赫斯 (HES) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the 2011 third-quarter Hess Corporation earnings conference call. My name is Modesta and I will be your coordinator for today. At this time all participants are in 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 conference over to your host for today, Mr. Jay Wilson, Vice President Investor Relations. Please proceed, sir.

Thank you, Modesta. 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.

With me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President Worldwide Exploration and Production; and John Reilly, 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 make a few brief comments after which John Reilly will review our financial results.

Net income for the third quarter of 2011 was $298 million versus $1.154 billion a year ago. Our third-quarter results included charges of $140 million for abandonment liabilities primarily in the UK North Sea and $44 million for an increase in the UK supplemental petroleum tax rate. These charges were partially offset by a $103 million gain from the sale of Hess' interest in the Snorre Field in Norway and the Cook Field in the United Kingdom.

Also, last year's third-quarter results included a net nonrecurring gain of $725 million. Excluding these adjustments earnings for the third quarter of 2011 were $379 million versus $429 million a year ago.

Exploration and production reported net income of $422 million. Crude oil and natural gas production averaged 344,000 barrels of oil equivalent per day which was 17% below the year-ago period. Aside from the sale of mature UK natural gas assets earlier in the year, most of the year-over-year production decline was due to several short-term setbacks.

We are pleased to say that most of these issues are being resolved and that, with the exception of Libya, we are in the process of recovering lost volumes.

In Norway a fire at the outside operated Valhall Field in July resulted in the field being shut in for more than two months, negatively impacting third-quarter production by approximately 20,000 barrels of oil equivalent per day. Operations resumed September 17 and net production is currently averaging more than 30,000 barrels of oil equivalent per day.

In the Gulf of Mexico, the Llano #3 well was producing at a net rate of approximately 10,000 barrels of oil equivalent per day prior to being shut in due to mechanical issues in the first quarter of this year. The operator plans to perform at a workover and restore production in the first half of 2012.

In Libya approximately 23,000 barrels of oil equivalent per day of net production remain shut in due to civil unrest. We cannot estimate when production will resume until security returns to the country.

With regard to the Bakken, net production averaged 32,000 barrels of oil equivalent per day in the third quarter, up from 25,000 barrels of oil equivalent per day in the second quarter. Currently net production from the Bakken is approximately 39,000 barrels of oil equivalent per day.

As a result of the increased acreage position from last year's acquisitions and positive well results year to date, we forecast net production from the Bakken will increase to 60,000 barrels of oil equivalent per day in 2012 and to 120,000 barrels of oil equivalent per day in 2015.

In September we announced the acquisition of 185,000 net acres in the emerging Utica Shale play in Eastern Ohio principally two separate transactions. We entered into an agreement with CONSOL Energy, which closed last week, to acquire a 50% interest in nearly 200,000 acres for aggregate payments of $593 million over five years. We also acquired Marquette Exploration and other leasehold interest which added another 85,000 net acres at a cost of approximately $750 million.

With these transactions we have built a strategic acreage position in the Utica Shales, strengthening our portfolio of high quality unconventional assets, leveraging our operating expertise and creating significant potential for future growth in reserves and production. Appraisal activities on this acreage are planned to commence in the fourth quarter.

Yesterday we also announced that we will proceed with the development of the Hess operated Tubular Bells Field in Mississippi Canyon area of the deepwater Gulf of Mexico. The plan calls for three subsea production wells and two water injection wells tied back to a third-party owned spar production facility.

Drilling is scheduled to begin in 2012 and initial production is expected in 2014 subject to the receipt of necessary government permits. Annual net production is expected to peak at approximately 25,000 barrels of oil equivalent per day and net recoverable resources are estimated at more than 65 million barrels of oil equivalent.

The net cost of the development is expected to be approximately $1.3 billion. Following government approval of the recent assignment of BP's interest, Hess will hold a 57.14% interest and Chevron will hold the remaining 42.86% interest.

With regard to deepwater exploration, the Stena DrillMAX drill ship has been contracted and we currently plan to drill a minimum of three exploration wells on our 90% owned Deepwater Tano/Cape Three Points Block in Ghana commencing in the first quarter of 2012.

In Indonesia we spud the Andalan well on the Semai V Block July 12. We are currently drilling below 17,000 feet and expect to reach total depth of about 22,000 feet during the fourth quarter. Hess has a 100% working interest in the block.

In Brunei the operator of Block CA-1, in which Hess has a 13.5% interest, spud the Julong Centre well on September 1. The well is expected to reach total depth in the fourth quarter and additional wells are planned in 2012.

Turning to marketing and refining, we reported a loss of $23 million for the third quarter of 2011. Our share of the HOVENSA refinery's losses was $36 million which was an improvement over the year-ago quarter as a result of stronger gasoline into distillate crack spreads. While the refinery effectively broke even in July and August, a significant drop in a gasoline refining margins in September contributed to the third-quarter loss.

Marketing earnings of $41 million were comparable to last year's third quarter. In retail marketing gasoline volumes on a per site basis and convenience store sales were both down nearly 2% reflecting the weak economy. In energy marketing electricity sales volumes were up versus the year-ago quarter while natural gas and fuel oil sales volumes were relatively flat.

Capital and exploratory expenditures in the first nine months of 2011 were approximately $5.2 billion. For the full year our capital and exploratory expenditures forecast has been increased to $7.2 billion from $6.2 billion. The acquisitions of acreage in the Utica and an additional 4% interest in the Hess operated South Arne Field in the Danish sector of the North Sea account for the increase.

We are excited to have acquired a strategic position in the emerging Utica Shale play which strengthens our portfolio of unconventional resources. We remain committed to maintaining a strong balance sheet to fund our future investment opportunities and profitably grow our reserves and production. I will now turn the call over to John Reilly.

Thanks, John. Hello, everyone. In my remarks today I will compare third-quarter 2011 results to the second quarter. The Corporation generated consolidated net income of $298 million in the third quarter of 2011 compared with $607 million in the second quarter. The third-quarter results included net after-tax charges of $81 million from items affecting comparability of earnings between periods.

Turning to exploration and production. Exploration and production had income of $422 million in the third quarter of 2011 compared with $747 million in the second quarter. Third-quarter results included several items affecting the comparability of earnings between periods that were described earlier by John Hess. Excluding these items the changes in the after-tax components of earnings are as follows.

Lower sales volumes decreased earnings by $171 million; lower selling prices decreased earnings by $98 million; lower exploration expense increased earnings by $33 million; higher operating costs decreased income by $25 million; all other items net to an increase in earnings of $17 million for an overall decrease in third-quarter adjusted earnings of $244 million.

Our E&P operations were under-lifted in the quarter compared with production resulting in decreased after-tax income of approximately $30 million. Our E&P total production unit costs were approximately $39.35 per barrel in the third quarter. We estimate our total production unit costs will be approximately $39 per barrel in the fourth quarter.

The charge of $44 million for the additional 12% supplementary tax in the United Kingdom includes a provision of approximately $15 million representing the incremental tax on earnings from the effective date of March 24, 2011 through the end of the second quarter and a charge of $29 million to increase the United Kingdom deferred tax liabilities on the balance sheet.

Excluding the impact of the items affecting comparability of earnings between periods, the E&P effective income tax rate was 27% for the third quarter, primarily reflecting the mix of earnings, and 37% for the first nine months of 2011.

Turning to marketing and refining. Marketing and refining generated a loss of $23 million in the third quarter of 2011 compared with a loss of $39 million in the second quarter. Refining losses were $38 million in the third quarter of 2011 compared with a loss of $44 million in the second quarter.

The Corporation's losses from its equity investment in HOVENSA were $36 million in the third quarter of 2011 compared with $49 million in the second quarter. Port Reading broke even in the third quarter of 2011, down from earnings of $5 million in the second quarter.

Marketing earnings were $41 million in the third quarter of 2011, an increase from $28 million in the second quarter principally reflecting higher margins and energy marketing. Trading activities generated a loss of $26 million in the third quarter of 2011 compared with a loss of $23 million in the second quarter.

Turning to corporate and interest. Net corporate expenses were $44 million in the third quarter of 2011 compared with $42 million in the second quarter. After-tax interest expense was $57 million in the third quarter of 2011 compared with $59 million in the second quarter.

Turning to cash flow. Net cash provided by operating activities in the third quarter, including a decrease of $11 million from changes in working capital, was $1.022 billion. Capital expenditures were $2.434 billion. Proceeds from asset sales were $131 million. All other items amounted to a decrease in cash of $86 million resulting in a net decrease in cash and cash equivalents in the third quarter of $1.367 billion.

We had $827 million of cash and cash equivalents at September 30, 2011 and $1.608 billion at December 31, 2010. Total debt was $5.592 billion at September 30, 2011 and $5.583 billion at December 31, 2010. The Corporation's debt to capitalization ratio at September 30, 2011 was 22.8% compared with 24.9% at the end of 2010.

This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions). Ed Westlake, Credit Suisse.

Obviously a disrupted quarter with all of what's been going on, but hopefully a bounce back in Q4. But I wanted to touch on the Bakken. Can you give a latest update on where well costs are trading given concerns over cost inflation in that area?

Yes, thanks, Ed. Let me first just make a couple of remarks about the Bakken. First of all, we're back on track in the Bakken following a tough weather-related start to the year. As John mentioned in his opening remarks, we're currently at about 39,000 barrels a day and up 28% or 7,000 barrels a day on average Q on Q.

We're adding an additional frac crew in the next couple of weeks and expect to reduce our backlog of wells while awaiting completion over the next nine months. And assuming normal weather through the winter we feel very confident about achieving not only our production forecast this year but also our 60,000 barrels a day in 2012.

Regarding your question, the cost for a 38 stage frac, a good number to use is $10 million (multiple speakers).

Okay, thanks very much. And just coming back to the overall capital spend, obviously the Bakken, you're spending a lot there. You've got some wells in Ghana and you've just launched Tubular Bells. You gave the guidance of sort of $6 billion to $7 billion as you get closer to next year. Where should we be thinking about in terms of -- within that range?

Yes, we're going to give that update no later than the fourth-quarter conference call in January. We're finalizing those numbers now. I think the important thing to recall both for this year and next year is that we're in a long-term business that obviously is commodity-based, volatile and cyclical.

Having said that, our strategy remains to grow our reserves in production on a profitable and sustainable basis and the majority of our funding for that will come from internal cash flow and selected asset sales. In fact this year we've had asset sales in the range -- receiving proceeds of about $490 million.

So you feel comfortable about your liquidity position?

Yes, I do.

Okay, thank you.

Paul Sankey, Deutsche Bank.

Just to follow up on your last response that you've I think said that you'll spend $6 billion to $7 billion next year. I assume you're still in that guidance range. And that in the past said you'll live within your means, although you had mentioned the possibility of raising debt.

Could you just update us really on whether you expect to meet next year's CapEx (inaudible) through -- more likely through asset sales or through debt and whether or not I'm on the right number for CapEx? Thanks.

Yes, the CapEx -- again, we'll give that guidance in -- no later than the fourth-quarter call in January. The majority of our funding for our program next year will come from internal cash flow and some selected asset sales.

Can you say more about what you might consider reducing? I mean it obviously doesn't feel like it's going to be the Bakken, but can you talk a little bit about where you're really wanting to push your focus, John?

Well, you know in the last couple years we've increased our exposure, happily so, to unconventionals. About 40% of our spending now is on unconventionals. It's a more balanced approach, provides lower risk growth to our future production and earnings. And that balanced approach between the unconventionals and conventionals -- that balance should continue in the future.

Okay, so we should think about you as kind of 50-50 unconventional international?

That's pretty close.

And then finally from me on refining -- you mentioned it was a margin story, the breakeven in July/August went into the severe September situation. Is it correct to characterize it as an asset event that's really subject to margin vagaries or are there more operational and strategic actions you can take to improve performance there?

Yes, as you know and recall that we took steps in the last year in our joint venture to downsize the refinery, to increase the margin per barrel and also take some cost out of the business, that's all been successful. I think the benefits of that we certainly saw at the beginning of the third quarter.

But what happened were really two things -- gasoline margins came down in September, but also the front-end of the crude market came up and so margins were squeezed there. I think the refinery is in a more competitive position, but it still has some competitive issues in its higher fuel cost versus a Gulf Coast refinery that has the advantage of natural gas as a feedstock. And that's an issue that we still look at.

And as I've said before, it's a very small piece of our portfolio, we want it to run reliably and securely, safely. And we're going to continue to do all we can to optimize its financial performance. And we'll always consider strategic options, but given the current environment there are not that many and we also have a partner that we also have to work with in that regard.

I understand, John. And within that segment somewhat the trading loss that you had this quarter Q3, was there anything unusual or one-off about that or what went wrong there?

No, nothing unusual. As you know, it was a difficult trading environment in the third quarter. The business, it's a small part of our portfolio, it's been good to us. It's been profitable 13 out of the last 14 years prior to this one. It took action, it did reduce positions and reduces its risk through the quarter. But nothing unusual there.

Okay. Thank you, guys.

Evan Calio, Morgan Stanley.

Some exciting changes in your portfolio. Let me ask a question and not to beat a dead horse, but just a bit of a follow-up on the spending and as you think about a downside commodity scenario. I know, look, the market is somewhat focused on a crude deck that's south of $30.

From the strip I know -- I remember, John, in 2009 you raised the potential of an equity offering in a much lower and different environment than we're in today. But how do you look at your combination of assets spending commit and balance sheet, as I know you've extended $4 billion plus in revolver, as distinguished versus '09 and support activity even if we're in a period of lower commodity price? How do you think about your flexibility versus that period of time and portfolio opportunities?

Well, I think it's important to know that we remain committed to keeping a solid investment grade rating. We also remain committed to having a very strong balance sheet that John Reilly talked about before. We have available to us a $4 billion revolving credit facility that is undrawn. So we feel we have plenty of liquidity to fund our capital spend going forward through the cycle between internal cash flow, selected asset sales and liquidity facilities that we have on hand.

Feeling better than '09 texturally if you think about it?

I wouldn't want to -- hypothesis. '09 was a much more difficult environment.

Good, now we agree. Maybe a different question on exploration and walk through the exploration portfolio a bit. I know you gave an update on Semai V in terms of drilling depth. I kind of missed that, but is that -- are we on track to hear results within weeks, is that the general take away there?

And then I know you had discussed, I think, two other prospects in that block that we should expect in 2012. And maybe you could either dimension those in size or discuss -- I believe they're different play types than the current structure. So it's not a path dependent exploration portfolio there in Indonesia.

Yes, so just to reiterate some of the comments in John's opening remarks. The well spud in July, we're currently drilling at 17,000 feet right now, PD is about another 5,000 feet down. So this is a tight well, so we're not going to reveal any interim details on the well, Evan, until the well is done.

Regarding your question about the block, it's actually a three well commitment on the block. And until we get this well done we won't determine where those next wells are going to be.

Okay. But you still anticipate two other prospects in 2012 on that commitment?

Yes, we can have two more wells that are commitments on the block following this one. Now yet to be determined what those wells are going to be or where or what depth or anything like that, we really want to get this well done first.

Okay, so you're trading that rig back-and-forth with Murphy in Indonesia, is that right?

We're finalizing all the rig strategy as we speak.

Okay. Any exploration in the (inaudible) a reasonable acreage position there in 2012?

Yes, the plans are we've got two exploration wells currently in the permitting process in various phases, (inaudible) and [Huron] in the exploration phase. Anticipating bringing the Stena Forth back into the Gulf of Mexico early 2012, most likely begin drilling (inaudible) in 2012.

Okay, so begin drilling in the second half, is that --?

No, early 2012, still finalizing our plans, but early 2012 is when we'll start drilling in the Gulf of Mexico again.

Okay. And then on Ghana, just to kind of finish that out. You mentioned a minimum of three. Can you give us a high level, and is that also -- is that path dependent of other wells or rig dependent? How should we think about that potential range there?

Yes, so we have committed to a rig and that's the Stena DrillMAX. We've contracted for five firm wells on that rig. Current plant with Ghana, which again we're continuing to work with the government, is to drill a minimum of three wells.

And I'll just remind everyone, we're really testing three different play types on the block in Ghana, one is a deeper Cretaceous structure that sits below Paradise, the next one is a look-alike structural play near Paradise, and then the third one is test -- one of the many stratigraphic channel sand plays in the western part of the block. So with these three well fracturing in a test, three different play types and they're exploration wells.

Good, I appreciate it. Thanks for taking my questions.

Doug Leggate, Bank of America-Merrill Lynch.

I'm going to try a few quick ones if I may. First of all, John or Greg, can you give us an update on your drilling plans in the Utica?

Yes, sure, Doug. As John mentioned in his opening remarks, we plan to begin appraisal activities in the fourth quarter. That will be the first thing that we will do is complete the Marquette well. And then we're working with our partner, CONSOL, on starting drilling activities on some of that acreage. Next year we'll be running three rigs in the Utica.

Great. And you've described this and my recollection is this is your second beachhead in unconventional shale after the Bakken. So I guess getting into the discussion about cash flow and asset sales and all the rest of it, a $3,000 per acre entry to the Eagle Ford given where those acreage positions are selling for right now. Could you describe the Eagle Ford as core or is that perhaps surplus requirements now? And maybe the same question around Australia given your growth options in North America.

Yes, I think, Doug, as you know, the Eagle Ford, our focus right now is on delineating the acreage we have and we're pleased with the results to date. So we've made no further decisions other than just staying focused on delineating what we have.

Similar story in Australia. I mean we've got some appraisal work left to do in Australia. As you know, we've so far flow tested five wells with results coming in as expected and we plan to drill and test three additional wells by mid-2012, we've got a rig coming back at the end of the year.

And so again, we're just in the appraisal understanding mode. Also in parallel, as you know, we're in commercial discussions with three liquefaction (inaudible) which I mentioned before multiple times on the call and really trying to bring all these things together so that we can make an informed decision sometime in 2012 about next steps for the block.

[Fantastic]. Let me just jump back to the Eagle Ford just to kind of follow up on it. Are you actively expanding your acreage position or are you kind of set pat with what you've got right now?

I think we're being opportunistic. The pricing is pretty high in the Eagle Ford still. As we see opportunistic ways to fill in our acreage around this we'll do that, but only if we believe it makes money.

Thanks. And the last one from me, this one is maybe for John Reilly. But again, the focus seems to be on CapEx and cash flow next year, John, but you're obviously stepping up capital expenditure on unconventional drilling of lower 48 capital overall. At least in my numbers that's going to leave you with a fairly significant deferred tax potential asset.

Can you help us quantify, my understanding is you can write off 70% of intangible drilling costs as an integrated oil company. Can you maybe just put some numbers around that, because I'm guessing that's a fairly big cash offset in terms of cash flow in 2012. And I'll leave it at that, thanks.

What you said is correct, there is -- you can take a 70% deduction on our intangible drilling costs as an integrated company. Now I think as John Hess said earlier, we're still working out our capital budget for 2012 and at this point I couldn't give you specific numbers on the amount from an unconventional standpoint that would become intangible drilling costs. It's really kind of detailed information from a tax standpoint that we really wouldn't provide.

Well, do you think it would -- would there be a meaningful cash tax number, John, at least in -- I'm not looking for a hard number, but notionally are we thinking about it the right way?

You are thinking about it the right way. So again, from an income statement standpoint it makes no difference, you're going to still have a federal and state tax provision that's at the statutory rate. But it does provide cash tax relief early on and then later on you'll end up paying those cash taxes.

Great, I'll leave it at that. Thank you.

Paul Cheng, Barclays Capital.

Maybe this is -- the first one for Greg. Greg, on Ghana, when are you going to drill the first well?

Well, it will be -- again, we're still in negotiations with the government on various things. But the plan is to get a rig in there early in 2012. So first quarter is when we anticipate spudding.

Do you think that -- I mean that the first well was quite a long time that before you finished it. With that learning how long do you think that the second will you're going to drill?

All these wells, assuming you just drill it and don't do a lot of testing and things like that, these are 60- to 80-day wells.

But I mean are you going to do some testing?

No, no, yes, we'll just have to wait until we get into the well, Paul, and see what we have. There's no plans to test Paradise, but future wells, we'll just wait and see what happens.

And after the first appraisal well in Paradise, will you be in a position that -- if that's successful will you be in a position that you perhaps disclose a little bit more in terms of the size of the range of the resource and also the Oil & Gas mix?

Yes. So let me clarify, the next three wells we're drilling are actually exploration wells.

Oh, so you're not going to do the appraisal well?

Not an appraisal well, right. So we're testing one look-alike to Paradise which is nearby, another structural test. We're testing something below Paradise that's a lower Cretaceous structure, large structure. And then we're testing a third play type which is a stratigraphic channel test. So those are three exploration wells.

I see. And on the fourth quarter -- this is for John Reilly. John, you're talking about total unit costs and E&P expense from third quarter at $39.35 to about $39, I would think that the job would be a little bit more given that the return of the [Waha] and also the maintenance season in UK is over and also that Bakken will continue to rise. Is there any reason that why the unit cost is not going to drop more?

You're right. Your answer are directionally right on the cash cost side. So as production will be coming up our cash cost will be coming down from the third quarter. Our DD&A in the fourth quarter, as you probably followed us, typically our DD&A rises throughout the year as we add additional CapEx onto the program and in the reserve -- more reserve bookings happening at the end of the year. So, one, you have that reason.

The other point is we are in an investment mode and a lot of good things are going on. So like take the Bakken, we've got -- we're drilling right now on all acquired acreage right now, it's not on our legacy position. So we're in the AOG and Tracker acreage. So that has some acquisition cost on it. We're making a lot of infrastructure investment and we moved to the 38 stage frac design.

So I mean a lot of good things going on that will provide very good returns for us for years to come. But those investments, what happens is with reserve bookings, they always like the investment dollar. So the reserve bookings will begin to come later on in fields like same thing in Valhall. So we'll begin to see the DD&A rate come down out in the future, but we will have a pickup in the DD&A rate in the fourth quarter.

I see. And going back to Greg. Greg, if we're looking at your runway of your exploration expense, this quarter is a little bit lower than usual. But you're probably talking about somewhere in the $900 million to $1 billion a year in exploration expense. And that's equal to roughly over say $6 to $7 per barrel of your production.

Is that the kind of number that you think on the long haul is a reasonable level? Or that it -- that over the long haul that you should target a lower per barrel production in terms of exploration expense?

Yes, Paul, so again, in 2012 -- we're in the middle of our budget cycle, so we haven't finalized any of those numbers at all for next year. I would like to think that as long as we can generate excellent prospects that we will continue with our organic drill bit led strategy. It's really going to depend (multiple speakers).

You don't think that you are spending too much money on the exploration side?

If we have opportunities to drill we will drill the opportunities that we have, yes.

Two final questions from me. One in the Eagle Ford, Greg, you provided some well data for Bakken. Can you give us the well data in terms of production (inaudible) for the well that currently is in production and also some of the IP and well cost? And secondly then for Bakken, do you believe that you have seen the plateau in terms of the well cost or that you're still seeing a lot of inflation pressure?

So, let me address the Bakken first. As I mentioned, the cost for a 38 stage, a good number to assume is $10 million. Looking forward we're optimistic that we can continue to drop that well cost through our lean manufacturing, further application of lean manufacturing and also whether or not you do sliding sleeve or plug and perf. We're pushing the technology on sliding sleeve to get greater and greater numbers of sliding sleeves in the well. So those are opportunities we see to continue to drop that well cost.

Turning to the Eagle Ford, just remind everyone that we've drilled 22 wells thus far, eight wells have been completed and brought on production and on average the 30-day IP rate of these wells are about 500 barrels per day of which about 60% is liquids. Well costs are running about $10 million each for a 15 to 21 stage frac design. However, we expect this cost to come down as we employ many of our Bakken operating practices to the Eagle Ford. So still early days in the drilling cycle on the Eagle Ford.

Thank you.

Arjun Murti, Goldman Sachs.

Just hoping for an update on the status of some of the Bakken infrastructure projects, most notably the rail capacity, how that project is progressing and timing of ramp-up? That is the key one that -- maybe I'll stop there for the question.

Yes, I think on the recall there was kind of two major infrastructure projects. One is the expansion of the Tioga gas plant, which is on track. That will be complete at the end of 2012. The Tioga rail expansion is nearing completion, and we will be ready to ship our first trains in early 2012.

And what is the initial capacity on the rail expansion?

It will be -- we've got nine train car sets, and that gives us about a 54,000 barrel a day capacity. Now, obviously, in the future if need be, we can expand that with additional train sets.

And the 54,000, once it starts up, it's up. We shouldn't think in terms of some ramp-up to 54,000. It's an on or off type of deal.

No, it will have some flexibility to deal with our own production flexibility. In fact, we're probably going to send a couple of railcars to de-bottleneck that facility in the fourth quarter.

That's fantastic. I don't think I missed it, any update on Australia LNG, where that stands right now?

No, I think as I mentioned earlier, we've taken a drilling break and that is really just waiting on the rig to come back out of the shipyard after recertification. Expect to begin drilling very late this year; drill three more appraisal wells and do some testing, and try and be complete with that program say mid 2012 on Australia.

In parallel, we're continuing all the commercial discussions with Pluto, with Wheatstone and with Northwest Shell, trying to figure out the optimum commercial route for the gas.

That's fantastic. Thank you so much.

Mark Gilman, The Benchmark Company.

I had a couple things. I was wondering whether or not you've seen any interest to date in the farm-down being offered on BM-S-22?

You know, that data room has just been opened, Mark. So really can't comment on how many people have been through.

Okay. Greg or John Reilly, perhaps you might be able to flesh out a little bit the circumstances surrounding the quote unquote assignment of BP's interest in Tubular Bells?

Yes, I think the terms of that assignment are confidential, Mark. Suffice to say that we've -- Chevron and us have split BP's interest.

For consideration or not, Greg?

Terms are confidential.

All right. Let me try something else. On the Bakken, the oil/gas split pretty much remaining constant?

Yes, it is.

So 90% plus liquids?

Yes, it is.

Last one for me, for John Hess. I noticed that the SEC utilization rate at HOVENSA continues to be low, John, Mid-70s, which has kind of been the range. Any issues there that perhaps you can address that might yield better performance going forward?

It's more an economic issue, Mark, than anything else. Some of the operating problems we've had at HOVENSA in the past -- I think they've made a lot of improvements in terms of reliability, operating excellence. So it's more an economics driven issue.

So you've been cutting it back basically?

Yes.

Okay, thanks, guys.

Yes, Mark, I just wanted to clarify. The Bakken ranges between 85% and 90% liquids.

John Herrlin, Societe Generale.

With the Utica Shale, Greg, what kind of spending rate do you think you'll have on kind of a quarterly basis or an ongoing basis?

Well, we're still trying to finalize that with our CONSOL. As I mentioned, we plan to ramp up to three rigs in the Utica in 2012, but we're finalizing all those estimates with our partner right now.

Hopefully for the fourth-quarter call we can give more definition on that.

Okay, thanks. Regarding the fourth quarter you are drilling a lot of -- you should TD a bunch of -- or at least two deep water wells. What kind of dry hole cost exposure is that?

We typically just don't -- we don't give those well cost data out. You can figure out from the rigs that are being utilized, as John Hess and Greg said earlier, we spud this in July, so from those days through -- obviously through September 30. And then we'll tell you when the final well comes in in the fourth quarter. It will be a significant amount, but we don't give out -- that on individual wells.

Okay, that's fine. With respect to the Bakken wells, how much are the fracs now running as a percentage of total well cost, 55% or 60%, how large are they?

Yes, I think 60% is a pretty good number.

With Ghana, when will you delineate Paradise?

Again, our focus in 2012 is getting some additional exploration wells in the ground, so that is our primary focus as agreed to with the government. We're still in the exploration phase right now on the block.

Okay. Still having partners or potential partners call up?

Absolutely, there's very high interest in this block. We've had a data room open and have had a number of partners through the data room.

Last one for me. Anything on Peru?

Nothing really noteworthy to report yet on Peru.

Okay, that's it for me. Thank you.

(Operator Instructions). Sven del Pozzo, IHS Herold.

Again on the Bakken, around what time in 2012 do you think that you'll feel that you'll have your leases secure, the ones that you most recently acquired with Tracker and American so that you'll be able to devote more pad -- do more pad drilling?

Yes, I think we'll largely have the majority of that acreage held by production by the end of 2012 with some spillover into 2013.

Okay. And again on the Bakken, do you have any plans to explore any of the deeper Three Forks formations?

Well, as you know, when we were doing the dual laterals in the pad drilling we were drilling both Bakken and Three Forks wells. In the acreage that we've acquired we've drilled some Three Forks wells as well. So it will be part of our long-term development strategy.

Oh, pardon me; I didn't explain myself properly. I believe there are actually some even deeper Three Forks formations than the ones that you've been developing thus far?

Right now we're not looking at those, we're just focused on the conventional Three Forks, I'll call it, and the Bakken.

Okay. And again, following up on the 60% liquids content in the Eagle Ford, are we talking condensate or black oil?

Both, but primarily condensate.

Okay. And what kind of an NGL proportion of the total hydrocarbon split should I consider -- or should I use?

Well, it's a bit premature because, again, we're continuing to delineate that acreage.

Okay. And this is more of an accounting question on the reporting for the North Sea. Oil price realizations in the third quarter look like something like $65. Just wondering why in the second quarter they were $85. How do I reconcile those two numbers?

It's a good question. In the third quarter with some of our North Sea maintenance we had a significant under-lift of barrels in the UK. And then you also know in Norway, Valhall -- we had the fire, so we had less sales volumes there as well.

So what that means is that our Russia production became a much higher part of that European production. And therefore that Russia, while profitable, has a lower price realization. And so that's what dropped the oil realization down. You should just expect our oil realization to go back to normal in the fourth quarter.

Okay. And at Valhall, did the fire pose -- does it have any implications for the long-term redevelopment program at Valhall?

No, there's no implications whatsoever for the long-term redevelopment.

Okay, and that's supposed to hit 75,000 Boe a day net yet to Hess? And I was wondering what time frame that I should consider for that?

Well, I think we continue to work with the operator to march our way to 75,000 barrels a day within five years after the completion of the redevelopment.

Okay, and this is my last question. I might have missed this during the comments. Working capital component of your operating cash flow in the third quarter?

It was a decrease to our cash flow of $11 million.

Okay, thank you.

Robert Kessler, Tudor, Pickering, Holt & Company.

A few more questions on the Bakken, if you don't mind. Greg, you mentioned adding a new frac crew to help handle the -- reduce your inventory of drillbit uncompleted wells. Can you give us a quantification of the number of wells that you've got sitting in a drillbit uncompleted status?

Yes, I think as we mentioned on last quarter's call we had around 70 wells in our backlog. That number has remained constant and that's why we're adding the additional frac crew.

Where do you think that will gravitate down towards? I mean could you get that down near zero? Is there always going to be an extra inventory of [ducks] (multiple speakers)?

I mean, there will always be a backlog because it's part of lean manufacturing; you always have a certain number of batch jobs in your queue. But we believe we can work down the majority of that backlog with that additional frac crew over the next six to nine months.

Okay, that's great. And then also, thanks for the clarification on when you expect to hold by production the incremental acreage kind of towards the end of next year, spillover into 2013. I'm curious what sort of drilling and completion efficiency uptick you might expect as you get back to more efficiently located wells? I mean is there sort of a 15% kind of uptick we could see in the number of wells completed per rig year for example?

Yes, I think certainly the productivity will improve substantially as we get back to pad drilling. I think the biggest opportunity for increased efficiency obviously on the completion side will be if we can push the sliding sleeve technology to 38 -- 34 to 38 stages. And we have a number of successful 34 stage sliding sleeves in the ground as we speak. So that's probably our biggest opportunity for efficiency. That will be a significant savings in number of days to get a well completed.

Okay, and last one for me. Thoughts on net backs in the Bakken once the rail comes online (multiple speakers) [update].

I wouldn't want to speculate about what the net backs are going to be because WTI has had a lot of movement recently relative to brent. So what the differentials will be going forward, there are a lot of moving pieces there. So I'd rather get some history under our belt and some clarity in the market before we would speculate that. Obviously the differential between brent or Gulf Coast based crudes and WTI is still a very significant number. So the fact that we have rail cars, that will enhance our net backs at the current time.

So clearly the wider the differential the more relative value of having the rail cars, right?

It will be net accretive in that regard.

Okay, thanks very much.

Ed Westlake, Credit Suisse.

Thanks very much for all the information on the call. I'm just going to ask three questions up front and that's it. So IP rates in the Bakken from your latest wells. Are you able to give a rough reserve split in Paradise for oil versus gas condensate? And then just a clarification on Arjun's question -- I thought rail was going to be 130,000 barrels a day of capacity. Did I hear you right to say 54? Maybe some color there. Thank you.

Yes, so let me answer the rail. With nine cars we'll have a capacity of 54. If we add additional rail cars, additional train sets we can go all the way up to 150,000 barrels a day or so. But right now we have nine train sets ordered, four have been delivered already, a fifth will come in October. And once we get those full nine we'll be at 54,000 barrels a day.

Regarding your IP rates on the Bakken, we now have 84 38-stage systems installed. We've got 35 on production, 19 of which have 30-day IPs and those IP rates are averaging just over 1,000 barrels a day on those 38-stage wells. So we continue to be obviously very encouraged by those results.

Regarding Paradise, it's just too early. We've got a lot more drilling, a lot more exploration to do on Ghana before we understand exactly what we have there. I think we're encouraged; we've got 490 feet of pay in the well, we've got good reservoir quality and we've got a liquids component in the well. So I think we're pleased to date, but we've got a lot more stuff to do.

Thank you very much for those clarifications.

Paul Cheng, Barclays Capital.

I have actually four quick follow-ups. First, Greg (inaudible) at the end of September which is the -- actually at the end of the year what is your expected exit rate for Bakken?

And also do you have a number you can share what is the Bakken -- from Bakken to the Gulf of Mexico, (inaudible) is the railroad (inaudible) that you guys have contract?

And third, when do you think you'll get enough of the production data and feel comfortable to get a production estimate or target for the Eagle Ford and Utica?

And then a final one is for a John Reilly. At the end of September do you under-lift or over-lift and in what region and what (inaudible)?

Okay, so let me answer the couple questions on the Bakken first and then the Eagle Ford and Utica questions, and then I'll give it to John to answer the net backs on the rail system.

We aren't going to quote an exit rate for the Bakken. I think what we've said is that we will -- our 2011 net production forecast is between $30,000 and $35,000 barrels a day in the range. We're confident we are going to be in that range. We've also said that our average for next year will be 60,000 barrels a day. I think we're confident that we can achieve that average rate for next year.

Regarding production data and target for the Eagle Ford and Utica, obviously Utica very early days. We haven't even gotten our first completion or well, so I can't really give you any color yet on what the Utica will be.

I think for the Eagle Ford, as I've said before, we're in the delineation mode. Most of our efforts have been focused on the southwest portion of the acreage. In the fourth quarter we're going to be starting to delineate the northeastern part of the acreage. So Paul, unfortunately it's early days to even give you estimates on the Eagle Ford because, again, we're still in this delineation mode, trying to understand what we have.

Yes, and on the railcars, Paul, two points. The commercial terms of the rail agreement and the shipping arrangements are competitively sensitive. So I can't give further color on that. The only thing is with spreads where they are it would be advantageous to our net back.

And what is the inventory at the end of September, under-lift or over-lift?

Okay, for the balance of our assets, Paul, we have a small under-lift, if you want to say, position. But -- and then in Norway we've got an over-lift position. Overall I'd say we're generally balanced that way. You shouldn't expect anything big, but you don't know based on the timings of lift.

Sure, sure. All right, very good. Thank you.

Katherine Minyard, JPMorgan.

Just a couple of quick clarification questions. Can I does confirm, is your full-year production guidance still $3.75 to $3.85?

Yes, it is.

Can I just quickly -- can you walk me through just a little bit of where we would expect some of the recovery in 4Q? I know you've walked through some Bakken and I know we've got Valhall back and both of those add a pretty generous level of volume as we look from 3Q to 4Q.

I guess when I look at 3Q it looks as though Africa is a little bit low on liquids. And I'm wondering, was there some maintenance or something that we'd expect to recover into 4Q? And what else might I be missing just in looking at 4Q to get into that full-year range?

You have the big pieces, so Valhall clearly coming aback is the biggest. We've got the growth in the Bakken like you mentioned. The one thing I don't think I heard you mention, we did have North Sea maintenance, so we did have fields down. It was -- we had South Arne, we had Bittern, we had Schiehallion. So we expect some additional production coming back there. As far as in Africa, the decline was in EG. There was a small amount of down time, between 1,000 and 2,000 barrels there.

Okay, all right great. Thank you very much.

But I would just add one comment on EG, we have a rate coming back into EG and anticipate being -- doing some completions and also drilling more wells next year in EG.

Okay, thank you.

Mark Gilman, The Benchmark Company.

John Reilly or Greg, have you got a capital cost number for the rail project?

No, Mark, we don't provide that individual detail.

John, can you say whether you're owning or leasing the rail cars?

We are owning them.

Okay. And with respect to the lifting issue, the volume of the third quarter under-lift?

We were under-lifted -- it was approximately 650,000 barrels in the third quarter. We were under-lifted by approximately 600,000 barrels in both the UK and Azure Bijan, so 1.2 billion combined between those two countries. And we did have an over-lift in Norway. We had the lower production, so based on the lower production our sales volumes were higher in Norway by 500,000 barrels and that's how it nets back down to the 650,000 barrels.

Great. Thanks, John.

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