赫斯 (HES) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Hess Corporation fourth-quarter 2010 earnings conference call. My name is Fab and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions).

As a reminder, this conference is being recorded for replay purposes. 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. Our 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 Jon Rielly, Senior Vice President and Chief Financial Officer. I will 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 and 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 lost $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's 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 and 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 regard to Exploration and Production, in 2010 we replaced 176% of production at a 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 thousand 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 UK 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 American 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 Reading, 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 to 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 Jon 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 250,000,000 cubic feet per day from 100,000,000 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 a combination of both single and dual lateral wells to get core acreage held by production into optimized 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 analyze 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 play into the Daqing Field, the largest oilfield in China. That study is now complete, and we are in discussions with PetroChina about expanding the study area to include other unconventional opportunities.

In addition, last week we signed two joint study agreements with SinoTech 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 on Block BM-S-22 encountered non-commercial quantities of hydrocarbons. As a result, we expensed both the Sabia and Azulao wells in the fourth quarter. We will continue to analyze the data from the three wells drilled and will 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 am once again very pleased with the performance of EP 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 will 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 costs associated with the Azulao 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 underlifted 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've 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 Reading 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 reflected 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) Jeff Dietert, Simmons.

Good morning. 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.

Thanks for the question, Jeff. First of all, let me say I am 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 the wells are going as expected.

Update on wells, again, the dual lateral walls are costing us between $11 million and $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.

Very good. 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 under way currently. We have frac crews pretty much secured for the first half of the year. We will 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.

Thank you.

Doug Leggate, Bank of America Merrill Lynch.

Thanks. Good morning, everybody. 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 are 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, 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 are basically holding back on that guidance, can you give us an idea as to what is holding you -- why are you being so conservative, in light of the fact that you've increased your acreage position 50%? And I have a follow-up.

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 flex rig, because it works on refracs and does some other work for us. And then we inherited the additional rigs from the acquisition. So our rig count does stand at 18 rigs currently.

Regarding the long-term guidance, Doug, I think we've talked about this before. Not prepared to do that yet, just because I want to get some -- digest the acquisitions. I 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.

Greg, are both the American and the Tracker acreage prospective for Three Forks across the acreage that you acquired?

Generally. Generally prospective across the whole acreage.

Okay. And 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. Thanks.

Thanks, Doug. So, as we mentioned in our remarks about 90,000 barrels a day currently in the Eagle Ford, not going to -- or 90,000 acres, sorry, in the Eagle Ford, don't really want to comment exactly where we are, because we are competitively trying to acquire acreage still around our positions.

Regarding wells, we've drilled three. Those are exploration kind of delineation wells. We will drill three more exploration delineation wells, and then are planning about a dozen development wells on top of that next year.

Okay, I'll leave it there, Greg. Thank you.

Arjun Murti, Goldman Sachs.

Thank you. Bakken is a popular topic. One more for you there. You gave a -- you've 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 is not all of it, because some of that it just acquired. Can you provide any color on that? Thank you.

I think our existing core acreage, of course, that we have before the acquisitions, we're very confident of. We would 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 looked very, very good.

But the existing core, I recall, was 300 to 350 of your amount, if I am remembering.

Yes, I think that is about right.

And then clearly, the stuff you've acquired, you have 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. Yes.

That's great. Anything you are seeing on the pressure pumping and the completion side? That has 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, and is that -- or is that something still to come in terms of -- and then in terms of getting confidence in the production ramp-up, given that is an important piece of it?

No, I think, Arjun, as I said, we have frac rigs -- or frac pumping services secured, and we are going to add another one frac crew sometime during the year that will bring us completely up to five. But we are essentially contract -- or have contracts in place for four, including what we inherited from the acquisitions.

That's great. And then just a final one on the Paris Basin. I think you mentioned six wells this year. I think -- I believe, and please correct me if I'm wrong, they are 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 will drill the six wells, take your time to study it, and then we come back sometime a year from now and continue to move forward? How should we think 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.

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

That's great. Thank you very much.

Paul Sankey, Deutsche Bank.

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 is really hard to say or speculate on first production at this point. The Sinopec JSAs really cover all unconventionals in a very large basin around the Shengli Field.

So that would be either oil or gas -- you're not sure yet?

Yes, either oil or gas.

And then you spoke about some of your news 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. Thank you.

Sure. So let's start with Ghana. As I said, we expect to spud our first well in February in Ghana. And in 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 are in the middle of our appraisal program down there. We've got -- it is still early days. We've got a couple [BSTs] under our belt, but so far so good. The results have been encouraging.

And then 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 are on the Northern Red Sea block as we speak. So that is a bit of an around-the-world tour quickly.

Great. Thank you.

Mark Gilman, Benchmark Company.

(Technical difficulty) where the 274 million reserve adds were booked and what revisions were implicit in that number, if any.

Mark, unfortunately, on our end, some of that cut out. Could you just be kind enough to repeat your question so we hear the whole question?

Yes. 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 revisions, one way or the other.

Okay, so just some of the big highlights. Of course, on the reserve adds, the 274 million, about 160 or so were in Norway. About 70 or so were in North Dakota in the Bakken. So those were the two big hitters. Another 30 in Russia, and then the rest really is just across the board.

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.

Any other revisions?

There is net adds, there is net revisions throughout all the fields. So yes -- I mean, again, that is baked into that overall 274 million.

Okay. If I could shift to the HOVENSA thing for a sec, I guess I'm trying to understand, John Hess, exactly what you are 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 are contemplating, what other units other than distillation [coms] 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 conservation, 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 west side that will be shut down and mothballed. And the 350 really reflects the east side configuration. So it is 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.

Okay. If I could just -- 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 underlifting has occurred and what the position was as of year-end? Thanks, John.

No problem. So 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 US 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 is the way the exploration expense gets benefited. So it is not a benefit that is recorded, per se, for Brazil. It is recorded for the US. So that is 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 barrels. So we had kind of an underlift across the portfolio.

And I always hate to project the timing of what will happen quarter to quarter, but it is -- if you looked at our year-end inventory positions compared to what it has looked like over the, say, past year and a half, it is clear that our inventory barrels are at a high stage right now. And so you would expect some overlifts coming into 2011.

Thanks very much, guys.

Evan Calio, Morgan Stanley.

Thanks for taking my call. 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 you're going to go batch release once you have both down?

I think we will have some early results from the first well in March -- March kind of a timeframe.

Okay, and there is no mention on -- did Hess bid on the Senegal pre-salt bid round?

Really don't discuss what we bid on or don't bid on.

Just a follow-up maybe on China, and I totally appreciate that it is early here. But what is the form -- is it some form of a PSC that would ultimately come out of that? Or any kind of way to preliminarily think about economics in those kind of ventures?

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

Great. That's it for me. Thanks.

Paul Cheng, Barclays Capital.

Several quick questions. John Rielly, you are saying that at year-end, your inventory is a bit high. Can you give us some rough idea there 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 overlifts. I will let you know, so again it was Norway, EG and Denmark. And you can see from a year-end inventory that those are the ones that are kind of higher on average. So we would expect through 2011 that those barrels would turn around.

Sure, I understand that. John, is there a number that you can share that you said, 1 million barrels high, 2 million barrels high, so we can have some rough idea?

It is -- I would tell you approximately 1 million, a little less than 1 million barrels I would say on average that we are high.

Okay. And for Greg, for Eagle Ford that 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. What I will say is, again, as I said in my remarks, that we saw good shows and good log response in the well. So we are very encouraged and pleased with the results we've seen so far.

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

I think we are 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 will hopefully be in a position to share at that point.

And for the longer-term, in terms of the capital allocation, right now if we are looking at you spend $1.8 billion in Bakken, presumably that you may spend, say, a couple hundred million dollars 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 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?

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

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

It is just rig arrival. That's the only thing, nothing else.

I see. And then I think this is for maybe John Rielly or John Hess. On (inaudible) horizon, that with this restructuring, what kind of [unit] caused that 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. So we are not at a point right now that we can give guidance related to that.

Okay. A final one for Greg. In 2010, on the reserve addition, you say F&D cost is 23 million barrels, and you say 160 is in Norway. I assume it is related to the acquisition of Valhall and all that. If I am excluding the acquisition, what is your funding and development cost on the organic basis for 2010?

Our F&D cost on an organic basis is $50 per barrel. But I think it is important to keep it 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.

Okay.

Obviously, Paul, you have to realize the nature -- and I knew you know this, and the people on the call know it -- when you are dealing with unconventionals and the acquisitions, you really are not buying very much of proved reserves. You are 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.

Okay, very good. Thank you.

(Operator Instructions) Ed Westlake, Credit Suisse.

Good morning, everyone. I guess two questions. First one on HOVENSA. I knew you haven't gone through all the plans. But 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 has obviously been losing money. Or do you think margins also have to improve?

It is 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. Then the external world provides us remains to be seen. But I think we will be able to capture more margin because of it.

And then a follow-up. I mean, I guess we are not talking about the Gulf of Mexico for a while. But you've got Shenzi water floods, Pony appraisals. 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 are 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. We are 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 sorting out all these regulations.

And then the final question, just on your comment about internally generated cash flow with a $5.6 billion CapEx budget, and you know, 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 are looking at is the existing asset sales. So, you know, as John Hess had mentioned earlier, the UK gas assets that we have actually hoped to close by the end of the year, but just a due to some timing, is closing in the first quarter; so we do have that sale. And then on top of that, it is just our operating cash flow right now and the oil price environment that allows us to fund the capital program.

Great. Thanks very much.

Katherine Flynn, IHS Herold.

Yes, 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 have very similar well performance. You are 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 is a good question, Sven. And as I've always said on all these plays, these are continuous learning plays. 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 fracs now in the ground. So I think you will see us continue to evolve the frac design. And we are excited about the learnings that we can gain from the two companies that we just acquired as well. So I think you will see this continue to evolve.

Could you give some concrete examples of efficiencies that will be generated, since it seems like they are right in your backyard, so to speak?

Well, I mean, clearly, we will just absorb it into our existing operations. So there is 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.

Okay. Regarding American Oil & Gas, that is mostly nonoperated. So I am kind of wondering what -- who are the most relevant operators to look at, to get an understanding of the quality of American Oil & Gas's acreage?

Yes, well, I think -- I'm not sure that's a factual statement, that that's largely nonoperated. And if you look at kind of our working interest share just across the whole Bakken play, we are averaging about 67% now across the play. So still very high working interest across the entire play for us.

Okay, thanks. And as regarding US production cost increases in the fourth quarter, what drove those versus the third quarter?

Sure. And I guess -- I'm glad the question got asked, because there is always timing that gets involved with our operating costs, our cash costs. 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 is ups and downs in it, we did a very nice job -- or the E&P group did a very nice job on that.

So specifically, as you are looking in the US, 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 were really forecasted.

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 costs came in at the low end of the range, and really pretty much in line with 2009.

Okay. 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 are still swallowing the acquisition, so I don't want to give a well number yet. It will be a combination of singles and duals. So I think you will see us drill many more singles than in the past, because we are trying to get the acreage held by production on the acquisition side.

I forgot one last one. The big shift in CapEx to the US 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 the TRZ Energy acquisition completed in the fourth quarter. So that is what drove the US, it is North Dakota.

Okay. All right. Thank you very much.

Blake Fernandez, Howard Weil.

Just a couple quick ones for you on the Bakken. Greg, you mentioned the shift from dual laterals to singles in an effort to HBP acreage. I'm just curious, how long do you think it will take you to achieve that?

I think we will have steady drilling in 2011 and 2012, primarily single laterals, to secure that acreage. So it will be over the next two years.

Okay, so post 2012, you should be there, right?

Exactly.

Okay. And then the other one -- I don't know if you would 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 laterals, before I give you an exit rate.

Understood. Thanks a lot. Appreciate it.

Pavel Molchanov, Raymond James.

Just 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 are a little more optimistic, it seems.

Well, with the December notice of discovery, I believe we are aligned with our partner on path forward on the block. So I don't think there is any discrepancy.

Okay. And with one confirmed discovery back in early 2009 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?

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

Okay. Thanks very much.

John Herrlin, Societe Generale.

Four quick ones. For the gas plant in North Dakota, how much is that going to cost, estimated?

I can't really break that out for you. The entire infrastructure cost in the Bakken is around $750 million.

Okay, that's fine. With regard to your additions, could you break it down, extensions, revisions, acquisitions? You didn't do that.

Sure. From our overall number, I would say from extensions, discoveries and revisions, is approximately -- it's 106 million barrels.

Okay. In the Paris Basin, have you been able to do any core studies from existing cores, or you are just drilling for the first time, and that is when you will actually get cores? Are you concerned at all about clay?

John, we have looked at some old core data. We have 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 are going to drill six wells. The first wells will be vertical wells, 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 are planning a combination of vertical and horizontal wells, with multi-staged hydraulic fracturing, subject to permits being issued.

Great. Last two for me. With the Eagle Ford, you said you were in the condensate window. How much gas do you think you will get or do you really think they are all condensate?

Don't know yet, John. I mean, it is going to be a mix of condensate and gas, but don't know until we get the wells flowing.

Okay. Last one for me is time to TD in Ghana and Brunei.

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

Great. Thank you very much.

Jack Moore, Harpswell 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. And 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 UK natural gas North Sea assets that we expect to close as a sale in the first quarter, there are a few others that we are contemplating. That is point number one. So there may be a few more asset sales that 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 UK 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 proscriptive than that because it is a very hypothetical question. And higher prices, that would be a nice problem to have.

Thanks. It was a great call. Just to check, there is 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 was more at risk. With some of the investment program we have, with the stronger balance sheet we have now, we are very comfortable taking the commodity price risk. If there are certain assets where we think the risk merits hedging, it is obviously something we will always consider.

Sure. Thanks a lot, guys. Good call.

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.