Murphy Oil Corp (MUR) 2014 Q4 法說會逐字稿

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 financial 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 the 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 will now turn the call over to Kevin.

Thanks, Barry.

For the fourth quarter of 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 2013 of $180.5 million or $0.96 per diluted share.

For the entire year of 2014, income from continuing ops was $1.025 billion or $5.69 per diluted share, compared to $88.1 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 two 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 was primarily a result of ongoing drilling in the Eagle Ford Shale and the current-year start-up 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 2013, with the increase primarily due to higher production from Dalmatian, the 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 for continuing operations for 2014 totaled $3.76 billion. For 2015, our CapEx is 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 $52.52 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.

With that, I will turn it over to Roger.

Hello, everyone.

Before we get started today on our usual update, I want a moment to recognize Kevin. As he announced previously, he is retiring from the Company the 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 am sure you will 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 am sure you will 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 the quarter and the year, we continue to make progress in portfolio optimization. We closed the sale of 30% from Malaysia business for $2 billion in two phases, one announced on December 18 at 20% and we just completed phase 2 for 10%, which was announced publicly this morning.

We completed the sale of the UK retail gasoline business, 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 $1.65 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 three 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. We 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, the drop in benchmark prices from third quarter to fourth quarter was near $25 a barrel. We saw fourth-quarter realized oil prices in our Malaysia business near $67 per barrel, in great contrast to the third-quarter prices of this year and fourth of last year.

Our oil index SK gas averaged near $5.50 per Mcf for the quarter.

Moving to the United States, Eagle Ford Shale oil prices were over $78 for the quarter, including the impact of our WTI hedging program, which finished up at year-end. Our realized oil prices in the Gulf of Mexico averaged near $73 per barrel.

In Canada, Syncrude was close to $71 per barrel and Seal, including a hedge and a narrowing heavy differential, was near $46.50 per barrel.

Our global lease operating expense for 2014, excluding Syncrude, is just over $11 per BOE, showing an improvement of 24% over 2013.

We went into the current price decline with an advantage to our peers on cash flow metrics. We expect to maintain this advantage, but at a lower level, due to continued decline in commodity prices.

Looking at production in the fourth quarter, we set a new quarterly record, averaging just over 259,000 barrel equivalent per day, 4% above our guidance of 250,000 per day for the quarter. The increase to guidance is primarily attributed to higher-than-planned gas production in the Montney and Sarawak areas and higher-than-planned oil production from the Gulf of Mexico and offshore Canada.

Production for the full year averaged just short of 226,000, 10% higher than 2013, and ended up above our 220,000 to 225,000 barrel equivalent range given on July 30. The year-on-year growth came from continued ramp-up at Eagle Ford Shale and new offshore projects coming online in the Gulf of Mexico and Malaysia.

In reserves, in 2014 we expect to add reserves at a replacement rate of over 180%. Year-end 2014 reserve volumes represented a reserve life index, or R over P, of just over nine years. This is consistent with our five-year reserve replacement rate of 180% and is our ninth consecutive year at over 100%, and during this time, we increased production since 2006 by 125%.

As we look at our price advantages here, our oil-weighted diverse portfolio has proven to have some benefits as we adjust to the lower price environment. Our Gulf of Mexico, Eagle Ford Shale, and Malaysia oil prices compare well to many of the onshore shale regions in the United States.

In the Eagle Ford Shale, we are oil weighted with very little condensate, and our proximity to the Gulf of Mexico is beneficial, compared to some of the Mid-Continent crudes.

Looking at our global offshore operation in Malaysia, following customary closing and adjustments, we have realized cash proceeds of approximately $1.87 billion on the 30% sale of our Malaysia assets. Production offshore Sabah near 46,500 barrel equivalent per day for the fourth quarter, with 85% liquids. The Kakap-Gumusut main project declared first oil in October 2014. The project has demonstrated excellent performance, with production ramping up over the fourth quarter into this year with rates reaching 120,000 barrels per day gross.

In shallow water offshore Sarawak, gas production in the fourth quarter was 177 million cubic feet per day, with higher-than-expected nominations into the LNG facility. Sarawak liquids production was just over 23,000 barrels per day for the quarter.

Drilling continues at the South Acis field, where we have delivered two oil wells and drilled four water injectors during the fourth quarter.

In the Gulf of Mexico, production for the quarter was near 32,400 barrel equivalent per day, with 65% liquids. We continue to progress our subsea two-well expansion project at Medusa and Mississippi Canyon, where we have a 60% working interest. The first subsea well has been drilled to plan and we are continuing with drilling the second well and subsea tieback to the Medusa facility. First production from the new wells is expected by midyear.

At the non-operated Kodiak development, where we held a 29% working interest, drilling continues on the initial development well, with first oil targeted in the first half of 2016. We are pleased with the pay results seen on the well so far.

In North American onshore business at the Montney, the Tupper gas fields in western Canada, our fourth-quarter production was 186 million cubic feet per day, up from 146 million per day in the third quarter as we added eight new wells. We currently have three rigs and one completion spread in operation, but we reduced the rig count to zero the middle of February as we reduced capital spending across the Company and across lower rate of return projects.

We brought eight new wells online in Quarter 4 and expect to deliver nine wells in 2015. We have seen excellent results utilizing our new completion and choke management strategies, which should lead to improved EUR on future wells.

We have approximately 65 million cubic feet per day of gas hedged at near CAD4.10 AECO for 2015.

In the Eagle Ford Shale, our fourth-quarter production averaged near 64,300 barrel equivalent per day, net, at 90% liquids, up from 60,500 barrel equivalent per day in the third quarter, as we brought on 54 wells. The full-year average of production at Eagle Ford Shale was just under 57,000 barrel equivalent per day, up from near 39,000 barrel equivalent per day in 2013.

We have reduced our rig count in Eagle Ford Shale from a high of eight in September to five today, and we plan to be at four rigs by early March as we release rigs due to capital constraints and falling commodity prices.

We are now using two completion spreads, down from three in December, and expect to average 1.6 spreads this year. Production in the fourth quarter of 2015 is estimated to average 63,000 barrel equivalent per day, with 45 new wells coming online. We are now estimating full-year production near 57,000 barrel equivalent per day, flat to the prior year, based on bringing on 118 new wells, down approximately 100 wells from 2014.

We continue to see positive results from our down spacing and staggered well testing across the play. Our current focusing is on managing capital spending and operating expenses. The long-term value of our Eagle Ford position is bolstered by our early entry into the play at an average lease cost of approximately $2,000 per acre.

We continue to execute well in the Eagle Ford Shale. We built a strong team, and in execution of building an onshore business have grown production to current levels from our entry in the play in 2009 by lowering our drilling and completion and lease operating expenses each year.

As we look at guidance, first-quarter guidance for 2015 is detailed in our earnings release and on slide number 14 today. We expect production to be near 221,000 barrel equivalents per day, with sales targeted 230,000 barrel equivalents per day, with the overlift coming primarily from Malaysia.

Exploration expense for the quarter is estimated at $108 million. It includes $50 million of potential dry hole costs for Urca in the Gulf of Mexico and three perf basin wells in Australia and $24 million for G&G expenses globally.

The full-year production guidance range is 195,000 to 207,000 barrel equivalents per day, and I will provide more detail on this shortly.

Looking at CapEx in 2015, our current budget for capital spending and production guidance is based on average oil prices for the year of $52 WTI, $57 Brent, and $3 Henry Hub. Further declines in price may result in changes to our guidance. We are forecasting our capital expenditures to be $2.3 billion, down approximately 33% from the 2014 pro forma of $3.5 billion, when calculating out the Malaysian sale.

The bulk of our spending will be in development drilling and field projects, with 17% of our capital allocated to exploration program, of which $266 million or near 75% is allocated to exploration drilling. The projected development spend of approximately $1.9 billion is split between our global offshore business at 45% and North American onshore at 55%.

Most significantly, we are cutting our Eagle Ford Shale CapEx by 46% compared to 2014 spending, with a reduction in rigs from eight in September to hopefully four in mid-March.

In our exploration program in the Gulf of Mexico, we are currently drilling the operated Urca prospect in Mississippi Canyon 697, where we farmed down from 50% to 35% working interest. We expect to reach TD by mid-February.

This Middle-Miocene target is a pre-drilled gross mean resource size of 130 million barrels.

In Australia, we spud the first of three wells in our Perth Basin program on January 22, where we operate with 40% working interest. We are testing a total of 280 million barrels of gross mean resource across three wells. The 3D seismic program in our Australian block in the Ceduna Basin is now over 50% complete and we expect to finish up in the near term.

Looking at the rest of our 2015 program, we plan to drill up to four wells in the Gulf, testing 620 million barrels equivalent of gross mean resource. We will drill five wells in southeast Asia, in Malaysia and Brunei, and test 350 million gross mean resource.

Overall, the 2015 program will test a net risk mean resource of near 190 million barrel equivalent or $266 million in exploration drilling capital.

If you look at production in 2015, we are guiding to a 2015 production range of 195,000 to 207,000 barrel equivalent per day in that year. The midpoint of this range, or 201,000, would place us with a slight growth over the 2014 pro forma, with the 33% budget reduction in 2014 to 2015, including a 46% reduction in Eagle Ford Shale capital year on year.

As we look into 2015 posted sell down, we have both near-quarter items and entire-year items further impacting production. As a starting point, our fourth-quarter average of near 259,000 equivalent would be lowered to 231,000, and the 2014 annual production of near 226,000 barrel equivalent per day is adjusted to just under 200,000, both on a pro forma basis, as sell down in Malaysia.

Looking at the first quarter, we see Sabah being higher with the ramp-up in the Kakap-Gumusut main project and new wells coming on at Kikeh. In the Gulf of Mexico, planned outages at non-operated Habanero in our Medusa field impact quarterly production rates. The rest of the decrease is attributed to assumed lower gas nominations in Sarawak and rig cuts for capital reduction starting to impact our North American onshore business.

Typically, the fourth quarter is a high production period, with no planned turnarounds or outages scheduled. Over the course of the full year, we have planned outages for maintenance work typically scheduled during the better weather in the middle of the year. In addition, we continued a risk reduction in nomination levels of both operated and the non-operated facilities that we do not control.

Moving to the full year, both Kakap-Gumusut and Siakap North-Petai will contribute for the entire year when compared to 2014. Full-year contribution from Dalmatian and the mid-year start-up of Medusa expansion add to this year, but is offset with the expected shut-in of the Mondo field, along with planned outages and field declines. Year on year, we see a slight increase in Montney production, despite a fall-off from the quarter high in 2014 in fourth quarter. We are seeing production decline in our heavy oil at Seal as we shut in uneconomic wells at this lower price level.

As to liquidity, we are starting off 2015 in very good financial shape, with our balance sheet and cash positions bolstered by the recent sell-down of our Malaysia business. We are well positioned with flexibility and optionality to carry out our 2015 plans of intention to operate in capital cost reductions, maintain the current dividend, manage our US cash position, take advantage of opportunities that may arise during this downturn, and increase our activity level when prices recover.

As to takeaways, as we look back in 2014 we impacted our shareholders positively with share buybacks, as well as increasing our dividend. We've again increased and replaced production now for nine years in a row. Our reserve replacement history continues at over 180%.

I feel the current downturn in prices and associated capital reductions gives us a recalibration point to production, and we plan to take advantage of this change, with recent results showing improvement in meeting production guidance.

Our onshore North American business has become very significant, representing near 45% of our 2014 production levels. Our early entry at low cost in Eagle Ford Shale will now show the value of the play going forward. Our plan is to maintain our Eagle Ford Shale 2014 production level flat in 2015, with a 46% reduction in capital spending year on year.

We have made many changes in senior personnel and process in our exploration business. We are confident in our plans to test nearly 190 million barrels equivalent this year's program, as well as evaluate new opportunities that will become available in this downturn.

We went into the current price collapse with a cash flow per barrel advantage to our peers, which should continue. In late 2013, we set out to mark the value of our Malaysia business and remove some concentration risk, as well as hopefully do further portfolio optimization work. The timely closing positions us very well to maintain flexibility from a balance-sheet perspective. Our Company has survived prior price drops with a conservative balance sheet, diverse producing assets, an exploration-based growth strategy that has stood the test of time.

I will now be glad to take your questions. Thank you.

(Operator Instructions). Leo Mariani, RBC.

I was hoping you all could speak to uses of the cash in Malaysia. Obviously, you have gotten the proceeds in at this point. Could you talk about how you are thinking about using that and how you would prioritize those uses?

Right now, we just -- it's been a very complicated, long closing process, as I 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 am very happy with that.

Just getting in the last piece today, Leo, during a pretty big price collapse there, so what we have 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.

Obviously, we all know where the opportunities would be. They would be M&A opportunity or share repurchase. We are 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 will have to see a calibration in the thoughts behind the sell price there or at least in the cost aspect of it or some slowdown in stability in crude.

Our plan is to hunker down and monitor all that right now and just not stating on what the plans are, quite frankly.

All right. 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 2015 and where you would pull back and where you would add capital, and maybe just talk through some scenarios?

I thought $52 was a good number a couple weeks ago; now, it's probably $45. That shows the problem today.

I think we're in pretty good shape to execute what we have. Obviously, I think you'll find that we will have, when all of the earnings releases are done, I think we will 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 -- obviously, the Eagle Ford Shale is a very valuable barrel. The barrels are in the ground there, and we can stop spending them there, and it is a US spend where the US 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 it 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.

I feel real good about ability to cut there some and quickly add there, but I think we can handle what we have pretty good here, even if things go down, Leo.

All right, and I guess could you maybe just speak to type of oil price you would need to see start ramping Eagle Ford, even if it is 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 am 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.

I think we have to do further rigs to be dropped, which is all the rage and all the discussion. When that gets in the 1,000 level, costs will calibrate. I don't believe we are there yet. I just don't walk around with a number saying we are going to get back after it. I am in the hunker-down mode right now and looking for opportunity, frankly.

All right, that makes sense. Thanks.

Guy Baber, Simmons.

Kevin, congrats on your retirement and on your Cal Ripken-like streak of calls.

That is. That's well put, Guy. He's a little -- he's in not quite as good a shape as Cal Ripken.

I wanted to talk a little bit about the cash flow and CapEx relationship, given the commodity price assumptions that you published and use to set the budget. But just curious if you could share with us 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 that you have cut pretty aggressively.

We don't usually get into all that kind of detail, but I will share with you a little 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]. Then we have the proceeds coming in from Malaysia. We will, of course, outspend at $52 million. It won't take a lot of calculation to get there. I think that will 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. I feel good about where we are because we happen to have a lot of cash today.

That's helpful. 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 see much of across the oil sands, at least not yet.

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 would be great.

First on Seal, there is hundreds of wells at Seal and they are very -- and we have two businesses there. We have an old conventional business that's been in place for a long time, which we are really not investing in anymore, and a futuristic kind of steam business that is going actually very well.

So we may have maybe a 250-barrel shut-in today, and we feel that at the worst case, we could get 80 wells shut in for a couple of thousand barrels a day for 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 are looking at on an individual well basis. We're not going to probably shut in the whole field, but that gives you a flavor for that. We have some of that in the guidance that we provided today, along with some risking of production I discussed.

The next question was about 2016?

That's right, just getting a handle on the Eagle Ford progression as you going to 2016, if CapEx was expected to stay at these low levels?

Guy, honestly, been down a lot the last couple days. There's a couple folks out on their call look pretty early out in the game. We will wait until some other guys talk about 2016 before I do. I am not in 2016 mode right now. Redone the budget four times and it's not even February, so I'm not giving 2016 guidance.

That's fair enough. Thank you.

Brian Singer, 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 material reductions in the exploration cost to drill deepwater Gulf of Mexico wells to develop future discoveries, and where are the services and E&C companies you speak with coming out, particularly for a company like Murphy that's committed to the offshore?

I have been around that business a long time, Brian. I have seen -- I've had the lowest rates. I have had the highest. We kind of got a mix of it today when it's 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 at 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 are in the business for a long time.

I think there is still a lot of high rate contracted rigs out there in the $550,000 range. There is many of them, almost all the newbuilds, have contracts at high rates. They are stacked, let's say one back technology rigs that can do the job that you can get for $300,000s.

I don't think -- with the big pullback in CapEx this year, I think those will be one-off opportunities for those 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 will have lower drilling costs, 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 years, but it will be very significant for development.

I think there is -- it is my personal opinion on this that 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 is controlled by less people. 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 go long with the rigs. It may take a couple of 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. Then you seemed to say earlier that you are most focused on new opportunities, which seems to imply, but correct, please, provide more color if -- that ideally you would like to do acquisitions over repurchase and repurchase over drilling. When you think about acquisitions among the deepwater, conventional onshore, or shale, where do you see the best opportunity to augment the portfolio?

I think we are a company that can operate in both. We are a significant deepwater operator. We have super-major deepwater ability. We have proven that time and time again. We are running three big deepwater rigs today and operate a lot of deepwater facilities. We're a big onshore player in the Eagle Ford and have done very well there, too. So we actually can play in both.

I would say today that there is less deal flow in the onshore, due to this view that it will be a rapid recovery in price, which may or may not happen, and then I would say that we are looking at both heavily and I really do not have a favorite. I am trying to improve my Company's RoCE, improve R over P, and make our Company into a better company and compare that always to share repurchase.

So those three are on the table for us and I see the onshore as a little bit slow in deal flow today.

Thank you very much.

Paul Cheng, Barclays.

First and foremost, Kevin, congratulations and thank you for all the years that -- I won't count how long that we know each other, but anyway, thank you very much.

It's been longer than the 77 calls.

But since I say thank you to you, that maybe either you or that you could 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? That would be really helpful.

Yes, we can get that to you.

Yes, that -- really appreciate. Roger, on the M&A, you guys are in great shape because you have perfect timing in selling your Malaysian asset.

Correct.

With that in mind, historically Murphy always is countercyclical in acquisition. If the opportunity come, will you guys be willing, then, to make a really big acquisition, like in the several billion dollars, using your balance sheet, or that you will still stick with historically that you want to go with several hundred million piece new kind of deal. How should we look at that?

I just -- I just [loathe] not to say. I don't see a need to pick one of those two horses right now.

We're in a severe price collapse. This is my fifth one in my career. This one is 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, I could increase production all I want to if I wanted to spend the money, but I believe time is -- it 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 at 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.

Maybe this is for Kevin. Of the $1.6 billion, how much of them you can bring it back to the US 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 lot of detail, with this kind of price drop and with your [IDC productions] and like, we're going to run a taxable loss in the US 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. 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% withholding and that's Canadian withholding, so there's nothing you can -- you will have that leakage automatically.

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 the closing on the first 20% and there was no tax associated with that because we had, like we had talked about several times, a lot of unused foreign tax credits from our UK operation that we (multiple speakers)

Let me ask that. On your cash balance, how much of them is now sitting in US?

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

Okay, and Roger (multiple speakers)

(multiple speakers) revolver is zero, Paul.

Yes, my revolver is currently zero. The only debt we have out, other than that lease, is our long-term bonds.

Okay. Roger, will you be able to give us a rough estimate what is the percent of your supply cost? They are currently under contract that longer than two years or still have more than two 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 service cost deflation, how quickly that you can come through? I am trying to see that what is the plan.

In my Eagle Ford business, if I wanted to leave the business today and get rid of all the fracking and the four rigs I have -- I have five today, it would be about $50 million. I have a series of rigs that come off term. I have one coming off on 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. We have some frac-spreads commitments, but we have standing wells today and our drilling is very efficient. I don't see ever getting to a price where we wouldn't probably frac some wells because we're out drilling that.

The onshore is big and I have some very large commitments in the deepwater, Paul. I've been in the deepwater business my whole career, so if you have to have rigs and boats and equipment, we have hundreds of millions of dollars of rigs contracted out into 2016 on one rig and 275 days this year in some rigs out in southeast Asia, which are part of long-term ongoing developments.

Okay. A final one, Roger, some other companies have 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?

We, 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&A 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 a $1.5 billion type cash flow number.

One thing that's different in this cost -- this price pullback, Paul, to all the others in our career -- if you have been on these calls with Kevin a long time, you have 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 make those calls, it's hard to crank back up.

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 have done, and me, like any manager in times like this, will have to look at organizational efficiency, but I'm not prepared for this time for any drastic measure, any kind at this time, Paul.

Thank you.

Roger Read, Wells Fargo.

Exploration program, so you sold down part of Urca, either at the beginning or during the drilling process. On slide 16, the $266 million of net costs for, I guess, all of the 2015 exploration program, which -- what is the potential for selling down some of that? In other words, lowering your exposure, if need be, from a CapEx standpoint or even from just an overall portfolio approach?

I'm not against doing that. I have been very fortunate this year to have this sale in Malaysia and at the same time sell down to a partner that we work with internationally coming into that well. 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, but a pretty inexpensive well. We are 50-50 on Desperado and 50-50 on Opal. I am not against taking a couple 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're already property 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 are partnered appropriately at deepwater Sarawak, which is a place that we've drilled many, many wells and have a good idea on the cost. Also Block H, partnered with a new partner, Pertamina, as well as Brunei.

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, I don't know, $35 million, $40 million off the $266 million might be the right way to think about it?

I am not against doing that, but I am a long way from -- we are 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, I'm just sort of looking at a couple of larger wells in the back half of the year and even Sarawak late Q2 (multiple speakers).

(multiple speakers) 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 --

(multiple speakers) everybody I could get off the call. (laughter).

Like you said, you went through several of these downturns before. They are all different. Operating costs and rig costs offshore are going to come down at least as significantly, it appears, as anything we will see onshore. It just takes a little longer.

As you think about where the returns are and where, let's call it, the pain and suffering of your competitors, where do you think we're 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 am thinking it's more of an offshore for the opportunity here.

I'm not sure. I'm not sure about that. I think there is 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.

Okay, thank you.

Ed Westlake, Credit Suisse.

Congrats on a record earnings -- sorry, record production. Obviously, the oil price will do what it does, but good execution. Just on the Gulf of Mexico, just remind me, is Opal the Miocene or is that up in the north of the play?

This is a Miocene pinchout play, kind of a look-alike of the old Petronius field, a pretty unique structure on the Cretaceous edge of the Gulf of Mexico, toward severe Eastern Gulf, so it would be nothing to do with the north [foot of that] yet.

Right, okay, and then where do you reckon that the Gulf of Mexico will break even as these costs shake out? If you were doing -- you mentioned that rigs are a decent chunk of the development spend. I don't know if you have done any sort of preliminary screening?

All the projects we are doing, like Medusa, are fine and at the $50 range. We have facilities there. Tie-back facilities can work in the $50s.

When you get some of this exploration at the costs we have today, you are really going to need it to be around $70. It's not $100 or $80 or $90. I believe oil can recover to the $70s into next year, personally.

That would be some of the places that are a little more remote or may require facility in the $70 range, but the tie-backs very near to where you're working, like Medusa and Dalmatian and Sea Eagle, which is near Thunder Hawk, can -- it can work pretty good.

That ties in with some of the work we have done. Deepwater Sarawak, just remind me what type of structure and hydrocarbon that is chasing?

This is a new play. We are very familiar with both Vietnam and Malaysia. We have been in Malaysia since 1999. This is a new gas opportunity area. There was a discovery by Newfield there that was sold to another party. This is in that block.

We have done a lot of technical work and really like exploring back in this region again, because we have maintained an exploration presence in that region for a long time. These are 1 Tcf gas with 80 million barrel 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. We are very excited about that area and we're working hard on that, be drilling that well mid-year.

Deepwater, but I guess -- I don't know what the conditions are like. Is that going to be a lower breakeven, you think, than the Gulf?

Yes, these are wells not even $60 million. We've probably drilled 50 or 60 of them just like it.

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 brought online dramatically into the fourth quarter, and obviously that will impact production. But would you be able to maintain that low rate -- say oil prices were low in 2016 -- and maybe not lose any of the acreage in terms of commitments? I am trying to think about how much flexibility you have versus lease commitments in terms of the Eagle Ford.

We'd like to keep four rigs to keep the acreage. We have not done a detailed review of it, and quite frankly, Ed, if oil stays at $44 until 2016, you may want to let some of it go and you'll buy it back.

Ed, I appreciate your tricky way to ask me 2016 guidance, but I'm not (multiple speakers). Appreciate that effort, though.

Okay, thanks. Then one final question, and this is more financials. In the fourth quarter, and 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. I guess you have helped us with 2015 numbers and I am similar to the numbers that were quoted. But what are those two main items related to, just so I can understand?

I'm going to have John answer that for me, Ed.

Ed, those items deal primarily with our sale in Malaysia. There was a lot of non-cash moving parts in that transaction, and when you referred to a deferred tax charge, it was really a benefit in that --

Yes, sorry, yes.

-- 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 non-cash related and have some impacts on the other categories that are referred to here.

Right, okay, thanks very much.

Ryan Todd, Deutsche Bank.

Congrats on the quarter. Question, I guess a couple follow-ups, one on exit rates and the trends in production. You were kind enough to provide 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 at it on the broader portfolio in terms of 4Q exit rates?

One thing that's a bit of a complication, we did do a home run ball on the sale, but it messes up all your production to explain in forums such as this.

So we had a very high quarter. We pro forma that down to 231,000, but what we got to get our hands around, our heads around here and everyone on this call, Murphy is a complicated company. We are East Coast, Canada, Syncrude, Gulf of Mexico, Malaysia. We are not an onshore player, and in the fourth quarter, the weather is pretty bad all over the world. It is monsoon season in Malaysia, it's very cold in Canada, it's a very bad weather in the Gulf, usually, and we don't work on or shut down or do things.

It was a very good quarter. We exceeded guidance because there is very little downtime, very little trouble. We also cut CapEx a lot, so if you are 231,000 going to 201,000, which I guess is your situation, right?

Yes.

13,000 of it, almost, is CapEx and Seal shut-ins 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. That's the first step.

We have probably 4,000 barrels of shut-ins around the world and turnarounds of various kinds across 10 different plays, at the Kikeh twice this year, Sarawak Gas on shore shutting down for some regulatory things, all those things.

If I give year breakdown here further, we have $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. We were probably close to 280 million gross and we have 240 million in our budget with some shutdowns coming.

$12,500 CapEx, $7,500 on nominations and down time, including the risking that I have spoken to many times. North American offshore, we have Medusa coming on and offset by outages at Habanero. Medusa. Mondo is the place that makes about 2,000 barrel equivalent for a very long time. The field is supposed to go off-line from a sub service perspective and it just never dies. No DD&A there. It's been one of the greatest gas fields of all time, but it is going to die this year at some point. I don't know exactly when.

That's $8,000 and I have $1,000 on Syncrude risking, because they have maintenance, a thing they didn't have in the fourth quarter.

Just not a fourth quarter to year Company. That's just not the way we roll here. If you look back at the history of Murphy, I would bet you that the fourth quarter was high every single time because the weather is too bad to work on anything.

Thanks, that was really helpful. At Tupper, where you effectively have a full-year number that's more or less flat with 1Q, just by dropping the rigs in 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 are 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 will be finished up. We can give the beginning and end rate. Barry, do you have that number?

We are 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 got 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. How much -- I know you say on one of the slides in here that you are 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 inflation 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 have assumed a 10% cost in reduction of drilling, the services to drill a well, and further efficiencies puts us probably about 15%. Because we do have efficiency, we worked there a long time, and we have assumed no cost reductions elsewhere in our business.

Okay, thanks. It's helpful.

James Sullivan, Alembic Global Advisors.

Thanks for taking the question. Just to piggyback on that, the last question that got asked there about the cost reduction assumptions, so it sounds like you're saying 15% total from cost of drilling and efficiency in the Eagle Ford was what 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 things. But if we get our hands on it, we will look to change, but right now I am trying to get a budget we can execute on and get a full rig strategy into the Eagle Ford. I am pretty much in a 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 geography, so that was really helpful.

I think you have $266 million over there. What is the delta there? I know you guys are doing seismic in Ceduna, but is there other things in there that we should -- that go into that?

It would be the cost of all of our exploration offices and people around the world in seismic and studies and a very small lease act in 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 drilling and a pretty decent program. I am quite happy with the program, just not happy with the amount of money I can spend today on new opportunity, but that's -- I have decided to cut as much as I can and have a tight balance sheet is where I'm going at this time.

Good, makes sense. Okay, and then just last thing, maybe at 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're 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 are not operators and didn't have complete freedom to choose to cut the budget?

Would you say that drove your -- obviously, if you can't cut the budget, you can't cut the budget, but to what extent would you say that the depth of the cuts in some places might have been driven by lack of optionality elsewhere in the portfolio?

The big rig commitments we have drove a lot of the exploration. We probably would have less.

No, we're a heavy operator. We're a non-op at East Coast Canada in the 5% to 7% range and 5% in Syncrude. Those people work with us and told us their CapEx; they, too, in these collapses want a lower CapEx.

We're really not controlled by the non-op too much. Most of the non-op 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 advantage that is our strategy to control a lot of what we do.

Okay, sounds great. Thanks, guys.

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, and appreciate everyone calling in, and we will talk to you next time and we appreciate it.

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