Good morning ladies and gentlemen and thank you for standing by. Welcome to the Murphy Oil Corporation’s first quarter earnings release conference call. (Operator Instructions) I would now like to turn the conference over to Claiborne Deming, President and Chief Executive Officer of Murphy Oil Corporation.

Thank you, and good afternoon. I’m joined today by Kevin Fitzgerald, Senior VP and Chief Financial Officer; John Eckart, VP and Controller; Mindy West, VP and Treasurer; and Dory Stiles, Manager of Investor Relations. I will turn it over to Dory at this time.

Thanks, Claiborne. Welcome everyone and thank you for joining us. Today’s call will follow our usual format. Kevin will begin by providing a review of first quarter 2008 results. Claiborne 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 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. Many of these have been identified in Murphy’s January 1997 Form 8-K filed with the SEC. I will now turn the call over to Kevin for his comments.

Thanks Dory. Net income in the first quarter of 2008 was $409 million or $2.14 per diluted share. That compares to the net income in the first quarter of 2007 of $110.6 million or $0.58 per diluted share. The 2008 quarter was favorably impacted by higher crude oil sales prices and volumes, partially offset by much tighter margins in the downstream part of the business. The 2008 quarter included an almost $40 million gain or approximately $0.20 a share related to the sale of all the Berkana Energy shares that we held in Canada. Looking at income by segments, E&P, the first quarter of 2008, net income was $428 million, compared to net income in the first quarter of 2007 of $88.8 million. Higher E&P earnings for 2008 were attributable to both higher oil and natural gas sales volumes and higher realized prices when compared to 2007. Crude oil, condensate, and gas liquids production for the current quarter averaged approximately 113,300 barrels per day compared to approximately 84,600 a day for the corresponding 2007 quarter. The increase was attributable to production from the Kikeh field in Malaysia which came on stream last August, partially offset by declines in the Gulf of Mexico, Western Canada, and at the West Patricia field in Malaysia. Natural gas volumes at 69 million cubic feet per day in the first quarter of 2008 compared to 61 million cubic feet a day in 2007. Most of this increase was due to production at the Mondo Northwest field in the Gulf of Mexico, which came on in July of last year and that was partially offset by a reduction in Canada due to the previously mentioned sale of the Berkana shares. The downstream segment, in the first quarter of 2008, we had net income of $10.2 million compared to $35.7 million of net income in the first quarter of 2007. Downstream was also significantly weak in the U.S. due to poor refining margins resulting from higher crude prices. However, results in the U.K. were improved over the first quarter of 2007 largely due to our now having 100% ownership in the Milford Haven, Wales refinery, compared to the 30% we owned in the first quarter of 2007. As you recall that transaction was effective last December 1. In the corporate segment, we had a net burden in the first quarter of 2008 of $29.2 million compared to a burden of $13.9 million in the first quarter of 2007. The higher cost in the 2008 quarter was a result of higher foreign exchange losses due to the weak U.S. dollar, higher stock based and other incentive compensation, and higher net interest expenses. At the end of the first quarter of 2008, our long-term debt amounted to $1.7 billion or approximately 24% of total capital employed. And with that, I’ll turn it over to Claiborne.

Thanks, Kevin. I will spend a few minutes on each of our major businesses to give you a feel for where we are and more importantly where we are going and I will start with E&P. Having new production come on stream in the current pricing environment is obviously of tremendous benefit. Kikeh is the main driver of our production growth with 7 wells producing 66,000 barrels a day from a field located in Block K offshore Sabah, Malaysia. Additional wells are currently being backed set with the next group scheduled to come on stream by midyear. By the end of the year, production will reach the plateau rate of 120,000 barrels per day, if field continues to perform as modeled. Meanwhile, development work continues elsewhere. In Sarawak, Malaysia, Phase I of our natural gas project remains on track for first quarter 2009 startup. By the way, as our realized price is tied to LNG landed prices in Japan and Korea, a recent run up will directly benefit the economics of this investment. Ground preparation has been completed for our onshore receiving plant adjacent to the Bintulu LNG facility, which will ultimately process the gas. Both Thunder Hawk in the Gulf of Mexico and Azurite, offshore Republic Of Congo remain on track for first production in the second quarter of 2009. Formal ministry approval has been reached for the sale as part of our working interest in the Azurite field. As you are aware, we’ve retained a 50% working interest and operatorship. At Kekap, our other oil discovery in Block K, Malaysia, batch drilling is now underway for its recently sanctioned development scheduled to commence production in late 2012. Production at Tupper, our Montney type sands gas resource play in British Columbia, is scheduled to begin in the fourth quarter…

Our first question is from Benjamin Dell - Bernstein.

I had a couple of quick questions. Previously, you talked about the M&A environment and looking at asset deals. Have you seen the market change, obviously, with the run up in crude and do you now consider that it’s something you’re going to get priced out of or is that something you’re still actively looking at?

No. We’re still looking at it, Ben. Typically, our preference has been natural gas, because we’re such an oily company and we’re certainly not fearful of going internationally for natural gas assets. And those haven’t quite responded as the same as oil because their price obviously hasn’t run up quite as much. But I think it’s a difficult time to be finding good assets to buy. I think that’s certainly undeniable. But the types that we typically look for, we like to think we are an advantaged buyer either through superior knowledge on assets that others might not see current value in. So, we’re still looking.

Okay. And my second question was just on production quarterly. The second quarter guidance seemed relatively light. Can you give us in detail on where the real weakness is in that second quarter and also with the Kikeh wells, how many wells will be coming on stream and their net contribution per well?

Ben, there’s not one thing that we can point to but I’ll give you list of several items that make up that difference between the second quarter and the first quarter. We have: 3,000 barrels a day from the Gulf of Mexico, primarily, as Claiborne mentioned, from Mondo Northwest being shut in; 3,000 BOEs per day of heavy oil; primarily, we’re in breakup period there and with the Lloydminster property being sold later in the quarter, we lose some barrels there; 3,000 barrels in the U.K. primarily (chihaleon?) maintenance later in the quarter; And 3,000 barrels offshore Eastern Canada, primarily related to the Terra Nova shut down for repairs in June. We gained about 4,000 barrels a day from Kikeh. Some additional wells will be coming on into the quarter as well.

So that’s the second versus the first quarter, Ben. We’ve got seven wells on; we’re a bit over 60,000 barrels a day; we’re going to be bringing 3 on in June and we’ll get up to around 80,000 barrels a day. And then the balance of the wells either come on in either 1 or 2 more tranches; we’ll have 14 at the end of the year for the 120,000 barrels a day.

Okay. Thank you.

Our next question comes from Arjun Murti - Goldman Sachs.

Thanks. Claiborne, any change to the capital spending budget this year?

Arjun, not materially. No, there’s not.

So like a 2/4 kind of a number, I think?

Yes. Just closer to 2/8, Arjun. We’re flipping through some numbers real quickly now but there’s nothing...

Yes. Just under 2/8.

No, there’s nothing hugely material.

That’s great. Thank you.

Our next question comes from Paul Cheng - Lehman Brothers.

Claiborne, when, now that the associated gas from Kikeh is going to be start up?

Some time this summer. It is a pipelay vessel, which is coming out of shipyard that we assumed would already be on location. It’s not and it’s a bit fuzzy but I would say this summer; later in the summer at the latest and perhaps earlier.

I see. I think at one point talking about Superior for the expansion to 200,000 barrel per day, any update there? And also, just any change in your view on the overall downstream operation given the weaknesses that we see in the margin. Do you think this is still part of your core operation going forward or that that has been changed in your view?

With respect to Superior, no change. We’ve certainly looked at lots of options there because of the location of the plant, obviously, on the pipe and close to market and with the expansions going in Athabasca. But there’s no update or anything that’s occurred in the last three months that would change where we are there, and we currently have no firm plans at Superior. As far as whether the downstream is quadrennial, certainly wouldn’t let three months impact as much there, but certainly, as I’ve said before, we leave all of our options open, it would be foolish for me to say otherwise. It’s an asset that we just added to by adding the other 70% of Milford Haven and down the lane at Wal-Mart, so it’s stronger, it’s firmer. And the asset in UK Milford Haven is performing extremely well, operationally as well as financially. I’m real glad we own it right now because it’s the highest returning plant and asset we have in our downstream business in fact. But no, I wouldn’t let the last three months change your mind for an asset that you keep for literally decades.

And Claiborne, when you’re talking about 130,000 barrel per day for this year, what’s the contribution of Kikeh within that?

Mindy is saying about 55,000.

And you have indicated that the SK 309, 311 the gas sales contract or the project seems now is on schedule. Are we still talking about it in the third quarter 2009 or just later? It’s more like fourth quarter now.

No. We had always said first quarter 2009, Paul.

So that is still on schedule? Without any problems?

I don’t see any delays there.

Okay. Very good. Thank you.

Our next question comes from Ryan Todd - Deutsche Bank.

I know you have a very active exploration stretch coming up here which could materially change how you see things going forward, but can you comment on allocation of cash going forward with extremely strong commodity prices. How you expect to use your cash?

I think, as I said before, the highest and best employment of our capital and our cash is developing a high margin oil and natural gas fuel and so if that is an option for us, I can clearly state that’s where we will go. We’ve been working on a program here for a year and a half and we had a program that we’re going to start drilling in mid-year, so we can see how that unfolds. And the Eastern Gulf prospects, in particular, are attractive in terms of risk versus reward, in terms of probabilities of success. I’ll probably condemn one by saying that but there’s good looking prospects with reasonable chances of success. Buntle is riskier but it’s bigger and it’s very large and then we have the West African prospects that we farm down a bit the risk that way and, as you know, it shot some additional seismic. So it’s a pretty good looking program. I want to see how it rolls out before we make any alteration or change in how we allocate capital. And then I always say having said that, I’m an owner like you’re an owner and as owners we like to get paid and like to be paid for owning the stock. I’m certainly aware of that and then if something other than investing in producing oil and gas fields or buying something very attractable on the downstream side shows up then we’d look at some other options.

What are your thoughts on special?

If you look back at the history of Murphy, we bought back stock from time-to-time not much recently, and we steadily increase our dividend. And we were dividend payers all the way back in the ugly ‘90s when a lot of people either suspended or stopped, and we went all the way through. So I think if you look at the sweep of time for us, pretty steady increased dividend payers, and we’re aware of the cash flow is enhanced, and we’re aware that shareholders have needs. And so we’ll certainly be mindful of that as our Board deliberates in the future, but we typically haven’t had special dividends, we typically have not. You never say never and you never say because we haven’t done it in the past we won’t do it in the future, but I would more steer you to what we have been in the past in that regard.

Great. A couple of just quick things: churn on is that still on tap for 2009 and has anything changed as you’ve looked at seismic and prepared down there?

No. Nothing has changed. We’re looking to farm down there and once we do, we’ll shoot 3-D, and we’ll drill a well next year. The plan is to definitely drill a well next year.

Okay. And finally, one last thing on the full year volume guidance. I know obviously the second quarter operational issues and turnarounds are going to have a material impact on the full year guidance. How much of the downgrade from the 135 is PSC oriented as opposed to the issues from the second quarter?

It’s about half.

Okay.

I’m finger-painting a little bit but about half. We have increased royalty at Syncrude due to higher prices and then at West Pat it’s just increased government take due to faster payout but there’s also another element of West Pat that I just didn’t want to belabor in the remarks and that is we’re spending a bit less capital that we didn’t forecast in our budget. So, there’s less overall cost oil where we have a higher allocation out there in the pool. So we get paid back faster and when we have less costs to (inaudible). So those two are about half and then, the other piece is first quarter at Syncrude was a bit ugly and we had (inaudible) excursion into some units and we had some pretty substantial unplanned downtime there. Plants partially down now but was planned but they are supposed to be up and running for the balance of the year. And then Kikeh gas, the delay there, I think we had it coming on second quarter perhaps. It’s material because it’s a pretty big number for us and so that’s the other half.

Okay. Thank you very much.

Our next question comes from Mark Gilman - Benchmark.

I think you said that you’ve drilled 9 wells in the Montney so far. Give me a rough idea what kind of IPs you’re seeing on those wells and what the recovery rate expectations look like?

Mark, on the verticals, we’re in the 2 to 3 million cubic feet a day range. And so far in the horizontals, and interestingly, we’re at about the same range. We have one that is out of that range but most are in the 2 to 3 million cubic feet a day range in horizontals. They’re right next to verticals, which are producing that same. So, we got a bit work to do to learn how to frac that a bit better, but it’s within the range that we had anticipated; I think in our horizontals we said 3.2 − or something like that − million feet per day to get the right amount of production that we would like. And the recovery factor, I think is 4 Bcf a well, plus or minus.

What percentage of that is likely to be in place, Claiborne, do you expect?

Mark, I don’t know if I know that off-hand. We’re talking about 2 Tcf we plan to recover after royalty, and I think we are saying there is 5 or 6 Tcf in place, somewhere around there I think. I am grabbing a little bit but I think that’s roughly right.

I would have thought the recoveries were closer to 50% than that would imply.

Because of the royalty issue?

So you are comparing net to gross in that?

Yes I am saying that our net would be somewhere around 2 Tcf and I think gas in place is around 5 or 6, so yes it sounds like 40% is what I’d say; 40% to 50%.

Okay. Claiborne, I was interested to see your participation in the Central Gulf sale. I wonder, given the fact that this has not been a great area for you, if you could talk a little bit about what your thinking was? Why the aggressive participation and where are your head’s at in terms of operator versus non-operator in those minusing plays?

Mark, I would tell you what got our attention is that first of all we have a big position here. We got about 35 or 40 leases primarily in the Central to Western part of Green Canyon and we anticipated last year that one of this wide-azimuth surveys and my trouble is it’s not a step change in clarity or the ability to match up salt but it’s a material noticeable improvement. So we are able to see prospects better than we have in the past and this particular prospect that we were a high bidder on – at a recent conference I said my ancestors are turning over in their grave, my Murphy ancestors, for bidding with a high bidder or a loose sale is something they typically hadn’t done. But we are with a company that had a nearby field and this was very similar to the nearby field, we could see it very clearly and that it had good seismic attributes. And so, the combination of those two, the one azimuth, and near a producing field that it had a very close similarity to, gave us the confidence to do it. If you noticed in last year’s Eastern Gulf sale, we bid pretty high per block as well. And it’s certainly reflects a bit of a change in the sense of our bidding strategy to spend a bit more, get the ones that we absolutely feel very good about and make at least a concerted effort to get those. And this block that we got in the last lease sales certainly manifests that.

Claiborne, I seem to recall Kikeh having been at about the 70 level at the time of the fourth quarter conference call about three months ago, pretty sure my recollection is correct and I think you said that it’s 60ish now?

The number I used was 66, Mark.

Okay, so it’s falling off a little bit and that’s consistent with expectation from those wells?

I wouldn’t read much into that. The field is producing as modeled and there may have been a well that went down for a while for some reason that might get us a 66. I don’t think there’s any worries there.

Okay. Thanks a lot, Claiborne.

Our next question comes from Erik Mielke - Merrill Lynch.

My question also relates to Kikeh. I am trying to look into 2009. If oil prices stay at healthy levels, above a $100 per barrel, what does that do for your entitlement in a 2009 scenario?

That is an issue; it will bring payout sooner than $70 of oil will be and we haven’t modeled it yet, but it will certainly be earlier in the year rather than later in the year that that would occur if oil prices stay up at this particular level and Tupper, which is what we benchmarked off of, in particular it’s been a very competitively priced crude. When I say competitive, it’s been a high priced crude. It’s good news, sure; we are making lots of money. On the downside we need PSC as you get paid out faster and your take goes down. But financially obviously we’re whole.

Okay, and for Tupper what contribution do you think that could make to your 2009 production profile?

I don’t have that to hand, but we will exit the year around 70 million a day plus or minus and then we will just build up all of next year. So, I don’t have a number for you. But we will get you one.

But it’s a pretty steady increase.

Yes. Our thought it’s just to keep drilling and this is Tupper 1 and then we have Tuppers 2, 3, and 4 coming and we are going to do some exploratory work there this year. I think we are going to drill 8 or 9 wells on those other assets and then we will have a better sense of what we have there even though we have a pretty good sense right now. But we’ll just keep drilling now for the next, actually, 6 or 7 years in that area.

And for Sarawak gas you mentioned that you are getting prices linked to the Asian LNG prices. Is that on a pure net back parity or is it a discounted price with a link to the moving prices?

We can’t disclose price because of contractual reasons, but we have always said that we net back at the well head a percent of what landed LNG is out of Dua.

Okay.

And that is a combination about contract terms and spot.

And finally in the downstream segment, you have obviously being adding assets in the last couple of quarters. Looking forward and where your cash flows are, are you more likely to be adding than selling assets in the downstream business?

The reason we bought the two that we bought is because one, the one made under Wal-Mart, that’s a wonderful asset and we made that asset even more wonderful and stronger and as we say took risk out of it. And then in the U.K. it’s a good macro market to be in and we got a particularly attractive price. And so both of them were a bit unique and I don’t think reflects necessarily a strategy of expanding widely, they just made current assets that we already have stronger assets. We tend to do deals like that where we have a levered position, where we can pay what we think is an attractive price and make what we have. If something came up that seemed particularly attractive we might certainly take a look at it, but we don’t have a particular strategic desire or urge to grow that end of our business hugely.

But you feel that your existing downstream is a good match for your upstream?

I didn’t say that. Our upstream business is certainly the larger part of our business and the part of our business that does grow. Our downstream business grows in the retail sector, where we have competitive advantage. And that we will feed capital to and you’ll see us continue to grow that, because it’s quite a healthy asset to own. But most of our capital right now, allocated towards the upstream side.

Right. Thanks for your time.

Our next question comes from Gene Gillespie - Howard Weil.

Claiborne, would you share with us the underlying assumptions implicit in your second quarter guidance, particularly as it relates to exploration expense downstream?

Yes, Dory will do it.

Gene, here is the assumptions we used in our guidance. Production of course you have 115,000 BOEs per day based on sales volume of 108,000 BOEs per day; realized oil price in the range of between $95 and $99 as a worldwide realize for us; natural gas worldwide realize gas price of a $11; total exploration expense in the range of $60 to $70 million. Included in that range is $10 million exposure for dry hole cost with mainly drilling with the Buntle well. The downstream segment we have $25 to $30 million built in and corporate, reflecting a loss of $23 million.

Okay. One last thing Dory, can you provide the impact that the supplemental tax cost your Malaysian realization in the first quarter?

About $35 million, Gene.

And that was the combination of Kikeh and West Pat?

That’s correct.

All right. Thank you very much.

Our next question is a follow up from Mark Gilman - Benchmark.

Claiborne, it almost seems just based on the arithmetic that you are, or have at times, been running Milford Haven at above nameplate. Is that true?

I don’t think so, Mark. I don’t think so. It’s a 108,000 barrel-a-day plant.

So, you don’t think that there is room to expand?

I wouldn’t say that; you mean to squeeze a few more barrels out of it?

Yes.

I won’t say yes and I won’t say no. If there is we will because the market there is quite healthy. But I think we are running just about near capacity; it’s a crude unit limit.

Okay. It’s also appeared from looking at some of the numbers as if you have started to buy gasoline in the U.K. for resale somewhat more aggressively. Is that a change in thinking or am I misinterpreting the numbers?

Don’t know what you are looking at but no, there has been no change in thinking there. That plant has got an oversize cracker. When we built the cracker, which is how we actually got our first 30% interest and it’s oversized relative to the crude unit and I don’t know if that is instructive to what you’re thinking or not.

Just looking at the U.K. gasoline sales versus gasoline make?

I can’t help you. I am sorry. I will do some homework and see if there is anything but there’s no strategic, no strategy change; there is nothing there but we have a commercial business, we have a wholesale business, and then we have got a retail business. As you might know we bought 60 more sites 18 months ago. So, they are in the mix, but they were in the mix this time last year as well I believe. But otherwise there has not been a material change there.

If you could just refresh my memory, the associated gas volumes at Kikeh, what’s that likely to be at 5/12?

Initially 20 million cubic feet a day or so ramping up to around...

120.

Yes, 120.

Is that a net number or gross?

No, it’s gross.

Gross, because the 20 I was starting to quote you was just a net number.

Okay and the 120 is what?

That would have been the gross number.

Okay thanks.

Mr. Deming, at this time I am showing no further questions in the queue. Please continue.

Thanks very much and I look forward to seeing you on the road and the next conference call. Thank you.

Ladies and gentlemen this does conclude the Murphy Oil Corporation’s first quarter earnings release conference call. AT&T would like to thank you for your participation and you may now disconnect.