 2010 downtime at our butyl plant in Fawley, in the UK, we upgraded critical equipment to help ensure reliable supply to our customers. The completion of these two projects in Japan and the UK demonstrate ExxonMobil's commitment to help meet the growing demand for butyl rubber. In addition to the butyl projects, we initiated a 10% capacity expansion at one of our flagship hydrocarbon fluids plants located in Antwerp, Belgium. This expansion will strengthen our supply reliability of high performance fluids used in applications such as water treatment, and is expected to be completed later this year. We also continue to progress one of the largest projects ever executed by ExxonMobil with the world-scale expansion of our chemical site in Singapore. These projects demonstrate our commitment to support growing chemical customer demand while leveraging our advantaged fee stock, products, and technology. Turning now to the chemical operating results, starting on slide 26, fourth quarter chemical earnings were $1.1 billion, up $350 million from the fourth quarter of 2009. Improved margins across our portfolio of commodity and specialty products added $380 million while volume and mix and other effects decreased earnings by $30 million. Moving to slide 27, sequentially, fourth quarter chemical earnings decreased by $160 million. Margin effects decreased earnings by $110 million, primarily reflecting higher feed stock costs. Volume and mix effects reduced earnings by $30 million, driven by seasonally lower volumes. Other effects decreased earnings $20 million. On slide 28, we show the full year comparison for chemical results. 2010 earnings were a record $4.9 billion, more than double 2009. Substantially stronger margin increased earnings by $2 billion, while volume and mix effects added $380 million. Other effects improved earnings by $200 million, primarily due to the absence of hurricane costs from 2009. Overall, the financial and operating results achieved in 2010 were a clear demonstration of the competitive strengths of our chemical company. As chemical demand began to recover from the economic downturn, we leveraged our advantaged feed stock, reliable operations, and unique product portfolio to deliver these record results. Moving to slide 29, while we manage our downstream and chemical businesses separately, we continue to capture benefits from the unique integration and optimization of these businesses. Both businesses delivered strong results in 2010, with combined earnings of $8.5 billion, up $4.4 billion from 2009, reflecting our competitive advantages and the strength of our business model. Moving to slide 30, ExxonMobil's fourth quarter and full year financial and operating performances were strong, and reflect the ability of our business model and competitive advantages to deliver superior results. We maintain a continuous focus on operational excellence and improving upon our industry-leading safety performance. We are continuing with the disciplined execution of our long-term investment plan and we are moving forward on the flawless integration of XTO's world-class organization into our existing portfolio of high-quality assets. As we continue to deploy high-impact technologies and leverage our unparalleled global integration, ExxonMobil remains well-positioned to maximize shareholder value. Finally, I would like to mention two upcoming events. First, in mid-February, we will be releasing our 2010 reserves performance data. Second, as many of you will already have seen, our analyst meeting this year will take place at the New York Stock Exchange on Wednesday, March 9. This will include a live audio webcast beginning at 9 am Eastern, 8 am Central time. ExxonMobil's presenters will be led by chairman and CEO Rex Tillerson. That concludes my prepared remarks. I would now be happy to take your questions.

[Operator Instructions.] And our first question comes from Ed Westlake with Credit Suisse. Your line is open.

Great results this morning. I guess just maybe thinking about the XTO. We're a few months more into it. What is surprising you? And particularly on the liquids side, if you could give us some details on, say, current production in the back and in Eagle Ford and the potential medium-term outlook for your liquids production elsewhere across the lower 48 portfolio?

First of all, thank you for your initial comment. As you would guess, we are very pleased with how the results turned out in the fourth quarter, and of course the full year 2010. In addition to the financial operating results that I mentioned, I would like to point out that once again we had an excellent year in the areas that really underpin our strong financial and operating results. We had record safety performance, we continued our overall focus on risk management and environmental performance, and generally across the portfolio had a very good year. If we look specifically at XTO, I don't know if I'd call it a surprise, but I can tell you that the integration has gone very, very well. We are very pleased with the way the organizations have come together and been able to seamlessly integrate all the strengths that XTO brought to the merger in addition to being able to quickly utilize some of the technology advantages that ExxonMobil had in order to begin to deliver the type of results that we were expecting in terms of improving production as well as lowering op ex. Attrition has remained low. Activity has increased over the year as you've seen, and as I've mentioned in my script. We have had a number of increases in the areas that I mentioned in my text with the 70 rigs we have running, and there has been some particular focus and making sure we have equipment in the highest priority wells, in particular in the Bakken and Eagle Ford. So all in all, we are very pleased with the integration and how things are going, and I'll also tell you that we will discuss XTO and the integration at length in our analyst meeting in March and we look forward to your participation in that.

And then maybe one follow-on. Specifically, just in the cash flow in Q4. Can you just say what the working capital contribution was to that $13 billion? And obviously your cap ex was up to $10 billion in 4Q. Normally you do spend a lot more money in Q4, but what should we expect in terms of, with the project sanctions, cap ex for 2011?

Let's talk about the cash flow first, and then take a look at cap ex. If we look at our cash flow from operations, fourth quarter of 2010 compared to the same quarter last year, of course it's really driven by the higher earnings that we saw and the depreciation and $1.3 billion in asset sales. And that really makes up the bulk of it. The working capital effects were basically negligible, very little. If we look at cap ex in the fourth quarter, it was a strong quarter, fairly typical of what we see in the fourth quarter of most years. We generally see a little higher activity including, of course, partner billings and that sort of thing. But really reflects the ongoing spending in our projects and we'll give you an update for the full year at the March analyst meeting, but it would not be appropriate to take the fourth quarter rate and multiply that by four for 2011. And again, we will give you a fulsome update of our cap ex outlook in March.

Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Your line is open.

I've just got a couple of things. On the [Barzan] project, can you just talk a little bit about how does that compare to what you already have in Qatar? Are these locally priced contracts? And if you could give an idea what the condensate yield would be so we can kind of figure out what that means for the company in 2014? And I have a followup.

That gas will be priced into the local market and as you would expect that price is certainly going to be less than what LNG trades for on a global basis, but then the investment to produce and deliver that gas, of course, is less. As far as what the condensate yield is going to be, I don't think it's going to be way different than other projects, but it's really too early for me to quote an exact number on that.

My followup's more of a housekeeping question on the results. Obviously you had, I think you said $1.3 billion on your previous commentary, I thought it was $1.7 in the release of asset sales on cash flow? Anyway, nevertheless, what I'm looking for is what is the actual contribution to net income from gains on asset sales on foreign exchange, just to give us an idea of what the actual underlying [inaudible] number was. And if possible, I know you might be reluctant to do this, but can you give us an idea of what the contribution was from XTO in the quarter? That would be great.

Let me first of all hit the absolute asset sales cash generation, just so that we're all clear on that. The absolute value of asset sales in the fourth quarter was $1.7 billion, and that was an increase from the same quarter last year of about $1.3 billion. If you look at total asset sales across the company, in the fourth quarter, the earnings impact of those things compared to the fourth quarter of 2010, was minimal, around $200 million. We have an ongoing program, as you know, but there was really nothing substantial in the fourth quarter in total different from the prior-year's quarter.

So the proceeds in the fourth quarter, the $1.7 billion, that was from pre-[inaudible] sales, and that just happened to complete in the fourth quarter? Is that how I should think about it?

Yes. That's from the sales that closed in the fourth quarter, and for example would not include the Canada sale that we announced but hasn't closed yet.

Would you care to give us the XTO contribution?

The XTO earnings contribution, or the XTO cash flow contribution?

Earnings contribution if you have it.

Yes, as you'll see in the 10-K that we'll publish, the fourth quarter total earnings were $120 million, and for the full year about $259 million.

And our next question comes from Paul Sankey with Deutsche Bank. Your line is open.

I hope you won't count this as a question, but could you just give us the volumes associated with XTO as well, and I guess just make sure whether that includes the Fayetteville stuff that you bought?

Sure, are you interested in the full year or the fourth quarter in particular?

Just the comparables for what you just told Doug on earnings.

The total volumes on an OEB basis were about 520, and in the third quarter they were about 498, so we're up quarter-on-quarter. And that includes a minimal bit from the acquisitions, but it's really all XTO.

And then if I could have just a couple more on volumes. First on Iraq, I've read that you're producing about 255,000 barrels a day at West Qurna and if I remember rightly your base production [inaudible] is 244. You want to get to 268 to get to 10% above your base level and hit commercial production. Can you confirm that I'm firstly right on the 255, and secondly, give us an estimate of how long it will take you to hit that 268?

You're correct on your numbers by and large, and we would expect to hit that 268 by the end of the first half of this year.

And then how much would you expect the total full-year contribution to be? How much more growth do you think you'll get in '11 over '10?

Oh I don't know, Paul. I don't have that number. It may be a little too early to tell until we can see where we are at the end of the first half and achieve what we're trying to do there. But I will tell you, as I mentioned, we're on track. Plans are progressing well, and I'll tell you we're very pleased with how things are going and we're looking forward to continuing on the plan we are, mobilizing the rigs that we've got contracted out, and really just continuing the progress that we've been making.

Is there anything to add on the water? I think it's called the common sea water supply facility?

As we mentioned, I think in the past, we're leading that concept selection study and of course what we're trying to do is really provide the sea water that's needed to all the southern Iraqi oil fields for the pressure there. We're currently evaluating the study results, and thinking about what the best way is to proceed, what that timeline might be, and how to go about doing it. But I don't have anything more specific than that today. We're still really looking at it and trying to understand what's in front of us and how we go about working on it.

And then if I could have just a final one on volume it would Qatar. I was just wondering what your exit rate was relative to your, I guess, nameplate capacity there, and how much, therefore, growth we could expect to see delivering in 2011 again? And that will be my last one.

Sure. If I step back I'll say in general all of the facilities that we have started up in Qatar exited the year at capacity. I'll tell you, the run rates and the uptime have just been phenomenal since those projects started up and so we exited the year basically you can think about it as being at full capacity and therefore in terms of a run rate I think we're pretty much spot on.

And therefore the capacity will stay approximately the same in 2011?

I think by and large you would expect it to be generally about the same. Might be up just a little bit, but I think generally about the same.

And our next question comes from Jason Gammel with Macquarie. Your line is open.

I want to ask a couple of questions on your unconventional natural gas portfolio, starting with the Horn River. My understanding is that other operators in the Horn River area have reported reasonably high levels of CO2 and H2S in the gas stream and that's kind of slowed down their drilling this particular winter campaign. Can you talk about the gas quality that you're encountering, and then also confirm when you would expect significant pipeline capacity would be in place to allow you to actually move those volumes to market?

As you know, Horn River is a key focus area in our global unconventional portfolio, in particular in North America. We do have continued active drilling underway in our wells. We're testing those, both our wells as well as wells we have in a joint venture. I'll tell you those wells are performing well and they successfully verified the presence of multiple productive reservoir areas on our lease holds. Without giving totals, we're seeing average test rates of anywhere from a 0.5 to 1.5 million cubic feet a day from a single frak, so we're happy with that. In terms of your question on CO2 and H2S, I'll tell you while we're continuing our evaluation on that, I really don't have any information and couldn't comment on that specific question.

Okay, that's fine. And just a quick followup before I ask my second question, that's per-frak stage you're getting 0.5 to 1.5, and you would theoretically be looking at something on the order of 10-12 frak stages there?

Yeah, that would be about right, maybe a little bit more than that.

And the second question, I believe one of your executives was quoted as saying that [inaudible] in Westfalia would have about 2,100 billion cubic meters of gas potential. I appreciate that you talked about drilling a couple of CBM wells in Germany over the course of the quarter, but given that type of a resource phase when would you expect to really start ramping up drilling activity and putting 10-15-20 rigs into the field?

Well, as we come off of what's been a very successful 2009 and 2010 program, whereas we talked about before we've been testing wells both in the shale plays as well as in now in the coal bed methane, and those are going very well. As we look into 2011 we are going to be continuing with our drilling program, again both CBM and shale gas. We are still evaluating the wells that we have been drilling, and we're in the early evaluation stages. You know, it's kind of like the U.S. unconventional of several years ago. What I can tell you is we did drill our first two coal bed methane wells last year. We're taking a look at those and then we'll really be determining what the exact drilling plan is going into this year. But we would expect that to ramp up a little bit and in fact we're getting ready to spud a well on the western side of the lower Saxony acreage here in the first quarter. So progressing right along, kind of what you'd expect in an evaluation stage of a very large resource potential, and hopefully as the year progresses and we have more well results we'll be able to give a little more, better outlook on what to expect in terms of timing and activity.

And your next question comes from Mark Gilman with The Benchmark Company. Your line is open.

First, on the Barzan project, I guess there's maybe a little bit of confusion with respect to your working interest in the project. Your F&O from last year says 10%. I've seen references to 7% in the trades. Could you clarify what that is and my assumption that it's a production sharing contract. Is that accurate? And then I also have a followup.

Sure, let me start with the first part on our working interest. I can confirm that it is 7%. As we go forward with the project, in terms of what type of fiscal arrangement we have, we're still finalizing those agreements and I really don't have any comments in terms of other specificity at this point.

My followup relates in general to Iraq and how you're accounting for it both in terms of production as well as earnings, and I was hoping you might be able to tie your response in that regard to what looks to me to be an unusual price-spend variance. On slide 17 in your presentation, where price-spend factors versus the third quarter increased volumes by 39,000 a day, if I'm interpreting it correctly. Is there an Iraq element to this? Or exactly what's driving that?

Sure Mark, I'd be happy to hit both of those. Let me start with the second one first. If we're looking at sequential volumes between the fourth quarter and the third quarter, the price and spend impact you saw there of 39,000 barrels a day. That was really generally attributable to much higher activity across a number of countries. We saw a much higher level of spending and again, just across West Africa and a number of other places, but nothing out of the ordinary. If we back up and talk about your Iraq question, we have not booked any significant production or earnings or any of that sort of stuff yet this year. Obviously that will come on later in the year when we hit our improved production target and then as that progresses, we'll be able to get more information on that. But I can tell you in 2010 there just wasn't anything to talk about.

And our next question comes from Paul Cheng with Barclay's Capital. Your line is open.

Talking about Iraq, given that you're sort of the service contract, from an accounting standpoint are you guys going to be able to book reserves related to Iraq? [How are you going to attribute it?]

I think as I mentioned before, and would still say today, we do have an expectation that we'll be able to book reserves associated with our Iraq business.

So should we assume that you did book reserves related to Iraq in 2010?

We'll be giving an update on our reserves performance here in a couple of weeks and I really wouldn't want to get out ahead of that release on either in total or in any specific country.

Okay, that's fine. On XTO, you're saying the total production in the fourth quarter is 520,000 [inaudible] per day? Can you break out for us what is between the liquids and the gas side?

Sure, liquids production was 87 kbd, and then gas production was about 2.6 ncfd.

And that $120 million, the net income, are you talking about for [inaudible] net of hedging? Or before hedging I should say.

Yes. Let's remember the discussion we had last quarter. There's some hedging that goes into earnings, and some that just goes into cash flow. And as you'll see, if I break the $120 million up, it's about $84 million associated with the derivative impact in earnings and about $36 million in the base.

The $120 million is the net income you reported, right?

Yes. In our earnings. Yes.

Right. And what's the $84 then? The mark-to-market loss or this is the realized hedging gain that you referred to?

No. If you think about when we completed the acquisition and we had the mark-to-market all of the hedges at the time, what flows to earnings after that - of course the original booking is based on the [inaudible] - what flows to earnings after that is gains that you make on those hedges as gas prices drop. And so it's that piece that then flows to earnings, and we saw that in the third quarter and then again on the fourth quarter.

So if I look at it without hedging, the impact [inaudible], then the earnings is $36 million only?

Yes, that would be the answer for the fourth quarter.

And a final one from me, any update for Poland?

Sure, I'd be happy to give you an update where we are in Poland. As you know, we have a lot of acreage there and we've been analyzing that, running seismic and doing things really to get ready for a drilling campaign. We do expect as we head into this year we're going to have a couple of wells. In fact, we spud our first well in December, and we would expect to have a couple of those completed this year and really give us an opportunity to just get an early look at that. But I stress an early look, because we're just at the beginning stages of evaluating what we have in Poland. But as part of our global unconventional resource portfolio this is certainly one we're excited to move forward and get the evaluation of that resource under way.

Do you have a total number of wells you target in Poland for this year?

The total number of wells as we look across 2011, I don't have a total outlook for you other than I know we're going to drill the first two. We'll see how those go, what we learn, and then later on in the year we can probably give you a full year outlook.

And our next question comes from Faisel Khan with Citi. Your line is open.

Just had a question on the accounting side. Your effective tax rate dropped sequentially from the third quarter of '10 to the fourth quarter of '10. I was wondering how much of that is the function of the mix of earnings coming from I guess lower tax jurisdictions versus kind of end of the year effects?

You know, that's an excellent question, and I can tell you it's basically all due to just the mix of both the businesses, between the upstream, downstream, and chemical, as well as the mix in geographies. But that's really it in a nutshell.

Okay, understood. And then on the U.S. chemical side, it looks like prime product sales dropped pretty precipitously the third quarter of '10 to the fourth quarter of '10? I'm just wondering what's driving that large drop off in sales?

It's really the impact of a major turnaround we have going on at Beaumont.

Okay. Would you say that had a major impact on the earnings number for the quarter?

It didn't have a major impact. It's part of the volume effect, but the biggest impact we saw quarter-on-quarter was the rapid rise in feed stock cost that really outpaced price increases as we went through the quarter.

And our next question comes from Blake Fernandez with Howard Weil. Your line is open.

Question for you on Brazil. I was hoping maybe you could give us a status update - A) if you could confirm the recent dry hole there and then B) elaborate on any future plans?

Sure, let me step back just a second and give you an update kind of in general on Brazil. The well that we completed in the fourth quarter, the Sabia well, did encounter non-commercial quantities of hydrocarbons, so it was expensed in the fourth quarter. As we look across the block, we are continuing to analyze data from all three wells that we drilled in the block. As you would guess, a block that size and those three wells and different locations and complexities, there's a lot to look at and analyze with our co-venturers. But we're going to take some time, review all of that information, and then determine the next steps for our evaluation plan for the block. So we've got a lot of information, and there's a lot of analysis to do, and as we progress what we're going to do next, we'll provide that update in subsequent quarters.

And my second question was on the Gulf of Mexico. I'm just curious if you have any experience to date with permitting, what the status is on the well containment system, and if that's being embraced by the BOEM?

Sure, let me start first with the drilling. The most important well we have is the Hadrian-5 well. You might recall that was an appraisal well on our oil discovery up in Keathley Canyon. We were just about to commence operations when the moratorium started. I can tell you that a revised permit application has been submitted to the BOEM and we're waiting on their approval. We feel like we've submitted all the information that's required and we are anxiously awaiting those permits to be approved so that we can get after that well. When we talk about the marine well containment system, we continue to make really good progress on the overall, the larger project that we talked about. We also have work continuing on the interim and expanded containment systems that we can have available literally very soon. I think the interim system, everybody can look forward to that being available here very quickly, and then the larger one that we've talked about before a little later on. So good progress being made there, and we look forward to getting both of those done and getting on with drilling.

And our next question comes from Doug Terreson from ISI Group. Your line is open.

I had a question, first of all about ENP. In Indonesia, the Natuna gas seems to be making some progress and obviously this could be significant for you guys at some point. And so I just wanted to see if you'd comment on the next steps for 2011 for that project, and also whether it's likely to be pipeline gas, or LNG, or whether it's too early to know

Sure. If you look broadly in Indonesia, of course this was a big year for us with the progress we're making in Cepu, the wells that we successfully drilled here last year. So that's progressing. You did note Natuna. Yes, there has been progress in there. In December we signed a heads of agreement with Pertamina, and that's going to provide us a framework for negotiation of a new production sharing agreement with the government, and we look forward to progressing those discussions and getting mutually agreeable [terms] for development sometime later this year. So we would expect that to progress further. Now, as we look at Natuna in terms of the ultimate disposition of the gas, or how we're going to get that gas to market, obviously as you would guess we're looking at how we're going to maximize the value of that resource, but I'll tell you, it's too early to comment which way we're leaning, okay?

I see. And also, chemicals results were great, and so my question is do you have the annual earnings breakdown yet between the specialty and the commodity businesses?

Sure, I have that, but I will say to start off with, when you look at our chemical earnings we saw tremendous strength in both the commodity and the specialty business. The commodity business did exactly what you would expect when you have an ability to leverage your feed stock advantage. And then the specialty business, we saw nice volume increases in there, and with the margins that we have. And then if we look at the full year basis for those I think the commodity piece of that was the bulk of the year. Certainly the bulk of the year to year increase, I can tell you that. I don't have the absolute values here in front of me, but it drove the bulk of the year to year change.

And our next question comes from Pavel Molchanov from Raymond James. Your line is open.

First on PNG LNG, we've seen a lot of comments about cost escalations, labor shortages in Australia, and of course recognizing that it's not quite the same scenario in PNG, I was wondering if you have any comments on how that might be affecting your PNG project.

Sure, I'd be happy to give you an update on the PNG project. It is underway, as I mentioned in my script. We've got infrastructure development underway. We've got a lot of work going on with our contractors. It is progressing right along. But I would tell you that we really haven't seen any impact on the PNG project from the items you noted. We're on track for a 2014 startup. Security, of course, is a very big focus area for us, and I know occasionally in the press you read about security items, but those are being managed with a very comprehensive risk management program in country. So like any project - large, complicated project - there are things that happen from time to time, but nothing out of the ordinary and we remain on track to start up that project on schedule.

And then just a quick followup on Hadrian-5, once you get the permit, if and when that happens, what kind of completion time do you guys expect?

I don't know exactly how long the completion time is expected. I do know that once we get the permit, we're going to be able to get after it and get the well underway. And I would expect it would be typical of any Gulf of Mexico well in that depth of water, but nothing out of the ordinary.

And your next question comes from John Herrlin with Societe Generale. Your line is open.

Thank you. Three quick ones. David, you mentioned unconventional activities both in North American and abroad. Could you give us a sense of what spending will be like on unconventional in 2011 versus 2010?

I don't have an outlook for you yet for 2011. We will talk about that, of course, as part of our cap ex outlook in the analyst meeting in March. So I just have to ask for you to wait until then and we're going to give a pretty fulsome outlook on that business. It will be an active year, but the actual cap ex we'll have to give you in a few weeks.

Okay. Next one: With XTO, could you give us a sense of what kind of completion optimization success that you've had? Were you able to increase drilling times, reduce frak costs, that sort of thing?

I can tell you - of course it's still early, we're only 6 months into this - we have been able to take some ExxonMobil technology and apply it to some of the wells that are being drilled and do some crossover of that. We have seen some success in that regard, but again the specifics of which I think we'll save for, again, a more fulsome discussion at the analyst meeting in March. We'll talk a lot about the integration and the progress we're making. But rest assured, we are transferring technology. We are transferring best practices back and forth, and again, we'll talk more about that in March.

Okay. And last one from me, David. What were your net capitalized costs at the end of the year - upstream?

If you're talking about the total capital deployed in the business?

Well no, your net capitalized cost. Like in 2009 it was about $85 billion. I was wondering where you ended up last year.

We don't have the segmentation yet for the businesses.

And our next question comes from Ian Reid from Jeffries. Your line is open.

Would you mind if I asked you a question about your energy outlook?

Sure, that would be just fine.

What's obvious from that is your more bullish view of natural gas demand versus coal compared to other commentators. I'm wondering if you could just characterize Exxon's view of natural gas versus coal, how it differs to other people, and what's kind of driving the numbers you're coming up with here?

Sure. Well, of course, the primary growth in the usage of natural gas is going to be in power generation, and I think if you've seen our energy outlook you see the growth in that. One of the fundamental reasons for the numbers that we've tabled, of course, is an assumption on cost of carbon, however form that might come, would certainly drive some conversion of coal to gas. I think one of the other things that we have out there as you see the economy ramp up and as you see the demand for power generation to ramp up, certainly the source of electricity generation that can be brought on the quickest, particularly here in the U.S., is fueled by natural gas. So if you're looking short-term increased industrial demand, increased need for power generation and electricity, and then longer term as we go out and look at the dynamics, the assumption that there will be some cost of carbon included. And as you know, natural gas has 60% less GHG emissions than a typical coal fired plant does, so you'll have an inherent competitive advantage.

Okay. Thanks for that. Can I ask a question on the results? In European gas, are you seeing further pressures from your customers for your oil linked gas to try and renegotiate the contracts to try and reduce the oil linkage and to focus that more on spot?

Certainly if you look at the European gas market this year, it's been a good year, very robust demand, particularly in the fourth quarter. Prices have held up well, and it's been a good market. I tell you, I wouldn't want to comment on specific commercial discussions or commercial agreements that are underway other than saying that the strategy we've implied in Europe, which is both a supply with indigenously produced gas on the continent as well as the ability to bring cargos of LNG out of Qatar into the UK and into the Adriatic and benefit from a nice strong spot market. All of that business, as we look across the year, particularly in the latter half, has been very successful, but I wouldn't attribute that to any one contract that we have in place, or comment about what's going on with those other than to say diversified portfolio, diversified contract mix, divertible cargoes. That strategy has been very healthy for us this year.

You just mentioned divertible cargoes. Is it possible to say what quantity of diverts you managed in the quarter?

I don't have a specific number for the quarter. I think if you think about in general, we've said the cargoes coming out of Qatar in total about two-thirds of them run out in long-term contracts and the balance are spot and those are divertible, which is kind of how the big picture looks there. And then again, we've benefited very well for that here in the year.

And our next question comes from Jacques Rousseau from RBC. Your line is open.

Just a quick question on asset sales. I guess in the quarter you said about $1.7 billion of asset sales, which I think was about the same amount as you had sold through the first three quarters. So my question is in prior years you seemed to have sold more in higher commodity price environments. Is that something we should look forward to in the next couple of years, assuming oil and such stays around where it is?

That's an excellent question. I have to tell you though, the pace of our asset management program is not driven by swings in commodity prices and margins. We have a fairly robust ongoing program, and it's very disciplined in its approach and we don't have any specific targets year by year or business by business. What you do see, though, and have seen very strongly this past year, is a program where - it sounds simple, but if some assets of ours are worth more to others than they are to us, we're happy to sell them. And that's irrespective - you can do that in a low-price or margin environment. You can do that in a high price environment. But it's really just an ongoing disciplined program, and I wouldn't have an outlook for 2011. We'll just progress the year like we did last year, and see what opportunities are presented.

And we have no further questions at this time.