Murphy Oil Corp (MUR) 2012 Q1 法說會逐字稿

Good afternoon and welcome to the Murphy Oil Corporation first quarter 2012 earnings conference call. Today's event is being recorded. I'll turn the conference over to Mr. David Wood, President and Chief Executive Officer.

Good afternoon, everyone, and thank you for joining us on our call today. With me are Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; John Eckart, Senior Vice President and Controller; Mindy West, Vice President and Treasurer; Barry Jeffrey, Director of Investor Relations; and Tammy Taylor, Assistant Manager of Investor Relations. I will now turn the call over to Barry.

Thank you, 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 first-quarter 2012 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 factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2011 annual report on form 10-K, filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

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

Thanks, Barry. Net income in the first quarter of 2012 was $290.1 million or $1.49 per diluted share. This compared to net income in the first quarter of 2011 of $268.9 million or $1.38 per diluted share. There were no unusual items significant to the 2012 quarter, but Q2 2011 did include $30.5 million or $0.16 per diluted share of income from discontinued operations related to the two US refineries and associated marketing assets that were sold at the end of the third quarter of 2011.

Taking a look at net income by segment, the E&P segment for the first-quarter 2012 had net income of $321.6 million compared to net income in the first quarter of last year of $260.4 million. Higher E&P earnings for 2012 were primarily attributable to higher average crude oil sales prices and lower exploration expenses. Unfavorable variances in the 2012 quarter included lower crude oil sales volumes, and significantly lower North American natural gas sales prices. Crude oil, condensate, and gas liquids production for the quarter averaged approximately 107,500 barrels per day in 2012, compared to approximately 113,300 barrels per day in 2011. This decrease was mostly attributable to lower gross volumes of Kikeh in Malaysia and Azurite offshore in the Republic of Congo. Natural gas volumes, however, were a quarterly company record of 525 million cubic feet per day in the first quarter of 2012, compared to 413 million cubic feet per day in the 2011 quarter, an increase of over 27%. This increase was primarily due to a full quarter of production at the Tupper West area in British Columbia, which was on production for only a portion of the 2011 first quarter, after coming online in February of last year.

In the downstream segment from continuing operations, we had net income in the first quarter 2012 was actually a net loss of $4.2 million compared to net income in the first quarter of 2011 from continuing operations of $300,000. In the US, downstream operations reported a loss of $7.2 million in the 2012 quarter compared to income of $9 million in 2011, mostly as a result of lower retail fuel margins, which averaged $0.02 per gallon lower in the current quarter and lower retail fuel sales volumes which were down about 6% year-over-year. Merchandise margins for the 2012 quarter were essentially flat with last year. Results for ethanol production operations were also down year-on-year due to weaker crush spreads. UK downstream operations reported income of $3 million in the 2012 quarter compared to a net loss of a $8.7 million last year. The improvement was largely due to better refining margins and higher throughput volumes at the Milford Haven refinery.

In the corporate segment, we had a net charge of $27.3 million first quarter of this year compared to a net charge of $22.3 million in the first quarter of 2011. This unfavorable variance was mostly attributable to higher administrative costs and lower interest income in the current quarter. At the end of the first quarter of 2012, our long-term debt amounted to just under $250 million, or 2.7% of total capital employed. Cash, cash equivalents and short-term investments totaled over $1.4 billion at March 31. Earlier this week, our 10-year $350 million bonds matured and were paid off through borrowings under our revolving credit agreement. We're currently working a process to sell $500 million of new ten year notes, the proceeds from which, if successful, will be used to repay those borrowings and for general corporate purposes. With that, I'll turn it over to David.

Thanks Kevin. Benchmark WTI prices averaged near $103 for the first quarter. David Brent, the marker for much of our production, outpaced WTI with the spread currently below $15. Our 2012 budgeted oil price was set at $85 WTI and $100 Brent. Based on recent history, we have revised these benchmark prices up to $95 and $110 respectively for our latest outlook.

Actual gas prices in North America have been disappointing for many in the first quarter of 2012, Henry Hub beginning the year near $3 and continuing to fall, settling near the $2 mark, as unusually warm winter conditions exacerbate an oversupply situation. We continue to see weak North American natural gas prices over the midterm, and as a result have cut spending on all our dry gas initiatives and are redeploying capital and rigs to our oilier North American plays. We also have plans to shut in 30 million cubic feet a day at Tupper. Naturally, this will impact our budgeted production volumes for the year, but with liquids places to invest, will stand us in better financial stead. US retail margin struggled in the first quarter on the back of persistently rising wholesale prices, but these have recently started to rebound as we exit this typically weak season. We continue to move forward on our repositioning efforts with evaluation work on the retail spin continuing, and the UK downstream sales process still ongoing. And we look to take this to our board later this year.

We're off to a nice start with our 2012 exploration program with three discoveries from three attempts already ready in the first quarter. Our two Block H wells in Malaysia made nice gas discoveries, which will be combined with plans to develop plugging (inaudible). In addition, the Julong East well in Block CA-1 offshore Brunei is a discovery. We're recently spud our first well in Iraq on our central Dohuk block in the Kurdistan region and are making encouraging progress. The rest of the year will see continual activity. In the Congo, we should look to spud our pre-salt prospect in the MPN block in the third quarter and test other prospects in Australia, Malaysia, Brunei, and the Gulf of Mexico. Our activity level in the Gulf of Mexico is slowly ramping up as we commence side track operations at the Thunder Hawk No. 4 development well late March, and expect to have it completed and on production in the second half of the year. To support our program there and worldwide, we are securing a three-year term on another deepwater rig.

Moving to our North American resource plays, we currently have 14 rigs contracted in North America, ten in the Eagle Ford and four in Canada waiting on spring breakup. Three of these rigs will be back to work at Seal, and the other rig will float between the Montney, South Alberta, and our new oil play in the Muskwa. In the Eagle Ford shale, we now have ten rigs running and are looking to add two more by year-end. We're operating two dedicated frac spreads and are looking to add a third crew shortly. We have stepped up the pace here based on strong results and redeployment of capital from dry gas areas, and now expect to drill 43 more wells [if] budgeted and complete an additional 34. To date, we have drilled 87 wells in the play and have 18 awaiting completion.

Current net production today is 11,800 barrels of oil equivalent. With our revised outlook, we should average approximately 15,000 barrels of oil equivalent a day net for the year. We have lots to do in the Eagle Ford with over 2000 oily locations yet to drill. Accelerated activity is ongoing at the Seal heavy oil project in northern Alberta with three rigs operating coming out of breakup. We expect to drill 71 production wells this year, up by 22 wells from our budgeted plan as part of our capital redeployment.

Results from our polymer pilot continue to be encouraging, and we have received approval on our commercial polymer project with phase one injection to begin around midyear. We have also received subsurface regulatory approval for a cyclic steam pilot and are awaiting facilities approval with expectations to start the pilot work late this year. Additionally, we will submit an application for a steam flood project by mid year. Production should average approximately 10,500 barrels for the year with sights set on getting to 20,000 barrels a day as soon as we can. At Tupper and Tupper West, we have reduced our capital spend in the Montney dry gas by $153.6 million from budgeted levels. Over the year, we will now drill 14 wells compared to our original budget of 37 levels. This will impact our 2012 production by approximately 3000 barrels of oil equivalent per day. We're also going to shut in an additional 30 million cubic feet of gas per day while still managing to take -- still managing our take or pay export capacity levels. This is clearly the right bottom-line focus in this low gas price environment, and if needed, we will curtail production further.

In southern Alberta, we continue to see positive results from our first well completed in the three Hawk zone, with production rates now over 400 barrels of oil per day of light oil and a well that has been producing over 120 days. We have fixed the wax buildup in that well and have been rewarded with these higher rates, a promising sign for this area. We have just completed our second well in the same zone and are monitoring initial production results. With this encouragement, I expect to step up activity here this year. Our fifth North American resource play is located in northern Alberta, on the Muskwa oil play. So far, we have accumulated 170,000 net acres and our first well flow light oil and initial production rates in the 50 to 100 barrel a day range. This is somewhat encouraging and we are looking to put that well on pump for further evaluation. Still early days for us, and we are planning to drill another well later this year to continue testing the play and our completion techniques.

First quarter production averaged just over our guidance of 195,000 barrels of oil equivalent per day. Production guidance for the second quarter is 185,000 barrels of oil equivalent per day, down 10,000 barrels a day from Quarter one as we see the impact of unplanned turnaround activities associated with Syncrude, the Medusa pipeline and the methanol plant taking Kikeh gas, and these collectively contribute nearly 6000 barrels of the shortfall. The remaining 4,000 is related to a lower Kikeh oil and Montney dry gas production. Reduced Montney gas production is tied to less spend and a decision to curtail some production due to cost. For the full year, this will reduce production by 4,500 barrels of oil equivalent for this asset. Kikeh is being impacted by slower than planned work overs, a field shutdown for new manifold installation, and two wells shut in pending work over. For the year, we see Kikeh near 46,000 barrels of oil equivalent net. Altogether, these production revisions place the [193,000] barrels of oil equivalent per day compared to our original 200,000 barrels per day budget, with two thirds of this reduction reflecting less North American dry gas production.

In business development, we continue to pursue both on acreage in our North American resource plays and evaluate new growth opportunities. I expect to announce new adds in West Africa and Southeast Asia later in the year. US downstream business had a difficult first quarter as US retail margins were depressed in a steadily rising wholesale price environment. Retail margins started to turn around in March and have recovered to start the second quarter as they typically do. First-quarter net income was a negative $7.7 million with a positive cash flow of $9.4 million. We added five new stations to the US retail chain in the first quarter, bringing our total to 1,133, with plans to end the year at 1,175. As I speak today, our station count stands at 1,137.

In renewable energy, our two corn-based ethanol plants in Hankinson, North Dakota and Hereford, Texas continue to operate reliably at full capacity in a tough market environment. Crush spreads have been under pressure as ethanol prices remain well below gasoline, with strong ethanol supply effectively hitting the [blank] wall on a sluggish gasoline demand. Cattle feed prices have remained strong, tracking corn and providing solid revenue stream to offset operating expenses. The UK downstream business provided a positive contribution for the quarter in an improved margin environment with the UK retail business continuing its steady performance. The Milford Haven refinery took the opportunity in the first quarter to do some maintenance work and is now benefiting from an uptick in the market as margins have improved due to run cuts associated with seasonal maintenance programs.

In summary, we're off to a good start in 2012 and are making the prudent adjustments in response to low North American natural gas prices. The exploration program is off to a promising start with three discoveries from three attempts, first quarter production met guidance, we have cut spending in our dry gas areas and have redeployed capital and rigs to our oilier plays, Eagle Ford and Seal, in response to current market conditions. We continue to appraise our southern Alberta acreage with good encouragement, and our new Muskwa oil play has flowed oil on the first test. US retail has rebounded from a difficult first quarter, which is typically our weak shoulder season and is showing expected improving performance heading into the second quarter. Lastly, our repositioning efforts continue with the UK sales process in evaluation of separating our E&P and downstream businesses. That concludes my prepared remarks, and I'm happy to take your questions.

Thank you.

(Operator Instructions)

Blake Fernandez, Howard Weil.

Good afternoon guys, thanks for taking my question. David, if I could go back to Kikeh. Can I just confirm -- the work over issues, does this have to do with the previous work over wells, or is this ongoing maintenance that you just haven't completed yet?

Blake, there was really some things in the first quarter that impacted Kikeh. One of which, we changed a rig out that was not performing very well and we brought a semi-rig over from Indonesia. It had been in Malaysia before he brought it back. So it is performing much better. We did that at the end of January. We did, on the other rig -- because there are two rigs working in the field, one on the spar have a stuck pipe incident which lost us six weeks on our work over program. And that has impacted us.

We also had a manifold installation there for wells that are going to be brought on later in the year, so all of those had an operational impact. And then we had two wells that went -- that were shut in for screen failure basically. And these are a carryover from wells that we had before. So if we look at our work over program, we have six expandable screen wells to work over, including these two that went off, and we will work those over during the course of this year. The two that have gone off.

Okay. And just to confirm though, the previous gravel packs, are you experiencing problems with those that were done last year?

No, if we look back a year ago, we now have equipment in the field to remedy this, and we now have done seven wells where we have completed them with these open hole gravel packs or frac packs. Four of those were wells that had problems. We had no problems with any of those seven including the four that were remedies. I think we are in a good shape here now with both equipment in the field to perform the work overs if needed and also with the technique that has shown that it fixes the problem. So, this time a year ago, we didn't have that, now we have that.

Got it, okay. And then on the commodity outlook, you suggested you have now a higher Brent -- I guess in WTI assumption. Are you alluding to potentially a shift in strategy or maybe higher CapEx? Is that where you're going with that comment?

It's just a recognition of where we see oil prices. I think our budget for the year was about $3.5 billion, and now it's likely to be about $3.7 billion. We have clawed some money out of Tupper as I mentioned, a little over [$150,000] we're doing some more spend in places like Eagle Ford and like Seal and like Malaysia. So that is the reason for the change.

Okay, if I could sneak in one last one. I'm curious, it's kind of outside the typical upstream realm, but I noticed your retail same-store sales were down 6%, which seems a bit inconsistent with what we are hearing from some of the downstream players. Is there anything unique you're seeing whether it is Walmart traffic or what could be driving that? That seems much lower than what we've heard.

It was a poor quarter for us. We typically in our business have poor first quarters. Because we haven't got into the main [driver part]. Remember, we don't sell much in a box. We sell mainly gasoline. And we struggled in the first quarter because wholesale prices rose pretty steadily, which is a pretty tough environment for us. So those are the real reasons. We are looking at it and I can tell you that since then, we have rebounded nicely. And so to me, the second quarter is setting up from these early numbers like it should be for us.

Okay, thanks, I will leave it there and let someone hop on. Thank you.

Leo Marian, RBC.

Hi guys, just wanted to follow-up on Kikeh. How many total producing wells do have in the field?

There are 21 wells completed to produce. There's 19 currently producing, and the two wells I mentioned are shut in.

Okay, and you've done gravel packs on seven of those and you mentioned you are going to do essentially the same thing on six more? Is that right?

Yes, where we had the problem was these expandable screen completions, and we have four more to do. And when those wells go off, and they are not off yet, they're producing now -- at some point if they do go off, we will re-complete those.

Okay, and what happened with the two wells that were shut in here for failure as well?

Screens failed and so we have to replace those.

Those are also the same expandable screen design though?

Yes, we have to replace those. They were making about [55, 100] barrels a day net between the two of them.

So just to clarify, that would be a total of six wells where you have to replace those screens out? I'm just trying to understand the numbers here.

Left to do, that's right.

Okay, got you. And can you give us some more information about this Julong discovery well in Brunei? What did you guys find? Any idea about potential there?

Yes, I think the operator needs to report, and what has been said which I would confirm is that it's a discovery, it has some oil and gas in it, our size going in was less than 100 million barrels size. I don't know that that is the right number because we have to appraise it. That's really all I would say Leo, until the operator reports.

Okay, and in terms of your Seal volumes, looks like they were flat this quarter with the prior quarter. Obviously, spring breakup right now. Any color on how we should expect those to grow during the year?

We're going to be, as I mentioned in my comments, we're going to be a lot more active in Seal this year, and so as soon as spring break is a little earlier this year, as soon as we get back with our three rigs working, I think will have a pretty active program. We're pretty high on what we have seen so far in our polymer pilot in Seal, and as I mentioned in my comments, we will be a lot more active there. Soon as we can get to 20,000 barrels a day, I like it and our guys are focused on it.

Thanks guys.

Paul Cheng, Barclays.

Hi guys. David, several quick questions. Same-store sales in the first quarter, is that really 6% down on the gas sales? On an apples to apples basis?

Paul, I'm sorry, I didn't follow the question.

The retail network, the gasoline sales, same-store sales, are we looking at for only those stores that are opened 12 months, what is that year-over-year in the first quarter? And also, do you have a number for [April]?

I think you said we are down -- that's right, that's correct. And the other part of your question, I'm sorry --

Do you have the number for April?

Not in front of me I don't. [Give me a call and we can mention] that one for April.

Maybe Barry can [see it over].

I will follow-up with you on that one.

All right on the CapEx, David, do you have a number for 2013 [preliminary]?

2013, we're working it in light of moving capital out of Montney, and so that something we are actively working now.

And based on what you say, we were suppose that we should assume that Tupper 2 is not going to get [funds], and so your 2015 target -- should we assume now more like in the 255,000, 260,000?

Paul, that is a great question, and we're going to address that next week in our analyst meeting, but let me finger paint that. It ties into spend as well, which you've highlighted. If I go back to last year's AGM, we talked about a target in 2015 of 300,000 barrels equivalent. And included in that was a Phase II Tupper, which was about 35,000 barrels equivalent. So, if you took that out, and I can tell you today that we will not sanction that clearly given these gas prices. That 300,000 number in 2015 goes to 265,000.

And so then the question is what in that 265,000 is still Tupper and still dry gas? And that is about 28,000 barrels equivalent. And so you end up with a number just shy of 240,000 looking back at AGM 2011, making the corrections for gas. I personally believe that gas is probably going to be $4 or a little bit better in 2015, so I wouldn't take Tupper to zero. My number, apples to apples will be like 265,000. So what you're going to hear next week as we go back is we're going to recalibrate that because we've had a year's worth of knowledge on projects like Seal and like Eagle Ford, which are doing better and of course the results in southern Alberta are much more. So we have to recalibrate, and we are going to do that.

We're also going to be able to support where we are at with the fact that we have gone through a complete redo of how we evaluate production and predict production within our Company. And so that I think is a more rigorous, more consistent way, and so that's yet another review that will be included in that. And then lastly, because we have done a look back and said -- in certain cases, your guidance was X and you had a different number than X, there is a factor there. Being prudent, we have gone in and applied a factor to that as well. So, I think it's a better improved process. I think it's a complete relook. It's dialed back from natural gas, and so that allows us to build on what I think will be the 260,000 type number, back towards the 300,000. All of that is fingerpainting, but the details that we will be able to talk about will be at the meeting next week.

If I could just add, I'm glad that you mentioned that you are changing the way how you are putting up the [Fort carson and filarjeeto], I think that you will be better than any of us on the phone that will be able to say nearly always have some [on the ninetendo or panda high cup] in the operation on the [trauma] basis. So it seems like it's always important that to manage the expectation by building and some [intended onion car] in your system.

Paul, you know I may not be the smartest guy, but when I keep getting banged on the head, it hurts after a while, so I fix it. And think you will see that we have a good review next week.

Should we assume that -- David, should we assume that your current forecast in the second quarter as well as full year 2012 you are already applied that methodology?

Yes. This year, the 195,000 we met for the first quarter, we have 185,000 second quarter, 185,000 third-quarter and 205,000 fourth quarter on the193,000, and yes, we have applied that process. Absolutely.

Okay. On the retail spin off process, there's some concern about if you do spin it off that would [take out a big chunk] of your cash in the domestic front. To fund your dividend and all that, is that a consideration or concern for the Company?

I think we see the merit of separating the two businesses, Paul, and that consideration plus others are all part of this diligence process that we're going through. So recognize I think all of the issues that we have to address and [that's just part of the table and part of the process].

Okay.

It's a bit of a moving target because you think about -- for instance, Eagle Ford is doing much better than we originally thought, so there's several moving parts in here, and we just want to get our head around all it, and at the appropriate time bring it to our board. That's where we are.

Final question. The drilling [time] in Eagle Ford, right now is how many days?

Our guys are doing pretty well here. I have some information on it. We have improved drilling time by about 40% year on year. So if I look at 2011, our average time was a little over 33 days, and here so far this year we are 20 days. So we are doing significantly better and great credit to the guys we have working there. And we now have I think a better process. We are also reducing our completion costs here, costing, just looking at the data about 17% less per stage, and that's almost $900,000 per well improvement. So as we build momentum and have more rigs and have more staff and have more focus, we are seeing better and better results.

How many stage that you're doing now?

On average 15, Paul.

Thank you.

(Operator Instructions)

Paul Sankey, Deutsche Bank.

Hi guys. On the Kikeh, could we confirm some of the volumes please? I think I might have missed it. Did you say -- I think you said the Q1 liquids number, if we could get liquids, the gas and then the outlook for the rest of the year, that would be great. Thanks.

Okay.

Q1, I think you gave Q2, and if we could do full year as well.

Yes, we are -- Barry will pull those numbers together in a minute, Paul.

Q1 actual on Kikeh was just under 45,000 barrels of oil net. Okay?

Yep.

And Q2 guidance Kikeh it's just shy of 43,000, it's about 42,500.

Those are both liquids numbers? Right? Is the gas number easy to give to complete the question in that respect?

Certainly. Do want Kikeh gas or Sarawak gas?

Let's do both.

Second-quarter Sarawak gas was about 175 million cubic feet, Kikeh will be about 35 million cubic feet.

That is Q2 guidance?

That's Q2, yes.

Do you have those numbers for Q1 probably right in front of you?

Q1 gas, I've got Sarawak was about just under 185 million cubic feet and Kikeh just under 44 million cubic feet.

And while we are driving into this point, can we do the full year average expected and then exit rate for the year that you are receiving?

Full-year gas on Sarawak gas was about [168], Kikeh about [46].

Kikeh liquids?

Kikeh liquids is about [46].

And then the final one, which might be one asked too many, would-be the exit rate that you hope to get?

The exit rate, Paul, for Kikeh gas should be about [58]. Sarawak gas is around [166], and Kikeh oil is roughly [51] or so. That's based on a December average, not a day rate.

Okay, great. I'm thinking that we will get a new outlook for you all, targets and longer term targets at the analyst meeting next week, and I'm assuming that you don't want to talk about that right now.

I've fingerpainted the numbers, Paul, and that's going to be about where we are going to land, but I'd rather have the details shown next week. You asked questions about Kikeh. We are actually quite active there this year, and I think in the last four months, we're going to add seven wells come on. That's the reason why the tail of our production is so strong. And so if I go from now to year-end, we will get Terra Nova back from its turnaround, we will have ten new wells at Kikeh, we will have 114 new wells at Eagle Ford, we will have two wells at Kakap, and we'll have 45 new wells at Seal. So that drives that end of year growth.

David, you spoke about your target methodology changing somewhat to avoid if you like missing. We've got another downgrade here. Is there something different about what's happened here against the new methodology employed? I think you said you had somebody employed to look at this and to avoid it happening.

Yes, if you look at the change, today, what we are signaling is that North American natural gas, dry gas is minimal, no value. So two thirds of what we have changed here is basically saying we're going to go from 251 million cubic feet, which is what we are producing in Tupper in January, to something in the 160 million to 180 million a day by the end of year, and probably keep that flat for as long as gas prices are unattractive. That's just a sound, I think, decision to say -- I am not putting money in things I am not making any money in. Syncrude's got no option there, but an unexpected turnaround because it's impactful to us -- I got to recognize. Kikeh is relatively small in terms of two work over wells. The problem there is that we didn't do a very good job in managing work overs. And that's being a focus for us.

I think you can break down the change and understand it in those terms. The process I think we have going forward allows us to feel more comfortable about where we are. It would've been relatively easy for us to say -- we will make that up later, but that's not how we do that. And so we recognize the issues at this point in time and communicate them. And that's what we're doing.

Okay. I will see you next week. Thanks a lot.

Pavel Molchanov, Raymond James.

Thanks very much. Two quick ones above Kurdistan. First on the existing well that you are drilling. Any pre-drill estimates on that one?

All those ones are pretty big. Multi hundred million barrels, low-end of our range is 500 million barrels.

Okay. And at the upcoming lease sell in Iraq, I'm assuming you guys will have no role given your Kurdistan exposure. Is that fair?

I'm happy with the two blocks we have. I think that's fair exposure for a Company our size anyway. Really wasn't an issue of being invited or not invited. I'm just happy where we are at.

Okay, and then just one on the potential spinoff of the retail business. One of -- probably not a pure company, but certainly a large fuel marketer has been trying to spin off purely fuel marketing business for the last couple of years and has not yet done that. Does that give you pause perhaps that the market might not be as receptive to this as it could have been?

You know, we evaluate the outside factors and also the internal factors and the nice thing about this is I don't feel as though I'm in any great rush or forced to have to make a decision. I think we will make a decision for us when its right and I think we are in the window when it could be right and so we're looking at all the information. That's what I see.

Very good.

Guy Baber, Simmons and Co.

Just wanted a quick question, I wanted to talk about the balance sheet a little bit, but obviously you guys have a tremendous amount of cash and short-term investments on the balance sheet and limited debt. You've been carrying more cash than debt for the last couple of quarters. Can you talk a little bit about planned usages of cash as well as how you plan on managing the balance sheet going forward? And along with that, could you touch on some commentary with respect to potential M&A? I think you've been clear that you would consider an acquisition if the fit is right. Are you primarily looking North America, unconventional or is your scope more global in nature?

M&A is one of those things that you usually can talk strategically but not specifically, so I'll kind of keep in that vein. Strategically, I would love to broaden our asset base. We've been quite successful in being able to pick up acreage in plays for relatively modest amounts of money. So haven't felt compelled to go and make an acquisition in resource play. Witnessed Eagle Ford, before that Montney, most recently southern Alberta and now Muskwa. I don't feel like we have to go and pay premiums necessarily to enter new plays because we still have those avenues. Ideally if I was to make an acquisition, I think it would be a nice fit to some of the things that we've already got. Maybe a bolt-on, or maybe something in a place like Canada where I see a lot of good opportunities.

It gets tougher as you go overseas, but overseas, the types of assets that will nicely complement us are available. I am open, I don't think it's ever going to be a bet-the-farm for a Company like us, but something that fits with what we're doing kind of makes sense. Our balance sheet is in very good shape, it allows us a lot of flexibility in uptimes and downtimes, particularly downtimes. It also allows us to move forward quickly when we have exploration success. As we've had in the past for large fields, and we hope for and plan to have in the future. It's a nice comfort to have to be able to respond that way. That's how we treat our business. Overall, I feel very comfortable with it.

Okay, great. And one more strategic question for me. You mentioned in the past you have been frustrated at times in the Gulf of Mexico with respect to regulatory hurdles and the permitting process, but activity does seem to be ramping up there. Can you give us a quick update on how you view the importance of the Gulf of Mexico to the Murphy portfolio and what options you might be considering there? How you think about that business?

If you look at balance, and I think it's a good question and one that we look at, and for us if you want to see that the budget table, if you will, you need to be having an asset or a group of assets that collectively make about 20,000 barrels a day because then you are a meaningful contributor. Part of the problem with us in the Gulf, particularly since the condo incident is that they decline has been quite fast, and that's pretty typical of the type of assets that we have. Now we are able to get back to work, [all] wells should help us a lot. Dalmatian development should help us a lot. We still have to find a way to grow that business so that it's a meaningful contributor at the table.

The Gulf generally is quite expensive. I think the new approval process has made things much slower to get done. And for smaller companies like us in the Gulf, that means you dedicate a large amount of capital and a large amount of people for something that may not necessarily move the needle as much as you would like. And much as it moved the middle and the past. Those are the strategic issues that we have to get comfortable with. I'm very comfortable with the talent that we have to work in the Gulf. But is just a question of how do we get it to be meaningful for us? That's really the key question.

Thank you for the comments.

Paul Cheng, Barclays.

Dave, two questions. One, do you have a [debt noy] that you guys imposed in terms of when you decide whether you are going to convert the Milford Haven into a terminal or are you going to continue trying to hope for someone going to buy it?

Paul, that's a good question. We actually have several parties interested in our UK assets. We have parties interested collective, meaning the refinery in the retail, and parties interested in just one of the two. Whilst we are active at the table here, I think I will push off any decision to make that into a terminal because I think there's a reasonably good chance here in the near term that we'll end up with a deal we are comfortable with.

Just in the event and unfortunately that a deal cannot be consummated or cannot be [concrued], do we have a [kind of debtnoid] that you guys set saying that -- okay, at what point do we have to make a decision?

What we have done internally is we have actually looked at what it would take to make it into a terminal and we have our own assessment that if we can't get a price and/or we can't get a deal in a timeframe that is comfortable for us, and that it impacts or is likely to impact any spend, that we would convert it to a terminal. It ties in with that.

You may not want to share with us that timeline?

That's right.

Second question, going back into earlier when you talk about the Gulf of Mexico deepwater, when we look at the size of the Company, relative to your peers, you actually have more international exposure and spread in more regions than other people. Are you concerned that you may be stretching too thin and you may need to perhaps consolidate and refocus your operation into a fewer areas? You have all the people in the technical skill sets to attack -- and tight portfolio as of today.

It's a good strategic question. If you look at us today and you look at us five years out, our production contribution is basically Malaysia, Canada, the US, and it stays about the same five years out. Where we are active is in looking and exploring for new things. And as we have seen in some countries, we may be in there for a short period of time, explore -- if we are unsuccessful, leave, if we are unsuccessful, do something else. The base piece of business for us is pretty consistent. And we have the talents to be able to do that.

It's these other places where we are trying to start something afresh where it's different. Do I think we are in too many places? No, we have said that we want to be in about 10 countries and that's about where we are. Do I see us going to 20 countries? No, I think we would have to shed some countries in order to keep it in that kind of range. So that's overall where we are at. My problem is with the offshore Gulf is can I get it to be meaningful in the size of company of ours, and that is the question that we are really asking ourselves, given the fact that it costs a lot of money to drill wells there and given the fact that it takes time to get things approved and given the time that the fields that you find generally produce pretty good margins but they don't last very long. And that is a big issue.

Thank you.

Pavel Molchanov, Raymond James.

Thanks again for taking me. On Malaysia and floating LNG project that you referenced earlier. Do you have a critical massive resource to make a decision on that in the near future? And if so, what sort of timeline to first gas would you anticipate?

We're working on a timeline that's got some moving parts here. So I will bracket it, but I don't see gas before 2016. Do we have enough resource base to be able to go forward? I believe we do. We have made now discoveries at Rotan, discoveries at [Baeris] and these two new discoveries, we're going to do some more drilling later this year, so I think the resource base for something that's about 1.5 million metric tons a year type of vessel is there. I think the resource base question is being addressed. I think we are out to -- [Petrobras] is out to feed for the ship. We will be making some sort of investment decision next year, I think 2016 is about when first gas should be expected. That's where we are at here.

So FID in 2013?

Yes.

Okay, appreciate it.

Kate Minyard, JPMorgan.

Thanks a lot. A quick question on your guidance for Q2. You're talking about a $67 million contribution from downstream. Which would be quite a recovery from the first quarter. What are some of the factors you have been noticing in April and first couple of days of May that would be driving that level of recovery?

We typically do much better in the second quarter, and all I can say is that what we have started to see here as we get into the spring driving season is consistent with what we have seen in the past. That's really all the flavor I can say. It's a little early yet and granted we have only seen a month here in the quarter, but a month is usually enough to give you reasonable assessments.

Okay, so are you seeing an uptick from that 6% same-store sales decline in the US or are we may be looking at UK strength coupled with US retail in April so far?

Kate, I really think its margin improvement is what we've seen.

Okay. All right, and I know it's early in the year, and so this may be a better question towards the end of the year, but do you see any potential implications for reserves from the gas shut-ins or drilling curtailments at Tupper, and also the Kikeh work and whether there's any not only an impact on [crude] reserves, but any potential migration from developed back into undeveloped or anything that you can cite so far?

You know Kate, it's a great question and you're absolutely right, it is kind of early to think about it. We will clearly have to look at Tupper reserves here and migration as the year goes on. I think as we start to spend more money and do more things in the Eagle Ford, for instance, we will probably do much better there. I think the drilling efficiencies alone are going to gain us 20 more wells versus our budget.

So the guys are doing a good job, and then we're adding more capital to that business. I think there will be some nice offset there, and it will be more oily versus more gassy. Overall, it will be pretty positive. I haven't seen anything so far that would cause me any concern, but it's early days in the year. But I'm not worried about it.

Okay, all right, good. Thanks very much.

At this time, there are no further questions in the queue. I'll turn the conference back to management for any additional remarks.

Operator, thank you, thanks everyone for calling in. I appreciate it, look forward to seeing those of you that are going to be here or listening in next week. And if not, we will talk to you again at the next quarter's results. Thank you.

That does conclude today's conference call. Thank you for your participation.