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

Evan Calio - Morgan Stanley, Research Division Edward Westlake - Crédit Suisse AG, Research Division Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division Paul Sankey - Deutsche Bank AG, Research Division Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Arjun N. Murti - Goldman Sachs Group Inc., Research Division Guy A. Baber - Simmons & Company International, Research Division John T. Malone - Mizuho Securities USA Inc., Research Division Paul Y. Cheng - Barclays Capital, Research Division Pavel Molchanov - Raymond James & Associates, Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research

Good day, ladies and gentlemen, and welcome to the second quarter 2013 Hess Corporation conference call. My name is Derek, and I'll 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, Derek. Good morning, everyone, and thank you for participating in our second quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. The 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 earnings information provided on our website. With me today are John Hess, 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 second quarter conference call. I will make a few high-level comments on the quarter and the progress we are making in executing our strategy to become a pure play E&P company. Greg Hill will then discuss our E&P operations, and John Rielly will then go over our financial results. Net income for the second quarter of 2013 was $1.4 billion, or $520 million on an adjusted basis. Adjusted earnings per share were $1.51 compared to $1.72 in the year-ago quarter. Net production in the second quarter averaged 341,000 barrels of oil equivalent per day compared to 429,000 barrels of oil equivalent per day in last year's second quarter. Asset sales associated with our strategic portfolio reshaping accounted for approximately 70,000 barrels of oil equivalent per day, or 80% of the decline versus last year's second quarter. Planned downtime at the Valhall Field in June and lower entitlement under the production sharing contract at the Malaysia/Thailand JDA accounted for the balance of the decline, which is partially offset by higher production from the Bakken. In the second quarter, net production from the Bakken averaged 64,000 barrels of oil equivalent per day, up 16% from a year ago. As a result of our transition to pad drilling, we expect to see an increase in production in the second half of the year. Our full year 2013 production forecast for the Bakken remains 64,000 to 70,000 barrels of oil equivalent per day. Bakken well costs declined to $8.4 million in the second quarter, down 28% from the year-ago quarter. For the corporation, our full year 2013 production forecast remains 340,000 to 355,000 barrels of oil equivalent per day. Taking into account the impact of asset sales, our pro forma 2013 production is expected to average 290,000 to 305,000 barrels of oil equivalent per day, up from pro forma production of 289,000 barrels of oil equivalent per day in 2012. From our pro forma 2012 base, we expect to achieve a 5-year compound annual growth rate of 5% to 8% through 2017 and growth in the mid-teens in aggregate from 2012 to 2014. This production growth will come from captured lower-risk assets, including the Bakken, Valhall, Tubular Bells, North Malay Basin and the Utica. Our portfolio reshaping moves have improved our cash margin. Second quarter 2013 pro forma upstream cash margin was $54 per barrel of oil equivalent, up $6 per barrel of oil equivalent from last year's actual second quarter results despite Brent oil prices declining more than $5 per barrel. Capital and exploratory expenditures in the first half of 2013 were $3.2 billion, which was down 20% from the first half of 2012. This decline reflects improved capital efficiency in the Bakken, the impact of asset sales, as well as the declining capital intensity of our portfolio. Our full year 2013 capital and exploratory expenditures forecast remains $6.8 billion. We continue to project that 2014 capital and exploratory expenditures will be significantly lower than 2013 and more aligned with our cash flow. We continue to make steady progress in executing our divestiture program. During the second quarter, we completed approximately $2.2 billion in asset sales, including the sale of our interest in Samara-Nafta for $1.9 billion. This brought completed asset sales as of June 30 to $3.5 billion. Proceeds were used to repay $2.4 billion of debt and to strengthen our balance sheet so that the company will have the financial flexibility to fund our future growth. Yesterday, we announced the sale of our Energy Marketing business to Direct Energy for $1.025 billion. This business markets natural gas, electricity and fuel oil to 23,000 commercial, industrial and small business customers in the eastern half of the United States. The sale of our Energy Marketing business brings year-to-date asset sales to $4.5 billion and puts the company in a position to commence our previously announced share repurchase program. The remaining divestment processes for our upstream assets in Indonesia and Thailand, as well as our downstream terminals, retail and trading businesses are well underway. We believe that our strategy to become a pure play E&P company will create significant long-term value. Our focus is on execution, growing production, driving further reductions in capital expenditures and operating costs, completing our remaining asset sales and increasing cash returns to shareholders. With that, I will turn the call over to Greg, who will provide 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. As previously discussed, Hess is executing a 3-pronged growth strategy through: one, unconventionals, with growth driven by the Bakken and Utica; two, exploitation, with growth driven by Tubular Bells, Valhall and North Malay Basin; and three, focused exploration in areas such as Ghana. This balanced strategy underpins the 5% to 8% compound annual production growth rate that John just laid out. Starting with unconventionals. In the second quarter, net production from the Bakken averaged 64,000 barrels of oil equivalent per day, up 16% from the second quarter of 2012. As we had previously indicated, our Bakken production was relatively flat in the first half of 2013 as a result of our transition to pad drilling. That transition is now largely complete, and we will see higher production in the second half of the year. There will be planned downtime in the Bakken during the fourth quarter as we complete the expansion of the Tioga Gas Plant. And while natural gas production will be partially curtailed for approximately 6 weeks, oil production is expected to be only modestly impacted. This downtime is incorporated into our 2013 Bakken production guidance, which remains 64,000 to 70,000 barrels of oil equivalent per day. In terms of individual Bakken well performance, we remain focused on driving superior returns, which is a function of well costs, productivity and price realization. Well costs in the second quarter averaged $8.4 million per well, down 28% from $11.6 million per well in the second quarter of 2012 and down from $8.6 million per well in the first quarter of 2013. In addition, the productivity of our wells continues to be among the highest in industry as 18 of the top 50 wells, or 36%, in the North Dakota Bakken play since the beginning of 2012 are Hess-operated wells. During the quarter, we brought 42 operated wells on to production, of which 27 were Middle Bakken and 15 were Three Forks. For the full year, we expect to bring approximately 170 wells on production, with 2/3 targeting the Middle Bakken and 1/3 targeting the Three Forks. We continue to conduct pilot programs to test optimal well spacing. While these tests are ongoing, our current thinking is that core Middle Bakken can be down spaced to approximately 180-acre spacing in many areas. Although we are still early in the testing in the down spacing of our Three Forks acreage, we believe the in-fill potential will be broadly similar to the Middle Bakken. Our Tioga rail facility ran at capacity in the second quarter, delivering an average of 53,000 barrels per day to higher-value markets. Our Tioga Gas Plant expansion project, which will increase wet gas input capacity from 120 million cubic feet a day to 250 million cubic feet a day, is on schedule for commissioning at the end of 2013, enabling us to capture more liquids and value from our own gas and from third parties. In summary, we are on track to deliver our 2013 production and capital guidance for the Bakken, and we are increasingly optimistic about the long-term upside. Turning to the Utica. The appraisal of our acreage continues, and we are increasingly encouraged by well results to date. In the second quarter, 10 wells were drilled, 3 were completed, and 3 were flow tested. Two of the 3 tested wells were operated by Hess. On our 100% owned acreage, the Richland B 1H-34 well in Belmont County tested at a 24-hour rate of 2,985 barrels of oil equivalent per day, including 29% liquids. On our joint venture acreage, we, as operator, tested the Cadiz A 1H-23 well in Harrison County at a 24-hour rate of 2,250 barrels of oil equivalent per day, including 57% liquids. In 2013, Hess and CONSOL expect to spud approximately 40 wells and drill 25 across both our 100% owned and joint venture acreage. Turning to the second element of our strategy, exploitation. Progress continues at Valhall, Tubular Bells and North Malay Basin. At the BP-operated Valhall Field in Norway, in which Hess has a 64% interest, net production averaged 13,000 barrels of oil equivalent per day in the second quarter. The field was shut in for one month during the second quarter due to planned downtime at Ekofisk. Full year 2013 net production from Valhall is forecast by the operator to be in the range of 24,000 to 28,000 barrels of oil per day, which we believe will come in at the lower end of this range. In July, net production has averaged approximately 26,000 barrels of oil equivalent per day from Valhall. At our 57% owned and operated Tubular Bells development in the deepwater Gulf of Mexico, our second production well was drilled during the quarter, and we are currently drilling the third. We are on track for field startup in mid-2014, delivering 25,000 net barrels of oil equivalent per day of high-margin Gulf of Mexico production. At North Malay Basin in the Gulf of Thailand, where Hess has a 50% working interest and is operator, the jacket and topsides were installed, and the Floating, Production, Storage and Offloading vessel for the early production system arrived on location in June. In addition, the 5-well development drilling program is underway. We anticipate an on-time start of production in the fourth quarter at a net rate of 40 million cubic feet per day. With regard to full field development, as a result of an upward revision in net gas sales from 125 million cubic feet a day to 165 million cubic feet a day, additional engineering and construction work will be required, which will push first gas toward year-end 2016. In terms of exploration, following 7 consecutive discoveries on the Deepwater Tano Cape Three Points Block in Ghana, where Hess has a 90% working interest and is operator, we submitted our appraisal plans to the government in June. We plan to commence appraisal drilling in 2014 and are continuing our pre-development work, including preliminary front-end engineering and design. Consistent with our exploration strategy in August, we plan to open a data room with the intent to farm down our Ghana interest. In Kurdistan, where Hess has a 64% working interest and is operator of the Shakrok and Dinarta blocks, we will spud the first of 2 planned exploration wells in August and anticipate spudding the second well in the fourth quarter. Here, we also recently opened a data room and plan to bring in partners. In closing, strong execution performance in the first half of the year means that we are on track to deliver both our short and long-term goals. I will now turn the call over to John Rielly. John P. Rielly: Thank you, Greg. Hello, everyone. In my remarks today, I will compare results from the second quarter of 2013 to the first quarter of 2013. The corporation generated consolidated net income of $1,431,000,000 in the second quarter 2013 compared with $1,276,000,000 in the first quarter of 2013. Excluding items affecting comparability of earnings between periods, the corporation had earnings of $520 million in the second quarter of 2013 and $669 million in the previous quarter. Turning to Exploration and Production. E&P had income of $1,533,000,000 in the second quarter and $1,286,000,000 in the first quarter of 2013. Excluding items affecting comparability of earnings between periods, E&P had income of $600 million in the current quarter and $698 million in the previous quarter. Second quarter income included a non-taxable gain of $951 million related to the sale of the corporation's 90% interest in its Russian subsidiary, Samara-Nafta. Second quarter 2013 results also included an after-tax charge of $18 million for employee severance and exit costs. The changes in the after-tax components of adjusted earnings were as follows: lower sales volumes decreased earnings by $165 million; changes in realized selling prices decreased earnings by $40 million; lower cash costs improved earnings by $60 million; lower depreciation, depletion and amortization improved earnings by $55 million. All other items net to a decrease in earnings of $8 million for an overall decrease in second quarter adjusted earnings of $98 million. Our E&P crude oil operations were over lifted compared with production by approximately 550,000 barrels in the quarter, which increased after-tax income by approximately $30 million. Based on our current crude oil lifting schedule, we expect this over lift to reverse in the third quarter. The E&P effective income tax rate, excluding items affecting comparability, was 44% for the second quarter of 2013. We have provided quarterly operational data for the Bakken in the supplemental earnings presentation posted on our website, including production data, number of rigs, Middle Bakken and Three Forks well counts, average gross 30-day initial production rates, well costs, working interest percentages and acreage totals. The supplemental earnings presentation also includes pro forma E&P results for 2012 and 2013. The pro forma information presents our results as if our asset divestiture program had all been completed effective January 1, 2012, in order to present a historical comparison of the performance for the ongoing portfolio. This pro forma information includes operational data and cash margins. Turning to Corporate. Corporate expenses after income taxes were $50 million in the second quarter and $44 million in the first quarter of 2013. Corporate expenses are higher than normal in both periods due to severance charges and increased proxy costs and professional fees. After-tax interest expense was $63 million in the second quarter of 2013 compared with $66 million in the first quarter. Turning to cost savings. As part of our transformation to a pure play E&P company, we are taking steps to realign the organization and reduce costs. During the second quarter of 2013, we continue to reorganize the E&P and Corporate functions to support the new portfolio and announced the closure of our London office by the end of the first quarter of 2014. These initiatives are anticipated to result in annual cost savings of $150 million. Turning to discontinued operations. Earnings from the downstream businesses were $11 million in the second quarter and $100 million in the first quarter of 2013. Second quarter 2013 results included after-tax charges totaling $21 million for employee severance related to the corporation's planned exit from its downstream businesses and cost to idle refinery equipment at the Port Reading refining facility. First quarter 2013 results included net after-tax income of $30 million from items affecting comparability. Adjusted earnings decreased for the quarter, principally reflecting seasonally lower natural gas and oil volumes in Energy Marketing, partially offset by higher retail gasoline margins and improved trading results. Turning to cash flow. Net cash provided by operating activities in the second quarter, including a decrease of $70 million from changes in working capital, was $1,247,000,000. Capital expenditures were $1,500,000,000. Net proceeds from asset sales were $2,291,000,000. Net repayments of debt were $1,688,000,000. All other items amounted to a decrease in cash of $69 million, resulting in a net increase in cash and cash equivalents in the second quarter of $281 million. Turning to our financial position. Earlier this year, we committed to applying the proceeds from our asset sales program to improve our financial flexibility to fund growth and provide current returns to shareholders. More specifically, proceeds from divestitures are to be applied to: repay debt, provide a cash cushion, fund the 2013 cash flow deficit and return cash to shareholders by repurchasing up to $4 billion of shares. To date, we have used proceeds from divestitures to repay debt, begin to build the cash cushion and fund the cash flow deficit. In the third quarter, the corporation plans to increase its annual dividend. And with the announcement of the sale of our Energy Marketing business, we are in a position to commence our share repurchase program. We are progressing plans to monetize our Bakken infrastructure assets by 2015 and use the proceeds to return additional cash to shareholders. We had $725 million of cash and cash equivalents at June 30, 2013, and $642 million at December 31, 2012. Total debt was $5,800,000,000 at June 30, 2013, and $8,111,000,000 at December 31, 2012. And the corporation's debt to capitalization ratio was 19.5% at June 30, 2013, compared with 27.7% at the end of 2012. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

[Operator Instructions] And our first question is coming from the line of Evan Calio, Morgan Stanley. Evan Calio - Morgan Stanley, Research Division: Let me start with a strategic question -- strategy question. John, you've reconstituted the board since last earnings call, 10 new and experienced members. The board has met. While you appear to have clear operational momentum, I was just -- could you update us on any broader strategic review occurring? Or any update on the strategic assessment or comments on how the board transition has gone so far? John B. Hess: Yes. The board transition has gone very well. I would characterize the first board meeting that we had in June as very constructive, and we're totally focused on executing the strategy we've outlined. Evan Calio - Morgan Stanley, Research Division: That's great. And keeping on the asset sale theme, restructuring theme, sale proceeds have exceeded expectations, I think yesterday is included, maybe harder to reconcile from the deconstructed historical EBITDA of the Retail segment. Maybe a few questions that could help. I mean, for -- could you provide a 2012 EBITDA or a cash metric for the Energy Marketing business for the OM? John P. Rielly: All right, Evan. So obviously, we're in the middle of these processes. Right? So the sale process, and we don't want to front run the process. You saw, I think, in Centrica's release that they had $200 million of estimated EBITDA for 2013. That's a reasonable estimate for the business. Last year, obviously, it was a warmer winter. Right? So it was at least 20% less heating degree days last year. So that obviously would have impacted the EBITDA in 2012 as it related to Energy Marketing, but that's really as far as we're going to go. We're not going to front run the sale process. Evan Calio - Morgan Stanley, Research Division: Okay. Well then, maybe a risk of a -- of getting a similar response on the terminal sales, can you give us any historical utilization rates? Or any metric there because I presume some uptick in potential value will be improved utilizations to a potential buyer. John P. Rielly: So, Evan, I mean, every buyer is going to look at the business potentially differently from how they want to manage it. So we're not providing that data right now. We are well into the process. Obviously, selling the terminal business in this current environment is a positive thing. It's a very good environment. The assets are strong. We've got a nice set of assets here on the East Coast, and the interest has been keen in these assets. So that's as far as I think we want to go. And just as John said, earlier, the sales progress is well underway and is going according to plan. Evan Calio - Morgan Stanley, Research Division: And then maybe lastly if I could. Could you provide any tax basis in assets held, or how much coverage, how much tax coverage you have for those assets that are announced yet haven't yet received -- closed yet? John P. Rielly: There will be significant gains on the assets on an overall basis to be sold. From a tax leakage guidance standpoint from the overall sale proceeds that we are getting as part of this program, we've talked about that our tax leakage will be less than 5%. That's overall. That's with the E&P businesses and the downstream businesses.

Your next question is from the line of Ed Westlake, Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Just continuing on that downstream thought process, are there any corporate costs that are in the downstream that would be discontinued if those assets were sold? Just trying to true up historical reporting to what a seller might look at for these assets. John P. Rielly: There are allocated costs. And for the most part, the Corporate cost, if you want to call it that, are -- assigned to the business units are allocated and are within the segment. Now there's no question, as I said as part of our cost-saving initiative, that we are looking at over all our functions and are going to right size and reorganize the functions for the smaller portfolio that we have. But I would tell you, in general, most of the costs are allocated into the segment. Edward Westlake - Crédit Suisse AG, Research Division: Right. Okay. And then switching to the Bakken. Obviously, you've guided that the shift to pad drilling would constrain volumes and that there will be an inflection in the second half. As we look out into 2014, '15, '16, I mean, any sort of feeling at this stage in terms of which of those years will be the faster growth on towards the sort of 120,000 barrel day that you've discussed in the past in terms of the rate of that growth? Any color there would be helpful. Gregory P. Hill: Yes, sure, Ed. So I think that's going to be function of obviously how much capital we put in it. But I think once we get through the gas plant commissioning at the end of this year, I think, for all practical purposes, you assume a relatively steady ramp from there to 120,000 barrels a day over a couple of years. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And initial volume estimates for the Utica, given the well results you've had? Gregory P. Hill: In terms of what year, Ed? Edward Westlake - Crédit Suisse AG, Research Division: Say next year, 2014? Gregory P. Hill: We haven't finished our plan yet, and we're still in the appraisal phase. So next year will be another appraisal year.

Your next question is from the line of Doug Leggate, Bank of America Merrill Lynch. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: A couple of questions, please. I guess, first, for Greg. Greg, the Three Forks opportunity in the Bakken, when our numbers -- you're going to be pretty much getting into a sort of cash breakeven type of situation and probably within the next 12 to 18 months. What are the plans there as it relates to optimizing the development of that inventory? Should we expect you to step up capital and development in the Bakken or shift capital toward the more aggressive development plan in the Utica? And I've got a couple of follow-ups, please. Gregory P. Hill: Yes, Doug. I think, again, we haven't finalized our business plan for next year. I think as we've done in the past, we will put that capital to wherever the best return is. And so obviously, as we appraise and understand the Three Forks, and that's going very well by the way, the Three Forks are actually some of our best wells in the play, we'll allocate capital between the Middle Bakken and Three Forks to drive whatever the highest return is. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: But in terms of the absolute rig count and activity level, Greg, as -- I mean, as you get to cash breakeven, are you going to step that up a bit or maintain the current operating plan? Gregory P. Hill: Yes. I think, again, Doug, we're still finalizing our plans for next year and the following year. So too early to kind of be specific on that. But suffice it to say, it'll be an aggressive program for the Bakken. John B. Hess: I think, Doug, how we think about it conceptually, and Greg and I were up in North Dakota a couple of weeks ago, our team is doing an outstanding job and our hat's off to them really working on capital efficiency, is Greg in his remarks talked about down spacing. And also, less of our money going forward is going to be for infrastructure. So there'll be more money for drilling. So we're really coming forward now with optimizing our investment program for next year and the year after. And as we get that defined, obviously, we'll be able to share it with you. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: A couple of follow-ups, please. John, latest thoughts on a potential -- I guess I was going to say restructuring, but that's not the right word. A potential MLP of the midstream business led by Tioga? John P. Rielly: Sure. So as I mentioned, Doug, we are on track. By 2015, we'll be -- we are going to be looking at monetizing that Bakken infrastructure. And obviously, an MLP is a potential key strategy for doing that. We are -- the big key to this, as Greg had mentioned, is to complete the Tioga Gas Plant. So we have all hands on deck to complete that expansion at the end of this year. What we're looking to do is then, as we start 2014, to begin to break out the midstream segment. So to be able to start reporting kind of EBITDA as we see going forward and how the midstream segment would operate, with the goal again of being ready in 2015 to be able to monetize or have an MLP in place for the Bakken assets. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Right. But, John, an outright sale as opposed to an MLP, is that possible given that -- I mean, MLPs need growth, and if you don't have a lot of drop downs, would a potential trade sale be on the table as well or not? John P. Rielly: Well, first of all, we'll look at all options, but it doesn't appear that, that would be the case, Doug and why we see good growth in that midstream asset. So one, we've got several types of assets that can be put into it, in the Bakken. One is the rail terminal aspect. So you can always start with a drop down of pieces of it. So you have the rail terminal, you have all the gathering facilities that are in place and then you have the gas plant. And so we view, one, that there's great growth in this business; and two, we want to maintain control because control is critical for us, as you would ask before, about us ramping up our production in the Bakken. And with the production growth coming through that, obviously, drive some growth. And as we move forward, we have other potential assets in our portfolio that can be included in the midstream and also will drive growth. So we see some good growth there, and it looks like it can provide very good value for our shareholders. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Last one for me, maybe to John Hess. John, it looks like you're going to do substantially better than the disposal proceeds, and a lot of people I think expect it. What's the chances of upsizing the buyback? And what is the mechanism of implementing the buyback? And I'll leave it there. John B. Hess: I'm going to let John Rielly answer the buyback question. John P. Rielly: So where we are right now, Doug, from a planning standpoint, I could talk at a high level, as John mentioned earlier, we're in a position to begin repurchasing the shares under our $4 billion authorization. So we have an authorization up to $4 billion. We expect the repurchases to be spread fairly consistently over time. And as a result, we will incur short-term debt periodically as we purchase shares in advance of receiving divestiture proceeds. So just to -- as part of that, any such debt we incur will be paid off with subsequent sale proceeds like the Energy Marketing transaction that we have. And then we'll keep you informed of our progress with the plan on future quarterly conference calls. It's just early to say anything more with that as far as our share repurchase plan.

Your next question is from the line of Paul Sankey, Deutsche Bank. Paul Sankey - Deutsche Bank AG, Research Division: Could I just follow-up straightaway on the buyback versus debt-type question? Do you have a target, a notional longer-term target for leverage now? I know in the past you've given one. John P. Rielly: The way we're looking right now. As you saw, we're under 20% of our debt cap. And our portfolio as we see going forward, as John had mentioned, in 2014, we've always referred to that as type of -- the tipping point with our portfolio, where free cash flow will approach our capital spend. And post 2014, our portfolio can deliver this 5% to 8% growth that we have targeted with our cash flow from operations. So from that standpoint, we don't have to increase debt. So there's no increase in leverage planned from that standpoint. And again, with the share repurchases, again, we are funding that with our proceeds from asset sales. So we're very comfortable that we will have a very strong balance sheet. And obviously, from that standpoint, we're not looking to lever up going forward but we'd be in a position if their commodity prices decrease, that our balance sheet would be able to handle any cash flow deficits that could occur from that standpoint. So we like our leverage where it is. Paul Sankey - Deutsche Bank AG, Research Division: On the announcement of the Bakken monetization of the midstream, is there any implication there for the spin of the entire Bakken that was mooted? Are the board -- is the board considering that spin now? John B. Hess: Obviously, the board will consider all moves to maximize shareholder value. But the plan we've outlined as a pure play E&P, having both the onshore and offshore business, we think, is the best way to maximize value. And the best way we're going to do that is to focus on the execution of the plan that we've outlined already. Paul Sankey - Deutsche Bank AG, Research Division: Yes. Okay. So to be very clear, I think that the announcements of the MLP doesn't have any implications for any potential or not, spin of the Bakken. John B. Hess: Not at all. And to reemphasize John Rielly's point, it's very important that, regardless of the financial structure that we move forward with our infrastructure in the Bakken, it could be an MLP, it could be a joint venture. Hess will continue to control and operate that infrastructure. That's essential for our future production and controlling that and accessing the markets as we move forward.

Your next question is from the line of Robert Kessler, Tudor, Pickering and Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I wanted to see if you wouldn't mind quantifying the degree to which you generate RIN in your -- I assume your terminal business or retail as the case may be? John P. Rielly: Sure. I mean, we are in a position that we are benefiting from the current RIN environment. Now just to point out, Hess does remain an obligated party for RINs because we do import transportation fuel to meet marketing's gasoline demand. But our retail and terminal networks do generate more renewable credits than required to meet our supply needs. In the second quarter, our excess RINs generated a $17-million after-tax benefit. So that's what it was in the second quarter. If you're looking at the third quarter, I would tell you, we're generating RINs around $20 million a month of excess RINs. So if you were to take the current pricing that's in place right now and just say you sold all the RINs at that price for the third quarter, you could expect us to record an after-tax benefit in the $35 million to $40 million. Now, again, that's additional, so that would be in the second quarter with the $17 million already been recorded in the first quarter. Now, however, I have to add this -- and it's not quantifiable. But the cost of RINs rising in recent months has led to some RIN sharing, I'll call it, at the wholesale level, which is reducing our retail fuel margins and offsetting some of the direct benefit from selling the excess RINs. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Now how do you think about this as it relates to marketing the assets? I mean, presumably different buyers might have different interests as far as how much value they attribute to their RIN integration. Are you considering different options as far as whether it's packaged with the terminals or retail or sold independent of the other 2 pieces? John B. Hess: Yes. Each one of our businesses, the terminal business and the retail business, will be divested separately to maximize value. Processes for those, as well as Indonesia, Thailand and our trading business are underway. Obviously, it's premature to share any details, but we're going to obviously pursue all alternatives to maximize value. John P. Rielly: If you don't mind, I just want to make sure I clarify this point out. When I said the $35 million to $40 million, that would be a third quarter benefit. I guess I had said second quarter. So that's a third quarter, and the RINs generate a $17 million after-tax benefit in the second quarter. So just to make sure I got that right. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then separately from me, the Bakken rail dynamics and pipe dynamics out of the basin have shifted quite a bit in recent weeks. I'm wondering what you might be seeing so far in the third quarter as it relates to your movement of third-party volumes by rail versus by pipe. John B. Hess: Right. Through the second quarter, we have been maximizing our rail shipments between 53,000 and 55,000 barrels a day out of Tioga. In July, as you rightfully point out, the market dynamics shifted where the WTI/Brent spread started to narrow, and it even narrowed more in August. As a consequence, because we have 3 alternatives to maximize our net backs of our crude in North Dakota, one is supplying local refinery, another is accessing pipeline Enbridge for the mid-continent, and the third is our rail. We were in a position to maximize value by moving approximately 4,500 barrels a day in July to pipeline markets and up that number to 12,000 barrels a day to pipeline markets in August. Right now, where the differentials are looking forward, the rail is actually more attractive again. And remember, the rail doesn't just go to St. James. It also goes to the East Coast and West Coast. So we're in a unique position to capture the highest value wherever the market offers it, and we continue to do so.

Your next question is from the line of Arjun Murti, Goldman Sachs. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: Just a couple of quick ones. I think, John, you mentioned the pro forma x asset sales number for 2013. Is the 2014 number still the 3 25 [ph] to 3 40 [ph]I think you'd previously articulated? John P. Rielly: Yes. There's no change in our guidance. Our guidance was that our pro forma production in 2012 was 289,000 barrels a day. And then by 2014, we would have aggregate mid-teens growth there, and there's no change in that. And again, the growth driven by Bakken, Valhall and Tubular Bells coming online. Arjun N. Murti - Goldman Sachs Group Inc., Research Division: That's great. And just one follow-up on the Bakken. I think in part, the lower-cost savings comes from a different completion methodology. It looks like the IPs are still doing quite well. I don't know, Greg, if there's any additional color on how you're feeling about overall EURs or what they might be with the changing completion methodology? Gregory P. Hill: Sorry, I didn't have my mic on. Yes, I think the EURs are within the range that we've discussed previously. We're a little bit at the higher end of the range in the second quarter versus the first quarter. Completion costs continued to come down this quarter. That was due to efficiency as a result of pad drilling, as well as some pricing concessions that we got some frac contracts.

Your next question is from the line of Guy Baber, Simmons & Company. Guy A. Baber - Simmons & Company International, Research Division: Just one quick one from me, but I was just hoping you could address some of the planned maintenance at Valhall in a little bit more detail? Because I didn't recall any maintenance there being telegraphed at the time of the last call, and obviously, that asset has had some significant downtime since the second half of last year. But was that strictly related to the Ekofisk shutdown? Or was there anything specific you had to address there at Valhall? Just hoping for a little bit more detail there. And then if you could just confirm your confidence in the longer-term targets there as well. Gregory P. Hill: Yes. So on the first thing, no. This was all just planned maintenance at Ekofisk. So Valhall was taken down for a month, and I do believe that we telegraphed that earlier, that, that was an upcoming maintenance event in the second quarter. I think over the long haul, our strategy is the same. Just work with the operator, BP, to get that facility as maximum capacity as possible. And we are at -- in July, we're back up around 26,000 barrels a day on Valhall.

Your next question is from the line of John Malone, Mizuho Securities. John T. Malone - Mizuho Securities USA Inc., Research Division: So one question on Ghana and on Kurdistan. You said the data rooms will be open, if not now, it will be open shortly. Do you expect to get partners in there before the end of 2013? And can you kind of give a range of what your ideal routine working interest would be in both of those assets? Gregory P. Hill: Well, I think as we've said before, part of our exploration strategy is to reduce our higher working interest opportunity set. So -- and as we said before, it's going to be case-by-case. But this kind of 40% kind of a working interest would be our ideal sweet spot. Regarding timing, again, the data rooms have -- in Kurdistan have just opened. Obviously, we would like to get a partner as soon as possible in Kurdistan because we'll start drilling in August. And then on Ghana, the data room hasn't opened yet but will open imminently. And clearly, we'd like to get a partner in there as soon as possible as well. So... John T. Malone - Mizuho Securities USA Inc., Research Division: And then just getting back to the Bakken for a second. It looks like in this quarter you had to do a higher proportion of gas and production. Is that a trend that ought to continue? And how does the Tioga refit influence that higher proportion of gas? Gregory P. Hill: Well, I think with time, as the Tioga Gas Plant comes on, you will end up with a little bit higher proportion of gas in your stream. But it won't be a significant major shift. John T. Malone - Mizuho Securities USA Inc., Research Division: Okay. So the proportion we're at now, I think, will go up a little bit from the proportion of gas in Q... Gregory P. Hill: Yes. Yes. Go up slightly. Yes.

Your next question is from the line of Paul Cheng, Barclays. Paul Y. Cheng - Barclays Capital, Research Division: Greg, earlier, talking about the farm down on Ghana and Kurdistan, what is the primary consideration when you consider that weather is going to come in? Is it a financial consideration? Or is that -- more importantly, is on the other strategic indication that may represent? Gregory P. Hill: Yes. I think there's 2 -- there's 2 drivers. I think on Ghana, obviously, the main driver there is reduce some financial exposure, right, for Ghana. And then for Kurdistan, it's the same, reduce some financial exposure, but also reduce risk. This -- Paul, if you recall, this is part of our overall exploration strategy to reduce working interest in order to allow us to get more drill bit exposure for the same investment. So obviously, if I'm 1/3, 1/3, 1/3, I can drill 3x as many wells as if I'm 100%. Paul Y. Cheng - Barclays Capital, Research Division: Sure. Totally agree. I just want to see that -- I mean, is the most important -- in terms of who going to win the bid, is it based on how much they pay you? Or there is other factor is more important? I guess that's my question. Gregory P. Hill: I think there's other -- yes, I think there's other factors. I mean, obviously, price will be a key consideration. But if you think about Ghana, we would obviously look at the technical capability of the partner as well as being an important consideration in that. Paul Y. Cheng - Barclays Capital, Research Division: But will you be looking at that -- sort of like a swapping asset in the case of Ghana? Or that's not really the preferred route? Gregory P. Hill: That's not really the preferred route. John B. Hess: It's getting someone with a financial capability to help us reduce risk and maximize value for the risk we will be taking. So I would say the economic concerns would be the primary one. Gregory P. Hill: Right. Paul Y. Cheng - Barclays Capital, Research Division: Okay. And John Rielly earlier, based on the way that you talk about the buyback, have you already started the buyback? Or that you are still waiting for the Energy Marketing deal to be closed before you start? John P. Rielly: We have not started the buyback, so just to be clear on that. And then to your question, no, we're in a position now that we expect our repurchases to be spread over time. And as I said, we can incur debt here periodically because we will be buying shares back prior to receiving divestiture proceeds. So we won't be waiting for the Energy Marketing proceeds. Paul Y. Cheng - Barclays Capital, Research Division: But will you start the buyback, say, in the third quarter? Or that is going to be later? John P. Rielly: So I mean -- we want to keep this at a high level from a planning standpoint. So we clearly -- as with the Energy Marketing sale, which we expect to close in the fourth quarter, we will be buying ahead of that. So yes, we do expect to start in the third quarter, but I don't want to say anything more than that. Paul Y. Cheng - Barclays Capital, Research Division: Okay. That's fair. And John, when you -- earlier, that you're talking about the potential tax leakage on the asset sales would be less than 5%, is that also based on the assumption that you're going to sell the retail and not a tax-based spin-off? John P. Rielly: So from an overall standpoint, right, we're on dual track on the retail. But from -- either way, if we're looking at that from a overall asset sale proceeds, including E&P, yes, we still say it will be less than 5% of the overall proceeds. Paul Y. Cheng - Barclays Capital, Research Division: So even if you're going to sell retail, not tax-based spin-off, you'll still be less than 5% do you believe? John B. Hess: I think the key point there, Paul, is we are going to pursue all alternatives to maximize value for retail, and it's just premature to share any details further than that. Paul Y. Cheng - Barclays Capital, Research Division: Okay. Greg, on Utica, on the liquid [ph], can you tell us what is the liquid [ph]? Is this C3, C4, C5, C6? I mean, what kind of component are we talking about? Gregory P. Hill: Sorry, I had to -- sorry, I had to turn my mic on and I apologize for that. It's -- for the majority of the wells that we've tested so far, so the ones in second quarter, the one that I quoted of 2,250 barrel equivalents per day, that's got about 360 barrels of condensate in it. So -- and some NGLs. So of that 2,250, 57% is liquids on an all-in basis. So really, Paul, it really just depends on where you are in this play. We're still delineating all of those lines. Where is the condensate? Where is NGLs? Where is dry gas? And so it's a mixed bag right now. Paul Y. Cheng - Barclays Capital, Research Division: So you're still not seeing an established pattern based on the well that you test in terms of this split between condensate and NGL? Gregory P. Hill: We just don't have enough well data yet. Just keep in mind, as far as tests, since 2012, we only have 12 or 13 wells that we've tested. So it's still very early, and we're trying to appraise all those various windows as industry is doing as well. Paul Y. Cheng - Barclays Capital, Research Division: And that -- Greg, when we're talking about Bakken, you had debt target of 120,000-barrel per day back, I think, in 2000 -- maybe in late 2009, 2010, early? And that target, is that already -- you incorporate your potential in Three Forks or just on the Middle Bakken? Gregory P. Hill: No. I think we -- either/or, I guess, is how I would answer that. It's mainly going to be a function of how much capital you put in and how fast you ramp it up. Because we will interchange Three Forks and Middle Bakken wells as necessary, again, trying to go where the highest return is. So [indiscernible]. Paul Y. Cheng - Barclays Capital, Research Division: No, I understand. Just saying that in terms of the resource potential, can -- including the Three Forks and the Middle Bakken, can they support even bigger than 120,000? I guess that's my question. Or the resources really can only support 120,000? Gregory P. Hill: No, no, no. They could definitely support a higher peak rate. And again, it's just going to be a function of how much capital you put into the Bakken on an annual basis. Right? [indiscernible] the resource is there. Paul Y. Cheng - Barclays Capital, Research Division: Two final questions. One, John, do you have a number that, in terms of what is the unit operating costs at Bakken in the second quarter and in terms of the cash operating cost and including the transportation cost? And second one, just want to confirm, you said that you generate about 20 million gallons a month in the excess RIN. I just want to confirm that number. John P. Rielly: So, yes, Paul. It's 20 million a month of excess RINs that we generate per month. And then as far as the Bakken unit costs, in general, our guidance has been -- is that our operating cash costs, including production taxes, are a bit below our portfolio average that we have for the overall portfolio. And our unit DD&A costs, including all the infrastructure-related costs associated with it, are higher than our portfolio average. And we do anticipate, and it has been happening, that our unit cash costs will decline as volumes increase and that the unit DD&A will also decrease going forward as a result of increasing the reserve bookings relative to investment. And also, as John mentioned earlier, decreasing infrastructure spend. Paul Y. Cheng - Barclays Capital, Research Division: Sure. Just a request, if possible, that in your supplemental data, that it's great that you put all those information on Bakken, if you can also add on the operating cost and the DD&A, that would be really helpful. John P. Rielly: Okay. Thank you.

Your next question is from the line of Pavel Molchanov, Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: You referenced the appraisal plan in Ghana. Any sense of the timetable for getting approval on that? And any particular conditions or -- that you're concerned about? John B. Hess: Greg and I were in Ghana. I met with the top government officials in June, got a very warm reception and encouragement, and the ball is in their court to tell us when they will approve the appraisal program. But I would say the signs are encouraging, as well as the signs for us bringing in a partner or partners. So we have a very good relationship there, and the ball is in their court. And when we have something to report, we will tell you. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Understood. And regardless of when you get approval, what's the anticipated timetable for bringing Ghana onto production? Gregory P. Hill: So I think -- so just the timetable, would be -- once we get approval of the appraisal plan, then the clock runs for 2 years for that appraisal period. Obviously, in parallel, we're doing pre-FEED studies. So the soonest that you would be able to sanction the project would be at the end of that 2-year appraisal program. Then you have to submit a development plan to the government and go through the approval process there. So the soonest you would be able to submit that plan would be at the end of the appraisal program. John B. Hess: As we pointed out before, it doesn't factor in -- assuming the investment would be attractive returns versus other opportunities we have, it doesn't factor in our 5-year production forecast. It's beyond that. So it's beyond 2017.

Your next question is from the line of John Herrlin, Societe Generale. John P. Herrlin - Societe Generale Cross Asset Research: Just a couple of quick ones for me. Greg, you didn't mention the China shale JV? Is there anything you can talk about with that? Gregory P. Hill: Yes, sure. We signed -- I was in China last week and signed a PSC for -- which covers about 200,000 gross acres in the Santanghu Basin in the northwest part of China. It's a phased program. And under this contract, we're going to invest about $25 million over 2 years to drill 2 vertical wells and one horizontal sidetrack. So a very small amount of money to kind of do a proof-of-concept. John P. Herrlin - Societe Generale Cross Asset Research: Okay. Any kind of update on Pony? Or still working on that? Gregory P. Hill: Yes. No, I think the partners are working towards a sanction pack. Early 2014 would be when we would anticipate a sanction decision. John P. Herrlin - Societe Generale Cross Asset Research: Okay. Regarding partnering with both Kurdistan and Ghana, are you looking for a carry or a heads-up deal? Or promote, basically? Gregory P. Hill: Yes. Obviously, we're looking for some form of carry. John P. Herrlin - Societe Generale Cross Asset Research: Okay. And last one from me. For the new slim-fasted Hess, approximately what will be ballpark on the headcount? Because obviously, you have a lot of people in retail. I was just curious. John B. Hess: Well, obviously, the retail would be out of the headcount. The exact type of numbers, we're working on and finalizing and not in a position to give you the final details on it yet, but it will be a significantly slimmer headcount because we're just going to be a pure play E&P, and we'll be right-sized to support that.

And at this time, ladies and gentlemen, as there are no further questions in the queue, this will conclude the second quarter 2013 Hess Corporation earnings conference call. They thank you for your participation, and you may now disconnect. Have a great rest of your day.