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

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division Evan Calio - Morgan Stanley, Research Division Arjun N. Murti - Goldman Sachs Group Inc., Research Division Paul Y. Cheng - Barclays Capital, Research Division John P. Herrlin - Societe Generale Cross Asset Research Mark Gilman - The Benchmark Company, LLC, Research Division Edward Westlake - Crédit Suisse AG, Research Division Philip Weiss - Argus Research Company Paul Sankey - Deutsche Bank AG, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Good day, ladies and gentlemen, and welcome to the 2011 Third Quarter Hess Corporation Earnings Conference Call. My name is Modesta, and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Jay Wilson, Vice President, Investor Relations. Please proceed, sir. Jay R. Wilson: Thank you, Modesta. Good morning, everyone, and thank you for participating in our third quarter earnings conference call. Earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. With me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President, Worldwide Exploration and Production; and John Rielly, Senior Vice President and Chief Financial Officer. I'll now turn the call over to John Hess. John B. Hess: Thank you, Jay, and welcome to our third quarter conference call. I will make a few brief comments, after which John Rielly will review our financial results. Net income for the third quarter of 2011 was $298 million versus $1.154 billion a year ago. Our third quarter results included charges of $140 million for abandonment liabilities primarily in the U.K. North Sea and $44 million for an increase in the U.K. supplemental petroleum tax rate. These charges were partially offset by $103 million gain from the sale of Hess' interest in the Snorre Field in Norway and the Cook Field in the United Kingdom. Also, last year's third quarter results included a net nonrecurring gain of $725 million. Excluding these adjustments, earnings for the third quarter of 2011 were $379 million versus $429 million a year ago. Exploration and Production reported net income of $422 million. Crude oil and natural gas production averaged 344,000 barrels of oil equivalent per day, which was 17% below the year-ago period. Aside from the sale of mature U.K. natural gas assets early in the year, most of the year-over-year production decline was due to several short-term setbacks. We are pleased to say that most of these issues are being resolved and that with the exception of Libya, we are in the process of recovering lost volumes. In Norway, a fire at the outside-operated Valhall Field in July resulted in the field being shut in for more than 2 months, negatively impacting third quarter production by approximately 20,000 barrels of oil equivalent per day. Operations resumed September 17, and net production is currently averaging more than 30,000 barrels of oil equivalent per day. In the Gulf of Mexico, the Llano #3 well was producing at a net rate of approximately 10,000 barrels of oil equivalent per day prior to being shut in due to mechanical issues in the first quarter of this year. The operator plans to perform a workover and restore production in the first half of 2012. In Libya, approximately 23,000 barrels of oil equivalent per day of net production remains shut in due to civil unrest. We cannot estimate when production will resume until security returns to the country. With regard to the Bakken, net production averaged 32,000 barrels of oil equivalent per day in the third quarter, up from 25,000 barrels of oil equivalent per day in the second quarter. Currently, net production from the Bakken is approximately 39,000 barrels of oil equivalent per day. As a result of the increased acreage position from last year's acquisitions and positive well results year-to-date, we forecast net production from the Bakken will increase to 60,000 barrels of oil equivalent per day in 2012 and to 120,000 barrels of oil equivalent per day in 2015. In September, we announced the acquisition of 185,000 net acres in the emerging Utica Shale play in Eastern Ohio principally through 2 separate transactions. We entered into an agreement with CONSOL Energy, which closed last week, to acquire a 50% interest in nearly 200,000 acres for aggregate payments of $593 million over 5 years. We also acquired market exploration and other leasehold interest, which added another 85,000 net acres at a cost of approximately $750 million. With these transactions, we have built a strategic acreage position in the Utica Shale, strengthening our portfolio of high quality unconventional assets, leveraging our operating expertise and creating significant potential for future growth in reserves and production. Appraisal activities on this acreage are planned to commence in the fourth quarter. Yesterday, we also announced that we will proceed with the development of the Hess-operated Tubular Bells Field in Mississippi Canyon area of the Deepwater Gulf of Mexico. The plan calls for 3 subsea production wells and 2 water injection wells tied back to a third-party owned SPAR production facility. Drilling is scheduled to begin in 2012, and initial production is expected in 2014, subject to the receipt of necessary government permits. Annual net production is expected to peak at approximately 25,000 barrels of oil equivalent per day, and net recoverable resources are estimated at more than 65 million barrels of oil equivalent. The net cost of the development is expected to be approximately $1.3 billion. Following government approval of the recent assignment of BP's interest, Hess will hold a 57.14% interest and Chevron will hold the remaining 42.86% interest. With regard to deepwater exploration, the Stena DrillMAX drillship has been contracted and we currently plan to drill a minimum of 3 exploration wells on our 90%-owned Deepwater Tano Cape Three Points Block in Ghana, commencing in the first quarter of 2012. In Indonesia, we spud the Andalan well on the Semai V Block, July 12. We are currently drilling below 17,000 feet and expect to reach total depth of about 22,000 feet during the fourth quarter. Hess has 100% working interest in the block. In Brunei, the operator of Block CA-1, in which Hess has a 13.5% interest, spud the Julong Center well on September 1. The well is expected to reach total depth in the fourth quarter and additional wells are planned in 2012. Turning to Marketing and Refining, we reported a loss of $23 million for the third quarter of 2011. Our share of the HOVENSA Refinery's losses was $36 million, which was an improvement over the year-ago quarter as a result of stronger gasoline and distillate crack spreads. While the refinery effectively broke even in July and August, a significant drop in gasoline refining margins in September contributed to the third quarter loss. Marketing earnings of $41 million were comparable to last year's third quarter. In retail marketing, gasoline volumes on a per site basis and convenience store sales were both down nearly 2%, reflecting the weak economy. In Energy Marketing, electricity sales volumes were up versus the year-ago quarter, while natural gas and fuel oil sales volumes were relatively flat. Capital and exploratory expenditures in the first 9 months of 2011 were approximately $5.2 billion. For the full year, our capital and exploratory expenditures forecast has been increased to $7.2 billion from $6.2 billion. The acquisitions of acreage in the Utica and an additional 4% interest in the Hess-operated South Arne Field in the Danish sector of the North Sea account for the increase. We are excited to have acquired a strategic position in the emerging Utica Shale play which strengthens our portfolio of unconventional resources. We remain committed to maintaining a strong balance sheet to fund our future investment opportunities and profitably grow our reserves and production. I will now turn the call over to John Rielly. John P. Rielly: Thanks, John. Hello, everyone. In my remarks today, I will compare third quarter 2011 results to the second quarter. The corporation generated consolidated net income of $298 million in the third quarter of 2011 compared with $607 million in the second quarter. The third quarter results included net after-tax charges of $81 million from items affecting comparability of earnings between periods. Turning to Exploration and Production. Exploration and Production had income of $422 million in the third quarter of 2011 compared with $747 million in the second quarter. Third quarter results included several items affecting the comparability of earnings between periods that were described earlier by John Hess. Excluding these items, the changes in the after-tax components of earnings are as follows: Lower sales volumes decreased earnings by $171 million; lower selling prices decreased earnings by $98 million; lower exploration expense increased earnings by $33 million; higher operating costs decreased income by $25 million; all other items net to an increase in earnings of $17 million for an overall decrease in third quarter adjusted earnings of $244 million. Our E&P operations were underlifted in the quarter compared with production, resulting in decreased after-tax income of approximately $30 million. Our E&P total production unit costs were approximately $39.35 per barrel in the third quarter. We estimate our total production unit cost will be approximately $39 per barrel in the fourth quarter. A charge of $44 million for the additional 12% supplementary tax in the United Kingdom includes a provision of approximately $15 million, representing the incremental tax on earnings from the effective date of March 24, 2011, to the end of the second quarter and a charge of $29 million to increase the United Kingdom deferred tax liabilities on the balance sheet. Excluding the impact of the items affecting comparability of earnings between periods, the E&P effective income tax rate was 27% for the third quarter, primarily reflecting the mix of earnings, and 37% for the first 9 months of 2011. Turning to Marketing and Refining. Marketing and Refining generated a loss of $23 million in the third quarter of 2011 compared with a loss of $39 million in the second quarter. Refining losses were $38 million in the third quarter of 2011 compared with a loss of $44 million in the second quarter. The corporation's losses from its equity investment in HOVENSA were $36 million in the third quarter of 2011 compared with $49 million in the second quarter. Port Reading broke even in the third quarter of 2011, down from earnings of $5 million in the second quarter. Marketing earnings were $41 million in the third quarter of 2011, an increase from $28 million in the second quarter, principally reflecting higher margins in energy marketing. Trading activities generated a loss of $26 million in the third quarter of 2011 compared with a loss of $23 million in the second quarter. Turning to corporate and interest. Net Corporate expenses were $44 million in the third quarter of 2011 compared with $42 million in the second quarter. After-tax interest expense was $57 million in the third quarter of 2011 compared with $59 million in the second quarter. Turning to cash flow. Net cash provided by operating activities in the third quarter, including a decrease of $11 million from changes in working capital, was $1,022,000,000. Capital expenditures were $2,434,000,000. Proceeds from asset sales were $131 million. All other items amounted to a decrease in cash of $86 million, resulting in a net decrease in cash and cash equivalents in the third quarter of $1,367,000,000. We had $827 million of cash and cash equivalents at September 30, 2011, and $1,608,000,000 at December 31, 2010. Total debt was $5,592,000,000 at September 30, 2011, and $5,583,000,000 at December 31, 2010. The corporation's debt-to-capitalization ratio at September 30, 2011, was 22.8% compared with 24.9% at the end of 2010. 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 today comes from the line of Ed Westlake with Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Obviously, a disrupted quarter with all of what's been going on, but hopefully it'll bounce back in Q4. But I wanted to touch on the Bakken. Can you give a latest update on where well costs are trading given concerns over cost inflation in that area? Gregory P. Hill: Let me first just make a couple of remarks about the Bakken. First of all, we're back on track in the Bakken following a tough weather-related start to the year. As John mentioned in his opening remarks, we're currently at about 39,000 barrels a day, up 28% or 7,000 barrels a day on average Q-on-Q. We're adding an additional frac crew in the next couple of weeks and expect to reduce our backlog of wells while waiting completion over the next 9 months. And assuming normal weather through the winter, we feel very confident about achieving not only our production forecast this year, but also our 60,000 barrels a day in 2012. Regarding your question, the cost for a 38-stage frac, a good number to use is $10 million. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And just coming back to the overall capital spend, obviously the Bakken, you're spending a lot there. You've got some wells in Ghana and you've just launched Tubular Bells. You gave the guidance of sort of $6 billion to $7 billion as you get closer to next year. Where should we be thinking about in terms of within that range? John B. Hess: Yes, we're going to give that update no later than the fourth quarter conference call in January. We're finalizing those numbers now. I think the important thing to recall both for this year and next year is that we're in a long-term business that obviously is commodity-based, volatile and cyclical. Having said that, our strategy remains to grow our reserves and production on a profitable and sustainable basis, and the majority of our funding for that will come from internal cash flow and selected asset sales. In fact, this year, we've had asset sales in the range receiving proceeds of about $490 million. Edward Westlake - Crédit Suisse AG, Research Division: So you feel comfortable about your liquidity position? John B. Hess: Yes, I do.

Your next question comes from the line of Paul Sankey with Deutsche Bank. Paul Sankey - Deutsche Bank AG, Research Division: Just to follow-up on your last response there. You've, I think, said that you'll spend $6 billion to $7 billion next year. I assume that you'll pull in that guidance range. And in the past you said you'll live within your means although you had mentioned the possibility of raising debt. Could you just update us really on whether you expect to meet next year's CapEx requirements more likely through asset sales or through debt? And whether or not I'm on the right number for CapEx? John B. Hess: Yes, the CapEx again, we will give that guidance in no later than the fourth quarter call in January. The majority of our funding for our program next year will come from internal cash flow and some selected asset sale. Paul Sankey - Deutsche Bank AG, Research Division: Can you say more about what you might consider reducing it. I mean, obviously, it doesn't feel like it's going to be the Bakken. But can you talk a little bit about where you really want to push your focus, John? John B. Hess: Well, in the last couple of years, we've increased our exposure happily so to unconventionals. About 40% of our spending now is on unconventionals. It's a more balanced approach. It provides lower risk growth to our future production and earnings. And that balanced approach between the unconventionals and conventionals, that balance should continue in the future. Paul Sankey - Deutsche Bank AG, Research Division: Okay. So we should think about you as kind of 50-50 on conventional international? John B. Hess: That's pretty close. Paul Sankey - Deutsche Bank AG, Research Division: And then finally for me on refining. You mentioned it was a margin story, the breakeven in July, August went into a severe September situation. Is it correct to characterize it as an asset that's really subject to margin vagaries? Or are there more operational and strategic actions you can take to improve performance there? John B. Hess: Yes, as you know and recall that we took steps in the last year in our joint venture to downsize the refinery to increase the margin per barrel and also take some costs out of the business. That's all been successful. I think the benefit to that, we certainly saw at the beginning of the third quarter. But what happened were really 2 things. Gasoline margins came down in September, but also the front end of the crude market came up, and so margins were squeezed there. I think the refinery is in a more competitive position but it still has some competitive issues in entire fuel cost versus the Gulf Coast refinery that has the advantage of natural gases at feedstock. And that's an issue that we still look at. And as I've said before, it's a very small piece of our portfolio. We wanted to run reliably and securely, safely, and we're going to continue to do all we can to optimize its financial performance. And we'll always consider strategic options, but given the current environment, they're not that many, and we also have a partner that we also have to work with in that regard. Paul Sankey - Deutsche Bank AG, Research Division: I understand, John. And within that segment somewhat the trading loss that you had this quarter Q3, was there anything unusual or one-off about that or what went wrong there? John P. Rielly: No, nothing unusual. As you know, it's a typical trading environment in the third quarter. The business, it's a small part of our portfolio. It's been good to us. It's been profitable 13 out of the last 14 years prior to this one. It took action. It did reduce positions and reduced its risk through the quarter. But nothing unusual there.

Your next question comes from the line of Evan Calio with Morgan Stanley. Evan Calio - Morgan Stanley, Research Division: Some exciting changes in your portfolio. Let me ask you a question and not to beat a dead horse, but just a bit of a follow-up on the spending and as you think about a downside commodity scenario, I mean, I know look, the market is somewhat focused on a crude deck that's south of $30. From the strip, I know -- I remember, John, in 2009 you raised the potential of an equity offering in a much lower and in a different environment than we're in today. But how do you look at your combination of assets, spending commit and balance sheet, as I know you've extended $4 billion plus in revolver, as distinguished versus '09 and support activity even if we're in a period of lower commodity prices? And how do you think about your flexibility versus that period of time and portfolio opportunities? John B. Hess: Well, I think it's important to know that we remain committed to keeping a solid investment grade rating. We also remain committed to having a very strong balance sheet that John Rielly talked about before. We have available to us a $4 billion revolving credit facility that is undrawn. So we feel we have plenty of liquidity to fund our capital spend going forward through the cycle between internal cash flow, selected asset sales and liquidity facilities that we have on hand. Evan Calio - Morgan Stanley, Research Division: Okay. So, I mean, feeling better than '09 contextually, if you think about it? John B. Hess: I wouldn't want to put a hypothesis. '09 was a much more difficult environment. Evan Calio - Morgan Stanley, Research Division: Good, now we agree. A different question on exploration. Walk through the exploration portfolio a bit, I know you gave an update on Semai V in terms of drilling depth. I kind of missed that, but is that -- are we on track to your results within weeks? Is that the general takeaway there? And then I know you had discussed, I think, 2 other prospects in that block that we should expect in 2012 and maybe you could either dimension those in size or discuss it. I believe they're different play types than the current structures, so it's not a path-dependent exploration portfolio there in Indonesia? Gregory P. Hill: Yes. So just to reiterate some of the comments in John's opening remarks, the well's spud in July, we're currently drilling at 17,000 feet right now. TD is about another 5,000 feet down. So this is a tight well. So we're not going to reveal any interim details on the well, Evan, until the well is done. Regarding your question about the block, it's actually a 3-well commitment on the block. And until we get this well done, we won't determine where those next wells are going to be. Evan Calio - Morgan Stanley, Research Division: Okay. But do you still anticipate 2 other prospects in 2012 on that commitment? Gregory P. Hill: Yes, we have 2 more wells that are commitments on the block following this one now. Yet to be determined what those wells are going to be or where or what depth or anything like that. We really want to get this well done first. Evan Calio - Morgan Stanley, Research Division: Okay. And you're trading that rig back and forth of Murphy in Indonesia. Is that right? Gregory P. Hill: We're finalizing all the rig strategy as we speak. Evan Calio - Morgan Stanley, Research Division: Okay. Any exploration in Ghana, a reasonable acreage position there in 2012? Gregory P. Hill: Yes, the plans are we've got 2 exploration wells currently in the permitting process in various phases, net fits [ph] and Heron in the exploration phase. Anticipating bringing the Stena Forth back into the Gulf of Mexico early 2012, most likely begin drilling net fits [ph] in 2012. Evan Calio - Morgan Stanley, Research Division: Okay. So begin drilling in the second half. So... Gregory P. Hill: No, early 2012. Still finalizing our plans. But early 2012 is when we'll start drilling in the Gulf of Mexico again. Evan Calio - Morgan Stanley, Research Division: Okay. And then on Ghana, just to kind of finish that out, you mentioned a minimum of 3. I mean, can you give us a high level and is that also -- is that path-dependent of the other wells or rig-dependent? How should we think about that potential range there? Gregory P. Hill: Yes. So we have committed 2 rigs and that's the Stena DrillMAX. We've contracted for 5 firm wells on that rig. The current plan with Ghana, which again we're continuing to work with the government, is to drill a minimum of 3 wells. Now just to remind everyone, we're really testing 3 different play types on the block in Ghana. One is a deeper Cretaceous structure that sits below Paradise. The next one is a look-alike structural play near Paradise, and then the third one is a test on one of the many stratigraphic channel sand plays on the western part of the block. So with these 3 wells, we're actually going to test 3 different play types and their exploration wells.

Your next question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: I'm going to try a few quick ones if I may. First of all, John or Greg, can you give us an update on your drilling plans in the Utica? Gregory P. Hill: Yes, sure, Doug. As John mentioned in his opening remarks, we plan to begin appraisal activities in the fourth quarter. That will be the first thing that we will do is complete the market well. And then we're working with our partner, CONSOL, on starting drilling activities on some of that acreage. Next year, we'll be running 3 rigs in the Utica. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Great. And you described this, and my recollection is this is your second beachhead in unconventional shale after the Bakken. So I guess getting into the discussion about cash flow and asset sales and all the rest of it are $3,000 per acre entry to the Eagle Ford given where those acreage positions are selling for right now, could you describe the Eagle Ford as core or is that perhaps surplus to requirements now? And maybe the same question around Australia given your growth options in North America. Gregory P. Hill: Yes, Doug, as you know, the Eagle Ford, our focus right now is on delineating the acreage we have, and we're pleased with the results to date. So we've made no further decisions other than just staying focused on delineating what we have. Similar story in Australia. I mean, we've got some appraisal work left to do in Australia. As you know, we've so far flow tested 5 wells with results coming in as expected. And we plan to drill and test 3 additional wells by mid-2012. We've got a rig coming back at the end of the year. And so, again, we're just in the appraisal understanding mode. Also in parallel, as you know, we're in commercial discussions with 3 liquefaction routes, which I mentioned before multiple times on the call, and really trying to bring all these things together so that we can make an informed decision sometime in 2012 about the next step for the block. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Let me just jump back to the Eagle Ford. Just to kind of follow up on that, are you actively expanding your acreage position? Or are you kind of set part with what you've got right now? Gregory P. Hill: Well, I think we're being opportunistic. The pricing is pretty high in the Eagle Ford still. As we see opportunistic ways to fill in our acreage around this, we'll do that but only if we believe it makes money. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: And then last one for me, this one is maybe for John Rielly. But again, the focus seems to be on CapEx and cash flow next year, John, but you're obviously stepping up capital expenditure on unconventional drilling or lower 48 capital overall. At least on my numbers, that's going to leave you with a fairly significant deferred tax potential asset. Can you help us quantify? My understanding is you can write off 70% of intangible drilling cost as an integrated oil company. Can you maybe just put some numbers around that because I'm guessing that's a fairly big cash offset in terms of cash flow in 2012, and I'll leave it at that. John P. Rielly: What you said is correct. There is -- you can take 70% deduction on our intangible drilling costs as an integrated company. Now I think as John Hess said earlier, we're still working out our capital budget for 2012. And at this point, I couldn't give you specific numbers on the amounts, from an unconventional standpoint, that would become intangible drilling cost. So and it's really kind of detailed information from a tax standpoint that we really wouldn't provide. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: But do you think it would -- say, would there be a meaningful cash tax number, John, at least not looking for a hard number but notionally, are we thinking about it the right way? John P. Rielly: You are thinking about it the right way. So again, from an income statement standpoint, it makes no difference. You're going to still have a federal and state tax provision that's at the statutory rates. But it does provide cash tax relief early on. And then later on, you'll end up paying those cash taxes.

Your next question comes from the line of Paul Cheng with Barclays Capital. Paul Y. Cheng - Barclays Capital, Research Division: Maybe this is the first one for Greg. Greg, on Ghana, when are you going to drill the first well? Gregory P. Hill: Well, it will be again, we're still in negotiations with the government on various things. But the plan is to get a rig in there early in 2012. So first quarter is when we anticipate spudding. Paul Y. Cheng - Barclays Capital, Research Division: Do you think that the -- I mean, that the first well was quite a long time before you finish it? With that learning, how long do you think that the second well you're going to drill? Gregory P. Hill: Well, I mean, all these wells assuming you just drill it and don't do a lot of testing and things like that, these are 60- to 80-day wells. Paul Y. Cheng - Barclays Capital, Research Division: But, I mean, are you going to do some testing? Gregory P. Hill: Don't know. Yes, we'll just have to wait until we get into the well, Paul, and see what we have. No plans to test Paradise, but future wells, we'll just wait and see what happens. Paul Y. Cheng - Barclays Capital, Research Division: And then after the first appraisal well in Paradise, will you be in a position that you'll be successful, will you be in a position that you perhaps disclose a little bit more in terms of the size of the range of the resource and also the oil and gas mix? Gregory P. Hill: Yes, so let me clarify that the next 3 wells we're drilling are actually exploration wells. Paul Y. Cheng - Barclays Capital, Research Division: So you're not going to do the appraisal wells? Gregory P. Hill: Not appraisal wells. Right. So we're testing one look alike to Paradise, which is nearby, another structural test. We're testing something below Paradise. That's a lower Cretaceous structure, large structure. And then we're testing a third play type, which is a stratigraphic channel set. So those are 3 exploration wells. Paul Y. Cheng - Barclays Capital, Research Division: I see. And on the fourth quarter, this is for John Rielly. John, you're talking about total unit cost, and in E&P you expect third quarter at $39.35 to about $39, I would thought -- I would think that the drop will be a little bit more given that the return of the Waha and also the maintenance season in U.K. is over and also that Bakken will continue to rise. Is there any reason that why the unit cost is not going to drop more? John P. Rielly: You're right. Your answers are directionally right on the cash cost side. So as production will be coming up, our cash cost will be coming down from the third quarter. Our DD&A in the fourth quarter, as you probably followed us, I mean, typically, our DD&A rises throughout the year as we add additional CapEx onto the program and then the reserve, more reserve bookings happening at the end of the year. So one, you have that reason. The other point is we are in an investment mode and a lot of good things are going on. So like take the Bakken. We've got -- we're drilling right now in all acquired acreage right now. It's not on our legacy position. So we're in the AOG and Tracker acreage, so that has an acquisition cost on it. We're making a lot of infrastructure investments, and we move to the 38-stage frac designs. So I mean, a lot of good things going on that will provide very good returns for us for years to come. But those investments, what happens is with reserve bookings, they always lag the investment dollars. So the reserve bookings will begin to come later on in fields like, same thing in Valhall. So we'll begin to see the DD&A rates come down out in the future, but we will have a pickup in the DD&A rate for fourth quarter. Paul Y. Cheng - Barclays Capital, Research Division: I see. And going back to Greg. Greg, I mean, if we're looking at your one way of your exploration expense, this quarter is a little bit lower than usual, but you're probably talking about somewhere in the $900 million to $1 billion at year-end exploration expense. And that's equal to roughly over, say, $6 to $7 per barrel of your production. Is that the kind of number that you think on the long haul is a reasonable level or that over the long haul that you should target a lower per barrel production in terms of exploration expense? Gregory P. Hill: Yes, Paul, so again, in 2012, I mean, we're in the middle of our budget cycle. So we haven't finalized any of those numbers at all for next year. I would like to think that as long as we can generate excellent prospects that we will continue with our organic drill bit-led strategy. It will really going to depend... Paul Y. Cheng - Barclays Capital, Research Division: But you don't think that you're spending too much money on the exploration side? Gregory P. Hill: If we have opportunities to drill, we will drill the opportunities that we have, yes. Paul Y. Cheng - Barclays Capital, Research Division: Two final question for me. One in Eagle Ford. Greg, you provide some well data for Bakken. Can you give us the well data in terms of production warning [ph] for the well that currently is in production and also some of the IP and well cost? And secondly, that for Bakken, have you -- do you believe that you have seen the petrol in terms of the well cost or that you're still seeing a lot of inflation pressure? Gregory P. Hill: Yes. So let me address the Bakken first. As I mentioned, the cost for a 38-stage, a good number to assume is $10 million. Looking forward, we're optimistic that we can continue to drop that well cost through our lean manufacturing, further application of lean manufacturing and also whether or not to do sliding sleeve or plug and perf. We're pushing the technology on sliding sleeve to get greater and greater numbers of sliding sleeves in the well. So those are opportunities we see to continue to drop that well cost. Turning to the Eagle Ford. Just to remind everyone that we've drilled 22 wells thus far. Eight wells have been completed and brought on production. And on average, the 30-day IP rates of these wells are about 500 barrels per day, of which about 60% is liquids. Well costs are running about $10 million each for a 15- to 21-stage frac design. However, we expect this cost to come down as we employ many of our Bakken operating practices to the Eagle Ford. So still early days in the drilling cycle on the Eagle Ford.

Our next question comes from the line of Arjun Murti with Goldman Sachs. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: Just hoping for an update on the status of some of the Bakken infrastructure product -- projects, most notably the rail capacity. How that project is progressing and timing of ramp up. And I know that's the key one that -- maybe I'll stop there for the question. Gregory P. Hill: Yes, I think on the recall there's kind of 2 major infrastructure projects. One is the expansion of the Tioga Gas Plant, which is on track. That will be complete at the end of 2012. The Tioga rail expansion is nearing completion, and we'll be ready to ship our first trains in early 2012. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: And what is the initial capacity on the rail expansion? Gregory P. Hill: It will be -- we've got 9-train car sets, and that gives us about a 54,000-barrel a day capacity. Now obviously, in the future if need be, we can expand that with additional train sets. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: Yes. And the 54,000, once it starts up, it's up. We shouldn't think in terms of some ramp up to 54,000. It's an on or off type of deal? John B. Hess: No, don't have some flexibility to deal with our own production flexibility. And in fact, we'll probably going to send a couple of rail cars to debottleneck that facility in the fourth quarter. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: That's fantastic. And I don't think I missed it. Any update on Australia LNG, where that stands right now? Gregory P. Hill: No, I think as I mentioned earlier, we've taken a drilling break, and that's really just waiting on the rig to come back out of the shipyard after recertification. Expect to begin drilling very late this year. Drill 3 more appraisal wells and do some testing and trying to be complete with that program say mid-2012 in Australia. In parallel, we're continuing all the commercial discussions with Pluto, with Wheatstone and with Northwest Shelf trying to figure out the optimum commercial routes for the gas.

Your next question comes from the line of Mark Gilman with The Benchmark Company. Mark Gilman - The Benchmark Company, LLC, Research Division: I had a couple of things. Was wondering whether or not you've seen any interest to date in the form down being offered on BM-S-22. Gregory P. Hill: That data room has just been opened, Mark. So really can't comment on how many people have been through. Mark Gilman - The Benchmark Company, LLC, Research Division: Okay. Greg or John Rielly, perhaps you might be able to flush out a little bit the circumstances surrounding the "assignment" of BP's interest in Tubular Bells? Gregory P. Hill: Yes, I think the terms of that assignment are confidential, Mark. Suffice to say that we've -- Chevron and us have split BP's interest. Mark Gilman - The Benchmark Company, LLC, Research Division: For consideration or not, Greg? Gregory P. Hill: Terms are confidential. Mark Gilman - The Benchmark Company, LLC, Research Division: All right. Let me try something else. On the Bakken, the oil gas split pretty much remaining constant? Gregory P. Hill: Yes, it is. Mark Gilman - The Benchmark Company, LLC, Research Division: So 90-plus percent liquids? Gregory P. Hill: Yes, it is. Yes. Mark Gilman - The Benchmark Company, LLC, Research Division: Okay. Last one for me. For John Hess, I noticed that the FCC utilization rate of HOVENSA continues to be low, John, mid-70s, which is kind of in the range. Any issues there that perhaps you can address that might yield better performance going forward? John B. Hess: It's more an economic issue, Mark, than anything else. Some of the operating problems we've had at HOVENSA in the past, I think they've made a lot of improvements in terms of reliability, operating excellence. So it's more an economic-driven issue. Mark Gilman - The Benchmark Company, LLC, Research Division: So you've been cutting it back basically? John B. Hess: Yes. Gregory P. Hill: Yes, Mark, I just wanted to clarify the Bakken range is between 85% and 90% liquids.

Your next question comes from the line of John Herrlin with Société Générale. John P. Herrlin - Societe Generale Cross Asset Research: Yes, just some quick ones. With Utica Shale, Greg, what kind of spending rate do you think you'll have on kind of a quarterly basis or an ongoing basis? Gregory P. Hill: Well, we're still trying to finalize that with our partner, CONSOL. As I mentioned, we plan to ramp up the 3 rigs in the Utica in 2012, but we're finalizing all those estimates with our partner right now. John B. Hess: Hopefully for the fourth quarter call, we can give more definition on that. John P. Herrlin - Societe Generale Cross Asset Research: Okay. Regarding the fourth quarter, you are drilling a lot of issued TD, a bunch of -- or at least 2 deepwater wells. What kind of dry-hole cost exposure is that? John P. Rielly: We typically just don't -- we don't give that -- those well costs out. So, I mean, you can figure out from the rigs that are being utilized as John Hess and Greg said earlier, we spud this in July. So from those days through, obviously, through September 30. And then we'll tell you when the final well comes in, in the fourth quarter. I mean, it will be a significant amount, but we don't give out that data on individual wells. John P. Herrlin - Societe Generale Cross Asset Research: Okay, that's fine. With respect to the Bakken wells, how much are the fracs now running as a percentage of total well cost 55% or 60%, how large are they? Gregory P. Hill: Yes, I think 60% is a pretty good number. John P. Herrlin - Societe Generale Cross Asset Research: Okay. With Ghana, when will you delineate Paradise? Gregory P. Hill: Again, our focus in 2012 is getting some additional exploration wells in the ground. So that is our primary focus as agreed to with the government. We're still in the exploration phase right now on the block. John P. Herrlin - Societe Generale Cross Asset Research: Okay. Still having partners or potential partners call up? Gregory P. Hill: Absolutely. There's very high interest in this block. We've had a data room open and have had a number of partners through the data room. John P. Herrlin - Societe Generale Cross Asset Research: Okay. Last one for me. Anything on Peru? Gregory P. Hill: There's nothing really noteworthy to report yet on Peru.

[Operator Instructions] Your next question comes from the line of Sven Del Pozzo with IHS Herold.

It's Sven Del Pozzo. Again, on the Bakken, around what time in 2012 do you think that you'll feel that you'll have your leases secured, the ones that you've most recently acquired with Tracker and American so that you'll be able to devote more pad, do more pad drilling? Gregory P. Hill: Yes, I think we'll have -- we'll largely have the majority of that acreage held by production by the end of 2012 with some spillover into 2013.

Okay. And again, on the Bakken, do you have any plans to explore any of the deeper Three Forks formations? Gregory P. Hill: Well, as you know, when we were doing the dual laterals in the pad drilling, we were drilling both Bakken and Three Forks wells. In the acreage that we've acquired, we've drilled some Three Forks wells as well. So it will be part of our long-term development strategy.

Pardon me, I didn't explain myself properly. I believe there are actually some even deeper Three Forks formations than the ones that you've been developing thus far. Gregory P. Hill: Right now, we're not looking at those. We're just focused on the conventional Three Forks, I'll call it, and the Bakken.

Okay. And again, following up on the 60% liquids content in the Eagle Ford, are we talking condensate or black oil? Gregory P. Hill: Both, but primarily condensate.

Okay. And what kind of an NGL proportion of the total hydrocarbon split should I consider or should I use? Gregory P. Hill: It's a bit premature because, again, we're continuing to delineate that acreage.

Okay. And this is more of an accounting question on the reporting for the North Sea. Oil price realizations in the third quarter look like something like $65. Just wondering why in the second quarter they were $85. How do I reconcile those 2 numbers? John P. Rielly: No, it's a good question. In the third quarter, with some of our North Sea maintenance, we had a significant underlift of barrels in the U.K., and then you also know, in Norway, Valhall we had a fire so we have less sales volumes there as well. So what that means is that our Russia production became a much higher part of our -- of that European production. And therefore, that Russia, while profitable, has a lower price realization. And so that's what dropped the oil realization down. You should just expect our oil realization to go back to normal in the fourth quarter.

Okay. And at Valhall, did the fire pose -- does it have any implications for the long-term redevelopment program at Valhall? Gregory P. Hill: No, there's no implications whatsoever for the long-term redevelopment. Philip Weiss - Argus Research Company: Okay. And that's supposed to hit 75,000 BOE a day to Hess, and I was wondering what time frame I should consider for that? Gregory P. Hill: Well, I think we're -- we continue to work with the operator to march our way to 75,000 barrels a day within 5 years after the completion of the redevelopment.

Okay. And this is my last question. I might have missed this during the comments, working capital component of your operating cash flow in the third quarter. John P. Rielly: It was a decrease to our cash flow of $11 million.

Your next question comes from the line of Robert Kessler with Tudor, Pickering, Holt & Co. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: A few more questions on the Bakken if you don't mind. Greg, you mentioned adding a new frac crew to help handle the -- reduce your inventory of drill bit on completed wells. Can you give us a quantification of the number of wells that you've got sitting in a drilled but uncompleted status? Gregory P. Hill: Yes, I think as we mentioned on last quarter's call, we had around 70 wells in our backlog. That number, it has remained constant, and that's why we're adding the additional frac crew. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Where do you think that'll gravitate down towards? I mean, is it going down near 0, is there always going to be an extra inventory of... Gregory P. Hill: I mean, there will always be a backlog because as part of lean manufacturing, you always have a certain number of batch jobs in your queue. But we believe we can work down the majority of that backlog with that additional frac crew over the next 6 to 9 months. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, that's great. And then also, thanks for the clarification on when you expect to hold by production the incremental acreage kind of towards the end of next years’ spillover to 2013. I'm curious what sort of drilling if incompletion efficiency uptick you might expect as you get back to more efficiently located wells. I mean, is this sort of a 15% kind of uptick we could see in a number of wells completed per rig here, for example? Gregory P. Hill: Yes, I think certainly the productivity will improve substantially as we get back to pad drilling. I think the biggest opportunity for increased efficiency obviously on the completion side will be if we can push the sliding sleeve technology to 38, 34 to 38 stages. And we have a number of successful 34-stage sliding sleeves in the ground as we speak. So that's probably our biggest opportunity for efficiency. That will be a significant savings in number of days to get a well completed. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And last one for me. Thoughts on netbacks on the Bakken once the rail comes online? John B. Hess: I wouldn't want to speculate about what the netbacks are going to be because WTI has had a lot of movement recently relative to Brent. So what the differentials will be going forward, there are a lot of moving pieces there. So I'd rather get some history under our belt and some clarity in the market before we would speculate that. Obviously, the differential between Brent or Gulf Coast-based crudes and WTI is still a very significant number. So the fact that we have railcars, that will enhance our net backs at the current time. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes. So clearly, the wider the differential, the more relative value of having new railcars, right? John B. Hess: It'll be net accretive in that regard.

Your next question is a follow-up from the line of Ed Westlake with Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: I'm just going ask 3 questions upfront, that's it. So IP rates in the Bakken from your latest wells, are you able to give a rough reserves split in Paradise for oil versus gas condensate? And then just a clarification on Arjun's question. I thought rail was going to be 130,000 barrels a day of capacity. Did I hear you right to say 54,000? Maybe some color there. Gregory P. Hill: Yes, so let me answer the rail. With 9 cars, we'll have a capacity of 54,000. If we add additional railcars, additional train sets, we can go all the way up to 150,000 barrels a day or so. But right now, we have 9 train sets ordered. Four have been delivered already. A fifth will come in October, and once we get those full 9, we'll be at 54,000 barrels a day. Regarding your IP rates, on the Bakken, we now have 84 38-stage systems installed. We've got 35 on production, 19 of which have 30-day IPs, and those IP rates are averaging just over 1,000 barrels a day on the 38-stage wells. So we continue to be obviously very encouraged by those results. Regarding Paradise, it's just too early. We got a lot more drilling, a lot more exploration to do on Ghana before we understand exactly what we have there. And I think we're encouraged. We've got 500 or 490 feet to pay [ph] in a well. We've got good reservoir quality, and we've got liquids component in the well. So I think we're pleased to date, but we've got a lot more stuff to do.

Your next question is a follow-up from the line of Paul Cheng with Barclays Capital. Paul Y. Cheng - Barclays Capital, Research Division: I have actually 4 quick follow-up. First, Greg, at the end of September, what is the -- actually at the end of the year, what is your expected exit rate for Bakken? And also, do you have a number you can share what is the Bakken -- from Bakken to the Gulf of Mexico, St. James what is the railroad tenant [ph] that you guys have contract? And third, when you think you get enough of the production data and feel comfortable to get a production estimate or target for Eagle Ford and Utica? And then a final one is for John Rielly. At the end of September, are you underlift or overlift? And in what region and what [indiscernible]? Gregory P. Hill: Okay. So let me answer a couple of questions on the Bakken first and then the Eagle Ford and Utica questions, and then I'll give it to John to answer the netbacks on the rail system. So we aren't going to quote an exit rate for the Bakken. I think what we've said is that we will -- our 2011 net production forecast is between 30,000 barrels and 35,000 barrels a day in the range. We're confident we are going to be in that range. We've also said that our average for next year will be 60,000 barrels a day, and I think we're confident that we can achieve that average rate for next year. Regarding production data and target for the Eagle Ford and Utica, obviously, Utica very early days. We haven't even gotten our first completion of wells. So I can't really give you any color yet on what the Utica will be. I think for the Eagle Ford, as I've said before, we're in the delineation mode. Most of our efforts have been focused on the southwest portion of the acreage. In the fourth quarter, we're going to be starting to delineate the northeastern part of the acreage. So, Paul, unfortunately, it's early days to even give you estimates on the Eagle Ford because, again, we're still in this delineation mode, trying to understand what we have. John B. Hess: Yes, and on the railcars, Paul, 2 points. The commercial terms of the rail agreement and the shipping arrangements are competitively sensitive. So I can't give further color on that. The only thing is where the spreads, where they are, it would be advantageous to our netback. Paul Y. Cheng - Barclays Capital, Research Division: And what is your inventory at the end of September underlift or overlift? John P. Rielly: Okay, for the balance of our assets, Paul, we have a small underlift, if you want to say, position. But and then in Norway, we've got an overlift position. So overall, I'd say we're generally balanced that way. So you shouldn't expect anything big, but you don't know based on the timings of lift.

Your next question comes from the line of Katherine Minyard with JPMorgan. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Just a couple of quick clarification questions. Can I just confirm, is your full year production guidance still 375 to 385? John P. Rielly: Yes, it is. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Can I just quickly -- can you walk me through just a little bit of where we would expect some of the recovery in 4Q? I know you've walked through some Bakken, and I know we've got Valhall back, and both of those add a pretty generous level of volume as we look from 3Q to 4Q. I guess when I look at 3Q, it looks as though Africa is a little bit low on liquids. And I'm wondering was there some maintenance or something that we'd expect to recover into 4Q? And what else might I be missing just in looking at 4Q to get into that full year range? John P. Rielly: You have the big pieces. So Valhall clearly coming back is the biggest. We've got the growth in the Bakken like you mentioned. The one thing I don't think I heard you mention, we did have North Sea maintenance. So we did have field down. It was -- we had South Arne, we had Sidern [ph], we had Shahalian [ph], so we expect some additional production coming back there. As far as in Africa, the decline was in EG. There was a small amount of downtime somewhere between 1,000 and 2,000 barrels there. Gregory P. Hill: But I would just add one comment on EG. We have a rig coming back into EG and anticipate being -- doing some completions and also drilling more wells next year in EG.

Your final question today is a follow-up from the line of Mark Gilman with The Benchmark Company. Mark Gilman - The Benchmark Company, LLC, Research Division: John Rielly or Greg, you got a capital cost number for the rail project? John P. Rielly: No, Mark. We don't provide that individual detail. Mark Gilman - The Benchmark Company, LLC, Research Division: John, can you say whether you're owning or leasing the railcars? John P. Rielly: We are owning them. Mark Gilman - The Benchmark Company, LLC, Research Division: Okay. And with respect to the lifting issue, the volume of the third quarter underlift? John P. Rielly: We were underlifted -- it was approximately 650,000 barrels in the third quarter. We were underlifted by approximately 600,000 barrels in both the U.K. and Azerbaijan. So 1.2 billion combined between those 2 countries. And we did had an over lift in Norway. We had a lower production. So based on the lower production, our sales volumes were higher in Norway by 500,000 barrels, and that's how it nets back down to the 650,000 barrels.

Ladies and gentlemen, that does conclude today's Q&A portion, as well as the conference. Thank you for your participation. You may now disconnect. Have a great day.