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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Edward Westlake - Crédit Suisse AG, Research Division Evan Calio - Morgan Stanley, Research Division Arjun N. Murti - Goldman Sachs Group Inc., Research Division Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Paul Y. Cheng - Barclays Capital, Research Division Paul Sankey - Deutsche Bank AG, Research Division Pavel Molchanov - Raymond James & Associates, Inc., Research Division Faisel Khan - Citigroup Inc, Research Division

Good day, ladies and gentlemen, and welcome to the First Quarter 2012 Hess Corporation Earnings Conference Call. My name is Chanel, and I will be your operator 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 Mr. Jay Wilson, Vice President of Investor Relations. Please proceed. Jay R. Wilson: Thank you, Chanel. Good morning, everyone, and thank you for participating in our first 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. John B. Hess: Thank you, Jay, and welcome to our first quarter conference call. I will make a few brief comments, after which John Rielly will review our financial results. Net income for the first quarter of 2012 was $545 million. Compared to the year ago quarter, our earnings were negatively impacted by lower crude oil sales volumes and higher operating costs, which more than offset the impact of higher realized crude oil and natural gas selling prices. Exploration and Production earned $635 million. Crude oil and natural gas production averaged 397,000 barrels of oil equivalent per day, which was roughly flat with the year ago quarter. Higher production from the Bakken in North Dakota, the Pangkah Field in Indonesia and the Malaysia/Thailand Joint Development Area offset the impact of North Sea natural gas asset sales and natural field declines in Equatorial Guinea. In North Dakota, net production from the Bakken averaged 42,000 barrels of oil equivalent per day in the first quarter compared to 25,000 barrels of oil equivalent per day in the year ago quarter. Thus far in April, net production from the Bakken has averaged 47,000 barrels of oil equivalent per day. While we expect the monthly average to continue to increase throughout the rest of the year, we now expect the average for the full year may come in somewhat lower than our original estimate of 60,000 barrels of oil equivalent per day. As usual, we will update this estimate as well as our overall company production forecast on the July conference call. At the Llano Field in the deepwater Gulf of Mexico, the operator is currently performing a workover on the Llano #3 well, which was shut in for mechanical reasons in the first quarter of last year. We expect that production from this well will resume by the end of May. At Valhall in Norway, field redevelopment is expected to be completed in the third quarter. Net production averaged 22,000 barrels of oil equivalent per day in the first quarter. In Libya, net production averaged 18,000 barrels per day in the first quarter and has averaged 21,000 barrels per day in April. With regard to exploration in Ghana, on March 27, we spud the Hickory North well in the Deepwater Tano Cape Three Points Block. This prospect is located 3.5 miles west of our Paradise discovery and the well will test reservoirs similar to those found at Paradise, as well as deeper targets. Following completion of Hickory North, we plan to drill a prospect called Sisili, a large structure located approximately 5.5 miles southeast of Paradise. As a result of recently signed farmout agreements, which are subject to final government approvals, Hess' working interest in the block will be reduced from 90% to 35%. Offshore Brunei. The Julong East well on Block CA-1, in which Hess has a 13.5% interest, encountered hydrocarbons and the operator is currently evaluating the results. The rig has now moved to the southeast to spud the Jagus East well, which will test an offset to the Gumusut Field, currently under development on the Malaysian side of the border. Later in the second quarter, we plan to resume exploration drilling in the deepwater Gulf of Mexico. Ness Deep, located in Green Canyon 507, is a Miocene prospect in which Hess has a 50% working interest. BHP has the remaining 50% and is the operator. Turning to Marketing and Refining. We reported net income of $11 million for the first quarter of 2012. The previously announced shutdown of the HOVENSA joint venture refinery was completed in the first quarter. As a result of the charge taken last quarter, there was no net income impact from HOVENSA's first quarter operations. Marketing earnings were $22 million compared to $68 million in last year's first quarter. Retail marketing faced rising wholesale prices during the first quarter, which put pressure on fuel margins. Gasoline volumes on a per site basis were flat, while total convenience store sales were down 2% versus last year's first quarter. Energy Marketing earnings were lower than last year's first quarter as a result of significantly warmer weather this past winter. With regard to asset sales, in the first quarter, we closed the sale of our interest in the Snohvit Field in Norway for $132 million and entered into an agreement to sell our interest in the in the Bittern Field in the United Kingdom, which is expected to close in the fourth quarter. Also in March, we announced that we have started the sale process for our St. Lucia oil terminal. Additional asset sales are in progress, and we will provide updates as soon as details become available. We anticipate that proceeds from asset sales, along with internally generated cash flow, will fund the majority of our capital and exploratory expenditures in 2012. Our principal focus this year continues to be on execution and the sustained profitable growth of 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 results from the first quarter of 2012 to the fourth quarter of 2011. Corporation generated consolidated net income of $545 million in the first quarter of 2012, compared with a net loss of $131 million in the fourth quarter of 2011. Excluding items affecting comparability of earnings between periods, Corporation had earnings of $509 million in the first quarter of 2012, compared with $394 million in the previous quarter. Turning to Exploration and Production. Exploration and Production had income of $635 million in the first quarter of 2012, compared with $527 million in the fourth quarter of 2011. First quarter results included a gain of $36 million related to the sale of the corporation's interest in the Snohvit Field, offshore Norway. Excluding the effect of the asset sale, the change in after-tax components of the results were as follows: Lower sales volumes decreased earnings by $16 million. Higher realized selling prices increased earnings by $10 million. Lower exploration expenses improved earnings by $94 million. Higher cash cost decreased income by $29 million. All other items net to an increase in earnings of $13 million, for an overall increase in first quarter adjusted earnings of $72 million. Our E&P operations were under-lifted in the quarter compared with production, resulting in decreased after-tax income of approximately $35 million. E&P effective income tax rate for the first quarter of 2012 was 40%, excluding items affecting comparability of earnings between periods. Turning to Marketing and Refining. Marketing and Refining generated income of $11 million in the first quarter of 2012, compared with a loss of $561 million in the fourth quarter of 2011. Marketing earnings were $22 million in the first quarter of 2012, compared with $48 million in the fourth quarter of 2011, principally reflecting lower margins and volumes in retail operations. In refining, Port Reading operations incurred a loss of $6 million in both the first quarter of 2012 and the fourth quarter of 2011. As discussed last quarter, HOVENSA reported losses of $592 million in the fourth quarter of 2011, which included an after-tax charge of $525 million due to the refinery shutdown. In the first quarter of 2012, trading activities generated a loss of $5 million, compared with a loss of $11 million in the fourth quarter of 2011. December 31, 2011, Corporation had an accrued liability of $487 million for its share of future funding commitments for costs to shut down HOVENSA's refinery in St. Croix. Corporation, along with its partner, fully funded their estimated commitments in the first quarter of 2012. Turning to Corporate. Net corporate expenses were $38 million in the first quarter of 2012, compared with $40 million in the fourth quarter of 2011. After-tax interest expense was $63 million in the first quarter of 2012 compared with $57 million in the fourth quarter, reflecting higher borrowings and bank facility fees. Turning to cash flow. Net cash provided by operating activities in the first quarter, net of funding of the accrued liability to HOVENSA of $487 million, was $988 million. Capital expenditures were $1,878,000,000. Net borrowings were $889 million. Proceeds from asset sales were $132 million. All other items amounted to a decrease in cash of $86 million, resulting in a net increase in cash and cash equivalents in the first quarter of $45 million. We had $396 million of cash and cash equivalents at March 31, 2012, and $351 million at December 31, 2011. Total debt was $6,978,000,000 at March 31, 2012, and $6,057,000,000 at December 31, 2011. And the corporation's debt to capitalization ratio was 26.7% at March 31, 2012, compared with 24.6% at the end of 2011. This concludes my remarks. We'll be happy to answer any questions. I will now turn the call over to the operator.

[Operator Instructions] Your first question comes from the line of Doug Leggate, Bank of America Merrill Lynch. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: I've got a couple of questions, if I may. First of all, on the progression in your Bakken production guidance, I wonder if you could help us reconcile what's going on there because basically, if you look at the latest sort of public well data from the state, it looks like your production in -- the vast majority of the wells you drilled, at least in the last 6 months or so, are coming in substantially better than the type curve guidance that you gave us, I guess, last September. So if could you help us understand how that reconciles with the potential risk to the 60,000 barrel a day number and how you expect that progression through the year. And I've got a couple of follow-ups, please. Gregory P. Hill: I guess before answering your question directly, let me just provide a little context on the Bakken. So the growth from the Bakken continues with our production averaging 42,000 barrels a day in the first quarter, which is up 11% from the fourth quarter and 68% from the first quarter of 2011. In the first quarter, we had 14 operating rigs running. We drilled 37 new wells and completed 52. So that means we currently have 142: 34-plus stage [ph] systems in the ground with 112 on production. Now 86 of these wells have been on production for at least 1 month and have an average 30-day IP rate of around 900 barrels a day. So obviously, very encouraging results. Now although first quarter production was a little lower than planned due to a combination of factors which included changes in well mix resulting from HBP requirements and some permitting bottlenecks, we continue to make progress in drilling efficiency and remain on this very solid growth trajectory. Now over the remainder of the year, Doug, we plan to add 2 to more rigs, going from 14 in first quarter to 16 and 17 for the balance of the year, and then modify our mix to focus our drilling activities on higher productivity and higher working interest areas, also meeting HBP requirements. Now as John said, while we expect the production will continue to increase throughout the year, the average for the full year may come in somewhat lower than our original estimate at 60,000 barrels a day. And as usual, we'll provide an update to that on our July conference call. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Greg, just picking up on some of your comments there. So the working interest in the wells you've been drilling early on in the HBP are more than what are you going to do in the second half of the year? Is that what you just described there? Gregory P. Hill: Yes. We're going to increase the working interest of wells in the latter part of the year than what we've been drilling currently. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: 'v So can you give an indication as to what the difference is and the working interest between the early wells and the later wells? Gregory P. Hill: No. I can't, Doug. I can't give you average between now and then. But suffice to say, it's going to be drilling higher working at the wells [ph]. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Okay. I don't need to push this point too much, but the IP rates, Greg, appear to be substantially better on some of the more recent wells. Can you comment as to what's changed there? Gregory P. Hill: Yes. So my comments were around well mix. So as you know, we're in HBP mode, Doug, which means that we're focused on getting acreage held by production rather than focusing on sweet spots. So not surprising, while in this mode, we expect to experience some variability in the IPs. And in the first quarter, we drilled in some areas which had somewhat lower IPs, but they still have very good economics. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Okay. My only other question really is on the CapEx. The first quarter number looks disproportionately high compared to the guidance for the year. Can you talk about -- are we looking at any acquisitions in there? And how does it change your guidance and maybe a little bit of explanation as to why it's so front-end loaded? And I'll leave it at that. John P. Rielly: Sure, Doug. As you know, it's still early in the year. And as usual, we'll provide an update to the capital spend guidance on the Q2 earnings call. Having said that, we are seeing upward pressure in scope in certain areas, as Greg just mentioned, such as the Bakken, where we'll be adding some rigs as we go throughout the year and we're shifting to drilling the higher working interest areas, as well in Tubular Bells, actually. Just sent a fourth rig that arrived earlier in the Gulf of Mexico. So it's actually in like 4 to 5 months to full year than we originally planned. So it's just an acceleration of spend into the year. Now however, even with that upward pressure in capital, as John mentioned earlier, we still anticipate funding the majority of our 2012 capital program with cash flow from operations and asset sales. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: So the guidance is -- the $6.8 billion guidance, John, what does that look like? John P. Rielly: We're going to -- we will update that on the second quarter conference call. But there is upward pressure on that number, as I spoke about.

And your next question comes from the line of Ed Westlake of Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: So just coming back to this Bakken issue, I mean how much of -- so as you sort of move through HBP, are there any acceleration in terms of the timing of getting through to the end of that HBP to give some confidence that in 2013, the performance is going to improve relative to the weaker performance in the first quarter? Gregory P. Hill: Yes. So Ed, again, we're increasing our rig count. So we're going up 2 rigs. We currently have 14 on a couple of new builds from Precision where we got rid of the old style rig. So we'll increase the well count. And we are moving back into some higher productivity and higher working interest areas in our HBP acreage. Edward Westlake - Crédit Suisse AG, Research Division: But to be, I guess, specific, if I look at some of the data, your wells seem to be down for longer periods than some of the competitors. So the actual calendar day, sort of IP, is lower than the sort of type curves. How are you going to close that gap relative to some of the other operators that we see up in North Dakota? Gregory P. Hill: Not really familiar with what you're talking about. I will tell you that our data shows we're very competitive with other operators in North Dakota. Edward Westlake - Crédit Suisse AG, Research Division: The issue is that each well doesn't produce as many days in any particular year, according to the Dakota information, in any month, particularly in the first couple of months, which could be infrastructure, could be HBP. Gregory P. Hill: Yes. I mean, it's early days, Ed. I mean, remember, we're adding a lot of infrastructure in North Dakota, much more than some of our competitors. Edward Westlake - Crédit Suisse AG, Research Division: And then just a follow-on question on CapEx. How much is the infrastructure spend as opposed to drilling spend in the Bakken this year? John P. Rielly: We've been running about $400 million to $500 million on infrastructure-type cost in the Bakken. And obviously, as Greg said, we're building that out and then that we'll go down in future years. Edward Westlake - Crédit Suisse AG, Research Division: And when do you think you'd see that inflection coming? John P. Rielly: We should start seeing some reductions in 2013 on those infrastructure costs.

Your next question comes from the line of Evan Calio, Morgan Stanley. Evan Calio - Morgan Stanley, Research Division: With Bakken and CapEx, a little more coverage here. Congrats on the execution of the Ghana sell down, was that a -- can you provide any color on the terms of the cap or on the promote? And is that likely to come into effect? And then with Hickory North spud in late March, we expect 60 to 90 days on that well. And is there any joint maybe pre-drill P50 that you could share with us? Gregory P. Hill: Let me kind of take your questions in reverse order, Evan. No, we don't provide any pre-drill estimates on exploration wells basically. The rig -- again, it will be about a 90-day well, 60 to 90 days, depending on testing and whatnot. Regarding the deals, the terms are confidential -- of both deals. So there's 2 partners. They're farming into the block. Final government approval was still required but both involved a combination of promote to pay a disproportionate amount of the well cost or an interest in the block. Evan Calio - Morgan Stanley, Research Division: Okay. And if -- shifting gears to the Brunei exploration. Julong East -- interpret the release in any color on whether that was commercial, or any color on what type of prospect that or I guess Jagus East is. I mean, were these the offset structures to Kikeh or Gumusut or were they lookalikes like the first prospect? Gregory P. Hill: Yes, Evan. So the first -- the last well we drilled was a discovery. Total is in the process of evaluating the results of the well, which we believe is an offset to the Kikeh Field. So I think it's best -- we're in the middle of evaluation and I think it's best for us to refer you to the operator for additional details. But it was a discovery. Regarding the current well that we're on, it is an offset to the -- offset location to the Gumusut Field, which Shell is developing in Malaysia, as John mentioned in his opening remark. Evan Calio - Morgan Stanley, Research Division: Okay, good. If I could squeeze one last one in here, maybe back to the Bakken. I know realization is more discounted year-on-year in the first quarter. You should see some offset in the second quarter and beyond. Can you update us on the -- on your unreal [ph] volumes in the quarter and where you may be now on takeaway capacity? John B. Hess: Yes. We just started up our rail facility and we're going to be moving about approximately 25,000 barrels a day of Bakken crude down to St. James, Louisiana. Spread is now, between LLS versus WTI plus the discount off of WTI to get it into Clearbrook or North Dakota or Western North Dakota as the case may be, is in about the $25 range. In March, it was closer to the $40 range. In prior months, it was closer to $20. So obviously, that's margin upgrade that we get on about 25,000 barrels a day. But we just started the rail facility in full force, and we should be ramping up during the year to higher volumes. Our full capacity for all the rail cars that we're going to have by the end of the year could be in the range of 50,000 to 54,000 barrels a day.

Your next question comes from the line of Arjun Murti, Goldman Sachs. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: Just a couple of more Bakken questions. The fact that you're doing a bunch of HBP drilling, is that in effect creating some bit of a backlog in terms of tying things in, maybe allowing for a catch-up at some point in the future and next year? And then secondly, can you talk about where well costs are trending in -- on your Bakken wells? Gregory P. Hill: Yes, sure. Let me just answer both of the questions. First of all, let me just again reinforce there were 2 issues in the first quarter. So the first thing was permitting issue, which really just reflects the huge amount of activity in North Dakota. So during the first quarter, we experienced some delays in receiving permits at certain locations, which resulted in delays in getting wells on production. So we're working with the state to resolve these issues. And then my second comment was around well mix, where you're in HBP mode and focused on acreage being held by production rather than focusing on the sweet spots. And of course, while in this mode, you're going to experience some variability in IPs. I think the final thing, Arjun, is when you're in HBP mode, you're essentially drilling the first well and pad, right. So you have a lot more movement of manpower, rigs, materials then when you're in pad drilling mode, which is different than some of our competitors that are back in pad drilling mode. So those are improvements we expect once we return to pad drilling in late 2012, early 2013. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: That makes sense, Greg. Is there a backlog, so to speak, of stuff that needs to be tied in beyond some of the permitting delays you talked about? Gregory P. Hill: There is. So we still have a backlog of wells to complete. That backlog is coming down, and we expect to be in the normal backlog. Normal will be 20 to 25 wells. Though in the backlog, this is part of your process, that work in progress. You had one more question. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: Well cost. Gregory P. Hill: You had one more question on well cost. A good number to use for 2012 is $10 million for drilling and completing wells. Our Q1 costs were a little higher due to a shortage of white sand proppant. However, that issue is now resolved. We expect our cost to drop as we transition to a full sliding sleeve completion. We're going to full 34-stage sliding sleeve completion. And we continue to achieve drilling efficiency gains. This quarter, our drilling days were down [indiscernible] 7. Before, they were 30 days. So we're continuing to see those drilling efficiency gains as well, which would get even better and better as we go to sliding sleeve and HBP drilling. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: That's great. On the Utica, any update on what you're doing there? Gregory P. Hill: Yes, the Utica, I think -- I mean, we're still in very early stages of our appraisal of the Utica, with only 2 wells having been drilled and completed both on our acreage and the CONSOL acreage. So as we mentioned in our last call, we completed the Marquette well in Jefferson County end of the year. That well flowed at an initial rate of 11 million cubic feet a day. It's currently producing 4.5 million cubic feet a day. And the reason is that's curtailed by pipeline capacity. So it's got much more potential than that. Our partner, CONSOL Energy, recently completed a well in Tuscarawas County, which is 45 miles west-northwest of our Marquette wells. It's currently under evaluation. We will commence our Hess-operated drilling program in mid-May. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: That's great. And then just a final quick follow-up. Was there any material acreage acquisition cost in that 1Q CapEx? Or it's just a comment about scope and so forth that John -- I think John Rielly had mentioned? John P. Rielly: There were some, just the routine type acreage, filling acreage cost, but nothing overly significant.

Next question comes from Robert Kessler, Tudor Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a quick follow-up on the Bakken. For your, say, 42,000 barrels a day of net production, how much of that might be nonoperated? Gregory P. Hill: We don't have that number here right now, Robert. We can get back to you with that number. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then separately on Tubular Bells, can you help me understand a little bit of the rationale for the strategy to sort of outsource the production facility to Williams and its Gulfstar FPS, and a little bit of color around the structure of that arrangement? Gregory P. Hill: Yes, Robert. That was -- just to remind everyone on the call, that arrangement was actually done by BP. If we recall on October 2011, we increased our interest to 57% from 40%, basically took over between us and Chevron BP's interest. And that was the development concept that was underway at that time. And we just continued on with the development concept. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Is there any way to provide some kind of overall kind of cash cost for Tubular Bells inclusive of the fee you have to pay for processing? Gregory P. Hill: No, Robert. We don't go down to that level of detail at this point in time. And again, we have to wait to see if the development actually starts up as well. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Is it fair to say you're on the hook for a certain amount of payment even if the wells are not brought online on time? Gregory P. Hill: No. It goes post development. So as production comes on, the facility effectively then gets paid off. That's part of the processing fee. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then I think Williams also references their comfort that they'll be carried through, say, hurricane disruption risk, which is currently not inconsequential in the Gulf of Mexico for up to, say, 6 months or so. How does that work? Do you still make payments to the operator of the facility even if you're not producing in that scenario? Gregory P. Hill: Those type of terms actually we won't discuss on a call. That's kind of -- that's confidential at this point.

Your next question comes from the line of Paul Cheng, Barclays. Paul Y. Cheng - Barclays Capital, Research Division: Greg, can you share with us what is in Bakken, your current cash lifting cost? Gregory P. Hill: Paul, we don't break -- again, break that down. You can see, obviously, in the U.S. that the Bakken is a good part of the production in the U.S. So it's built into those costs. Paul Y. Cheng - Barclays Capital, Research Division: John, is the unit cash cost higher or about the same as your average U.S.? John P. Rielly: With the Bakken again, what we have right now is a ramp-up. So there's a lot of people. There's a lot of equipment and everything being done to support the growth that's going on there. So just like with the cash cost, as well as on DD&A, where the initial DD&A rates are high because the reserve bookings lag the investment dollars, you will have that kind of higher cost type impact that will come down over time. Paul Y. Cheng - Barclays Capital, Research Division: We understand. I just want to note that we need to look at that based on and see that what kind of improvement we could potentially expect. If you can draw down to some of the -- your competitor in the basin, then maybe down to 5 or 6, are we at this point in the 20-plus or at the 15? Are we -- I mean, what kind of improvement at least we could expect from a cash flow standpoint going forward? You have assumed indeed would be once you move to the batch and be able to move down to the kind of cost curve as your best competitor. So we're just trying to get some better understanding. John B. Hess: Yes, Paul. I think we are one of the best competitors. We are pre-investing in infrastructure, over $500 million on our Tiago Gas Plant to strip liquids out and be able to capture the value from the natural gas. Most people don't have that or they have to pay a lot on tariffs to get access to that. The rail facility is already showing its wisdom of revenue upgrade. It's not just about cost, as you well know. And on the cost side, our people are very efficient. Obviously, the logistical challenge of the 14- and ultimately 16-rig program going -- manufacturing, HBP, it's going through the early phases of ramp-up in a very big operation. And that creates some of the noise and the unit costs. But we do see those stabilizing over time. And then last but not least, as we get more well production history, we will be booking more proved reserves, which will also help us in terms of the DD&A. So it's early stages of a major investment for our company, creates some volatility and being able to predict both on the cost side and on the production side. But we're very confident that we're on a solid growth trajectory. And as we move forward in time, our unit costs will improve. Paul Y. Cheng - Barclays Capital, Research Division: No, I understand that, John, but I just want to see if you can give us some number or some estimate so that we can -- you say that's a baseline, so that we can do some calculation ourselves what is the improvement that we could expect from a cash flow and earning from that operation over the next several years? John B. Hess: I think you will able to see that, Paul, as we deliver results. So as we deliver results, I think you'll be more satisfied with the answer. Paul Y. Cheng - Barclays Capital, Research Division: On the unit train [ph], assume if the economic years permit, how quickly or that -- what is the fastest that you can get ramp up to 50,000-54,000 barrel per day? And what is the limitation in terms of the time take to ramp it up? John B. Hess: It's a number of things. It's ability to offtake in the market. It's access to 2 of the trains we leased out, I think, of the 9 train sets that we have until about August. So gradually, you'll see a ramp-up from the 25,000 barrels a day now ultimately to that 50,000-barrel-a-day number or higher by the end of the year. Paul Y. Cheng - Barclays Capital, Research Division: So by the end of the year. So you're not going to be able to get that, say, by the third quarter? John B. Hess: As I said, there will be a gradual ramp-up from 25,000 barrels a day right now to about 50,000 to 54,000 by the end of the year. Paul Y. Cheng - Barclays Capital, Research Division: Okay. Can you give us an update on the Valhall? Gregory P. Hill: Yes. Paul, this is Greg. Valhall production about flat. I mean, the -- as we've said before, the BRD will be done this year. And so you can expect volume at Valhall to be about flat with what it was last year until we get that redevelopment program done. We do have -- we are doing some producer drilling this year. So we're anxious to see the results of that producer drilling as those wells come online. Paul Y. Cheng - Barclays Capital, Research Division: Greg, are we still talking about in the third quarter the redevelopment start-up? Gregory P. Hill: Yes. The work on the redevelopment occurs in the third quarter. Paul Y. Cheng - Barclays Capital, Research Division: Okay. On Utica, CONSOL, that well, I think, has been complete more than 1 month ago. Do you have any production number you can share? Gregory P. Hill: The operator. You have to refer to the operator on that. Paul Y. Cheng - Barclays Capital, Research Division: Okay. A final one on Libya. What was the sales being record in the first quarter? John P. Rielly: In Libya, we did get a lift towards the end of March. So we had a lift in approximately a 600,000-barrel type area. So we did have a significant under-lift with Libya. We had an under-lift of approximately 950,000 barrels for Libya in the first quarter. Paul Y. Cheng - Barclays Capital, Research Division: So John, should we assume that as you start to catching up your effective tax rate for international E&P, it would be substantially higher because of Libya? John P. Rielly: Correct. If you assume that lifting catch-up in equal production, that will increase that effective tax rate and will get it up, if lifting vehicle production, into the -- overall, this is 44% to 48% effective rate range. Paul Y. Cheng - Barclays Capital, Research Division: How much? I'm sorry. John P. Rielly: 44% to 48%, if Libya -- if we get all our production lifting and catch-up. The other thing that Libya does then it will help us on the unit cost. So from the unit cost aspect, our unit cost will go down $1 to $2 per BOE. Paul Y. Cheng - Barclays Capital, Research Division: Is the 44% to 48%, is that total E&P or just international E&P? John P. Rielly: Total E&P. Paul Y. Cheng - Barclays Capital, Research Division: Total E&P. Do you have an estimate of your deferred tax look like in this year? John P. Rielly: No. Now that's too early to be able to do that, Paul.

Your next question comes from Paul Sankey, Deutsche Bank. Paul Sankey - Deutsche Bank AG, Research Division: On your -- if I could ask about your cash flows. Forgive me if you mentioned this, but was there any major working capital movements within that number that you gave? John P. Rielly: The big movement was the funding of our HOVENSA commitment. So we had an accrued liability of $487 million related to the shutdown for HOVENSA. So we, along with our partner, funded our share. So we funded the $487 million to HOVENSA in the first quarter because there was a tender offer for the debt down there at HOVENSA and due to the timing of the liquidation proceeds from the inventory and also the timing of shutdown cost. So we fully funded. That was the biggest impact from the working capital standpoint. There were other positive impacts of working capital aside from that of approximately $240 million. Paul Sankey - Deutsche Bank AG, Research Division: Okay. So the entire $487 million you just mentioned was within the quarter? John P. Rielly: Was within the quarter. Paul Sankey - Deutsche Bank AG, Research Division: And then it was offset by $240 million positive. John P. Rielly: Correct. And the -- we do not expect any more funding for HOVENSA for the rest of the year. Paul Sankey - Deutsche Bank AG, Research Division: I've got you. Can you give us a sense of the cash impact of the hedges in the quarter? John P. Rielly: Sure. So I mean, you saw the after-tax impact was $71 million in the quarter. So you can just divide that by the effective tax rate. So it's approximately $110 million to $115 million pretax. Paul Sankey - Deutsche Bank AG, Research Division: That is helpful. I was wondering, you gave a number for -- I believe you gave a number for infrastructure spend in the Bakken of about $400 million, just in the Q&A. Do you have a number for the spend, the overall CapEx in the Bakken for the year? John P. Rielly: No. We don't have that number at this time. Paul Sankey - Deutsche Bank AG, Research Division: It's simply that you obviously -- that you just don't break it out, right? John P. Rielly: Correct.

Your next question comes from Pavel Molchanov, Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Well, no one has asked about downstream yet, so I thought I would do that. I just saw the -- a news release from the EPA stating that you guys will be investing $45 million in pollution controls at Port Reading. Given that refinery just seems to be kind of in perpetually in the red, I'm curious what the logic is to retain it and in fact invest more in the facility rather than just do what you did with HOVENSA? John B. Hess: No. As you -- no, Port Reading is a much smaller refining complex than HOVENSA. As long as its -- generates acceptable financial returns, we'll keep running it. And as there are updates to be given on its status, we will give them. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. What do you think needs to happen to get margins at that facility to an acceptable levels? I mean, is it a purely kind of crack spread issues? Or are there internal changes that could be made? John B. Hess: The biggest determinant is market conditions, which obviously we have no control over.

[Operator Instructions] Your next question comes from Faisel Khan, Citigroup. Faisel Khan - Citigroup Inc, Research Division: I was wondering if you could, maybe I missed this, give us an update on the Eagle Ford. What kind of well results that you had out of that basin? Gregory P. Hill: Yes. Faisel, this is Greg. So we have -- just recall, we currently have about 109,000 net acres in the Eagle Ford. And we drilled 38 wells, 29 completed and brought on production. Now of those 29, 22 wells have been on more than 30 days and they delivered 30-day IP rates ranging between 250 and 650 barrels a day. So keep in mind the Eagle Ford is just like all of our unconventional plays. We're still very early in the appraisal mode on the Eagle Ford. Faisel Khan - Citigroup Inc, Research Division: Okay. And what's the mix of black oil versus condensate versus NGLs and gas or maybe just a liquids-gas ratio? Gregory P. Hill: Yes. So we're -- with the current well mix, it's about 60-40. But part of our appraisal program is to move through different areas of the oil window, condensate window, et cetera. So that number is going to change over time as we appraise it. Faisel Khan - Citigroup Inc, Research Division: Okay. And then just going back to the funding of HOVENSA. Was all that capital related to the debt, or was it also related to some sort of environmental remediation sort of liability? John P. Rielly: No. So HOVENSA, they had debt to be extinguished plus they had the overall shutdown cost. So at the end of the year, we had an accrual for $487 million for the totality of shutting down HOVENSA. So that was going to be the total amount that Hess -- and our estimate was that we were going to fund. We put that in there. And it's for the debt and other related shutdown cost. Faisel Khan - Citigroup Inc, Research Division: And what happens to the inventory? How does that kind of come back you guys? John P. Rielly: So that inventory was -- the liquidation of the inventory was net in that estimate. Our estimate then was reduced by the estimated proceeds from the inventory. Faisel Khan - Citigroup Inc, Research Division: Okay. So what happens from now on? Is it -- I guess you could turn the facility into a terminal, and then is there any value that you could accrue back from that sort of situation? John P. Rielly: That is the plan right now, that HOVENSA will be turned into a storage terminal. Faisel Khan - Citigroup Inc, Research Division: Okay, so you then collect a fee-based sort of revenue off of it over time? John P. Rielly: Correct.

And you have a follow-up from the line of Paul Cheng with Barclays. Paul Y. Cheng - Barclays Capital, Research Division: Greg, where are we in the Australian gas appraisal and the supply agreement negotiation? Gregory P. Hill: Just -- the Jack Bates rig has returned on location there, and we expect to complete all of our appraisal work by mid-2012. So that's complete drilling of 1 well plus 2 tests. So test the well that we're drilling. Let's then go back to a well that was previously drilled that we plan to test. Now in parallel, we continue these commercial discussions with the liquefaction partners. Our aim is to complete those in 2012, and those are ongoing, Paul. Paul Y. Cheng - Barclays Capital, Research Division: Greg, in Bakken, what's the split in your liquids between black oil and condensate? Is the bulk of your production in the liquids side is black oil or just condensate? Gregory P. Hill: Majority is black oil. Approximately, like -- you're getting like 85% to 90% black oil. Paul Y. Cheng - Barclays Capital, Research Division: So it's black oil. And then in Eagle Ford, just when you say 60-40, is that 60% condensate, 40% black oil? Or are you talking about just between the liquid and gas mix? Gregory P. Hill: No. It's 60% condensate, 40% black oil. It's kind of that split. But again, Paul, remember, we're in appraisal mode. So those numbers are constantly moving around as we move around in the play.

Ladies and gentlemen, that concludes the Q&A session. That also concludes the presentation. Thank you for your participation. You may now disconnect. Have a great day.