Good day, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2016 Earnings Conference Call. Today's conference is being recorded. I would now like to turn the conference over to Mrs. Kelly Whitley, Vice President of Investor Relations and Communications. Please go ahead.

Good morning, 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. John will begin by providing a review of fourth quarter financial results, highlighting our balance sheet and strong liquidity position, followed by Roger with fourth quarter highlights and operational update and outlook, 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 projections will be attained. A variety of factors exists that may cause actual results to differ. For further discussions of risk factor see Murphy's 2015 Annual Report on Form 10-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 morning to all. Murphy's fourth quarter results from continuing operations were a loss of $62.8 million or $0.36 per diluted share. The fourth quarter of 2016 results from continued operations included a $24.2 million after-tax charge associated with an expected cash settlement during 2017 for contractually required redetermination of working interest in the Kikeh field offshore Southern Malaysia. The redetermination settlement is expected to reduce the company's net working interest in the Kikeh field and spending the approval of Petronas [ph]. Adjusted earnings which adjust our GAAP numbers for various items that affect comparability of results between periods was a loss of $26.9 million or $0.16 per share in this quarter. Our schedule of adjusted loss is included as part of our earnings release and amounts in this schedule are reported on an after-tax basis. The Company's average realized price for its crude oil production was $47.75 per barrel in the fourth quarter of 2016, realized natural gas sales prices in North America averaged $2.19 per MCF in the quarter while realized oil indexed natural gas price offshore Sarawak averaged $3.23 per MCF. At this time, we have WTI crude oil hedges of 22,000 barrels per day at $50.41 per barrel for 2017. We have Canadian natural gas hedges for 2017 that totaled 124 million cubic feet per day at AECO and the average price of these are at $2.97 Canadian per MCF. We have hedges for 18 through 20 of 59 million cubic feet per day also at AECO and an average price of $2.81 Canadian per MCF. At December 31, Murphy's totaled debt amounted to $2.99 billion or 37.8% of total capital employed while net debt to capital employed was $2 billion and 29%. As of year-end 2016, we had no outstanding borrowings under our $1.1 billion revolver. Our worldwide cash and invested cash balances totaled approximately $1 billion at December 31. That concludes my comments and at this point I will pass the call to Roger.

Thanks, John. Good morning everyone. Thanks for calling in today. Murphy closed out the year at an all-round solid quarter with strong results from higher than forecasted production while generating free cash flow. During the year we took several actions to high-grade our North American onshore portfolio, amidst one of the most difficult years in our industry's history. We believe our improved portfolio provides us with a stabilized and balanced production base that will be our foundation for growth. Together with a solid balance sheet, ample liquidity and top quartile dividend yield we're set up to be successful heading into 2017. Fourth quarter production was $168,000 equivalents per day and full year production was $176,000 equivalents per day both of which exceeded the high end of our production guidelines. The strong fourth quarter production is attributable to $1,500 equivalents per day and better than scheduled performance and facility in Sabah and Sarawak, Malaysia following our planned facility turnarounds. Approximately 1,800 barrel equivalents additional production from new wells that outperformed in our Catarina area. For the quarter the Company spent $176 million in capital expenditures, bringing the full-year total to $605 million as compared to $2.2 billion in 2015. 2016's capital budget is exclusive of the $207 million we spent at [indiscernible] acquisition last year. For the full year our keen attention on reducing costs has paid off, it lowered LOE by 15% year-over-year and reduced G&A by 14% year-over-year. This is achieved through implementing multiple cost-cutting measures along with efficiency gains made across the organization. During the quarter we expanded our exploration portfolio by entering into a successful Gulf of Mexico fireman and winning a black in Malaysia's -- excuse me, Mexico's recent bid ground. With regard to our onshore portfolio, we monetized our non-core Canadian heavy oil sealed asset…

Thank you. [Operator Instructions] We'll take our first question from Ben Wyatt with Stephens.

I wanted to ask a couple questions on Canada. I guess I can start first with Tupper. I mean and the well you guys brought online, obviously, you rent the sand volumes there; any other tweaks you guys are going to do on wells going forward? Do you feel like you've kind of dialed in? How you want to complete these Tupper wells going forward?

Well, Tupper is a big asset for us, mind-boggling amount of TCF's there. We do have three zones there and many locations. And we are now on a -- really in this play the sand is not near as high concentration as we're using in Duvernay or in Eagle Ford; these are only £1,000 a foot type fracs. We've never really experimenting with much higher but we belong to a cluster perforation designed much longer lateral wells. And now we're always drilling wells above over 9,000 feet of horizontal up there. Just onto a good flow of lower costs, great execution and the wells are performing ahead of expectation and they are setting up a place where we can easily keep this plant full, and take all the volumes from some of our peer companies that will be leaving the plant over time by drilling five or six wells per year. It's going really well for us in that area.

Got it. Very good. And then maybe hoping over to the Duvernay. Just taking a look at the tight curve you guys have in the bottom right on that slide, the 43 -- 4-30 sticks [ph] looks like it takes a month or so to clean up then stays relatively flat. How are you guys internally thinking about that? Does that stay flat for much longer, and also are you having to put any type of artificial lift in that pretty quick or is it flowing naturally for you guys?

It's flowing naturally at this time. That whole deal about this plate we're trying to delineate. There's only very limited well information in this volatile, considering how vast and large this acreage is in this region. You can see it on the scale, these are townships on this map. And I am real pleased at the wells, these are real non-optimized, there are only 4,100 feet linked tight curve here. And the stimulation is really not even full 4,000 feet there. And to come in on and EUR in the 4-70s just getting started in the play, and the production we believe will made up with a 4-70 curve that will continue to the right. They aren't on artificial lift, and we are pleased with our first foray, it is just really taken a while here to take over operator ship. We didn't close this deal until May. These wells were drilled by our joint venture partner. We participated in the design of completion but we didn't execute the completion and we have now moved and drilled another two well pad with what I consider low cost for the beginning of our work, that will is not optimized in azimuth we would like, and we're just now drilling the azimuth we want, the links we want, permits and everything set up for the much longer lateral and we're going to try to hit this plate with a 9,000 foot laterals and not a start off into 4,000 to 5,000 foot we have done years ago. Really trying to build our expertise, it's -- we drilled thousands of wells between Eagle Ford and Montney and we know what we're doing here as far as executing in shale, but it takes time to take over and get your game plan, get your permits, deal with the long-term rig schedule, keep our rigs moving between Montney and Duvernay and are frac crews for efficiency, driving the back-and-forth breakup season and getting going good and I am real pleased with how we are executing, it's going to be about getting the cost down. We are very good at doing that we're off to a good start here.

Very good. Well I appreciate it guys. Thanks.

Thank you, appreciate it.

We'll take our next question from Kyle Rhodes with RBC Capital.

Good morning, guys. Just curious, does Murphy it's up as a potential consolidator in Eagle Ford and curious on Murphy's view on bringing financial planner to help facilitate the larger transaction there?

We are like any other player with a full on business development team that look at opportunities such as that quite often, that depend on that cost to capital versus the cost of capital opportunities we would have our Company . I think a lot of this consolidation in overview has been more Western of our Catarina are more a [indiscernible] area at Catarina which be like a 33% between NGL, gas , and we are really in the high 80s here. I'm not sure if there's been a lot of consolidation in real true oil window there. And we have look at those opportunities often, and widget against others we can do, but probably, not really interested in giving away a lot of value in our oil weighted Eagle Ford advanced to capital at this point. But we are approached and to look at opportunities naturally every day. We don't preclude that we're going to do that.

Great, that's helpful. And then I was just hoping you could discuss Murphy's thoughts on the potential boarder adjustment tax. Specifically if you think opposes any risk to your Canadian operations and if there's anything Murphy can do to kind of mitigate that kind of risk form of hedging or something else?

Yes, everyday there's a change coming from this administration which I believe will lead to lower regulation and many positive things for our industry. But to understanding of how that would particularly work, I do not believe Murphy will be incredibly disadvantaged we have our crude in Asia that's really sold in that part of the world. Our East Coast of Canada crude has treated like crude and would come in into Eastern United States possibly I suppose. And our production our take up Duvernay sure as it great goes into Edmonton and goes into there, and not really coming into the United States. But I think they will manufacturers coming from this administration of many changed items over the course of the next year or so. I think it's too early to predict what that would actually be. We just have to keep lowering our costs, keep making our production levels, keep growing and let our president to what it needs to do which in general will help business in America in my view, and go from there.

Great, great. And one more if I could. I believe 2017 budget was based on $52 oil, we are sitting on a strip, it's closer to $55. It's closer to $55 to 56. If we to stronger oil prices in 2017 where does that incremental next dollar of cash flow go? How does Murphy rank potential dividend increases or is this debt pay down versus growing production versus growing acreage?

I would say we're not really looking to focus on the big debt paydown because that $3 increase from strip to where we are something below $100 million. I would like to look for opportunities in our Catarina areas very, very prolific area for us. If you look at cumulative production coming out of Catarina compared to some Permian cumulative production slots that are available from our peers, if any's cumulative reduction areas quite competitive that probably actually in some cases exceeding. So I would say we have less than $100 million in capital, we would have additional opportunities in our Catarina area, with also Duvernay shale would like to complete pad or two wells there will end up was some docks in the water there at the end of the year. Those types of opportunities would be the first for us over dividend per share and for balance sheet. Balance sheet is pretty strong leverage, metrics pretty strong cash available to pay a bond to at the end of the year, cash balance even at a strip basis keeping our cash levels 400 to 500 range easily. So I would like to do a little more drilling if we could get $3 more. The prom month is always 52. We will go from there.

Appreciate the color, Roger.

Thank you.

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

Good morning, Roger. Good to talk to you in 2017. Just following up a little bit on some of expectations of production growth for 2017 and onshore and even kind of the guidance for higher rate of onshore growth in coming years; how should we think about that between that Eagle Ford Shale and the Canadian opportunities? Clearly a lot more wells in AFS is that the right way to think about protection as well?

Compare back to this year, the growth will primarily be across those three plays almost evenly. CR Eagle Ford his stabilizing our Kaybob Duvernay and our placid areas almost doubling, and that's where the production is coming from. There's drilling program in place there. It's not like we are thinking of that, it's happening now; and so when I look at for the year, I will be looking at that Eagle Ford Shale slightly higher than 2016. I'll be looking at the Montney and Duvernay combined to be somewhat higher price almost $6,000 a day higher. So those are the primary growth areas, Roger.

Okay. Appreciate that. And then in the offshore space, you mentioned in your opening comments, probably pretty low here on the cost structure. You made the move into Mexico during the fourth quarter. I am just curious oil above 50, obviously everybody feels a little bit better about life. Is that slowing the number of opportunities to acquire something that's maybe partially along the process in the offshore. Is it bringing in more bidders, is it made you more confident about moving forward. Has that brought more potential sellers out? I am just curious have there been any real any evolution along those lines?

I do not see any increase in bidders, I can tell you. That's how you roll when things are when you don't have a lot of bidders. There's a lot of bidders in other parts of North American business I can tell you work we did have a lot of bidders on the around rebid including some large companies in some very successful expiration companies, as the most bid block in Mexico. We had I believe we had four other bidders beside our bid group. That is competition come to that and we were successful and glad to have that. I just think that that cost structure will be there a while, and the opportunity to enter into the ground floor expiration, it's just changed so much in three or four years. I mean any type of aspect that's a decent prospect was a two-for-one remote at least three years ago, and now you're entering on these ground floor basis. I strongly believe the efficiency and onshore drilling has driven the teams in these companies in the offshore to improve as well these very large new rigs barely got a chance to go, and we are seeing these new high-end rigs performing incredibly well, and this will anticipate drilling into something days. That well was easily double that two or three years ago. And the rig rate here was probably north of 4-50 and our cost to drill the well was $16 million so you can imagine drilling that fresh air being $8 million and can do that for a while ahead in my view. That's a real positive F&D CapEx per barrel total business there that will rival shale without a problem.

Got you, thanks for that. Maybe just one last little follow up along those lines. When you were evaluating a known discovery that a Company as attempting to put on the market versus I don't know if we call it let's call it a legitimate exploration prospect. Have we seen those narrow up in terms of relative risk reward adjustment or is it still that much more attractive to due to the exploration side relative to that entry cost and the projected drilling costs?

I think that as we look at benchmarking and look at a lot of things involved in exploration, today's time a finding cost of below four dollars is pretty consider to be pretty decent are pretty good. If you look at some of the deals in the world primarily in Brazil, and there's been some super major activity going to Brazil and the very large fields, you are in a 25 kind of per dollar acquisition kind of deal, with some type of in outcome from their of how to get that $2.50. That's what we see there, so the exploration is not far away from that. But the issue will be the timing, the delineation of each particular prospect that you're looking to buy. That's going to drive that entry cost work if the project hasn't been delineated appropriately, you will be paying less. I think just not a lot of people looking to do it is the big issue over the comments I had about cost per barrel, that's where we like to in there. But I'll be very clear that you can enter into an international discovered resource and you can compare that to an entry into a major shale basin, where you would have three to four benches if you well in each making barrels in each, and 24 section in you drove that out over 30,000 acres, I can tell you that the breakeven this lower overprice, the payout is similar, the acquisition cost is lower, the CapEx for BOE is lower and the supply cost of the business is better and the MPV per BOE is better, and the rate of return better.

So better then.

It's better or we wouldn't be doing it. I do not believe the offshore deepwater industry will turn into the edges tape type thing.

How about Betamax? I am just kidding you, thanks, Roger.

Whatever.

We'll take our next question from [indiscernible].

Thanks very much. Good morning, Roger. Hi everybody. I wanted to ask a little about the longer-term growth guidance that you have in your slides, which we very much appreciated. And give a little more color on the 2017 growth. I was hoping you could dive a bit deeper into the 2017 to 2020 CAGR that you show, but you obviously are showing very meaningful growth in the onshore portfolio. So could we discuss a bit more the individual components maybe, because I believe previously you had been talking about Eagle Ford as flat to flattish to slightly up business over time. Are you more optimistic there now? And to what extent is the growth in the Tupper Montney drive gas contributing. Any color you could put aromas drivers would be very much appreciated.

Yes. Right now we do have what I consider the Eagle Ford to be quite flat through 2020 slightly increasing from where we are for 2017 which is around 49,000 in there. See that slightly maintaining a couple years and slightly trending up by 2020. Our Montney position will go up probably around 8,000 or 9,000 POA per day, because the plant has some Company that will be coming out to the plant, and we will be taking their place with these high 14 to 17 BCF wells that breakeven little over $2 Canadian AECO and will be taking its place and will have to see growth in plan on growth from K-Bob placid but a lot of CapEx going in there the next two or three years. Many, many different types of wells drilled, many areas or near competitors that are drilling successful wells -- and can shell and Chevron. We have date going up the rest of the way there from an unsure basis.

Okay. Great. That's helpful. And then can you talk a little more on the topic of the Kaybob Duvernay. You mentioned it's really important for you guys to get the costs down there, it sounds like you have already made some pretty impressive strides. So you just lay it out for us just the type of well cost improvement that you're looking to achieve. What you have already achieved. Maybe what you see is the runway, in addition to maybe a reminder on the enhancements you are making on the drilling front there is well.

It's going to be a year or more before we can show the improvements that we need. I think I am encouraged by the idea that we go in the middle of the field between many peers and this is third-party information that in the slide today. And we get in there and we start off and the wells are permitted prior we go in and execute the wells at a normalized rate, I mean length like they are and we're already in the top quartile. And are even with the quartile of everyone else was been on the play ahead of us. It's up to a positive direction, but we will be struggling from a lowering cost mode because we really only have we are drilling on a two well pad right now, and we have one pad that's it three well pad in the rest are single well pads or possibly two. So you really need to get to four well pads to get the efficiency of high-spec rigs that we contracted there. Will then to 2019. We will have well costs probably approaching $9 million for these wells, $9 million to $10 million. These wells I'm also reading across at my notes here, we were talking 9,800 feet, 9,800 feet, 7,500 feet, so our wells are 9,800 and two wells almost 10,000 feet in horizontal. So these wells almost two wells under prior thoughts about shale. And we believe it's all about days and drilling days. We will pull these days down, as we get to pad drilling and we already start off at the benchmark now, and our long-term goal is to have $6 million $6 million-$7 million wells in here at 9,000 feet and I believe we will be able to do that.

That's very helpful. And last one for me. You mentioned a comment, and this was discussed a little bit earlier but you mentioned the goal of adding reserves to $13 a barrel F&D to the portfolio. I was hoping you could discuss that comment a little bit more. Is $10 a barrel FF&E the type of F&D you see a sustainable for your portfolio and for that business? Are you talking specifically about some specific adds to the portfolio? I just want to better understand the commentary around the $10 barrel.

I actually even consider it team to be top percentile. If you look back over a while, you'll see that's really good F&D. I think you have two situations here, if you look at F&D and a big onshore entry you are probably going to be talking about -- talking about first quartile there too. But in the offshore deals we are working on that we discussed today we feel being in the $10 range, and I believe that over the next three to four years that will be pretty firm. It's possible the cost increase in the onshore will try that. And our view -- but the offshore we are looking at it's about return and top quartile F&D and not getting into a project that on the risk basis that not lead you to be able to accomplish that. That's what our new focus and expiration opportunities are, smaller work in interest, less expensive wells around $10 F&D which in the worst take us to 15 that's okay. And if we determinant from a success case that we can't get to the F&D that we were, then we are moving on and not looking at that.

That makes a lot of sense. Thanks for clarifying that.

That's a totally different view that we had a few years ago and I think we improved in one that will lead to value creation here.

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

Hey guys, good morning. Can you talk about exploration program. Can you give us some sense that what consider going forward as a normal expiration program at year end. How much you're going to spend? How many wells you're going to precipitate? And what kind of tie up that you comment on that share?

I don't believe we are off on a ground of getting back to the high-level of exploration spend we had before, and we are looking at consistently 100 million to 150 million plan that we had now in the plan today. We are looking at opportunities where those opportunities would be helpful to us, we would participate more, but the costs are so much lower, and the entries so much lower in the availability so much better that 100 million goes a lot more in deep water than it did two years ago. Is probably similar to three or 400 actually. We would like that to be higher, but we have to have our growth plan that we have here are value-added growth where we have really good four months in Eagle Ford. We believe topline performance ahead in Kaybob Duvernay. We'll illustrating more and more value-added creation in Montney. And so we half of that mindful of that. We aren't off into a big jump back into the 400 million expiration budget just trying to accomplish lower interest in the right sort of things with the lower level of exploration spend. I think we're off to pretty good start doing that.

And should we assume that this kind of exploration budget which seem to say somewhere in the five to six well, 25% to 30% interest, that kind of program ? That year?

No, we will have other expenses in our international offices like of Vietnam office and things of that nature Seismic work we're probably only drilling a couple was a here with our current plan. Our current plan outlined in here is not a heavily weighted exploration plan.

I see. Okay. And this will be at least in the foreseeable future the kind of program you have in mind?

What's that? I'm sorry Paul, one more time.

At least in the foreseeable future, this is the kind of program you have in mind at this point.

Yes, you are right, at this time.

Just clear on the acquisition fund for exploration acre, have you guys looked at Conoco Gulf of Mexico Deepwater program whether you are interested or not. If you're not interested is a because of the quality or because of the size of that portfolio?

We looked at several months ago, I'm not sure because I don't recall exactly the outcome a head. We're not really looking to take on large exploration acreage, looking to one-off select opportunities to drill wells with partners, or work opportunities in which we can operate which would be the best situation for us where we had the most value. We were very interested in the project they had in West Africa which was a sale of a on oil field that they had partially delineated but not interested in going to a data room and taking on massive exploration acreage from appear rather go on anticipate in wells that will be drilled and from a ground floor basis, and that's much more our plan than to take on a big set of acreage and commitments from other people that's not the plan at all at this time.

And for the recent fund [indiscernible], any color in terms of discovery in terms of the size whether that's type of oil and gas mix and water depth, when you're going to drill the , any kind of information you may be able to share?

It's in medium water depth range of around 5,000 feet or something to that effect. It was high quality oil found there, it's not a gas well or anything like that. I prefer not to talk about the size. We have delineation well that we had to take some seismic reprocessing from the well we drilled near salt there and there some salt proximity work that's being done by both parties working very well with Chevron and enjoy working with Chevron, and planning delineation. At that time we will say what comes out of it. Obviously to move and discuss our suspend a well must have some idea's above a minimum field volume, which we do and the pay that was found in the well. Just tiptoeing back into this business and prefer to have things better lined up prior to quoting size and numbers on it at this time, Paul. I'm really happy with the results. It's near a lot of tie back opportunities for three to four areas to bring the production, so summer very close, to where we are drilling, lot of successful wells in this area. Mississippi, very prolific reservoir and we're very happy with the partnership real happy with the outcome. And looking forward to some more information they're coming hopefully in the second half are later part of this year.

So this is and when you drill the appraisal well?

We are working with them on that plan. I would say it would be at us that end of this year. No at best I anticipate that happening before the end of the year. And it won't take long to do it.

And just want to clarify earlier that you're talking about a $9 million to $10 million well in the end it's so you implied at least until that you get into more the drilling that the completion cost is going to be about 70% of the total well cost save $7 million $8 million kind of range, I just wanted to clarify that?

In Kaybob area ?

Yes.

That's primarily completion. I don't have it written down in front of me. But the drilling will be a third of that, something of that nature.

I see. And then Eagle Ford and on the Kaybob, Kaybob I think when you initially bought it and I believe you guys have the this release sustainment or someone else's speculating, saying the total production to you might be 20,000 barrel per day, and Eagle Ford a while ago before the downturn was talking about 17,000 barrel a day and now you just say Eagle Ford that you expect to be flat at around 50 through 2020 and only modestly up. So have those numbers has been changed at this point. What the total maybe look like.

Paul, we cut back CapEx therefrom $1.1 billion a year to $200 million. I would say a lot of numbers change for a lot of peers this year, I think it is per year maintenance CapEx person, you have asked me about it many, many times. We barely went down in our production this year with only $200 million and we get in there and spend a little over $300 million a year we stay flat production, it is actually leading to free cash flow, with any type of help on oil price before 2020, and I think that's a really good deal to spend $300 something million a day in a big asset like this and keep oil around 49,000 day going into low 50s in 2020. More oil weighted.

Longer-term cash is available. Based on the resource and based on your portfolio management that your overall synergy where you see the longer term for Eagle Ford could settle into is it still at the 70 or is it now that given how you do.

Thanks, Paul. Our plan stops at 2020. But 2021 has a going up a good bit, so were probably going to be plateau back in 65 range and will get back to the 70 again because we have other opportunities and things we can be allocating capital to. However, if that changes and we went to put our capital back in here we can reach back to the 70s again but this time probably get in the mid-60s there around 2020, 2021. That's a long time from now, Paul.

Understand. How about Kaybob and Duvernay, that portfolio, I think at some point someone was speculating 20,000 net to you as the total, is there any number you can share on that?

Speculating that our Kaybob would be 20,000 our shares is that which were saying?

Yes.

Yes, I believe about 2020 it will be higher than that in that business.

Okay. Final one for me on hedging. Look like the oil already [indiscernible] 2017 your oil hedge comparing to the future strip is losing money. Is there any change in your hedging strategy going forward should we assume you will continue on the hedge position or are you pretty much done?

Pretty much done. I wanted to have some protection from OPEC issues ahead and I want to be conservative about my U.S cash flow for the U.S cash expenses I have and the capital allocation into Eagle Ford Shale, and I made that call a couple months ago and here I am today with that. But not interested in that, but am very pleased with our quite aggressive hedging and Montney where we have nice had positions there. We did do very, very well in our hedging last year in oil as well. All in all the book is pretty positive for us there, and this hedging into Montney is something we spend a lot more time and focus on and we want to be heavily hedged their, well above our breakeven SEC AECO price and we are doing well in that regard, and I am happy about that.

Thank you.

Thank you Paul, good talking to you.

We will take our next question from Pavel Molchanov with Raymond James.

Thanks for taking my question guys, just one for me maybe in two parts. A lot of your peers are also raising 2017 CapEx kind of within 20% to 30%. By depending on where we are in the oil service supply chain, we're hearing reports of cost escalation of upwards of 20%, most particularly in North America but not exclusively. Given my pretty diverse asset base that you guys are currently at, can you walk us through the service cost inflation that is embedded in the $800 million budget kind of by geography?

No, I don't have a net written down, but I'll give you my view of how we are lined up here. We're -- main thing for us go with the U.S, I mean, we believe from our data that they increase in cost is primarily related to frac and casing. And we have our rigs lined up to work here for us. Actually our rig costs are going down, because we had a co-mingled rate last year from some contract pulling together to one rig if you will, so actually looking at 16 to 18 well into 2018 and have to rigs we need for two rig budget there and pick up the third rig as need on occasion. The main thing for us is in Eagle Ford we have around 10% per year efficiency gains, this has been quite consistent. If you pull one day off of our well, we are right now keeping our cost flat from last year [indiscernible] will have this continued efficiency and I'm informed of a pacesetter well almost every week here and have been for a very long time. And then if you start looking at it of going into the frac issue, that could happen of course. We have a crew lined up for us with prices agreed to the first half of 2017, working with them and the second half of 2017. We have a second crew that's prices are fixed for all of 2017. All of these contracts in fracturing allow for increases for sand and fuel on a documented basis, some are limited by the market must move by 10% on that. We will work with our vendors toward doing that, we to see they are the name brand large vendors in space, they are smaller companies. We have…

Yes, that's helpful. So maybe just kind of aggregating everything of the 24% year-over-year spending increase, how much is cost inflation?

Our cost inflation is very limited there.

Okay.

Because our efficiency, we just drilled a well at Kaybob at the top of the quartile and we're going to improving there. We only got started and our Eagle Ford just continues to deliver. It's mostly in the drilling side because the completion days have been more complex due to more sand.

Okay. I appreciate it , guys. Thank you.

We'll go next to Ryan Todd with Deutsche Bank.

Maybe a couple of follow-ups on -- one on Duvernay. How do you think about -- when you look over the next few years about your potential ramp in the Duvernay, how do you think about limitations on your ability to ramp? Is it -- is the governor primarily going to be cash flow? Is that where the appraisal signs is, is it permitting as -- if cash flow exceeds the expectation to the upside, can you accelerate beyond with the current plan is in the Duvernay or are there other reasons that would kind of keep the pace moderate?

No, of course it's a negative cash flow as we build up here where we're getting cash from our other businesses are pretty much neutral across our Company and our free cash flow from offshore spending our other corporate needs. No, we are in the middle of really setting up a lot of optionality around permitting both for additional infrastructure and wells and pads and we are able to move back into if we're not successful in some areas, we can move into other gas condensate -- and kind of lead in the gas condensate, it's been very prolific by one of our peers. Leaving that off to the side we feel we can easily go in and execute there. And just dependent on these results over this year and that we're setting up options to work inside out. I don't see a problem for Murphy in some type of large increase in oil price or cash flow or additional capital allocation for some of these wells to perform above a million barrel BOE type curve, so we could double this from two rigs to four rigs. I don't see that as a stretch on our Company and things of that nature but you know, in shale today compared to five years ago, we used to have 13 rigs in the Eagle Ford and we're doing all the work with two. So there is no 10 to 12 rig plan in here anymore, you can do a lot of work with four to six rigs and I think we could easily handle permit and work that issue if that opportunity comes to us. Where do you -- I mean would you be willing to say over the plan that you have out through 2020, where do you have the rig count headed in that Duvernay? Is that -- by the end of that plan up there at the end of that, four to six rigs?

No, we're going to be two for a couple of years and moving into the full range later in the planned cycle. Okay. And then maybe one on the Montney, I know in the past you've talked about the possibility of expansion in the Montney or maybe underpinning some expansion of infrastructure out there. I know you referenced taking some of the capacity and existing infrastructure in there over the next couple of years but what's the thought process right now in terms of potential higher expansion there in the Montney?

Well, we have one facility we're not talking about that, I'm talking 30 million or 40 million a day increase for us to feel that type of number. It's not over-shattering [ph] especially when wells produce like we are having here. And we have many, many TCFs here and we would work with our infrastructure partner to build out plants if you will, and we would look to expand and fill those plants, we're reviewing that, probably make a decision about that at the end of the year, probably also look and have a partner on that if we were to consider that. But you got to compete with capital with other things we're doing and that would -- it has a lot to do with how different things end up with infrastructure price point out of Chicago, California, Don [ph], different things of that nature. How LNG progresses in Canada and a lot of factors involved with that. But it definitely works economically and we have that in one of our to-do list of things to do ahead for us. We have a lot of resources in our Company and a lot of things to review and compete for capital and I think it's a good position to be in.

And ladies and gentlemen, this will conclude today's question-and-answer session. At this time I'd like to turn the conference back to your speakers for any additional or closing remarks.

Our time is up today, we went over an hour here. We appreciate everyone calling in, so we can get back to executing our plan. And appreciate all the calls and questions today and we'll speak to you soon. Take care. We appreciate it.

Ladies and gentlemen, this concludes today's conference. We appreciate your participation.