赫斯 (HES) 2007 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2007 Hess Corporation earnings conference call. My name is Nicole, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS)

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

Thank you, Nicole. Good morning, everyone, and thank you for participating in our third-quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.

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

With me today are John Hess, Chairman of the Board and Chief Executive Officer; John O'Connor, 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 third-quarter conference call. I will make a few brief comments, after which John Rielly will review our financial results.

Our Company delivered solid operating performance in the third quarter of 2007. Our financial results benefited from strong crude oil prices and lower exploration expense, which more than offset higher production costs and weaker refining margins compared to those in the third quarter of 2006.

Exploration and Production generated net income above the year-ago quarter. Third-quarter 2007 crude oil and natural gas production averaged 357,000 barrels of oil equivalent per day, which was slightly above production for the same period last year.

In the fourth quarter, we forecast production to increase to approximately 390,000 barrels of oil equivalent per day as the result of recommencement of natural gas production from the Cromarty Field in the UK North Sea; start of production from the Snohvit Field in Norway and from the Genghis Khan Field in the Gulf of Mexico; completion of facilities work on various North Sea fields and the CATS pipeline system; ramp-up of crude oil production at the Okume Complex in Equatorial Guinea, which is on track to reach a net plateau rate of 40,000 barrels per day by the first quarter of 2008; and resumption of natural gas production from the Malaysia-Thailand JDA, which restarted operations on October 10 after a 50-day shut-in to install facilities required for Phase 2 development.

For the full-year 2007, we expect production to average between 375,000 and 380,000 barrels of oil equivalent per day.

With regard to exploration, we currently have two wells drilling in the deepwater Gulf of Mexico. The first is Bob North, which is a Miocene prospect being drilled on Mississippi Canyon Block 860. Hess has a 30% interest in the prospect, and we expect to reach TD during the fourth quarter.

The other well is Pony #2, in which Hess owns a 100% interest. Operations resumed last week after being temporarily suspended while the Ocean Baroness drilling rig completed a statutory Coast Guard ABS inspection. We expect to have results around year-end.

In the fourth quarter we will participate in two additional exploration wells. In the deepwater Gulf of Mexico, the Tubular Bells #3 well, in which Hess has a 20% working interest, spud on October 19 and is expected to be the final appraisal well on this discovery.

Also in December, we will spud the first of four initial wildcat wells on our 100% owned WA-390-P block in the Northwest Shelf of Australia. Each of the Australia wells is expected to take about 30 to 35 days to drill.

In September, we contracted for the new build StenaMAX III drillship for five years beginning in the middle of 2009. This rig will enhance our ability to execute our global deepwater exploration and development drilling programs.

Turning to Marketing and Refining, our financial results in the third quarter of 2007 were below those of the year-ago period. While operating performance was solid across our businesses, earnings were negatively impacted by lower refining and retail gasoline margins.

I will now turn the call over to John Rielly.

Thanks, John. Hello, everyone. In my remarks today, I will compare third-quarter 2007 results to the second quarter.

Net income for the third quarter of 2007 was $395 million compared with $557 million in the second quarter.

Turning to Exploration and Production, income from Exploration and Production operations in the third quarter of 2007 was $414 million compared with $505 million in the second quarter. Excluding the items affecting comparability in earnings, the after-tax components of the decrease in earnings are as follows.

Higher selling prices increased earnings by $64 million. Lower sales volumes decreased earnings by $86 million. Higher costs, primarily exploration expenses, decreased income by $36 million. All other items net to an increase in earnings of $15 million for an overall decrease in third-quarter adjusted income of $43 million.

The Exploration and Production effective income tax rate for the first nine months of 2007 was 50%. In the third quarter of 2007, our E&P operations were underlifted compared with production, resulting in decreased income in the quarter of approximately $30 million.

As indicated in the earnings release, third-quarter 2007 results include an out-of-period charge for the estimated cost of settling production imbalances at a Gulf of Mexico field and a North Sea field, resulting from adjustments to meter readings. Production imbalances were determined to exist between the Company fields and third -party producers using common transportation and production facilities. The estimated cost of settling these production imbalances amounted to $33 million after income taxes.

Turning to Marketing and Refining, Marketing and Refining earnings were $46 million in the third quarter of 2007 compared with $122 million in the second quarter. Refining earnings were $25 million in the third quarter of 2007 compared with $87 million in the second quarter.

The Corporation's share of HOVENSA's income, after income taxes, was $12 million in the third quarter compared with $49 million in the second quarter, due to lower refining margins. During the third quarter, the Corporation received a distribution from HOVENSA of $75 million.

Port Reading earnings were $10 million in the third quarter of 2007 compared with $35 million in the second quarter. Marketing results were $21 million in the third quarter of 2007 compared with breakeven results in the second quarter.

After-tax trading income was breakeven in the third quarter of 2007 compared with income of $35 million in the second quarter.

Turning to Corporate and Interest, net corporate expenses amounted to $28 million in the third quarter of 2007 compared with $32 million in the second quarter. After-tax interest expense was $37 million in the third quarter compared with $38 million in the second quarter. After-tax interest for the full year is currently anticipated to be in the range of 160 to $165 million.

Turning to cash flow, net cash provided by operating activities in the third quarter, including a decrease of $41 million from changes in working capital, was $863 million. The principal use of cash was capital expenditures of $735 million. All other items amounted to a decrease in cash flow of $45 million, resulting in a net increase in cash and cash equivalents in the third quarter of $83 million.

At September 30, 2007, we had $565 million of cash and cash equivalents. Our available revolving credit capacity was $2.618 billion at quarter-end. Total debt was $3.985 billion at September 30, 2007, and $3.772 billion at December 31, 2006.

The Corporation's debt-to-capitalization ratio at September 30, 2007, was 29.5% compared with 31.6% at the end of 2006.

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

(OPERATOR INSTRUCTIONS) Nikki Decker with Bear Stearns.

Good morning. I think I would like to start with your Gulf of Mexico program. You have made some comments in the past indicating that you would be a participant in the lease sale that occurred in the last quarter. Maybe you could bring us up-to-date on the results there.

Yes, we did bid on prospects that we identified as being effective to us in the Central Gulf lease sale, Nikki. We were pleased with the blocks we were awarded. I don't know if there is anything more I can add to that.

Well, perhaps, maybe you could talk about now that you have got your positions secure, maybe what further activity you plan at Jack Hays.

Jack Hays remains a tight hole. We are obviously doing quite an amount of work in the Western Gulf of Mexico. The Western Gulf lease sale was quite an active lease sale, and more work will be dependent on the context of the rest of our work program in the Gulf of Mexico, obviously.

John, when you talk about your participation in the lease sales, were you active in both or just the Western sale?

We were active just in the Central Gulf sale. We did screen through all of the opportunities that were available in the Western Gulf sale; but we did not identify any prospects that really met our threshold for bidding.

Okay, one more for me. You did not mention [Will-K] in your formal remarks. What is the status there?

We expect that the operator, BP, will secure a rig and will spud the well this quarter.

Great. Thank you.

Paul Sankey from Deutsche Bank.

Hi, good morning, everybody. You have reduced debt-to-cap over the course of this quarter. Obviously we've got the [uprights] running far ahead of expectations in Q4 today, keeping in mind also you have got a high leverage to light sweet crude prices. We know that in the past you have talked about growth as a focus for your investment.

If we were continue with this kind of price environment, would you -- could you talk a little bit about how you would spend the excess cash flow that would be implied in 2008? Thanks.

Good question, Paul. It is a little premature to make those sort of estimates on where prices might be. So with that as sort of a guideline, we continue to put the priority on investing our cash flow to grow our reserves in a financially disciplined and sustainable manner. The majority of our cash goes to that.

Obviously, these higher prices are giving us a little extra cash and improving our debt-to-cap as well. But I think it would be premature to say that there would be a strong call on that cash for other purposes outside of the organic growth program that we have, given that we are still finalizing our budget for next year; and it remains to be seen where these crude prices end up.

So right now, we're happy to have a little bit more liquidity, a little bit more cash on the balance sheet, a little stronger debt-to-cap ratio. But at the same time the majority of our cash flow is still being dedicated to our E&P program to grow our reserves.

But I guess the evidence here, John, is that you would be working first at paying down debt as a kind of excess cash flow destination.

You know, certainly continuing to improve our balance sheet, to improve our investment-grade rating is a top priority for the Company. But it definitely comes as a second one to the growth in our reserves. So the priority is still the growth in reserves.

Okay, that's great. If I could just have a follow-up, could you talk a little bit about your outlook for the UK gas market and your exposure to that? It is notable that you've got Cromarty, you mentioned in your comments, coming back on. Just any observations you've got would be interesting, and I will leave it there. Thank you.

Well, right now, obviously there has been a very strong rebound in UK gas prices, in part to some signs of winter coming and just the supply-and-demand fundamentals going into the winter.

We are very happy that Cromarty is back on, getting the current spot price, which is in the 50p range, and we are very happy about that. Where the market goes for the winter will depend very much on the weather.

Right now, it is very economic for us to produce that gas. If prices were to go down to the low levels of last year, we certainly would consider shutting the gas in again. So how long we produce Cromarty will very much depend on the market conditions that we are presented with.

Thank you.

Robert Kessler from Simmons & Co.

Good morning. It seems that EOG has raised the degree of attention paid to the Bakken shale recently. I don't think that you've got a direct in the Parshall field. But you do of course have a substantial degree of acreage up there. Can you comment about what sorts of initial production rates you have seen of late, and what your expectations are for that program going forward?

Robert, we would like to think that we were one of the first movers in the Bakken, quite frankly, as being one of the bigger and longer present operators in the Williston.

Just to recap for others who may not be familiar, we have a net interest in about 320,000 acres covering the Bakken Play. We currently have some 36 wells on production with three more completed and awaiting tie-in. So we will end the year with some 40 wells. We're currently running six rigs, and we would expect in time to see that number move to eight and then to 10 in a controlled and effective manner.

The issue of initial production rates is a somewhat complex one because different operators describe that differently. We tend to discuss an average 30-day rate as being the IP for the wells. They do vary from 300 barrels a day to in excess of 1,000 barrels a day. Currently, the average for all of our wells on production is some 300 barrels a day of 43 to 44 API crude.

Thank you for that. How might you describe the longer-term production profile decline rates after the initial first 30 days?

In aggregate, we see significant continuing production over time. We see an extended life for Bakken production net to us. After 30 days, the wells pretty much stabilize out and continue at that rate without significant deterioration after the initial period.

Thank you very much.

John Herrlin from Merrill Lynch.

Great. I've got a couple of quick ones. In Australia, how long will the well take to reach TD?

John, we think, obviously, being the first well that we will operate offshore Australia, we don't have a very good database. But the well plan calls for 35 days from spud to TD.

Great. Thanks, John. With Genghis, what is the current rate and what is the ramp on Genghis for you?

We're currently completing the second well on Genghis. There is just one well on production right now.

In terms of a performance of the well or wells, I would frankly, John, leave it to BHP, the operator, to comment on that, rather than us commenting in advance of them.

Okay, next one for me is on Pony. Have you drilled out the plugs yet? Where are you in terms of restarting?

We have not. We have pulled the storm packer, but we have not drilled the plugs out yet. So I'm still confident that we will see TD in this well by year end. But the intermediate steps are a little less clear.

Okay, regarding the Central Gulf of Mexico sale, you guys kind of got outbid on a lot of things. Are you seeking to partner, since you had a lot of other competitors interested in the same plays?

You know, there is a degree of knowledge that is compatible with other people who have secured blocks that we were interested in. It would be surprising if we didn't have conversations with respect to sharing both knowledge and equity in some of the prospects. So yes, I think those discussions will be ongoing, John.

Okay, last one for me is on marketing. Any sign with prices running back up on gasoline that demand is waning at all?

No. You know, both outside for gasoline and inside for the C-stores we are pretty consistent even at this time of our same-store sales being up 2% year versus year.

As you know, John and people on the call, while crude prices have run up quite a bit, gasoline is actually down since April. So the retail price is not seeing the full impact of the crude price as of yet.

Great, thanks very much.

Paul Cheng from Lehman Brothers.

Hi, good morning, gentlemen. I have several quick ones. This is for John Reilly. John, you mentioned that in the third quarter you have a 30 million underlift position. Is that -- that is for the third quarter. As of the end of September, do you underlift, or do your overlift, or balance?

So for the quarter, correct, we underlifted production just under 1.4 million barrels in the third quarter. The top three countries that were underlifted were Norway, EG, and Gabon.

For the full year, we are actually -- if you're asking for year-to-date through September 30, we are actually underlifted in the 3 million barrel range. Now, this doesn't mean that our inventory position is out of line. We just came into the year with lower inventory balances at that point. So we have just been underlifting production in the normal course.

Just in general for guidance for the fourth quarter, we don't see any significant overlift or underlift right now. So based on, as John said earlier, 390,000 barrels per day production, we see us coming in with sales volumes around that number in the fourth quarter.

Okay. John, what is the meter adjustment? Is it related to the period early this year, or it is for prior years?

Predominantly for prior years, actually. Just a small piece in 2007.

Okay. This is for John O'Connor. John, I think in the second-quarter conference call, at the time the fourth-quarter production guidance you said in excess of 400. I think right now that you are talking about 390.

Is there any field that has come up lower than expected, or that the [country] has been a little bit higher than expected?

No, I don't think so, Paul. I think that probably the major impact is that the work at the JDA, the 50-day shutdown, while the bulk of the work planned to be completed then was completed effectively, there is another 20-day shutdown in the JDA for final tie-ins that will occur in December. That is something that was not forecast at the point in time that you mentioned. That really is the impact. In fact, I would (multiple speakers).

So there is another 20 days in December?

Another 20 days in December, that is correct.

During that 20 days, that means the JDA, that was shut-in totally or just partially shut?

No, totally shut-in.

Totally shut-in? Okay. John, I know it maybe is still early. Any [type] of drilling program that you can share with us for next year on the exploration front? I mean, how many wildcat wells that you're going to drill, or what kind of expense or capital that you may spend?

I would love to share that with you, Paul, but my staff would kill me, because they are still working this up. I have not seen it yet.

Okay, so I presume that we don't have anything on the CapEx for 2008 at this point. It is too early, right?

It is too early, Paul.

Okay. Final one for the Bakken shale [there], how many [do-able] prospects that you still have?

Oh, man. I mean --.

Then what is the inventory? Are we talking about for the next five years that you would continue drilling? How many wells that you are going to drill a year? (multiple speakers)

Yes, I see the annual drilling rate ramping up over the next five years, Paul. As I had mentioned earlier, we are currently running six rigs. We see the program going to 10, probably in a controlled manner, by around the end of 2009 or 2010.

So, there is absolutely no shortage of drilling locations. We will be very busy in the Bakken for the foreseeable future.

When we look at Bakken, then, if do the simple math, seems like it right now is about 10,000 barrels per day of production to you guys. When we look at by 2010, 2012, and you get to a steady 10-rig program, what kind of sustainable production that we may be talking about?

First of all, Paul, currently the net production to us from the Bakken is more on the quarter 4,500 barrels a day and of course increasing.

We are approaching this, as I said earlier in sort of a disciplined, controlled manner. Forward projections of the total program really won't be available in a sensible manner until about this time next year. So we are still determining optimum technologies for drilling and completion, for identifying sweet spots in the play as a whole. So a lot of moving parts still.

So, John, you are saying there is 4,500 barrels per day net to you, so that suggests that your average interest is roughly about 50%?

Well, it varies all over the place, Paul. In some locations it is higher than 90%, in others it is more like 50%.

Okay. Very good. Thank you.

(OPERATOR INSTRUCTIONS) Mark Gilman with Benchmark.

Hi guys, good morning. A couple things if I could, please. John O'Connor, do you have any guess-timate as to when the stepdown on the profit split on ACG is going to hit you? Is it around the middle of next year plus or minus?

Mark, really, what is happening with the stepdown on ACG -- and in fact, we say stepdown; what the PSC has is rate of return type triggers on the profit oil split. There's actually two triggers that will happen.

But really, we have got to leave that to BP. They're the operator. They will be working with SOCAR on that trigger. Again, anything we give you as far as our production guidance when we get in 2008 would encompass that and, again, should that trigger happen in 2008.

Okay, thanks, John. Secondly, it seems that there has been some positive results from recent [Foolhorm] drilling activity, suggesting there maybe some upside to previous estimates in the field. John O'Connor, any comment on that?

No comment, Mark.

Okay, I will try for strike three, John O'Connor. Has there been any success or attempt to renegotiate the pricing provisions of the West Med gas contract?

There is a lot of activity associated with the West Med ownership. We are currently shooting the multi-azimuth seismic. The operating company, now [Petco], has been established and staffed up. The contract for a front-end engineering design has been awarded; and the project engineering and design work has commenced at the contractor's UK offices.

The pipeline route survey offshore is very near completion. A location for the gas plant has been essentially agreed with the authorities. So a lot of progress there, Mark.

We think that combination of firm cost estimates together with commodity pricing understandings will come together in the first quarter next year.

Okay, I will call that a foul ball; which means I get one more.

Whoa, whoa, whoa, whoa.

When you acquired the interest in Genghis Khan, I think that at least in part it was motivated by drainage-related concerns and issues re Shenzi. How should we look at the profile of Genghis Khan versus the previously indicated plateau rate of 100,000 gross at Shenzi?

Very good question. I would say, just to add a little texture to your observation about why the acquisition of Genghis, I think it was first and foremost a clear profit opportunity at a point in time the equity interest became available to the Shenzi partners.

Secondly, there were a lot of synergies in terms of full understanding of reservoir management issues. Once you control the whole feature.

Thirdly, there was significant opportunity for cost reductions through elimination of redundant wells, both potential injectors and producers. So there was an ability to optimize take points on the feature, have a better understanding of the subsurface, together with a profit opportunity -- all three of which still remain valid today.

In terms of the impact on the plateau, I really don't know the answer to that, to be honest with you. But I would think that if the subsurface performs as we expect it performs, then we really have two production facilities on the same feature.

So we have the design capability for the TLP, elements of which will be installed through 2008; together with the ability to process the Western flank, if I could call it that, through the Marco Polo facility. So I think you would look at it at this stage as being additive.

Thanks, John.

I show no further questions at this time.

Okay. Well, thank you very much for attending our call, and we look forward to having you on our January call. Have a good day.

Thank you for your participation in today's conference. This concludes the presentation and you may now disconnect. Good day.