John Hess - Chairman & Chief Executive Officer Greg Hill - President of Worldwide Exploration & Production John Rielly - Senior Vice President & Chief Financial Officer Jay Wilson - Investor Relations

Arjun Murti - Goldman Sachs Evan Calio - Morgan Stanley Doug Leggate - Merrill Lynch Paul Cheng - Barclays Capital Robert Kessler - Simmons & Co. [Bruce Laning] - NCCI Mark Gilman - Benchmark Company Paul Sankey - Deutsche Bank Pavel Molchanov - Raymond James Blake Fernandez - Howard Weil Kate Lucas - Collins Stewart

Good day, ladies and gentlemen and welcome to the Hess Corp. fourth quarter 2009 earnings conference call. My name is Francine and I am 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 presentation over to your host for today, Mr. Jay Wilson, Vice President, Investor Relations; please proceed, sir.

Thank you, Francine, and good morning everyone. 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. 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 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 of 2009 and provide some guidance for 2010. Greg Hill will then discuss our exploration and production business, and John Rielly will review our financial results. Corporate net income for the full year 2009 was $740 million. Exploration and Production earned $1.04 billion and Marketing and Refining earned $127 million. While our earnings were down versus the previous year, our results reflected strong production performance, increasing crude oil prices throughout 2009, and successful cost reduction efforts. In terms of our 2010 capital and exploratory program, we are revising our budget to $4.1 billion from $3.9 billion. This increase of $200 million is the result of the strategic asset trade with Shell announced in December, in which we will assume Shell’s interest in the Valhall and Hod fields in Norway, in exchange for Hess’s interest in the Clair field in the United Kingdom and all of Hess’s interest in Gabon. The transaction is anticipated to close in the first quarter and be effective January 1, 2010. As another step to improve our portfolio, we completed the sale earlier this month of our interest in Jambi Merang in Indonesia, receiving proceeds of $180 million. As in previous years, substantially all of our 2010 spending will be targeted to Exploration and Production, with $2.4 billion budgeted for production operations, $800 million for developments, and $850 million for exploration. With regard to Exploration and Production, in 2009 we replaced 103% of production at an FD&A cost of about $20 per barrel of oil equivalent. At year end, our proved reserves stood at 1.44 billion barrels of oil equivalent, and our reserve life was 9.5 years. In 2009, we increased crude oil and natural gas production 7% to 408,000 barrels of oil equivalent per day. In 2010, we forecast that crude oil and natural gas production will average between 400,000 and 410,000 barrels of oil equivalent per day. This forecast includes a net reduction of about 3,000 barrels of oil equivalent per day resulting from the strategic asset trade with Shell. With regards to developments, the Shenzi field in the deepwater Gulf of Mexico, in which Hess has a 28% interest, commenced production in March and achieved a net rate of about 40,000 barrels of oil equivalent per day during the second half of 2009. We also sanctioned our Bakken shale development in North Dakota. We plan to build up to a 10 rig program over the next 18 months and invest about $1 billion per year over the next five years. As a result, we expect net production to increase from 10,000 barrels of oil equivalent per day currently to 80,000 barrels of oil equivalent per day in 2015. In exploration, we had continued success at our 100% owned WA-390P Block offshore Australia, where in 2009 we drilled seven wells, six of which were natural gas discoveries. In Libya, we successfully flow tested the A1 discovery well on our 100% owned Area 54 license and subsequently drilled and successfully flow tested a down dip appraisal well. With regard to Marketing and Refining, our full year 2009 financial results were lower than 2008, as the weak economy continued to have a negative impact on our business. Our HOVENSA joint venture refinery experienced losses as a result of significantly lower distillate crack spreads and narrow light heavy crude oil differentials. In retail marketing, our financial results were adversely affected by lower gasoline volumes, which were 3% below last year, and weaker margins, partially offset by higher convenience store sales, which were up nearly 11% from last year. In energy marketing, we generated stronger financial results and increased sales of fuel oil and electricity. In 2009, we maintained a strong financial position in the face of a difficult economic environment. Our debt-to-capitalization ratio at the year end was 24.8%, a slight increase over 2008. Our liquidity was enhanced by the February 2009 issuance of $1 billion of 10 year notes and $250 million of five year notes to reduce short term debt. Also in the fourth quarter of 2009, we refinanced notes due in 2011 by issuing $750 million of 30 year bonds. We are pleased with our performance during 2009 despite a challenging and volatile year. We remain committed to our strategy of investing to profitably grow our reserves and production on a sustainable basis. We are extremely excited about our future investment opportunities, which we believe will create long term value for our shareholders. I will now turn the call over to Greg Hill.

Thank you, John. Let me begin with production. In 2009, crude oil and natural gas production averaged 408,000 barrels of oil equivalent per day, which was up 7% versus 2008. Production growth was underpinned by strong performance from the Shenzi field in the deepwater Gulf of Mexico, a full year of Phase II natural gas sales from the Malaysia, Thailand Joint Development Area, and overall solid operating performance. In 2009, we added proved reserves of 157 million barrels of oil equivalent at an FD&A cost of about $20 per barrel of oil equivalent, yielding a replacement ratio of 103% and an ratio of 9.5, a good result considering the capital spending reductions we made and our strong production growth in 2009. Including this year’s results, our five year average rig reserve replacement ratio is 162%, and our average FD&A cost is about $16 per barrel of oil equivalent. In December, we announced a strategic asset trade with Shell that provides us with an opportunity to consolidate our portfolio and double our interest in the now Valhall and Hod fields in Norway, which are long life producing assets with significant reserves and upside potential, which will further support our long term objective of profitably growing our reserves and production. Turning to our capital program for 2010, we plan to invest nearly $1 billion in the Bakken oil shale play in North Dakota, where we hold more than 500,000 net acres. We expect our average rig count to increase from three in 2009 to 10 in 2011. At Pony in the deepwater Gulf of Mexico, we plan to drill an additional appraisal well and anticipate unitization of Pony and Knotty Head in 2010, followed by project sanction in 2011. The remainder of our capital program will focus on continued investment in a number of our core assets including Shenzi, field redevelopment at Valhall, and additional development drilling in Equatorial Guinea, the Malaysia-Thailand JDA, and Pangkah in Indonesia. Turning to exploration, in Australia, as a result of the 2009 drilling program on our 100% owned Western Australia 390P license, we have now drilled 11 of the 16 commitment wells on the block and have had nine discoveries. We plan to drill the additional five commitment wells during the first half of 2010 and are considering further appraisal wells. At the same time, we are continuing discussions regarding commercialization. Also at the Western Australian 404P license, in which Hess has a 50% interest, the operator, Woodside, will drill eight wells during 2010. Earlier this week, the operator announced that the first of these wells, Noblige-1 resulted in a natural gas discovery. By the end of the year, we should therefore have a much clearer picture of the future development options in Australia. In Libya, we have completed operations on two wells on our 100% owned Area 54 license. In 2010, we will reprocess 3D seismic and begin discussions with the government about future plans and commercial options. In Brazil, we completed two wells, obtained 450 feet of core, and gathered a large amount of log and pressure data on the BM-S-22 license, in which Hess has a 40% interest. In 2010, the partnership will use this data to reprocess 3D seismic and drill a third well in the second half. In both Ghana and Semai V in Indonesia, we continue to technically mature our 100% owned prospects during 2009 and expect to be in a position to drill in late 2010 or early 2011 and finally, in unconventional resources, we continue to selectively grow our position with the acquisition of 80,000 net acres in the Marcellus in 2009. In 2010, we will begin evaluation drilling and seek to acquire additional acreage. In closing, I’m very pleased with the performance of E&P in 2009. We successfully navigated difficult business conditions in the early part of the year through tight spending controls and strong operating performance. We also continued to advance our portfolio of material exploration 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 2009 results to the third quarter. Fourth quarter 2009 consolidated results amounted to net income of $358 million, compared with $341 million in the third quarter. Turning to Exploration and Production, Exploration and Production operations in the fourth quarter of 2009 had income of $494 million, compared with $397 million in the third quarter. The third quarter included after tax income of $89 million relating to the resolution of a royalty dispute on production from certainly leases subject to the U.S. Deep Water Royalty Relief Act. Excluding the effect of the royalty matter, the after tax components of the improved results are as follows. Higher selling prices increased earnings by $151 million. Higher sales volumes increased earnings by $49 million. All other items net to a decrease in earnings of $14 million, for an overall increase in fourth quarter adjusted earnings of $186 million. In the fourth quarter of 2009, our E&P operations were over lifted compared with production, which increased after tax income by approximately $40 million. However, earnings were lower in the fourth quarter by $20 million due to deliveries of natural gas to partially settled take-or-pay obligations at the JDA for volumes previously paid for by the buyers at a lower price. The E&P effective income tax rate was 47% for the fourth quarter of 2009. The E&P effective income tax rate was 48% for the full year of 2009, excluding items affecting comparability between periods. Turning to Marketing and Refining, Marketing and Refining operations had income of $17 million in the fourth quarter of 2009, compared with income of $38 million in the third quarter, which included a non-recurring income tax benefit of $12 million. Refining operations lost $40 million in the fourth quarter, compared with a loss of $15 million in the third quarter, excluding the non-recurring income tax benefit. The Corporation’s share of HOVENSA’s results after income taxes was a loss of $40 million in the fourth quarter compared with a loss of $30 million in the third quarter, primarily reflecting lower margins. Port Reading broke even in the fourth quarter compared with earnings of $16 million in the third quarter. Marketing earnings were $45 million in the fourth quarter of 2009, compared with $35 million in the third quarter, principally reflecting seasonally higher margins and refined product volumes in energy marketing operations. Trading activities generated income of $12 million in the fourth quarter, compared with income of $6 million in the third quarter. Turning to our bond offering and tender, in December 2009 the Corporation issued $750 million of new 30 year bonds at a coupon of 6% and tendered for the $662 million of bonds due in August 2011. The Corporation completed the repurchase of $546 million of 2011 bonds as of December 31. The remaining $116 million of bonds were redeemed in January and will result in an after tax charge of approximately $7 million in the first quarter of 2010. Turning to corporate, net corporate expenses amounted to $97 million in the fourth quarter of 2009, compared with $33 million in the third quarter. Net corporate expenses in the fourth quarter included after tax charges of $34 million for the repurchase of the $546 million of 2011 bonds referred to earlier and $10 million for pension plan settlements related to employee retirements. Excluding the effect of these two items, net corporate expenses increased in the fourth quarter due to higher bank facility fees, employee related expenses, insurance costs, and lower returns from pension related investments. For the full year 2009, net corporate expenses were $145 million, excluding items affecting comparability. After tax interest expense was $56 million in the fourth quarter, compared with $61 million in the third quarter. For the full year of 2009, after tax interest expense was $224 million. Turning to cash flow, net cash provided by operating activities in the fourth quarter including an increase of $256 million from changes in working capital was $1.271 billion. Net proceeds from the bond offering were $744 million. Repayments of debt amounted to $656 million. Capital expenditures were $925 million. All other items amounted to a decrease in cash flow of $29 million, resulting in a net increase in cash and cash equivalents in the fourth quarter of $405 million. We had $1.362 billion of cash and cash equivalents at December 31, 2009 and $908 million at December 31, 2008. Our available revolving credit capacity was $3 billion at December 31, 2009. Total debt was $4.467 billion at December 31, 2009 and $3.955 billion at December 31, 2008. The Corporation’s debt-to-capitalization ratio at December 31, 2009 was 24.8%, compared with 24.2% at the end of 2008. Now turning to 2010 guidance, in addition to the 2010 production and capital expenditure guidance given by John Hess, I would like to provide further information on certain 2010 financial 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 of oil equivalent produced. For the full year of 2010, we currently expect our E&P effective tax rate to be in the range of 47% to 51%. In January 2010, HOVENSA commenced a turnaround of its FCC unit, which is expected to take approximately 40 days. The Corporation’s estimated share after income taxes of HOVENSA’s turnaround expenses is approximately $20 million. The Corporation is also planning a turnaround of approximately 35 days for the Port Reading refining facility in the second quarter of 2010. The estimated after tax expenses for the Port Reading turnaround are approximately $25 million. Net corporate expenses in 2010 are estimated to be in the range of $160 million to $170 million, and after tax interest expense in 2010 is anticipated to be in the range of $220 million to $230 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) Your first question comes from Arjun Murti - Goldman Sachs. Arjun Murti - Goldman Sachs: A couple questions, just the first on the Bakken. You mentioned the rig count there is going from three rigs in ‘09 to 10. I believe you said 2011. Just so I make sure I kind of understood the contribution to 2010 from ramping up your Bakken activity. Will we see kind of much production contribution from the increased activity this year? Or should we think about that as sort of more of 2011 and beyond?

Yes, we will see some production contribution next year. We anticipate volumes to be up on average 4,000 to 5,000 barrels a day in the Bakken next year. Sorry, in 2010. Arjun Murti - Goldman Sachs: In 2010 and would that be 10 rigs by early ‘11 and so, we can kind of think of as proportional, or is there a midyear or some point where it kind of steps up in terms of the rig count in the Bakken for this year?

Arjun, it will be a gradual ramp to 10 rigs by the middle of 2011. Arjun Murti - Goldman Sachs: Then apologies, if I’m nitpicking the language here, but I think you said the Brazil well will be second half of this year. I think we’ve always thought it was closer to year end, which obviously does fall into the second half, but is there a chance you actually do go back to the third well say in the third quarter, or sometime earlier? I guess the related part of that is do you know when you’ll get the rig back from Petrobras that was loaned out to them for a temporary basis?

No, Arjun, of course it will ultimately be the operator’s decision, but kind of the hard line in the sand is the well has to be spudded by October 2, of 2010. So we have to have the well underway by that period of time.

Your next question comes from Evan Calio - Morgan Stanley. Evan Calio - Morgan Stanley: I had a question, whether it was a change of language in your preceding comments. I thought you mentioned that Ghana may be late 2010 versus a 2011 spud date. Is that correct? How is that allocated under your current budget?

So what’s going to drive the timing on both Ghana and Semai V in Indonesia is our technical readiness. So we are trying to get those wells ready to drill at the end of 2010, but that’s going to depend upon whether we have all our seismic reprocessing work done. In terms of the budget, what we’ve assumed is that, we’ll actually spud those wells in 2011. So obviously if we pull those into the late fourth quarter, there’ll be some minor budget impact in 2010. Evan Calio - Morgan Stanley: I think you also mentioned, did you say that you’d expect to know more on Australia until year end, I thought midyear prior. Is that correct? Is there any change there? If there is, what’s going to driving that change?

No, I think what we’ve said is that, we will finish out our exploration drilling program by mid year, July-August kind of timeframe. What we’re currently evaluating is additional appraisal wells on the back end of that program. So I think, obviously, as we get towards the end of the program and into our appraisal program, we’ll have a much better understanding of what the total volume on the block is at that point in time. Evan Calio - Morgan Stanley: Then you’re still allocating yourself sometime to consider various monetization alternatives; is that the difference in the timeframe as well?

Yes, absolutely. I think this year, we are in discussions with Chevron, Shell, and Woodside about liquefaction options and anticipate being in those discussions for the majority of 2010.

Your next question comes from Doug Leggate - Merrill Lynch. Doug Leggate - Merrill Lynch: I want to try a couple here. First one, I guess, is for Greg. Greg, the Bakken production target 80,000 barrels a day is obviously a big number. It’s kind of come out of nowhere, if you compare back to the last couple of years, to where the focus was. Can you maybe just give just a little more color as to what exactly has going on here in terms of why this has now been given such a high profile? If I may just layer on a related question, the operating costs from the likes of Brigham and Continental and those other guys out there are obviously much, much lower than your guidance let’s say for the current year. So, if this thing is going to be 20% of your production a couple years down the line, why are we not seeing any drop in the guidance on cash flow operating costs? I have a follow-up for John Rielly, if that’s okay.

Yes, that will be fine. So let me take the first question and then I’ll turn it over to John after that. So, Doug, I mean really what nothing has really changed in the Bakken. Of course, what happened in 2009 was that the oil price shock in the early part of the year. We were actually well advanced in our thinking in the Bakken in late 2008; and we actually put the brakes on a bit in 2009 just to wait and see where the oil price was actually going to go. That actually gave us some breathing space to really get our entire plans together, figure out our contracting strategy, etc. So really over the course of 2009, that’s what we did. We finalized our thinking; we finalized our contracting strategy; and then at the end of the year took sanction on that project. So nothing has really changed in our thinking about the Bakken. It was just a timing thing related to the oil price shock in early 2009. Again, I’d like to remind everyone the Bakken is robust at $40. It returns the cost of capital at $40. So that’s why we feel very confident kind of pulling the trigger on the Bakken now and aggressively going after a five year program. I’ll turn it over to John to answer the cost question.

I mean as far as the cost, and I guess you’re referring to the overall cost figure that I gave for the portfolio, in the Bakken and our costs are very competitive. We benchmarked our drilling time and our drilling costs there. So our costs are very competitive, but when you’re in the Bakken and we’re in a growth mode and as Greg said, as we’re ramping up the 10 rigs. The amount of drilling activity it’s there, it’s fairly intensive at this point. The overall cash cost in the Bakken are higher than our average of our portfolio. So at this point in time, actually the Bakken is one of the reasons that our overall cash cost in the portfolio are going up. Now as Greg said, the returns are very good. We like the returns in the Bakken; and obviously we like being in the U.S. in the shale play and the lower risk, but if you’re looking at the one line from the cash cost standpoint, the Bakken does have an average production cost higher than our portfolio. Doug Leggate - Merrill Lynch: I guess the cash operating cost, something around $6, does that sound about right in the Bakken?

We actually don’t get into individual aspects of it, but again, as I’ve saying, Doug, the cash costs in the Bakken are above the average of our portfolio. Doug Leggate - Merrill Lynch: I guess I’m thinking more about a run rate versus your competitors as you go forward. The follow-up I had, it maybe isn’t for John Rielly, but I’ll see which one of you guys wants to take this, but reserve replacement, if you’ve got I guess a five-year program, $1 billion a year, again related to the Bakken. What are we talking about in terms of reserve ads? How we are likely to see that, given project has been sanctioned? How are we likely to see those be booked as we move forward?

Yes, Doug, I think you know we don’t project that far into the future, but of course, the reserve ads will be an annual reserve ads as we kind of drill out the acreage. Just to give you some perspective, in our reserve adds of $157 million this year, the Bakken was about $30 million, $31 million barrels associated with a three rig program. So likely to get gives you some context. Doug Leggate - Merrill Lynch: Okay, Greg, just to clarify on this. You’ve talked about drill laterals, a million barrels per drill lateral. Is that still a good number?

Yes, I think at this point that’s still a pretty good number. To be fair, we only have four dual laterals in the ground now. So I think it’s a little early to give definitive numbers about that, but I think at this point in the play, that’s probably a decent number.

Your next question comes from Paul Cheng - Barclays Capital. Paul Cheng - Barclays Capital: Maybe several quick questions for Rielly. You’re talking about the fourth quarter, that you have an over-lift. As of year end from an inventory standpoint, are we still over-lift, or under-lift, or neutral?

Right now, Paul, we are over-lifted, if you want to say from the standpoint. So we can see that potentially as we look at the first quarter, that we can see an under-lift coming. Now, while it all turn around in the first quarter? No. Overall, though, we are in a slight over-lift position as we look at inventory. Paul Cheng - Barclays Capital: Can you tell us that by how much?

Paul, it’s just so different, because it all really compares on the amount of the liftings that come in and the timings of those liftings. So it’s not an extensive amount, but you could easily see a million barrels flipping on us. Paul Cheng - Barclays Capital: Then for Greg, for sometimes that you guys really have not spent any time talking about West Med in Egypt. Does that means that the play is not a priority and that the resource potential is really nothing excited for you guys to talk about yet? Or what’s the reason why we haven’t heard much about it?

I mean the simple answer is we’ve got some well results; we’re reprocessing seismic data and figuring out what our next steps are, so again, we prioritize all our investments in our global portfolio, and that’s just where it’s fallen in the seriatim of ranking. Paul Cheng - Barclays Capital: So is it just really that as of this point, at least based on what you know when you rank it, this is a way behind Bakken, way behind Brazil, Ghana, and everything, right?

I think that’s fair to say. I mean, it’s in the queue later than those development programs. Paul Cheng - Barclays Capital: You have not talked about, or maybe I missed it; if I do I apologize. Have you talked about what is your deepwater Gulf of Mexico drilling program for this year; is there any interesting or high potential well that you’re going to drill for the first six months of the year that we should be aware?

In the Gulf of Mexico, our first well that we’re going to drill in the Gulf will actually be the Pony appraisal well. We’ll drill that with the Stena Forth in the early part of the year. After that, we’re still trying to finalize the sequence, the Gulf of Mexico relative to other parts of the world. Part of it depends on Ghana, Libya, some of these other things as to whether, how we’re going to utilize that rig and where she goes. So we just don’t have a definitive answer on the Gulf of Mexico program beyond Pony at this point. Paul Cheng - Barclays Capital: Why we would be drilling another well in Pony? I thought that is already quite thoroughly delineated by, say, early last year?

It is, but we have a block next door called 469. So we’d like to drill a well in 469, and assuming it’s successful brings that into the unit. What that also does it allows us to hold the block 469. So that’s why we decided to drill that Pony appraisal well. Paul Cheng - Barclays Capital: So you’re not actually drilling at the existing block for the Pony. You’re actually drilling it in the adjoining block and trying to see whether that the reservoir extend into that.

Exactly. Paul Cheng - Barclays Capital: How far is that from the discovery or from the appraisal well?

Don’t know the distance, but you can say it’s probably about a half a Gulf of Mexico block to the edge of 469. Paul Cheng - Barclays Capital: When I’m looking at your capital spending, you’re only going to spend about $800 million for the development effort and far lower I think than the percentage to the past than what you spend in the development. So other than Bakken, is there any other major development project maybe coming on stream over the next two years?

Yes, the way I’d rather think about this, Paul, is I don’t really split it between production and development. That is a bit of an arbitrary split inside of our own company. The big areas where we’re spending money in 2010, of course North Dakota is the flagship; so that will be around $1 billion. Valhall of course is in the final phase of its redevelopment; that will be around $650 million or so in Valhall, followed by the deepwater Gulf of Mexico next, about $300 million. That’s a combination of Shenzi and some other wells that were going to do in the Gulf and then after that, it’s a whole seriatim in $150 to $100 million chunks really across the board. Paul Cheng - Barclays Capital: Greg, can you remind me always to drag on so long. For the Valhall, when that redevelopment is going to come on stream and what is the net production to you guys going to be after this well?

Well, the bulk of the redevelopment work will be done by mid 2011. So, all of that work will be done by then and then you’ll see additional wells come on be drilled and come on production. Paul Cheng - Barclays Capital: What is net impact to you guys after the asset swap?

Just for information, Paul, in 2009, the net production for Valhall to us was 14,000 barrels a day. So, that was, again, at our 28% interest. So subsequent to this transaction we will double that 28% interest. Paul Cheng - Barclays Capital: Okay, but I’m saying that after the completion on the redevelopment, what is the benefit that is going to be to you?

Right, I think what Greg was saying, it will start once we start doing the drilling. So the redevelopment again is replacing the facilities that are out there on the field, which will allow us to continue the development drilling and then the production will ramp up from there once the drilling starts… Paul Cheng - Barclays Capital: So in other words, when you say complete by mid 2011, you are not going to see any increase in production in perhaps that after that as you ramp up your drilling?

That’s right.

Your next question comes from Robert Kessler - Simmons & Co. Robert Kessler - Simmons & Co.: I wanted to see if you could clarify a few numbers on the reserves. In the Bakken, it sounds like you added about 30 million barrels, if I heard correctly and I want to say the prior number on Bakken reserves was about 50. So can you confirm you’re at about 80 million barrels for the Bakken now and then on Shenzi, given that the positive production performance there in 2009, any positive revisions to reserves?

So let me just kind of highlight some of the major areas of reserve adds because I said, the Bakken was about 31. We had some performance additions at Libya for another 24 to 25 million barrels. Russia and Okume were each just shy of 20 million barrels. It was really just across the board additions and revisions. So the biggest single area again was the Bakken. Robert Kessler - Simmons & Co.: Then just a quick one on the Bakken as well. You guys put out for data think some long term service contracts. How close are you to those at this point have any been awarded or what is the expected timing from here?

Very close and imminent. Robert Kessler - Simmons & Co.: I’m assuming you are still fairly happy with what you have seen come back from contractors.

Yes, we are.

–: Bruce Laning - NCCI: A couple questions follow up on the reserve replacements that were just asked. Can you give approximate breakout of the additions and revisions? That would be the first question. So, in other words, what is the net organic number out of that total?

Okay, so let me see if I can walk you through this a bit. So if you add back the price, the total addition from all sources is 192 million barrels. The only acquisition number in there is 16 million barrels. So if you take that out, your organic additions, your true organic additions are about 176 million barrels. Bruce Laning - NCCI: Was the bulk of that through additions, revisions, or actual drill bit? Can you comment on that?

Yes, the bulk by far was through revisions. So, of the 157 million in total, 144 million was associated with revisions and 31 was associated with extensions and discoveries; and then 17 was associated with acquisitions. So, that gives you kind of the breakout of all three pieces. Bruce Laning - NCCI: Just one more question on Libya, can you add any more color or detail to what you are seeing in Libya now that you have two wells down I mean do you have any idea of what size you are dealing with and anything associated with that?

No, we don’t yet. I think what we can say is we’ve had two successful path. The result of one was published, so that was about 27 million cubic feet and 500 barrels a day of condensate or so through a 52, 64 choke. The second well tests weren’t published and that’s because we don’t have permission from the Libyan Government. So we really can’t speak too much about Libya, but suffice to say we had two very successful tests.

Your next question comes from Mark Gilman - Benchmark Company. Mark Gilman - Benchmark Company: A couple things, John Rielly, could you just clarify your comment about the impact of the take-or-pay situation on the JDA I guess I kind of lost you on that?

Sure, Mark at in prior years, actually it was in 2005, 2007, and 2008, the contract that we have with the JDA is take-or-pay and so what happened is that the buyers, pretty much related to their pipeline delivery to their pipeline they couldn’t take all the quantity of gas under the contract. So they paid us for that and at that point in time, it was approximately 36 Bcf was in this gas bank. So now in the fourth quarter of 2009, they took 17.6 Bcf related to that gas bank and so they had already paid for that gas at prices that were in effect in ‘05, ‘07, and ‘08. So what we had to do was essentially deliver that gas to them at basically those prices that we had built up deferred revenue associated with it. So they received that gas free during that when they start taking down the gas bank and what we have is basically 18 Bcf left in the gas bank; and we have deferred revenue on our books of just under $80 million associated with that take-or-pay liability.

John, when you referred to the $20 million hit, that was an opportunity cost?

Absolutely compared to current market prices for the gas. Mark Gilman - Benchmark Company: I’m with you on that now. Greg, I guess I’m a little unclear on what the economic and NPV merits are of the asset swap with Shell. No matter how I look at it, unless there is some big upside numbers associated with the incremental resource on Valhall and incremental production, it looks NPV negative. Particularly with the front end increase in spend as well as the very low profitability of those barrels given the tax situation. Can you help me understand that a little bit?

Yes, Mark. I think we see significant upside in Valhall. This is a joint field with very, very low recovery factors. So I think there is an awful lot more upside potential in Valhall. We will be working with the operator, BP to unlock that upside potential. So we don’t see it as value neutral at all. We see additional value. Mark Gilman - Benchmark Company: What is the recovery factor currently, Greg and what do you think it can go to?

I’m not going to give you that number; but we can certainly call you back and give it to you. I don’t know what it is off the top of my head. Mark Gilman - Benchmark Company: Greg, just one other. Can you give us your current thoughts on length of plateau on production at both Shenzi and Ceiba/Okume going forward? How long do you think the plateau holds?

I wish I could. On Shenzi, I think we have been pleasantly surprised, pleased I guess, with the performance of the aquifer. So, how long that plateau lasts depends upon the performance of the aquifer and so far so good. Now, of course on Shenzi you have additional drilling opportunity as well that will keep that plateau for a number of years, but again, the big uncertainty is the aquifer and the pressure and how long does that hold. Mark Gilman - Benchmark Company: Have you seen any pressure fall off in any of the wells yet?

Not significant. So we are seeing good pressure support from the aquifer. Having said that, we are in the stages of planning for water injection, so I think the operator and us believe we believe ought to be conservative there and make sure that we have adequate injection support . Equatorial Guinea, we continue to drill additional wells there. We’ve got a number of years left of kind of plateau production in Equatorial Guinea.

Your next question comes from Paul Sankey - Deutsche Bank. Paul Sankey - Deutsche Bank: I appreciate a lot has changed here, but in many respects that’s the reason for the question. If we roll all the way back to the 2006 analyst meeting, the last analyst meeting, you talked about I believe 3% to 5% volume growth and 5% to 8% reserves growth. Obviously, there’s been a huge change here in regards particularly to the Bakken. We’ve also got a situation where you’ve talked about ‘09 as being a very strong year, well above that target for production growth. Not so much next year on the volume growth side. Can you just give me some idea of how you’re thinking about the parameters of reserves growth going forward relative to the game changer in the Bakken and the higher CapEx that you have this year? The 9.5 year reserves life and the aspiration I believe was to get that to above 10, and any other sort of new parameters that we can think about at a corporate long term level relative to that previous target? Thanks.

When we had the analyst meeting, we were definitely in the investment mode to grow our reserves. With the ultimate objective of getting to a reserve production life of 10, which we reached last year and we’re close to it in terms of where we were at the year end. Our targets going forward as you are well aware over the last year or so have evolved to where on a sustainable basis to optimize financial returns to set a 3% growth target per year for reserves and a 3% production target as well on an annual basis. That is really to be looked at because the E&P business being so capital intensive and lumpy in the timing of developments. It’s over the longer term, year-in, year-out, like last year we were over 7%, now it’s a 3%, 2010 closer to flat on production, but our long term targets, meaning a five year rolling average. We still aspire to and certainly feel that we have captured the opportunities in our portfolio of exploration and developments and production investments to deliver a 3% a year reserve growth and 3% a year production growth. So those are the targets going forward. You can’t judge us on a one year basis. You have to do it over the long term, because this is a long term business and we feel very good between our Bakken program, our exploration projects that we have in queue, the Pony project going forward, that we’re pretty much on trend to meet those objectives. Paul Sankey - Deutsche Bank: If I could just ask a follow-up on FD&A, you mentioned $20 a barrel for the year, again allowing for the lumpiness. What do you think the outlook for that is? Can you bring that number down back towards the average that you talked about over five years of $16 a barrel?

That’s obviously very difficult to forecast. Again, with the lumpiness that we have, so I mean Greg had mentioned we have the Pony sanction that will be coming up in 2011. Bakken will be more of a consistent provider, but again, with the way exploration projects and things like that come on stream, it’s very difficult to forecast and where is industry cost going to go? Where are commodity costs going to go? So it’s difficult. I mean we’re very focused on being as efficient as possible to drive that cost down as low as we can. Paul Sankey - Deutsche Bank: I guess the Bakken, obviously is bringing the cost down overtime and I guess you’re also seeing that it’s going to be able to continue this sort of the reserves add performance that you’ve seen in ‘09.

I think that’s a fair assumption. So the Bakken will bring it down and I think you’ll see very similar kind of reserves adds year-on-year. Obviously, the pace is going to go up, so with that will come more reserve adds. Paul Sankey - Deutsche Bank: Then just a very specific one for me, the swap with Shell, was that a reserves? Was there a net reserves impact from that?

Yes, there will be. There will be a positive upward revision to our account of over 100 million barrels this year. Shell In ‘10, obviously?

Yes.

Your next question comes from Pavel Molchanov - Raymond James. Pavel Molchanov - Raymond James: Most of them have been answered, but when I look at your year end ‘09 versus year end ‘08 reserves, can you tell me what the change would be had oil prices been constant year-over-year? In other words, how much did you lose through higher pricing under your production sharing contract?

So the price revisions in our reserves number were a negative 35 million barrels this year. Pavel Molchanov - Raymond James: Is that essentially all under your DSCs overseas?

Yes, it is.

Your next question comes from Blake Fernandez - Howard Weil. Blake Fernandez - Howard Weil: I had a question on the Bakken. I know you’re testing kind of dual lateral, single lateral, trying to find the optimal well. I’m just curious if you have any estimate on kind of the timeframe before you identify that, presumably once you identify it and move to a more of a program kind of drilling program, I’m assuming that should get you some efficiencies and help lower the cost, but wanted to get your thinking on that?

Our development plan is to drill dual laterals, one in the Three Forks, one in the Middle Bakken, and as I said earlier, we only have four wells done so far with that configuration, but suffice to say they’ve been very successful and the cost of a dual lateral versus two single wells, there’s quite a cost advantage there. We’re early in the learning curve, and we’re also contracting rigs at a little bit better price. So I think you’ll see those costs continue to drop. We also plan to apply lean manufacturing to the play as well. So my experience with that is you’ll see these costs continue to drop on the wells as we go forward. Blake Fernandez - Howard Weil: The only other one I had for you, on the Marcellus, it looked like the verbiage in the release suggested you were looking to add acreage. I’m just curious if there was any targeted amount and what your thinking is on entertaining new plays or just kind of focus on the Marcellus for the time being?

I think we will be opportunistic in the Marcellus is what I would say. I mean there’s still some more acreage in and around our existing acreage that we would like to pickup. In regards to the second part of your question, I think I’ve spoken about this before. We view the globe as really the unconventional playground for us. So we are looking in a number of places around the globe at unconventional.

Your final question comes from Kate Lucas - Collins Stewart. Kate Lucas - Collins Stewart: Just a couple of quick points of clarification on the Bakken, first of all, you talked about the economics being robust down to $40 a barrel and the project returning cost of capital returns at that price. Is that your realized price in the Bakken or is that a NYMEX price?

That’s, WTI price. Kate Lucas - Collins Stewart: Then just as you look at the Bakken production growth that you’re targeting over the next several years, are you concerned at all about any infrastructure constraints?

We have a plan in place for the infrastructure. Obviously that’s an issue for all the players in the Bakken. We’re fortunate because we have a privileged infrastructure position already. So that will carry us through a period of time and then after that we’re looking at rail options and/or pipeline options. So I think you’ll probably see both of those come in to our future export strategies.

To be clear, Kate, just so you get, when Greg says WTI $40, our realized price from that marker is currently about $4 under for the North Dakota crude. So it’s the netback price that we use for the economics, but it’s tied to a $40 WTI marker.

Ladies and gentlemen, that concludes the Q-and-A portion of the presentation. We would like to thank you very much for your participation in today’s conference. You may now disconnect. Have a great day.