赫斯 (HES) 2014 Q3 法說會逐字稿

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. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. (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.

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's 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'll now turn the call over to John 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 three 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 the limits of our cash flow over the long-term, after continuing to return capital to our shareholders. We look forward to sharing our plans in more detail with you at our upcoming Investor Day on November 10th. 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 five years. We and our partner Console have a core acreage position in the webcast 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 is a 25% working interest and is the operator. Chevron, Statoil and Nexon 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 barrels 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 ask $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 in 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.

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 six 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 BSU 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 costs 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, seven 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 three 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 four 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 two-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 three new wells, which are planned to be brought on in the fourth quarter.

Companywide 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 the Shireen-1 well on the Dinarta Block earlier this month, following a two-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 3-D 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.

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 costs 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 $1.00 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) Ed Westlake, Credit Suisse.

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 cumes and overall recoveries higher. Is your strategy still going to be to try and focus on these, I guess, relatively simpler completions, and their giving you acceptable returns? Or are you going to go down the route of boosting the, I guess, the frac intensity, et cetera?

This is Greg. Currently, our standard design is 35 stages. And there's a lot of significant amount of data that supports this 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, you know, 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 are focused on drilling the highest return Bakken wells.

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?

Well, certainly, Stampede, first of all, is one of the largest undeveloped fields in the GOM. And project returns are expected to exceed our investment threshold, even in this lower price environment. And I think it's noteworthy that all four partners have sanctioned the project, with the final sanction coming in this week.

I do think the costs do have room. I mean, certainly, the Diamond rig contract that is tied to this project for two years -- seven string years in total -- I think set a new market benchmark for Deepwater rig rates.

I guess my question is, is that included in the $6 billion number? Or is that potentially optimization around it?

Yes, it is. It's included in the $6 billion number.

Okay. Thank you.

Doug Leggate, Bank of America.

I wonder if I could take two, 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 of 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 [kept down]. So what are your strategic thoughts around what you can do in Norway and whether you are optimistic that it gets better? And I've got a follow-up.

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's it going? Well, we've established regular multilevel executive engagements with BP management. In fact, John and I are flying to London tomorrow for a 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 is 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.

Greg, do you think you can ever get to topline capacity on it?

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.

Okay. Thank you. My follow-up is on the Bakken, as you'd 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 the latest 30-day rates were like. But so I'm guessing that the downspacing wells that you -- I think it 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 10th, 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 lowered oil pricing. And I guess what's behind my thinking is you're coming into this lowered oil price with a very robust balance sheet. So, would that be -- would you still look to accelerate activity? Or would you look to moderate to live within cash flow? And I'll leave it there. Thank you.

Okay. Well, just to kind of give everyone an update on the downspacing pilots, just recall in 2014, we have two well-designed pilots going on. We have 17 well pads with 13 wells per DSU, and we have two 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.

All right. It was worth a try. Thanks.

Evan Calio, Morgan Stanley.

Maybe somewhat of a follow-up to Doug's comment, if I understood -- did I understand your opening comments, John, that you'd target CapEx to be within cash flow for 2015? Or does it -- what does kind of longer-term mean? There's some view of normal cash flow and you'd be willing to outspend, if we find ourselves at a lower oil price scenario, given your cash and balance sheet positions?

Very good question. Look, with our focus balance 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 are 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 with a pretty comprehensive update on November 10th.

Great. Looking forward to that. But maybe a follow-up on that return comment. Hess is moving against a trend offshore with Stampede FID, while I know it's been a long time coming. I mean, can you discuss how you compare and analyze your returns or payback when making an allocation for a new offshore project versus your unconventional resource opportunity?

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.

Okay. 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 component there, whether it's topside capacity or otherwise? Or is that all leased? And I'll leave it there.

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.

Is it a lease design? Is that what's envisioned?

No -- Stampede, no. It's not a leased design. This is being built -- as us as the operator, we are building that facility along with our partners.

Got it. Thank you.

Ryan Todd, Deutsche Bank.

A question on the Utica. The Utica had 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?

Yes. Thanks, Ryan. It was really a combination of both. A little bit 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 are drilling 8,800-foot laterals now, which has been the longest ones to date, at least in the Utica. So that contributed to the strong well results.

You know, regarding future plans for the Utica, we are going to provide, again, a full update on the results and our forward plans for the Utica at Investor Day in November.

Great. Thanks. 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 [plus] 80 to 90 wells in fourth-quarter. How many rigs are you running right now? And I guess 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?

Yes, we're on track for that. We are running 17 rigs currently. And as we said in our opening remarks, we're going to have six 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 are on pace to do so.

Great. Thanks a lot. I'll leave it there.

Guy Baber, Simmons.

Thanks for taking my question. A 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 then 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 is positioned in a way to take advantage of those opportunities? And does that think -- or does that impact the way you think about the buyback at all over the next quarters?

Yes, there were a number of questions there. First of all, we are always going to be disciplined in our investments to invest for returns. So, we are 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 a 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 an 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 are going to be disciplined in our approach there.

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.

Yes, so thank you for that, Guy. You know, 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.

Okay, makes sense. Thanks.

Paul Cheng, Barclays.

Several hopefully pretty short questions. Greg, in one hand, can you remind us -- or maybe this is for Rielly -- that when the cash tax is going to resume? Is it 2017 or 2018?

Yes. So the guidance that we've given is that we are not paying cash taxes in Norway through 2017.

Okay, so 2018 will resume. And that earlier, that when you were talking about a 15% project hurdle rate, just wanted to clarify that. Is it based on $100 Brent or based on $85 Brent?

Well, you know, our old standard was $100 Brent. But as we allocate capital now, we are going to be disciplined in how we invest. So it would have to meet it at the $85 hurdle.

Okay. So that actually is a change in some ways, I guess, it's become tougher or that you raised the bar from (multiple speakers) $100 now to $85 Brent?

(multiple speakers) Yes. You have to deal with the current reality of where the oil markets are.

Okay. That's good. And that -- John, this is for Rielly, that for -- at the end of the third quarter, from an inventory standpoint, I presume that you are overlift -- any idea to how much you are overlift?

So, for the fourth quarter, just for guidance going forward on the fourth quarter, we don't see basically an under or overlift; a pretty balanced sales volumes 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.

Okay, great. And that the -- in Utica, Greg, are you running a three-rig program right now?

Yes, we are, Paul.

And that -- how many wells is actually in production to contribute 11,000 barrels per day?

Let's see. The online production well count for the Utica in the third quarter was four 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.

28 wells drilled. But how many of them are actually in production?

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.

Okay. And that do you have a rough split between oil condensate NGL and natural gas in Utica?

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.

Okay. Great. And John, can you comment about the press release, talking about HOVENSA sales and that the $1.6 billion number cited by the government? Does that mean that when you finally decided, should we assume that we will receive in the upfront payment from that sales?

We are in the third 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.

Okay. A final one. For 2014 exploration expense, based on your fourth-quarter estimate, is 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?

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 are 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 are right in line with the guidance that we have sent out.

Okay, thank you.

Paul Sankey, Wolfe Research.

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? Thanks.

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 are drilling some of the lowest-cost/higher-productive wells, so our breakeven is lower. You know, we have some of the best acreage.

We are certainly going to be focused on investing for returns, as opposed to growth for growth sake. So we are 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 10th.

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? Thanks.

Yes, Paul. So the -- given our infrastructure position in the Bakken, we don't anticipate any impacts due to the NDIC flaring rules. So we are well-positioned to continuously reduce our flaring on a go-forward basis.

And then volumes from the Basin, given the lower oil price environment and in terms of their infrastructure?

No, we're not seeing major volume impacts as of right now.

Great. Thanks very much.

Roger Read, Wells Fargo.

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 two weeks. But looking at the North Sea, which has historically been considered a relatively high-cost area, and I recognize Valhall is 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?

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 us. 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 are 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.

Okay. So quite a lot of headroom on both of those, then?

Yes.

And reasonable to presume it makes sense to continue to invest in them, not just to operate them, at sort of an $80 to $90 environment?

Yes. I mean it is -- generally, as 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.

Okay. And last question I have is just really two 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 give you confidence to go back into Kurdistan and restart the exploration well there after the two-month hiatus?

Yes. In terms of Libya, look. There is still significant political unrest in the country and a lot of stability, but the oil is flowing. And so far, from our Waha concession, we have sold three cargoes of a cedar 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 is a lot more secure today after the United States and allies have stood by the Kurds. And security is the number one 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.

Okay, thank you.

Jeffrey Campbell, Tuohy Brothers.

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?

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-year next year with the government. So, we are actively evaluating the results of the appraisal plan. We've also got some new 3-D seismic that we are 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.

But at least at this time, you can say that the drilling portion of it is done, pending these further developments?

Yes. Yes.

Okay, great. Thank you.

Pavel Molchanov, Raymond James.

Thanks for taking the question. 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?

No. We haven't given one. And we expect to reach TD in that well in Q1 of 2015.

Okay. Okay. Fair enough. And then on Libya, you mentioned the three 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?

No. We're not in a position to comment on that.

All right. Fair enough. Thanks.

Faisel Khan, Citigroup. (Operator Instructions)

Okay, thanks. Appreciate it. Sorry about that. Just wanted to understand the Supplement that you guys put out on the Utica JV well test. I just want 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 just want to make sure that that sort of is coming through into the fourth quarter as well.

Yes, those are the third-quarter results from the wells actually. And those are our wells. In addition, CONSOL also tested seven wells from their operated pads. But these are our wells drilled, and completed and tested in the quarter.

Okay. I mean, these are pretty huge results. I mean, what's the game plan in terms of sort of moving some of this gas and liquids out? I mean, a 4,000 BOE test is still pretty substantial. Are these -- what's a well like that doing a month later or two months later?

You know, 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 are going in the future with it.

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?

It will have an LLS typing -- LLS relationship in terms of pricing.

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 have been a number of pipeline projects announced. I just want to understand sort of what your game plan is for those volumes in the future.

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.

Okay. The 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?

So -- just so you know, we have not disclosed the terms, the proceeds associated with this sale, because it is confidential. And from a general aspect, it's not going to be material to our financial statements.

Okay, fair enough. Thanks for the time. I appreciate it.

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