赫斯 (HES) 2009 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Hess Corporation's second-quarter 2009 earnings conference call. My name is Wayne and I will be your coordinator for today. At this time all participants are in listen-only mode. We will be facilitating a question-and-answer session toward the end of this call. (Operator Instructions)

I would now like to turn this presentation over to your host for today's call, Mr. Jay 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 risk 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 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 (technical difficulty). 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 (technical difficulty) quarter.

For the second quarter of 2009, Exploration and Production earned 250 (technical difficulty). Crude oil and natural gas production averaged 407,000 barrels of oil equivalent per day, which was nearly 4% above the year-ago period. Higher year-over-year production resulted primarily from the (technical difficulty) of Phase 2 volumes at the Malaysia-Thailand JDA and the ramp-up of the Shenzi field in the (technical difficulty), 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 390,000 to 400,000 barrels of oil equivalent versus our previously forecasted range of (technical difficulty) 390,000 barrels of oil.

With regard to Exploration, as was announced in early July, the operator of the Guarani well on block BM-S-22 (technical difficulty) 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 (technical difficulty).

On permit WA-390-P, Northwest Shelf of Australia, recently resumed exploration drilling. Over the next 12 months, (technical difficulty) plan to execute a 12-well program designed to further appraise the block. Hess has a 100% interest in permit WA (technical difficulty).

Turning to Marketing and Refining we've 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 (technical difficulty) light-heavy (technical difficulty).

Marketing results, while negative, were better than (technical difficulty) year-ago quarter, although retail marketing fuel volumes on a per-site basis were down 4%, (technical difficulty) 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 (technical difficulty) sustain growth in 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 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 short-lived fields located offshore UK. Excluding the items affecting comparability and earnings, the after-tax components of 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 overlifted 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's share of HOVENSA's 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 $19 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 employee severance costs. 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 principal 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 $1.063 billion of cash and cash equivalents at June 30, 2009, and $908 million at December 31, 2008.

Our available revolving credit capacity was $2.964 billion at June 30, 2009. Total debt was $4.313 billion at June 30, 2009, and $3.955 billion at December 31, 2008. The corporation's 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 will be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions) Doug Leggate, Howard Weil.

Thanks. Good morning, guys. Thanks for taking my question. A couple of things, one operational and one, I guess, big-picture on the debt structure in the Company.

Operationally, can you just talk a little bit about where you are in 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 Pluto, the LNG project down the line?

My follow-up 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 future development sanction projects, maybe later this year. I notice an absence of any reference to that this quarter. I just wonder if you could clarify where you stand on that, again as kind of a big-picture question. Thanks.

Okay, thanks. On the first question, it's early days to be talking about any commercial terms, really. We do have discussions ongoing with both Woodside and Shell, so it's 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, happy to give further clarification. Once we further divine our future development projects and growth projects, the Bakken being one, hopefully the Pony project as well, we'll have a better feel on our funding needs. 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 table. Some may be asset sales in the normal course of business; some may be diluting down some of the projects we have if that makes sense and they're defined enough; and another may be accessing the equity market. So we just want our shareholders to know that all options are on the table because, as you 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 that.

Evan Calio, Morgan Stanley.

Good morning, gentlemen. Thanks for taking my call. I had two general questions, the first regarding Pony. As you discussed in the prior calls, guys, the discussions with the Knotty Head partners on potential unitization of the blocks, is there any update on those discussions or general information on the cost or timing impact of potential unitization?

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. We are 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 is a strategy question. Is it fair to say there's been some modest shift in strategy, a shift towards unconventionals in the mix versus exploration with Bakken and potentially unconventional US gas going forward?

Greg, after spending time reviewing Bakken activities, can you give any update on pace of development going forward for your large position in the play? Thank you.

I wouldn't say there is a strategic shift. However, we do know we are very pleased, as you know, with our position in the Bakken. So I think that will 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 acreage, etc.

So when we have those development plans done, we will share more information about the Bakken; but we are very pleased with what we have and we're anxious to get moving on the Bakken.

Thank you.

Arjun Murti, Goldman Sachs.

Thank you. I think you mentioned on the exploration program the Australia wells. 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 had any comments on those three areas, thank you.

Okay, so for the go-forward exploration program, as you know 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 newbuild drill ship called the Stena Forth 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 test on our discovery last year and also a next appraisal well in Libya.

Regarding Brazil, as John mentioned in the call upfront, we've got an awful lot of core data, seismic data, and log data to go through to determine next steps on a third well in Brazil. So it's early days to be talking about when we might drill a third well in Brazil.

Regarding the farmout of the rig to PETRONAS, I would encourage you to just refer that question to ExxonMobil.

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

Ghana, we're still evaluating all the seismic and trying to figure out when we may drill the next well. So I 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 Tubular Bells and where that development potentially stands?

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

That's great. Thank you.

Robert Kessler, Simmons & Company.

Good morning, guys. A couple of accounting-related questions if I can. The first on BM-S-22. If I recall correctly you have 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 leave that capitalized or held in suspension. Is there any sort of one-year, two-year time out on that, in which case you might have to expense it?

Then secondly, on tax rates, curious if you have an update on your expectations going forward, in particular on international E&P taxes.

Sure. On the first one, with the well, you are correct. The first well is capitalized and the second well, as John Hess mentioned earlier, has been expensed. Greg just mentioned that we've got a lot of log and core data that we'll be reviewing right now as well as combining it with all our seismic information to determine a location of the third well.

What the accounting rules are is just based on the notice of discovery that we filed on the first well and our continuing studies. We can leave that well capitalized. What it is, is just part of the evaluation to determine a commercial development.

So there is no real hard and fast timing cutoff for expensing a well. It's just going to become part of our normal operation there in Brazil as we evaluate BM-S-22.

As far as the tax rate, we did have a lower tax rate than expected or from a guidance standpoint in the second quarter. It really had to do, as I mentioned earlier, we had an overlift in the second quarter. The significant areas that had the overlift were West Africa, which was EG and Gabon, that have lower tax rates than our overall 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 where the liftings 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 and on the mix of income. Right now I'd 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. Thanks very much.

Paul Sankey, Deutsche Bank.

Hi, everyone. If I could keep drilling down into the exploration program, if that's the right way to think of it. It sounds as if the Libya well will be before the end of the year. I've heard what you said on Ghana. I've heard what you said on Brazil. I believe that you've got a couple of other wildcats, possibly Gulf of Mexico and non-subsalt Brazil.

Could we just round that out with a particular idea of what you are going to be drilling this year? Thanks.

Yes, the only one I haven't mentioned -- so thanks for bringing that up -- is we are drilling a post-salt well in the Espirito Santo basin in Brazil. So that's the only well that 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 have not made that decision yet on where that rig will go.

Okay. 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 terms of then deciding how much capital you need to spend. You mentioned Bakken. You mentioned Pony. And you mentioned keeping a strong balance sheet.

Obviously, those are both essentially development programs. Does that mean that you keep pressing ahead with the exploration as the primary focus of the value-add that Hess can generate? And think more about less spend on development and selldown of development?

And within that question, John, if you could also just define strong balance sheet for me, so I can have a good idea of how to model that. Thanks.

Sure. On the exploration side, no, exploration is a key component of our strategy going forward. You know, looking at our global portfolio of opportunities and high-grading them. So we are 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 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 is 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 the ratings that we have now and hopefully leaning forward to where they will strengthen with the passage of time.

That's great. Thanks so much. I'm going to consider that one question. A quick follow-up. We had an interesting discussion, John, about price elasticity of US gasoline demand and how people behave through your service station network 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 are seeing demand in your system, that would be great. Thanks.

Yes, good question. 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.

When I say income effect, the fact that 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 the last several weekends, when summer driving should be peaking, it's not. So you have a weather effect to go along with the income effect that is hurting the gasoline volumes.

Yes, I understand that. But at the DOE data level we do see gasoline demand up year-over-year. Are you saying that you're -- allowing for the fact that you are price competitive, you're still seeing year-over-year declines?

Yes, that's right, and I think it's the two issues that I talked about. One (multiple speakers) effect for consumers, and the other the weather effect in the Northeast.

Finally, could you put a number on that? Is it down 1%, 2%, 3%?

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.

(Operator Instructions) Paul Cheng -- I'm sorry, Neil McMahon, Sanford Bernstein.

Hi, just a few quick questions, again -- sorry -- along the exploration front. You are in Ghana and we heard about the future activities there. It seems like the main players in Ghana, Tullo and Anadarko, are moving further West along the coast.

What are your plans there? Do you know enough about the stratigraphic traps and natures of the geology to start going along that ridge 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 it's early days to be talking about where we're thinking about drilling or how it reflects what Tullo and the other partners are doing. So it's just way too early, Paul, to be talking about that.

It's Neil, actually, but it's --

Neil, sorry.

What about going to Sierra Leone and Liberia and places like that? Have you considered that yet?

No, we have not, Neil. No comment on that.

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

I think, Neil, again, as John said in his opening comments, I think we have just got a lot of seismic core. You know, we've got several hundred feet of core to go through from the last well. Extensive sidewall core data, MDT data, all kinds of data that we need to evaluate.

The one thing I am excited about is we actually have physical rock now to tie to the seismic, so we will be doing an 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 it would be preliminary to talk about a fourth well. Our focus is really going to be now on where do we drill the third well.

Okay, great. Thank you.

Mark Flannery, Credit Suisse.

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 you maybe just talk about how sensitive the international tax rate is, say, to commodity prices?

Or if you prefer, if there is 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 rates. Just pure mechanics.

So again, the guidance that I gave earlier, which is an overall blended rate, was assuming that commodity prices stayed in this range. So from an international standpoint I would just tell you that versus the 50% it will be a little higher than that 50%.

So obviously the US 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 look at right now in the third quarter -- but things can change with liftings -- 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 a 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 out by an underlift in the third? Or was it balancing of first-quarter underlift?

For the -- let's just say in the second quarter it was almost a 3 million barrel overlift. For the first half of the year, we're a little over 2 million barrels overlifted.

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, that this should normalize over time. It will normalize over time, but it clearly is not going to reverse all in one quarter. So this will happen over time and I won't be able to give you the exact forecast on that.

Great. Thank you very much.

Paul Cheng, Barclays Capital.

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

Yes, Paul. So thanks for the question. We're in the middle of our portfolio review and analysis right now. I think what I will say is there's not going to be a change in strategy. I mean, our strategy is to continue to grow reserves and production at 3%.

So that is where we're headed with E&P. We are doing a detailed portfolio analysis; and whether the mix changes or whatever, it's just too early to say.

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

Yes, Paul, again, I just refer you back to our comments before. I think we have an awful lot of data to sort through. As I said, I'm excited about the amount of data we do have, particularly physical rock 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.

Is Exxon finished their negotiations with ANP on the evaluation phase terms yet?

They are currently still in discussions with the ANP, and I would refer you to the operator for specific questions about that.

Okay. Can you talk about, maybe give us an update -- if there is any update at all -- on the West Med appraisal and development option?

Yes, for West Med, again we're still in the -- I believe, in the last call we commented we're in the midst of development studies on West Med. 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 either for John Hess or John Rielly. John, I know you guys normally don't give an estimate that far out. But in 2010, any kind of a --the direction of your capital budget may look like? Is going to be higher than this year, about the same, or lower?

And secondly for John Rielly, I think previously that you have give a full-year unit cost estimate for the cash costs and DD&A. Any change from those numbers before?

Yes, Paul, as you know, our practice is to give guidance for 2010 spend at the end of the year, the beginning 2010. So I would wait till that. We are in still in definition mode there.

Obviously, we were signaling that an area we are looking at beefing up some, once the clarity of commodity pricing hopefully gets a stable base and gives us encouragement, is the Bakken. If we make progress with our partners to the South, Knotty Head for Pony, that's something that may start to move forward. But the definition of that is still in the scoping 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 a time for giving you an update on our spending expectations for next year -- at the end of this year.

John, you say 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?

Yes, no, we continue to make progress in talking to our partners to the South, and we're cautiously optimistic that we will have an 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 Rielly?

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

Thank you.

Mark Gilman, Benchmark.

Guys, good morning. Had a couple things. The release, Greg, refers to two dry holes in the Gulf of Mexico. Could you be specific as to what they were, please?

Yes, those two dry holes were Will K., operated by BP and Turtle Lake, operated by Chevron.

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 a 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 the 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 is 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 to the first-quarter call, you offered the observation that at the time you thought the rock quality in the second well, namely Guarani, would be better than that which you saw in the initial well in BM-S-22. Was that in fact the case?

Well, Mark, I think obviously we're disappointed that it was a dry hole. So I think that tells you something, hm?

But again, what I am 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 will give me a better sense of how the subsurface is all hooked up and the various rock qualities. So that's what I'm excited about.

Okay. Just one more for 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 thereof 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 highly uncertain all around the world right now.

Okay. Thanks very much, guys.

Pavel Molchanov, Raymond James.

Thanks for taking my question. Just another follow-up about the Bakken. You have previously given out a number of 230 MMBOE of 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 that picture becomes more clear, we can give you more guidance when that work is done.

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

In the normal course, competitive information like that, we don't comment on.

Okay. Thank you.

Kate Lucas, Collins Stewart.

Good morning, gentlemen. Could you 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 standpoint on the PSC aspect of it. With the higher prices coming in the second quarter, we did have some lowered production resulting from it, but nothing that material.

So from the standpoint of where we are today and where we see, let's say strip pricing or anything like that, I think it's all baked into the guidance that John Hess gave you earlier.

Great. Then if I could just follow up quickly on HOVENSA. Your crude utilization levels have averaged less than about 85% during the last three quarters; and the FCC unit 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 and the current market environment? Or are we observing more of a strategic shift in the way that HOVENSA is being operated?

Very good question and it's really the first supposition you made, which is with the poor economic environment it's much better to run that refinery for yield than 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.

Mark Gilman, Benchmark.

Yes, also regarding HOVENSA, John, I noticed that the coker utilization in the second quarter was really high. I'm sure you don't 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 at the optimum rate. So I wouldn't want to delve into coker versus FCC versus crude units; but basically the general concept is with the poor economic impairment much better to run for yield than it is for volume.

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