Kelly L. Whitley - Vice President-Investor Relations & Communications John W. Eckart - Chief Financial Officer & Executive Vice President Roger W. Jenkins - President & Chief Executive Officer.

Leo Mariani - RBC Capital Markets LLC Peter Francis Freeman Kissel - Scotia Howard Weil Roger D. Read - Wells Fargo Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Paul Y. Cheng - Barclays Capital, Inc. Guy Allen Baber - Simmons & Company International Ryan Todd - Deutsche Bank Securities, Inc. Pavel S.

Molchanov - Raymond James & Associates, Inc. Brian A. Singer - Goldman Sachs & Co. Paul Sankey - Wolfe Research LLC.

Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2015 Earnings Call. This call is being recorded. I would now like to turn the call over to Kelly Whitley, Vice President, Investor Relations. Please go ahead..

Thank you, Lisa. Good afternoon, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer; and John Eckart, Executive Vice President and Chief Financial Officer.

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.

John will begin by providing a view of third quarter 2015 financial results and then Roger will 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 discussions of risk factors, see Murphy's 2014 Annual Report on Form K (sic) [Form 10-K] (1:23) 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 John for his comments..

Thank you, Kelly, and good afternoon to everyone. Murphy Oil's consolidated results in the third quarter of 2015 were a loss of $1.6 billion, which equates to $9.26 per diluted share, that's compared to a profit of $246 million or $1.37 per diluted share a year ago.

The third quarter 2015 results included non-cash property impairments of $2.3 billion, which after tax has amounted to $1.54 billion charge. These impairments were attributable to significant declines in future periods oil prices, which fell by as much as $15 per barrel at quarter end compared to three months earlier.

The impairments were not related to reductions in the company's reported reserves. Adjusted earnings, which adjust our GAAP numbers for various items that affect comparability of earnings between periods, was a loss of $124 million in the third quarter of 2015, down from a profit of $205 million a year ago.

This decline in adjusted earnings was primarily attributable to lower oil and natural gas sales prices in the current year. Our schedule of adjusted earnings is included as part of our earnings release and the amounts in this schedule are reported on an after-tax basis.

Company's average realized price for its crude oil production fell more than $43 per barrel in the third quarter compared to the prior year. This amounted to a 48% drop between periods in oil prices.

Natural gas prices also were weaker in the third quarter 2015 compared to the prior year, with average North American gas price realizations dropping $1.21 per Mcf or a decline of 33%. Realized natural gas prices offshore Sarawak also fell by 27%.

Sales prices continued to be soft in October, and therefore revenues continued to be under pressure, as quarter four 2015 prices remained significantly below prices a year ago. The company continues to address its cost structure by aggressively reducing both operating and administrative cost.

By year-end 2015, we anticipate a 23% reduction in staffing levels compared to a year earlier. At September 30, 2015, Murphy's long-term debt amounted to approximately $3.3 billion, 35.6% of total capital employed, while net debt amounted to just over 25% at the end of the third quarter.

At this time, I'll turn the call over to Roger for his comments..

Thank you, John. Looking back, a solid operational third quarter following highlights stand out. Our company remains in a favorable financial position with a healthy balance sheet, it's flexible, take advantage of opportunities that arise both in onshore and offshore.

With major pullback in oil prices, we've been able to maintain our net-debt-to-EBITDA ratio at less than 1.5. Subsequent to the third quarter, we hedge for 2016 and currently have 20,000 barrels per day in WTI contracts at an average price of $52 per barrel.

On the cost side, we continue to make significant improvements in reducing both operating and G&A expenses on a year-to-year basis. We continue to review our portfolio as we still have many levers remain to reposition the company going forward. We're currently reviewing the value of various midstream assets in North America.

We're enthusiastic about the new area that we recently formed into offshore Vietnam. We expanded our Vietnam footprint with the new block and a highly prospective, oil prone; Cuu Long Basin. Our partnership group was successful in testing our first well, and we are working to increase acreage in this prolific area.

In the Gulf of Mexico, we drilled the Dalmatian South #2. We like what we see here as it has commercial hydrocarbons in two separate zones. Currently the well is being completed with first production expected early next year. In Malaysia, we achieved record average daily gross production for Sarawak gas at 291 million per day.

In addition, we drilled the Merapuh 5 and Marakas wells with positive results and process of evaluating both. In our onshore business, the Eagle Ford Shale continues to outperform expectations, where we delivered 33 new wells online in the third quarter, plus the Montney production continues to be above plan.

Our third quarter production is just over 207,500 barrels equivalents per day. We're increasing our 2015 annual production guidance to a range of 205,000 barrel equivalents per day to 209,000 barrel equivalents per day.

Over the course of the year, we've increased the midpoint of our production guidance from 201,000 barrels equivalents to-date (6:43) to 207,000 barrels equivalents per day, almost 3% increase. In operations, we're pleased with the ongoing efforts we're making on cost reductions.

Our lease operating expenses for the third quarter 2015, excluding Syncrude, is $8.09 per boe, showing a reduction of 23% from the third quarter of 2014. More importantly, we are posting a 45% reduction from full year 2013 on LOE. In Eagle Ford Shale, our third quarter operating expenses are just over $8 per boe.

This represents over $2 reduction from the second quarter of this year. On a cash margin basis, we are just over $19 per barrel equivalent in third quarter and are $20.28 per boe for nine months ended. This compares very favorably to our peers and has been a staple for Murphy for a long time due to our oil-weighted diverse portfolio.

In production, the positive production in Brent (7:40) to 7,500 barrel equivalents a day for the quarter is attributed to Sarawak oil and natural gas sales performing better, above planned performance on base decline, the Eagle Ford Shale, new well volumes exceeding plan due to EUR increases and completion performance and higher natural gas production from Montney.

Looking ahead to the fourth quarter, production guidance is estimated to be 199,000 barrel equivalents per day.

Our third quarter actual production is higher than our fourth quarter guidance due to higher risk SK natural gas nominations and planned downtime, natural well decline in the Gulf of Mexico and significant reduction in the number of completed wells in Eagle Ford Shale.

More importantly, we are maintaining our 2015 CapEx of $2.3 billion, some 32% below last year's level when taking into account the sell-down in Malaysia. In Western Canada, our natural gas production in the Montney in the third quarter 2015 was over 194 million per day.

We've been successful in implementing fracture techniques from our Eagle Ford Shale work to the Montney and our new completion design with increased sand (8:47) concentrations continue to confirm our 8-11 BCF EURs. Also, we continue to have positive results on our refract pilot (8:56) that is under way in some older, tougher wells.

In Eagle Ford Shale, we're especially pleased with our results for the third quarter for production average over 63,000 barrels equivalent per day. We brought 33 new wells online in the third quarter, and we're planning to deliver 20 wells in the fourth quarter for a total of 136 wells this year. A program has been frontloaded as prior disclosed.

Production for 2015 full year outlook is now expected to exceed 61,000 barrel equivalents a day, which is 8% above 2014 production. We continue adding to our total remaining resource into play by downspacing wells, drilling longer laterals and optimizing completions to name a few.

We now estimate that our total remaining resource has grown to over 800 million barrels and this growth even takes into account the total review (9:51) of our resources from a price perspective. We successfully drilled our first Austin Chalk well in Collins County, and we're hopeful.

Hopefully, we'll be moving this play concept westward to our Catarina area. This would add a third horizon to our upper and lower Eagle Ford Shale locations. We drilled the first of three well appraisal pilot and are currently analyzing core and logs to better understand the reservoir properties.

Our Karnes Austin Chalk appraisal well has a very successful flow rate of 1,500 barrel oil equivalent per day. We look forward to continuing to test the Austin Chalk play in 2016. In Malaysia, we achieved record average daily gas production in Sarawak of 291 MMcf a day.

We successfully drilled too shallow water Sarawak oil prospects, the Merapuh 5 and Marakas wells had positive results, where we're evaluating development options. These wells are in the Block SK314A area adjacent to our successful Sarawak oil and gas developments.

The Murphy operated Paus-Kelasa well failed to encounter commercial quantities of hydrocarbon and was expensed as dry hole in the quarter. Offshore Vietnam, we signed the farm-in agreement in the shallow-water 15-105 Block and the prolific oil prone Vietnam Cuu Long Basin. Two discoveries have been made in the block.

Murphy participated in the drilling and testing of the LDV-4X well, which successfully tested two prospective zones. We're also working with PetroVietnam to advance our footprint in the Cuu Long.

This new block entry was made possible by our long-term relationship with our partner and our significant position and successful operator in both deepwater and shallow water, Malaysia (11:36). In the Gulf of Mexico, production for the quarter was over 27,200 barrel equivalents per day at 71% liquids.

We spud the Dalmatian South #2 well during the quarter. We're now completing the wells we found commercial hydrocarbons with over 98 feet of (11:52) zones, and we expect first production early next year.

Field development work on the non-operated Kodiak project continues, where the first of two wells have been drilled and completed to plan and modification of topside facilities and subsea execution is under way.

We're currently progressing the sidetrack of our Thunder Bird well to plan and all of our current Gulf of Mexico projects can withstand lower for longer prices.

Looking at the drilling program for the fourth quarter 2015 in the Gulf, the non-operated Solomon well, which is currently projected to reach total depth sometime in the fourth quarter, has been included in our dry hole exposure for the fourth quarter.

We planned to finish off the year with an oil exploration well, Senyum, located in Block H, Malaysia. That's a non-operated well to appraise our oil linked gas discoveries in Brunei. At this time, we have two deepwater rigs under contract at Murphy. These contracts expire in 2016, one in February and the other in November.

With continued low commodity prices we're experiencing an expected reduction in our 2016 CapEx program and uncertainty about whether working interest partners will agree to participate in drilling programs, we're considering all options. Our current contractual commitments to the end of the term for both rigs equals $277 million.

In financials, Murphy has been able to maintain our investment grade BBB bond rating, maintained our dividend policy through the year with current yield of 5%. We have $1 billion available under our current revolver. We have over $1.2 billion of cash abroad with marketable securities. And we achieved a net-debt-to-EBITDA of less than 1.5.

Production for the fourth quarter is estimated to be 199,000 barrel equivalents a day. Again, we've increased our full-year production guidance at the range of 205,000 to 209,000 equivalent per day. Capital expenditures remain unchanged from previous guidance, and are currently forecast to be $2.3 billion.

To close in my comments today, I would like to leave with a few points. Murphy continues to have financial flexibility and strength. We've greatly lowered operating and G&A expenses over the course of the year, and cost reductions remain a priority.

Our entry into the Eagle Ford Shale has been extremely successful addition to Murphy over the past few years, and we've built an excellent high-performing team, now producing around 30% of our total volumes in just over four years.

We, like most peers, continue to see efficiencies in cost reductions in drilling and completion activities across all of our operating areas. Our Gulf of Mexico projects generate sound economics at current prices.

And over the quarter, we have participated in many positive well results from the Gulf of Mexico to shallow water Malaysia and to Vietnam, and a very high rate well test in the Austin Chalk area of Eagle Ford Shale. We continue to execute on all cylinders in a tough commodity environment. And like to now open it up, the phone, for your questions.

So, thank you..

Thank you. And we'll take our first question from Leo Mariani with RBC Capital Markets..

Hello, Leo..

Hey, guys (15:17). How are you doing here? Just a question for you. Philosophically I know, earlier in the year, you guys talked about moving away from some of the exploration activity. I guess you guys announcing that you're farming in to a block in Vietnam here is sort of a new area.

I guess, is this not really seen as sort of exploration? It sounds like there's some existing discoveries, or do you guys just see this as lower risk exploration?.

I think we see it as a little bit of both, Leo. We have had a pause in our exploration. When I say that, it's primarily related to the big $100 million-plus big wells in the Gulf of Mexico; they're very expensive at very high day rates. But we're not opposed to entry into lower risk opportunities.

It was clear to us that the block did have prior discovery zone. I mean, we entered into the block and participated in delineation of all the (16:08) discoveries. That delineation is going very, very well. We're very excited about it.

We're talking about, when we have – you have two types of wells in the world; the big Gulf of Mexico, West Africa new entry type wells, and you have lower risk opportunities in a place like Vietnam, where you can drill a well for $15 million and have a 50 million barrel to 100 million barrel type prospect.

So on an F basis of an F&D perspective, that's a very positive thing. And this is about our strategy. This is about our company. We do work internationally. We are a big major player in Malaysia. We have a strong relationship and a very strong reputation in Southeast Asia.

Our expertise in shallow water development there, and across other acreage in Vietnam is the reason we were able to get into this block.

And it's very favorable, but I do not consider it to be (17:01) place somewhere, it's very similar geology, what we're used to, very similar areas of operation, very similar cost, very similar well design, and a place where we work nearby, and something we're focused on in that area.

But I consider it not a new big wild entry into far off place yet (17:18)..

Okay.

Can you give us a little more color about this exploration well you're drilling in Malaysia towards the end of the year? And you also mentioned another well in Brunei, which I guess is non-op, can you give us a little more color around those?.

Yeah, we have commitment wells in our business. We do not have commitments usually in the Gulf, as you would anticipate. So we've had these in. These are again, lower cost wells. The well in Block H has moved up in our schedule from what we thought prior.

It's a big world out there on rig contracts, and this is an opportunity for us to be subsidized and drill a very low-cost well in that part of the world. So, if you're in the game for a long time, you're on both sides of the rig equation.

I've been in – at that business a long time and we have an opportunity to drill the well cheaper due to that, and it's a very nice well to drill. It's probably a 60 million barrel mean type project near the Conoco-operated Kebabangan area of Block H.

It would be different from the Block H wells we drilled in the past from an exploration basis, and totally different from our shallow flat spot gas amplitudes in which we've had enormous success. So we're going to drill that well. It's probably be 18 million to 20 million (18:26) net to Murphy.

It's disclosed in our costs here in Kereta (18:33), where we've been a non-operated smaller partner off Brunei. We've had several successes there in a row. This is a continuation towards that commerciality of flowing LNG into Brunei.

We do have the right type of partners there, meaning people that are across the value chain of LNG, and I consider it also to be a lower risk, lower cost opportunity, which is what we're looking for, not the big rank expensive wells at this particular time..

Okay, that's helpful, and I guess you guys also mentioned that you had two recent successes at Sarawak on the oil side..

Yeah..

I don't know if I can pronounce the two names of these wells. They both begin with an M. Could you give us a little bit more just color around there? I guess it sounds like you're still appraising them. Would these be wells that potential could come online in the near future like 2016.

What else can you tell us about those?.

Well, it's called Merapuh and Marakas. If you live over there five years or six years, you can say it really easily, Leo, like me. So, they're both nearby structures, near two very nice fields.

Merapuh is a major part of our gas project in SK Gas; and the Marakas well is a western feature to the west of our south axis platform; that does it very, very well. Marakas is a deeper section. I mean higher pressure, deeper section that was successful and we have to take those pressures and see how we're going to delineate that with the platform.

It is not a 2016 event. This would be out in 2017-2018 time, and it will depend on capital allocation next year as we go through – what you can imagine a difficult budget cycle.

The Merapuh well found extensions of some prior gas that we produced today in Merapuh and another structure – so we proved downdip gas there and some updip oil opportunities; both of them were 10 million barrel type thing. We probably drilled both wells for less than 20-something million dollars. It's going to fit in well with our nearby development.

Some are working on it, and they're successful..

Okay, that's helpful. I guess, you sort of went through the math in terms of saying that your fourth quarter production was going to be a little bit lower than 3Q..

Yeah..

I know you had some maintenance in the third quarter. Just to be clear – expecting some incremental maintenance in fourth quarter or is this more of just sort of risking and the fact that you're saying your nominations for your SK Gas are likely to be lower.

Could you just maybe explain that a little better?.

Well, SK Gas is a place (21:08) so much we've had a very, very good year. It's a place where we planned on being 250 million (21:14) a day and we got up close to 300 million (21:17) a day this quarter. It's a record quarter for us. It is a situation with many, many fields fiddling into a very large (21:27) incredible LNG facility.

So there's ups and downs of nomination. We're known as a swing producer there and a very reliable swing producer with very high uptime (21:36). Again, it facilitates our strong relationship with Petronas.

But things come and go there as to impurities of other fuel such as nitrogen, H2S, and the management that makes (21:47) hard to predict the guidance for that field. It's one of the issues around our company. We have very high cash flow per barrel metrics, but with that becomes just not as simple as an onshore situation, Leo.

So, we have to risk what our nominations will be there. We do have some downtime at that facility operated by Petronas that we've been notified of in November, December.

Also the same situation with our gas, associated gas that comes off TK (22:15), and we have some downtime in the Gulf at Front Runner, and then we have to repair some things and we have some decline in some of our wells in the Gulf because we're not really adding any wells there until early in 2016, and this year – and this quarter was a very good quarter for us and all those combined into that..

We'll take our next question from Peter Kissel with Howard Weil..

Hi. Good afternoon, guys, and thanks for taking my questions. Maybe just going back to Vietnam here to start with.

Roger, can you give us a projected spend rate over the next couple of years for that asset?.

There is an extension involved with the block and we're just on the tail end. This well happened in September, Pete, and we're working with them on that. It's possible we could have an exploration well there. This is a pretty complex commerciality field development plan process at PetroVietnam. We're used to that working with Petronas in Malaysia.

We're talking about probably spend on that in the 2017, 2018 range, and not next year, very aggressive (23:22) there in my view, but we're very excited about this field here..

Got you. Okay. And then, Roger, I know you've been pretty actively looking at a lot of different M&A potential this year.

Does the decision to go into Vietnam a bit more aggressively change your stats a little bit, or are you still pretty actively looking for other assets elsewhere?.

Oh no, it has nothing to do with that. I'm not at liberty today to talk about the cost, but it's a $2 type finding cost number, and F&D number on this project of about 14 to 15 (23:55), that's pretty good. It's not incredible CapEx for us.

We have a lot of cash, if you will, in Malaysia, through our subsidiary arrangements of moving money in that situation. This has nothing to do with our incredible focus on both offshore and onshore opportunities today, but we want to have value.

We want to have return for our shareholders, and we're constantly working three or four of them with a full team of people and we'll continue to do so..

Got you. Okay. Thanks, Roger. Maybe one quick question for John, too. With regards to cost, you've had a very successful year of lowering your costs.

And just wondering how much more is there to go from here both on the OpEx side and the CapEx side? Is it in the 5% to 10% range that's still likely, or something a bit bigger or less than that maybe?.

It's Roger, I was preparing for that one, Pete. I thought (24:46) with somebody else, but glad you called in today. You know you have to look at – first off, you can't look at Murphy quarterly on LOE. We've made big change from year-to-year, because we have offshore operations and subsea maintenance. We don't have just one singular place where we work.

And I think the real thing as you know, we're looking at $9.65 this year without Syncrude and probably getting out into very close to $9. I don't believe we can keep the trajectory of taking it to $7 right now.

But our big growth in Eagle Ford is going to be looking at a $8.50, continue trending down and for all of next year, that's a big move from the last two years, three years. Now with that said, I'm very proud of getting to these levels.

We have an organization incredibly focused on lowering these costs, but we can't go on forever to $7 (25:38) Pete, here in our business with an offshore business and an onshore business. We're very happy about where it's headed, and on a year-to-year basis I think it's quite possible (25:47)..

Okay. Great. Thanks, Roger, and congrats on a good quarter..

Well, thank you, Pete..

We'll take our next question from Roger Read with Wells Fargo..

Hi, good afternoon..

Hi, Roger.

How are you doing?.

I'm well. I hope you are doing the same.

Hopefully, that Blackberry is not causing you the trouble this year it did last year, Roger?.

Roger, you've got to get off that story..

I always thought it was a good one, because I know exactly how it feels..

I moved on to an iPhone. I'm going crazy with technology..

All right, all right. Well, it's a different tone anyway. Hey, kind of following up on the M&A question before.

I know you don't want to get into the specifics of the property, but what are you seeing in terms of cost bid-ask spreads? Has there been an increase in the properties that are available to look at in terms of data rooms, that sort of thing?.

There's just everything of the above there. You have some public situations. You have private equity situations. You probably have a vision of more of return of their multiple than probably be able (26:49) to offer the returns we would like. The Midland area is very, very frothy. Delaware getting a little better I'd say.

Offshore opportunities in the Gulf are the key ones for value adds. And we're expanding a little bit across North America to make sure we've touched every place for value, and not necessarily focused – I think we're not quite as singularly focused as we were before.

And like I said to Pete here, I mean, we have a certain criteria we're looking for and we execute on that and keeps on going. And when we decide we can't make a return, we have a process of looking at the NAV or the rate of return of investment, Roger, on strip. And a price recovery deck that we have. We have four price decks here at Murphy.

And when we feel we can't get to the strip or some level of return, I would like (27:45) then we move to another, and we will continue that process and (27:52)..

Sure.

And in terms of the return you would be looking for on one of these acquisitions, to the extent you can share with us, what would be the hurdle rate for something like a meaningful transaction?.

I'm really not going to probably say that, Roger. You anticipate some level of return on a price recovery deck that would have to be far in excess of cost of capital.

And the reason you can't just say exactly what it is because it's more complicated and that depends on the reserves that would be – what are those price for those barrels, do they have flow in (28:28) production that you could have some level of CapEx without earning your capitalization of the company, and just a list of issues that would have different types of terms (28:40) for different types of things..

Okay. And then just my last question.

In terms of the cash that's overseas that you could repatriate, can you remind us what the potential tax leakage on that would be?.

Okay. The tax leakage on that is not that great. We have foreign (28:57) tax credits that would offset almost all of it. If we bring money home from Canada, if we do that, there's obviously a 5% withholding tax associated with that you can't get out of. It is a creditable tax against the U.S. taxes owed.

But you'd likely be out that 5% at a minimum and really there's not that much leakage otherwise at the present time..

Okay, great. Thank you..

Thank you, Roger..

We'll take our next question from Edward Westlake with Credit Suisse..

Hi, Ed..

Good afternoon. So, congrats on the operational performance. I mean, I guess the key focus is the cash flow outspend. I mean, you've got a balance sheet, but obviously, prices are low. People will worry about it. So, you've got a CapEx for this year of $2.3 billion. You've talked about potentially dropping rigs.

Maybe walk through what are the big deltas that you see from this year to next year, I appreciate you may not want to give a specific number, but what should we be thinking about?.

Yeah. Ed, I'm probably not going to be the leader in that and I had a bet around (30:00) different ways people would ask that question. Obviously, we at Murphy kind of – when you're looking at $45 WTI deck and of course you've got to take that across all your netbacks and natural gas deck appropriate that (30:15), et cetera.

We're looking at cutting CapEx significantly. I don't think that will be a surprise. Then we have to look at that CapEx as to what will happen with production. We have been working through a lot of that issue recently, a long range plan determining where we wanted to allocate capital.

Then we get through our quarter issue here to close out you guys and it's our next focus and we as usual approve our budget in December. But it'd be significantly reduced. And when we do do that, we'll look at it and do it. We have several factors there, dividend policy we'd like to maintain, what will happen to production and we can.

I do feel that we are in a – we're not saying flexible (31:05) in these highlights, et cetera. We do have flexibility. We have liquidity and ability to handle $40 world in 2016 and $45 in 2017 and make our commitments and our dividend. And that includes projections we might (31:23) would have on production that we probably aren't sharing here today.

So, I feel our liquidity situations and the levers we have there are adequate to handle this, and we're taking that to a real high level of review at this time..

Okay.

And so then coming to the rig comment you made in the opening remarks, you said one rolls off, I think, in spring and one in November and considering all options, how much are you spending if you say drop both those rigs, what would the impact be of that?.

The way it works in an offshore (32:01) environment today, it's just around $1 million a day to run a rig, and if you have – the day rate of the rig is 550 to 590 (32:09), and you stop paying the other half and you have about the same level of CapEx.

That is a very poor return, and one I'm not happy with, but I do not want to take this as an opportunity to drill 100% rank (32:23) wells and add more CapEx, probably I'm not interested in situations where our carry (32:30) partners and help them and loan money to them, I'm not interested in that.

The deepwater world is one that doesn't go well at 100% and we take all that to account, you just (32:43) start looking at the options and there are many and we have different types of people who want to take non-working interest in some of our partners.

We have people that offer us some level of a wildcat exposure at an appropriate level of risk for us because the rate of return of paying it off is not good, Ed, as you would know.

So, we are looking at all those things, but when I mention the liquidity in the $40 and $45 world and our dividend and where – what happens with our net debt and our debt to cap, all these factors take into account the worst case scenario in that situation, and I'm not concerned about liquidity on that front..

Okay. And then final question, again, you may not be able to answer.

Midstream monetization in Canada and other infrastructure, any sort of rough ballparks, I guess, in terms of how much cap do you think you could raise?.

No, but I consider it significant, and we continue to work that. We're not a company that throws around MLPs, and that does all this wild stuff all the time. So we're taking a measured approach at that. We're very pleased with how that's going, and it would be a termination of the terms and conditions and how that's going to go.

And it too would be another liquidity situation that I have not factored in in the discussion I just had with you a few minutes ago..

Do you have the book value of what you've invested overall in infrastructure?.

Really just going to – the way we're going to do BD on this, Ed, is when we have it, we're going to announce it, and setting up these visions of what would be a good EBITDA multiple's really not where I'm headed today..

Okay. Thanks so much (34:26) seeing in summer..

Appreciate it..

We'll take our next question from Paul Cheng with Barclays..

Hi, Paul..

Hey, guys. Good afternoon. Roger, I know that you're not going to talk about the budget yet, but can....

Why are you asking, Paul?.

No, I'm actually not asking the budget, I'm asking that, what is the CapEx that you need today, based on the current market condition? If you want to hold the production flat and have the same similar asset mix? What the CapEx look like?.

Asset mix isn't going to change overnight. It's pretty similar, sales very good, everything is going well. I don't have that number exactly calculated, because we're in the middle of our budget, Paul. I would anticipate like $1.3 billion (35:11) or so..

$1.3 billion (35:13)?.

Yeah..

Okay.

And that's, I presume that is including some form of exploration expense, or that exploration will be on top?.

We're trying to have exploration limited in the $45 world, with (35:27) certainty, Paul. As I mentioned earlier, there are commitments that you have when you're in this business, international oil and gas business, you do have some level of commitment.

And we're working to be on a committed basis only, and it would be much less spend than in 2014, and we're working on that right now..

And on the Midstream monetization, or strategic review, from a timeline standpoint at this point, is it going to be driven primarily by the market condition, or that is based on that how quickly that you guys will go through all the analysis?.

Oh, it's complicated. We have to have the appropriate person that we want to do business with. They have to be happy with us. We have to get those terms and conditions. We then have to have it approved by our board and really, I'm not in a real bond to do it.

I don't have to do it, and I'm not probably at liberty to discuss a timeline, because I'm not in a hard spot..

I see.

Final one, in Eagle Ford, if we're looking at your best sweet spot, based on your current drilling program, how long the prospect inventory can last?.

Till I'm well and gone, Paul, probably at 100 wells a year for 10 year to 12 years or more – no – more than that, 20 years..

Okay. Thank you..

All right. Thanks Paul..

Our next question comes from Guy Baber with Simmons..

Guy, how you're doing?.

I'm good. Good afternoon, everybody. Roger, I wanted to talk a little bit more about the performance, which was impressive, and apologies if I missed this.

But do you have an estimate of the split between the cost gains and efficiencies you have achieved, which you might be classified as – or which you might classify as more cyclical versus what is more structural, and the result of what Murphy specifically is doing differently?.

Any G&A here is not continuing event. So, Guy, it's significant though, 23% of staffing by the end of the year is very significant – that would be both employees and contractors and all types of changes around the company.

And we would not want to see that continue for another 23% next year, but we have not got the full estimate of that in this – this type of actions are recent to Murphy, very recent over the last few days, and we need to put that into our budget process, but we are looking at – we do know that, last year, we spent $365 million on G&A, and this year we're in our internal work around $300 million, and then we will have – and we do know that the staffing thing is in the mid-$20 million per year, and we'll have a full help to that to our side, and we are very much significantly down from a couple of years back.

On the operating expenses, I mean, we – like I said earlier in the call, we made incredible improvements there.

It's driven by a lot of great performance in Eagle Ford Shale, a lot of work in the offshore as well, a lot of sharing of helicopter, sharing – when things go difficult, many people work together to lower the cost, and I'm very pleased with how my staff has performed in that. It's incredible job for us.

We're incredibly focused on it, because we're trying to get to cash flow CapEx parity at $45 and every penny counts, and that's how we're working it. And when you work on things with the good people I have, you start seeing the results..

That's helpful. Thanks, Roger. And then, focusing in on the Eagle Ford, you're now running three rigs there, which is down from four last quarter, and the production was better than we had expected this quarter.

In a $45 to $50 world, can you just talk about the priorities which will govern the way you think about managing activity levels there over the next year? Is it about the returns of that specific play, or is it more about the portfolio and cash flow CapEx parity and you having flexibility there? So just, your high level thoughts there would be appreciated? And then, if you could help us out with what the implicit effect might be on the production profile, that would help as well?.

Well, we have a lot of flexibility around production. Like I said earlier, I don't have that finalized, and I'm probably not going to be the leader in that pack, with the year we've had here. We have some really good wells to drill in Eagle Ford Shale.

A $45 based pricing, we have – a lot of wells are 30% rate of return and I think that's pretty decent. And if oil prices are $50, we have many wells to drill at 45% rate of return, incremental going forward. I don't like to do – work that way, but this does help when you're allocating capital.

So we're going to be allocating capital on the best areas that deliver the best return on that incrementally.

We also do not need a lot of rigs to protect our acreage, that's different than it was in times past, and we'll have to do some big capital allocation study and we're in the middle of doing so about protecting acreage versus protecting efficiency.

The reason we have such efficient operations, we've been running same numbers of rigs for a while now with the same teams. So if you go forward to zero, to two, to three, to four, to zero, it's hard to do that. So it's almost a situation of allocating capital to remain some level of efficiency.

And we're really trying to get to preparing for lower prices here from a cash flow CapEx parity over other things, because we cannot continue to outspend our CapEx and wake up one day and be – with the credit of other people, we have very good credit situation today, debt to cap and we don't want to wake up with it like to norm (41:26) and not have done something or looked or attempted to do something to add value to our shareholders.

So, we're in the middle of all that, and obviously, the Eagle Ford Shale will be a key part of capital allocation, I think today $2.3 billion CapEx of 14 (41:46), our CapEx in Eagle Ford Shale is $855 million, and we're going to be at that percent or more as we could (41:53) CapEx, because this is a very valuable asset for us.

It's going extremely well on everything you can imagine that's known in shale business. We at Murphy have that ability as well, and we're proud about it, and it too has incredible flexibility, because if things were to get worse, you can reduce it, you can add to it.

You won't have the efficiency when you're jumping at (42:15), but it's a very nice thing to have a company of our size, and I think very, very material..

Thanks, Roger..

Thank you..

Our next question comes from Ryan Todd with Deutsche Bank..

Hey, Ryan, how you're doing, man?.

Great, thanks.

How you're doing Roger?.

All right..

Maybe, one quick follow-up on, I mean, the Eagle Ford performance was impressive on the quarter with – actually growing sequentially with fewer completions, can you talk a little bit about what, I mean, you referenced better productivity of the wells, high EURs, some enhanced completions, can you talk a little bit about some of the things that you're seeing in the wells, how (42:58) sustainable you think that is, and what sort of confidence that gives you, I guess, in terms of maintaining better production levels in 2016?.

Well, we've recently done a big study and Eagle Ford Shale started over with all of our PUDs, all of our proven locations and our reserves. We're doing very, very well in reserve (43:18). I'm very pleased at that trajectory where I think this year will end.

We had some gas acreage in Eagle Ford Shale that we've taken off the table, of course, and we've made some big changes in EUR. As I walk through a couple of the fields, I think (43:35) significant Karnes where – is a prolific area there as you know, Ryan. We used to think that an 80-acre spacing well would have about a 660,000 EUR.

And now we pull (43:49) that 660,000 to 600,000, but we're at 40-acre spacing. So that's an enormous change in resource, both in upper and lower Eagle Ford Shale. Tilden would be the same way. We're doing a lot of work with longer laterals there, bigger sand.

Today, from back to 2012, we're talking about the same situation, where EURs continue to improve there probably not as much as Karnes, but the big improvement for us is Catarina, which is our most western area, which is a very organized – we went ground floor here (44:23), so we don't have the perfect giant sections of land, but Catarina is very, very organized from that perspective.

And we have improved the EURs there. We have three big ranches there. One area from 210,000 a day – 210,000 equivalent EUR to over 400,000, with less spacing. And then another area from 210,000 to over 550,000 again with less spacing. And another area from 210,000 to 600,000.

So this is enormous change in an area that we drill wells for only four-point-something million dollars. This is a big deal and that we may not have it all modeled in yet, but our trajectory and where we're headed there, it's very, very positive in my view..

Thanks. That was very helpful.

And then maybe if I could – one more I guess from a little bit of a strategy point of view, I mean, I think one of the concerns that people have had with Murphy has been maybe depth of resource and what would drive in an oil price recovery, what are going to be the assets or the resource that's going to drive when the growth, again, when you return the planned offense as opposed to defense? And I guess as you think about that and you think about the resource that you have in your portfolio, what would you see? The Eagle Ford is clearly going to be one, but what would you see as kind of resource that will be the kind of the driver to the next leg of growth for the company? And I guess in that context – and how does M&A fit in terms of either complementing or competing with that resource for kind of the next cycle of Murphy?.

Well, I mean, clearly, when we do M&A, we look at how it affects our long range plans and how it increase our income, our cash flow per share and every type of metric including R-over-P (46:23), I think, when you're speaking in a nice way about the R-over-P (46:26), it's very frustrating to me the R-over-P (46:29) here has been eight for a long time.

It's going to be eight for a long time, but from an oil-weighted perspective, we're probably fifth place out of 16 peers. If you take the R-over-P (46:39) that's really through the oil. We're very limited. We'll probably be the lowest NGL R-over-P (46:44) player, and very, very low on natural gas.

That's quite frustrating to me, because this view (46:50) that we don't have any locations.

If this year in Eagle Ford Shale, we're going to drill, operate about 136 wells down there, bring online 136 wells, then we probably have 3,000 locations to go, so this idea that Eagle Ford Shale is not material for a company that has 756 million barrels approved and now a resource size remaining of 800 million barrels, it's mind-boggling to me and it's very well-known how this project models.

But outside of that, I mean, places like Vietnam, we have focus areas that are very tied around where we want to work. We want to bring that focus tighter, projects like Kodiak, Kodiak, Vietnam, and things from Gulf are available to us, that are not large M&A change your entire capital structure type deals but they're very helpful on adding barrels.

We do have the floating LNG coming online, Malaysia is going very well. I didn't mention, but we took a core there in a well this quarter to continue to confirm our outstanding resource available and we're partnered with a leading LNG player in the world, in Petronas, which is a big deal.

So, small things like Kodiak, big ones like Vietnam, M&A on top of all that, but we do not have a collapsing R-over-P (48:06) in this company. If you take a look at the long range plan of the company, we do not significantly drop ever our R-over-P (48:13). We just don't have the 12, because they don't have a lot of gas to make it 12 (48:17).

So I think it's a misnomer a bid about the resources we have, and we probably need to do a better job of outlining those resources, that's hard to do that. In two years when the oil price collapsed twice. That's not the time to go out, set expectations when you lower CapEx, you had the wrong expectation, it doesn't work well that way.

So, it's hard to get into that vision that you're asking in these incredible volatile oil price times. If you want to maintain balance sheet to do transformational things in the company, you can easily outspend and grow production and end up not having a transformational change, that's very easy, I can just pick up the phone and do that.

So, decided not to do it that way at this time..

That's great. I appreciate your thoughts. And maybe, I mean, I guess it's – I mean it's safe to say to you that there's probably more resources (49:18) than the market gives you credit for. But maybe one last one on that. Is the Gulf of Mexico and there is a lot of – you've had some recent successful wells there.

And as you think over the next couple of years as is the play that I think it's probably a little bit harder for us to model out.

How do you think about production in the Gulf of Mexico over the next couple of years? Have you tie in these wells? Will this effectively hold production flat? Will it drive moderate growth or moderate declines? How should we think about that?.

If we could get partners to participate in our wells that had ability and income do so and cash flow, we could grow production there and that's hard to deal with at this particular time. We have some really nice low risk opportunities there like Medusa, where we placed two wells on line and doing very, very well.

So we have some additional locations there. It will be a matter of an oil price recovery. However, tiebacks like Dalmatian South #2 and various other things, the tiebacks from the Gulf of Mexico are right up there with returns you have in Eagle Ford, if you take full cycle into account, meaning the drilling of the well, the pipeline, et cetera.

These things are very economic. We need a higher oil price, Ryan, to get into facility building big exploration successful things, or where we can enter into a well or enter into the things going forward during this unique pull-back, because we have the balance sheet to be able to do so.

Those need oil to be a little higher, so if you have a higher vision of oil, you can participate into the Gulf and many, many favorable projects today. So, our ability to operate there, work there and long history of being there and have our business – so that way it's very advantageous for us right now.

So we have great Eagle Ford Shale business going and we are executing incredibly well on. You've got to keep in mind, we built this team for years. It's incredible. And we are then able to look at those opportunities.

We have a long-standing deepwater team, where we're not exploring today, but factor is how do we get comfortable in changing staffing to do that again another day when oil prices recover, if we choose to do so.

But there's a lot of opportunities in both, and we're very advantaged to able to look at both of them, and I don't know if many people have that..

Great. Thanks, Roger..

Thank you..

Our next question comes from Pavel Molchanov with Raymond James..

Hey, Pavel..

Hey, guys.

You talked about your entry into Vietnam as an exploration opportunity, are there any components of your exploration portfolio that you are considering not staying in or either divesting or simply exiting in 2016?.

Yes. That's all I'm saying..

Okay. Fair enough.

Let me try it this way, given the diverse scope of your kind of geographic footprint and the different host country relationships, or have you noticed more willingness on the part of governments and NOCs to improve the fiscal terms for you, guys, specifically or if you want to talk about the industry in general?.

I found that in Southeast Asia, Petronas is such a leader there that the physical terms are very similar. We've been very successful. We directly (52:47) understand it. That's going fine. I think that will come. It takes a while for a – I have a lot of experience with NOCs.

It takes a long time for them to have – through their government to change these situations. I think it will greatly improve into next year, probably. So I believe that's coming, and we at Murphy are really trying to focus down on less (53:09) places. And we're doing so, and that's why we will have exits that we will talk about when they're exited.

And so, I think we're doing all the things that you're suggesting by your question that we probably should look at, and we are, and I believe that the NOC help will come, but it's not exactly documented today. But clearly, everyone in the industry has to make a change around everything they're doing when oil prices used to be $100. Today they're $45..

But specifically in Vietnam, were you able to get better terms than you think you would have gotten, let's say, 6 months or 12 months ago?.

No, I doubt so. Like I say, we're sought after there by them, we have incredible relationship with (53:57) relationship. We found the terms to be very similar to shallow water Malaysia. We're very familiar with how they work. I consider them fair. They've been incredibly changed of late. It takes a long time to do a deal like this.

So it takes longer to do it than oil price recovery takes. So, we're very happy about it. It's a block that had success on it. This is not some new entry, ranked wildcatting (54:27) block in the middle of nowhere. This is totally – the op to this one, the bigger oilfields anywhere in onshore, it's discovered in the 1970s by Mobil.

This is a $4 billion to $5 billion type resource. They may come to 300,000 barrels a day in area of Vietnam. This is the key crown jewel of Vietnam, and we're very fortunate to be invited to be in it..

Okay. Appreciate it, guys..

All right..

Our next question comes from Brian Singer with Goldman Sachs..

Thanks. Good afternoon..

Hey, Brian..

Your op costs have seen some wild quarter-to-quarter swings, but as was highlighted here, there was a consistency of strong cost performance here in the third quarter. When we look at the Eagle Ford production cost at $8, the rest of the U.S.

at $8, Canada ex-Syncrude sub-$6, is this the new ceiling and base case where costs come down from here? And if your production declines in places like the Eagle Ford or elsewhere, how would that have an impact on the unit op costs?.

Well, I think in the onshore, we're doing very, very well in that regard, I mean, looking back at 2014, I'm talking about just LOE, Brian, not the taxes and all that. There's different aspect of this, as you know. Last year, around $11.

This year in Eagle Ford Shale looking at $10.20 or so for the year – all year-end because we had some higher costs pull over into the first quarter. And next year we're probably looking at $8 and change; that's really good. I think in Canada, we make incredible OpEx improvements at both Montney and Seal.

Seal, of course, very challenged from a price perspective. And so, the onshore areas I think are good. The ups and downs are in an offshore business, you have to model it, Brian, a little bit to get that value. And so, we've had a good year in offshore, especially in the Gulf, and that it will come.

You have subsea inspections, intelligent piggings of pipelines, and it makes the quarter a little bit jumpy in that regard. But overall as a company, I think that we're, like I said earlier in the call, we're looking at $9.65, it probably is a record here, of LOE, and we're looking at right around $9 for all of here of (56:45) all of our business.

We've probably done a lot of that heavy lifting, and that would account for – if there are levels of production dropping of whatever due to capital, which will be the range over the next few months, that can handle that, in my opinion..

That's great. And shifting to the Eagle Ford, just another follow-up on one of the earlier questions.

You have this push versus pull of budget versus deficiencies, is there a minimum level of completion cadence that you see as needed per quarter in the Eagle Ford to retain a minimum level of efficiencies, and should we expect that production to decline?.

Well, I mean, obviously, if you go – to answer your question, I say you need to keep two rigs running, and if you have two drill wells and that probably lead to one frac spread and you can always pick up other ones as needed. We're not a company with a lot of drilled uncompleted wells. I think we only have 30.

I'm not a guy to build up hundreds of those things. I don't believe that's appropriate thing to do with capital.

And so, with that said, obviously, we'd have production decline, Brian, if you go from 8 to 6 to 4 to 2, there would have to be a decline, which is, as your firm speaks about often, which should lead to – which I guess your firm doesn't believe – but it would lead to an oil price recovery, I would hope..

Great. Thank you..

Thanks..

And our final question comes from Paul Sankey with Wolfe Research..

Hi, Paul..

Hi, Roger.

Can you hear me?.

Yes. Sure haven't heard from you in a while..

Yeah, I hope you're well. Roger, just had a couple of – you've been through several permutations of the options and you've talked about transformational, deeper resource inventory than you get credit for, et cetera, et cetera, I just had two questions for you.

One was to be considered a merger of equals with someone else is a transformational deal; and the second is, would there be the potential for you just to take Murphy private? Thanks..

Well, those are unusual complex questions, Paul. That the complete board of directors of Murphy, in which I am one. We have not, in my view, if you look at my desk today piled with papers. I do not have a merger document there, nor a going private document. So, my focus is to – it's real hard, with these big price collapses.

We had a very difficult budget last year, coming from a tough one again this year, make him stand about trying to get to cash flow CapEx parity and going from there is my focus today, over mergers in that effect, that will always be available to any publicly traded company of course, but it's not the focus I have today, to be honest..

I understand. And so, the clear frustration you've got is that the share price is low and the multiple is so low.

How do we change that?.

What would change that? By continuing to – when you're in – when you get back to cash flow-CapEx parity and do that first, and continuing to focus on cost, you can only go so far with that, but we're going keep working on those two matters, and we do have singles and doubles here that we've been hitting..

Yeah..

(1:00:09) I think we're back doing that again. It's pretty big gross type resource we're touching this quarter, Dalmatian, 10 million (1:00:17) each for shallow water well, significant well in Vietnam. And so we've got some things going our way there..

Sure..

And we feel like we're pretty well-positioned. But in my view today, we have to maintain balance sheet that we have. And at some point, I suppose, there will be a time when we try to do M&A and have return for our shareholders, and we feel we're unable to do that anymore, and we could look at other things.

So I feel a lot good about where we are in a pretty poor price environment, and we're working on that is the answer, Paul..

Yeah. Appreciate it, Roger. Thank you very much..

Thank you. And good to hear from you..

And that concludes the question-and-answer session. I'd like to turn the conference back over to Roger Jenkins for any additional or closing remarks..

We appreciate everyone calling in today with some active questions today. I loved been participating with you and I think we did have a good quarter. And we'll be back with you again after the holidays, and we'll go from there and I appreciate it..

Thank you. And that does conclude today's presentation. Thank you for your participation..