Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2014 Earnings Call. Today's conference is being recorded. I would now like to turn the call over to Mr. Barry Jeffery, Vice President, Investor Relations. Please go ahead, sir.

Thank you. Good afternoon, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer; Kevin Fitzgerald, Executive Vice President and Chief Financial Officer; and John Eckart, Senior Vice President and Controller. Please refer to the informational slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Today's call will follow our usual format. Kevin will begin by providing a review of fourth quarter 2014 results. Roger will then follow with an operational update, after which questions will be taken. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see both Murphy's 2013 Annual Report on Form 10-K and Form 10-Q for the quarterly period ended September 30, 2014, on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I'll now turn the call over to Kevin.

Thanks, Barry. For the fourth quarter 2014, we had income from continuing operations of $442 million or $2.48 per diluted share. This compares to income from continuing ops in the fourth quarter of '13 of $180.5 million or $0.96 per diluted share. For the entire year of 2014, income from continuing ops was $1,025,000,000 or $5.69 per diluted share compared to $88.1 million (sic) [ $888.1 million ] or $4.69 per diluted share for 2013. The fourth quarter results from continuing operations for 2014 included a gain of $321.4 million on the sale of 20% interest in our Malaysian business, and this is made up of 2 pieces. We have $144.8 million of pretax profit, which is included in the Malaysia operating revenues and $176.6 million of tax benefits included in income taxes. We also had income tax benefits of $120.6 million related to foreign oil and gas investments, $46.3 million of impairments related to the Tahoe field in the Gulf of Mexico and Canadian goodwill assets, and $59.6 million related to the write-off of previously suspended exploration wells. These, and other items affecting comparability of earnings between periods, are listed in the schedule of adjusted earnings included as part of our earnings release. Unless stated otherwise, all of these figures are on an after-tax basis. Earnings in the 2014 quarter were negatively impacted by significantly lower realized sales prices for crude oil and natural gas liquids, the effects of which were partially offset by higher production levels. Crude oil and gas liquids production averaged approximately 173,000 barrels per day in the 2014 quarter compared to just under 140,000 barrels a day in 2013. The increase is primarily a result of ongoing drilling in Eagle Ford Shale and the current year startup of the Dalmatian field in the Gulf of Mexico. Natural gas volumes were 514 million cubic feet a day in the 2014 quarter compared to 399 million cubic feet a day in '13, with the increase primarily due to higher production from Dalmatian, Eagle Ford Shale, the Tupper area in Western Canada and at Kikeh in Malaysia. In our corporate segment, we had net charges of $25 million for the fourth quarter of 2014 compared to net charges of $62 million in the fourth quarter of last year. Decreased costs in 2014 primarily relate to favorable results from transactions denominated in foreign currencies and lower administrative costs partially offset by higher net interest costs. Capital expenditures from continuing operations for 2014 totaled $3.76 billion. For 2015, our CapEx expected to total $2.3 billion. Of that, approximately $1.9 billion is for development projects and approximately $380 million is to be spent on exploration activities. This assumes WTI pricing of $52.50 per barrel and Henry Hub pricing of $3 per Mcf. At year-end 2014, Murphy's long-term debt amounted to approximately $2.54 billion, and this included about $290 million related to the Kakap FPSO lease or 22.7% of total capital employed. And with that, I'll turn it over to Roger.

Hello, everyone. Before we get started today on our usual update, I want to a moment to recognize Kevin. As he announced previously, he's retiring from the company in end of February after 32 years of service. This is Kevin's 77th consecutive call at Murphy dating back to 1996. A feat I do not think will be broken again. Kevin, I want to thank you for your long-term dedicated service to Murphy and wish you well in retirement. I'm sure you'll miss the fun of working with me personally on call preparations, especially when we have a great quarter and we go down 10%.

Absolutely.

I'm sure you'll continue to listen in, but I will not be taking questions from you.

I appreciate the comments, Roger. Thank you.

As we get into highlights for this quarter and the year, we continue to make progress in portfolio optimization. We closed the sale of 30% of our Malaysia business for $2 billion in 2 phases: one announced from December 18 at 20%; and we just completed Phase 2 for 10% which was announced publicly this morning. We completed the sale of the U.K. retail gasoline business. We initiated decommissioning of the Milford Haven Refinery process units with divestment of the terminal assets ongoing. We divested our small non-operated interest in South Louisiana and Alaska for cash proceeds of approximately $6 million. We built a balance sheet at the end of 2014 with a net debt to total cap ratio of 13.5%, which includes $1.6 billion -- $1.65 billion of cash and invested cash located across our business. We set a quarterly production record of 258,868 barrels of oil equivalent per day. We set an annual production record of 225,973 barrel equivalents per day, up 10% from 2013. We recorded total proved reserve replacement of 180%. We achieved First Oil at 3 new deepwater fields at Siakap North-Petai and Kakap-Gumusut in Malaysia and Dalmatian in the Gulf of Mexico. We sanctioned the Block H Malaysia floating LNG project and increased production in the Eagle Ford Shale to a level near 57,000 barrel equivalent per day for the year with over 500 operating wells. We repurchased 375 million of company common stock. We authorized an additional $500 million share repurchase and increased the regular dividend by 12% to $1.40 per share. When we look at prices, a drop in benchmark prices from third quarter to fourth quarter was near $25 a barrel. We saw our fourth quarter realized oil prices in our Malaysia business near $67 per barrel, in great contrast to…

[Operator Instructions] And we will take our first question from Leo Mariani at RBC.

I was hoping you could speak to uses of the cash in Malaysia. Obviously, you've gotten the proceeds at this point. Can you talk about how you're thinking about using that and how you would prioritize the uses?

Well, right now, we just -- it's been a very complicated long closing process, as I have said in my comments, and it takes a long time to sell these big assets for these big premiums. It's quite a complicated set of assets. Our team did an incredible job of closing and getting all this data together and all the approvals necessary. So I'm very happy with that. It's just getting in the last piece today, Leo, during a pretty big price collapse there. So what we've been doing of late, quite honestly, is working real hard on our budget, getting our budget to the lowest level we think we can go until we see this price recovery get better. And we -- obviously, we all know where the opportunities would be, there would be M&A opportunity or share repurchase. We -- looking a lot -- at a lot of opportunities, I think the opportunity set today has been reduced some by onshore players pulling many of those deals, and we'll have to see a calibration in the thoughts behind the sale price there or at least in the cost aspect of it or some slowdown and stability in crude. So our plan is to hunker down and monitor all that right now and not -- just not stating on what the plans are, quite frankly.

Alright. In your prepared comments, you spoke about your budget being based on, I guess, $52.50, $57 and $3. Can you talk as to where you would pull back some of the capital to the extent that prices stay lower for longer? And then alternatively, can you speak to an acceleration case, if we do get a recovery at some point during '15, and where you would pull back and where you would add capital? And maybe just kind of talk through some scenarios.

Well, I mean, I thought $52 was a good number couple of weeks ago, now, it's probably $45, so that shows the problem today. I think, we're in pretty good shape to execute what we have. I mean, obviously, I think you'll find that we'll have -- when all the earnings releases are done, I think we'll end up with probably one of the better balance sheets due to this timely closing, very fortunate there and feel real good about being able to do what we have even if it gets worse. But if we choose to make it worse, I mean, obviously, the Eagle Ford Shale is a very valuable barrel. The barrel is on the ground there. We can stop spending them there, and it is a U.S. spend, U.S. debt would be increased. It is a place, too, that can be rapidly increased, add rigs very quickly. I look for cost calibration to go very quickly there. We are seeing progress and got to 10% on cost reductions probably quicker than anticipated, heading toward 15% to 20% now. On top of the efficiencies that we have, it allows us to keep some of the better rigs and make deals on the rigs that we had in the release. So, I feel real good about it the ability to cut there some and quickly add there, and -- but I think we can handle what we have pretty good here, even if things go down, Leo.

Alright, I guess, could you maybe just speak to type of oil price you would need to see to start ramping. Eagle Ford, even if it's just a rough range, if we were at $65 or $70, would that be good enough? Can you maybe just speak to that?

I don't really have that in my mind. I'm hunkered down right now, looking for opportunity, quite frankly, over increasing CapEx. I see that as the best thing to do for us, and don't really have a number in mind for things that we have to do further up -- further rigs to be dropped, which is all the rage and all the discussion. And that gets in the thousand level cost we'll calibrate. I don't believe we're there yet. And I just don't walk around with a number saying we're going to get back after them. I'm in the hunkered down mode right now and looking for opportunity, frankly.

Alright that makes sense thanks.

And we'll take our next question from Guy Baber at Simmons. Guy Allen Baber - Simmons & Company International, Research Division: Good afternoon everybody and Kevin congrats on your retirement and on your Cal Ripken-like streak of calls.

That is -- I'd say well put.

He's a little -- he's just not as quite in good shape as Cal Ripken. Guy Allen Baber - Simmons & Company International, Research Division: I wanted to talk a little bit about the cash flow and CapEx relationship given the commodity price assumptions that you published and used to set the budget. But just curious if you could share with us kind of your general expectation for where cash flow should shake out on those planning assumptions and how close you are to cash flow neutrality with the CapEx numbers on that you've cut pretty aggressively.

We don't usually get into all that kind of detail, but I'll share with you a little cover -- color. I guess, on just an E&P-only basis, Guy, we would be probably out of kilter there, about $700 million. I think you may have -- someone forecasted that last evening, $700 million, $800 million, which I think will be accurate. Then, of course, we have a dividend of $2.48 and some corporate expenses of $169 million. And then that is -- and then we have the proceeds coming in from Malaysia. So we will, of course, outspend at $52 million. It won't take a lot of calculation to get there. I think that would be a common theme this year. We did go back as much as we could. I think -- it's my view that's the way to handle this, is to cut back as much as possible and wait, and that's what we did. And I feel good about where we are because we happen to have a lot of cash today. Guy Allen Baber - Simmons & Company International, Research Division: That's helpful. And then I had a couple production-related follow-ups. I was hoping you could speak to the decision around shutting in production at Seal. How many wells? How much production that impacted? And just if you could talk about that decision-making process because it's not something -- I don't believe we've seen much of across the oil sands, at least not yet. And then in the Eagle Ford, appreciate all the disclosure and the trend that you provided. If the spending levels remain at these constrained levels, do you have an expectation for where 2016 production would shake out? If you could share that, that will be great.

First, on Seal, I mean there's hundreds of wells at Seal, and they're very -- and we have 2 businesses there. We have an old conventional business that's been in place for a long time, which we're really not investing in it anymore and a futuristic kind of steam business is going actually very well. So we may have maybe 250 barrels shut in the day and we feel that, at the worst case, we could get 80 wells shut in for a couple of thousand barrels a day in the year. That's probably be the worst case scenario because we need some level of -- what it is, it's each well's economics to OpEx that we're looking at on an individual well basis. And we're not going to probably shut in the whole field, but that gives you a flavor for that. And we have some of that in the guidance that we provided today, along with some risking of production I discussed. So the next question was about 2016? Guy Allen Baber - Simmons & Company International, Research Division: That's right, for -- just give us a handle on kind of the Eagle Ford progression as you go into 2016, if CapEx was expected to stay at these low levels.

No, Guy, honestly, been down a lot the last couple of days. There's a couple of folks out on their call, we're pretty early out in the game. I'm going to wait for some other guys to talk about 2016 before I do. I'm in 2016 mode right now. Redone the budget 4 times, and it's not even February. So I'm not giving 2016 guidance. Guy Allen Baber - Simmons & Company International, Research Division: Yes, that's fair enough. Thank-you.

And we'll take our next question from Brian Singer at Goldman Sachs.

I wanted to see if you could provide some color on how you see the cost structure in the offshore evolving, if you see a material reduction in the exploration cost to drill deepwater Gulf of Mexico wells, to develop future discoveries. And where are the services in E&C companies you speak with coming out, particularly for a company like Murphy that's committed to the offshore?

I've been around that business a long time, Brian, I've seen -- I've had the lowest rates, I've had the highest. We kind of got a mix of it today, with a couple of pretty high rates in our business today as to commitments, but today, this Kodiak project in the Gulf of Mexico, I think, is one of the cheaper rigs in the world, a little over 300,000 a day. So I have one of the higher and one of the lower in my business. And that's the way it goes if you're in the business for a long time. I think there are still a lot of high rate contracted rigs out there in the 550 range. There's many of them. Almost all of the new builds have contracts at high rates. They are stacked. Let's say, one bad technology rig that can do the job, that you can get for 300s. I don't think -- with the big pullback in CapEx this year, I think those would be one-off opportunities for the drillers in my view, I don't see it as to be a big impact. I think it will be a big impact on development. I think you'll see people that hit on exploration wells, unable to sanction. We'll have lower drilling cost, maybe $150,000 a day per rig. So it will be very significant. I don't see it being that significant for me over the next couple of years, but it will be very significant for development. I think that -- it's my personal opinion on this, but this cost going down issue is more onshore-focused at present, massive numbers of rigs. I think that will be the first shoe to drop as to big lowering of expenses. The offshore is controlled by, in my view, larger service providers, more high-tech Christmas trees, completions, gravel packs. I believe it's controlled by less people, too. Two of those people have recently merged, as we know. I don't see the big pullback in that because they won't have the mom-and-pop competition that you would have to the super major service onshore. But a lot of these boats, along with the rigs, it may take a couple years for that to work. But that's -- it's just not as significant as I think you may be thinking, Brian, in my opinion.

That's helpful. And then you seem to say earlier that you're most focused on new opportunities, which seems to imply -- the correct me please, provide more color if that, ideally, you like acquisitions over repurchase and repurchase over drilling. And when you think about acquisitions between the -- among the deepwater conventional onshore, shale, where do you see the best opportunity to augment the portfolio?

Well, I think we're a company that can operate in both. We're a significant deepwater operator. We have super major deepwater ability. We've proven that time and time again. We're running 3 big deepwater rigs today and operate a lot of deepwater facilities. We're a big onshore player and Eagle Ford has done very well there too. So we actually can play in both. I would say today that there's less deal flow in the onshore due to this view there'd be a rapid recovery in price which may or may not happen. And I would say that we're looking at both heavily and, I really do not have a favorite. I'm trying to improve my company's ROCE, improve ROP, and make our company into a better company and compare that always to share repurchase. So those 3 are on the tables for us and I see the onshore as a little bit slow in deal flow today.

And we'll take our next question from Paul Cheng of Barclays.

Hey Guys, good afternoon. Hi, first and foremost, Kevin, congratulations, and thank you for all the years. I won't count how long that we've known each other so -- but anyways, thank you very much.

Been longer than the 77 calls.

(Laughter). But since I say thank you to you that maybe either you or that you could you have someone, on the special item in the quarters. Can you have someone send to us or maybe to other people, I suppose, they also want, the pretax number? And also that what region that they are hitting at? That would be really helpful.

Yes, we can get that to you.

Yes, that really appreciate. On -- Roger, on the M&A, you guys have been in a good shape because you have a perfect timing in selling your Malaysian asset. So with that in mind, historically, Murphy always is countercyclical in acquisition. And if the opportunity come, will you guys be willing to make a really big acquisition now, in the several billion dollar, using your balance sheet? Or that you would still stick with, historically, that you want to go with several hundred million piecemeal kind of deal? How should we look at that?

I just loathe not to say. I don't see a need to pick one of those 2 horses right now. We're in a severe price collapse. This is my fifth one in my career. This one's pretty bad because costs are pretty high and a lot of things can happen. And I'm in a very fortunate position with the balance sheet, obviously, could increase production all I want to if I wanted to spend the money. But I believe time is time to sit back and watch this a bit, Paul, on the sidelines. And I'm not going to preclude anything, really, to be honest with you this time. But historically, we haven't been a big giant M&A company, and that would probably be safe to say in the future also.

Okay. And that maybe this is for Kevin. That out of the $1.6 billion, how much of them you can bring it back to the U.S. without any tax penalty?

Actually, we could bring back quite a bit of it without a cash tax penalty right now. But then you start to run into some other accounting tax things. And without getting into a whole lot of detail, with this kind of price drop and with the IDC deductions and like I mean, we're going to run a taxable loss in the U.S. and it's not tax efficient to bring money back when you show a taxable loss because you can't take your benefit from your NOL and you have a bunch of unused foreign tax credits running around. It gets very challenging to do it, but you can do it. So the cash taxes right now would be very minimal. But there are other implications that we have to consider. Now of course, anything we bring back from Canada has an automatic 5% withhold and then that's Canadian withhold. And so there's nothing you can -- you will have that leakage automatically.

How much of the...

We did bring back the first tranche without tax.

Yes, we brought back $1.7 billion from Malaysia at the end of last year, most of which -- some was money they already had, most of it was a closing on the first 20%. And there was no tax associated with that because we helped, like we had talked about several times, a lot of unused foreign tax credits from our U.K. operation that we used.

Oh let me ask that, I mean, on your cash balance, how much of them is now sitting in U.S.?

In the U.S., it's probably about $400 million, in the neighborhood of $400 million.

Okay. And Roger, I mean...

And the revolver is 0, Paul.

Yes, our revolver is currently 0. The only debt we have other than that lease is our long-term bond.

Okay. Roger, will you be able to give us a rough estimate? What is the percent of your supply cost? They are currently under contracts that are longer than 2 years or still have more than 2 years to go?

You mean in rigs or...

Everything that is under your supply -- if I look along your supply chain, and I'm trying to understand that how quickly is the opportunity, if we do see a service cost deflation, how quickly that you can -- come to see that? What is plan?

In my Eagle Ford business, I want to leave the business today and get rid of all the fracking and the 4 rigs I have. I have 5 today, it will be about $50 million. So I have a series of rigs that come off-term. I have one coming off in February 4, one on March 11, one in October, one in December, one in September, one in June. These are rates in the 25,000 to 27,000 range, pretty normal in the play. And we have some frac spread commitments. But we have standing wells today and our drilling is very efficient. I don't see ever getting to a price we wouldn't probably frac some wells because we're out drilling that. So the onshore is big, and I have some very large commitment in the deepwater, Paul. Been in the deepwater business my whole career. So if you have to have rigs and boats and equipment, and we have hundreds of millions of dollars of rigs contracted out into 2016 and one rig in 275 days this year and some rigs out in Southeast Asia, which are part of long-term ongoing developments.

Okay. A final one, Roger. I mean, some other company that has started talking about headcount reductions and other more significant measurement in trying to get their cost reduction. Anything that from your standpoint that you feel pretty comfortable with your organization as it is and just going to ride it out or that you're also going to be looking along those lines?

Well, we're like any company during these times. You have to look at each thing. We have to look at organizational efficiency and where we have places for improvement. The entire cost of all our G&As is probably a $300 million number of everything we have, including all comp, all people, all things. So it's not the end-all of our $1.5 billion type cash flow number. One thing that's different on this cost, this price pullback, Paul, to all the others in our career, we've been on these calls with Kevin a long time, you've seen this before, the shale revolution requires a lot more people, accounts payable, procurement, royalties, production allocation, et cetera. It's a little bit more complicated. And if you think there could be a recovery and you make those calls, it's hard to crank back up. So I think that will be at play this time. It is -- my first focus is to try to finally get through with the budget, which we've done. And me, like any manager in times like this, we'll have to look at organizational efficiency. But I'm not prepared at this time for any drastic measure of any kind at this time, Paul.

And we'll take our next question from Roger Read at Wells Fargo.

Exploration program. So you sold down part of Urca, either at the beginning or during the drilling process. And on Slide 16, $266 million net cost for, I guess, all of the '15 exploration program, which -- what's the potential for selling down some of that, in other words, kind of lowering your exposure, if need be, from a CapEx standpoint or even from just an overall portfolio approach?

Well, I'm not against doing that. I've been very fortunate this year to have the sale in Malaysia, at the same time sell down to a partner from -- that we work with internationally coming into that well. I would -- I don't -- when wells get over $100 million, I'd like to be 35%. I don't mind drilling some, a little bit less than that at 50%. Sea Eagle is currently a 50-50 opportunity, Dalmatian South is 70-30, Murphy got a pretty inexpensive well. We're 50-50 on Desperado and 50-50 on Opal. I'm not against taking a couple of those to 35%, and I would. But it's not that easy to sell that today. Not everyone has the balance sheet I have, Roger and so that would be the goal there. The Perth Basin, we are already properly partnered there at 40%, and these are pretty inexpensive wells testing a pretty big program for 27 million barrels net. We now have a new partner, of course, on the wells in Malaysia, as I read on Slide 16. We're partnered appropriately at deepwater Sarawak, which is a place that we drilled many, many wells and have a good idea on the costs. So obviously, at Block H, we partnered with our new partner, Pertamina, as well as Brunei. So my Gulf of Mexico wells would be an opportunity to take those $100 million type wells down by 15% would be the type of CapEx savings there, Roger.

Okay. So take kind of a, I don't know, $35 million, $40 million off the $266 million, might be the right way to think about it?

I'm not against doing that, but I'm a long way from -- we're just having a couple of meetings on a couple of them now. So I don't have it, at all, put to bed, Roger, in these times.

Sure, sure. Yes, I'm just sort of looking at the -- I mean, a couple of the larger wells in the back half of the year, and even Sarawak late Q2.

I think our balance sheet ability here, I think there could be some opportunity to come for us to go in, instead of maybe so much going out. So if I were to go out, I may want to go in somewhere else.

You just stole my second question there, Roger, which was in an environment like this...

[indiscernible] everybody I could get off the call.

And like you said, you went through several of these downturns before, they're all different. Operating cost and rig cost offshore are going to come down at least as significantly, it appears, as anything we'll see onshore, it just takes a little longer. So as you think about where the returns are and where the, let's call it, the pain and suffering of your competitors, where do you think you were going to see opportunities too early maybe? Or it seems like shale guys are, generally speaking, fairly healthy and able to get their costs in line. So I'm thinking it's more of an offshore for the opportunity here.

I'm not sure, I'm not sure about that. I think there's going to be a lot of opportunity in shale and in the offshore. And I think both are going to be equally available in my view.

And we'll take our next question from Ed Westlake at Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Hey, good afternoon and congrats on a record earnings -- sorry, record production. Obviously oil prices will do what it does, but good execution. Just on the Gulf of Mexico. Just remind me what is? Is Opal the Miocene or is that up in north of the play?

No, this is a Miocene pinch-out play, kind of a look-alike of the old Petronius field, a pretty unique structure unlike the Cretaceous edge at the Gulf of Mexico toward severe Eastern Gulf. So it would be nothing to do with the Northwood area. Edward Westlake - Crédit Suisse AG, Research Division: Right. Okay. And then where do you reckon the Gulf of Mexico will break even as these cost shake out, if you would? You mentioned that rigs are a decent chunk of the development spend. I don’t know if you've done any sort of preliminary screening.

All of the projects we're doing like the Medusa are fine and at the 50 range. We have facilities that are tied-back facilities, can work in the 50s. When you get some of these exploration at the cost we have today, you're really going to need it to be around 70. It's not 100 or 80 or 90. I think, and I believe, oil can recover to the 70s into next year personally. So that would be some of the places that are a little more remote or may require facility in the 70 range. But the tiebacks are very near to where you're working, like Medusa, Dalmatian and Sea Eagle, which is near Thunder Hawk, and it can work pretty good, Ed. Edward Westlake - Crédit Suisse AG, Research Division: Yes. That ties them into some of the work we've done. Deepwater Sarawak, just remind me what type of structure and hydrocarbon that's chasing.

This is a new play. We're very familiar with both Vietnam and Malaysia. We've been in Malaysia since '99. This is a new gas opportunity area. There was a discovery by newfield there it was sold to another party. This is a net block. We've done a lot of technical work and really like exploring back in this region, again, because we've maintained an exploration presence in that region for a long time. These are 1 Tcf gas with 80 million barrels of liquid, heavy liquid, and we would have an advantage where we could take this gas production into our long-term Sarawak gas facilities and have a route to LNG and recover the condensate offshore. This is a new opening play for us, and we're very excited about that area and working hard on that, be drilling that well mid-year. Edward Westlake - Crédit Suisse AG, Research Division: And deepwater, but I guess I don't know what the conditions are like. I mean is that going to be a sort of a lower breakeven you think than the Gulf?

Oh, yes. These are wells not even 60 million. We probably drilled 50 or 60 of them just like it. Edward Westlake - Crédit Suisse AG, Research Division: Right. Just on a question on the Eagle Ford chart that you presented, very helpful in terms of the managing the balance sheet and cutting the wells borderline dramatically into the fourth quarter and, obviously, that will impact production. But would you be able to maintain that low rates, say, oil prices were low in '16, and maybe not lose any of the acreage in terms of commitments? I'm trying to think about how much flexibility you have versus lease commitments in terms of the Eagle Ford.

We like to keep 4 rigs to keep the acreage. We've not done a detailed review of it. And quite frankly, if oil stays at $44 until 2016, you may want to let some of it go, and go buy back. So -- and Ed, I appreciate your tricky way to ask me a 2016 guidance, but I'm not -- I appreciate that effort. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And then one final question, and this is more financials. In the fourth quarter, and I appreciate there's lots moving around with the sales, I'm looking at the cash flow statement. You ended up with a deferred income tax charge. Obviously, there was another large movement in the other area to get to the $700 million. And I guess you have sort of helped us with 2015 numbers, and I'm -- similar to the numbers that were quoted, but what are those 2 main items related to, just so I can understand.

I'll have John answer that for me, Ed.

Ed, those items deal primarily with our sale in Malaysia. There was a lot of noncash moving parts in that transaction. And we -- when you referred to the deferred tax charge, it was really a benefit in that our purchaser acquired the obligation to pay some of those future taxes in Malaysia, so that brings down the deferred tax liabilities on our books. But some of the -- a lot of the gain was noncash-related and had some impacts on the other categories that are referred to here.

It's all related.

And we'll take our next question from Ryan Todd at Deutsche Bank.

Question -- I guess a couple of follow-ups, one on exit rates and the trends in production. You were kind enough to provide kind of a quarter-by-quarter outlook in the Eagle Ford. But given the high starting point from a high fourth quarter production level and the full year number, can you help us understand a little bit the trajectory and where you might be looking on the broader portfolio in terms of 4Q exit rates?

Well, one thing, this is a bit of a complication. We did do a home run ball in the sale, but it messes up all your production to explain in a form such as this. So we had a very high quarter. We pro forma-ed that down to 231. But we got to get our hands around or heads around here, and everyone on this call. Murphy is a complicated company. We're in East Coast, Canada, Syncrude, Gulf of Mexico, Malaysia, we're not an onshore player. And in the fourth quarter, the weather is pretty bad all over the world. It's monsoon season in Malaysia, it's very cold in Canada, it's very bad weather in the Gulf usually. We don't work on or shut down or do things. So it was a very good quarter, and we were -- exceeded guidance because there was really downtime, very little trouble. We also cut CapEx a lot. So if you're 231 going to 201, which I guess is your situation, right, Ryan?

Yes.

So 13,000 of it almost is CapEx and Seal shut-ins that related to oil price -- or related to my desire to really protect the balance sheet going forward. We could drill -- we could absolutely afford to add 13,000 equivalent production if we wanted to, I just chose not to. So that's the first step. We have probably 4,000 barrels of shut-ins around the world, turnarounds of various kinds across 10 different places: Kikeh, twice this year; Sarawak gas onshore shutting down for some regulatory things; and all those things. So if I give you a breakdown here further, I mean, at 12,500 of CapEx, 7,500 of Malaysia assumed. Another thing is, we had a very good quarter in the assumption of these gas nominations are probably close to 280 million gross, we have 240 million in our budget with some shutdowns coming. So 12,500 CapEx, 7,500 on nominations and downtime, including the risking I've spoken to many times, and have North America offshore, we have Medusa coming on and offset by outages at Habanero, Medusa. Mondo is a place that makes about 2,000 barrel equivalent for a very long time. Now the field is supposed to go off-line from the sub-service perspective and it just never dies. We have no DD&A there. It's been one of the greatest gas fields of all times, but it's going to die this year at some point, I don't know exactly when. So that's 8,000, and have a 1,000 on Syncrude risking because they have maintenance, and things they didn't have in the fourth quarter. So just not a fourth quarter to a year company, this is not the way we roll here. If you look back at the history of Murphy, I would bet you that the fourth quarter is high every single time because the weather is too bad to work on anything.

That was really helpful. At Tupper, where you effectively have a full year number that's more or less flat with 1Q despite drop in the rigs in February. Is that kind of timing of the completions issue? Or what would you expect the decline rate to eventually settle out at Tupper going forward?

I don't have that off the top of my head. We are going to be declining because we're not adding. We just added a bunch of wells in the fourth quarter. We have some we're just about to put on production now and we'll be finished up. We can give the beginning and end rate. Barry, do you have that number?

Yes. So I mean, we're going to average in the neighborhood of 170 in the Montney for the year, but it starts off the year pretty strong with these new completions. We ended up the back half of last year bringing on these new completions with this new completion technology flowing, higher rate wells, and so those really kicked in, in the fourth quarter and those carry on. And we have the benefit of those in the first part of the year, but once the rigs go in February, it's just more of a decline now through the end of the year. So you end up averaging a pretty good number for the year, but it drops from the start to the end.

Okay. And then maybe one last one. On the - how much -- I know you said in one of the slides in here that you're targeting 10% to 20% cost reductions in the Eagle Ford. How much -- is that what you assume in the $2.3 billion budget? Or I guess how much cost deflation do you assume and how much upside might there be, I guess, from that point of view or downside to cost, I guess?

In the Eagle Ford Shale, we've assumed a 10% cost in reduction of drilling, the services to drill the well. And further efficiencies puts us probably about 15% because we do have efficiency work there a long time, and we've assumed no cost reductions elsewhere in our business.

And we'll go next to James Sullivan at Alembic Global Advisors.

Just to piggyback on that, the last question that got asked there about the cost reduction assumptions. It sounds like you're saying 15% total from cost of drilling and efficiency in the Eagle Ford, which you had baked in. There are people talking about larger numbers. And if you guys -- if that did materialize, could you just speak to what your thoughts are today in terms of what you would do to redeploy or, if you would, just try to save any capital savings on -- from further service cost deflation?

I don't like forecasting unless I have my hands on it. We have our hands on the 10%. 15% will come from efficiency learning curve type thing. If we get our hands on it, we'll look to change. But right now, I'm trying to get a budget we can execute on and get a full rig strategy into the Eagle Ford. I'm pretty much in the saving mode and opportunity-searching mode over jumping to add a rig back in the Eagle Ford right now.

Okay, sounds great. The other thing was just, I wanted to get a little clarity on the exploration budget. I think you guys have in your slide about 380 million. And the Slide 16 gives you nice delineation of the wells that you guys have been drilling across the geographies. That was really helpful. And that. Do you have $266 million over there? What's the delta there is it? I know you guys are doing seismic in Ceduna, but is there other things in there that we should -- that go into that?

With the cost of all of our exploration offices and people around the world, and seismic, and studies and a very small lease or lease act and the Gulf of Mexico budget, I wish I could have more, but it would be those type of matters, non-drilling. But primarily a pretty good year of drilling and a pretty decent program. I'm quite happy with the program. Just not happy with the amount of money I can spend today on new opportunity. But that's -- I've decided to cut as much as I can and have a tight balance sheet, it's where I'm going with this thing.

Okay, that makes sense. Okay. And then just last thing, maybe at a more of a macro level or just pulling back a little bit from the specifics of the budget. How constrained did you feel in terms of -- as you were working through this, it sounds like it was a long and difficult and iterative process. But how constrained did you feel in terms of where -- places where you're not operators and didn't have complete freedom to choose to cut the budget? And would you say that, that drove your decision? I mean, obviously, if you can't cut the budget, you can't cut the budget. But to what extent would you say that the depths of the cuts in some places might have been driven by lack of optionality elsewhere in the portfolio?

Well, the big rig commitments we have drove a lot of the exploration, we probably would have less. And no, we're a heavy operator. We're a non-op at East Coast, Canada, like in the 5% to 7% range and a 5% at Syncrude. Those people work with us and told us their CapEx. They, too, in these collapses, want to lower CapEx. We're really not controlled by the non-op too much. Most of the non-ops is quite older, requiring some capital to maintain. But most of the CapEx is in our control and allows us, I think, this balance sheet advantages, kind of our strategy to control a lot of what we do.

And gentlemen, we are at the top of the hour. I believe we have no more time for questions.

Okay, I want to thank everyone, and again congratulations, Kevin.

Thank you.

And appreciate everyone calling in, and we'll talk to you next time. And we appreciate it.

And that does conclude today's conference. We thank you for your participation.