Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Murphy Oil Corporation fourth quarter 2009 earnings call. During today’s presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. (Operator Instructions) This conference is being recorded today, Thursday, January 28, 2010. I would now like to turn the conference over to Mr. David Wood, President and CEO; please go ahead, sir.

Thank you, operator. Good afternoon, everyone and thank you for listening in on our call today. Joining me are Kevin Fitzgerald, Senior Vice President and Chief Financial Officer; John Eckhart, Vice President and Controller; Mindy West, Vice President and Treasurer; and Craig Bonsall, Supervisor of Investor Relations. I will now turn the call over to Craig.

Thanks, David. Welcome everyone and thank you for joining us. Today’s call will follow our usual format. Kevin will begin by providing a review of fourth 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 Form 10-K filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I’ll now turn the call over to Kevin for his comments.

Thanks, Craig and welcome everyone. Net income for the fourth quarter of ‘09 was $318.8 million or $1.65 per diluted share. That compares to net income in the fourth quarter of ‘08 of $127.4 million or $0.67 per diluted share. For the full year of 2009, net income totaled $837.6 million or $4.35 per diluted share, compared to net income in 2008 of $1.74 billion or $9.06 per diluted share. In 2009, fourth quarter included $185.3 million of after tax benefit, which included after tax interest income of $27 million, from anticipated recovery of royalties paid on certain deepwater oil and gas fields in the Gulf of Mexico. The interest income is included in our corporate segment with the remaining $158.3 million included in our E&P segment. As you’re probably aware this recovery is as a result of a U.S. Circuit Court of Appeals affirming in 2009 that the U.S. government improperly collected royalties on these leases when oil and gas prices exceeded certain levels. The ‘09 quarter also included a $31.3 million after tax charge associated with an anticipated reduction of our working interest in Azurite field offshore Eastern Canada due to redetermination process currently underway. There were no unusual items of significance in the 2008 quarter. Looking at income by segment, E&P segment earnings in the fourth quarter of ‘09 was $339.1 million, compared to $68.6 million in the fourth quarter of ‘08. Higher earnings in the ‘09 quarter were primarily attributable to the previously mentioned anticipated recovery of deepwater Gulf of Mexico royalties. In 2009 quarter also benefited from higher oil prices, higher natural gas sales volumes and lower exploration expenses. The ‘09 quarter was adversely affected by lower natural gas prices and the redetermination charge. Crude oil and gas liquids production from continuing operations averaged over…

Thanks, Kevin. This quarter closes out my first year as Chief Executive Officer of Murphy Oil and it’s hard to believe an entire year has passed so quickly. 2009 was an uncertain and challenging year, but one for which I assure you that Murphy was ready. Financial flexibility, reserve cash balances and ample credit capacity that we can continue on track with our plan as well as look for buying opportunities. Historically, we tend to capture quality opportunities, when conditions are at their poorest. This go round we used the low point in North American natural gas prices to expand our footprint at Tupper in British Columbia and aggressively a new trend at Eagle Ford Shale in South Texas. Our aim is simple, to assimilate an impactful, long term position in high quality, lower cost onshore natural gas to complement our main oil based portfolio. We also stepped into the buyer fuels business and purchased an ethanol plant to balance part of our U.S. retail plant. Looking back, the three fields promised to come on in 2009 did, Azurite, Thunder Hawk and Sarawak gas. All performed as or above expectations below ground, which is always the key for me. Above ground, slower ramp up at Sarawak gas was vexing, but all three are making important cash flow contribution at the levels we expect. Continued expansion of our North American natural gas position was targeted for 2009 and to that end we added 42,000 net acres to the Montney, British Columbia position. We sanctioned the Tupper West into the Eagle Ford Shale play in March and by the end of the year are moving on towards 200,000 leased acres having just drilled our first promising well. Exploration activity was below the level we like due to pairing of the overall budget…

(Operator Instructions) Your first question comes from Mark Gilman - Benchmark Company.

David, I wonder if I could just ask you to be a little bit more specific regarding one of your last comments in your prepared remarks, namely that you’re two thirds of the way to establishing a 10 trillion cubic foot objective resource position in North American gas. I kind of got some trouble getting to that number. Can you help me?

Mark, I’m really happy you asked that question because I was dying to answer that. Let me kind of break it down. I think up in Canada, we have the two sanctioned developments for Tupper Main, which is producing and Phase I of Tupper West, probably halfway to 3 Tcf and I can see that doubling and maybe a bit better than that with the acreage we currently have under lease, all at this 160 acre spacing. On top of that, of course if we can go from 160 acres to 80 acres, there’s additional upside. So I would say that of the two thirds, 10 Tcf better than half is there on acreage we’ve already identified. We’ve drilled a lot of wells. We’re on production and feel real good about what we have. The Eagle Ford, we ourselves have not drilled many wells. Actually, we’ve really only drilled two wells and only flow tested one well, but we’re in a great location with our acreage in LaSalle and McMullen County, where we have over 100,000 acres in the key part of the play as we see it. I’m very encouraged with the well that we’ve drilled and very encouraged with the core information that we’re just starting to get in. So if you take any reasonable amount of parameters there, I think you can get our acreage and risked, of course, another three plus TCF. So that’s kind of how I break it down, Mark, in getting towards that 10. Again, the upside of down spacing exists in both those plays.

The number, both the 10 and as well as the being two-thirds of the way there, David, are risked numbers?

Yes, we’ve gone through a risking process for the acreage, based on in the Montney case our own drilling and in the Eagle Ford just about what other people have been doing and then risking certain parts of the acreage, so there is an element of risk there. You have to remember we’ve not drilled many Eagle Ford wells so, I would feel real comfortable if you asked me the same question at the end of the year after we’ve drilled a lot more wells, but I’m as equally as comfortable now saying I like what we have.

If I could just follow-up with one more, David, I’m a little bit curious as to why the first Eagle Ford well was apparently not one that had potential for liquids kick, given the importance of that in terms of the economics in the play the way it seems to be shaking out.

Yes, this first phase of drilling for us, Mark, was designed to appraise kind of three main areas of our leasehold and we chose this one deliberately to be at the southern end of the play or the deepest part of the play, deliberately targeting what we believed was going to be the dry gas window and that’s kind of what we found, because we were really trying to get a gauge of what kind of rate we could get out of these wells. So I’m actually not surprised that we didn’t find any liquids here. I think the $11.7 million rate is a good rate. We clearly need to dewater that well some more. I think we recovered just over 8% of the water that we put in. Typically, these wells start to show their true quality once you get well north of 10 and so we’re a little way off there. One of the nice things is, we did hook this up and are making sales so I kind of like that. We did find a small concentration of CO2 here, 4%. So we’re going to put a aiming unit on this area and I think once we have that and dewater the well, I think we’ll do much better. The second well that we’re drilling that we’re getting ready to frac now is up in Karnes County and it is in the oil rich window and so I’m very interested, as all the team here is, to see what we do there. So we’re fortunate to have an acreage position that allows us to access both the oil component, as well as hopefully the higher rate gas components in that play.

David, I’m not accustomed to hearing the term dewatering in they the Eagle Ford.

Well happens, Mark, is that on that particular well, we did a 13 stage frac and we put away just over 200,000 barrels of water. When you flow these wells back, you are going to recover a significant portion of that water. So that’s what I mean by dewatering. It’s just the recovery of the water that we used during the fracking process.

Your next question comes from Paul Cheng - Barclays Capital.

If I could have ask a number of quick questions, Dave, at a point that you would be able to tell us that what is the cause of the Eagle Ford first well?

Yes, the wells are more expensive, these first three, Paul, because we’re drilling them covering the full section turning them horizontal and then drilling them horizontal so that well including frac is a little over $13 million.

What’s your target, once you finish the initial pilot?

Yes, I can pushing closer to the $8 million number. My drillers always love me to lead with the chin there, but I think it’s possible to kind of get down to those numbers. Again, remember that was in what we thing is the deepest part of the play. So, if you kind of look at an average, I think you should be drilling and frac these things in the $8 million range.

In earlier that you’re talking about the 3TCF capacity in the Eagle Ford potentially. What’s your assumption on per well recoverable rate?

Yes, I think these wells are going to be in the five to six Bcf recoveries Paul. Again, we’ve only drilled one well. So we need some more data out there. So I think that’s a reasonable conservative position.

I presume that the 3 Tcf is not a Mcf equivalent including the liquid component or this is just the dry gas component?

It’s a Mcfe is the way I look at it. We’ve not drilled any wells up in the oil area. So I would recalibrate that once we had some hard data.

When do you think the first well will reach the 10% water recovery or the most production that you can talk about it?

The nice thing about this program is we’re going to be able to yank about it almost every time we have a call because we’re going to be pretty active. So in terms of getting to over 10%, another 30 days would I think comfortably get us there. I think we’ll start to see the effects of having less water in the well so more gas can come out.

You think, right now at 11.7?

The best rate that we have got out of the well is 11.7. The well is currently going to sales at about 4 million a day.

Right now it’s 4 million?

Yes.

You talk about ethanol that it’s going to be a bigger piece of your overall downstream business. Is that means that you intend to make substantially more acquisitions?

Paul, it actually means that the refining business is a terrible business this year that really what it’s saying. The ethanol business, we bought this one plant and I’m real happy with it and if we got the opportunity to buy, I don’t know, one or two more, I would. I think there’s a nice fit in our business. Strategically, the volume from that plant makes up about a quarter of the ethanol that we sell in our retail and so having a degree of coverage there I think is good, but if you can buy things below replacement cost and there’s good economics, so why not. So I would.

You’re not going to aggressively acquire a lot of ethanol plants?

One or two more, Paul, I think would be my…

On that subject, Dave, have you already went for or intended to went for internal review in terms of the long term viability of your refining asset to see whether that any of your facilities you may actually better off to just shut it down?

We’re going through turnarounds in both Milford Haven and Meraux really the first part of this year. We have new teams and new folks looking at those. If I look at external reports on the quality of the iron we have, I’ll be perfectly frank, we should be operating those better than they are and so that’s our goal now. Now, I can’t control and we can’t control the external environment and so we’re just going to have to do what we can do and then take a look and see what looks best for us going forward.

We’re going through turnarounds in both Milford Haven and Meraux really the first part of this year. We have new teams and new folks looking at those. If I look at external reports on the quality of the iron we have, I’ll be perfectly frank, we should be operating those better than they are and so that’s our goal now. Now, I can’t control and we can’t control the external environment and so we’re just going to have to do what we can do and then take a look and see what looks best for us going forward.

I was going to say based on what you’re saying, means that at least for the next, say, maybe six to nine months you’re going to give time to your new folks to try to prove they can operate better, but you’re not planning to shut them down, there’s no review at this point whether they should be shut down?

We’re just going to continue on after turnaround and clearly the turnaround on those two plants is very important. The superior facility operates very well and we do make money up there, largely through the asphalt part of the business. So I think that’s going to stay the real question in terms of margins and differentials is going to be Meraux and Milford Haven and we need to run them better and I think after turn around they will be run better.

Dave, I don’t know whether it’s a fair comment. If you look at over the last, say, five years or six years, ever since the Kikeh discovery, I think you will agree that the explosion result has not been as good as you hoped or that what you had been able to demonstrate early in the decade. Have you guys did a internal review and look at whether the approach is wrong or have some issue or that the model that your geological model as well as maybe the people need to be changed or whether you think the conclusion after you review it is just pure bad luck?

No, luck plays a role in all of these things, but you get paid to manage and put yourself in good positions. I will say that they got rid of the guy that was managing that program and got another guy in charge. The guy that was running that program was me. So I don’t do that anymore. There are smarter, more capable people doing that with that approach. So I will say from that viewpoint, we’ve done that. If you actually look over the last five or six years, the types of fields that Kikeh is and are, I mean we found Kikeh, we found Kakap, those don’t come around all the time. I think you have to look at the underlying success rate and we have been up and down. Just last year, we actually made some pretty nice attractive discoveries individually, not large, but definitely added to our program. So I think the issue really is why have we not found another significantly large deal and I think that’s a bigger issue than anything else. I don’t expect every year to find one of those. I think what you do is you put yourself in a position to have a chance. We have been successful in Congo in a new province, an oil field on production and a discovery that followed on and that play is about a one in three type of prospectivity. So the program is looked at all the time. It’s looked at by people that are new to the company that have new ideas. So I think once we get back to being active, which is critically important. I think you will start to see results from the program. Get back to hopefully where we were before.

Two final questions, one, you’re talking about the reserve replacement and the funding and development cost in the 150% and $17, I presume that’s including the Syncrude reserve booking for the first time, this year because of the change in SEC rules? If we’re not including the Syncrude reserve, what are those numbers? Secondly, in the Canadian heavy oil, I presume right now with the $70 to $80 oil economy is really good. Surprised you’re not ramping it up. Is it a resource constraint they? Thank you.

Let me answer your last question first. We really like Seal and what was happening in that area was that we cut our activity because of budget controls. We did not do the EOR last year that we wanted to do because we were trying to manage our discretionary spend. We’re back to doing that this year. We’re back to adding a pipeline up there, which will give us a fuller season of production and reduce some of the risk on trucking. If I look at the total play there, primary production we recover about 6% to 7% of the oil in place. If this EOR works and this pilot will tell us a lot this year then you’re likely to go up to, I don’t know, 12%, 13%, 14%, maybe eve 15% of the oil in place and that’s a meaningful number and $30 million, $40 million, $50 million barrel type number. So I’m very keen to get after that and I think this year we’re in better shape than we were last year or the year before to get after that program. So that’s kind of how I view Seal, I like it and we are going to go back to work In terms of your F&D question, it’s pretty much a wash with the inclusion of Syncrude. If I look at the top five reserve adds this year, Kikeh, Sarawak gas, Tupper, Azurite, right there and I think the important thing to remember is those major fields we have booked a lot less than 50% of the 2P reserves. So we have a little running room in all of our stars here.

So Dave, do you have a number you can share, what’s the F&D cost and the reserve replacement without counting the Syncrude?

It’s the same thing, Paul it’s about $17.50 and about 150%.

Your next question comes from Blake Fernandez - Howard Weil.

Question for you on the Eagle Ford, I see you did a 13 stage frac, which seems to be kind of the industry average. Yet we have seen some folks testing more like the 17 and 18 stage fracs and I’m just curious if you’re, with the upcoming wells, are you going to be trying any kind of different frac stages or are you going to be sticking with 13?

The reason why we did 13 on this well is it was a deeper well, I think one of the deepest points drilled in the trend and we wanted to get information. So we only drilled a lateral of 3200 feet. The Karnes County well, which is to a shallower target, that lateral is 5,000 feet. So we’ll be doing more frac zones in that well. So I think the average is to move towards a larger number of fracs per horizontal type to how long we drill these horizontal. So I think we’ll be in that 13 this have to be this evaluation step that took place.

Question for you on production I know you said full year probably around 200 a day, maybe just north of that. Obviously with 192 in the first quarter, I’m just trying to think about how to balance out the year. I know we have some compression issues do you think a lot of that would be an elevated going into second quarter and we should be trending more toward the 200 level in second quarter?

We feel good about the 200, just over 200, Blake, I have to say and if I look at the delta between December and January, we did see some decline in places like Tupper, getting ready to bring new wells on, things there occur in batches. We did have one well in the Gulf of Mexico, go off a small well that we need to move a sliding sleeve on. We had some Syncrude issues and so forth. So I think those things are going to move to the right, but I think we’ll be able to catch up. We did have a little bit of a delay in Azurite and we have a well that’s ready to go but we have an FIV valve that will not open. We’ve had this problem elsewhere in the world before. So that’s causing us a little bit of a delay, but that’s a mechanical delay and Sarawak Gas we’re still working on getting these compressors to quit vibrating like my old car and be able to perform at the level and we’ve got steps in place to do that. So those are the things that I think we’ll get back, so just mechanical things get us back.

The last one from me, just on the royalty relief proceeds, I see that has not made it on the balance sheet yet. For one, do you have any idea on timing?

We’ve not been told when we’re going to get a check, and I can guarantee you that when we do, Mindy will come running into my office and tell me that we got the money, but hopefully it’s going to be relatively soon. As far as proceeds, we don’t identify things like that for a specific.

This is Kevin. That number is in the working capital, receivable set up since we booked it.

Your next question comes from Ray Deacon - Pritchard Capital

I was wondering if I could ask you about Motley and how you think the returns their might stack up to the Eagle Ford and what kind of laterals you guys are drilling their most recently?

The Motley its funny, you kind of get to almost same answer and we have more data with Motley, so but our guys are doing fabulous job up there where our drilling and completing cost in DD&A puts that gas at cheaper than $4 and I think that’s the game I have said this before I think we are going to live in an over supply gas world, be never to bring things on and produce them for less than $4 is really important. If I look at the well performance in the market for us as wells continue to get better and better Tupper main what we have on production as we look at the well results in Tupper west, which is not yet on production, the deliver ability I think and the quality is actually better in Tupper west and Tupper main. So I expect that those wells are produce a little bit better to don’t have any data but I expect they well just by…

Also I guess given your view on the gas market, what are your thoughts about hedging now that gas is becoming a bigger part of the portfolio?

Yes. We’ve done one forward sale so far for a small amount out of Tupper main, a little over 30 million a day, and when you see the gas market in the contangle that it is, kind of makes sense. So we’ll evaluate that going forward, if there’s good opportunities to help keep these programs running along, comfortably, then we’ll look at those.

Your next question comes from Anthony Guegel - Upstream Newspaper.

Just couple quick questions. You mentioned Dalmatian you expect a sanction this year. What is the plan for development and what’s the date for first production there?

We’re going to have to drill the DC full well first and then know its results before we’ll bring that forward for sanction through our partners and ourselves. So that’s really kind of the data point that we’ll get here in the first half of the year. The well is going to here pretty imminently. As far as the development goes, we still have a favored route. We still have some other options. So I’m a little load to kind of telegraph that. That will be part of our sanction, but the way I look at it, Anthony, it will be a two well development assuming the DC full works and the tied, subsidy tiebacks to somebody else facility.

The other question I had. I was curious about Medusa. I imagine you have some excess capacity there. Any plans for filling that excess capacity?

Yes, we do have a nice facility there and we have got third parties that are looking to use it. So that’s part of our business that our guys in the Gulf run to reduce our overall cost, so it is one of those nice hub facilities that we use.

What is the current production rate there?

Anthony, this is Mindy. Medusa gas for the first quarter we have it in about little over 6 million cubic feet a day and a little over 6,000 barrels of oil a day. That’s net to Murphy.

Yes. Okay, but no plans for you yourselves as operator to drill any satellites in that immediate area or anything like that?

Yes, not right now.

Your next question comes from Gene Gillespie - Gillespie Consulting Group

David, now that all the professionals are out of the way, I wanted to ask you something. Actually, this is a modeling question, so Mindy or Craig probably more appropriately handles this. What does it look like the profit barrel; cost barrel split in Malaysia will be in the first quarter?

For first quarter, Gene, it’s the same really for the full year, we’re process in low 60% entitlement and a split, if you do the math to try to make an entitlement of 62%, what you end up with is about, if you break down the 62%, it’s about 20% cost barrel, 42% profit barrel and so just as a reminder, it’s those profit barrels that go into that entitlement payment so roughly two/thirds.

That was very similar to fourth quarter?

Yes.

Your next question comes from Kate Lucas - Collins Stewart.

Just a quick question on your, it looks like you’ve got an under lift position in Malaysia that may not completely reverse even if Malaysia is the source of all of the sales in excess of production in 1Q. So do you anticipate that reversing during the first half of the year or should we think about that reversing over the course of the entire year?

Well, you’re right, Kate, at year end we did have an under lift position in Malaysia of about 1.3 million barrels and we’re not going to resolve that first quarter, but it will resolve over time, but whether that’s going to occur, second quarter, third quarter, it may take us that long to do that, but these inventory balances do bounce around from quarter to quarter so we will work that off, but it may take us a few quarters to do it.

Kate, you have to remember that we lift 600,000 plus barrel cargoes and we lift about one every six or seven days. So you can move that around pretty quick.

Your next question comes from Mark Gilman - Benchmark Company.

David, where do you stand on perhaps additional activity in the northwestern shelf of Australia?

Next year we’ll get to drilling, Mark, and so I’m excited about that. We’ve got a couple of box with some nice looking prospects and that’s what is in our plan. If I could have drug it into this year, I would have done, but it’s a 2011 activity.

Just one other one, if I could. Could you remind me, regarding the PSC in Malaysia, is this ringed fence for the block as a whole or on an individual field by field basis? In other words, raising a question, if you have un-commercial exploratory wells, do you get cost recovery on it?

Yes, Mark, you’re exactly right. Block K doesn’t distinguish. We talk about Kikeh and we talk Kakap, but it is a PSC that doesn’t distinguish costs within that block and so dry holes that we drill get into the cost recovery pool and get recouped against the revenues that we’re generating from any production in the block. Similarly, the Kakap development costs also get recouped. So you’re exactly right.

How about P&H, David, is it the same thing?

Block H, we don’t have any production and there is no connection between Block H and Block K and similarly in Block B all we’ve done is explore, we haven’t done any production there. It is once you establish that production, Mark, you’ve then be able to recoup subsequent costs, but you build up that exploration expenditure if you will that you will get to recoup against any future production.

The PSC is for each of the blocks individually?

Yes.

Your final question comes from Paul Cheng - Barclays Capital.

Real quick, in Congo, maybe you already mentioned if I missed it, I apologize, when you expect that to ramp up to the peak production and that seems you still only have one well, is that a rig availability issue; why that we didn’t see a faster pace in terms of getting the production up?

I did touch on it. The whole development is a six producer, four injector development and currently we have one producer, which has been up for some time and doing very well and we have completed a second producer that should have been on before today. The problem that it isn’t on is we have this valve in the completion strain that is not cooperating. So we’re going to have to go in and take some time and beat on it a little bit and get it to cooperate and once that is done, and that well will come on, and then over the course of the remainder of this year, we will get the rest of the wells brought on, including the water injection. As far as rig goes, this is an FDPSO so the rig is actually on board the FDPSO, so we don’t have any rig issue. It’s just a question of getting the work done that’s laid out in front of us.

So Dave, when do you think you’re going to reach the peak production?

Second quarter, Paul.

Thank you. There are no further questions at this time. Please continue.

Well, thanks everyone. I appreciate you dialing in and look forward to the next call next quarter. Thanks a lot.

Thank you, operator.