Good day ladies and gentlemen and welcome to the Hess Corporation Second Quarter 2009 Earnings Conference Call. My name is Wayne and I'll be your coordinator for today. At this time, all participants are in a listen-only mode. We'll be facilitating a question and answer session towards the end of this call. (Operator Instructions). I would now like to turn this presentation over to your host for today's call, Mr. J. Wilson, your Vice President of Investor Relations. Please proceed, sir.

Thank you, Wayne. Good morning everyone. And thank you for participating in our second quarter earnings conference call. Our earnings release was issued this morning and appears on our website www.hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of the Federal Securities Laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. With me today are John Hess, Chairman of the Board and Chief Executive Officer; Greg Hill, President Worldwide Exploration and Production and John Riley, Senior Vice President and Chief Financial Officer. I'll now turn the call over to John Hess. John B. Hess: Thank you Jay and welcome to our second quarter conference call. I will make a few brief comments after which John Rielly will review our financial results. Net income for the second quarter of 2009 was $100 million, versus $900 million a year ago. Our results were negatively impacted by lower crude oil and natural gas selling prices, which more than offset the impact of higher production volumes compared to the year ago quarter. For the second quarter of 2009, Exploration and Production earned $215 million. Crude oil and natural gas production averaged 407 thousand barrels of oil equivalent per day, which was nearly 4% above the year ago period. Higher year-over-year production resulted primarily from the addition of Phase 2 volumes at the Malaysia-Thailand JDA and the ramp up of the Shenzi Field in the deepwater Gulf of Mexico; each of which added about 20,000 barrels of oil equivalent per day versus the same period last year. As a result of strong year-to-date production performance, we have raised our full year 2009 production forecast to a range of 390 to 400 thousand barrels of oil equivalent per day, versus our previously forecasted range of 380 to 390 thousand barrels of oil equivalent per day. With regard to exploration, as was announced in early July, the operator of the Guarani well on Block BM-S-22 offshore Brazil did not file a Notice of Discovery and our share of the well cost was expensed in the second quarter. The next steps are to analyze the significant amount of seismic, log and core data gathered from the first two wells, and to plan the location of a third well to help further evaluate the BM-S-22 license. On Permit WA-390-P in the Northwest Shelf of Australia, we recently resumed exploration drilling. Over the next 12 months, we plan to execute a 12 well program designed to further appraise the block. Hess has a 100% interest in Permit WA-390-P. Turning to Marketing and Refining, we reported a loss of $30 million for the second quarter of 2009. The weak economy continued to have a negative impact on both volumes and margins in our M&R business. Refining margins at our HOVENSA joint venture refinery were significantly lower than last year's second quarter primarily as a result of lower distillate crack spreads and significantly narrower light/heavy crude differentials. Marketing results, while negative, were better than the year ago quarter. Although retail marketing fuel volumes, on a per site basis, were down 4%, total convenience store sales were up 9%. In Energy Marketing, electricity sales were higher, while natural gas and fuel oil sales volumes declined year-over-year. Capital and exploratory expenditures in the first half of 2009 were $1.6 billion, substantially all of which were related to Exploration and Production activities. For the full year 2009, our capital and exploratory expenditures forecast remains $3.2 billion. We continue to control our capital expenditures and operating expenses in light of the weak economy and uncertain commodity price environment. As we mentioned on our last conference call, we are committed to maintaining our financial strength so that we will have the capability to fund our attractive investment opportunities to sustain growth in our reserves and production. I will now turn the call over to John Rielly. John P. Rielly: Thanks John. Hello everyone. In my remarks today I will compare second quarter 2009 results to the first quarter. Second quarter 2009 consolidated results amounted to net income of $100 million compared with a net loss of $59 million in the first quarter. Turning to exploration and production; exploration and production operations in the second quarter of 2009 had income of $215 million compared with a loss of $64 million in the first quarter. The second quarter included after tax charges of $31 million to reduce the carrying value of production equipment in the UK North Sea and materials inventory in Equatorial Guinea and the United States. While the first quarter included a 13 million after-tax charge for the impairment of two lived fields, located offshore UK. Excluding the items effecting comparability in earnings, the after-tax components or the improvement in results are as follows: Higher crude oil selling prices increased earnings by $240 million. Higher sales volumes increased earnings by $121 million. Increased depreciation expense reduced earnings by $54 million. Increased exploration expense reduced earnings by $57 million. All other items net to an increase in earnings of $47 million for an overall increase in second quarter adjusted earnings of $297 million. In the second quarter of 2009, our E&P operations were over lifted compared with production, resulting in increased after-tax income in the quarter of approximately $50 million. Turning to marketing and refining; marketing and refining operations had a loss of $30 million in the second quarter of 2009, compared with income of $102 million in the first quarter. Results of refining operations amounted to a loss of $26 million in the second quarter compared with a loss of $18 million in the first quarter. The corporation share of in these results after income taxes amounted to a loss of $46 million in the second quarter compared with a loss of $25 million in the first quarter primarily reflecting lower margins. Port reading earnings were $90 million in the second quarter compared with $7 million in the first quarter. Marketing results amounted to a loss of $13 million in the second quarter of 2009 compared with income of $101 million in the first quarter, principally reflecting seasonally lower margins and sales volumes of fuel oil and natural gas in our energy marketing operations. Trading activities generated income of $9 million in the second quarter, compared with income of $19 million in the first quarter. Turning to corporate; net corporate expenses amounted to $26 million in the second quarter of 2009, compared with $49 million in the first quarter. Net corporate expenses in the first quarter of 2009 included an after-tax charge of $16 million for retirement benefits and employees severance cost. Excluding this special charge, net corporate expenses were lower in the second quarter, primarily due to gains from pension related investments and lower employee and administrative expenses. After-tax interest expense was $59 million in the second quarter, compared with $48 million in the first quarter, primarily reflecting higher average debt and increased letter of credit fees. Turning to cash flow; net cash provided by operating activities in the second quarter was $616 million. The principle use of cash was capital expenditures of $685 million. All other items amounted to a decrease in cash flow of $25 million resulting in a net decrease in cash and cash equivalents in the second quarter of $94 million. We had $1,63 million of cash and cash equivalents at June 30, 2009 and $908 million at December 31, 2008. Our available revolving credit capacity was $2,964 million at June 30, 2009. Total debt was $4,313 million at June 30, 2009 and $3,955 million at December 31, 2008. The corporations debt-to-capitalization ratio at June 30, 2009 was 25.8% compared with 24.2% at the end of 2008. This concludes my remarks. We'll be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions). And our first question will be from the line of Dough Leggate with Howard Weil Please proceed sir.

Thanks. Good morning guys. Thanks for taking my question.

Good morning.

A couple of things. One operational and one I guess big picture on the debt structure of the company. Operationally, can you just talk a little bit about where you are and potentially negotiating sales contracts for your Australian Gas? Is it too early in the process or is the joint venture with Woodside really positioning you to potentially participate in the L&G project down the line? My follow up on is really on the capital structure. On the first quarter call, I think everyone noticed the reference to the potential for or preparedness rather to come to the equity markets, both to protect the credit rating and perhaps fund through development sanction projects maybe later this year. I notice an absence to any reference to that this quarter, I just wonder if you can clarify where you stand on that, again it's kind of a big picture question? Thanks.

Okay, thanks. On the first question its early days to be talking about any commercial terms really. We do have discussions ongoing with both Woodside and Shell. So its way early to be talking about commercial terms or which price we're going to take the gas?

And on the capital structure Doug, now really, I was making a reference to that, at the end of my remarks but for clarification, I'm happy to give further clarification. Once we further divide our future development projects and growth projects, the Bakken being the one, hopefully, the Pony project is well. We'll have a better feel on our funding needs and the thing that we want our shareholders and potential investors to know, that we will maintain a strong balance sheet, have adequate funding to pursue those projects. So as those projects get further definition, we have many options on the tables. Some may be asset sales in the normal course of business, some maybe diluting down some of the projects we have. If that makes sense and they're define enough and another maybe accessing the equity markets. So we just want our shareholders to know that all options are on the table because as you've mentioned yourself, maintaining a strong balance sheet in these uncertain times, with the capital projects that we have ahead of us, it's a prudent thing to do.

Terrific. Thanks a lot. I appreciate it.

Thank you. Our next question will be from the line of Evan Calio from Morgan Stanley. Please proceed sir.

Good morning gentlemen. Thanks for taking my call.

Good morning.

I have two general questions. The first regarding Pony, as you discussed in prior calls guys, the discussions were not you had partners on potential utilization of blocks. Is there any update on those discussions or general information on the cost or timing impact of potential unit station? And I guess, maybe John, you just maybe answered this question but I guess, would you also consider selling down some of your interest in Pony?

On the first question, the discussions are ongoing with the Knotty Head Partners. Those discussions are progressing. And we're still in the midst of doing our development planning studies for Pony, so it's early to talk about when it might come on or anything like that.

In terms of funding, Pony is not one of the assets on the list for selling down.

Okay. Thank you. And my second question maybe more of a question for Greg or for both it's a strategy question I mean is it fair to say there has been some modest shift in strategy; a shift towards unconventional in the mix versus that exploration with Bakken and potentially unconventionally U.S. gas going forward and after, Greg after spending time reviewing Bakken activities, and can you give any update on pace of drilling going forward for your large position in the play? Thank you.

I wouldn't say there's a strategic shift. However, we do know we're very pleased with our position in the Bakken. So I think that we'll play an increasingly important part of our portfolio mix and we're currently in the middle of evaluating various development options in terms of pace and additional late rigs etcetera. So when we have those development plans done, we'll share more information about the Bakken but we're very pleased with what we have and we're anxious to get moving on the Bakken.

Thank you.

And thank you. Our next question will be from the line of Arjun Murti from Goldman Sachs. Please proceed.

Thank you. I think you mentioned on the expiration program, the Australia wealth. Can you just give a quick update on the timing of any follow up in Libya, Ghana and I think the third well in Brazil, when you might get the rig back from Petrobras. I assume that's in early 2010 but if you have any comments on those three areas? Thank you.

Okay. So for the go forward exploration program as you know, we are starting our -- we have started our first of 12 back-to-back drilling campaigns in Australia. We just completed the first well and we're now on the second well. We have a new build drill ship called the Stena IV that's currently in the shipyard in Korea. It's due to set sail sometime in August and it's headed to Libya to do a follow-up past on our discovery last year and also in a next appraisal well in Libya. Regarding Brazil, as John mentioned in the call up front. I mean we've got an awful lot of core data, seismic data and log data to go through to determine next steps on a fair ground in Brazil. So it's early today to be talking about when we might drill a third well in Brazil. Regarding the format of the rig the Petronas had, I'd encouraged you just refer that question to Exxon Mobil.

For sure. Ghana, when did you think it might come back there?

Ghana, we're still evaluating our seismic and scientific out wind we may drill our next well. So really can't comment yet.

That's great. And then just one final one, you mentioned the Pony discussions with the Knotty Head Partners. Any update on than tubular wells and where that development potentially stands?

I think BT is in the same position we are with Pony. They are evaluating development studies and we don't yet know when that's going to come on.

That's great. Thank you.

Thank you. Our next question will be from the line of Robert Kessler with Simmons and Company. Please proceed.

Good morning guys. A couple of accounting related questions if I can. The first on BM-S-22, if I recall correctly, you've capitalized the first well on that block and now that you've taken somewhat of a hiatus on drilling activity, I'm curious how long you might be able to lead that capitalized or held in suspension. Is there any sort of one year or two year time out on that in which case, you might have to expense it? And then secondly, on tax, curious if do you any update on your expectations going forward in particular on international E&P taxes?

Sure. On the first one with the well you're correct. The first well is capitalized and the second well as John has mentioned earlier has been expense. Greg just mentioned that, we got a lot of log and core data and that we will be reviewing right now and as well as combine it with all our seismic information to determine the location of the third well. But the accounting rules are just based on the notice of discovery that we found on the first well and are continuing studies, we can lead that well capitalized and what it is, its just part of the evaluation to determine a commercial development. So there's no real hard and fast timing cut off for expense in a well; this is just going to become part of our normal operation there in Brazil as we evaluate the BM-S-22. As far as the tax rate we did have a lower tax rate than expected or that from a guidance standpoint in the second quarter. And it really had to do as I mentioned earlier, we had an overlift in the second quarter. And the significant areas that had the overlift were West Africa, which was EG and Gabon that have lower tax rates that our over all portfolio rate. So that helped us on the tax rate in the second quarter. Going forward, it's always difficult to forecast the tax rate based on where commodity prices are and based on the mix of income, depending on the where the lifting's occur. What we generally see here going for the next six months is a rate around 50% overall, for the next six months. Now, it's going to vary based on the quarters, on the mix of income. Right now, I'll tell you a little bit lower in the third and a little bit higher in the fourth related to that 50, but overall about 50% going for the next six months.

Okay, that's helpful. Thank you very much.

Thank you.

Our next question will be from the line of Paul Sankey from Deutsche Bank. Please proceed, sir.

Hi everyone. It's like you keep drilling down into your exploration program if possibly, right way to think of it. It sounds just Libya well will before the end of the year, I've heard what you said on Ghana, I heard what you said on Brazil, I believe that you got a couple of other wildcats possibly Gulf of Mexico and non-subsoil Brazil could we just round that out with a particular idea of what you're going to be drilling this year? Thanks.

That was the only one I haven't mentioned so thanks for bringing that up. As we are drilling a pre-salt well in this Santos Basin in Brazil, so that's the only well I did not mention. As far as our Gulf of Mexico program we're looking at using a rig there for either a production program or an exploration program, we've not made that decision yet of where that rig would go.

Okay. And if I could take it up to a high level John, you mentioned having to define how your future development outlook will shape up in some and present by how much capital you need to spend, you mentioned Bakken, you mentioned Pony. And you mentioned keeping a strong balance sheet. Obviously, that's a both, is actually development programs. Does that mean that you keep pressing ahead with the exploration as a primary focus of the value add that has generate. And think more about less spend on development and slowdown of development. And within that question John, if you could also just define strong balance sheet for me, so that I can have a good idea of how to model there? Thanks.

Sure. On the exploration side, now exploration is a key component of our strategy going forward. Looking at our global portfolio of opportunities and high-grading them. So we're going to be financially disciplined and technologically disciplined as well, in terms of which projects we pick next year. The good news is we have a healthy inventory to pick from, but we're going to be disciplined about how much we have an appetite for. So, I would say in the normal course, we are still committed to having exploration be a key component of future resource growth. And in terms of how we think about our capital structure and our funding, obviously, as you look at the first two quarters, we had slight deficits capital spend versus cash generated. It's certainly manageable, but as our spending will step up for things like the Bakken and Pony once they are further defined, we want to make sure all options are on the table to make sure we keep a strong investment grade. Meaning, not lower than more the ratings that we have now and hopefully leaning forward to where they will strengthen with the passage of time.

That's just great. Thanks very so much. I need to consider about one question a quick follow-up. We had an interesting discussion John, about price elasticity of U.S. Gasoline demand and how people behave to your service station networks in terms of filling up tanks completely and other observations that you had about that subject. If you could just give us the latest on how you're seeing demand in your system that would be great. Thanks.

Good question. I obviously, gasoline prices are lower this year. So you would think the volumes would go up accordingly and while I think we get our fair share of business from competitors because of the value proposition and customer service that we differentiate ourselves with, I think what's going now is overwhelmed in terms of the income effect versus the price effect. And when I say income effect, the fact there is 9.5% unemployment in the country. People are being more conservative with their personal expenditures. And I think that we're seeing that in terms of our retail chain the fact that gasoline volumes are still down year-versus-year on a per site basis. So I think it's much more the economy. I also think that in the Northeast the lousy weather we've had last several weekends when summer driving should be peeking it's not so you have weather effect to go along with the income effect that's hurting the gasoline volumes.

Yeah. I understand but the DOE data level we do see gasoline demand up year-over-year, you're saying that your reliance of the fact that you're price competitive, you're still seeing year-over-year declines?

Yeah. That's right. And I think it's the two issues that I talked about one is effect for consumers and the other weather effect in the Northeast.

And finally if could you put a number on that, is it down 1%, 2% or3%?

Well the number that we mentioned earlier in the speech that I gave, I want to make sure it's the same number that I'm giving you now. It's down 4%.

Excuse me, I missed that. Thank you.

Thanks.

(Operator Instructions). And our next question will be from the line of Paul Cheng. I am sorry, Neil McMahon from Sanford Bernstein. Please proceed.

Hi, just few quick questions again, sorry along the exploration front. In Ghana and what happened about the future activities there. It seems like the main players in Ghana, Anadarko are moving further west along the coast. What are your plans there? Do you know enough about the strata-graphic traps and natures of the geology to start going along that as well or are you going to wait for the first well to be drilled or second well, I should say to be drilled in your block?

No, I think again we're in the phase of reprocessing the seismic to figure out where we want to drill. So I think its early days to be talking about, where we're thinking about drilling or how it reflects, what teller and the other partners are doing, so it's just way too early Paul to be talking about that.

It's Neil actually.

Neil sorry.

But it's rather than going tom Sierra Leone and Liberia and places like that, have you considered that yet?

No, we haven't Neil. No comment on that.

Just one final one back on Brazil. Have got any scope at all in your thinking given the fact that its been sort of voyage of discovery on BM-S-22 so far to go after a fourth well, and we're talking about a third, but that has all being figured out to make sure you've drilled all the potential prospects on the block?

No I think Neil again as John said in his opening comments. I think we just got a lot of seismic core. We got several hundred feet of core to go through, from the last well. Extensive seismic core data, MBT data, all kinds of data that we need to evaluate. And the one thing I'm excited about is we actually have physical rock now tie it to the size mix. So we'll be doing am awful lot of work over the next six to nine months, trying to understand what we have and then figure out where to drill the next well. So I think to be preliminary to talk about a fourth wealth. Our focus is really going be now on where do we drill our third well.

Okay, great. Thank you.

Yeah.

Thank you. Our next question will be from the line of Mark Flannery, from Credit Suisse. Please proceed.

Hi, yes. I'd like to talk a little bit specifically about the international upstream tax rate. I know John you just gave us a blended tax rate guidance of about 50%. Could maybe just talk about how sensitive the international tax rate is? Say to commodity prices or if you prefer if there's no change in commodity prices from here to the end of the year, what would you expect that international tax rate to look like?

Sure. First of all it's very sensitive to commodity prices. You saw the first quarter and the way our tax rate performed in there and that's just because Libya becomes a bigger part from a pre-tax standpoint in our portfolio and it just drives up the rate, just pure mechanics. So again the guidance that I gave earlier which is overall blended rate was assuming that commodity prices stayed in this range. So from an in international standpoint I would just tell you that versus the 50% it will be a little higher than 50%. So obviously the U.S rate being below down at that 38% international rate we see being just slightly higher than the 50% for the next six months. However, again I would tell you if I'm looking -- what I looking at right now in the third quarter if things can change with lifting I would tell you the third quarter rate would be a little bit below that and the fourth quarter would be a little bit higher.

Okay. And this is a sort of semi follow on. The lifting I'm sorry if you answered this before but the overlift in the second quarter, do you expect that to be balanced up by an underlift in the third or was it balancing of the first quarter underlift?

For the -- well, let's just say in the second quarter it was almost for $3 million barrels overlift. For the first half of the year we're a little over 2 million barrels over lifted. We don't forecast how these will turn around again because it's very easy that lifts can slip at quarter ends. So what I would tell you is this should normalize overtime. It will normalize overtime but, it's clearly not going to reverse all in one quarter and so this will happen overtime and I won't be able to give you exact forecast on that.

Okay. Thank you very much.

Sure.

Our next question will be from the line of Paul Cheng from Barclays Capital. Please proceed.

Hi, hey guys. Maybe this is for Greg. Greg, you've been joining the company for several quarter now. Have you finished with your review of the entire E&P portfolio in organization and if you have done so, any shift or change in the strategy or that the focus that you may come along?

Yeah, Paul. So thanks for the question. We're in the middle of our portfolio review and analysis right now. What I will say there's not going to be a change in strategy. I mean, our strategy is to continue to grow reserves in production at 3% and so that is where we're headed VP. We are doing a detailed portfolio analysis and whether the mix changes or whatever it's just too early to say.

Okay. And Greg, I know that it's early day in the BM-S-22 you have drilled two well, can you share with us what you may have learned from those two wells so far?

Yeah, Paul. Again I just refer you back to our comments before I think we have an awful lot of data to sort through and as I said I'm excited about the amount of data we do have particularly physical lot data so we can tie that now to the actual seismic lines and reprocess all the seismic and figure out where the next well should be. So again I'm very excited about the data we have and just what it means in terms of next steps and where we go next.

Breaking out Exxon finished their negotiation with ANP on the evaluation based terms here?

We're currently still in discussions with the ANP and I'd refer to the operator for a specific questions about that.

Okay. And can we follow up though maybe you could give us an update, if there's any update at all, on the West Met appraisal? And the development option?

Yeah. For West Met, again we're still I believe in the last call we commented, we're in the midst of development studies. On West Met, we're still in the middle of those development studies. So we've made no decisions yet, in terms of where the next drilling is going to be.

Okay. This is probably for you to John Hess or John Rielly. John, on the -- I know note you don't normally don't give estimate that far but in 2010, any the kind of the direction of your capital budget may look like is it going to be higher than this year about the same or lower? And secondly, for John Rielly, I think previously that you have given a full year unit cost estimate for the cash cost and DD&A, any change on those number before?

Yeah, Paul as you know our practice is to give guidance for 2010 spend at the end of the year at the beginning of 2010. So I would wait till that. We're still in definition mode there. Obviously we were signaling that in area we're looking at beefing up some once the clarity of commodity pricing hopefully gets a stable base and gives us encouragement as the Bakken. If we make progress we're going to partners to the south and Knotty Head for Pony that something, that maybe we start to look forward. But the definition of that is still in the scope being and work phase so it would be premature to talk about any numbers there. So, we would look to the end of the year as the time for giving you an update on our spending, expectations for next year, at the end of this year.

John, you said at this point, it's more likely than not Pony is going to be unitized and developed together with the Knotty Head Partners or that you still think that you may go ahead and just do it on your own?

No, we continue to make progress and talking to our partners to the South. And we're cautiously optimistic that we will have a agreement with them because it's in both our interest to proceed that way. We are prepared to go alone but having said that, the talks are making progress for us to unitize. And we'll keep our fingers crossed that as we make progress there, we can finally bring it across the finish line.

And John Reilly.

Yes. I can give you the guidance for the unit cost. We did lower unit cost guidance on the first quarter conference call based on some cost cutting initiatives that we put in place. The cash costs we lowered to a 14 to $15 range and the DD&A was left at the 13 or $14, so overall unit costs of 27 to $29 for the year. And we're on track to achieve those at lower target guidance.

Thank you.

Thank you. Our next question will be from the line of Mark Gilman from Benchmark. Please proceed.

Hello guys. Good morning, I had a couple of things. The release, Greg referred to two dry wells in the Gulf of Mexico, could you be specific as to what they were please?

Yeah those two dry holes were okay operated by GP and total lake operated by Chevron.

Okay. So they were not your prospects?

No, they were not.

Okay. Could we get just a bit of an update on the Bakken in terms of individual well metrics and what kind of production level you saw in the second quarter please?

So on the Bakken we're averaging about little over 10,000 barrels a day right now. In the Bakken we've got about 130 operated wells, in the Bakken. And as I said before we're in a midst of formulating our development plans, but we're very excited about the opportunity that we do have up there.

How about well costs, Greg and reserves per well?

It's early to be talking about that because we're still really figuring out what we have, Mark.

Okay. If I could shift gears just a little bit Greg, I believe going back perhaps the first quarter call, you offered the observation at the time you thought the rock quality in the second well namely Guarani would be better than that what you saw in the initial well on BM-S-22. Was that in fact the case?

Well Mark, I think obviously we're disappointed that it was dry hole. So I think that tells you something. But once again what I'm pleased with is we did get an awful lot of core out of the well. So that allows me to tie core now directly back to the seismic and it'll give me a better sense of how the sub-surfaces is all hooked up in the various rock qualities. So that's what I'm exited about.

Okay. I just one more from me, it appears that in JDA you at least in the second quarter and I think in the first as well are selling at a level above contract quantities. I believe there is also some additional fields coming online in the near term in the JDA, should we assume that as a result there was in the context of comparatively weaker regional gas demand that it's likely your volumes will drop back to contract quantities, let's say over the second half of the year and into 2010?

Mark I think it's early to speculate on what's going to happen in the second half of the year in that part of the world. But you are correct; we had much higher quarter two gas nominations above our DCQ. So we're obviously pleased with the amount of production that's coming out of JDA.

Can you say anything about competing sources of supply and the timing and extent to which it's likely to have an impact?

No, I can't Mark, I can't really comment, I don't want to speculate on how the second half of the year might unfold in that part of the world. As you know the economies are higher again certain all around the world right now.

Okay. Thanks very much guys.

Thank you. Our next question will be from the line of Pavel Molchanov, from Raymond James. Please proceed.

Thanks for taking my question. Just another follow up about the Bakken end. You've previously given out a number of 230 among BOE estimated net resource. Do you have any update on that, at least directionally?

No, we don't. Again, we're in the middle of doing our development planning and studies right now. Really looking at all the 130 wells that we drilled and really trying to assess what is the development strategy going forward and how quickly do we want to develop this stuff. So as we, as that picture becomes more clear, we can give you more guidance when that work is done.

Got it. And as a quick follow up on a very different topic. Are you planning to participate in the second Iraqi licensing ground and if so, what are your generally thoughts on that process?

Yeah. We are in normal course competitive information like that we don't comment on.

Okay. Thank you.

Thank you. And our next and last question will be from the line of Kate Lucas from Collins Stewart. Please proceed ma'am.

Good morning gentleman. Could give us an update as to your current PSC related production sensitivity to oil price changes?

Sure. Again, we don't have there's nothing really significant from our stand point on the PCS aspect of it. We, with the higher prices coming in the second quarter, we did have some lower production resulting from it, but nothing that material. So from the standpoint of where we are today and where we see lets say strip pricing or anything like that, I think it's all baked into the guidance that John has gave you earlier.

Great. And then, if I can just follow up quickly on HOVENSA. Your crude utilization levels have averaged less than about 85% during the last three quarters and the FCC in it has been running below 75% since the first quarter of last year. Is this really a temporary decision related to the economics of the facility in the current margin environment or are we observing more of a strategic shift in the way that HOVENSA is being operated?

Very good question and its really the first supposition you made, which is, with the poor economic environment, its much better to run that refinery for yield and then it is to run for volume. So, the lower rates, we get better recoveries and it's much more driven from economics than anything else.

Great, thank you.

We now take one more question from Mark Gilman from Benchmark. Please proceed sir.

Yeah. Regarding, also regarding HOVENSA John, I noticed that the coker utilization in the second quarter was really high and I'm sure you don't to need me to say something about the relatively poor coker economics. We're seeing others cut coker utilization rates. Why nothing from you with respect to this?

The joint venture there obviously has their economic parameters and based upon the inputs of the prices that we get and the cost profiles that we get, we try to run it at the optimum rate. So I wouldn't want to dove into coker versus FCC versus crude units but basically, the general concept is with the poor economic environment much better run for yield than it is for volume.

Thank you. This concludes our presentation. We have no additional questions. We like to thank you for participating in the conference call. Ladies and gentlemen, enjoy the rest of your day.