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

Edward Westlake - Crédit Suisse AG, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Evan Calio - Morgan Stanley, Research Division Ryan Todd - Deutsche Bank AG, Research Division Guy A. Baber - Simmons & Company International, Research Division Paul Y. Cheng - Barclays Capital, Research Division Paul I. Sankey - Wolfe Research, LLC Roger D. Read - Wells Fargo Securities, LLC, Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Pavel Molchanov - Raymond James & Associates, Inc., Research Division Faisel Khan - Citigroup Inc, Research Division

Good day, ladies and gentlemen, and welcome to the Third Quarter 2014 Hess Corporation Conference Call. My name is Gary, 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 call over to Jay Wilson, Vice President of Investor Relations. Please proceed. Jay R. Wilson: Thank you, Gary. Good morning, everyone, and thank you for participating in our third 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. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC. Also on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. With me today are John Hess, Chief Executive Officer; Greg Hill, President, Worldwide Exploration and Production and COO; 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 third quarter conference call. I will provide some key highlights on the quarter and the progress we are making in executing our strategy. Greg Hill will then review our operations and John Rielly will go over our financial results. I thought it would be appropriate, before discussing our third quarter results, to make a few comments about recent volatility in oil prices. As most of you know, we have used $100 Brent as the basis for our plans even as Brent has averaged nearly $110 for the last 3 years. However, with Brent now at approximately $87 per barrel, we are reviewing our plans and actions that we might take in a lower-price environment. As always, we are taking a disciplined approach to: first, allocate capital to the projects with the highest risk-adjusted returns; second, maintain a strong balance sheet and a high degree of financial flexibility; and third, manage capital and exploratory spending within limits of our cash flow over the long term after continuing to return capital to our shareholders. And we look forward to sharing our plans in more detail with you at our upcoming Investor Day on November 10. Also we will release our 2015 capital and exploratory budget, as usual, in January 2015. Now turning to our financial results for the third quarter of 2014. Net income was $1,008,000,000 or $377 million on an adjusted basis. Adjusted net income per share was $1.24 compared to $1.18 in the year-ago quarter. Cash flow from operations was $1.3 billion. Compared with the third quarter of 2013, our results were positively impacted by higher crude oil and NGL sales volumes and lower exploration expense, which were offset by lower realized crude selling prices and higher depreciation expenses. Net production in the third quarter averaged 318,000 barrels of oil equivalent per day or 314,000 barrels of oil equivalent per day, excluding Libya. This represents an increase of 17% from pro forma production of 269,000 barrels of oil equivalent per day from the year-ago quarter, excluding Libya. Now we will review highlights from the quarter. Starting onshore. Net production in the Bakken averaged 86,000 barrels of oil equivalent per day in the quarter, up 21% from the third quarter of 2013. In the fourth quarter, we forecast net Bakken production will average between 92,000 and 97,000 barrels of oil equivalent per day. We continue to focus on drilling some of the lowest-cost, highest-return wells in the Bakken. In the third quarter, drilling and completion costs averaged $7.2 million, down 8% from the year-ago quarter, and our wells continue to be among the most productive in the play. The Utica is positioned to be a material contributor to our production growth over the next 5 years. We and our partner, CONSOL, have a core acreage position in the wet gas window. During the quarter, production averaged 11,000 barrels of oil equivalent per day. Moving offshore. In the deepwater Gulf of Mexico, the Tubular Bells Field, in which Hess has a 57% interest and is operator, is completing its final checks and is expected to achieve first production within the next week. Following a ramp-up period, Tubular Bells is expected to deliver net production of approximately 25,000 barrels of oil equivalent per day by year-end. Yesterday, we announced that we will proceed with the development of Stampede, a deepwater oil and gas project operated by Hess in the Green Canyon area of the Gulf of Mexico. Hess has a 25% working interest and is the operator. Chevron, Statoil and Exxon each have a 25% working interest. Total recoverable resources for Stampede are estimated in the range of 300 million to 350 million barrels of oil equivalent. First production is expected in 2018. In terms of overall company production, we are on track to average toward the upper end of our 2014 pro forma production forecast of 305,000 to 315,000 barrels of oil equivalent per day, excluding Libya. In terms of divestitures, the sale of our retail business closed during the third quarter for cash proceeds of $2.8 billion. The sale of our HETCO energy trading business was announced on Monday and is expected to close in the first quarter of 2015. Also we continue to negotiate with a potential buyer for the sale of the HOVENSA joint venture refinery in St. Croix, which we hope to complete in the near future. We continue to make progress in our plans to monetize our Bakken midstream infrastructure in 2015 through an MLP structure, which will allow Hess to retain operational control while realizing additional value from our infrastructure investment. During the third quarter, the corporation's wholly owned subsidiary, Hess Midstream Partners LP, filed an initial Form S-1 with the SEC in preparation for its proposed initial public offering in 2015. Based on the sale of our retail business, we increased our share repurchase authorization to $6.5 billion from $4 billion. Year-to-date, through October 28, we have repurchased 34.7 million shares for $3.1 billion. Since the commencement of the program in August of 2013, we have repurchased 54 million shares for $4.6 billion. We will continue to implement this program in a disciplined manner and provide quarterly updates on future conference calls. In summary, we are delivering strong performance and executing our plan. With our focused, balanced portfolio and strong balance sheet, we are well positioned in the current price environment to drive cash-generative growth and sustainable returns for our shareholders. I will now turn the call over to Greg for an operational update. Gregory P. Hill: Thanks, John. I'd like to provide a brief review of the progress we're making in executing our E&P strategy. In the third quarter, we again demonstrated continuing delivery against plan. Starting with unconventionals. In the third quarter, net production from the Bakken averaged 86,000 barrels of oil equivalent per day, up from 80,000 barrels of oil equivalent per day in the second quarter of 2014. We operated 17 rigs and brought 59 Bakken wells online in the third quarter. This was up from 53 wells in the preceding quarter. In the fourth quarter, we plan to have 6 frac crews working and expect to bring more than 80 new wells online. Thus far in October, we have brought 30 new wells online, and net production has averaged 91,000 barrels of oil equivalent per day. For the fourth quarter, we forecast net production in the Bakken to average between 92,000 and 97,000 barrels of oil equivalent per day. We anticipate that full year 2014 Bakken production guidance will be toward the lower end of our range of 80,000 to 90,000 barrels of oil equivalent per day. This reflects delays in bringing the Tioga gas plant online at the beginning of the year as well as permitting delays for the Hawkeye South of the River Pipeline, which has prevented additional gas volumes from being processed at the Tioga plant. Inlet volumes to the Tioga plant continue to increase, and the plant is currently processing approximately 160 million cubic feet per day and 31,000 gross barrels of oil equivalent per day of natural gas liquids. We expect to fill the plant to capacity in 2015 and are evaluating low-cost options to expand the current capacity from 250 million to 300 million cubic feet per day. Our 13 and 17 well per DSU downspacing pilots are progressing well and performing in line with expectations. We will provide an update of the results from these pilots at our Investor Day in November. Drilling and completion costs continue to be reduced in the Bakken with the third quarter averaging $7.2 million per well versus $7.8 million per well in the year-ago quarter and $7.4 million per well in the second quarter of this year. We continue to make steady progress in reducing costs as a result of our unique lean manufacturing approach, and we see room to continue to drive these costs lower. Based on our top quartile drilling and completion cost and the productivity of our wells, we believe we are delivering some of the highest-return wells in the play. In the Utica, the appraisal and early development of our 44,000 core net acres in the Hess-CONSOL joint venture continues to be encouraging. In the third quarter, the joint venture drilled 10 wells, completed 11 wells and brought 18 wells on production. In the third quarter, the joint venture also tested 14 new wells, 7 of which were Hess-operated. Test results from the Hess-operated wells located in Harrison and Belmont Counties averaged approximately 2,700 barrels of oil equivalent per day and 47% liquids based on 24-hour tests. In the third quarter, net production averaged 11,000 barrels of oil equivalent per day compared to 3,000 barrels of oil equivalent per day in the prior quarter. We intend to provide an update of our forward plans for the Utica at our Investor Day. Turning to offshore. Progress continues in Tubular Bells, Stampede, North Malay Basin and Valhall. At Tubular Bells in the deepwater Gulf of Mexico, in which Hess holds a 57% working interest and is operator, we are in the final stages of commissioning and anticipate achieving first oil within the next week. From there, we will ramp up net production from 3 wells to approximately 25,000 barrels of oil equivalent per day by year-end. Also in the Gulf of Mexico, the Stampede development project, in which Hess holds a 25% working interest and is operator, was recently sanctioned by all 4 partners. Building on the successful execution of our Tubular Bells project, Stampede will develop one of the largest remaining discovered Miocene fields in the deepwater Gulf of Mexico and is expected to deliver first oil in 2018. A 2-rig drilling program is planned with the first rig commencing operations in the fourth quarter of 2015. Gross topsides processing capacity for the project is approximately 80,000 barrels of oil equivalent per day and 100,000 barrels of water injection capacity per day. Gross recoverable resource is estimated to be in the range of 300 million to 350 million barrels of oil equivalent. At North Malay Basin in the Gulf of Thailand, in which Hess holds a 50% working interest and is operator, third quarter net production averaged 40 million cubic feet per day through the Early Production System. Engineering work continues on the full-field development project, which will increase net production to 160 million cubic feet per day in 2017. In Norway, at the BP-operated Valhall Field, in which Hess has a 64% interest, third quarter production averaged 25,000 barrels of oil equivalent per day compared to 31,000 barrels of oil equivalent per day in the second quarter. This was primarily due to a seasonal planned maintenance shutdown. Full year production for Valhall is still expected to average in the range of 30,000 to 35,000 barrels of oil equivalent per day net, supported by 3 new wells, which are planned to be brought on in the fourth quarter. Company-wide pro forma production in the fourth quarter is forecast to be between 330,000 and 340,000 barrels of oil equivalent per day, excluding Libya. Full year production is forecast to be toward the upper end of our 2014 pro forma production of 305,000 to 315,000 barrels of oil equivalent per day, excluding Libya. Moving to exploration. In Kurdistan, where Hess has a 64% interest, we resumed drilling in the Shireen-1 well on the Dinarta block earlier this month following a 2-month suspension due to the security situation. We expect to reach total depth in the first quarter of 2015. In Ghana, Hess and its partner successfully completed our appraisal drilling program in the third quarter. Results are encouraging, and once the data from the appraisal drilling and new 3D seismic have been incorporated into our models, we will provide an update as appropriate. In closing, this quarter is yet another demonstration of strong execution against our plan and delivery of key milestones. I will now turn the call over to John Rielly. John P. Rielly: Thanks, Greg. Hello, everyone. In my remarks today, I will compare results from the third quarter of 2014 to the second quarter of 2014. The corporation generated consolidated net income of $1,008,000,000 in the third quarter of 2014 compared with $931 million in the second quarter of 2014. Adjusted net income was $377 million in the third quarter of 2014 and $432 million in the previous quarter. Turning to Exploration and Production. E&P had income of $441 million in the third quarter and $1,057,000,000 in the second quarter of 2014. E&P adjusted net income was $412 million in the third quarter of 2014 and $483 million in the previous quarter. The changes in the after-tax components of adjusted net income were as follows. Changes in realized selling prices decreased net income by $81 million. Lower sales decreased net income by $23 million. Lower exploration expenses increased net income by $59 million. Lower cash costs increased net income by $20 million. Higher DD&A expense decreased net income by $38 million. All other items net to a decrease in net income of $8 million for an overall decrease in third quarter adjusted net income of $71 million. Our E&P crude oil sales volumes were overlifted compared with production by approximately 300,000 barrels. However, the impact to net income was immaterial in the quarter. The E&P effective income tax rate, excluding items affecting comparability of earnings, was 41% for the third quarter and 34% in the second quarter of 2014, primarily reflecting the impact of a Libyan crude oil lifting in the third quarter. Turning to corporate and interest. Corporate and interest expenses, net of income taxes, were $80 million in the third quarter of 2014 compared with $91 million in the second quarter of 2014. Adjusted corporate and interest expenses were $78 million in the third quarter and $82 million in the second quarter. Turning to cash flow. Net cash provided by operating activities in the third quarter, including a decrease of $170 million from changes in working capital, was $1,338,000,000. Net proceeds from asset sales were $2,956,000,000. Capital expenditures were $1,362,000,000. Common stock acquired and retired amounted to $903 million. Repayments of debt amounted to $53 million. Common stock dividends paid were $76 million. All other items amounted to an increase in cash of $15 million, resulting in a net increase in cash and cash equivalents in the third quarter of $1,915,000,000. Turning to our stock repurchase program. During the third quarter, we purchased approximately 9.2 million shares of common stock at a cost of $903 million, bringing cumulative purchases for the program through September 30, 2014, to 49.4 million shares at a cost of $4.2 billion or $85.14 per share. We have continued to buy back our common stock. And through October 28, total program-to-date purchases were 54 million shares at a cost of $4.6 billion or $85.03 per share. Turning to our financial position. We had $4,120,000,000 of cash and cash equivalents at September 30, 2014, compared with $1,814,000,000 at the end of last year, primarily reflecting the collection of proceeds from the sale of the retail business. Total debt was $5,996,000,000 at September 30, 2014, compared with $5,798,000,000 at December 31, 2013. The corporation's debt-to-capitalization ratio at September 30, 2014, was 19.7% and 19% at the end of 2013. Turning to guidance. I would like to provide fourth quarter 2014 guidance for certain metrics. E&P cash operating cost per barrel of oil equivalent are estimated to be in the range of $20.50 to $21.50, and E&P DD&A per barrel is expected to be in the range of $29 to $30. In the fourth quarter, we expect to incur exploration expenses, other than dry hole costs, in the range of $180 million to $200 million. The fourth quarter effective tax rate is expected to be in the range of 41% to 43%, excluding Libya. Fourth quarter corporate expenses are expected to be between $35 million and $40 million after income taxes, and after-tax interest expenses are expected to be in the range of $50 million to $55 million. Given the current volatility in crude oil prices, we are providing additional guidance with respect to price sensitivities on fourth quarter results. Based on the fourth quarter guidance provided, we estimate that every $1 change in crude oil benchmark prices will result in a change in fourth quarter net income of approximately $8 million. This estimate includes the impact of the corporation's crude oil hedge contracts outstanding at September 30, 2014. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

[Operator Instructions] We have our first question from the line of Ed Westlake of Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Yes. I'm sure there's going to be lots of questions on the Bakken and also on the Stampede project. On the Bakken, you've got a $7.2 million well cost. Others are actually increasing their costs to drive the initial cums. and overall recovery is higher. Is your strategy still going to be to try and focus on these, I guess, relatively simpler completions, and they're giving you acceptable returns? Or are you going to go down the route of boosting the, I guess, the frac intensity, et cetera? Gregory P. Hill: Ed, this is Greg. Currently, our standard design is 35 stages, and there's a lot of significant amount of data that supports the sliding sleeve technology as being as effective as plug and perf in terms of IP and EUR as well as being a significant lower cost completion. Now, as always, we continue to experiment and pay very close attention to what competitors are doing, and we've trialed some of these more expensive completion designs, but thus far, none have proven to be economically superior to our methodology. Again we're focused on drilling the highest-return Bakken wells. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And then on Stampede, $6 billion for 320 million F&D cost. I mean, that works probably at a decent level of oil price, and obviously we know it's very deep. But I guess do you think those costs have room to fall, given what's going on in the offshore industry at this point? Or do you think that's a pretty good metric? Gregory P. Hill: Well, certainly Stampede, first of all, is one of the largest undeveloped fields in the GOM, and the project returns are expected to exceed our investment threshold even in this lower-priced environment, and I think it's noteworthy that all 4 partners have sanctioned the project with a final sanction coming in this week. I do think costs do have room. I mean, certainly the diamond rig contract that is tied to this project for 2 years, 7 straight years in total, I think set a new market benchmark for deepwater rig rates. Edward Westlake - Crédit Suisse AG, Research Division: I guess my question is, is that included in the $6 billion number? Or is that potentially an optimization around it? Gregory P. Hill: Yes, it is. It is included in the $6 billion number.

The next question comes from the line of Doug Leggate of Bank of America. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: I wonder if I could take 2, please. My first one is actually in Norway. So obviously maintenance in the third quarter, but I wonder if you could just give us an update as to how you see the Norwegian production outlook for the potential for BP to really start to ramp this thing over the next couple of years relative to your current guidance. And I guess what's behind my question is: this is obviously a non-declining asset. You're not paying cash taxes on it, but the production contribution always seems to be kind of challenged. So what are your strategic thoughts around what you can do in Norway and whether you're optimistic that it gets better. I've got a follow-up, please. Gregory P. Hill: Yes, Doug. As we've said before and as you mentioned, Norway is a huge cash machine for us. Obviously, with brand-new facilities and 40-year life, we have every interest as does BP to maximize the production off of that facility. And our net production goal is still in the range of 40,000 to 50,000 barrels a day in 2017. So how is it going? Well, we've established regular multilevel executive engagements with BP management. In fact, John and I are flying to London tomorrow for our third meeting, and there's a lot of work left to be done, but we are encouraged by the progress. So the reliability of the plant's better. Recent well results leveraging our South Arne drilling and completion experience are encouraging in terms of both cost and schedule. So cautiously optimistic on Valhall. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Great. Do you think you can ever get the platform capacity on it? Gregory P. Hill: That's what we're going to try and drive to do. How long that takes, again, is just going to be a function of price, CapEx and delivery from BP. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Okay, my follow-up is on the Bakken, as you would expect, I suppose, but unfortunately, I haven't been able to access the supplement this morning, so I haven't been able to see what latest 30-day rates were like. But I'm guessing that the downspacing wells that you -- I think was about half your program more or less this year, I'm guessing they've been performing pretty much in line with what you'd expected at the beginning of the year. So not to preempt November 10, but I'm just kind of curious as to how you're thinking about the activity level there, given the potential to expand the inventory but traded off against what is obviously looking like a lower oil price. And I guess what's behind my thinking is you're coming into this lower oil price at a very robust balance sheet. So would that be -- would you still look to accelerate activity? Or would you look to moderate to look for the cashable amount? I'll leave it there. Gregory P. Hill: Okay. Well, just to kind of give everyone an update on the downspacing pilots. Just recall in 2014, we have 2 well-designed pilots going on. We have 17 well pads with 13 wells per DSU, and we have 2 well pads with 17 wells per DSU. So those, respectively, represent a 700-foot between well spacing and a 500-foot well spacing. And results so far are in line with expectations. And Doug, we plan to provide a complete update on the downspacing pilots and what it means for our long-term Bakken guidance on Investor Day in November. So stay tuned.

And we have our next question from the line of Evan Calio of Morgan Stanley. Evan Calio - Morgan Stanley, Research Division: Yes. Maybe somewhat of a follow-up to Doug's comment if I missed it. Did I understand your opening comments, John, that your targeted CapEx to be within cash flow for '15? Or does it -- or is it kind of longer term mean there's some view of normal cash flow and you'd be willing to outspend if we find ourselves in a lower oil price scenario given your cash and balance sheet positions? John B. Hess: Very good question. Look, with our focused, balanced portfolio underpinned in the unconventionals with very strong positions in the Bakken and Utica as well as our offshore and international assets generating free cash flow with some growth and our strong balance sheet, we're really well positioned in the current environment to drive cash-generative growth as well as sustainable returns for our shareholders. So given current prices, we're going to be guided to invest with a disciplined approach to allocate capital to projects with the highest risk-adjusted returns. And remember that our hurdle rate is to meet at least a 15% return, and that accounts for current prices. We're going to be guided to maintain a strong balance sheet and keep our financial flexibility. So accordingly, we'll manage our capital expenditures in line with this, but it is over the long term. So depending upon market movements, we may use our balance sheet some. But I think the important thing is we are going to definitely be guided to live within our cash flow over the longer term while continuing to return capital to shareholders. So the exact details on this, we'll provide you a pretty comprehensive update on November 10. Evan Calio - Morgan Stanley, Research Division: Great, I look forward to that. But maybe a follow-up on that return comment. Hess is moving against a trend offshore with Stampede FID. Well, I know it's been a long time coming. I mean, can you discuss how you compare and analyze returns or payback when making an allocation for new offshore projects versus your unconventional resource opportunity? John B. Hess: Yes, again at current prices, and Greg mentioned this before. It has to meet our hurdle rate of 15% accounting for risk and whether that's an unconventional project or an offshore project, and Stampede met the threshold and in fact, beat it. Evan Calio - Morgan Stanley, Research Division: Great. Maybe one last, if I could, and maybe you can't comment due to the filing. But is there -- when you FID a project like Stampede, I mean, is there any MLP-able [ph] component there whether it's topside capacity or otherwise? Or is that all leased? I'll leave it there. Gregory P. Hill: Yes, since we're in the quiet period right now, Evan, we can't make any comments on what potentially could be included in the MLP. Evan Calio - Morgan Stanley, Research Division: Is it a lease design? Is that what's envisioned? John P. Rielly: On Stampede, no, it's not a lease design. This is being built as -- Hess is the operator. We are building that facility along with our partners.

And next question comes from the line of Ryan Todd of Deutsche Bank. Ryan Todd - Deutsche Bank AG, Research Division: Great. A question on the Utica, and the Utica has an exceptionally strong quarter. Was that a result of better-than-expected well results, higher completion count? And how should we think about activity levels and production growth there in the fourth quarter and going forward? Gregory P. Hill: Yes. Thanks, Ryan. It was really a combination of both. A little bit of higher activity in terms of getting wells online. We had a real strong quarter there. I think the second thing is, is we are leading the industry in terms of lateral length, so we're drilling 8,800-foot laterals now, which is the longest ones to date at least in the Utica. So that contributed to the strong well results. Regarding future plans for the Utica, we're going to provide again a full update on the results and our forward plans for the Utica at Investor Day in November. Ryan Todd - Deutsche Bank AG, Research Division: Great. And if I could ask one follow-up as well. In the Bakken, based on -- I guess can you talk a little bit about -- you talked about the activity levels in October. I mean, I think from a completion point of view, to hit your full year targets, you probably need to bring on close to 80 to 90 wells in the fourth quarter. How many rigs are you running right now? And -- I guess, yes, how many rigs are you running in the fourth quarter? And should we be good to be on pace for that 80 to 90 completion target? Gregory P. Hill: Yes, we're on track for that. We're running 17 rigs currently. And as we said in our opening remarks, we're going to have 6 frac crews working, and we expect to bring more than 80 wells online in the fourth quarter. And I think it's important that in -- just to give you some color on that, in October, we've already brought 30 new wells online. So we're on pace to do so.

And the next question comes from the line of Guy Baber of Simmons. Guy A. Baber - Simmons & Company International, Research Division: Strategic question for me to start off, but obviously in the Bakken you have a huge core position, very advantaged infrastructure position, operations improving there and you have a conservative balance sheet with a lot of cash. So one could view you longer term, I think, as a natural consolidator in that play. So the question is do opportunistic acquisitions have a part in your strategy fundamentally in the Bakken, particularly if this lower oil price environment were to persist and valuations came in a bit? And along those lines, do you feel the company's positioned in a way to take advantage of those opportunities? And does that think -- or is that impact the way you think about the buyback at all over the next quarters? John B. Hess: Yes. There were a number of questions there. First of all, we're always going to be disciplined in our investment to invest for returns. So we're always going to look to optimize our portfolio, but it's got to be focused on investing for returns and keeping a strong balance sheet. Now the strong balance sheet obviously gives us flexibility. So if there were opportunities out there to optimize our portfolio to strengthen our hand and it met our return threshold, we will have a open mind on that for sure. But having said that, the key is when it comes to investment, we're going to be disciplined focusing on returns, and I've talked about that earlier. In terms of the buyback, it's an ongoing program, and we're going to be disciplined in our approach there. Guy A. Baber - Simmons & Company International, Research Division: Okay, great. Very helpful, and then a detailed follow-up on the Bakken. Your oil production was actually down slightly quarter-on-quarter despite the overall increase from 80,000 to 86,000 barrels a day. You had a big increase in NGLs. So understanding that the mix can be volatile from one quarter to the next, I was just hoping you could maybe provide some commentary on the drivers there. And as we think about production going forward, should we still be thinking around about an 80% oil cut or so? So if you could just comment on that, that would be helpful. Gregory P. Hill: Yes. So thank you for that, Guy. If you look on a barrel equivalent basis, obviously, our production was actually higher than Q2 and continues to trend upward. What happened in the third quarter was there were some heavy rains in the quarter, and that resulted in some county-imposed road closures, which then led to a higher level of well downtime due to some transportation constraints. So -- and as you mentioned given the typical oil-gas mix of a Bakken well, this downtime preferentially hurts oil production much more than it does gas production. So that's why you've got this swing.

And next question comes from the line of Paul Cheng of Barclays. Paul Y. Cheng - Barclays Capital, Research Division: Several -- hopefully 3 short questions. Greg, in Valhall, can you remind us, or maybe this is for Rielly, that when the cash tax is going to resume, is it 2017 or 2018? John P. Rielly: Yes, so the guidance that we've given is that we're not paying cash taxes in Norway through 2017. Paul Y. Cheng - Barclays Capital, Research Division: Okay. So 2018 will resume. And then earlier when we're talking about a 15% project hurdle rate, just want to clarify that. Is it based on $100 Brent or based on $85 Brent? John B. Hess: Well, our old standard was $100 Brent, but as we allocate capital now, we're going to be disciplined in how we invest. So it would have to meet it at the $85 hurdle. Paul Y. Cheng - Barclays Capital, Research Division: Okay. So that actually is a change in some way, that it's become tougher or that you raised the bar from previously $100 now to $85 Brent. John B. Hess: Yes, you have to deal with the current reality of where the oil markets are. Paul Y. Cheng - Barclays Capital, Research Division: Okay. That's good. And John -- this is for Rielly, that fourth -- at the end of the third quarter, from an inventory standpoint, I presume that you are overlift -- any idea of how much you are overlift? John P. Rielly: So for the fourth quarter, just for guidance going forward on the fourth quarter, we don't see an -- basically an under or overlift, a pretty balanced sales volume versus production. Excluding, Paul, it's excluding Libya. So with Libya in there, we could end up, if they have lifts continuing in the fourth quarter, could end up in an overlift position with Libya. But excluding that, from the equation, there's no projected under or overlift in the fourth quarter. Paul Y. Cheng - Barclays Capital, Research Division: Okay. Great. And that the -- in Utica, Greg, are you running a 3-rig program right now? Gregory P. Hill: Yes, we are, Paul. Paul Y. Cheng - Barclays Capital, Research Division: And then how many well is actually in production to contribute the 11,000 barrel per day? Gregory P. Hill: Let's see. The online production well count for the Utica in the third quarter was 4 wells, and we've got -- sorry, I'm looking at my notes here. Sorry about that. So we've got -- in the third quarter, we have 10 -- we have 28 wells that have been drilled year-to-date in the Utica. Sorry, it took me a minute to find that number. Paul Y. Cheng - Barclays Capital, Research Division: 28 wells drilled, but how many of them is actually in production? Gregory P. Hill: Look, I'm just looking at my notes, Paul. I'm sorry. It's going to take me just a second. So online in this year, all of the JV wells and our wells, we've got 31 wells online. Paul Y. Cheng - Barclays Capital, Research Division: Okay. And then do you have a rough split between oil condensate NGL and natural gas in Utica? Gregory P. Hill: So Paul, just -- let me just give you the numbers that we have in the quarter. So of the 11,000 barrels a day, there are -- it's just under 2,000 barrels a day is condensate. Just above 2,000 barrels a day are NGLs, and the rest of it, so on a 7,000 barrels a day oil equivalent is gas. Paul Y. Cheng - Barclays Capital, Research Division: Okay. Great. And John, can you comment about the press release, talk about HOVENSA sales and that the $1.6 billion number signed [ph] by the government. Does that mean that when you finally decided, should we assume that you will receive any upfront payment from that sales? John B. Hess: We're in the negotiation phase now with a third party, and I wouldn't want to get ahead of ourselves, Paul. When we have something definitive to say, we'll say it. Paul Y. Cheng - Barclays Capital, Research Division: Okay, a final one. For 2014 exploration expense based on your fourth quarter estimate, it's about call it $460 million. Going forward, is that a reasonable proxy? Or that 2014 is just not drilling a lot of wells so that going forward, the exploration expense may be higher than this level? John P. Rielly: Yes, so -- I mean, we've been guiding basically that we've been, like, especially in the near term that our exploration program overall from a spend standpoint would be between $500 million and $600 million. And in fact, our guidance this year was $550 million, and so we're not giving guidance yet. We'll talk a little bit more about exploration on Investor Day and go forward, but that's where we've been. So we're right in line with the guidance that we have set out.

The next question is from the line of Paul Sankey of Wolfe Research. Paul I. Sankey - Wolfe Research, LLC: Given your position in the Bakken, both in terms of acreage and infrastructure, first, could you clarify, John, I think you were saying that you have to take into account oil prices in terms of your activity. Equally, I think I heard you in your opening remarks say that you wanted to live within cash flow long term, which implied that you would maintain a relatively high level of activity over the next year. That was part one, and part two, could you make any observations about how you see the wider behavior of players in the Bakken, given the current price environment? Do we anticipate less activity at these prices? Do we think prices have to go lower before we see an impact? John B. Hess: I think one of the things -- I can't talk about others. Let them speak for themselves, but in our case, we have a very strong balance sheet. We're drilling some of the lowest-cost, high-productive wells so our breakeven is lower. We have some of the best acreage. We're certainly going to be focused on investing for returns as opposed to growth for growth's sake. So we're going to be capital disciplined in this price environment, but with the acreage that we have, many of our wells still generate very good returns even in the current price environment. So the exact details on what our program is going to be going forward and our planning premises, we'll give you further details on November 10. Paul I. Sankey - Wolfe Research, LLC: Sure. I think the perspective of others was to do with your infrastructure position. I mean, are you seeing lower volumes? And can I just throw in also if you saw any impact from the flaring rules in North Dakota? Gregory P. Hill: Yes, Paul. So given our infrastructure position in the Bakken, we don't anticipate any impacts due to the NDIC flaring rules. So we're well positioned to continuously reduce our flaring on a go-forward basis. Paul I. Sankey - Wolfe Research, LLC: And then volumes from the basin given the lower oil price environment in terms of your infrastructure. John B. Hess: No, we're not seeing major volume impacts as of right now.

The next question comes from the line of Roger Read of Wells Fargo. Roger D. Read - Wells Fargo Securities, LLC, Research Division: Just getting back to the kind of initial comments about where crude oil prices are, and I recognize some of this will be handled in 2 weeks. But looking at the North Sea, which has historically been considered a relatively high-cost area, and I recognize Valhall's pretty far along. But could you give us an idea of kind of where it falls in given, say, a sub-$90 Brent environment as opposed to a plus or minus $100 Brent environment? John P. Rielly: Sure. I mean, again where we are with the -- with both our North Sea investments, so Valhall and South Arne, the infrastructure basically is there. It's completed so all our big spend is behind it. So as you said, you've got just your general operating costs, but at $80, as you mentioned, with where our operating costs are and in Valhall where we're not paying cash taxes, it will still generate. Our North Sea assets, our offshore assets in general, too, are going to generate significant cash flow for us. Roger D. Read - Wells Fargo Securities, LLC, Research Division: Okay. So quite a lot of headroom on both of those then. John P. Rielly: Yes. Roger D. Read - Wells Fargo Securities, LLC, Research Division: And reasonable to presume it makes sense to continue to invest and not just to operate on that sort of an $80 to $90 environment? John P. Rielly: Yes. I mean, it is generalized. John Hess had mentioned earlier it's that balanced portfolio. It is our offshore assets that are funding the growth on the unconventional side. So it definitely makes sense and some of our best return projects are there. Roger D. Read - Wells Fargo Securities, LLC, Research Division: Okay. And last question I have is just really 2 areas that have been, well, let's just say security issues both Libya and Kurdistan. Can you give us kind of an update of what you're seeing in terms of any changes in Libya from, say, the middle of the third quarter to the present? And then what was it that gave you confidence to go back into Kurdistan and restart the exploration well there after the 2-month hiatus. John B. Hess: Yes. In terms of Libya, look, there's still significant political unrest in the country and a lot of instability, but the oil's flowing. And so far from our Waha concession, we have sold 3 cargoes of Es Sider crude. So the oil business is up and running. But in terms of how the political unrest gets resolved, that's still very much an open issue. So security is still an issue there. And in terms of Kurdistan, you've read the news. I think the country's a lot more secure today after the United States and allies have stood by the Kurds, and security's the #1 concern for our company and safety of all of our employees and contractors. And once we were given the assurances we needed about security, we staged a reentry into the country.

[Operator Instructions] Next question is from the line of Jeffrey Campbell of Tuohy Brothers. Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.: Most of my questions have been answered, but I would like to ask -- having completed the Almond 2, what is the current timeline for the progression of your offshore Ghana prospects? Gregory P. Hill: Yes. So in terms of obligations to the government, we have to file a declaration of commerciality first. And after that, we would have to file a development plan middle of the year next year with the government. So we're actively evaluating the results of the appraisal plan. We've also got some new 3D seismic that we're also processing. Once that's done and once that's reviewed with our partners and reviewed with the government, then we can give you much more color on Ghana. Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.: But at least at this time, you can say that the drilling portion of it is done pending these further developments. Gregory P. Hill: Yes.

And so the next question is from the line of Pavel Molchanov of Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. Can I go back to Kurdistan for a moment? Now that you guys are drilling with Petroceltic, as I understand, the Shireen-1 prospect is kind of the near-term catalyst. Is there a pre-drill resource estimate for that? Gregory P. Hill: No, we haven't given one, and we expect to reach TD in that well in Q1 of 2015. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. Okay. That's fair enough. And then on Libya, you mentioned the 3 cargoes so far, given that operations are, well, maybe not normal but certainly improving versus a year ago, have you had a chance with the other partners to actually assess the state of the infrastructure relative to any potential physical damage, anything like that? John B. Hess: No, we're not in a position to comment on that.

And the next question is from the line of Faisel Khan of Citigroup. Faisel Khan - Citigroup Inc, Research Division: Just wanted to understand the supplement that you guys put out on the Utica JV well test. I'd just like to confirm that those well tests up there from 1,500 BOE a day to almost 4,000 BOE a day are all for the third quarter. And I just want to make sure that, that sort of is coming through into the fourth quarter as well. Gregory P. Hill: Yes, those are the third quarter results from the wells actually, and those are our wells. In addition, CONSOL also tested 7 wells from their operated pads. But these are our wells drilled and completed and tested in the quarter. Faisel Khan - Citigroup Inc, Research Division: Okay. I mean, these are pretty huge results. I mean, what's the game plan in terms of sort of moving some of those gas and liquids out? I mean, 4,000 BOE test is still pretty substantial. Are these -- what's the well sort of -- well like that doing a month later or 2 months later? Gregory P. Hill: We'll give you -- again in Investor Day in November, we'll give you a full kind of update on the Utica, how it's performing, the play and also where we're going in the future with it. Faisel Khan - Citigroup Inc, Research Division: Okay. Okay. Fair enough. And just on Tubular Bells, as that facility ramps up, what's the quality of crude coming out of that field? Is it sort of a Mars Blend? Or is it something that we should expect more of an LLS type of crude? John B. Hess: It'll have an LLS typing -- LLS relationship in terms of pricing. Faisel Khan - Citigroup Inc, Research Division: Okay. And then in terms of moving your crude out of the Bakken, has anything changed with regard to how you're moving your crude out or how you're thinking about moving your crude out, whether it's rail or pipeline? There've been a number of pipeline projects announced. So I just want to understand sort of what your game plan is for those volumes in the future. John B. Hess: Yes. Currently, we move approximately 50% of our crude by pipeline and 50% by rail. And as our production ramps up in the future, you can expect that, that balance will stay roughly in place. We are subscribing to more pipeline space, but we're also looking at adding some more railcars to make sure we have the infrastructure in place to move to the highest value markets. Faisel Khan - Citigroup Inc, Research Division: Okay. Then last question for me. The sale of HETCO, how much capital or working capital does that free up from -- within the company on the balance sheet? John P. Rielly: So just so you know, we have not disclosed the terms, the proceeds associated with the sale because it is confidential. And from a general aspect, it's not going to be material to our financial statements.

This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day. Thank you.