Murphy Oil Corp (MUR) 2015 Q3 法說會逐字稿

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 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 taxes, amounted to a $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.

The 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 continue to be soft in October and therefore, revenues continue to be under pressure as quarter four 2015 prices remain significantly below prices a year ago. The Company continues to address its cost structure by aggressively reducing both operating and administrative costs. 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 will turn the call over to Roger for his comments.

Thank you, John. Looking back at a solid operational third quarter, the following highlights stand out. Our Company remains in a favorable financial position with a healthy balance sheet that's flexible to take advantage of opportunities that arise both in onshore and offshore. With the 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 hedged 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 remaining to reposition the Company going forward. We are currently reviewing the value of various midstream assets in North America.

We are enthusiastic about a new area that we recently formed into, offshore Vietnam, which expanded our Vietnam footprint with a new block in 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 are in the 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 Montney production continues to be above plan.

Our third-quarter production is just over 207,500 barrel equivalents per day and we are increasing our 2015 annual production guidance to a range of 205,000 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 a day to 207,000, almost a 3% increase.

In operations, we are pleased with the ongoing efforts we are making on cost reductions. Our lease operating expenses for the third quarter of 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 the Eagle Ford shale, our third-quarter operating expenses of just over $8 per BOE. This represents over a $2 reduction from the second quarter of this year.

On a cash margin basis, we are just over $19 per barrel equivalent in the 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 variance of 7500 barrel equivalents a day for the quarter is attributed to Sarawak oil and natural gas fields performing better, above plan 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 risked 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 the 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 selldown in Malaysia.

In Western Canada, our natural gas production in the Montney in the third quarter of 2015 was over 194 million per day. We've been successful in implementing fracture techniques from our Eagle Ford shale work to the Montney. Our new completion design with increased sand concentrations continues to confirm our 8 to 11 BCF EURs.

Also, we continue to have positive results on our refrac pilot that is underway in some older, tougher wells.

In the Eagle Ford shale, we are especially pleased with our results for the third quarter. Production averaged over 63,000 barrels equivalent per day. We brought 33 new wells online in the third quarter and we are planning to deliver 20 wells in the fourth for a total of 136 wells this year.

The program has been frontloaded as prior disclosed. Production for 2015 full-year outlook is not expected to exceed 61,000 barrel equivalents a day, which is 8% above 2014 production. We continue adding to our total remaining resource in the 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 a total review of our resources from a price perspective.

We successfully drilled our first Austin Chalk well in Karnes County and we are hopeful -- hopefully, we will 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 a three well appraisal pilot and are currently analyzing coring logs to better understand the reservoir properties. Our Karnes Austin Chalk appraisal well has a very successful flow rate of 1500 barrel of 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 million a day. We successfully drilled two shallow water Sarawak oil prospects. The Merapuh-5 and Marakas Wells had positive results where we are evaluating development options. These wells are in the Block SK314A area, adjacent to our successful Sarawak oil and gas development. The Murphy-operated [Paskalasa] well failed to encounter commercial quantities of hydrocarbon and was expensive to dry hole in the quarter.

Offshore Vietnam, we signed a farm-in agreement in the shallow water 15-1/05 block in 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 LBV4X well, which successfully tested two prospective zones. We are 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 as a successful operator in both deepwater and shallow water Malaysia.

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 during the quarter. We are now completing the wells we found commercial hydrocarbons with over 98 feet of pay in two zones and we expect first production early next year.

Field development work on the non-operated Kodiak project continues for the first of two wells have been drilled and completed to plan and modification of topside facilities in subsea execution is underway. We are currently progressing the side track of our Thunderbird 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 of 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 dryhole exposure for the fourth quarter. We plan to finish off the year with an oil exploration well, Senyum, located in Block H Malaysia, plus 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 are experiencing, an expected reduction in our 2016 CapEx program and uncertainty about whether working interest partners will agree to participate in drilling programs, we are considering all options. Our current contractual commitments to the end of term for both rigs equals $277 million.

In financials, Murphy has been able to maintain our investment-grade BBB bond rating, maintain our dividend policy through the year with a 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 have 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 an 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 and cost reductions in drilling and completion activity 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 the Eagle Ford shale. We continue to execute on all cylinders in a tough commodity environment and I would like to now open it up the phone for your questions. Thank you.

Thank you. (Operator Instructions). Leo Mariani, RBC Capital Markets.

Just a question for you. First off, I know, earlier in the year, you guys talked about moving away from some of the exploration activity. I guess you guys are announcing that you are farming into a block in Vietnam here as sort of 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 that are very expensive and have very high day rates. But we are not opposed to entry into lower risk opportunities. It was clear to us that the block did have prior discoveries on them and we entered into the block and participated in the delineation of those discoveries.

That delineation has gone very, very well. We are very excited about it. We are 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 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 and we are able to -- 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 entry in a wild off place somewhere. It's very similar geology what we are used to. Very similar areas of operation, very similar costs, very similar well design in a place where we work nearby. And it's something we are focused on in that area. I consider it not a new big wild entry into a far off place (inaudible).

Okay. Can you give us a little bit 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 bit more color around those?

Yes, we have commitment wells in our business. We do not have commitments usually in the Gulf, as you anticipate, so we've had these and 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 it's an opportunity for us to be subsidized and drill a very low-cost well in that part of the world. So if you are in the game for a long time, you are on both sides of the rig equation.

I've been 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 [Kimobogen] area of Block H. Would be different from the Block H wells we've 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 are going to drill that well. It's probably 18 million to 20 million net to Murphy. It's disclosed in our costs here. In Keratau, 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 are 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. I don't know if I can pronounce the two names of these wells. They both begin with an M. Can you give us a little bit more just color around there? I guess it sounds like you are still appraising them. Would these be wells that potentially 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 for five or six years, you can say it real easily, Leo, like me. So they are 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. It does very, very well.

Marakas is a deeper section -- I mean, a higher pressure deeper section; it was successful. And we have to take those pressures and see how we're going to delineate that with a platform. It is not a 2016 event. This would be out in 2017, 2018 time and would 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 produce today in Merapuh in another structure, so proved downdip gas there and some updip oil opportunities. Both of them were a 10 million barrel type thing. We've probably drilled both wells for less than $20 million. It's going to fit in well with our nearby developments and we are working on it and they are successful.

Okay, that's helpful and 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. I know you had some maintenance in the third quarter. Just to be clear, I was expecting some incremental maintenance in the fourth quarter or is this more just sort of a risking and the fact that you are saying your nominations for your SK gas are likely to be lower? Can you just maybe explain that a little better?

Well, SK gas is the place in which we've had a very, very good year. It's a place where we planned on being 250 million a day and we got up close to 300 million a day this quarter. It's a record quarter for us. It is a situation with many, many fields filling into a very large nine-train incredible LNG facility. So there's ups and downs of nomination. We are known as a swing producer there and a very reliable swing producer with very high uptime. Again, this facilitates our strong relationship with Petronas.

But things come and go there as to impurities of other fields such as nitrogen, H2S and the management of that makes it 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 and December. Also the same situation with our gas, associated gas that comes off of Kikeh and we have some downtime in the Gulf at Frontrunner that we have to repair some things. And we have some decline of some of our wells in the Gulf because they are not really adding any wells there until early in 2016. And this year -- this quarter was a very good quarter for us and all those combine into that.

Peter Kissel, Howard Weil.

Maybe just going back to Vietnam here to start with. Roger, can you give us a projected spend rate over the next couple years for that asset?

There's an extension involved with the block and we are just on the tail end. This well happened in September, Pete, and we are 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 are used to that working with Petronas in Malaysia. We are talking about probably spend on that in the 2017, 2018 range and not next year, very (inaudible) in my view. We are 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 stance a little bit, or are you still pretty actively looking for other assets elsewhere?

Oh, no. It has nothing to do with that. This is a very -- I'm not at liberty today to talk about the costs, but it's a $2 type finding cost number and an F&D number on this project of about 14 to 15. That's pretty good. It's not incredible CapEx for us. We have a lot of cash, if you will, in Malaysia and 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 shareholders and we are constantly working three or four of them with a full team of people and we will continue to do so.

Got you. Okay, thanks, Roger. Maybe one quick question for John too. With regards to costs, you've had a very successful year of lowering your costs. I'm 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 bigger or less than that maybe?

I was preparing for that one, Pete. First off, you can't look at Murphy quarterly on LOE, a big change from year to year because we have offshore operations, subsea maintenance. We don't have just one singular place where we work. And I think the real thing is we are looking at $9.65 this year without syncrude and probably getting that 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, 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 and -- but we can't go on forever to $7 probably, Pete, here in our business, with an offshore business and an onshore business. But very happy about where it's headed and on a year-to-year basis, I think it's quite positive.

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

Roger Read, Wells Fargo.

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 costs, 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 a turn of their multiple than probably that's available to offer the returns we would like. The Midland area is very, very frothy, Delaware getting a little better, I would say.

Offshore opportunities in the Gulf are the key ones for value adds and we are expanding a little bit across North America to make sure we've touched every place for value and not necessarily focused -- I think we are not quite as singularly focused as we were before. And like I said to Pete here, we have a certain criteria we are looking for and we execute on that and keep some 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 the investment, Roger, on the strip and a price recovery deck that we have. We are 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 to see there, then we move to another one and we will continue that process and it may work and it may not.

Sure. And in terms of the return you would be looking for on one of these acquisitions, to the extent you can share it 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 is because it's more complicated than that. It depends on the reserves that would be -- what are those prices for those barrels? Do they have flowing production that you could have some level of CapEx without hurting your capitalization of the Company. And just a list of issues that would have different types of terms 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 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 US taxes owed, but you would 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.

Edward Westlake, Credit Suisse.

So congrats on the operational performance. I guess the key focus is the cash flow outspend. 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. Appreciate you may not want to give a specific number, but what should we be thinking about?

Yes, Ed, I'm probably not going to be the leader in that and I had a bet around here the different ways that people would ask that question. Obviously, we at Murphy kind of -- we are looking at a $45 WTI deck and of course, you've got to take that across all of your netbacks and natural gas deck appropriate to that, etc. And we are 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 and determining where we wanted to allocate capital and 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 would be significantly reduced and when we do do that, we will look at it and do it.

We have several factors there, a dividend policy we would like to maintain. We have what will happen to production and what we can. I do feel that we are -- when I say flexible in these (technical difficulty) highlights, etc. We do have flexibility. We have liquidity, an ability to handle a $40 world in 2016 and $45 in 2017 and make our commitments and our dividend. And that includes projections (inaudible) would have on production that we probably aren't sharing here today. So I feel our liquidity situation and the levers we have there are adequate to handle this and we are 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 that be -- what would the impact be of that?

The way it works in an offshore [water] environment today is it's just around $1 million a day to run a rig. And if you have the day rate of the rig is $550,000 to $590,000 and you stop paying the other half, then you have about the same level of CapEx. That is a very poor return, one I'm not happy with. But I do not want to take this as an opportunity to drill 100% rank wildcat wells and add more CapEx. I probably am not interested in situations where I carry 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 into account and start looking at the options and they are many -- we have different types of people who want to take non-working interest from some of our partners and we have people who 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 mentioned the liquidity in the $40 and $45 world and our dividend and 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 ballpark figures in terms of how much capital you think you could raise?

No, but I consider it significant and we continue to work that. We are not a company that throws around MLPs and that does all this wild stuff all the time. So we are taking a measured approach at that. We are 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 kind of -- the way we are going to do BD on this Ed is when we have (inaudible) announce it and setting up these visions of what would be a good EBITDA multiple is really not where I'm headed today.

Okay. Thanks very much. Look forward to seeing you in December.

Paul Cheng, Barclays.

Roger, I know that you are not going to talk about the budget yet (multiple speakers) what is the CapEx that you need today based on the current market conditions if you want to hold the production flat and have the same similar mix? What does the CapEx look like?

The asset mix isn't going to change overnight. It's pretty similar. The Eagle Ford shale is very good. Everything is going well. I don't have that number exactly calculated because we are in the middle of our budget, Paul, but I would anticipate like 1.3 or so.

1.3?

Yes.

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

We are trying to have exploration limited in the $45 world with certainty, Paul. As I mentioned earlier, there are commitments that you have. When you are in this business, international and gas business, you do have some level of commitment and we are working to be on a committed basis only and it will be much less spend than in 2014 and we are working on that right now.

And on the midstream monetization or strategic review, from a timeline standpoint at this point, you said it's going to be driven primarily by the market conditions or that is based on how quickly that you guys will go forward with the analysis?

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

I see. A final one, in the Eagle Ford, if we are looking at your best sweet spot based on your current drilling program, how long the prospect inventory can last?

Until I am well and gone, Paul. Probably at 100 wells a year for 10, 12 years or more -- no, more than that, 20 years.

Okay. Thank you.

Guy Baber, Simmons.

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 what you might classify as more cyclical versus what is more structural and the result of what Murphy specifically is doing differently?

Any G&A are not continuing events, 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 and these type 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 are in our internal work around $300 million and we do know that the staffing thing is in the mid-$20s million per year and we will have a full help to that to our side. And we are very much significantly down from a couple years back.

On the operating expenses, we, like I said earlier in the call, we've made incredible improvements there. It's driven by a lot of great performance in the Eagle Ford shale, a lot of work in the offshore as well, a lot of sharing of helicopters -- when things go difficult, many people work together to lower the cost. And I'm very pleased at how my staff has performed in that. It's an incredible job for us and we are incredibly focused on it because we are trying to get to cash flow CapEx parity at $45 and every penny counts and that's how we are 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 are now earnings three rigs there, which is down from four last quarter and the production was better than we had expected this quarter. In a $45 world, $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 can 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 the Eagle Ford shale. At $45 base pricing we have a lot of wells that 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 it does help when you are allocating capital. So we are 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 will have to do some big capital allocation study and we are in the middle of doing so about protecting acreage versus protecting efficiency. The reason we have such efficient operations, we've been running the same number 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 are 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 a very good credit situation today debt to cap and we don't want to wake up with it like the norm and not have done something or looked or attempted to do something to add value to our shares, to our shareholders.

So we are 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 for 2014, our CapEx in the Eagle Ford shale is $855 million and we are going to be at that percent or more as we cut CapEx. This is a very valuable asset for us. It's going extremely well on everything you can imagine that's known in the shale business. We at Murphy have that ability as well and are real 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 jump and add, but it's a very nice thing to have at a company of our size and I think very, very material.

Thanks, Roger.

Ryan Todd, Deutsche Bank.

Maybe one quick follow-up. The Eagle Ford performance was impressive on the quarter with actually growing sequentially with fewer completions. Can you talk a little bit about -- you referenced better productivity of the wells, higher EURs, some enhanced completions. Can you talk a little about some of the things that you are seeing in the wells, how 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 in the Eagle Ford shale and started over with all of our PUDs and all of our proven locations and our reserves. We are doing very, very well on the reserve front. I am very pleased at that trajectory of where I think this year will end. We know we had some gas acreage in the Eagle Ford shale that we have taken off the table, of course and we've made some big changes in EUR.

I think that as I walked through a couple of the fields I think it's significant. Karnes, where it is a very 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've pulled that 660,000 to 600,000, but we are 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 are doing a lot of work with longer laterals there, bigger sand today from back to 2012. We are 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, so we don't have the perfect giant sections of land, but Catarina is very, very organized from that perspective.

And we have improved EURs there. We have three big ranches there. One area from 210,000 a day, 210,000 equivalent EUR to over 400 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 an enormous change in an area that we drill wells for only $4.7 million something. This is a big deal. And we may not have it all modeled in yet, but our trajectory and where we are headed there is very, very positive in my view.

Great, 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, and 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 resources going to drive when -- growth again -- when you return to playing offense as opposed to defense?

And I guess as you think about that and you think about the resources 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 the resource that will drive -- that will be the drivers of 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 the next cycle of Murphy?

Clearly, when we do M&A, we look at how it affects our long-range plans and how does it increase our income, our cash flow per share and every type of metric, including R/P. I think you are speaking in a nice way about the R/P. It's very frustrating to me that R/P here has been 8 for a long time. It's going to be 8 for a long time. But from an oil-weighted perspective, we are probably fifth place out of 16 peers if you take the R/P that's really truly oil. We are very limited. We would probably be the lowest NGL R/P player and very, very low on natural gas.

That's quite frustrating to me is this view that we don't have any locations. If this year in the Eagle Ford shale, we are going to drill/operate about 136 wells down there -- bring online 136 wells and we probably have 3000 locations to go. So this idea that Eagle Ford shale is not material for a company that has 756 million barrels of proven and now a resource size remaining of 800 million barrels is mind-boggling to me and it's very well known how this project models.

But outside of that, places like Vietnam, we have focus areas that are very tight around where we are wanting to work and we want to bring that focus tighter. Projects like Kodiak. Kodiak Vietnam and things in the Gulf are available to us that are not large M&A, change your entire capital structure type deals, but they are very helpful on adding barrels. We do have floating LNG coming online in Malaysia. It's 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 are partnered with the 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/P in this Company. If you take a look at the long-range plan of the Company, we do not significantly drop ever our R/P. P. We just don't have the 12 because we don't have a lot of gas to make it 12.

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

So it's hard to get into that vision that you are 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. It'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 the thoughts. It's safe to say that there's probably more resource depth than the market gives you credit for, but maybe one last one on that. Is the Gulf of Mexico -- you've had some recent successful wells there and as you think over the next couple years, it's a play that I think is 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? As you tie in these wells, will these effectively hold production flat, will it drive moderate growth or moderate declines or how should we think about that?

If we could get partners to participate in our wells that had ability and income to 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. We've placed two wells online and are doing very, very well. So we have some additional locations there. It'll be a matter of an oil price recovery.

However, tiebacks like Dalmatian South #2 and various other things -- tiebacks in the Gulf of Mexico are right up there with returns you have in the Eagle Ford if you take full cycle into account, meaning the drilling of the well, the pipeline, etc. These things are very economic. We need a higher oil price, Ron, to get into facility building big exploration successful things or where we can enter into a well or enter into (inaudible) ground floor during this unique pullback 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 in many, many favorable projects today. So our ability to operate there, work there and a long history of being there and have our business set up that way is very advantageous for us right now.

So we have great Eagle Ford shale business going. We are executing incredibly well on -- you have got to keep in mind we built this team in four years. It's incredible. And we are then able to look at those opportunities. We have a long-standing deepwater team where we are not exploring today, but the 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 are very advantaged to be able to look at both of them. And I don't know if many people have that.

Thanks, Roger.

Pavel Molchanov, Raymond James.

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 geographic footprint and the different host country relationships, 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've found that in Southeast Asia, Petronas is such a leader there that the fiscal terms are very similar and we've been very successful and we greatly understand it. That's going fine. I think that will come. It takes a while for a -- and I have a lot of experience with NOCs. It takes a lot of 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 places and we are doing so and that's why we will have exits that we will talk about when they are exited. So I think we're doing all the things that you are 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 are doing when oil prices used to be $100 and today, they are $45.

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

No, I doubt so. Like I say, we are sought after there by them. We have an incredible relationship with them. We've been (technical difficulty) building this relationship. We find the terms to be very similar to shallow water Malaysia. We are very familiar with how they work. I consider them fair. They are 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 are very happy about it. It is a block that has success on it. This is not some new entry, rank wildcatting block in the middle of nowhere. This is totally the opposite. This is one of the bigger oilfields anywhere in offshore. It was discovered in the 1970s by Mobil. This is a 4 billion to 5 billion type resource. They make almost 300,000 barrels a day in this area of Vietnam. This is the key crown jewel of Vietnam and we are very fortunate to be invited to be in it.

Okay. Appreciate it, guys.

Brian Singer, Goldman Sachs.

Your op costs have seen some wild quarter-to-quarter swings, but as we've highlighted here, there was a consistency of strong cost performance here in the third quarter. When we look at the Eagle Ford production costs at $8, the rest of the US 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 are doing very, very well in that regard. I mean looking back at 2014, I'm talking about just LOE, Ron, not the taxes and all that. There's different aspects 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 are probably looking at $8 and change. That's really good.

I think in Canada, we are making incredible OpEx improvements at both Montney and Seal. Seal, of course, very challenged from a price perspective. And so 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 had a good year in offshore, especially in the Gulf and it will come. You have subsea inspections, intelligent (inaudible) of pipelines and it makes the quarter a little bit jumpy in that regard, but, overall, as a company, I think that we are, like I said earlier in the call, we are looking at $9.65. It's probably a record here of LOE and looking at right around $9 for all of our business. So we've probably done a lot of that heavy lifting. That would account for -- if there are levels of production dropping of whatever due to capital, which will be the rage 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. As you have this push versus pull of budget versus efficiencies, is there a minimum level of completion cadence that you see is needed per quarter in the Eagle Ford to retain a minimum level of efficiencies and should we expect that production to decline?

Obviously, if you go -- to answer your question, I see you need to keep two rigs running and if you have to drill wells and that would probably lead to one frac spread and you can always pick up other ones as needed. We are 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 an appropriate thing to do with capital. And so with that said, obviously, we would have production decline, Brian. If you go from eight to six to four to two, it 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.

Paul Sankey, Wolfe Research.

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

Those are unusual complex questions, Paul. As our complete Board of Directors of Murphy, of which I am one, we have not -- 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 making a stand about trying to get the cash flow CapEx parity and going from there is my focus today over mergers and that affect. That will always be available to any publicly traded company, of course, but it's not a 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?

Well, we change that by continuing to -- when you are in a get back to cash flow CapEx parity and do that first and continuing to focus on costs, you can only go so far with that, but we're going to keep working on those two matters and we do have singles and doubles here that we've been hitting. (multiple speakers) doing that again. It's pretty big growth type resource we are touching this quarter, Dalmatian $10 million; $10 million each for the shallow water well. Significant well in Vietnam and so we've got some things going our way there and we feel like we are pretty well-positioned.

But in my view today, we have to maintain the balance sheet that we have and at some point, I suppose, there will be a time when we tried to do M&A and have return for our shareholders and we feel we are unable to do that anymore, then we could look at other things. So I feel good about where we are in a pretty poor price environment and we are working on that is the answer, Paul.

Yes. I appreciate it, Roger. Thank you very much.

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.

Appreciate everyone calling in today with some active questions today. Loved participating with you and I think we did have a good quarter and we will be back with you again after the holidays and we will go from there and I appreciate it.

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