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

Edward Westlake - Crédit Suisse AG Paul Cheng - Barclays Capital Evan Calio - Morgan Stanley Mark Gilman - The Benchmark Company, LLC Arjun Murti - Goldman Sachs Group Inc. Faisel Khan - Citigroup Inc Douglas Leggate - BofA Merrill Lynch Paul Sankey - Deutsche Bank AG Blake Fernandez - Howard Weil Incorporated

Good day, ladies and gentlemen, and welcome to the Second Quarter 2010 Hess Corporation Earnings Conference call. My name is Shamika, and I will be your operator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today's call, Mr. Jay Wilson, Vice President, Investor Relations. Please proceed.

Thank you very much. Good morning, everyone and thank you for participating in our Second 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, and welcome to our second quarter conference call. I will make a few brief comments, after which John Rielly will review our financial results. Net income for the second quarter of 2010 was $375 million versus $100 million a year ago. Our results were positively impacted by higher crude oil and natural gas selling prices and lower exploration expense compared to the year-ago quarter. Exploration and Production earned $488 million. Crude oil and natural gas production averaged 415,000 barrels of oil equivalent per day, which was 2% above the year-ago period. Higher year-over-year production resulted primarily from increased volume from the Shenzi Field in the Deepwater Gulf of Mexico and the Valhall field in Norway. Net production from the Bakken is currently more than 16,000 barrels of oil equivalent per day, and we remain on track to exit this year at a net rate of about 20,000 barrels of oil equivalent per day. We added three additional rigs during the second quarter, and currently have eight rigs dedicated to drilling Bakken wells. As a result of strong year-to-date production performance, we have raised our full year 2010 production forecast to a range of 405,000 to 415,000 barrels of oil equivalent per day from our previously forecasted range of 400,000 to 410,000 barrels of oil equivalent per day. Regarding the recent tragic accident in the Deepwater Gulf of Mexico, we are deeply saddened by the devastating loss of life, ecological damage to the Gulf coast and severe economic impact on local communities. While our company believes we have extremely high performance requirements for the safety of drilling operations, we in our industry need to do all we can to learn from this disaster, and to take the necessary precautions to ensure such a tragedy never happens again. The near term impact of the moratorium on Hess is expected to be relatively minimal. Our only operated rig in the Gulf of Mexico, the Stena Forth, left the Pony #3 location on Green Canyon 469 in June. That's part of a pre-existing farmout agreement. We anticipate completing the Pony #3 well as soon as practicable, following the lifting of the moratorium. The drilling of a production well at the Shenzi Field, in which Hess has a 28% interest, was suspended as a result of the moratorium. But this delay is expected to have only a very modest impact on our 2010 production. In June, we announced our intent to preempt BP under acquisition of Total's interest in the Valhall and Hod fields in Norway. Hess will pay $496 million in cash for an additional 7.85% interest in the Valhall field and 12.5% interest in the Hod fields, adding proved reserves of approximately 45 million barrels of oil equivalent. This preemption, along with the previously announced asset swap with Shell will result in our share of the Valhall and Hod fields increasing to 64.05% and 62.5%, respectively. Both transactions are expected to close by the end of the third quarter. During the second quarter, we made progress in our strategy to grow our global inventory of unconventional resource opportunities. In May, we announced a partnership with Toreador Resources under which Hess will invest up to $65 million in an initial exploration phase, and has the option to earn a 50% working interest and become operator in more than 1 million gross acres in the Paris Basin in France. An initial six-well program will commence in the fourth quarter and continue through 2011. Yesterday, we announced the acquisition of American Oil & Gas Inc. for 8.6 million shares of Hess common stock. This transaction will add approximately 85,000 net acres in the Williston Basin in North Dakota, build upon Hess' strong land position, leverage our infrastructure and enhance our growth profile in the Bakken oil play. The transaction is expected to close in the fourth quarter. With regard to exploration, we drilled two wells on our 100% owned permit WA-390-P in the Northwest Shelf of Australia, resulting in one discovery and one dry haul. We have now drilled 14 wells on the block resulting in 11 discoveries. We expect to complete our remaining two commitment wells during the third quarter, followed by an appraisal program that will include additional drilling and flow testing of several wells. Commercial discussions with potential partners regarding WA-390-P are ongoing. In the fourth quarter, we expect to spot exploration wells on our 40% owned BM-S-22 block in Brazil and our 100% owned Tano Cape Three Points block in Ghana. In addition, we plan to drill our 100% owned Semai V prospect in Indonesia during the first quarter of 2011. Turning to Marketing and Refining, we reported a loss of $19 million, an improvement over the year-ago quarter. Refining margins at our HOVENSA joint venture refinery improved from last year's second quarter as a result of higher distillate crack spreads and wider light heavy crude differentials. This improvement in Refining was more than offset by costs associated with the planned turnaround of the FCC and other related units at our Port Redding, New Jersey facility. Marketing results were better than the year-ago quarter, principally due to improved margins. Although retail marketing gasoline volumes on a per site basis were down about 4%, total convenience store sales were up nearly 7%. In Energy Marketing, oil sales were higher year-over-year, while natural gas and electricity sales were lower. Capital and exploratory expenditures in the first half of 2010 were $1.8 billion, substantially all of which were related to Exploration and Production activities. For the full year 2010, our capital and exploratory expenditures forecast has increased to $5.5 billion from $4.1 billion. The increase primarily reflects the acquisition of additional interest in the Valhall and Hod fields from Total; the acquisition of American Oil & Gas Inc.; and further appraisal of permit WA-390-P in Australia. We are pleased to make these acquisitions that will help us sustain profitable growth in reserves and production. At the same time, we are maintaining our financial strength, which will provide us the ability to fund future investments. I will now turn the call over to John Rielly.

Thank you, John. Hello, everyone. In my remarks today, I will compare second quarter 2010 results to the first quarter. The corporation generated consolidated net income of $375 million in the second quarter of 2010 compared with $538 million in the first quarter. Turning to Exploration and Production. Exploration and Production operations in the second quarter of 2010 had income of $488 million compared with $551 million in the first quarter. The first quarter results included after-tax income of $58 million relating to the sale of the corporation's interest in the Jambi Merang field in Indonesia. Excluding the effect of this asset sale, the change in the after-tax components of the results are as follows: lower selling prices, primarily natural gas, decreased earnings by $30 million; increased exploration expense reduced earnings by $18 million; increased depreciation expense reduced earnings by $11 million; lower cash operating costs increased earnings by $21 million. All other items net to an increase in earnings of $16 million, for an overall decrease in second quarter adjusted earnings of $5 million. In the second quarter of 2010, our E&P operations were under-lifted compared with production, resulting in decreased after-tax income in the quarter of approximately $30 million. Total production unit costs for the first six months of the year amounted to $27.65 per barrel of oil equivalent. We are reducing our total production unit cost guidance for the full year by $1 per barrel to $28.50 to $30.50 per barrel. E&P cash operating costs are expected to be in the range of $14.50 to $15.50 per barrel, down from the previous guidance of $15 to $16 per barrel. Depreciation, depletion and amortization charges are expected to be in the range of $14 to $15 per barrel, down from $14.50 to $15.50 per barrel. The E&P effective income tax rate was 43% in the second quarter. For the full year of 2010, we are reducing our E&P effective tax rate guidance to a range of 44% to 48%, down from 47% to 51%. Turning to Marketing and Refining. Marketing and Refining operations generated a loss of $19 million in the second quarter of 2010 compared with income of $87 million in the first quarter. Refining operations lost $31 million in the second quarter compared with $56 million in the first quarter. The corporation's share of HOVENSA's results after income taxes was a loss of $4 million in the second quarter compared with $52 million in the first quarter, reflecting improved refining margins in the second quarter. Also the first quarter included turnaround expenses of approximately $20 million after income taxes for scheduled maintenance on the FCC unit at HOVENSA. Port Redding generated a loss of $27 million in the second quarter compared to a loss of $4 million in the first quarter. During the second quarter, this refining facility was shut down for 41 days for a planned turnaround. The turnaround expenses recorded in the second quarter totaled approximately $27 million after income taxes. Marketing earnings were $17 million in the second quarter of 2010 compared with $121 million in the first quarter, principally reflecting seasonally lower margins and sales volumes in Energy Marketing operations. Trading activities generated a loss of $5 million in the second quarter compared with income of $22 million in the first quarter. Turning to Corporate. Net Corporate expenses amounted to $42 million in the second quarter of 2010 compared with $48 million in the first quarter. Net Corporate expenses in the first quarter included an after-tax charge of $7 million for the repurchase of the remaining $116 million of bonds that were scheduled to mature in 2011. After-tax interest was $52 million in both the second and first quarters. Turning to cash flow. Net cash provided by operating activities in the second quarter, including a decrease of $39 million from changes in working capital, was $981 million. Repayments of debt were $15 million. Capital expenditures were $901 million. All other items amounted to a decrease in cash of $72 million, resulting in a net decrease in cash and cash equivalents in the second quarter of $7 million. We had $1,363,000,000 of cash and cash equivalents at June 31, 2010, and $1,362,000,000 at December 31, 2009. Our available revolving credit capacity was $3 billion at June 30, 2010. Total debt was $4,326,000,000 at June 30, 2010, and $4,467,000,000 million at December 31, 2009. The corporation's debt to capitalization ratio at June 30, 2010 was 22.9% compared with 24.8% at the end of 2009. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

[Operator Instructions] And your first question comes from the line of Edward Westlake of Crédit Suisse. Edward Westlake - Crédit Suisse AG: The acquisition of AXP's obviously going to be high on the agenda. Clearly, paying cash for acreage it'd be interested to hear your views around the flow rates that you'd expect in their acreage because it's a different area to your own. But two separate related questions. One is around gas utilization. I think you have a gas plant nearby which means you hopefully get production from AXP. And the second one is a more broad question around lease expiry in your own acreage and in AXP. I understand there might be quite a big lease expiring next year. If you could make some comments on that.

Yes, thanks Ed. This is Greg Hill. A couple of comments. First of all, just to give everybody some perspective. So this is 85,000 net acres as John said. And it's located six miles west of Tioga Gas Plant. So clearly, it's very close to our existing infrastructure. It is the west of the anticline. We've got a lot of drilling to do in there. So we don't really want to comment about flow rates yet. There's only three wells in the block. So we've got a lot more drilling left to do before we're going to update our guidance on production. But clearly, we're excited about the acreage and it will be accretive to our Bakken production profile. Edward Westlake - Crédit Suisse AG: And on lease expiry?

Yes, lease expiry, so obviously, that was part of our thinking in the acquisition. We're going to use a three-rig program on that acreage and plan to fully develop it. Edward Westlake - Crédit Suisse AG: And in the core acreage in terms of the progress you're making in terms of drilling enough to avoid lease expiry in the 500,000 acres?

In our own core acreage, recall our phase one area is about 350,000 acres. The other acreage is in delineation acreage or in the process of still delineating that acreage. We will probably farm down some of that acreage.

Your next question comes from the line of Doug Leggate of Bank of America. Douglas Leggate - BofA Merrill Lynch: I've got a couple of quick ones on the Bakken and then one on just rigs if I may. First of all dealing with the acquisition. Greg, can you give us some idea of what the likely locations, if you're able to get that granular, that you have or that you think you've acquired in this acreage. Or some of the idea of the risk resource that you see over that 85,000 acres. Just adding on to that, if you could give some idea if there's any contribution from Production assumed in the higher guidance for the current year. I'm guessing not, but if you could just confirm that?

Yes. Thanks, Doug. So on production reserves this year, it'll be very, very minor because there's just a few wells over there. As far as future locations, I mean we plan to develop the acreage just like we're developing our core acreage in the East Nesson kind of area. So the plan is do a lateral, use three rigs and basically mow it down just like we're doing on the east side. Douglas Leggate - BofA Merrill Lynch: So they were running two rigs, Greg, or were they running three rigs? Or can you just confirm, well, if you're adding rigs there or you're using the existing fleet?

Yes, we're using the existing fleet. They've got three rigs currently. I think they're going to add another rig and two more rigs in the fourth quarter. But we plan to reduce that to three next year. Douglas Leggate - BofA Merrill Lynch: So you're just going to run to three basically through the period?

Yes, through the period. Douglas Leggate - BofA Merrill Lynch: Okay. So that takes you to 13 rigs then on your total plan for 2011?

Yes, that right. Douglas Leggate - BofA Merrill Lynch: Okay. If I may just do a follow-up on the cost guidance that John Rielly gave. How much of that is the contribution from the Bakken as you move this forward? And I guess what's behind my question is if you think 80,000 plus within four or five years, what's that going to do to your cost guidance please?

Sure, I mean, let's just talk about this year. From a cost guidance standpoint, clearly, we have higher volumes that we projected earlier in the year. And so obviously, with the cost going over more volumes, it's going to lower our cost per barrel. The Bakken contracting strategy that was put in place also was beneficial to our forecast. So we were able to lower our cost of there. Now going forward and obviously it makes sense if you have more volumes with a cost base, it will eventually begin to drive down your cost in an area. But we're not going to project where our costs are going over the next several years. Douglas Leggate - BofA Merrill Lynch: But risks are skewed lower, John. Fair? Is it fair to say that the risks are skewed lower?

Oh, yes, correct. And again, Greg had mentioned this previously. We have locked in most of our -- probably about 90% of our drilling and completion costs in the Bakken here for the next five years. So when we've locked in these costs, which we believe are at favorable rates, there's performance incentives in these contracts also to continuing to try to drive down cost as we get more and more familiar with the acreage. And on top of that, we have dedicated crews up there for frac-ing it as well as equipment. So again, we do like our position here in the Bakken. Douglas Leggate - BofA Merrill Lynch: Great stuff. And the last one from me is just jumping to rig redeployment I guess. My understanding was you were due to get the Stena Forth back sometime later this year. What are the plans in terms of redeploying that elsewhere? I'm thinking Egypt might be on the list but if you could just give us some thoughts around that, that would be great.

Yes, thanks, Doug. So the Stena Forth is in a farmout to Cairn currently. She'll come back to us sometime in the fourth quarter. And the plan is to move her to the Northern Red Sea to drill a couple of wells there. And then depending upon the outcome of the moratorium in the Gulf of Mexico, she'll either come back to the Gulf of Mexico mid-year next year or go to Ghana and drill a follow-up drill in Ghana. So that's the plan for the Stena.

Your next question comes from the line of Paul Sankey of Deutsche Bank. Paul Sankey - Deutsche Bank AG: I wanted to ask you just a kind of high-level strategy question about what's been a very active set of asset deals and company deals that you've done. Where are you in this process now do you feel? Is this going to be a level of activity that you see yourselves maintaining? Or do you feel like you're arriving at an asset base that you're comfortable with?

Thanks, Paul, I mean we're being very opportunistic. I mean as we see -- particularly in the Bakken, as we see opportunities that's clearly a core hub for us. As we see profitable opportunities to capitalize on our competitive advantage on the Bakken, we'll entertain those opportunities. Paul Sankey - Deutsche Bank AG: Right. So this is not an unusual level of -- from your point of view, not an unusual level of activity that you're undertaking in terms of M&A and could be kind of sustained on with onward strategy if you like?

No, I don't think so, Paul. As I have mentioned before, we are trying to rebalance the portfolio a bit to get a few more unconventionals into the mix. And I think that's what you're seeing primarily us doing. Paul Sankey - Deutsche Bank AG: Okay. And when you say that, is that expansion or are you trying to offset at the same time say, for example, a reduction in your deepwater exploration? Is that a balancing process or would you say it's overall an expanding process?

I'd say it's a balancing process, Paul. Paul Sankey - Deutsche Bank AG: Okay, that's great. And then a specific one. How long will it be now -- you've given some guidance on Shenzi and Pony, but from the moment that moratorium is listed, assuming it is, how long would it be now would you expect from that point before you saw first production at both of those two assets?

Okay thanks, Paul, I think that's a really good question. Because I think the biggest factor on the uncertainty in Pony or really anything in the Gulf of Mexico is all around the regulatory framework which the government -- even though the moratorium is going to be lifted in November as we understand it. So certainly, as soon as that's lifted, we'll plan to bring a rig back in the Gulf of Mexico. But until there's clarity on that regulatory framework, it's really kind of hard to speculate right now on when timing will or -- whether it'll slip or not on things like Pony and some of the developments. So until we get clarity from the government on that framework, I don't really want to speculate on what it means. Paul Sankey - Deutsche Bank AG: Sure. In terms of some of the elements that are out there in terms of limitations, let's say, for example, liability cap changing, what would be your perspective on what would be a damaging government policy or a preventive government policy against what you think would be very reasonable reaction to the disaster?

Yes, Paul, I might come in on that one. There's been a lot of numbers speculated by different politicians about what the right cap level is. And some of the things that are being discussed now that we would be supportive of is rigs in the cap to $1 billion were the company that was doing the drilling would be responsible for that $1 billion exposure with insurance on its side. And then having some kind of a cooperative above that where all the investors and operators in the Gulf of Mexico would participate in some kind of insurance cooperative. That then would deal with catastrophic spills. So that kind of idea of having a company number going up to, let's say $1 billion. And then anything in excess of that being a group cooperative is something that we would be supportive of. Things higher than that, I think would be destructive to the competition in the Gulf, and wouldn't be in the United States' interest.

Your next question comes from the line of Evan Calio of Morgan Stanley. Evan Calio - Morgan Stanley: Maybe a question on the tax rate. I know your lower tax guidance after two quarters trending lower, I presume that's lower international versus 50% type of average. Is there a mix issue or can you kind of help us understand the other driver in the lower cost guidance? And is this a sustainable new level beyond kind of the guided period?

Sure, I'll try to help you with that. There's nothing really, I'm going to say, unusual in our tax rate in the first two quarters. So you do have -- you always have mix. You've got the concept of the under-lift that I mentioned. So it's not a big portion but Libya is a bit under-lifted here in this quarter. But what ends up happening with our forecast is the higher commodity price that you have, brings in more pre-tax income from other areas outside of Libya. And so Libya becomes a smaller percentage of our overall pre-tax income. And therefore, the effective rate becomes lower just when you put the portfolio together. So you have that coming about. And so with these higher commodity prices, we've been forecasting lower rate and that's why we're bringing down the guidance. Now going out, I mean, again, we'll give you the guidance for next year on our January call but the one thing you do see, our guidance is still higher for the second half of the year as compared to the first half of the year. And some of the results of that is our Valhall swap. So we will be getting more interest in Valhall. It's a higher rate and so that will be bringing up our rate in the second half of the year, and obviously then we'll have a higher interest in Valhall going into 2011. So that can cause that rate again to be a little higher than where it is right now. Evan Calio - Morgan Stanley: Great. And maybe a second question and it's a bit of a follow-up on some of the prior Gulf of Mexico exposure. But I mean is your insurance policies you think about the Gulf of Mexico, is that renegotiated on an annual basis or is it kind of a mid-year renegotiation process?

It's renegotiated every year, and different policies expire different times in the year. But it's a yearly event. Evan Calio - Morgan Stanley: Okay. So I mean but you're not -- have you seen any change in insurance rate as of yet? And I clearly understand there's a lot of uncertainty around liability [lag] et cetera, et cetera.

The government has to be clear on what its regulations are going to be. And then the insurance companies would respond in time. But the kind of number I talked about before, $1 billion is pretty close to one that we can handle right now. Evan Calio - Morgan Stanley: Okay. And if I could slip in just one last smaller question and follow-up on Toreador and your Paris Basin partnership. I mean are you guys on track to report some results there by year-end? I thought that was the original release with Phase I. And that's all I have.

Yes, Evan, I think the plan is again that we'll start drilling on that acreage in the fourth quarter. So we'll have some drillings results. But whether we'll will say anything about them or not because we're in delineation mode up there.

Your next question comes from the line of Mark Gilman of Benchmark Company. Mark Gilman - The Benchmark Company, LLC: Greg, I wonder if you could just give us a little bit of a overall update on the Bakken in terms of EURs, well costs? And in particular just address for me whether you're continuing to develop on a 1,280-acre spacing mode?

Yes, we are, Mark. So let me take the first bit of that. We currently are developing on the 1,280-acre spacing mode using dual laterals. So that gives you an effective acreage of 430 if you think about how the dual laterals are configured. Still early days in the dual laterals, but our costs are averaging $10 million to $11 million each. EURs are 1 million barrels per well and our 30-day average IP rate's around the order of 400 to 500 barrels per lateral, so you effectively double that for a dual lateral. Mark Gilman - The Benchmark Company, LLC: Okay thanks. I noticed, Greg, in the trades that I guess it was PETRONAS has issued a platform tender for the JDA, new platform. Is that just part of production maintenance or is there potential for expanding production there?

No, that particular platform is just all part of production maintenance. That's all it is. Now we did acquire PM301 to the south and we're working with PETRONAS to try and bring PM301 into the JDA infrastructure. Mark Gilman - The Benchmark Company, LLC: Okay. I noticed also apparently you and your colleagues in Libya made a fairly significant gas discovery in Waha. Any color you can provide on that?

No, not at this point, Mark. Mark Gilman - The Benchmark Company, LLC: Okay. Just one further if I could. Anything to say about Marcellus activity at this point, Greg?

Yes. So again our plans in the Marcellus just to remind everyone, we've got about 92,000 acres in the Marcellus. That's split between Newfield and ourselves. Our plans are to drill five wells on the Newfield acreage in 2010, drill five wells on the Hess acreage in 2010. And we've got permits for those. Seven of those wells are going to be in the DRBC. The remainder will be in the Susquehanna River basin. So we've got all the permits we need and we will plan to finish our drilling before the end of the year. Mark Gilman - The Benchmark Company, LLC: The end of 2010?

Yes.

Your next question comes from the line of Paul Cheng of Barclays Capital. Paul Cheng - Barclays Capital: Greg, maybe I'm missing something. You're talking about the 85,000 net acre. When I look at the 10-Q for the first quarter for American Oil & Gas I thought that they say it's 68,500 net acre in the Bakken and Three [ph] Locks (38:33) and then 131,000 in the Bigfoot. So what's the 85,000 refer to? Am I missing something here?

No, Paul, they've continued to expand their position there and continue to acquire acreage in the second quarter. So they're now at about 85,000 net acres as we speak. Paul Cheng - Barclays Capital: I see. And so they still have the 131,000 in the Bigfoot?

Yes, they do. Paul Cheng - Barclays Capital: Okay. So that's what the 85,000. And I know that it's early stage in but you ought to have some kind of expectation what is the recoverable resource that you may be targeting in order for you to pay the extra money. Is there a number that you can share here?

No, and I don't want to do that, Paul because obviously, we've got a range. We look at these things in a range. I just want to get some more wells in the ground and delineate some of that acreage before I give anybody definitive numbers.

Your next question comes from the line of Arjun Murti of Goldman Sachs. Arjun Murti - Goldman Sachs Group Inc.: Just some follow up questions on Australia. I think you mentioned you were in negotiations with partners on the 390 or commercialization plans. When do you plan to -- when do you think you'll be able to finalize that? And then any comment on the block you own with Woodside? Will that gas most likely go to Pluto-2 or any comment there?

Okay. Thanks, Arjun. Just to remind everyone on the call, remember this 390-P is a 16 commitment well block. As John said, we've now drilled 14 of those wells and 11 of which have been discoveries. So we'll finish out the two remaining commitment wells in the next couple months, and then we'll move right into an appraisal program and flow-testing phase using the same rig. So that will take us into the first quarter of 2011. So at that point in time in the first quarter of 2011, we'll be essentially done with drilling and appraisal. Regarding commercialization, we're still talking to all the parties down there, Wheatstone, Woodside, Shell. So all those discussions are still ongoing, Arjun, and we'll make a decision sometime next year on which route we're going to take. Arjun Murti - Goldman Sachs Group Inc.: Great. And on the Woodside block?

Yes, on the Woodside block, so Woodside's now drilled four of nine commitment wells. So they've had two discoveries in those four wells that they've drilled. They're on track to finish out the balance of their commitments also in 2010. And currently that gas is slated to go to Pluto-2. Arjun Murti - Goldman Sachs Group Inc.: Got it, that's great. And then just a follow-up on the Gulf of Mexico. You've always generally commented that within core areas, you're willing to expand if interesting packages come available. You've obviously done than that today with the Bakken and you did the Valhall. Does the Deepwater Gulf of Mexico still fit that bill? It's clearly an area of focus for Hess but if other smaller companies or midsize companies or even larger companies, BP's got a big asset sale announced. Does Hess view that as an area it is willing to expand in? Or is your sense of the risk profile there changed to the point that you prosecute your program but you're not really looking to expand in the Gulf?

No, I think we'll be opportunistic. I mean we will look and if things fit and they make sense to consolidate our position, we'll take a very objective look. I think all of us are just sort of waiting for the regulatory framework to see how that's going to shake out, but I think we'll be very opportunistic. Arjun Murti - Goldman Sachs Group Inc.: That makes sense. And just a final one on your comments on the liability cap. There is a much lower threshold today that for all practical purposes BP has said we're going to pay all reasonable costs well above that cap. They're obviously a very prominent, large, global company. You all may not be as large as BP but you're also pretty well known. Is it practical to think a liability cap does have meaning for a company like Hess? Hopefully there won't be further catastrophic damages. Hopefully it wouldn't involve you if there is one, but you never know. Do you think practically speaking even if there is a liability cap you could effect it? Or like BP, do you just face so much pressure that you end up paying all that you have to pay?

I wouldn't want to speculate. It's a great question, Arjun, about risk. I wouldn't speculate different outcomes that could happen. Obviously, this was a catastrophe. God willing, it doesn't happen again. But having said, the world's changed. And with the world changing, the cap should be raised. It should reflect the risk that one has in drilling in deepwater. And we've heard a lot of numbers out there so we want our voice heard. And we think a middle ground of saying $1 billion which is a big number but the cost of drilling the wells and the exposure of drilling wells in deepwater is high. So you have to have a cap that reflects that. But then again for a catastrophe, I think that's where mutual insurance, cooperative insurance comes in. And that's why above the $1 billion, I think it would make sense for a group to insure the risk as opposed to any sole company because otherwise just one or two companies would drill in the Gulf, and I don't think that would be a good outcome for anybody.

You have a question from the line of [ph] John Herlen (44:09) of Societe Generale.

With the Bakken, what are the completed well costs running? And how much is the frac as a percentage of total?

Okay, John, we typically won't break down all the well costs for you. I'll just say the total well cost, drilling and completion are averaging $10 million to $11 million for the dual laterals.

Okay. With Ghana, what's your time to TD and resource potential?

So with Ghana, the plan is that we will begin drilling there in the latter part of fourth quarter. So we've got a drilling rig coming in there to just [ph] spot (44:52) our first well. We don't give any resource estimates at this point in time. I mean we haven't even drilled our first well yet.

Worth a shot, okay. With Paris, have there been any cores on this acreage you're going to be drilling? Do you know the age of the shelves?

Yes, there's been a number of old cores that were taken in years past. So we've gotten a lot of that core data. The geologists tell me that it's the closest analogue to the Bakken anywhere certainly in the European theater. So we're anxious to prosecute that development or the delineation of that.

Do you know if it has high organic silicon content?

Very similar to the Bakken.

Okay. Last one from me. Was American Oil & Gas a data room situation or was it solicited?

Yes. We've been talking to each other probably for the last six months. So that was an ongoing situation to cover that dialogue.

You have a question from the line of Blake Fernandez of Howard Weil. Blake Fernandez - Howard Weil Incorporated: The only one I had for you is on your decision to issue stock for the acquisition. It seems like your balance sheet is very flexible and you could have easily paid cash. I'm just curious if there were any thoughts there.

Well this was the case where the seller actually wanted to have our stock. So it had the added benefit of keeping our balance sheet strong. So it was just worked out where the use of stock and the transaction facilitated the acquisition of the high-quality acreage and our infrastructure. So it just worked out that way.

Your next question comes from the line of Faisal Khan of Citigroup. Faisel Khan - Citigroup Inc: With the acquisition, does this sincerely change year 2015 net production target of roughly 80,000 barrels of oil equivalent per day?

Yes, I think it does. Clearly, we're pretty excited about the acreage. And it's clearly going to be accretive to our Bakken production target of 80,000 barrels a day in 2015. Once we complete additional drilling and some development planning, then we'll update our guidance accordingly.

[Operator Instructions] Your next question is a follow-up from the line of Edward Westlake of Crédit Suisse. Edward Westlake - Crédit Suisse AG: The Red Sea well, I guess that is a pre-sell potential maybe a few words around that. And then secondly just all this discussion on the liability caps. I mean assuming as the versions of the House that came out last night and senate go through which is unlimited liability, that's clearly a challenge. And there's no text in there about some form of insurance cooperative. How do you fight that battle and can you talk about where that might come into the language?

I'll let John talk about the liability issues. I'll answer Northern Red Sea first. Northern Red Sea is block one. It's a Hess-operated block. It's got a water depth of about 710 meters. We've got a couple of prospects there that we're going to drill. It's believed to be an oil prospect. So that's where we're headed with that.

And on the liability cap, there're a number as you know proposals of that are there, some of which you're referring to, none of which are absolute or definitive. They're just different ideas of different politicians being [ph] bandied (48:51) about. And so we think it's important to someone that is in the industry that has a position in the Deepwater Gulf, that is an independent to have our voice heard. And we're trying to find a middle ground that will allow activity to continue in the Gulf with competition. And yet at the same time, reflect the higher risk that we obviously have given the incident that occurred.

Your next question is a follow-up from the line of a Mark Gilman of Benchmark Company. Mark Gilman - The Benchmark Company, LLC: John Hess, the utilization rate at the coker at HOVENSA, low in the first half of the year. Was there additional downtime in the second quarter? Or was it voluntarily curtailed? Give me some color on that if you could please?

Yes. The lower utilization rate's not just in the coker but in the other units as well was unplanned downtime, Mark. And those issues have been dealt with and the units are running at a better rate. Mark Gilman - The Benchmark Company, LLC: Okay. And just one other for John Rielly. U.S. DD&A unit rate creeping up pretty good. Anything anomalous about what it was in the second quarter, John?

Yes, it really related to a new well. So we brought on a new well in [ph] Lano (50:04) actually, a [ph] Misee (50:05) target that's doing well. But that DD&A rate is above the U.S. portfolio DD&A rate and that's what's driving up the U.S. DD&A rate. Mark Gilman - The Benchmark Company, LLC: So it'll stay there for a bit anyway until that well declines?

I would say it'll stay there through this year. And we'll see on the performance and the performance stats from the reserves towards the end of the year. So it's been a very good well actually.

This concludes the Q&A portion of today's conference. I would like to thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.