John Rielly - Chief Financial Officer, Principal Accounting Officer and Senior Vice President John Hess - Chairman of the Board and Chief Executive Officer Gregory Hill - Executive Vice President, President of Worldwide Exploration & Production and Director Jay Wilson - Vice President of Investor Relations

Edward Westlake - Crédit Suisse AG Jeffrey Dietert - Simmons & Company Evan Calio - Morgan Stanley John Patrick Moore Pavel Molchanov - Raymond James & Associates Mark Gilman - The Benchmark Company, LLC John Herrlin - Merrill Lynch Sven Del Pozzo - John S. Herold Paul Cheng Arjun Murti - Goldman Sachs Group Inc. Douglas Leggate - BofA Merrill Lynch Paul Sankey - Deutsche Bank AG Blake Fernandez - Howard Weil Incorporated

Good day, ladies and gentlemen, and welcome to the Hess Corporation Fourth Quarter 2010 Earnings Conference Call. My name is Fab, and I'll be your operator for today. [Operator Instructions] I would now like to turn the conference over to Mr. Jay Wilson, Vice President, Investor Relations. Please proceed.

Thank you, Fab. Good morning, everyone, and thank you for participating in our fourth quarter earnings conference call. Earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. As usual, with me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President, Worldwide Exploration and Production; and John Rielly, Senior Vice President and Chief Financial Officer. I'll now turn the call over to John Hess.

Thank you, Jay. Welcome to our fourth quarter conference call. I would like to review key achievements for 2010 and provide some guidance for 2011. Greg Hill will then discuss our exploration production business, and John Rielly will go through our financial results. Corporate net income for the full year 2010 was $2.1 billion. Exploration and Production earned $2.7 billion, and Marketing and Refining loss, $231 million. Our improved results reflect higher crude oil production and selling prices and increased retail and energy marketing earnings, which more than offset the impact of weaker refining results. Included in our financial results is a provision of $289 million to reduce the carrying value of our interest in the HOVENSA joint venture refinery to $158 million. This write-down, which reflects our outlook for continued weakness in refining margins, reduces our share of the HOVENSA joint venture refinery to less than 1% of Hess' capital employed. In 2011, our company's capital and exploratory expenditures are budgeted to be $5.6 billion. Substantially, all of our spending will be targeted to exploration production, with $3.1 billion for production, $1.6 billion for developments and $900 million for exploration. We expect to fund our capital program from internally generated cash flow. With regards to Exploration and Production, in 2010, we replaced 176% of production at an FD&A cost of about $23 per barrel. At year-end, our proved reserves stood at 1.54 billion barrels of oil equivalent, and our reserve life was 9.9 years. In 2010, we increased our crude oil and natural gas production to 418,000 barrels of oil equivalent per day from 408,000 barrels of oil equivalent per day in 2009. In 2011, we forecast crude oil and natural gas production will average between 415,000 and 425,000 barrels of oil equivalent per day. This forecast includes a net reduction of about 16,000 barrels of oil equivalent per day, resulting from the previously announced sale of non-core natural gas assets in the U.K. North Sea, which is expected now to close in the first quarter. Last year, we expanded our portfolio of unconventional resources. In the Bakken oil shale play in North Dakota, we completed the acquisitions of America Oil & Gas and TRZ Energy and commenced the expansion of key infrastructure. In addition, we acquired acreage in the Eagle Ford in South Texas and formed a partnership with Toreador Resources to explore the unconventional oil potential of the Paris Basin in France. In Norway, we increased our interest in the Valhall field to 64% from 28% via strategic asset trade with Shell and an acquisition from Total. In the Gulf of Mexico, we doubled our working interest in the Tubular Bells field to 40% and took over as operator. In 2011, we will be working with our partners to move this project towards sanction. With regard to Marketing and Refining, our full year 2010 financial results were lower than 2009. Our HOVENSA joint venture refinery was negatively impacted by the continued weak margin environment, higher year-over-year fuel costs and unplanned downtime. In addition, both HOVENSA and our Port Redding New Jersey facility completed FCC turnarounds in 2010. This morning, HOVENSA announced that it would reduce crude oil distillation capacity to 350,000 barrels per day from 500,000 barrels per day by shutting down older, less efficient units. We expect this action will reduce HOVENSA's operating costs and capital expenditures and make it a more competitive and efficient refinery, producing a greater percentage of high-margin products. In Retail Marketing, 2010 convenience store sales were up by more than 4%, while average fuel volumes per station were down by 1%. In Energy Marketing, we generated stronger earnings primarily as a result of improved margins in our natural gas and electricity businesses. Our financial position remains strong. Our debt-to-capitalization ratio at year-end was 24.9%, essentially unchanged from 2009. In 2010 August, we issued $1.25 billion of 30-year notes. Proceeds were used for the acquisitions of an additional 8% stake in the Valhall field from Total and TRZ Energy. In December, we issued 8.6 million shares of stock to complete the acquisition of American Oil & Gas. Our company made significant progress in 2010 in increasing our reserves and production and building our position in unconventional resources. We are committed to maintaining a strong balance sheet so that we will be able to fund our portfolio of attractive investment opportunities to generate long-term profitable growth for our shareholders. I will now turn the call over to Greg Hill.

Thank you, John. Let me begin with production. In 2010, crude oil and natural gas production averaged 418,000 barrels of oil equivalent per day, which was up 2.5% versus 2009. This production growth was underpinned by the Bakken, the Deepwater Gulf of Mexico and better operating performance across the portfolio. In 2010, we added proved reserves of 274 million barrels of oil equivalent at an FD&A cost of about $23 per barrel of oil equivalent, yielding a reserve replacement ratio of 176% and an R/P ratio of 9.9. Including this year's results, our five-year average reserve replacement ratio is 169%, and our average FD&A cost is about $18 per barrel of oil equivalent. As John mentioned in his remarks, 2010 was very active in terms of rebalancing the portfolio. Unconventional resources are becoming an increasing proportion of our mix and are commanding a significant part of our 2011 investment program. In 2011, we plan to invest about $1.8 billion in the Bakken oil shale play in North Dakota, where we currently hold more than 900,000 net acres. On average, we expect to have 18 rigs operating in 2011. We will also continue to invest in infrastructure, including the construction of a new crude oil rail loading and storage terminal, which is expected to be completed in the first half of 2012. In addition, we are expanding our Tioga Gas Plant to 250 million cubic feet per day from 100 million cubic feet per day, with completion expected in the second half of 2013. With the acquisitions of American Oil & Gas and TRZ Energy completed, we intend to utilize the combination of both single and dual lateral wells to get core acreage held by production and to optimize the development of the field. In 2010, net Bakken production averaged 15,000 barrels of oil equivalent per day, and we exited the year at our target rate of 20,000 barrels of oil equivalent per day, excluding production from the American Oil & Gas and TRZ Energy acreage. In 2011, net production is expected to average about 40,000 barrels of oil equivalent per day. Later this year, after we have drilled some additional wells and analyzed the data on the American Oil & Gas and TRZ acreage, we will update our longer-term production forecast. In the Eagle Ford shale play in South Texas, we acquired about 90,000 net acres in 2010, primarily focused in the condensate window. We have already drilled three wells and results thus far have been encouraging, with good shows and log response. Over the course of the year, we plan to drill an additional 15 wells. In the Paris Basin in France, we plan to spud our first well toward the end of the first quarter. Our 2011 program will consist of six exploration wells and will include extensive data collection and testing. We have also been very active in China. In 2010, we signed a joint study with PetroChina to evaluate a tight oil plan at Daqing Field, the largest oilfield in China. That study is now complete, and we are in discussions with PetroChina about expanding this study area to include other unconventional opportunities. In addition, last week, we signed two joint study agreements with Sinopec involving other unconventional opportunities in China. To summarize, we are pleased with the progress we have made in building our unconventional portfolio. We will continue to evaluate expansion of our existing positions and pursue new unconventional plays, both domestically and internationally. Our capital program in 2011 also includes further investment in Valhall, where we continue redevelopment; the Deepwater Gulf of Mexico, where we continue to advance the development of the Pony and Tubular Bells fields; and in Australia, where we continue appraisal of Block Western Australia 390-P. Now let me turn to our exploration program. In Brazil, the Sabia-1 well and Block BM-S-22 encountered non-commercial quantities of hydrocarbons. As a result, we expensed both the Sabia and Azulão wells in the fourth quarter. We will continue to analyze the data from the three wells drilled, and we'll work with the ANP and our partners Exxon Mobil and Petrobras to determine next steps for evaluation of the block. At the end of December, we spud a well on our Cherry prospect on Northern Red Sea Block 1, in which Hess has an 80% working interest. The well is expected to be completed late first quarter, and a second well is planned on the block immediately following completion of drilling at Cherry. In Ghana, we plan to spud a well on our Tano Deepwater Cape Three Points south block in February. In Indonesia, we plan to begin drilling on our Semai V block in late February or early March, depending upon rig arrival from Murphy. In Brunei, where Hess has a 13.5% working interest on Block CA-1, the operator, Total, is planning to spud the first of several wells during the third quarter. In closing, I'm once again very pleased with the performance of BP in 2010. We delivered strong operating performance, maintained solid cost discipline, continued to advance our portfolio of material exploration and development opportunities and strengthened our growth options for the future. Thank you. Now I'll hand the call over to John Rielly.

Thank you, Greg. Hello, everyone. In my remarks today, I will compare fourth quarter 2010 results to the third quarter. The corporation generated consolidated net income of $58 million in the fourth quarter of 2010 compared with $1,154,000,000 in the third quarter. Excluding the items affecting the comparability of earnings between periods, the corporation had earnings of $398 million in the fourth quarter compared with $429 million in the third quarter. Turning to Exploration and Production. Exploration and Production operations had income of $420 million in the fourth quarter of 2010 compared with $1,277,000,000 in the third quarter. The fourth quarter results include an after-tax charge of $51 million related to dry hole cost associated with the Azulão exploration well located offshore Brazil on Block BM-S-22. The costs related to this well, which were previously suspended in 2009, were expensed in the fourth quarter of 2010 following the unsuccessful Sabia well. Third quarter results included net after-tax income of $725 million from items affecting comparability of earnings between periods. Excluding the effect of these matters, the changes in the after-tax components of the results are as follows: Higher selling prices increased earnings by $99 million; lower sales volumes decreased earnings by $146 million; increased cash costs reduced earnings by $32 million; increased depreciation reduced earnings by $16 million; all other items net to an increase in earnings of $14 million; for an overall decrease in fourth quarter adjusted earnings of $81 million. In the fourth quarter of 2010, our E&P operations were under-lifted compared with production, resulting in decreased after-tax income in the quarter of approximately $50 million. In addition, earnings were lower in the fourth quarter by approximately $17 million due to deliveries of natural gas to settle take-or-pay obligations at the JDA for volumes previously paid for by the buyers at a lower price. All take-or-pay obligations with the buyers at the JDA have now been settled. The E&P effective income tax rate was 44% for the quarter and the full year of 2010. Turning to Marketing and Refining. Marketing and Refining operations generated a loss of $261 million in the fourth quarter of 2010 compared with a loss of $38 million in the third quarter. In the fourth quarter of 2010, we have recorded an after-tax impairment charge of $289 million to reduce the carrying value of our equity investment in HOVENSA to the estimated fair value. Excluding the impact of this impairment, refining losses were $19 million in the fourth quarter compared with $50 million in the previous quarter. The corporation's share of HOVENSA's results of operations was an after-tax loss of $30 million in the fourth quarter compared with $51 million in the third quarter. During the fourth quarter, HOVENSA reduced LIFO inventories. The effect of the LIFO inventory liquidation was to improve the corporation's share of HOVENSA's results by approximately $34 million after income taxes. Port Redding reported income of $11 million in the fourth quarter, up from $2 million in the third quarter. Marketing earnings were $37 million in the fourth quarter of 2010 compared with $40 million in the prior quarter. Trading activities generated income of $10 million in the fourth quarter compared with a loss of $28 million in the third quarter. Turning to Corporate and Interest. Net corporate expenses were $43 million in the fourth quarter of 2010 compared with $26 million in the third quarter. Net corporate expenses were higher in the fourth quarter, primarily reflecting the timing of expenses, including insurance costs and pension plan settlement charges related to employee retirements, partially offset by an increase in the effective state income tax rate. After-tax interest expense was $58 million in the fourth quarter compared with $59 million in the third quarter. Turning to cash flow, net cash provided by operating activities in the fourth quarter, including an increase of $444 million from changes in working capital, was $1,478,000,000. Capital expenditures were $2,341,000,000. All other items amounted to an increase in cash of $118 million, resulting in a net decrease in cash and cash equivalents in the fourth quarter of $745 million. We had $1,608,000,000 of cash and cash equivalents at December 31, 2010, and $1,362,000,000 at December 31, 2009. Our available revolving credit capacity was $3 billion at December 31, 2010. Total debt was $5,583,000,000 at December 31, 2010, and $4,467,000,000 at December 31, 2009. The corporation's debt-to-capitalization ratio at December 31, 2010, was 24.9% compared with 24.8% at the end of 2009. In addition to the 2011 production and capital expenditure guidance given by John Hess, I would like to provide estimates for certain 2011 metrics. Our E&P cash operating costs are expected to be in the range of $15 to $16 per barrel of oil equivalent produced. Depreciation, depletion and amortization charges are expected to be in the range of $14.50 to $15.50 per barrel for a total production unit cost of $29.50 to $31.50 per barrel. Actual 2010 total production unit costs were $28.96 per barrel. For the full year of 2011, we expect our E&P effective tax rate to be in the range of 45% to 49%. Net corporate expenses in 2011 are estimated to be in the range of $165 million to $175 million, and after-tax interest expense in 2011 is anticipated to be in the range of $240 million to $250 million. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

[Operator Instructions] And your first question will come from the line of Jeff Dietert from Simmons. Jeffrey Dietert - Simmons & Company: I was wondering if you could talk about some of the recent performance from the Bakken wells that you're drilling, recent 30-day IPs and any EURs, and how those trends are progressing.

First of all, let me say I'm real pleased with the Bakken team. We continue to make significant progress there. As I said, we exited the Bakken at our targeted rate of 20,000 barrels a day at the end of the year. So those wells are going as expected. Update on wells, again, the dual-lateral wells are costing us between $11 million, $11.5 million. Single-laterals between $7 million and $7.5 million. EURs are in the order of about 500,000 barrels per lateral, and our 30-day average IP rate for 18-stage wells are in the 400 to 500 barrels per lateral range. Now we recently revised our base completion design to 22 stages, so those IP rates are going to go up. Jeffrey Dietert - Simmons & Company: And you've got an aggressive program there, capital program. Could you talk about what are the most constraining factors for the pace of development in the Bakken?

Well, I think we have everything secured that we need. We've got 18 drilling rigs underway currently. We have frac crews, pretty much here for the first half of the year. We'll add another frac crew in the last half of the year, but so far, there is no constraints or bottlenecks, good progress on the infrastructure as well. So good shape. So far, so good.

Your next question will come from the line of Doug Leggate from Bank of America Merrill Lynch. Douglas Leggate - BofA Merrill Lynch: Greg, if I could also ask a couple, first of all on the Bakken. It seemed on your press release for the full year capital expenditure program, you're going to be running about 15 rigs, and if I'm not mistaken, you said 18 on your prepared remarks. Your original organic program was a 10-rig program, and of course, four or five years out, you were looking at getting to around 80,000 barrels a day. Would you care to just give us some color as to directionally where you think that 18-rig program gets you to over that longer term? And if you're basically holding back on that guidance, can you give us an idea as to what's holding you? Why are you being so conservative in light of the fact that you've increased your acreage position 50%?

Sure, Doug. So let me talk about the rigs for a minute. You are correct. On our non-acquired acreage, we had actually 11 rigs operating towards the end of the year. One of those is kind of a FlexRig because it works on refracs and then it does some other work for us. And then we inherited the additional rigs from the acquisitions. So our rig count does stand at 18 rigs currently. Regarding the long-term guidance, Doug, I think we've talked about this before. I'm not prepared to do that yet just because I want to get some -- digest the acquisitions. We want to get some more wells in that acreage under our belt before we adjust our long-term guidance. But we plan to do that later in the year. Douglas Leggate - BofA Merrill Lynch: Greg, are both the American and the Tracker acreage prospective for Three Forks across the acreage that you acquired?

Generally prospective across the whole acreage. Douglas Leggate - BofA Merrill Lynch: My only follow-up really is on the Eagle Ford. Can you give us a little more color as to where exactly are you located in the play? You said the condensate window, but can you give us some color on maybe the counties where you are, what roughly your working interest is and how your acreage acquisition plans are progressing? And maybe some activity updates would be great. I know you said 15 wells this year, but are we in the evaluation stage or are we moving to development phase? Some color would be appreciated.

As we mentioned in our remarks, about 90,000 acres currently in the Eagle Ford. I don't really want to comment exactly where we are because we're competitively trying to acquire acreage still around our positions. Regarding wells, we've drilled three. Those are exploration kind of delineation wells. We'll drill three more exploration delineation wells. And then we're planning about a dozen development wells on top of that next year.

Your next question will come from the line of Arjun Murti from Goldman Sachs. Arjun Murti - Goldman Sachs Group Inc.: Bakken is a popular topic. One more for you there. You reiterated your comments on the well costs and the EURs. Just curious what portion of your acreage you have confidence in those kind of numbers for. Would it be a third of the acreage, half of the acreage? I'm sure it's not all of it because some of it, you've just acquired. Can you provide any color on that?

Our existing core acreage, of course, that we have before the acquisitions, we're very confident of. We'd like to get a few more wells in the acquired acreage before we lean forward on the prospectivity of that acreage. Obviously, we think the acreage is pretty good. Otherwise, we wouldn't have acquired it. And there are some wells in the acreage drilled by others that look very, very good. Arjun Murti - Goldman Sachs Group Inc.: The existing core, I recall, was 300 to 350 of your amount, if I'm remembering.

Yes, I think that's about right. Arjun Murti - Goldman Sachs Group Inc.: And then clearly, the stuff you've acquired, you have yet to drill it. But we might think of that at some point as maybe moving into these kind of economics as well, if it drills out.

Yes, that's right, Arjun. Arjun Murti - Goldman Sachs Group Inc.: Anything you're seeing on the pressure pumping and the completion side? That's been a general bottleneck across the shale plays. I think some of the service companies have been adding capacity. Are you seeing that in the Bakken, or is something still to come? And then in terms of getting confidence in the production ramp-up given the that's an important piece of it.

No, I think, Arjun, as I said, we have frac rigs or frac pumping services secured, and we're going to add another one frac crew sometime during the year that will bring us completely up to five. But we're essentially contract or have contract in place for four, including what we inherited from the acquisitions. Arjun Murti - Goldman Sachs Group Inc.: Just a final one on the Paris Basin. I think you mentioned six wells this year. I believe, and please correct me if I'm wrong, they're very much along the lines of just trying to understand the acreage and a little bit of a science experiment phase. If the six wells -- is it possible for the six wells to go particularly well where you then end up drilling a lot more this year? Or is it you'll drill with six wells, take the time study it, and then we come back sometime a year from now and continue to move forward? How should we be thinking about the pace of the Paris Basin, I guess, if these six wells go particularly well or not, or if you can even tell that from the initial wells?

Arjun, I really can't say at this point. Let's get the six wells under our belt, see if we can get some fractures, some vertical fractures in particular, and we're going to try and do a horizontal well or two next year, and then after that, we'll go from there.

Your next question will come from the line of Paul Sankey from Deutsche Bank. Paul Sankey - Deutsche Bank AG: You talked about the importance of unconventional going forward in your portfolio. In China, I was just wondering if the Sinopec studies are related to gas or oil and generally, when we could begin to hope for first production from China, either from the PetroChina or the Sinopec agreement.

I think it's really hard to say or speculate on the first production at this point. The Sinopec JSAs really cover all unconventionals in a very large basin around the Shengli field. Paul Sankey - Deutsche Bank AG: So that would be either oil or gas, you're not sure yet?

Yes, either oil or gas. Paul Sankey - Deutsche Bank AG: And then you spoke about some of your new flow potentially for the rest of the year beyond the unconventional. I think you mentioned Ghana. I just wondered if you could say a little more about what we can hope for in the course of the whole year from Indonesia, I'm thinking Australia and any other highlights.

Sure. So let's start with Ghana. As I said, we expect to spud our first well in February in Ghana. And then Semai, I mentioned in my remarks, we expect to spud that well in the first quarter as well. And if we turn to Australia, of course, we're in the middle of our appraisal program down there. It's still early days. We got a couple of DFPs [ph] under our belt, but so far, so good. The results have been encouraging. And then, the next we go to Brunei, which the operator, Total, is planning to spud the first well sometime in the second half of the year. So those are some of the big highlights outside of the unconventional business, and of course, we're on the Northern Red Sea block as we speak. So that's a bit of an around-the-world tour quickly.

Your next question will come from the line of Mark Gilman from Benchmark Company. Mark Gilman - The Benchmark Company, LLC: I was looking for some qualitative or preferably quantitative indication as to the 274 million of reserve adds booked at year-end 2010 and the impact, if any, of the revisions one way or the other.

Just some of the big highlights. Of course, on the reserve adds, the 274 million, about 160 million or so were in Norway, about 70 million or so were in North Dakota in the Bakken. So those were the two big hitters. Another 30 million in Russia, and then the rest, really, is just across the board. Mark Gilman - The Benchmark Company, LLC: And, Greg, the revision issue?

From the PSCs, Mark, with the increase in price, we took off 21 million barrels related to the PSC effect. Mark Gilman - The Benchmark Company, LLC: Any other revisions?

There's net adds, there's net revisions throughout all the fields. So yes, I mean, again, that's baked into that overall 274 million. Mark Gilman - The Benchmark Company, LLC: If I could shift to the HOVENSA thing for a second, I guess I'm trying to understand, John Hess, exactly what you're doing. My recollection says that HOVENSA actually consisted almost of two separate refineries, an east and a west, and yet the 350 number distillation capacity kind of seems in the middle of the two. Could you give me a little clarification of exactly what you're contemplating, what other units other than distillation coms [ph] you intend to shut down and quantify any cost benefits going forward?

Mark, your memory is very good. There is an east side of the refinery that is much more modern -- better heat conversion, better recovery, better upgrading. And then the west side, which is the original part of the refinery, which is the older part and the older units. It is that the west side that will be shut down and mothballed. And the 350 really reflects the east side configuration. So it's not something in the middle. The 350 reflects the east side, which is the better-performing, more efficient area. And until we finalize our operating plans, we can't provide more specific guidance in terms of operating expenses going forward, capital going forward, but I can assure you that they will be down. And these moves should improve HOVENSA's financial performance going forward. Mark Gilman - The Benchmark Company, LLC: One more for John Rielly. A little bit puzzled on booking a tax benefit on the write-offs on the Brazilian wells with no income in the area. If you could give me an idea, the hows and whys of that. And John Rielly, you indicated, I think, a lifting impact as you discussed the E&P results. If I recall correctly, it was $50 million. Can you give me a volume element to that in terms of where the under lifting has occurred and what the position was as of year-end?

The first thing was on Brazil. As you said, we did book a tax benefit on that. And it is typical that we will set up our exploration program in a way that you can get a U.S. tax benefit for an exploration loss in a foreign country. So what it basically is, Mark, is we refer to it as a worthless stock-type deduction. And that's the way the exploration expense gets benefited. So it's not a benefit that's recorded per se for Brazil. It's recorded for the U.S. So that's the Brazil aspect of it. On the lifting side, the overall impact was approximately 2 million barrels in the quarter. The biggest driver of that was Norway, and then you've got a group of them with EG, Denmark, Algeria. Libya is also in there, actually even some JDA condensate to pump out. So we had a kind of an under-lift across the portfolio. And I always hate to project the timing of what will happen quarter to quarter, but if you looked at our year-end inventory positions compared to what it's looked like over the, say, past year and half, it's clear that our inventory barrels are at a high stage right now. And so you would expect some over-lift coming into 2011.

Your next question will come from the line of Evan Calio from Morgan Stanley. Evan Calio - Morgan Stanley: Just a follow-up question on exploration. I think, Greg, in Egypt, you spud in December, I think, before there were 90-day wells. So we should expect results there in 2Q to discuss or are you going to go batch release once you have both down?

Yes, I think we'll have some early results from the first well in March, March kind of a time frame. Evan Calio - Morgan Stanley: And there's no mention on -- did Hess bid on the Senegal pre-salt bid round?

We really don't discuss what we bid on or don't bid on. Evan Calio - Morgan Stanley: Just a follow-up maybe on China, and I totally appreciate that it's early here, but what's the form? Is it some form of a PSC that would ultimately come out of that? Or any kind of way to preliminary think about economics in those kind of ventures?

Early for economics, but I think, obviously, that's what we would hope, is that the PSC would come out of it, assuming that we find material unconventional opportunities in those areas.

Your next question will come from the line of Paul Cheng from Barclays Capital.

John Rielly, you're saying that at year-end, your inventories are a bit high. Can you give us some rough idea how much is it high by comparing to the average?

Paul, what happens is, obviously, by country, the barrels are up and down, so we don't really want to compare to that. But just look at the countries that had the big over-lift. I let you know, again it was in Norway, EG and Denmark, and you can see it from our year-end inventories that those are the ones that are kind of higher on average. So we would expect for 2011 that those barrels would turn around.

John, is there a number you can share that you said 1 million-barrel high, 2 billion-barrel high, so we can have some rough idea?

I would tell you approximately 1 million, a little less than 1 million barrels, I would say, on average that we're high.

And for Greg, for Eagle Ford, you drilled three wells. Is there any kind of data you can share at all, whether it's the production rate, any resource data, anything you can share? You're saying that the results so far is encouraging. Is there anything you can share?

No, I'm not prepared to share anything yet, Paul. What I will say is, again, as I said in my remarks, we saw good shows and good log response in the well. So we're very encouraged and pleased with the results we're seeing so far.

When do you think you may be at a position you feel more comfortable to share some additional data?

I think we're going to complete the wells and hook them up for production in the second quarter. So there will be two horizontals we hope to get on in the second quarter. So we'll be, hopefully, in a position to share at that point.

And for the longer term in terms of the capital allocation, right now, if we're looking at -- you spend $1.8 billion in Bakken, presumably that you may spend, say, a couple hundred million dollar in Eagle Ford. And so you were talking about $2 billion of the $5.5 billion in the upstream. So we are talking about in the 36% capital. Is there sort of an expectation or target that you guys feel comfortable, say, "Okay, I do not want the unconventional to be way in excess of 50%, 60%"? Is there any kind of number that you can share in terms of what is your longer-term plan on capital allocation on the unconventional side?

Paul, I think it just depends on the opportunity mix that we have, the opportunity mix and the profitability of those opportunities. That's how we rank our opportunities internally. So we don't have a specific number that we're trying to shoot for one way or the other.

On Ghana, I thought initially that the well was supposed to be drilled in December. What's causing the delay?

Paul, it's just the rig arrival. That's the only thing, nothing else.

I think is for maybe John Rielly or John Hess. On some cost horizon with this restructuring, what kind of unit cost reduction that we may be able to expect?

At this time Paul, we just did announce it. So we will be going through the plans and working with our partner and our employees down there. And so we're not at a point right now that we can give guidance related to that.

A final one for Greg. In 2010, on the reserves addition, you said F&D cost is $23 million there, and you said $160 million is in Norway, I presume, is related to the acquisition of Valhall and all that. If I excluding the acquisition, what is your funding and development cost on an organic basis for 2010?

Our F&D cost on an organic basis is $50 per barrel. But I think it's important to keep that all in context in the five years. Our five-year average organic replacement ratio is 125% at an F&D cost of $22 per barrel.

Paul, you have to realize the nature, and I know you know this and the people on the call know it. When you're dealing with unconventionals in the acquisitions, you're really not buying very much of proved reserves. You're buying the opportunity to exploit and develop and produce proved reserves. So we have a burden from the acquisitions of about $1,600,000,000, for which there are no reserves today, but there will be for the future.

[Operator Instructions] Your next question will come from the line of Ed Westlake from Crédit Suisse. Edward Westlake - Crédit Suisse AG: First one on HOVENSA. I know you haven't gone through all the plans, but just holistically, do you think that the cost cutting and reliability improvements will enable you to get back to sort of a breakeven for that refinery? It's obviously been losing money. Or do you think margins also have to improve?

Well, it's going to be a function of the margin environment, obviously, to be able to give an absolute answer to your question. But on a relative basis, these moves should improve HOVENSA's financial performance going forward. So it will make it more competitive than what the external world provides us remains to be seen. But I think we will be able to capture more margin because of it. Edward Westlake - Crédit Suisse AG: I guess we're not talking about the Gulf of Mexico for a while, but you've got Shenzi waterfloods, Pony appraisals. I mean, when do you think you can actually, in the current environment, get back to drilling those wells?

Of course, in Shenzi, we are back to work. We've got a second rig there drilling another water-injection well, so we're planning to -- we approved five water injection wells on Shenzi, and the plan is to continue with those injectors. Regarding our own portfolio, Pony 3 will probably be first out, and we're expecting to get on that well in the second half of 2011. But, I think as everyone in the industry is saying right now, everything is highly uncertain due to the sorting out all these regulations. Edward Westlake - Crédit Suisse AG: On your comments about internally generated cash flow with a $5.6 billion CapEx budget and maybe a sort of $1.1 billion, $1.2 billion before working capital kind of cash run rate, is that just a function of oil prices, or are you going to be looking to make some further asset sales to realign the portfolio?

No. What we're looking at is the existing asset sales. So as John Hess had mentioned earlier, the U.K. gas assets that we had actually hoped to close by the end of the year but, just due to some timing, is just closing in the first quarter. So we do have that sale. And then on top of that, it's just our operating cash flow right now and the oil price environment that allows us to fund the capital program.

Your next question will come from the line of Katherine Flynn from IHS Herold. Sven Del Pozzo - John S. Herold: This is Sven Del Pozzo for Katherine Flynn. My question regards the integration of the private entities acquired in the Bakken. It looks like you and Tracker are very similar well performance. You're in the same regions, too, big Dunn County operators. Are you guys going to change the completion technique at all, or can we foresee similar well results or well performance in the future compared to what we've seen so far?

I think that's a good question, Sven. And as we've always said on all these plays, these are continuous learning play. So if you look at our own completions, we've evolved to 18-stage fracs and moved to 22. We have a couple of 28-stage fries now on the ground. So I think you'll see us continue to evolve the frac design, and we're excited about the learnings that we can gain from the two companies that we just acquired as well. So I think you'll see us continue to evolve. Sven Del Pozzo - John S. Herold: Could you give some concrete examples of efficiencies that will be generated? Since it seems like they're right in your backyard, so to speak.

Well, I mean, clearly, we'll just absorb it into our existing operations. So there's people synergies, infrastructure synergies, all those things. But we haven't put a number on anything like that. But clearly, that was part of the original acquisition part of our thinking. Sven Del Pozzo - John S. Herold: Regarding American Oil & Gas, that's mostly non-operated. So I'm wondering who are the most relevant operators to look at to get an understanding of the quality of American Oil & Gas' acreage?

I'm not sure that's a factual statement, that that's largely non-operated. And if you look at kind of our working interest share just across the whole Bakken play, we're averaging about 67% now across the play. So still very high working interest across the entire play for us. Sven Del Pozzo - John S. Herold: Regarding U.S. production cost increases in the fourth quarter, what drove those versus the third quarter?

I'm glad the question got asked because there's always timing that gets involved with our operating costs, our cash costs, and so from an overall standpoint for the year, we finished at $14.40 was our overall cash production unit cost. And the increase actually from 2009 was really solely related to production taxes. So the cost we were able to control. While there's ups and downs in it, we did a very nice job and the E&P group did a nice job on that. So specifically, as you look in the U.S., we've got timings related to maintenance. We have additional production taxes with the higher price environment. In the fourth quarter, we had workovers. Those type of things, we really forecast. We actually also had Tubular Bells, we had some development studies that were ongoing in the fourth quarter. So as we picked up operatorship of that, we flowed that through the production line. So those went to the fourth quarter. But on an overall basis, our production cost came in at the low end of range and really pretty much in line with 2009. Sven Del Pozzo - John S. Herold: Lastly, do you think 200 wells in the Bakken in 2011, is that an achievable number or is it in the ballpark?

Sven, as I said, we're still swallowing the acquisitions, so I don't want to give a well number yet. It will be a combination of singles and duals. So I think you'll see us drill anymore singles than in the past because we're trying to get the acreage now by production on the acquisition side. Sven Del Pozzo - John S. Herold: The big shift in CapEx to the U.S. versus the third quarter, where was most of that capital allocated regionally? If you could give me some regionally specific references.

Sure. Because of the large increases due to the acquisitions in North Dakota. So again, we did see TRZ Energy acquisition completed in the fourth quarter. So that's what drove the U.S. It's North Dakota.

Your next question will come from the line of Blake Fernandez from Howard Weil. Blake Fernandez - Howard Weil Incorporated: A couple of quick ones for you on the Bakken. Greg, you mentioned the shift from dual-laterals to singles in an effort to HBP acreage. Just curious, how long do you think it will take you to achieve that?

I think we'll have steady drilling in 2011 and 2012, primarily single-laterals to secure that acreage. So it will be over the next two years. Blake Fernandez - Howard Weil Incorporated: So post-2012 you should be there, right?

Right. Blake Fernandez - Howard Weil Incorporated: I don't know if you'd be willing to share this, but you gave guidance of about 40,000 barrels a day for '11 in the Bakken. Could you clarify maybe what an exit rate may look like?

Not yet. Again, I just want to swallow these acquisitions and kind of rejigger our whole program including the HBP and the single well laterals before I give you an exit rate.

Your next question will come from the line of Pavel Molchanov from Raymond James. Pavel Molchanov - Raymond James & Associates: A quick question on Brazil. Exxon had some comments earlier this month that indicated maybe a more ambiguous picture. Of course, you guys decided to just take the write-off immediately. Just curious kind of what prompted that decision on your part because, as I said, they're a little more optimistic it seems.

Well, with the December notice of discovery, I believe we're aligned with our partner on path forward on the block. So I don't think there's any discrepancy. Pavel Molchanov - Raymond James & Associates: And with one confirmed discovery back in early '09 and then two dry holes that you've already written off, do you see a path towards commercial development, or is it too early to say?

Yes, it's too early to say. I think I said in my opening remarks, the co-ventures will now take all the data from the three wells and the cores and the seismic, really step back and figure out what we want to do.

Your next question will come from the line of John Herrlin from Societe Generale. John Herrlin - Merrill Lynch: For the gas plant in North Dakota, how much is that going to cost, estimated?

I can't really break that out for you. I mean, the entire infrastructure cost in the Bakken is around $750 million. John Herrlin - Merrill Lynch: With regard to your additions, could you break down extensions, revisions, acquisitions? You didn't do that.

Sure. From our overall number, I would say from extensions, discoveries and revisions, approximately that's 106 million barrels. John Herrlin - Merrill Lynch: In the Paris Basin, have you been able to do any core studies from existing cores or are you just drilling for the first time and that's when you'll actually get cores? Are you concerned at all about clay?

John, we have looked at some old core data. We've also looked extensively at old well data. I just wanted to clarify again on the Paris Basin since you asked the question, our plans on the Paris Basin is we're going to drill six wells. The first wells will be vertical wells, will which will be logged and cored. Then we expect to complete single-stage fracs and flow tests on as many as four target intervals in each of those three wells. And then although preliminary, for the next three wells, we're planning a combination of vertical and horizontal wells with multi-staged hydraulic fracturing subject to permits being issued. John Herrlin - Merrill Lynch: With the Eagle Ford, you said you're in the kind of safe window. How much gas do you think you'll gather or do you really think they're all condensate?

We don't know yet, John. I mean, it's going to be a mix of condensate and gas. But we don't know until we have the wells flowing. John Herrlin - Merrill Lynch: Last one for me is time to TD in Ghana and Brunei?

Well, Brunei, don't know because wells haven't been planned yet. But certainly, Ghana, these are 90-day wells.

Your next question will come from the line of Jack Moore from Huntswell [ph] capital.

I was wondering if you could just give a little more color on the moving parts with respect to your budget and your capital structure going forward? Just give a sense if commodity prices soften, what the moving parts were, and if they stay robust, where you would expect to allocate resources if they surpass current expectations?

Obviously, with current prices, we make the statement that we should be able to fund our capital program from internally generated cash flow. Having said that, in the normal course of our business, we always are upgrading our portfolio. And in addition to the U.K. natural gas North Sea assets that we expect to close as a sale in the first quarter, there are a few other that we're contemplating. That's point number one. So there are maybe a few more asset sales that can get completed in 2011 just to upgrade our portfolio. As you are aware, we currently have about $1.5 billion, $1.6 billion of cash on the balance sheet before those U.K. asset sales. So that cash is a cushion should commodity prices go down. And we will do what we have to do to deal with lower prices. We have in the past. And if it means making adjustments to the program, we certainly have the financial flexibility to do that. I don't want to get more prescriptive than that because it's a very hypothetical question. And higher prices, that would be a nice problem to have.

Just to check, there's no changes in your posture towards hedging going forward, right?

You never say never. In the past, we've hedged when our balance sheet was much weaker, and it was more at risk with some of the investment program we have, with the stronger balance sheet we have now. We're very comfortable taking the commodity price risk. If there are certain assets where we think the risk merits hedging, it's obviously something we will always consider.

Ladies and gentlemen, that does conclude the question-and-answer session and today's conference. Thank you for your participation. You may now disconnect. Have a great day.