Murphy Oil Corp (MUR) 2009 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome the Murphy Oil Corporation third quarter 2009 earnings call. (Operator Instructions) This conference is being recorded today, Thursday, November 5, 2009.

I would now like to turn the conference over to Mr. David Wood. President and Chief Executive Officer

Hello everyone. Thanks for joining us on our call today. With me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer, and John Eckhart, Vice President and Controller, Mindy West, Vice President and Treasurer, Dory Stiles, Manager of Investor Relations and Craig [Vonsil] Supervisor of Investor Relations. I will now turn the call over to Dory.

Thanks, Dave. Welcome one and thanks for joining us today. We will follow our usual format with Kevin beginning by providing a review of third quarter, 2009 results. David will then follow with an operational update after which questions will be taken.

Please keep in mind that some of the comments made during this call will be considered forward-looking statements. As defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur, or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors see Murphy's 2008 annual report on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Kevin for his remarks.

Thanks, Dory and welcome everyone. Net income for the third quarter of '09 was $188.9 million or $0.98 per diluted share. This compares to net income for the third quarter of '08 of $584.4 million or $3.04 per diluted share. For the nine months of '09 net income was $518.8 million, or $2.70 per diluted share. Compared to net income for the nine months of '08 of $1.61 billion or $8.39 per diluted share. The 2009 nine month period included $97.8 million or $0.51 a share of income from discontinued operations, which was mostly related to a gain on the sale of our operations in Equador in March. 2008 nine month period included after tax gains from the sales of Canadian assets, this consisted of our interest in.[Britana Energy] and the Lloydminster heavy oil property of $108.3 million or about $0.57 a share.

Looking at the net income by segment, in the E&P we had net incomes from continuing operations in the third quarter of '09 of $184.1 million this compares to net income from Continuing Operations in E&P in the third quarter of '08. of $530.5 million Lower earnings for the 2009 quarter were mostly attributable to significantly lower crude oil and natural gas price realizations. Crude oil and liquids prices averaged $61.13 a barrel in the third quarter of '09 versus $112.55 last year. North American natural gas prices averaged $3.01 per mcf this year compared to $11.51 last year. Crude oil and gas liquids production from continuing operations for the current quarter was a little over 131,600 barrels per day as compared to approximately 111,700 barrels per day in the corresponding 2008 quarter, up almost 18%.

The increase was primarily attributable to reduction from Kikeh, offshore Malaysia which was ramping up throughout 2008 and also new production at two fields that started up this quarter, Thunder Hawk in the Gulf of Mexico and Azurite off shore the Republic of Congo.. Sales volumes were up almost four fold at 182 million cubic feet per day in the third quarter of '09 compared to 46 million per day in the third quarter of last year.. This increase was primarily due to production at Tupper and Western Canada and at Kikeh. In the downstream segment net income in the third quarter of '09 was $37.2 million this compares to net income in the third quarter of '08 of $85.8 million.

In North America, an earnings decline of approximately $45 million was mostly due to weaker US retail margins while the UK earnings reduction of about $3.5 million was mostly attributable to lower refining margins. In the corporate sector, we had net after tax charges in the third quarter of '09 of $32.4 million and this compares to net after tax charges third quarter of '08 of $31.3 million. Lower interest income on invested balances in the '09 quarter were largely offset by lower net interest expense and lower foreign exchange losses when compared to the third quarter after '08. As of September 30, 2009, Murphy's long-term debt was approximately $1.48 billion or . 17.6% of total capital employed. I have a couple of other things I would like to mention.

First, as you know, last month the US Supreme Court refused to review the decision of the Fifth Circuit Court of Appeals whereby Kerr-McGee was held not liable for royalties when oil and/or natural gas prices exceeded thresholds on certain deepwater leads within the Gulf of Mexico. Murphy actually paid royalties on similar leases when the benchmark levels were exceeded. In October of this year we filed a refund claim of $244 million plus interest. Nothing was booked during the third quarter to reflect this claim. Nor was the claim included in our estimated net income range for the fourth quarter.

This benefit to income net of any applicable income tax effects will be recognized when the department of interior provides appropriate evidence that our refund request will be honored. Additionally, fourth quarter earnings projection of 75 to $0.90 per share does include a lifting at Kikeh which is currently scheduled for late December.. Should this listing be delayed for any reason Into 2010, earnings for the quarter would be reduced by a little over $0.07 per share. With that I'll turn it over

Thanks, Kevin. Results from the third quarter were favorably impacted by improving crude prices. On the other hand, the North American natural gas market has not fared well this year at all. We have used the low cycle entry point to establish strong positions both at the [Montly] play at Tupper in British Columbia and more recently, the Eagleford play in South Texas. We see this as a complementary to our long historic waiting to crude which over time will remain. Over the medium and long term we see strength in North American gas business, and with these steps have started to position ourselves. Looking at the highlights from the third quarter, many things stand out including the startup of three major development projects. Thunder Hawk in the Gulf of Mexico, Azurite, offshore Republic of Congo and Sarawak natural gas off shore Borneo Malaysia .

Also, the drilling of successful appraisal wells at,[Surrender and Permis] offshore Sarawak as well as Siakap north and block K Malaysia. The spuding of our first well on our Eagleford shale acreage, respectable US retail performance, and work towards finalizing the acquisition of our new ethanol plant. I will now walk through the individual segments of our business and further elaborate on the previously mentioned activities beginning with E&P. Concurrent with starting up three fields in production we have been moving forward in the evaluation process of other recent discoveries. Offshore Sabah Malaysia our Siakap north discovery where we have 80% and is located in block K has been successfully appraised with two additional wells.

The path forward to development will likely include a unitazation process with an adjoining block. Development options continue to be evaluated and I suspect we will be moving forward towards sanction here before too long. Offshore Republic of Congo in the (inaudible) block, the first appraisal well at Turquoise Marine where we have 50%, did not yield commercial qualities of oil in the same horizon as the discovery well but pay was encountered in a shallow horizon not previously penetrated. We will further appraise this discovery next year by testing the remaining (inaudible) on this feature.

Turquoise and the surrounding prospects present promising add-ons to our currently producing Azurite field that lies just 17 miles to the south. In the Gulf of Mexico, the Samurai oil discovery in Green Canyon in block 432 where we hold a one-third working interest is scheduled to be appraised in the second quarter of 2010. Tieback options are being looked at here also. Of the five exploration wells spud during 2009, four were discoveries, three of which found oil. While I wouldn't classify any as home runs, they do provide growth momentum and I'm pleased with the distribution mix.

We will close out 2009 by drilling two more exploration wells, one of which is in the Eastern Gulf of Mexico, a DC4 located in DeSoto Canyon block four as a natural gas prospect located in 5800 feet of water. We own a 64% working interest and will operate the well. The location is near our operated Dalmatian natural gas discovery. The other exploration well is at Siakap in block K Malaysia. as a follow up to our recent success on the separate feature, Siakap north. On-shore US we are in the midst of a three well drilling program that will extend into next year and marks our initial Eagelford shale drilling in south Texas. The first well is nearing total depth and testing should be completed within a month. We are continuing to acquire acreage and moving towards 200,000 net acres in the play. These are early days for us but our acreage is well situated and has good promise. I will now move to production.

Sarawak natural gas commenced production on September 17th and has had some surface startup issues that have delayed our planned ramp-up thus reducing third quarter volumes and necessitating a downward revision of our forecast for the fourth quarter. This is especially unfortunate as the subsurface results and flows have been better than planned. We're fully focused on getting this project back on track. Kikeh associated gas is still short of expectations but improving. Fourth quarter production for the company is now estimated to be 193,000 barrels of oil equivalent per day, down from our previous estimate of 210,000 barrels of equivalent per day. This still compares favorably to the third quarter 2009 average production rate of 162,000 barrels of oil equivalent per day. As for an exit rate for the month of December 2009, production should near 208,000 barrels of oil equivalent per day.

Aside from our Malaysia natural gas the remainder of the portfolio is performing well and at budget. Worldwide, crude production has been strong. Thunder Hawk where we have 37.5% in Mississippi canyon block 734 has been averaging about 37,000 barrels of oil equivalent per day gross. Offshore the Republic of Congo, the Azurite field where we have 50% is producing nearly 15,000 barrels of oil per day from the first well.. Additional wells are being batch drilled and will come on stream later this year. As with any new technology, there have been some growing pains with the FDPSO but reservoir performance has been much better than expected. We had our first Azurite lifting in mid-October with the crude price.less than $3 below (inaudible)

In Malaysia, Kikehed gross oil production continues around 116,000 barrels of oil per day. In British Colombia, Canada, Tupper natural gas production volumes have been averaging, 80 million cubic feet per day right at our current gas plant capacity. Plans to reconfigure the plant to achieve volumes over 90 million cubic feet per day are being finalized as we have such strong well performance. All of our existing production comes from Tupper main area right now. During the third quarter, we sanctioned Tupper west, the next phase in the development of our overall acreage. Production there should commence in the second quarter of 2011, utilizing 180 million cubic feet a day new build gas plant. Well testing has been very positive in Tupper west. It should be long lived contributed to production and a real winner for us.

In our downstream business, not surprisingly retail in the US was a key performer during the third quarter. Retail margins began and ended the quarter on high notes. Margins were somewhat mixed in between. Crack spreads remain weak both in the US and the UK and asphalt sold from our Superior system was one of the few bright spots in refining during the quarter. To day the Meraux refinery is operating at 110,000 barrels per day while Superior refinery is running at 34,000 barrels per day.. Milford Haven, our UK refinery is currently running near 103,000 barrels per day. Refining margins during October were weak. Turnarounds are planned at both Meraux and Milford Haven during the first quarter of 2010.

In US retail, we now have 1,038 retail outlets in operation, made up of 993 Murphy USA sites and 45 Murphy express sites. While merchandise margins have been good in October, fuel prices have not. As the escalation in crude price led to higher wholesale prices. Weak refining plus weak retail equals a weak downstream outlook for the fourth quarter we announced yesterday. On October 1, our purchase of an ethanol plant located in [Hankenson,] North Dakota was completed. Within days the facility began grinding corn and was making ethanol within the week. The facility has an annual production capacity of. 110 million gallons We view this entry into the biofuels business as an add-on to our North American fuels business where we sell almost 3% of the nation's gasoline and have mandates with fuel additive. The state of the art Hankenson plant was acquired at a favorable price and most importantly has the potential to make returns which it is doing today by the way.

I have been very impressed with the entrepreneurial spirit that both led to the acquisition and has exhibited by our new employees at the plant. For the balance of the year we will finish ironing out a few wrinkles in our production and complete our 2009 drilling program. We will also be finalizing our capital spending plans for 2010 including next year's exploration program that I expect to be more active than 2009, which was impacted pretty heavily by the precipitous fall in oil prices. Focus areas for exploration next year will include wells in the Gulf of Mexico, [Surinam], Republic of Congo, Malaysia and Indonesia. Australia drilling will likely be pushed into 2011 as we continue our predrilling work next year. In refining our focus is on operations ahead of the scheduled turnarounds in the first quarter. In retail we have picked up the pace a little on site construction and anticipate that to continue next year as well. That ends my prepared remarks. I'm happy to take

Thank you. (Operator Instructions) First question is from the line of [Evan Calio] with Morgan Stanley.

Good morning, guys, how are you doing or good afternoon. I'm good. So I have a follow-up question on the production guidance. I know you identified primary related to Sarawak gas, above ground issues. Can you provide an exit rate there into year-end and expectations for volumes into 2010 or even more color on what you guys are doing to get that back on track.

Yes, Sarawak gas, we had some very good results in the drilling and in the flowing of the wells and the productive capacity from the offshore facilities is 300 million plus. The issue for us is on the onshore receiving facility and in just delving down into the specifics, the real issues is with the rental compressors that we have and a particular piece of equipment that relates to each of those compressors, so it's uniform throughout all of the setup there and once we got started up we realized we had a problem.

We took the facility down for a few days and are now back up. I think today's production's about 140 million a day. And I would think we would be well north of 200 before the end of the month. And assuming that we don't have a repeat of these issues, which I don't think we will, we'll be getting back to where we need to be here pretty handily. So those are the reasons why production was down in that one particular case.

That's great. Different question on underlift issue. I heard Kikeh lifting due in December. I presume that's included in your sales at 184 for the quarter, and I know you underlifted in the third quarter and are projecting underlift in the fourth quarter. Could you quantify your net underlift and how we think these will unwind?

Yes, it just so happens that when we look at our lifting position, we have a whole bunch of fields that all put us in that same position, so when they add up together, if I look at the list here, we're at 300,000 barrels behind at Kikeh, 380,000 barrels behind at West Path, 240,000 barrels behind at Azurite. Normally all those things don't happen at the same time. They just happened to coincide here. So in the grand scheme of things, looking back at the data, we generally are not more than one lifting out of balance. This just happens to be an occurrence where we have several fields that are important to us, all at the same status. That's really the issue.

Great. Thank you very much.

You bet. Thank you.

Thank you. Our next question is from the line of Mark Gilman with The Benchmark Company. Please go ahead.

Folks, good afternoon. A couple things, if I could, please. The Malaysian volumes in the quarter really quite strong. David, I think you said Kikeh averaging 116 gross. Any change in your entitlement on Kikeh that might account for it picking up back to the 76,000 level for Malaysia in the quarter?

No, essentially, low 60s, same mark (inaudible) no change.

I didn't catch that.

Same level, there's no change in the quarter.

Okay. I noticed also in the release that the lease amortization charges on Tupper were lower and I was just wondering what reasoning or what took place to cause that to happen?

Mark, this is Kevin. It's due to the sanctioning of Tupper west.

Okay. Finally, last one from me. I was trying to do some rough math on the earnings guidance for the fourth quarter, folks. And taking into consideration the factors cited, the change in the downstream situation, little higher exploratory expense, the lift, the anticipated level of lifting increase, I can't make the math work. 75 to 90 seems well too low unless my unit profitability assumptions on the incremental volumes are way too high. Any thoughts you can offer and in particular tell me what kind of price realization underlies that forecast?

Mark, this is Dory. I'll take you through the assumptions that we built into our range and perhaps that will help you.

That would be great, Dory, thank you.

Worldwide realized oil price we used $65 a barrel. US realized gas price we used $4.75 a barrel. Total exploration expense range was 40 to $75 million. Downstream, the forecast calls for a loss of $24 million, and on corporate our loss range is 25 to $30 million.

Okay. Guys, thanks very much.

Thank you.

Thank you.

Thank you. Our next question is from the line of Paul Sankey with Deutsche Bank. Please go ahead.

Hi, Paul.

Mr. Sankey, your line is open.

Can you hear me? Yeah. Sorry. Apologize. I lost my question,unfortunately I was on mute. Next year, going forward, with the volume guidance left from Q4 could you give us some initial guidance on where we should now think about volume for 2010 and any kind of moving parts in that. Thanks.

Yeah, Paul, it will be north of 200,000 barrels equivalent for next year. I think that's where we'll be.

Okay. Fair enough. Is there any major moving parts relative to what you said at your analyst meeting, for instance, that we should be aware of?

No, not really. I think things are moving along pretty well. The big step up for us is going to occur actually in 2011 when we get Tupper west on production in the second quarter and we bring on 180 million cubic feet a day so that's the next big step up that we're going to look at. We are drilling Eagleford wells now or an Eagleford well now. We have anticipation that in a success case we will have some of that come on but we're a few steps away from that. So that could be something else that we would look to add in the event that that works.

I got you, David. Then you mentioned that you're stepping up your exploration spend a little bit for next year. I don't even think you said a little bit. If you could just quantify the scale of that. Further to that financial strength that you enjoy and the generation of free cash flow that's likely certainly if we keep these oil prices. Would you spend -- would you be tending to spend incremental free cash more in exploration, that is to step up the program even more than you've just indicated or would you be more towards spending on conventional gas which is obviously the other major area that you've talked about?

Yes, if I look at 2010 budget and we're kind of going through that and we'll get it approved here by our board in December, total budget's probably going to be about the same as it is for this year, about, oh, 2.2, $2.3 billion. We'll spend the bulk of that in the upstream. We'll probably spend north of 300 on exploration which is up quite a bit from this year. And I would like to be in the game where we're drilling at least 10 exploration wells and that's kind of where we're geared towards. As most things, you can maybe add an extra one or two.

We need to be at that level. We weren't this year for obvious reasons and so I think now with oil prices as you quite rightly point out where they are, allows us a little more free board. We'll get back in that game and I think we'll have some pretty attractive things to drill. We'll spend about a billion and-a-half on development projects. The development mix this year included things that we have to do and next year one of the new big spends really is Tupper west. So we have a little more flexibility in the event that oil prices do come down, we won't be hemmed in like we were a little bit this year (inaudible) cut discretionary spend.

If I look at this year and next year, about the same spend, little bit more exploration, more flexibility in the event that prices go down, a little bit less spending in our downstream business. The biggest spend there will be on retail stations in the US, which we're going to go back to doing that. So that's kind of how the rub will all work out.

Thank you, David. That's very clear. I had one more. You've had four consecutive quarters of underlift. Seems like you've got literally millions of barrels now or over a million, certainly, of barrels of storage. How does that rationalize itself? Is it going to -- I don't know. Is it going to be over the course of the next year that you reduce that? Do we consider an inventory position? How should we look at the way that works its way out? Thanks.

I think I touched on that with one of the early questions. We have about I think 1.1 million barrels that we're in an underlift position and it's not really in one place. It's across a number of fields and it just happens to work out there, work out that way. We tend to lift 100% cargoes on things like Kikeh and West Patch so that's kind of the way we're looking at it. If I look forward on the lifting schedule, we'll kind of work that out and it will go up and down during the course of the year, so I don't see it as a problem, Paul. I love having lots of barrels and I love being able to lift them. It's just the timing here is such that we're in this position, collectively, on a number of fields.

Yeah, I mean, I think that's. More thinking about how long it takes to work it down and I guess the confirmation that ultimately it will be worked down.

Paul, this is Kevin. Just kind of an item to note, we were looking at this position and this time last year we were almost a million barrels underlifted and it reversed in one quarter. This time it's not going to happen because we already know the timing of liftings. And then it started rebuilding again. This thing does bounce around. We'll make it back.

That's helpful. Thanks a lot.

Thanks, Paul.

Thank you. Our next question is from the line of Paul Cheng with Barclays Capital. Please go ahead.

Hi, guys.

Hi, Paul, how are you?

Very good. Dave, I don't know whether it's a fair question, I mean, with a lot of concern, we have more natural gas in US and North America than what we know to do, and if we look at some of the major that have reports quite alarmingly that year over year third quarter North American gas production, from the major (inaudible) not even down. A lot of the independents have seen gas shot up quite dramatically. With that in mind, what kind of gas price that you really need to make you take a more aggressive stand on economically makes sense for you to take a more aggressive stand than Eagleford and in the Tupper west, what kind of gas price you need in order for you to generate a reasonable return in the 15 to 20%?

You know, Paul, I think that is the actual key question to ask in all of this. And how we approach it is that over the longer term, I think gas prices will move on up and in the midterm, so the way I view that is kind of out three or four years, we're probably going to be in a position where oversupply is going to be the more dominant feature. Those companies that can get in in produce gas at a price $4 all in and less, Are the ones that are going to be able to capture margin and so I'm eliminating all of this financial forward selling from that.

I'm just saying just on a cost basis. So we kind of have that as our guide here, is to be able to get into these plays, drill wells, develop facilities and produce the gas so that we are making money at $4 less. Now, of course at the beginning of these things, it doesn't quite get to that point but very quickly it does and I think we're at that point in Tupper now. So I'm comfortable with that play. In the Eagleford, we haven't really drilled a well and flowed it yet so it's a little bit premature but from what we know I think that that will be a play that will work also at $4 and less. And the way I look at gas in North America is it's really a different animal. It's really a margin game and it's really a manufacturing game.

And in order to be good at both of those, you've got to be leasing all the time, drilling all the time, producing all the time, getting better at all of those three all the time and functionally making your costs as low as possible. The one thing that is interesting about this particular resource in North America is how quickly individual wells productivity falls off. It's no different in the Eagleford or Montley or (inaudible). I think in the other types of plays. And so what we're all going to be faced with is when we don't drill enough wells collectively as an industry, this bubble of gas is going to go away very, very quickly and I think it's going to go away and come back just as the price moves up and down, and just as activity moves up and down.

What we've been trying to do here is get exposure in the low point of the cycle, which we think we've just been in, and get ourselves acreage position at low entry costs which we think we've done. And then manage how fast and how quickly we make investments in those particular plays. Which I think we're doing as well. So that's kind of our approach.

Earlier I heard you say that $4 in Tupper is economic. When you say economic, I presume it's not just you make money but what kind of return are you talking about at $4?

Yes, I think you should be targeting something above the cost of capital. When I talk about $4 you've got to be north of 10%.

So in your case is that you're assuming at $4 at Tupper that you would do better than 10% return?

Yes

Okay. Is it a full cycle, I presume?

Yes

Okay. And second question is that in Congo. The appraisal well was dry. What have we learned from that?

If I describe the feature that was drilled, it's a four-way feature that has a fault cutting it in half. The discovery well was drilled in the left half. The appraisal well was drilled if the right half. What we found was that the channels which run east to west, so the fault is north, south, the channels run east to west, they don't all sit on top of each other. So the two channels we found in the west part of the feature that had pay were present on the Eastern side but were wet but a third channel that we had not seen on the Western side because it didn't quite sit at the same location had oil pay.

And so we've confirmed that there is pay on the Eastern side. Confirmed that there's pay on the Western side. Now we have the appraisal to look for the channel that we found on the Eastern side on the Western side. So that's what we learned. Overall, I think the feature's about the size of Azurite. The upside that we gain knowledge from was that the same channels which run east-west, if we go further to the west by just a few miles, they go over another four-way dip feature and so having oil in these channels with the well confirming it, going down a sink line and up on another structure to me high grades that pretty nicely.

So our look at the whole Turquoise Marine area is that we're going to be dealing with multiple features, multiple channels in an area that collectively could be larger than Azurite and what we're looking at is how to appraise or explore and then how to develop that in conjunction with Azurite.

Dave, Turquoise in the sense that you MPS or that most of the prospect you guys identified to date would look in a similar structure, with all the channel running the way that they did, I mean, is it similar structure, geological structure that the prospect or this is what you need on its own?

Yes, if you look at that block, Paul, most of the prospects that we've identified, and there's 20, plus, have these east-west trending lower tertiary [bioscene-ligoscene] channels running across them. And the risk that we have primarily is that some of these channels on the features have had oil go through them but has not been trapped. In other words, the late fault movement has caused oil to leak out and so right now we're batting one in three in terms of discoveries. Going in, before we ever drilled a well in MPS we thought it would be one in three. We've drilled a discovery with the first well so we thought we were smarter and then we went around that discovery, Azurite, and proceeded to drill four dry holes and finally realized that the issue of trap seal integrity was the most important.

So we came back knowing that and drilled Turquoise and confirmed that. The one structure that we drilled midway between Turquoise and Azurite, we drilled it because it was going to be on the pipeline right-of-way, anyway so that's why we drilled that. If I look at the rest of the inventory on that block, there are a number of prospects, a handful that we high graded, that have the same attributes, both as Azurite and as Turquoise, so our exploration program next year and in subsequent years is clearly going to target those that we think have a minimum chance of this late fault movement and this late seal risk. So that's the overall game in that particular block. If you look at the block to the north, MPN, we have same age, same types of features in the southern part but then we have other plays there and so we're looking at that. But that's a completely different play type, completely different risk profile.

I see. Very good. If the I could have two final questions. One is for Kevin. On the $244 million of the refund claim that you filed, how much of that is related to the third quarter 2009 operation? In other words, assume that we get it, that on a going forward basis, how much improvement that we're going to see in earnings or in production number? And secondly is that on maybe for Dave, previously I think about two years ago when you first become the -- even before you become the COO, you had had looking at the M&A activities, maybe more closely. Wondering that, I mean, is there any change in your stand related to M&A, the position in your overall portfolio or strategy over the next one or two years. Thank you.

Thanks, Paul. Kevin, you want to take the first one?

On the royalty issue, the third quarter impact was $6.5 million of additional revenue and in the fourth quarter we're estimating a little bit under $18 million of additional revenue due to the royalties.

Yeah, Paul, on M&A, we're still in the game. We're still looking. I think the entry into the Tupper play initially was the acquisition of some lands from a small company and then we proceeded to pick up and bolster that position largely through lease sales. And in the Eagleford, we entered through leasing land.

We've had opportunities in other plays but for oil and for gas to make acquisitions but I have to tell you, the ability to write a check to buy something if you can just go and lease it, I'd much rather go lease it. And so our M&A track record, if you will, in buying things has not been good because we can pick up things that we really like by leasing them and so that's really the issue. Going forward, I'd be happy to find something that we could acquire to fit in with the company and we're actively looking all over the world.

Thank you.

Thanks, Paul.

Thank you. And our next question is from the line of Blake Fernandez with Howard Weil. Please go ahead.

I wanted to go back toward Mark's question on the guidance for 4Q. I had trouble with the downstream. I guess it took me a bit by surprise on I guess the down tick versus 3Q. I know the refining industry obviously is very weak but it was in the third quarter as well and I just wanted to confirm, is the driver there really on the retail side of things?

Retail generally is good in the middle of the year for us. And so when you start getting into the third quarter, you start getting into the shoulder and so yes, retail is not as good. As you quite rightly say, Blake, the manufacturing side of the business, absent our asphalt game in Superior which has been pretty okay this year, the margins at Milford Haven have been very weak.

Okay. And then speaking of asphalt, David, there's been some positive commentary out there as far as the outlook going into 2010 with some of the stimulus dollars making their way into the system and what have you. Do you have any thoughts on that?

We did pretty good in asphalt this year and I would say that we had a higher expectation which was pretty lofty. Where we think that disconnected was that the stimulus dollars did not actually translate into new projects and our sense is that they will next year. And so I think overall asphalt is going to be more robust next year.

Now, having said that, at the beginning of this year, heavy crude prices were quite low and the cost to put asphalt in storage was pretty attractive. Prices are higher now and so it's going to be interesting to see how next year plays out. We didn't add incremental storage into our asphalt business so that we can actually store more product than we have been able to in the past and so we're positioning ourselves for next year and so I think next year should be better. But then again, I thought this year was going to be better than it was. It was a good year so we'll just have to see.

And then the final one from me, you had mentioned the preference to lease rather than acquire. And obviously you've been adding to your Eagleford position. Do you think that's really where your area of focus is going to maintain for right now or do you think you're going to start to evaluate some other shale play opportunities?

We've been looking at all -- pretty much all types of North American shale opportunities and we settled on the Eagleford for a lot of good reasons I think. Having said that, we haven't drilled a well yet. We're drilling one now. which should be at TD this weekend in it's horizontal section. Then we should flow it here and have some results in a month. I'm happy to keep growing the Eagleford position based on the data that we've seen. The well that we drilled, we haven't flowed it yet but it's done all the things that we would ask. The section has drilled more like Haynesville section than anything else that we've seen and so we think the play's well worth making and 200,000 acres, getting that is a -- it puts us with a great footprint and I think one of the pluses for that particular play is the richness of the gas as well. So there's lots of good reasons. Above ground issues are less than some other plays.

Being able to lease has lots of advantages, one of which you don't have to write a big check to start off with. Second thing is you don't have to make all of your commitments all at once and you can kind of space things out so you can -- it goes back to one of the earlier questions about where the oversupply of gas is likely to be. One of the flexibilities that you want to have in these games is to slow down or speed up and if you've got commitments that force you to drill a lot of wells very quickly, you remove a lot of that flexibility and so one of the beauties of having leases with longer terms is that you can can go in there and you can decide how fast you want to go and so both Montley Play and Eagleford for us . allows that flexibility and so I

Thanks a lot. David, appreciate it.

(Operator Instructions) Our next is a follow-up from the line of Mark Gilman with the Benchmark Company. Please go ahead.

David, the SiaKap north appraisal well, did that all alter the preliminary.gross resource estimate for that structure?

No, it kind of confirmed it, Mark . The way I look at it is that feature's 100 million-barrel, maybe a little bit more and probably split 50/50. And so it really just confirmed all of that. What we've got to do is agree with the people in the other block on how to develop it and then go and submit a development plan to the government and say hey, this is what we would like to do. This is how we would like to develop it.

The Siakap well that I mentioned that we'll be drilling before the end of the year, that's not associated with that unitization area at all. But it's relatively modest. It's a one or two well tieback, a little over 10 million barrel type number.. We can go ahead and tie that back to Kikeh whenever we get spare capacity so that's what

The Sarawak gas price, the 331 figure for the third quarter, how should we think about that on a going forward basis? Can I essentially assume that that's a well head price?

Mark, I think it's tied to a landed LNG pricing the mechanism there. On a go forward basis, that price will fluctuate some. For the remainder of the fourth quarter in our estimate, that that number is probably a good number for you to use.

Okay. So it's going to fluctuate with crude Dory on a lagged basis?

Yes, that's correct.

Yes, that's right, Mark. It's tied to LNG landed prices and that's tied to oil, so that's how it's going to -- and yes, basically it's a well head price. It's the price we get when it jumps from our plant over the fence to the LNG facility.

Okay. Just one other one, if I could. The production and lifting or sales guidance, what does that assume about the royalty, the deepwater Gulf of Mexico royalty situation given that I assume that what you were doing as you were accounting for the given reporting net barrels is it was a deduction from your gross working interest.

Talking about the royalty reduction in the Gulf?

Yes In other words, does your guidance assume that you will no longer accrue if you will that royalty and, therefore, production will be higher?

Yes.

And that's built into your fourth quarter guidance.

Fourth quarter, it's about 2800 barrels, barrels of oil equivalent.

And in the third quarter, what did you do?

1200.

And production was burdened by that in the third quarter or was not?

No, that was an increase to production by that amount.

Okay. I got it.

And then everything prior to that is part of that $244 million claim.

Okay. I got it, Kevin. Thank you.

We were paying that.

Okay. So it's a cash issue?

244 is cash.

Okay.

And going forward we're just not deducting the royalty, we're going forward as if it's no royalty on that.

Thanks very much.

Thanks, Mark.

Thank you. And I show that there are no additional questions at this time. I would like to turn the call back to management for closing remarks.

Operator, and everybody, thanks for listening in and asking good questions. We appreciate it and look forward to the next call. Thanks a lot.

Ladies and gentlemen, this concludes the Murphy Oil Corporation third quarter 2009 earnings call. If you would like to listen to a replay of today's call, please dial 1-800-406-7325, or 303-590-3030, followed by the access code of 417-1047 and the pound sign. ACT would like to thank you for your participation. You may now disconnect.