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Murphy Oil Corporation (NYSE:MUR)

Q3 2009 Earnings Call

November 5, 2009 1:00 pm ET

Executives

David Wood – President & CEO

Kevin Fitzgerald – EVP & CFO

John Eckart – VP & Controller

Mindy West – VP & Treasurer

Dory Stiles – Manager IR

Craig Bonsall – Supervisor IR

Analysts

Evan Calio – Morgan Stanley

Mark Gilman – The Benchmark Company

Paul Sankey – Deutsche Bank

Paul Cheng – Barclays Capital

Blake Fernandez – Howard Weil

Operator

Welcome to the Murphy Oil Corporation third quarter 2009 earnings conference call. (Operator Instructions) I would now like to turn the conference over to Mr. David Wood, President, and Chief Executive Officer.

David Wood

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

Dory Stiles

Thanks David, welcome everyone 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 undertakes no duty to publicly update or revise any forward-looking statements.

I will now turn the call over to Kevin for his remarks.

Kevin Fitzgerald

Thanks Dory and welcome everyone. Net income for the third quarter of 2009 was $188.9 million or $0.98 per diluted share. This compares to net income for the third quarter of 2008 of $584.4 million or $3.04 per diluted share.

For the nine months of 2009 net income is $518.8 million or $2.70 per diluted share compared to net income for the nine months of 2008 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 Ecuador in March.

The 2008 nine month period included after-tax gains from the sale of the Canadian assets, this consisted of our interest in Berkana Energy and the Lloydminster Heavy Oil properties of $108.3 million or about $0.57 a share.

Looking at the net income by segment, in the E&P we had net income from continuing operations in the third quarter of 2009 of $184.1 million and this compares to net income from continuing operations in E&P in the third quarter of 2008 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 2009 versus $112.55 last year. While 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 production from Kikeh, offshore of 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, offshore the Republic of Congo.

Natural gas sales volumes were up almost fourfold at 182 million cubic feet in the third quarter of 2009 compared to 46 million per day in the third quarter of last year. This increase was primarily due to production at Tupper in Western Canada and at Kikeh.

In the downstream segment net income in the third quarter of 2009 was $37.2 million and this compares to net income in the third quarter of 2008 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 2009 of $32.4 million and this compares to net after-tax charges in the third quarter of 2008 of $31.3 million. Lower interest income on invested balances for the 2009 quarter were largely offset by lower net interest expense and lower foreign exchange losses when compared to the third quarter of 2008.

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 deep oil leases in the Gulf of Mexico.

Murphy actually paid royalties on similar leases when the benchmark price 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 the Interior provide the appropriate evidence that our refund request will be honored. Additionally our fourth quarter earnings projection of $0.75 to $0.90 per share does include a lifting at Kikeh which is currently scheduled for late December.

Should this lifting be delayed for any reason into 2010 earnings for the quarter would be reduced by a little over $0.07 per share. And with that I’ll turn it over to David.

David Wood

Thanks Kevin, results from the third quarter were favorably impacted by improving crude prices. On the other hand the North America natural gas market has not faired well this year at all. We have used this slow cycle entry point to establish strong positions both in the [inaudible] at Tupper in British Columbia, and more recently the Eagle Ford play in South Texas.

We see this as a complimentary 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 the Republic of Congo; and Sarawak natural gas offshore Borneo, Malaysia.

Also the drilling of successful appraisal wells at Serandah and Pemanis, offshore Sarawak, as well as Siakap North and Block K Malaysia; the [spudding] of the first well on our Eagle Ford shale acreage; respectable US retail performance; and work towards finalizing the acquisition of our new ethanol plant.

I will 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 unitization 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 Mer Profonde Sud 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 fault blocks 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 Block 432 where we hold a one third working interest is scheduled to be appraised in the second quarter of 2010. Tie back 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, DC 4 located in De Soto Canyon Block 4 is a natural gas prospect located in 5,800 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. Onshore US we are in the midst of a three well drilling program that will extend into next year and marks our initial Eagle Ford 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 17 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 then 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 equivalent per day.

This still compares favorably to the third quarter 2009 average production rate of 162,000 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 then expected. We had our first Azurite lifting in mid October with the crude price less then $3.00 below [inaudible].

In Malaysia Kikeh’s gross oil production continues around 116,000 barrels of oil per day. In British Columbia, 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 a 180 million cubic feet a day new build gas plant. Well testing has been very positive in Tupper West. It should be long lived contributor 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, however 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.

Today the Meraux refinery is operating at 110,000 barrels per day while the 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 on an ethanol plant located in Hankinson, 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 bio fuels business as an add-on to our North American fuels business where we sell almost 3% of the nation’s gasoline and have mandates for this fuel additive.

The state of the art Hankinson plant was acquired at a favorable price and most importantly has the potential to make returns which is it doing today by the way. I have been very impressed with the entrepreneurial spirit that both led to the acquisition and has been exhibited by our new employees at the plant.

For the balance of the year we will finish ironing out the 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 then 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 pre drilling 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 your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Evan Calio – Morgan Stanley

Evan Calio – Morgan Stanley

I have follow-up question on the production guidance, I know you identified primarily related to Sarawak gas, it sounds like 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 are doing to get that back on track.

David Wood

Sarawak gas, we had some very good results in the drilling and in the floating of the wells and the productive capacity from the offshore facilities is 300 million plus. The issue for us is in the onshore receiving facility, and just delving down into the specifics, the real issue is with the rental compressors that we have and a particular piece of equipment that relates to each of those compressors.

So its uniform throughout all of the set up 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 is about 140 million a day. And I would think we’d 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.

Evan Calio – Morgan Stanley

A different question on under lift 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 under lifted in the third quarter and are projecting under lift in the fourth quarter, can you quantify your net under lift and how we think these will unwind.

David Wood

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 Pat, 240,000 barrels behind at Azurite, and 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 then one lifting out of balance. And this just happens to be an occurrence where we have several fields that are important to us all at the same status. So that’s really the issue.

Operator

Your next question comes from the line of Mark Gilman – The Benchmark Company

Mark Gilman – The Benchmark Company

A couple of things if I could please, the Malaysian volumes in the quarter really quite strong, 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.

David Wood

No, essentially to our low 60’s, same mark, no change. The same level, there’s no change in the quarter.

Mark Gilman – The Benchmark Company

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

Kevin Fitzgerald

Its due to the sanctioning of Tupper West.

Mark Gilman – The Benchmark Company

Okay. Finally I was trying to do some rough math on the earnings guidance for the fourth quarter and taking into consideration the factors cited, the change in the downstream situation, little higher exploratory expense, 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.

Dory Stiles

I’ll take you through the assumptions that we built into our range, and perhaps that will help you. Worldwide realized oil price we used $65 a barrel. US realized gas price we used $4.75 a barrel. Total expiration 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.

Operator

Your next question comes from the line of Paul Sankey – Deutsche Bank

Paul Sankey – Deutsche Bank

For next year going forward with the volume guidance from Q4 onwards, can you just give us some initial guidance on where we should now think about volumes for 2010, any moving parts in that.

David Wood

It will be north of 200,000 barrels equivalent for next year, I think that’s where we’ll be.

Paul Sankey – Deutsche Bank

And is there any major moving parts relative to what you said at you analyst meeting, for instance that we should be aware of.

David Wood

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 Eagle Ford wells, an Eagle Ford 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.

Paul Sankey – Deutsche Bank

And 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 and 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 be tending to spend incremental free cash more in exploration that is to step up the program even more then you’ve just indicated or would you be more towards spending it on conventional gas which is obviously the other major area that you’ve talked about.

David Wood

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 is probably going to be about the same as it is for this year, about $2.2, $2.3 billion. We’ll spend the bulk of that in the up stream, we’ll probably spend north of $300 on exploration which is up quite a bit from this year.

And I’d 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. You know as most things you maybe add an extra one or two but we need to be at that level. We weren’t this year for obvious reasons and so I think with oil prices as you quite rightly point out where they are allows us a little more free [board].

So we’ll get back in that game and I think it’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 had to do and next year one of the new big spends really is Tupper West and so have a little more flexibility in the event that oil prices do come down. We won’t be kind of hemmed in like we were a little bit this year in [where we had to] cut discretionary spend.

If I look at this year and next year, about the same spend, a 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 look out.

Paul Sankey – Deutsche Bank

You’ve had four consecutive quarters of under lift, it seems like you’ve got literally millions of barrels now or over a million certainly of barrels of storage, how does that rationalize itself. It is going to be over the course of next year that you reduce that. Do we consider it an inventory position, how should we look at the way that works its way out.

David Wood

I think I touched on that with one of the early questions, we have about 1.1 million barrels that were in an under lift position and its not really in one place, its across a number of fields and it just happens to work out that way. We tend to lift 100% cargos on things like Kikeh, and West Pat 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. I love having lots of barrels and I love being able to lift them, its just the timing here is such that we’re in this position collectively on a number of fields.

Paul Sankey – Deutsche Bank

I don’t think that’s the word as a problem, I was just more thinking about how long it takes to work it down and I guess your confirmation that ultimately it will be worked down.

Kevin Fitzgerald

Just kind of an item to note, we were looking at this position and this time last year we were almost a million barrels under lifted and it reversed in one quarter. Now this time that’s not going to happen because we already the timing of liftings and then it started rebuilding again.

So this thing does bounce around and we’ll make it back.

Operator

Your next question comes from the line of Paul Cheng – Barclays Capital

Paul Cheng – Barclays Capital

I don’t know whether this is a fair question 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 report quite alarmingly year over year third quarter North American gas production from the major actors, not even down, and of course a lot of the independents have seen gas shot up quite dramatically. So with that in mind what kind of gas price that you really need to make you take a more aggressive stand on the economic of it, make sense for you to take a more aggressive stand in Eagle Ford in the Tupper West, what kind of gas price you need in order for you to generate a reasonable return like in the 15 to 20%.

David Wood

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 in the mid term, so the way I view that is kind of out three or four years we’re probably going to be in a position where over supply is going to be the more dominant feature.

And those companies that can get in and 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 pool with selling from that, I’m just saying just on a couple of places.

And 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 and 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 at Tupper now.

So I’m comfortable with that play. In the Eagle Ford we haven’t really drilled a well and floated 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 its really a different animal.

Its really a margin game and its 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 of those three all of 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 and its not different in the Eagle Ford or the [inaudible] that we’re in or I think any 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 its 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.

Paul Cheng – Barclays Capital

Earlier you say, that $4 in Tupper is economic, when you say economic, I assume its just that you make money, but what kind of return you are talking about at $4.

David Wood

I think we should be targeting something above the cost of capital so when I talk about $4 you’ve got to be north of 10%.

Paul Cheng – Barclays Capital

Okay in your case is that you’re assuming at $4 at Tupper that you would do better then 10% return.

David Wood

Yes.

Paul Cheng – Barclays Capital

Is it a full cycle I presume.

David Wood

Yes.

Paul Cheng – Barclays Capital

And the second question is that in Congo the appraisal well was dry, what have we learned from that.

David Wood

If I describe this 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 in 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.

And 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 is about the size of Azurite. The upside that we gained knowledge from was that these 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 a well confirming it, going down a sink line and up on another structure to me high grades that pretty nicely.

And 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 then Azurite and what we’re looking at is how to appraise or explore and then how to develop that in conjunction with Azurite.

Paul Cheng – Barclays Capital

[Turquoise] in the sense that you meet within the MPS block or that most of the prospect you identifying to date will look in the similar structure with all the channels running the way that they did and is there similar structure, geological structure in the other prospect or this is what that you need on its own.

David Wood

Yes, if you look at that block most of the prospects that we have identified and there’s 20 plus have these east west trending lower tertiary [bioscene] or [ligascene] 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 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 and so that’s why we drilled that. But if I look at the rest of the inventory on that block, there are a number of prospects, a handful that we’ve high graded that have the same attributes both as Azurite and as Turquoise.

So our exploration program next year and 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 the 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.

Paul Cheng – Barclays Capital

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 that assume that we get it that on a going forward basis how much improvement that we going to see in earning or in production number and second is that previously I think about two years ago when you first become the, even before you become the CEO you had looking at the M&A activities, maybe more closely, wondering is there any change in your stand related to M&A, the position in your overall portfolio strategy over the next one or two years.

Kevin Fitzgerald

On royalty issue, the third quarter impact was about $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.

David Wood

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 Eagle Ford we’ve entered through leasing land. We’ve had opportunities in other plays both 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.

Operator

Your next question comes from the line of Blake Fernandez – Howard Weil

Blake Fernandez – Howard Weil

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. I just wanted to confirm is the driver there really on the retail side of things.

David Wood

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 the manufacturing side of the business absent our asphalt gain in Superior which has been pretty okay this year, the margins that grow in Milford Haven have been very weak.

Blake Fernandez – Howard Weil

And then speaking of asphalt 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.

David Wood

We did pretty good in asphalt this year and I would say that as had a higher expectation which was pretty lofty and 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 its going to be interesting to see how next year plays out.

We did add incremental storage into our asphalt business so that we can actually store more product then 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 then it was. It was a good year, but so we’ll just have to see.

Blake Fernandez – Howard Weil

And then you had mentioned the preference to lease rather then acquire and obviously you’ve been adding to your Eagle Ford position, do you think that’s really where you’re 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.

David Wood

We’ve been looking at all, pretty much all types of North American shale opportunities and we settled on the Eagle Ford 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 its horizontal section and then we should flow it here and have some results in a month.

I’m happy to keep growing the Eagle Ford position based on the data that we’ve seen. The well that we’ve drilled, we haven’t flowed it yet but its done all the things that we would ask. The section has drilled more like Haynesville section then anything else that we’ve seen.

And so we the play is well worth making. And 200,000 acres getting that, 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 then 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 and the second thing is you don’t have to make all of your commitments all at once and you can kind of space things out and so you can, it goes back to one of the earlier questions, about where the over supply 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 go in there and you can decide how fast you want to go and so both the [inaudible] play for us and Eagle Ford for us allow us that flexibility and so I like that.

Operator

Your final question is a follow-up from the line of Mark Gilman – The Benchmark Company

Mark Gilman – The Benchmark Company

The Siakap North appraisal wells did that alter the preliminary gross resource estimate for that structure.

David Wood

No we kind of confirmed it. The way I look at it is that feature is 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’d like to do and this is how we’d 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 its relatively modest, it’s a one or two well tieback, a little over 10 million barrel type number. And we can go ahead and tie that back to Kikeh whenever we get spare capacity so that’s what we’re looking at.

Mark Gilman – The Benchmark Company

The Sarawak gas price, the $331 figure for the third quarter how should we think about that on a going forward basis and can I essentially assume that that’s a well [head] price.

Dory Stiles

It’s tied to L&G landed prices, the mechanism there and on a go forward basis that price will fluctuate some. For the remainder of the fourth quarter and our estimate that that number is probably a good number for you to use.

Mark Gilman – The Benchmark Company

So its going to fluctuate with crude on a lagged basis.

Dory Stiles

Yes that’s correct.

David Wood

That’s right, its tied to L&G landed prices and that’s tied to oil so that’s how its connected. 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 L&G facility.

Mark Gilman – The Benchmark Company

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

Kevin Fitzgerald

You’re talking about the royalty reduction in the Gulf?

Mark Gilman – The Benchmark Company

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.

Kevin Fitzgerald

Yes.

Mark Gilman – The Benchmark Company

And that’s built into your fourth quarter guidance.

Kevin Fitzgerald

For fourth quarter its about 2,800 barrels, barrels of oil equivalent.

Mark Gilman – The Benchmark Company

And in the third quarter, what did you do.

Kevin Fitzgerald

It was 1,200.

Mark Gilman – The Benchmark Company

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

Kevin Fitzgerald

No that was an increase to production by that amount. And then everything prior to that is part of that $244 million claim.

David Wood

We were paying that.

Mark Gilman – The Benchmark Company

Okay so it’s a cash issue.

Kevin Fitzgerald

The $244 is cash. And going forward we’re just not deducting the royalty, we’re going forward as if its no royalty on that.

Operator

There are no additional questions at this time; I would like to turn it back over to management for any additional or closing comments.

David Wood

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

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Source: Murphy Oil Corporation Q3 2009 Earnings Call Transcript
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