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Executives

David M. Wood - Chief Executive Officer, President, Director and Member of Executive Committee

Barry Jeffery - Director of Investor Relations

Kevin G. Fitzgerald - Chief Financial Officer and Executive Vice President

Mindy K. West - Vice President and Treasurer

Analysts

Blake Fernandez - Howard Weil Incorporated, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

Paul Sankey - Deutsche Bank AG, Research Division

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Guy A. Baber - Simmons & Company International, Research Division

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Murphy Oil (MUR) Q1 2012 Earnings Call May 3, 2012 1:00 PM ET

Operator

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.

David M. Wood

Thanks, operator. 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 Jeffery, Director of Investor Relations; and Tammy Taylor, Assistant Manager, Investor Relations. I will now turn the call over to Barry.

Barry Jeffery

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 2011 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 a 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.

Kevin G. Fitzgerald

Thanks, Barry. Net income in the first quarter of 2012 was $290.1 million or $1.49 per diluted share. This compares 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 2011 did include $30.5 million of $0.16 per diluted share of income from discontinued operations related to the 2 U.S. refineries and associated marketing assets that were sold at the end of the third quarter 2011.

Taking a look at net income by segment. E&P segment for the first quarter of 2012 a 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 in Kikeh, Malaysia and Azurite, offshore Republic of the Congo. Natural gas items, 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 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 of 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 U.S. 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.

U.K. downstream operations recorded income of $3 million in the 2012 quarter compared to a net loss of $8.7 million last year. The improvement was largely due to better refinery 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 2011. This unfavorable variance is mostly attributable to higher administrative costs and lower interest income in the current quarter.

At the end of the first quarter 2012, our long-term debt amounted just under $250 million, a 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 bond matured and were paid off through borrowing under our revolving credit agreement. We're currently working a process to sell $500 million of new 10-year notes. The proceeds from which, if successful, will be used to repay those borrowings and for general corporate purposes. And with that, I'll turn it over to David.

David M. Wood

Thanks, Kevin. Benchmark WTI prices averaged near $103 for the first quarter. Dated Brent, the market 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 revised these benchmark prices up to $95 and $110 respectively for our latest outlook.

Natural gas prices in North America have been disappointing for many in the first quarter of 2012, and Henry Hub beginning the year near $3 and continuing to fall, settling near the $2 mark, as unusually warm winter conditions exacerbate on oversupply situation. We continue to see weak North American natural gas prices over the midterm. And as a result, we've cut spending on all our dry gas initiatives and our 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. U.S. retail margin struggled in the first quarter at the back of consistently rising wholesale prices. These have recently started to rebound as we exit this typically weak shoulder season. We continue to move forward on our repositioning efforts with evaluation work on the retail spin continuing and U.K. 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 3 discoveries from 3 attempts already in the first quarter. Our 2 Block H wells in Malaysia made nice gas discoveries, which will be combined with plans to develop flooding in [indiscernible]. In addition, the Julong East well and Block CA-1 offshore Brunei is a discovery. We have recently spud our first well in Iraq, on our Central Dohuk block in the Kurdistan region are making encouraging progress. The rest of the year, we'll 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 sidetrack operations at the Thunder Hawk #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 3-year term on another deepwater rig.

Moving to our North American resource plays. We currently have 14 rigs contracted in North America, 10 in the Eagle Ford and 4 in Canada waiting on spring break-up. Three of this 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 10 rigs running and are looking to add 2 more by year end. We are operating 2 dedicated frac spreads and are looking to add a third crew shortly. We've 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 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 to date net for the year. We have lots to do in the Eagle Ford with over 2,000 oilier locations yet to drill.

Accelerated activity is ongoing at the Seal heavy oil project in Northern Alberta. With 3 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 1 injection to begin around midyear. We have also received subsurface regulatory approval for cyclic steam pilot lead and are awaiting facility's approval with expectations to stop pilot work late this year.

Additionally, we will submit an application for a steam flood project by midyear. 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. For the year, we will know drill 14 wells compared to our original budget of 37 wells. This will impact our 2012 production by approximately 3,000 barrels of oil equivalent per day. We are 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 level. 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 Forks zone, with production rates now over 400 barrels of oil per day of light oil, 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 on 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, the Muskwa oil play. So far, we have an accumulated 170,000 net acres in our first well flowed light oil with initial production rate 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. It is 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 has 185,000 barrels of oil equivalent per day, down 10,000 barrels a day from quarter 1 as we see the impact of unplanned turnaround activities associated with Syncrude, the Medusa pipeline and methanol plant taking Kikeh gas; and this collectively contribute nearly 6,000 barrels of the shortfall. The remaining 4,000 is related to a lower Kikeh oil and Montney dry gas production. The reduced Montney gas production is tied to less spend and a decision to curtail some production due to price. 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 workovers, field shutdown for new manifold installation and 2 wells shut-in pending workover. 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 equivalent per day budget, with 2/3 of this reduction reflecting less North American dry gas production.

Business development. We continue to pursue both on acreage and 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.

The U.S. downstream business had a difficult first quarter as U.S. retail margins were depressed in a steadily rising wholesale price environment. Retail margins started to turn around in March and have recovered to stop the second quarter as they typically do. First quarter net income was a negative $7.7 million with positive cash flow of $9.4 million. We added 5 new stations to the U.S. 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 2 corn-based ethanol plants at 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 blend roll on a sluggish gasoline demand. Cattle feed prices have remained strong tracking corn to provide a solid revenue stream to offset operating expenses.

The U.K. downstream business provided a positive contribution for the quarter in an improved margin environment where the U.K. retail business continuing its steady performance. Our 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 3 discoveries from 3 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. U.S. retail has rebounded from a difficult first quarter, just typically a weak shoulder season. And we're showing expected improving performance heading into the second quarter.

And lastly, our repositioning efforts continue with the U.K. sales process and evaluation of separating our E&P and downstream businesses. That concludes my prepared remarks. And I'm happy to take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] We will go first to Blake Fernandez of Howard Weil.

Blake Fernandez - Howard Weil Incorporated, Research Division

David, if I could go back to Kikeh, can I just confirm, the workover issues, does this have to do with the previous workover wells or is this ongoing maintenance that you just haven't completed yet?

David M. Wood

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 has been in Malaysia before we brought it back, and so it's performing much better. We did that the end of January. We did, on the other rig -- this is 2 rigs working field one on the spar had a stuck-pipe incident which kind of lost the 6 weeks on our workover program and that has impacted us. We also had a manifold installation there for wells are going to be brought on later in the year. So all of those had an operational impact. And then we had 2 wells that went -- that were shut in for screen failure basically. And these are carryover from wells that we had before. So if we look at our workover program, we have 6 expandable screen wells to work over, including these 2 that went off, and we will work those over during the course of this year, the 2 that have gone off.

Blake Fernandez - Howard Weil Incorporated, Research Division

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

David M. Wood

No, no. If we look back a year ago, we now have equipment in the field to remedy this. And we now have done 7 wells where we've completed them with these open-hole gravel packs or frac packs. Four of those were wells that had problems -- we have no problems with any of those 7, including the 4 that were remedies. So I think we're in a good shape here in now with both equipment in the field to perform the workovers 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 them.

Blake Fernandez - Howard Weil Incorporated, Research Division

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

David M. Wood

Well, it's just a recognition of where kind of 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've clawed some money out of Tupper, as I mentioned, about 100 -- a little over 150, and we're doing some more spend in places like Eagle Ford and like Seal and like Malaysia. And so that's the reason for the change.

Blake Fernandez - Howard Weil Incorporated, Research Division

Okay. If I could sneak in one last one. I'm just 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're hearing from some of the, I guess, downstream players. Is there anything unique you're seeing, whether it's Wal-Mart traffic or what could be driving that? That seems much lower than what we've heard.

David M. Wood

Yes. 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. But 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're looking at it, and I can tell you that since then, we've rebounded nicely. And so to me, the second quarter is setting up on these early numbers like it should do for us.

Operator

We will go next to Leo Mariani of RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just wanted to follow up on Kikeh. How many total producing wells do you have in the field?

David M. Wood

There's 21 wells completed to produce. There's 19 currently producing and the 2 wells I mentioned that are shut in.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And then you've done gravel packs on 7 of those, then you mentioned you're going to do essentially the same thing, I guess, on 6 more, is that right?

David M. Wood

Yes. Of the -- where we had the problem was these expandable screen completions, and we have 4 more to do. And when those wells go off and they're not off yet, they're producing now, so at some point, if they do go off , we will re-complete those.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And what happened with the 2 wells that were shut in here for failure as well?

David M. Wood

The screens failed, and so we had to replace those.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Those are also expandable screen design now?

David M. Wood

Yes, we had to replace those. They were making about 5,500 barrels a day net between the 2.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. But that -- so just to clarify, that will be a total of 6 wells we have to replace the screens out? I'm just trying to understand the numbers here.

David M. Wood

Yes. Left to do, Leo, that's right.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

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

David M. Wood

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

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. I guess, in terms of your Seal volumes, look like they were sort of flat this quarter with the prior quarter. I guess, obviously spring breakup right now, just any color on how we should expect those to grow during the year?

David M. Wood

Yes, 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 breaks a little earlier this year, as soon as we get back with our 3 rigs working, I think, we'll have a pretty active program. So we're pretty high on what we've seen so far in our polymer pilot in Seal. And as I mentioned in my comments, we'll be a lot more active there . So as soon as we can get to 20,000 barrels a day, I'll like it, and our guys are focused on it.

Operator

We'll go to Paul Cheng of Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

David, couple -- several quick questions, hopefully. There seems also -- in the first quarter, is that really 6% down on the gasoline sales warning, on an apple-to-apple basis?

David M. Wood

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

Paul Y. Cheng - Barclays Capital, Research Division

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

David M. Wood

I think you said they were down 6 -- that's right, that's correct. The other part of your question...

Paul Y. Cheng - Barclays Capital, Research Division

Do you have the number for April?

David M. Wood

In front of me, I don't. But we can, if you call, we can mention that number for April...

Paul Y. Cheng - Barclays Capital, Research Division

Yes. Maybe Barry can send it over.

David M. Wood

Yes, I don't have it.

Barry Jeffery

I will follow up on you on that one.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. All right. On the CapEx, David, do you have a number for 2013 preliminary?

David M. Wood

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

Paul Y. Cheng - Barclays Capital, Research Division

And that -- based on what you just said, I believe -- I suppose that we should assume that Tupper 2 is not going to get fund, and so your 2015 targets, should we assume now is more like in the 255, 260?

David M. Wood

Yes, Paul, that's a great question, and we're going to address that next week in our Analyst Meeting. But let me kind of finger paint that. It kind of ties in to spend as well, which you've highlighted. So 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 2 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 number in 2015 goes to 265. And so then the question is, what in that 265 is still Tupper and still dry gas? And that's about 28,000 barrels equivalent. So you end up with a number just shy of 240 looking back at AGM 2011 making the corrections for gas. Now 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 0. So my number apples-to-apples would be like 265. So what you're going to hear next week when we go back is we're going to recalibrate that because we had a years’ 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're going to do that. We're also are going to be able to support where we're at with the fact that we've 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've done a look-back and said, "Hey, in certain cases, your guidance was x and you had a different number than x. There's a factor there." And so being kind of prudent, we've gone in and applied a factor to that as well. So I think it's a better improved process. I think it is complete relook. It's dialed back from natural gas, and so that allows us to build from what I think will be the 260 type number back towards the 300. So all of that is fingerpainting, but the details that we'll be able to talk about will be at the meeting next week.

Paul Y. Cheng - Barclays Capital, Research Division

And if I could just add, I mean, I'm that glad you mentioned that you're changing the way to how you putting up the forecast and [indiscernible]. I think you will be better than any of us on the phone that we'd be able to say that's nearly always have some unintended or intended hiccup in the operation on the 12-month basis. So it seems like it's always important that to manage the expectation by building in unintended downtime in your system.

David M. Wood

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

Paul Y. Cheng - Barclays Capital, Research Division

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

David M. Wood

Yes. So this year, we're -- the 195 we met for the first quarter. We have 185 second quarter, 185 third quarter and 205 fourth quarter for the 193. And yes, we have applied that process absolutely.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. On the retail spinoff process, there's some concern about if you do spin it off, that would take off a big chunk of your cash in the domestic front to fund your dividend. Is that a consideration or concern for the company?

David M. Wood

I think we see the merits of separating the 2 businesses, Paul, and that consideration plus others are all part of this diligence process that we're going through. So we recognize, I think, all of the issues that we have to address and [indiscernible]. It's bit of a moving target as you think about, I mean, for instance, Eagle Ford is doing much better than we originally thought. I mean, there some several moving parts in here, and we just want to get our head around all of it, and then at the appropriate time, bring it to our Board. So that's kind of where we are.

Paul Y. Cheng - Barclays Capital, Research Division

Final question. The drilling time in Eagle Ford right is how many days per well?

David M. Wood

Our guys are doing pretty well here. I have some information on it. We've 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, were 20 days. So we're doing significantly better, and great credit to the guys we have working there. And we now have, I think, a better process. We're also reducing our completion costs here, costing -- just looking at the data of about 17% less per stage, so that's almost $900,000 per well improvement. So as we build momentum have more rigs, have more staff, have more focus, we're seeing better and better results.

Paul Y. Cheng - Barclays Capital, Research Division

And how many stage are you doing now?

David M. Wood

On average, 15, Paul.

Operator

[Operator Instructions] We will go next to Paul Sankey of Deutsche Bank.

Paul Sankey - Deutsche Bank AG, Research Division

On the Kikeh, could we just confirm some of the volumes, please? I think I might have missed it. Did you say that -- I think you said the Q1 liquids number, if we could get liquids to gas and then the outlook for the rest of the year that would be great. Q1, I think, you gave Q2, and then if you could do full year as well.

David M. Wood

Yes, we're -- Barry, will pull those numbers together here in a minute, Paul.

Barry Jeffery

So Q1, Paul -- Q1 actual on Kikeh, that's just under 45,000 barrels of oil net, okay? And then Q2 guidance, Kikeh, it's just shy of 43. It's about 42.5.

Paul Sankey - Deutsche Bank AG, Research Division

Okay. And I mean, let's just go for a -- those are both liquids numbers, right?

Barry Jeffery

Yes. That's the oil play.

Paul Sankey - Deutsche Bank AG, Research Division

Is the gas number easy to give just to complete the question in that respect?

Barry Jeffery

Certainly, the -- you want Kikeh gas or Sarawak gas?

Paul Sankey - Deutsche Bank AG, Research Division

Let's do both.

Barry Jeffery

Okay. So second quarter Sarawak gas is about 175 million cubic feet. Kikeh is going to be about 35 million.

Paul Sankey - Deutsche Bank AG, Research Division

That's Q2 guidance.

Barry Jeffery

That's Q2, yes.

Paul Sankey - Deutsche Bank AG, Research Division

Now do you have those numbers in Q1? That's right in front of you probably, so.

Barry Jeffery

Q1 gas, I've got -- Sarawak was about just under 185, Kikeh just under 44.

Paul Sankey - Deutsche Bank AG, Research Division

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

Barry Jeffery

The full year gas on Sarawak gas is about 168. Kikeh, about 46.

Paul Sankey - Deutsche Bank AG, Research Division

Kikeh liquids?

Barry Jeffery

Kikeh liquids is about 46.

Paul Sankey - Deutsche Bank AG, Research Division

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

Mindy K. West

I have that. The exit rate, Paul, for Kikeh gas should be about 58. Serawak gas is around 166, and Kikeh oil is roughly 51 or so. That's based on the December average, not a day rate. It's December average.

Paul Sankey - Deutsche Bank AG, Research Division

Okay, great. I'm thinking that we'll get a new outlook for your targets and longer-term targets at the Analyst Meeting next week, and I'm assuming that you don't want to talk about it right now.

David M. Wood

Yes, I've fingerpainted the numbers, Paul, and that's going to be about where we're going to land but I'd rather have the details shown next week. You asked questions about Kikeh. We're actually quite active there this year, and I think in the last 4 months, we are going to add 7 wells come on. So that's the reason why the tail of our production is so strong. And so if I go from now to year end, we'll get Terra Nova back from its turnaround. We'll have 10 new wells at Kikeh. We'll have 114 new wells at Eagle Ford. We'll have 2 wells at Kakap, and we'll have 45 new wells at Seal. So that drives that end-of-year growth.

Paul Sankey - Deutsche Bank AG, Research Division

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 that you've got some of the employees to look at this and to avoid it happening.

David M. Wood

Yes, if you look at the change today, what we're signaling is North American natural gas, dry gas is minimal no value, and so 2/3 of what we've changed here is basically saying when you go from 251 million cubic feet, which is what we're producing in Tupper in January, something in the 160 million to 180 million a day by the end of the year and probably keep that flat for as long gas prices are unattractive. That's just a sound I think decision to say, "Hey, I'm not putting money in things I'm not making any money at." Syncrude got no option there but an unexpected turnaround because it's impactful to us, I got to recognize. Kikeh, it's relatively small in terms of 2 workover wells. The problem there is we didn't do a very good job in managing workovers, and that's being a focus for us. So I think you can break down the change and understand in those terms. The process, I think, that we have going forward allows us to feel more comfortable about where we are. It would have been relatively easy for us to say, "Well, we'll 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.

Operator

We will go next to Pavel Molchanov of Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

Two quick ones about Kurdistan. First on the existing well that you're drilling, any pre-drill estimates on that one?

David M. Wood

All those ones, Pavel, are pretty big multi-hundred million barrels. I think, the low end of our range is 500 million barrels.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

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?

David M. Wood

I'm happy with the 2 blocks that we've got. I think that's fair exposure for a company our size anyway, and so it really wasn't an issue of being invited or not invited. I'm just happy where we're at.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

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

David M. Wood

We evaluate the kind of 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'll make the decision for us when it's right, and I think we're in the window when it could be right, and so we're looking at all the information. So that's kind of what I'd say.

Operator

We will go next to Guy Baber of Simmons & Company.

Guy A. Baber - Simmons & Company International, Research Division

Guy Baber with Simmons & Company. Just wanted -- a quick question. I wanted to talk about the balance sheet a little bit. But obviously, you guys have tremendous amount of cash and short-term investments on the balance sheet, limited debt. You've been carrying more cash than debt for the last couple of quarters. Can you just talk a little bit about planned usages of cash as well as how you plan on managing the balance sheet going forward and then 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's right? Are you primarily looking North America unconventional or is your scope more global in nature?

David M. Wood

M&A is one of those things that you usually can talk strategically, but not specifically, and so I'll kind of keep in that vein. I think 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, and so I haven't felt compelled to go and make an acquisition in resource plays, so witnessed Eagle Ford, before that Montney, most recently Southern Alberta and now Muskwa. So 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 would nicely complement us are available. So I'm open. I don't think it's ever going to be a better forum for a company like us but that's something that fits with what we're doing, I think, kind of make sense. Our balance sheet is in a very good shape. It allows us a lot of flexibility in up-- 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. So it's a nice comfort to have to be able to respond that way. So that's kind of how we treat our business overall, and I feel very comfortable with.

Guy A. Baber - Simmons & Company International, Research Division

Okay, great. And then one more strategic question for me. You mentioned in the past that you've 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 just 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?

David M. Wood

Yes. If you look at balance, I think it's a good question and one that we look at. For us, if you want to sit at the budget table, if you will, you need to be having an asset or 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 Macondo incident, is that decline has been quite fast, and that's pretty typical of the type of assets that we have. And so now we're able to get back to work, Thunder Hawk oil well 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 make 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 needle in the past. So 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 it's just a question of how do we get it to be meaningful to us. That's really, I think, the key question.

Operator

We'll go next to Paul Cheng of Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

Dave, two questions. One, do you have a deadline that you guys impose in terms of when you decide whether you're going to convert the Milford Haven into a terminal or that the -- you're going to continue -- try to hope for that someone's going to buy it?

David M. Wood

Paul, that's a good question. We actually have several parties interested in our U.K. assets. While we have parties interested collective, meaning the refinery and the retail and parties interested in just 1 of the 2. So the last, we are active at the table here, I think, I'll 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 will end up with a deal that we're comfortable with.

Paul Y. Cheng - Barclays Capital, Research Division

Right. Just in Uganda, unfortunately that deal cannot be consummated or cannot be conclude. Do we have a higher deadline that you guys set, saying that, okay, at what point do we have to make a decision?

David M. Wood

What we've 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's comfortable for us and that it impacts or is likely to impact any spend that we will convert it to a terminal, and so it kind of ties in with that.

Paul Y. Cheng - Barclays Capital, Research Division

Right, but there's also -- but you may not want to share with us then what's that timeline?

David M. Wood

That's right.

Paul Y. Cheng - Barclays Capital, Research Division

Okay, that's better. Second question, going back into earlier that when you're talking about the Gulf of Mexico deepwater, when we're looking into the size of the company relative to your peer, they actually have more international exposure, and actually, that's spreading in more regions than other people. Are you concerned that you may be stretching too thin and then you may need to, perhaps, consolidate and refocus your operation into fewer areas? You have all the people and the technical skill set to attack all the entire portfolio as of today.

David M. Wood

Yes, it's a good strategic question. If you look at us today and you look at us 5 years out, our production contribution is basically Malaysia or Canada, the U.S., and it stays about the same 5 years out. And where we are active is in looking and exploring for new things. And as we've seen in some country, we may be in there for a short period of time. Explore, if we're unsuccessful, leave. If we're successful, do something else. So I think the base piece of business for us is kind of pretty consistent, and we have, I think, the talents to be able to do that. It's these other places where we're going to start something afresh where it's different. And so -- do I think we're in too many places? No. We've kind of said 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're at. My problem is with the offshore Gulf is kind of get it to be meaningful in the size of company of ours, and that's the question that we're really asking ourselves, given the fact that it cost 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's the big issue there.

Operator

We will go next to Pavel Molchanov of Raymond James.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

On Malaysian Floating LNG project that you referenced earlier, do you have a critical mass of resource to make a decision on that in the near future? And if so, what sort of timeline to first gas would you anticipate?

David M. Wood

We're working on kind of a timeline that's got some moving parts here. So I'll kind of 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've made now discoveries at Rotan, discoveries at Biris. And these 2 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 kind of there. So I think the resource base question is being addressed. I think we're out to-- Petronas out to feed for the ship. We'll be making some sort of investment decision next year. And I think 2016 is about when first gas should be expected. So that's kind of where we're at here.

Pavel Molchanov - Raymond James & Associates, Inc., Research Division

So FID in 2013.

David M. Wood

Yes.

Operator

We will go next to Kate Minyard of JPMorgan.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Just a quick question on your guidance for 2Q. You're talking about a $67 million contribution from downstream. Which would you make quite a recovery from the first quarter? So what are some of the factors that you've been noticing in April and in your first couple of days of May that would be driving that level of recovery?

David M. Wood

Yes, we typically do much better in the second quarter, and all I can say is what we started to see here as we get into the spring driving season is kind of consistent with what we've seen in the past. So that's really all the flavor I could say. It's a little early yet, granting we've only seen a month here in the quarter. But a month is usually enough to give you a reasonable assessment. So I haven't seen anything yet.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Okay. So are you seeing an uptick from that 6% same-store sales decline in the U.S. or are we may be looking at some U.K. strength coupled with U.S. retail in April so far?

David M. Wood

Kate, I really think it's margin improvement is what we have seen.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Okay, all right. And then I know it's kind of early in the year, so just maybe a better question for toward the end of the year, but do you see any potential implication for reserves from the gas shut-ins or drilling curtailments at Tupper? And then also the Kikeh work and whether there's any not only an impact on proved reserves but any kind of potential migration from developed back into undeveloped or anything that you can cite so far?

David M. Wood

Kate, it's a great question, and you're absolutely right. But it is just kind of early to think about it. And we'll 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'll 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 into that business. So I think, there'll be some nice offsets there, and it'll be more oily versus more gassy. And so I think, overall, it would pretty positive. So 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.

Operator

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

David M. Wood

Operator, thank you. Thanks, everyone, for calling in. Appreciate it. Look forward to seeing that are going to be here or listening in next week, and if not, we'll talk to you again at the next quarter's results. Thank you.

Operator

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

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