赫斯 (HES) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Hess Corporation first-quarter 2010 earnings conference call. My name is Madge, and I will be your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the call over to Mr. Jay Wilson, Vice President, Investor Relations. Please proceed, sir.

Thank you, Madge, and good morning, everyone. Thank you for participating in our first-quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.

Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements.

With me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President, Worldwide Exploration and Production; and John Rielly, Senior Vice President and Chief Financial Officer. I will now turn the call over to John Hess.

Thank you, Jay, and welcome to our first-quarter conference call. I will make a few brief comments, after which John Rielly will review our financial results.

Net income for the first quarter of 2010 was $538 million versus a loss of $59 million a year ago. Our earnings were positively impacted by higher crude oil and natural gas selling prices and production volumes. That more than offset the impact of weaker refining results.

Exploration and Production earned $551 million. Crude oil and natural gas production averaged 423,000 barrels of oil equivalent per day, which was 8% above the year-ago quarter. This increase resulted primarily from higher production from the Shenzi and Conger fields in the Deepwater Gulf of Mexico and the JDA in the Gulf of Thailand.

In January, we closed the previously announced sale of our Jambi Merang asset in Indonesia, receiving proceeds of $183 million. At the end of March, we announced the sale of a package of mature, nonoperated natural gas production and transportation assets in the UK North Sea for $423 million. The sale, which is expected to close in the third quarter, is part of the Company's ongoing portfolio management efforts.

We also continue to make progress in finalizing our previously announced strategic asset trade with Shell, which is now expected to close in the second half of this year. In this trade, Hess will assume Shell's 28.09% interest in the Valhall field and 25% interest in the satellite Hod field in Norway. In return, Shell will assume Hess's 9.29% interest in the Clair field in the United Kingdom and all of Hess's interests in Gabon.

Although the net effect of these asset sales and the strategic asset trade with Shell is to reduce full-year 2010 production by approximately 5000 barrels of oil equivalent per day, our 2010 production forecast remains at 400,000 to 410,000 barrels of oil equivalent per day.

In North Dakota, net production from the Bakken reached 13,000 barrels of oil equivalent per day in March. We currently have five rigs dedicated to drilling Bakken wells, and we plan to add five additional rigs over the next 12 months.

With regard to exploration, drilling is continuing on permits WA-390-P and WA-404-P in the northwest shelf of Australia. Also, discussions with potential partners regarding the commercialization of natural gas resources on our 100% owned WA-390-P block are ongoing.

In February we spud the Pony #3 well on Green Canyon 469, in which Hess has 100% working interest. This well, which is still drilling, is designed to test the eastern extent of the Pony structure.

Due to a previous farmout agreement regarding the Stena Forth drill ship, we plan to release the rig in early June to another operator and then bring it back to finish drilling the well in the fourth quarter.

In Brazil, the operator of block BM-S-22 is in the process of completing the analysis of seismic log and core data and plans to drill a third well in the second half of 2010. Hess has a 40% working interest in the block.

In Indonesia, we have secured a rig to drill the Semai V Prospect, in which Hess has a 100% working interest. This well is expected to spud by the first quarter of 2011.

With regard to our Deepwater Tano/Cape Three Points block in Ghana, we are seeking a rig and expect to spud the first well by the first quarter of 2011, as well.

Turning to Marketing and Refining, we reported a profit of $87 million for the first quarter of 2010. Financial results at our HOVENSA joint venture were below the year-ago quarter, primarily due to costs associated with the planned turnaround of the FCC and higher refinery costs.

Marketing earnings were better than the first quarter last year. Retail marketing gasoline volumes on a per-site basis were down 6%, but total convenience store sales were up 8%, due partly to new product offerings.

In energy marketing, although there were fewer heating degree days than the year-ago quarter, the business delivered strong financial results. While fuel oil and natural gas sales volume declined year-over-year, electricity sales were higher.

Solid operating performance and improving commodity prices have strengthened our cash and liquidity position. We remain committed to maintaining our financial strength, so we are positioned to fund our investment opportunities to profitably grow our reserves and production. I will now turn the call over to John Rielly.

Thank you, John. Hello, everyone. In my remarks today, I will compare first-quarter 2010 results to the fourth quarter of 2009.

First-quarter 2010 consolidated results amounted to net income of $538 million compared with $358 million in the fourth quarter. Turning to Exploration and Production, Exploration and Production operations in the first quarter of 2010 had income of $551 million compared with $494 million in the fourth quarter. The first-quarter results included after-tax income of $58 million relating to the sale of the Corporation's interest in the Jambi Merang natural gas development project in Indonesia. Excluding the effect of this asset sale, the change in the after-tax components of the results are as follows.

Higher selling prices increased earnings by $48 million. Lower sales volumes decreased earnings by $95 million. Lower costs increased earnings by $48 million. All other items net to a decrease in earnings of $2 million, for an overall decrease in first-quarter adjusted earnings of $1 million.

Following a large overlift in the fourth quarter of 2009, E&P operations were underlifted compared with production in the first quarter of 2010, which decreased after-tax income by approximately $55 million. The E&P effective income tax rate was 45%.

Turning to Marketing and Refining, Marketing and Refining operations had income of $87 million in the first quarter of 2010 compared with income of $17 million in the fourth quarter. Refining operations lost $56 million in the first quarter compared with a loss of $40 million in the fourth quarter. The Corporation's share of HOVENSA's results, after income taxes, was a loss of $52 million in the first quarter compared with a loss of $40 million in the fourth quarter.

Port Reading generated a loss of $4 million in the first quarter and broke even in the fourth quarter.

During the first quarter, the planned turnaround of the FCC unit at the HOVENSA refinery in St. Croix was completed, and operations recommenced in March 2010. The Corporation's share of HOVENSA's turnaround expenses in the first quarter was approximately $20 million after income taxes.

In addition, the scheduled turnaround for the Port Reading refining facility commenced in April and is expected to last approximately 35 days. The estimated after-tax expenses to be recorded in the second quarter for the Port Reading turnaround are approximately $20 million after-tax.

Marketing earnings were $121 million in the first quarter of 2010 compared with $45 million in the fourth quarter, principally reflecting seasonally higher margins and refined product volumes in energy marketing operations. Trading activities generated income of $22 million in the first quarter compared with income of $12 million in the fourth quarter.

Turning to corporate, net corporate expenses amounted to $48 million in the first quarter of 2010 compared with $97 million in the fourth quarter. Net corporate expenses in the first quarter included an after-tax charge of $7 million for the repurchase of the remaining $116 million of bonds that were scheduled to mature in 2011. Net corporate expenses in the fourth quarter included an after-tax charge of $34 million for the repurchase of $546 million of the 2011 bonds and $10 million for pension plan settlements related to employee retirements. Excluding these special charges, net corporate expenses were lower in the first quarter, primarily due to lower employee-related costs. After-tax interest expense was $52 million in the first quarter compared with $56 million in the fourth quarter.

Turning to cash flow, net cash provided by operating activities in the first quarter, including a decrease of $432 million from changes in working capital, was $825 million. Proceeds from the Jambi Merang asset sale were $183 million. Repayments of debt amounted to $142 million. Capital expenditures were $788 million. All other items amounted to a decrease in cash of $70 million, resulting in a net increase in cash and cash equivalents in the first quarter of $8 million.

We had $1,370,000,000 of cash and cash equivalents at March 31, 2010 and $1,362,000,000 at December 31, 2009. Our available revolving credit capacity was $3 billion at March 31, 2010. Total debt was $4,335,000,000 at March 31, 2010 and $4,467,000,000 at December 31, 2009.

The Corporation's debt-to-capitalization ratio at March 31, 2010 was 23.6% compared with 24.8% at the end of 2009.

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

(Operator Instructions) Arjun Murti, Goldman Sachs.

A couple different questions. First, just on the Bakken, I think you mentioned you were up to five rigs so far. Just wondering how you are feeling about how the well costs are coming in and production rates, if there is any update there. And then also in the Shale area, if there is any update on where you are on the Marcellus program. Thank you.

On the Bakken first, yes, we are up. We have five rigs operating. We've got four dual-lateral wells that we've completed to date. And while it is still early days, the results are coming in as expected on those wells.

So the well costs for those dual-laterals are averaging $10 million to $11 million each. The EUR is about 1 million barrels per well. And the 30-day average IP for those dual-laterals is around 1000 barrels a day. So that is 450 to 500 barrels per lateral.

If I turn to the Marcellus, again, we are continuing to build our position in the Marcellus. We are at about 80,000 net acres now in the Marcellus, primarily in Wayne County, Pennsylvania. About 50,000 of that is Hess-operated, and the balance is part of this joint venture we have with Newfield. Our plans this year are to drill five to 10 wells during the second half of 2010 in order to evaluate the resource potential on the acreage.

That is very helpful, Greg. Thank you. If I can try one more, on the Pony eastern flank extension, if that does come in, order of magnitude of what it might mean for Pony -- 100 million barrels, 50, 100, something along those lines -- in terms of additional reserve potential?

Yes, just a little background first on Pony 3. You know, as John said in his opening remarks, it is an appraisal well on our 100%-owned Block 469, and it's really designed to delineate the Pony reservoir on the eastern extension under the block.

Now, the results of that well are going to be used to determine the final equity split in this combined Pony-Knotty Head joint development. Can't give you any volume estimates. It is just way too early. I mean, we are only at 25,000 feet in the well.

I see. You are drilling your extension. I think they are drilling their Knotty Head Number 2. And maybe after those two wells, one from each of you, we can then get a unitization and some sort of agreement on the split?

Absolutely. We are both going to use the results of both of those wells to kind of finalize our negotiations on the unitization.

And you think that will happen this year?

We will get the wells -- as John said in his opening remarks, the Stena Forth will come back and finish the well in the fourth quarter. So early 2011 is when we will be back in the discussions.

Got it. That's really helpful. Thank you.

Mark Gilman, Benchmark Corporation.

A couple things. Greg or John, now what is the holdup on the asset trade with Shell?

Mark, we have normal partner and government approvals to get, and it is just the normal course of that process. So there is nothing unusual that is going on.

Nothing unusual at all?

No, no, it is just the normal process of getting approvals from both partners as well as government.

Okay. John Rielly, am I correct that there's a potentially large deferred tax item in the quarter as a source of cash?

No. If you are referring to from the working capital discussion, no. It is -- we just had a decrease in working capital in the quarter of $430 million. So our cash flow was quite strong from our operations. So from that standpoint, there is nothing, per se, from a deferred tax aspect. So if you removed the working capital, our cash flow would have been above $1,250,000,000 in the first quarter.

Okay. Greg Hill, where are we in terms of having a resource assessment for the northwestern shelf block, the 100% block?

Thanks, Mark. Let me just kind of give a broad update about Australia. So we are completing, as we speak, our 12th well. So this will be the 12th of 16 commitment wells. Of those 12 wells, we've had 10 discoveries so far.

We plan to finish out drilling those 16 commitment wells by midyear. And then after, that we will follow with an appraisal and flow testing phase during the second half. Now as we've said before, we don't plan to give resource estimates until our drilling programs are complete.

On the commercialization side, we are continuing again in parallel to work various commercial options with all the potential partners.

Okay, final one for me. The US liquids production in the first quarter dropped down from the fourth. Is that Bakken, Shenzi, or is there something else going on?

It is all Shenzi, and it's Shenzi's decline as expected.

Kind of a steep decline over 90 days, Greg, isn't it?

Well, Mark, we always knew that Shenzi was going to come off plateau. It is as we expected. I think if you look at what our expectation is for Shenzi for the year, it is going to average between 30,000 and 35,000 barrels a day.

Net?

Yes, net.

Okay. Thanks a lot, Greg.

Doug Leggate, Merrill Lynch.

A couple of diverse questions from me also. Greg, the Exploration expenditure in the quarter is -- the run rate obviously sticks in that sort of $150 million kind of level, but there is not a whole lot of exploration activity going on. Can you just kind of tell us what exactly are you doing right now in terms of fleshing out the program? What exactly are you spending on right now? And if you could give us an update on the well program for the balance of this year, particularly in the Gulf of Mexico? I think you had talked about possibly drilling two unnamed prospects at some point.

Thanks, Doug. The majority of our spend in exploration, as you know, is in Australia. So that is both on our 390 block and also the 404 block with Woodside.

As we move forward, where is our exploration spend is going to move to? As John mentioned in his opening remarks, of course, Donna Ghana, we are out contracting a rig for Ghana. We expect to spud the first well early 2011.

We have also entered a rig-sharing agreement with Murphy in Indonesia, so we anticipate drilling Semai early 2011. Maybe we can squeeze it in in late 2010. And then as we move further into 2011, of course, Australia continues with appraisal and follow-up. And then the Stena Forth, after she finishes Pony 3, will then begin an exploration program in the Gulf of Mexico. So plans are she will stay in the Gulf and just continue an exploration program. So that's actually a little color on where it is headed.

Have you identified the prospects in the Gulf, Greg?

No, we haven't finalized the drilling order. We've got two or three that we would like to do, but we are working with partners, trying to get commercial arrangements in place, so we've not finalized the drilling order.

Okay. Great stuff. Jumping if I may to John Rielly, John, is it possible you could give us a breakdown on the marketing earnings between retail and energy marketing, please?

No, we don't go into specifics on the downstream side related to those business units. As John Hess said in his opening remarks, the majority of it related to our energy marketing operations.

Okay, that's terrific. And the final one for me is, if we look at the last quarter, you had some issues around the JDA in terms of delivering gas that had been previously paid for. Is that process now complete or can you just give us an update as to where you stand in those deliveries? And that's it for me. Thanks.

Sure, Doug. The take-or-pay, it's not an issue of deliverability from the JDA. It is a take-or-pay contract. So what had happened early in the field due to getting the pipelines online a little bit late, the buyers were required to pay us for gas that wasn't delivered.

So we recorded a take-or-pay liability, if you want to say, deferred revenues. And what happens is when the buyers take gas above a contractual nomination amount, they eat back into that take-or-pay liability. And it goes back -- if you remember in the fourth quarter, what happens is they get it at the prices that were in effect during that time period.

So that is why from a revenue standpoint, we showed a lower realization at the JDA. We still do have about 18 Bcf, I think, left in our take-or-pay liability, so we still have deferred revenues up on our books. And that will continue to come down as the buyers take additional gas above the contracted amount.

Okay. That's very clear. Thanks, John.

Paul Sankey, Deutsche Bank.

Just on your volumes and volumes guidance, would you mind -- I did drop off the call for a second, so please forgive me if this is a repeated question that you've addressed. But I think what you were saying is that there obviously is the issue of the disposals. But I was still surprised, given the run rate that you are achieving in this quarter, that you would be retaining the full-year guidance in the previous range.

I'm just wondering firstly, did I miss something on disposals or other reasons why you are doing that? And secondly, if you could add anything else as to how you get to that full-year number from what was obviously a strong Q1?

Yes, I mean, obviously we were unhappy with our first-quarter production performance, and so let me -- I'll come back to the asset trades.

Normally, for Hess, as you move throughout the year and you get to the second quarter and particularly in the third quarter, our volumes are always decreased, typically due to the shutdowns in the UK and normal maintenance that is happening across the globe. So we always come in stronger in the first quarter and then dip down.

On top of that we have these asset trades. So as John Hess mentioned, the UK gas assets, as well as our trade with Shell, are expected to be completed in the second half of the year, which will cause our production to decrease by approximately 5000 barrels a day.

So at this point here, from our stronger performance, we are not changing our guidance that we went out earlier in the year with. So we are reflecting some of that stronger performance, but we are keeping our guidance at 400 to 410.

Yes, but I guess it is a conservative number, isn't it?

No, I mean, again, we will continue to update everyone as we go throughout the year. But we feel comfortable with that forecast range.

Great. And if I could continue on the guidance a little bit, please. I think you mentioned 1250 is your underlying cash flow from operations. Was there anything one-off about that number? I'm thinking about tax rates or anything else that might have boosted that.

And the extension is that we were at about -- under $80 barrel of oil here, and you are well in excess in terms of cash flows above CapEx and dividends. Could you just address how you intend to utilize that excess cash over the course of the year? My guidance CapEx number is $4.1 billion. Anything you could add on dividend policy or debt paydown would be great. Thanks.

So let me start with your first question, were there one-off in the quarter. So from -- cash flow from operating activities, and excluding working capital, it was as you said, $1,250,000,000. There were no real one-offs in there. You were asking about the tax rate. And if you are looking at our press release just from the E&P earnings, which include the special, you will see a tax rate around 40% for the group. However, that includes the special item on the Jambi Merang sale. And that sale, due to that it was a share sale, did not have tax associated with it.

So our run rate for the first quarter excluding the special was 45%, a little below our guidance, but basically really no one-offs in the first quarter from a cash flow standpoint.

Then as you are going forward through the year, it is early in the year right now, so we have that guidance at $4.1 billion. You always have things that move in and move out of our CapEx profile. At this point, we will update and it is our plan to update on the second-quarter conference call on where our CapEx is going.

Okay. And I guess what I was driving at is that you're generating excess cash. Would you be pushing CapEx up? Would you be pushing dividend up? Would you be pushing debt down, as a general --?

As you know, Paul, the priority of our cash flow is to grow our reserves and production profitably. Our CapEx program reflects that. At the middle of the year, we will be giving an update on that CapEx program. And it is a little hard now and inappropriate now to get ahead of ourselves.

So the first call on cash is the CapEx, and then maintaining the Company's financial strength for future investment.

Great, John. I understand. Thank you all.

Neil McMahon, Sanford Bernstein.

Two questions. Back again to Australia. Obviously, you are looking at the best ways to commercialize the acreage there. Have you got any thinking as to whether it could be an outright exit out of Australia, having done extremely well in the exploration program?

Or are you looking at trying to get some sort of partnership in the LNG schemes that are going on, particularly with Woodside? If you can give us any color on that.

And secondly, just really any update on Libya and offshore. Have you had any interest from any of the bigger companies in terms of farming in to your discovery there, or any updates in terms of how your geological/geophysical studies are going? Thanks.

I think first of all, let me address Australia. Our intention is to commercialize those resources, so that is our primary intention. As I said earlier, we are working with three different parties down there. We've made no decisions on which liquefaction route we are going to take, because we are still in commercial discussions, and we want to make sure we understand all the resources on the block before we make any decisions.

In regards to Libya, recall we had two successful flow tests on the Libyan block. And right now, we are currently on a joint feasibility study with the NOC, which includes development plans and commercial terms. So that is kind of where we are on Libya right now.

Any interest from other players in getting involved with you in Libya?

We've had companies approach us. We've made no decisions on involving others in Libya at this point.

Okay, thanks.

Robert Kessler, Simmons & Company.

Greg, I might be getting too granular on the Bakken rate of change over just three months, but wanted to get a few points of clarification there. It looks like you are about 13,000 barrels a day now in the Bakken versus about 10,000 barrels a day about three months ago, which seems like a pretty good clip of growth, given, I think your full-year guidance for about 4000 to 5000 barrels a day of growth in the Bakken. Is it outperforming your expectations, and as a result, is there some upside to that full-year expectation?

And then just kind of looking at your quotes on the four dual-laterals completed to date, I thought that is about the same number you had in January. And with five rigs running and I thought the bulk of the development activity dedicated to the dual-lateral completion technique now, just wondering if maybe you've got a few wells now queued up awaiting completion that have been drilled. Or again, maybe I'm splitting hairs, but just any more color, trying to help me fit those pieces together, if you don't mind.

No problem. So on the production rate first, we are essentially on plan, and we are sticking with our 20,000 barrel-a-day production rate at -- exit rate for the year. So no change there.

Regarding your questions about the wells, I think probably what I said on the last call is that we drilled four wells. We've actually drilled nine dual-laterals now; we just have completed four. So they are in various phases of completion.

Thanks. That helps.

Evan Calio, Morgan Stanley.

Maybe a broader question on the Bakken and then following up on some of your previous comments on the dual-laterals, on whether you envision any change in the type of wells that you will be drilling as you ramp activity. Maybe from a lack of a better term, reservoir characterization mode to a manufacturing load. Meaning is there going to be change from the dual-lateral to a single-lateral?

And then secondly, and somewhat related, I know on your last call you had referenced long-term Bakken service contracts as more imminent. Has anything been awarded there? Is -- can we talk about any cost advantage [about] lockup? Thank you.

Thanks, Evan. So where are we on the drilling? So our current base plan is to utilize the dual-laterals across most of our Phase I acreage. And that is because the Middle Bakken and Three Forks are largely present across that Phase I acreage.

Now, the cost advantage of this approach is clear. You get one less vertical well bore, you have fewer downhole equipment, you have fewer surface facilities. So we really believe that this dual-lateral approach combined with the application of lean manufacturing techniques and pad drilling is going to result in superior returns for us on the Bakken, which is why we are going with that approach.

I will say it is early days. As we learn, as we need to, we will change and modify as appropriate. But right now, we are happy with the dual-lateral performance.

Great. Any update on any long-term service contracts?

Yes, we've awarded the drilling rig contracts for five-year terms. We've awarded the pumping services contracts for five-year terms. And we've awarded various construction contracts with kind of varying terms, length of terms.

Right, and taking that duration, do you get some price concession, or how does that work?

We are pleased with the results of the bidding.

Maybe one other question, a little bit different. But with the recent Brunei Malaysia offshore territorial dispute being settled and opening up exploration there, I know Total is the operator; yet Hess with a 15% interest. Any idea or kind of thoughts on timing there in what is a pretty interesting neighborhood?

I think we are encouraged that the governments are talking and, you know, really seem intent on settling this issue finally. There is a partner meeting at the end of the month with the operator -- at the end of next month -- to talk about the go-forward plan. So that is really all I can say at this point.

Great. Thanks, guys. Great quarter.

Ed Westlake, Credit Suisse.

Good numbers. I guess a question on Ghana; obviously, a small dry hole for Tullow. I mean, does that change anything in terms of your view of your acreage there?

A follow-up on the Bakken in terms of has there been any variation in the well resource, early days, from region to region? And perhaps some commentary on the discounts you think you will get for the Bakken relative to WTI, really driven by the ability to get the crude oil out of the region. Thanks.

Yes, the discounts, I will go with first, and then Greg will pick up on the other questions you asked. Currently, the discounts have widened it a little bit, by about $2.00 off of WTI. So it is like $4.00 going to $6.00 range, about. And that is because of the [Mandang] turnaround and work that is going on there.

We can't predict differentials, what WTI is going to do, but we see that narrowing back. So the pricing that we've gotten in the past -- for at least the next year going forward, we think that will hold for the increase in our Bakken. So anywhere from $2.00 to $6.00, let's call it $4.00 average. That is a guesstimate, at best, but I'm just trying to give you a feel that while the discounts have widened out in the last month or so, we expect them to come back in once [Mandang] is back on stream. That is number one.

Number two, as the volumes go up, we are going to continue to look at different evacuation routes to maximize value, and it would be premature now to say what those numbers are.

And in terms of the variation, has there been any variation as you've drilled in different areas across the Bakken acreage that you've observed so far -- good wells, bad wells?

On the Bakken, it is a statistical play, so you are going to have variation in your wells. We forecast on a probabilistic basis for the Bakken. We are well within the range. So we are not seeing anything -- we are not being surprised by anything.

You had a second question, I think, about --.

Ghana.

I haven't seen the well data, so I really can't comment on what it means.

Thank you.

Paul Cheng, Barclays Capital.

Two quick questions. This is for John Rielly. John, as of the end of the first quarter, are you still overlevered or underlevered?

Paul, we are actually in a balanced position, I'm going to call it, from an overall inventory position across our assets. There are obviously some assets that have a little bit higher inventory and some a little bit below. But if you're going quarter-by-quarter average, we feel we are in a pretty balanced position. So it shouldn't be a material under or overlift occurring, let's say, in the next quarter.

There will always be small ups and downs, though.

Sure. And also that previously, you have given the unit cost guidance for the year for cash and the DD&A. With the asset sale and the asset swap and everything going on, is there any update or change in those numbers?

No, we are not changing our guidance related to that. So -- with the UK gas asset sale and with the Valhall trade. So we still have cash costs at $15 to $16 for the year, and DD&A at $14.50 to $15.50 for the year. And then we will update our guidance, as we said, just like on CapEx, in the middle of the year.

I see. Okay, very good. Thank you.

(Operator Instructions) Pavel Molchanov, Raymond James.

You mentioned the five Marcellus wells in the second half. Just to clarify, is that on your own acreage, the JV acreage or both?

It will be on both acreage positions.

Got it. And then is there a level of gas prices where you might either cut back on that program or conversely, where you might consider accelerating it?

No, I think it's early days. I mean, we are just in the proving up phase on the Marcellus.

Thanks.

Blake Fernandez, Howard Weil.

Just a point of clarification. I thought I understood that Ghana was previously scheduled for second half of the year 2010. So I'm just trying to confirm, has that been pushed to the right a bit first quarter '11, and if so, can you explain what the driver is there?

No, it hasn't. I think last time what we said is that we would drill the well in early 2011; that there was a possibility that we could squeeze it in at the end of 2010.

It is really going to depend on rig availability. We are out to tender with three separate companies right now to get a slot for the Ghana well. So that is what is driving the timing, is just the slot timing.

Okay, great. Thanks. And then the only other question I have for you, is it just premature -- I know you are kind of getting ramped up in the Marcellus, and the Bakken continues to ramp up. But with regard to international opportunities, is that something that is on the radar screen at this point, or are you really just trying to focus on your expertise in the US right now?

No, I think as we've said before, we are looking at international opportunities and unconventionals, but just not prepared to talk about that right now as to what we are specifically looking at. But we are looking.

Okay, great. Thanks.

Mark Gilman, Benchmark Corporation.

John Rielly, could I possibly ask you to put a volume number on that first quarter underlift in terms of barrels per day or total barrels? And just also to isolate if you could the Libya piece of it.

Sure. The underlift on a volume basis was 2 million barrels in the first quarter. And it is primarily Azerbaijan, e.g., UK, Algeria and Gabon. Libya did not factor into that.

Thanks, John.

And there are no more questions in the queue. Thank you for your participation in today's conference. This concludes the presentation, and you may now disconnect. Good day.