赫斯 (HES) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2011 Hess Corporation earnings conference call. My name is Modesto 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, Modesto. Good morning everyone and 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.

As usual, 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 2011 was $929 million, including a $310 million gain on the sale of assets versus $538 million a year ago. Our earnings were positively impacted by higher crude oil selling prices, which more than offset the impact of lower production volumes and higher exploration expense.

Exploration and Production earned $979 million. Crude oil and natural gas production averaged 399,000 barrels of oil equivalent per day, which was 6% below the year ago quarter. This decrease resulted primarily from the loss of production from Libya and the previously announced sale of mature natural gas assets in the United Kingdom.

In terms of our 2011 production forecast we believe the implementation of US and international sanctions make it prudent to assume production from Libya will remain suspended for the balance of the year, resulting in a 20,000 barrel per day reduction in our forecast.

In addition, a shut-in well at the outside operated Llano field in the Deepwater Gulf of Mexico and PSC effects related to higher oil prices combined to further reduce our forecast by 10,000 barrels of oil equivalent per day. We now forecast 2011 net production to average between 385,000 and 395,000 barrels of oil equivalent per day versus our previous forecast of 415,000 to 425,000 of barrels of oil equivalent per day.

In North Dakota net production from the Bakken averaged 25,000 barrels of oil equivalent per day in the first quarter. We are currently operating an 18-rig program and focusing most of our drilling on the acreage we acquired last year from American Oil & Gas and TRZ Energy.

In South Texas we have drilled seven wells in the Eagle Ford. We have completed two of these wells and expect to commence production in the second quarter. In total we plan to drill about 25 Eagle Ford wells in 2011, and we continue to add acreage in the play.

In France a political debate regarding hydraulic fracturing has delayed our drilling program in the Paris Basin. We are actively engaged with local and national stakeholders. While we believe it will take time to work through the issues, we are confident that the drilling and completion operations can be done safely and responsibly.

In Australia appraisal activities are continuing on our 100% owned WA-390-P permit. And commercial discussions with potential partners are ongoing.

In the Deepwater Gulf of Mexico we continue to advance our Tubular Bells development where we are operator and have a 40% working interest. Last week we signed a letter of award to process production from the field and a third-party owned spar facility. Project sanction is anticipated to occur later this year.

We also continue to progress the engineering and design work for the Pony Knotty Head Field, and expect to sanction the project in 2012. In addition, we have joined the Marine Well Containment Company and also the Helix Well Containment Group to enable us to have access to both oil spill response capabilities that conduct drilling operations in the Deepwater Gulf of Mexico.

With regard to exploration we thought it appropriate to provide an update on the Paradise prospect in Ghana. As we have previously commented, we are drilling this prospect in 6,038 feet of water on the Deepwater Tano Cape Three Points block. Hess is carrying 100% of the well cost and has a 90% working interest. The Ghana National Petroleum corporation has the remaining 10% interest.

While results are preliminary, intermediate wireline locks indicate that we have thus far encountered 370 feet of net hydrocarbon pay in two separate intervals. Our current plan is to drill an additional 1,100 feet to test a third stratigraphic interval, reaching a total depth of approximately 16,400 feet.

In Egypt drilling of the Cherry Prospect in the North Red Sea was recently completed resulting in a dry hole. Hess is operator and has an 80% working interest in the block. We will evaluate the results of the Cherry well to determine future plans for the buck. We are currently negotiating agreement with another operator to farm out the Stena Forth drillship through October of this year.

In Indonesia we plan to spud the Andalan well on the Semai V Block in the second 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, intends to commence exploration drilling in the third quarter.

Turning to Refining and Marketing, we reported net income of $39 million for the first quarter of 2011. Financial results at our HOVENSA joint venture refinery came in slightly better than the year-ago quarter. During the first quarter HOVENSA completed a reconfiguration of the refinery, which reduced distillation capacity to 350,000 barrels per day from 500,000 barrels per day. This action will allow the refinery to produce a greater percentage of higher-margin products and reduce operating costs and capital expenditures.

Marketing earnings were lower than the first quarter last year. Retail marketing faced rising wholesale prices during the first quarter, which put pressure on fuel margins. Gasoline volumes on a per site basis were down approximately 2%, while total convenience store sales were up nearly 1%.

Our energy marketing business delivered strong operating results, but earnings were lower than last year's first quarter.

Solid operating performance, higher commodity prices and a new five-year $4 billion revolving credit facility have strengthened our financial position. 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 Rielly.

Thanks, John. Hello everyone. In my remarks today I will compare first-quarter 2011 results to the fourth quarter of 2010. The Corporation generated consolidated net income of $929 million in the first quarter of 2011 compared with $58 million in the fourth quarter of 2010. Excluding items affecting the comparability of earnings between periods, the Corporation had earnings of $619 million in the first quarter of 2011 compared with $398 million in the fourth quarter of 2010.

Turning to Exploration and Production. Exploration and Production operations had income of $979 million in the first quarter of 2011 compared with $420 million in the fourth quarter of 2010. The first quarter of 2011 results include an after-tax gain of $310 million related to the sale of the Corporation's interest in certain natural gas producing assets in the United Kingdom North Sea.

Fourth-quarter 2010 results included an after-tax charge of $51 million from items affecting the comparability of earnings between periods. Excluding the effect of these items, the changes in the after-tax components of the results are as follows.

Higher selling prices increased earnings by $231 million. Lower operating costs, principally DD&A, increased income by $25 million. Higher exploration expense decreased earnings by $48 million. All the other items net to a decrease in earnings of $10 million for an overall increase in first-quarter adjusted earnings of $198 million.

Our E&P operations were over-lifted compared with production, resulting in increased after-tax income in the quarter of approximately $25 million. The E&P effective income tax rate for the first quarter of 2011 was 42%, excluding items affecting the comparability of earnings between periods.

In March 2011 the government of the United Kingdom proposed increasing the supplementary tax on petroleum operations by an additional 12%. This supplementary tax is expected to be enacted in the third quarter and will be effective from March 24, 2011. As a result, we expect to record a charge in the third quarter that will include a provision representing the incremental tax on earnings from the effective date to the date of enactment, and a charge to adjust the deferred tax liability in the UK.

Turning to Marketing and Refining. Marketing and Refining operations generated income of $39 million in the first quarter of 2011 compared with a loss of $261 million in the fourth quarter of 2010.

Fourth-quarter 2010 results included an after-tax impairment charge of $289 million to reduce the carrying value of our equity investment in HOVENSA.

Refining losses were $48 million in the first quarter of 2011 compared with $19 million in the fourth quarter of 2010, excluding the impact of the impairment.

The Corporation's losses from its equity investment in HOVENSA were $48 million in the first quarter of 2011 compared with $30 million in the fourth quarter of last year, excluding the impairment. Port Reading reported earnings of $2 million in the first quarter of 2011, down from $11 million in the fourth quarter of 2010.

Marketing earnings were $68 million in the first quarter of 2011 compared with $37 million in the fourth quarter of 2010. Trading activities generated income of $19 million in the first quarter of 2011 compared with $10 million in the fourth quarter of 2010.

Turning to corporate and interest. Net corporate expenses were $28 million in the first quarter of 2011 compared with $43 million in the fourth quarter of 2010. After-tax interest expense was $61 million in the first quarter of 2011 compared with $58 million in the fourth quarter of 2010.

Turning to cash flow. Net cash provided by operating activities in the first quarter, including a decrease of $325 million from changes in working capital, was $1.135 billion. Capital expenditures were $1.082 billion.

Proceeds from the sale of the United Kingdom gas producing assets were $359 million. All other items amounted to a decrease in cash of $52 million, resulting in a net increase in cash and cash equivalents in the first quarter of $360 million.

We had $1.968 billion of cash and cash equivalents at March 31, 2011, and $1.608 billion at December 31, 2010. Our available revolving credit capacity was $3 billion at March 31, 2011. In April we established a new five-year revolving credit agreement, which increased our credit facility to $4 billion.

Total debt was $5.552 billion at March 31, 2011 and $5.583 billion at December 31, 2010. The Corporation's debt to capitalization ratio at March 31, 2011, was 23.5% compared with 24.9% at the end of 2010.

I would like to update our 2011 guidance for certain metrics in light of recent events, including the suspension of Libyan production. The anticipated loss of Libyan production for the remainder of 2011 will raise our unit costs and lower our effective tax rate, but it is not expected to have a significant adverse impact to net income and cash flow.

Our new guidance for unit costs for the full year is $33.50 to $35.50 per barrel, up from our previous guidance of $29.50 to $31.50 per barrel.

E&P cash operating costs are now expected to be in the range of $18 to $19 per barrel. And depreciation, depletion and amortization expenses are expected to be in the range of $15.50 to $16.50 per barrel.

The higher unit costs are due to the expected loss of low-cost Libyan barrels, but also include the effect of increases in commodity price-driven production taxes in other geographical areas.

Our new guidance for our 2011 E&P effective tax rate is 38% to 42%, down from our previous guidance of 45% to 49%. The lower tax rate guidance reflects the absence of Libyan production taxed at an effective rate of 93.5% and the effect of the proposed higher UK supplementary tax on oil and gas operations.

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

(Operator Instructions). Doug Leggate, Bank of America Merrill Lynch.

I've got a couple of questions, if I can. Obviously, the first one on the great news you have had in Ghana, but also Egypt. Is it possible to just give us a little bit of an update on the prognosis of these two areas, and specifically in Ghana.

Obviously, or at least I believe, this is not a stratigraphic play, could you talk, therefore, about the potential scale of the opportunity of this structural -- is it a channel sand? What are we talking about in terms of potential predrilled prospect size now that you're actually halfway through this thing? Any update would be appreciated. And I have a follow-up.

This is Greg Hill. The first thing I want to do is just to emphasize what John said. The results are preliminary on the well. Our next steps are to finish drilling the well, then evaluate all the data out of the well. So that includes wireline logs, MDT sample pots, etc. And then work with the government on the next step.

So, Doug, it is just too early to speculate on how big, what not. The thing I will say is it was a structural play. I mean, that was the location that we picked was a structural play.

Can you tell us what the hydrocarbons that you [frac'ed], are you talking liquids?

We don't know yet. We are just getting -- we are just literally pulling the sample pots last night.

Okay, so it is that recent. What about Egypt, Greg, you have obviously pushed the rig out it looks like until September. You've got a lot of prospects there, so anything you can tell us there or is it still too early?

I think on Egypt the prospect that we were targeting was oil in the Cretaceous and Nubia sandstone within a three-way closure, and that is a complex rifted system there. And frankly the Nubia was just not present in the well. So while we experienced some gas shows through the Miocene, it was noncommercial.

I think given this, Doug, we will take a step back. We will study all the results from the well, and then figure out next steps for the block, because there are a lot of additional prospects on the block.

As John mentioned in his remarks, the plan is to farm out the rig to another operator, so she will be heading out of the Northern Red Sea.

Great stuff. My follow-up is really just on the unconventionals in the US. Bakken and Eagle Ford, I guess Eagle Ford specifically, the seven wells, can you give us any kind of indication as to the results you have had there? On the Bakken, to interpret John's comments correctly, are we now basically off the dual lateral program for the time being in order to lock up HBP acreage? A little bit of color there, and maybe on production guidance in the Bakken for this year would be appreciated. And I will leave it there.

Okay, so let me talk to the Bakken first. So the Bakken is proceeding as planned. As John mentioned, we have an 18-rig program. We expect to average 40,000 barrels a day this year. And as John did mention in his opening remarks, the primary objective is HBP, to get that new acreage held by production. So, therefore, for the next 18 months, Doug, our program is going to be primarily single laterals with those 18 rigs.

Your question on the Eagle Ford, we got seven wells down. We are pleased with results. We have a couple of wells completed. They won't be on production until early May, so we don't have any production results yet, but the logs are encouraging.

Perfect, thanks, Greg.

Paul Sankey, Deutsche Bank.

With the changes that we've seen in the UK and Libya, and even I guess you could say Ghana, could you talk a little bit about your CapEx for the year, which I think is running behind guidance? I am really thinking of any potential shifts you might be considering in where you spend and how much you spend. Thanks.

Well, it is still a little early in the year. As you can see, you are saying we are running behind guidance, but it was really in accordance with our plan. And there was some ramping up as we go through the year. So typically as usual we will update guidance on our next quarter conference call.

Fair enough. But is there any more on sales of disposals? Can you give me an indication of what you may be doing in terms of the portfolio over the rest of the year? You have been very active, obviously, over the past year or so. I just wondered if there will be a continuation of that kind of activity or whether you think you are settling into the asset base you've got?

What we will do, I mean, it is a typical portfolio pruning. We will look at what assets that may fit in others' portfolios compared to ours. The things that you may have heard or have been announced in the marketplace, besides our UK gas assets on the first quarter, is we have come to an agreement on Cook and Maclure in the UK. And also we have a small interest in the [Snore Field], which we have also come to an agreement on, on selling. At this point right now that is all we have on our plate.

Finally for me, just to be very near term, when can we expect something from Ghana news flow-wise? I'm thinking of when you hit TD and all the rest of it. Thanks.

We've got about 1,100 feet to drill to TD. So we are currently at about 15.3. We are going to go down to 16.4. We've got at least another two weeks of drilling and logging to go before we will be at bottom.

Thank you, Greg. Thanks guys.

Paul Cheng, Barclays Capital.

So I have a quick question. John, when you're talking about -- I know there is a new (inaudible) and you are not going to give the new budget number, but what is the budget number for Libya or region only?

The amount of capital in Libya really is just not that significant that we been planning in the budget. So, again, there will be ins and outs in our CapEx budget program, but Libya was not a big piece of it.

So when you say not a big piece, it is less than $100 million, less than $200 million, any rough number?

It is less than $100 million.

Less than $100 million, okay. And that for Greg, the Eagle Ford, you say you finished, or you drilled seven wells. I know that you don't have the data, because none of them are in production, but can you give us then what is your target estimate for those wells, and ultimately where you think that you can get to in terms of the cost per well, the target resource per well, and if there is any IPO, or any kind of data that you can help us?

Again, it is still pretty early on the Eagle Ford, so until we get the wells on production and CIP rates and all that, I can't really talk about resource estimates. So we will say again the logs have been encouraging. And as far as the wells we have drilled, they have cost us on average about $10 million including hookup costs. That is a round number for what they're going to cost.

Okay, and that so far from what you see, have you seen anything significantly different than what the other industry data out there in the Eagle Ford area?

No, Paul, it has pretty much come in as prognosed.

This is for John. For energy marketing, if my recollection or calculation is correct, in the first quarter last year you probably made maybe about $100 million, $120 million. And it does look like that is much lower in this quarter. I am wondering if there is any rough number that you can share.

Also, given how cold it was in the first quarter, so it seems to be a little bit surprising that you didn't make a least similar to what it was in the first quarter of last year. Any light -- insight that you can help us?

The insight I can give you is really in the first quarter of last year there were some very good spot margin opportunities that we had with energy marketing, and so we were able to take advantage of certain activities there in the first quarter of last year that were kind of unique to that quarter versus this quarter.

So from a -- as John has mentioned, it was a solid operating performance from energy marketing, pretty much in-line with what we were looking at, but we had just some higher margin in the first quarter of last year.

Yes, I would complement that. You are absolutely right, from a degree day perspective our sales were very comparable on gas, good electric margins as well. And oil held its own even though more of it was gas-driven. So I would say on an operating basis you are 100% right, it was very comparable.

There are just a few accounting adjustments on timing in there that mismatched the, if you will, economic results to the accounting results, and that happened from quarter to quarter. But operationally it was very comparable to the year-ago.

John, can you share with us how much did energy marketing make last year as a whole?

We don't break out individually within the segment, Paul.

And a final question for Greg. I now it is early -- now they are trying to just finish the Paradise well drilling. Any idea that the next well, the current thinking is more going to do an appraisal well first or that you're going to drill for the new prospect?

Too early to say, Paul. Obviously, our plans have to be worked with the government, so we will be in conversations with the government over the next month, month and a half to figure out next steps.

Okay, very good. Thank you.

Mark Gilman, Benchmark Company.

I guess I had a couple of things. Greg, can you talk about the specific horizons which you encountered in the Ghana well?

Yes, the two horizons that we did in Ghana that John mentioned in his opening remarks where the [Peroni and the Santamonian], and then we are deepening ourselves to try and tap into the Albian below that.

Just shifting to the Bakken for a sec, is there anything that you might be able to share with us in terms of recent drilling results on the new acreage blocks and how it might compare to the work you have done in the area up to this point?

Suffice to say that the wells that we have drilled on the new acreage have met or exceeded our expectations. Just let me give you an update just on the costs in the Bakken right now. Single laterals are about $7.5 million. EURs are averaging about 550,000 barrels per lateral. And our 30-day average IP rates are averaging between 700 and 750 barrels a day per lateral. Now those are from 18 to 22 stage frac wells.

And you have seen similar results on the American acreage?

Yes, similar or better.

John Rielly, I'm a little bit puzzled, I guess, by the tax rate guidance which you suggested in light of the mix. It just seems a little bit low with the Norwegian effective rates being as high as they are, the obvious increase in the weighting as a result of recent portfolio transactions, as well as the 12.5% increase on the UK side. Can you help me understand that a little bit?

I think you said it. It does come down to mix. So while we do operate in some higher tax rate regimes, as you mentioned, we do also operate in a number of regimes that have tax rates below our overall effective rate. So basically without Libya, which was driving that rate up, our tax rate comes down.

So there is nothing else, it is just a mix?

It is just mix, correct.

Finally, for John Hess, John, can we at all look at the first quarter HOVENSA results as substantially reflecting the benefits of the reconfiguration or should we look at it as a transition quarter? I guess I'm trying to figure out whether or not on a variable cost basis HOVENSA is or is not profitable in an environment similar to the first quarter.

I would say look forward to the next quarter. There were a couple of issues. We had a distillate desulfurizer that had a fire; that was out of capacity. We had one or two problems with the sulfur unit. We also had the transition of the reductions in workforce and capital programs going forward. So hopefully starting in the second quarter it will be smoother sailing.

One final one for me. It looks like you might have sold some retail stations in the first quarter, was that true? And was there any significant gain or proceeds associated with it?

Those are a couple of marginal stations. And just like in Exploration and Production we upgrade our portfolio from time to time. There is some pruning going on in our retail business and it is the normal course of activities.

If I could sneak in one on the lifting. Can you give me an idea, John Rielly, where the lifting variance occurred, and what the volume element was?

Sure. So I am just taking Libya out of the picture. We were over-lifted by approximately 1 million barrels in the first quarter, and the primary contributors were the UK, Norway and Denmark.

Thanks very much, guys.

Pavel Molchanov, Raymond James.

Just two quick ones. First on Andalan, it seems to be a little bit delayed in terms of spudding. Can you talk about that?

Thanks for that, Pavel. Yes, the rig is showing up late for Murphy, so that is the only issue. We are just waiting on the rig from Murphy. In May, early June is our projected date at this point.

Okay, great. Then on Libya, do you have a sense of the physical state of your assets? Is there any physical damage that you're aware of or is it just a matter of getting the people back to work as soon as the situation stabilizes?

No, we really have no information where we could give you a meaningful update at this time. That is, I think, pretty understandable given the civil strife that is going on there.

Okay, understood. Thanks.

Edward Westlake, Credit Suisse.

Congratulations everyone first for Ghana. I've got two questions on Ghana, if I may. The first one is can you give us any feeling for the aerial extense of the actual structure that you're drilling? Obviously in the next oil block you've got structures that -- you know, Teak is 20 kilometers, but Mahogany is 120, and Tweneboa is even bigger. That would be very helpful, thanks.

No, we just can't yet. It is just too -- just, again, it is too preliminary to be talking about size on Ghana. Obviously, that will be part of any evaluation program or appraisal program which we will have to discuss with the government before we proceed.

Okay, my follow-up on Ghana is, I think you just said, Greg, that you're aiming to tap into the Albian below. Obviously the Albian has been very productive in Brazil, so am I interpreting your comments correctly that you will actually get some understanding of that reservoir as well in this well?

Yes, that is a sedimentary section of the Albian. There is a carbonate section below that which we don't plan to drill into at this point.

Presumably your comment about needing to work to the government as to when you could drill the carbonate section also applies.

Yes, absolutely.

Okay, can I just switch to another country, Australia? Obviously, you have had lots of discoveries in your appraising. There has been a shift in sentiment towards it being more of a seller's market in LNG. Woodside, I think, are making some positive comments about your gas out there and contributing to Pluto. At this stage is it possible to talk about reserve estimates, and any estimated timing on when you might contribute into a Pluto LNG expansion?

So we are -- just to give you an update on Australia, we have completed the appraisal work on three wells now, and are drilling a fourth appraisal well. And we have had good results of the appraisal program so far. So what I mean by that, no contaminants in the gas and good flow rates from the wells.

And in parallel, of course, as I have discussed before, we've got negotiations with several potential liquefaction partners. And we have made no decisions on where that gas is going to go yet, because we are still in the midst of all the commercial discussions. I think once we complete the appraisal drilling and finalize the liquefaction route than we will announce further details.

Great. And any sort of timing do you think on that or it is just too early to say?

It is too early to say. The appraisal will take us through this year, because we've had some weather impacts due to cyclones. It has been a tough cyclone year down there.

Okay, thanks very much.

(Operator Instructions). John Herrlin, Societe Generale.

Three quick ones. With Ghana, Greg, can you address the Trap morphology. You said structural; is it a combination trap? Are there stratigraphic elements, could you describe it a little more?

We think it is primarily a structural trap at this point.

Does that mean a four-way, a three-way or --?

Three-way.

Okay, fine. For John O'Reilly, how much of a deferred tax charge are you going to take in the third quarter ballpark?

It is not going to be that material. But we are still working on the numbers. We are looking at the legislation, so we will update you in the second quarter (multiple speakers).

Okay, that's fine.

From an operational standpoint, the tax is included in that tax rate guidance that I gave you.

Assumed. Great. The last one for me is on the Bakken. You are very active. Any equipment issues? And also what are you seeing in terms of your base and differentials on price for the oil?

Let me talk about equipment. We are locked and loaded ready to go. So we get our 18 rigs secured. You'll recall we had the 10 rigs already secured under a five-year contract, along with associated frac crews. We are currently in tender rounds for the majority of the AOG and Tracker rigs. I don't foresee any issues or problems there.

In terms of differentials, it was Clear Brook $3 under WTI, now $3 over WTI.

Great, thank you.

Mark Gilman, Benchmark Company.

Greg, just another quick one on the Red Sea block. You mentioned a number of other prospects, are they of a different play type?

There are actually two plays there, Mark. One is this Nubia sandstone. The other one is Miocene sandstone. So there is two distinct plays. Our second well was going to be in that second type of play, which was a Miocene play. But we just said -- let's just circle the wagons, let's understand all the data from the well before we proceed on another well.

Okay, thank you, Greg.

Edward Westlake, Credit Suisse.

Just to follow-up on Eagle Ford. I know it is very early, but at this point is it possible to give a sort of rough estimate of where production might be sort of 2013, 2014?

Not yet, Ed. I would like to get a few completions on production before I do that.

Right. Okay. Thanks very much.

Paul Cheng, Barclays Capital.

Greg, in the Bakken, your unit train is going to start up in the first quarter. There is some concern, I think, in the industry that whether even if you have the unit train from your end, St. James [end], and the receiving end whether it would be able to handle more on the unit train. Any comment on that or if St. James will not be able to handle yet the west, now the other destination that your unit trains will be able to get to?

Initially the train will go to St. James, and we do not, to the best of my knowledge, anticipate any problems on that timing.

Do you think that St. James and when you start up you would be able to absorb what? Your capacity is up to 120,000 barrels per day. Obviously, that is really based on the spread was whether it is economic to do that much, but what is the St. James capacity that you think you would be able to ship to at the maximum?

We are going to start in small pieces, so I would rather get a little experience under our belt before we start making estimates of that. I understand why you're asking. We are just happy that we are going to have a third outlet. So we are going to be able to optimize our marketing differentials because of that.

Okay, thanks.

Ladies and gentlemen, we have reached the end of our Q&A portion of the call, which does conclude today's conference. We thank you for your participation. You may now disconnect. Have a great day.