Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2017 Earnings Conference Call. I would now like to turn the call over to Mrs. Kelly Whitley, Vice President, 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. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion on risk factors, see Murphy's 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 now turn the call over to Roger Jenkins, President and Chief Executive Officer.

Thank you, Kelly. Good morning, everyone. And thanks for listening to our call today. Our fourth quarter production was 168,000 barrels equivalent per day and full year production was 164,000 equivalents per day, both at 61% liquids. Our cash flow providing offshore assets generated nearly $120 million of free cash for the quarter and over $500 million for the year. Our fourth quarter production was slightly below our guidance range due to some temporary factors including: end-of-year offset frac impact in the Eagle Ford Shale and delay in well recovery caused by Hurricane Harvey; the non-operated downstream shut-in of the Enchilada platform in the Gulf, which impacted our Habanero field along with other Gulf of Mexico operators; unplanned downtime at the non-operated Canada Hibernia platform; and lastly, there's an unplanned downtime from a weather system in Malaysia in our Sarawak field, involving back-to-back typhoon and a tropical storm in that area. Despite these impacts, we're able to hit our production sales target. Capital expenditures for full year 2017 totaled $976 million. Our capital for the fourth quarter was above guidance due to drilling and completing three additional wells and an increase in unplanned non-operated well count in the Eagle Ford Shale. In addition, we also added field development spend in the Eagle Ford at our Catarina area, which is outperforming our plan. Our diverse oil-weighted asset base, priced primarily at Brent and LLS, delivers high margins, generating a competitive fourth quarter adjusted EBITDAX of approximately $24 per barrel. We continued to drive down our operating costs, achieving a lease operating cost of $7.89 per barrel equivalent for full year 2017. Over the past few years, we've focused on creating value through commodity price cycle. For several consecutive quarters, we've been able to maintain a consistent level of cash on our balance sheet while simultaneously growing production and paying a competitive dividend. This is an example of our strategy in action, paying our own way and living within cash flow. We're now focusing on expanding our free cash flow by creating sustainable cost savings, allocating capital to our growing North American onshore profitable well count, participating in highly economic offshore projects, and in countercyclical move, returning to a focused strategic offshore exploration program at the bottom of the cycle. With another great year replacing our production, increasing our reserves, we anticipate when our 10-K is filed at the end of the month our total proved reserves will be 698 million equivalents. We replaced 123% of our production with 113% organic replacement, 65% of our reserve replacement specifically related to our oil-weighted producing areas. We had an F&D cost for 2017 of $13 per barrel, with a three-year average of $14 per barrel. We've improved our three-year finding and development cost by 40% since 2013. We now have a reserve life index in our company of 11.7 years. Let's turn the call back over to John to discuss some of our financial outcomes.

Good morning. Consolidated results in the fourth quarter of 2017 were a loss of $287 million or $1.66 per diluted share compared to a net loss of $64 million, which is $0.37 per diluted share in the same quarter one year ago. Our adjusted income was a profit of $13 million, $0.08 per share in the fourth quarter 2017. The adjusted income primarily varies from our net loss due to a $274 million non-cash tax charge associated with the recent U.S. tax reform, and also a $20 million loss from mark-to-market of open crude oil hedge contracts at the end of the year. On December 22, 2017, United States enacted the Tax Cuts and Jobs Act, which made significant changes to U.S. federal income tax law. The major impacts as a result of the new tax legislation are non-cash tax charges resulting from both the deemed repatriation of our historical undistributed foreign earnings, and a revaluation of our net deferred tax assets and liabilities to the new federal tax rate of 21%. And that's a reduction from the previous tax rate of 35% in the U.S. Under the act, we will have the ability to repatriate most of our past and future foreign earnings tax-free to the U.S., other than a 5% withholding tax required to be paid on Canadian earnings that we repatriate to the U.S. We currently expect to repatriate a portion of our past Canadian earnings beginning this year in 2018. We expect that these tax changes will positively impact our future earnings in the U.S. Following the fourth quarter impact from tax reform, we see positive outcomes for Murphy from tax reform related to both the ease of global repatriation going forward as well as significantly lower taxes in the future on profits we generate from our Eagle Ford Shale and Gulf of Mexico assets. Roger will now present a review of the company's operations.

Thank you, John. I'm now on Slide 7. Our Malaysia assets continue to be a stable cash flow-generating business, delivering over $100 million of free cash flow this quarter. During the fourth quarter, we achieved startup with our electric submersible pump pilot project at Kikeh, an innovative low-cost project, it will help mitigate natural decline of the field. We continue to progress our Kikeh gas lift project and expect the production at midyear. Also in Malaysia, our Block H floating LNG project with PETRONAS remains on track for first production in 2020. In the Gulf of Mexico, we're currently preparing for a workover of Medusa subsea well, which is scheduled to begin in the first quarter, and also planning for a fourth quarter 2018 platform rig program at the Front Runner facility. We achieved nearly 100% uptime in our operated fields in the Gulf of Mexico during the quarter. However, over the past few quarters, non-operated fields have caused impacts to our production levels. The Kodiak well, which has been off production since mid-2017, with the workover progressing slower than planned, production is now anticipated in late February. Habanero, which I mentioned earlier, the shut-in due to Enchilada facility and expected to produce in late February. On Slide 8, in the Gulf of Mexico I'm extremely pleased with our progress building an oil weighted high-margin portfolio of prospects that are near infrastructure and have outstanding full cycle returns that are greater than 30% in a $50 price environment. We made great progress putting together a new partner group to appraise our Samurai discovery that was previously drilled in 2009. We plan to spud our Green Canyon 432 Number 2 well at Samurai later in the first quarter. The well will confirm previously discovered commercial resources in two reservoirs while targeting…

Thank you. [Operator Instructions] Our first question comes from Roger Read from Wells Fargo. Your line is open.

Hey, good morning.

Good morning, Roger.

Good morning, Roger. It's been a while since we've caught up. But I guess if we could kind of dive in, as you think about the breakdown of CapEx in 2018, deemphasizing the North American unconventional, particularly the Eagle Ford, favoring Canada. Can you kind of walk us through maybe what's driving that besides some of the HBP issues that you need to follow up there as we think about IRRs per well, kind of how you want to think about managing CapEx and cash flow, as you said, to generate some modest free cash flow, and then maybe anything else that goes into it? I just sort of looked at the press release, and you have a 10-year backlog of potential well sites in the Eagle Ford at $40. Clearly today, oil is well above that. But just curious also what the upside on that well site backlog might be at a $55 or even a $60 WTI price.

Okay. Thanks, Roger. Really, what's going on this year is we have a unique year for a couple of years on capital allocation here. We have some projects that I mentioned in our offshore business as having capital this year. I think, the worst project we have is 43% full cycle and the other two are 100% full cycle. And our Block H project is over 30% the rate of return post-sanction there. So these are very strong economic projects that have been delayed and pushed aside due to prior years. And now with the cost structure in that offshore business, these are very, very economic projects. So we pull that CapEx into those projects, and we have to keep in mind, we started building a budget at $52 in early December, we were only $2 or $3 below the curve at that time. And so we set up a capital program this way. Also, in our Duvernay business, we have a required spend there from our agreement to purchase that, which is fine. We're actually doing very well there. All of our wells that we have drilled and operate ourself are above the preplanned results. Our drilling costs are drastically coming down, and when we increase water management, our completion costs are coming down. And actually over time, while our Eagle Ford business is incredible with all the locations that you mentioned at breakeven to these prices, the Duvernay actually has a lower breakeven price if we can get the costs down in the development mode because of the royalty, because of the mix, because of the strong condensate price we get there. So we're in an allocation of capital toward that, pulling back, and due to our offshore out of Eagle Ford for approximately two years, we'll be around the $350 million a day - $350 million a year capital. But in 2020, 2021, 2222, the Eagle Ford gets back into the $500 million, $600 million CapEx range, as we pull off the offshore projects. Until we know the full development plan of Kaybob, we have it going down and Eagle Ford going back up. So this has to do with the picture of what we need to do over the next couple of years. Nothing wrong with Eagle Ford, but due to the capital allocation I have, that's how that shakes out. Of course, the Eagle Ford business is doing very well. It's doing very well with less CapEx. We're able to maintain production. We're also able to deliver a lot of free cash flow out of it, which is our goal to have free cash flow in shale assets. And that's the reason for the capital allocation at this time, Roger, if that answers your question.

It does. Thanks, Roger. And maybe as a little follow-up to that, $52 is your budget base. Let's say, at the end of this year, we average $60, just to pick a round number. Incremental $8 a barrel, where does the cash go? Like, what's your order of where you'd want to put your cash at this point? Is it balance sheet? Or is it back into activity?

Well, we're trying to set up a discipline around here of keeping our CapEx, and I'm happy with the CAGR we have in our plan. I would like for our plan to be slightly more oil-weighted. That's what I said earlier about the production - about the capital allocation and our success exploration program that could move oil volumes to the left there in a different capital allocation. Right now, I would say, balance sheet, we're still focused, with the strong cash position we have, on M&A activities that are accretive on free cash flow, and of course, accretive on an income basis to our business. We constantly have one of those in the mill. There'll be a time when we say, we're not going to be able to accomplish that and do things differently. But this time, it's for balance sheet and trying to have that discipline of delivering these volumes for this level of capital and let the upside come when it will.

Okay, great. Thank you.

Thank you, Roger.

Thank you. Our next question comes from Paul Cheng from Barclays. Your line is open.

So, Paul, how you're doing this morning?

How you're doing? Good morning. Just a curiosity, I mean, your balance sheet is actually not too bad, and the oil price is much lighter. Have you revisited on the hedging policy? I mean, do you really need to continue hedges in the future?

No. We had typically hedged here 25% of our global production, around 40%-something of our U.S. production, and that's been my policy for last few years. We do that when we get in our budget and see how we are looking to budget and the risk of that at that time. Of course, oil has gone up a lot since then, but I do not anticipate ever exceeding that amount. And if our $60 case rolls on in this year, as Roger just mentioned on the phone, then we probably will get away from hedging altogether here as we've done years ago.

Okay. So it would be somewhat of oil price driven, so you believing that $60 is sustainable, that you're probably not hedging?

Correct.

Okay. And on the Permian, how - maybe that I missed it, how many wells are you going to drill this year?

We have two - we have about two other wells planned at this time. We're all about making that business in an accretive number of breakeven locations for our onshore business in Texas. We are just flowing back to two wells now, and we have not altered our capital based on those results at this time.

Okay. And how much money are you spending in Permian? I probably missed that.

We just disclosed all of our U.S. onshore. I think it's approximately $330 million, and it would be in that number and would - and could be less than 5% of that total at this time.

Less than 5%. And any plan that - or that do you have an estimate that you can share over the next, say, three or four years that, that number, how that trend up?

We're not breaking that out at this time till I get the well results I need, and I need to test both contiguous positions. And I am not allocating major capital on that until I have the success, I need that can compete with my other areas.

Okay. And the final one on Eagle Ford. I think at one point, you have a 70,000 barrel per day of the peak production runway on a sequential basis, and then I think later on, talking about maybe more like in the 50,000 to 55,000. So just curious that, as of right now given the improvement that you see in terms of how - is that number have changed?

No. The cost of the capital allocation I mentioned a while ago with the offshore projects is going to the left, which are very, very economic, and our spend in Duvernay, we'll be in the 46,000, 47,000 range for a couple of years. And over the long-range plan that we have here today, that asset will go 50,000, 60,000, 65,000 in 2022 as we allocate capital in a different way after a couple of years and get it back, not in the 70s again, Paul, but in the mid-60s is our current plan and outlook.

Okay. Thank you.

Thank you.

Thank you. Our next question comes from John Herrlin from Société Générale. Your line is open.

Yeah, John

Hi, how are you?

Good.

In Midland, are you doing controlled flow? Or have you thought about using ESPs for flowback or what...

What's going on there is we did a massive frac there, kind of a lot of water, a lot of sand, big 10,000-foot laterals we drilled in there. Also, we're partnering a well very nearby with the same. And it appears in that region that you have to draw the well down to 1,000 psi, bottom-hole pressure differential for the rates. We put in a conservative ESP pumping system there. And we could have gone with a larger pump, but because of the large frac and the lack of knowledge we had there, we have been conservatively flowing it back, meaning our pump that you mentioned is there, but it's not in a size to pull the pressure down as drastically, because of the risk of sand. And we're still progressing that now.

Okay. But as you go forward, chances are you'd then size up?

Yeah, after we get information on this well and if it's successful and there's also information of two other zones working just through our south, and we're in two zones here. And our other contiguous acreage is near, so more success. We have a long way to go for that, but of course, I think, we learned that we - I'd rather have a larger ESP in the well today, but that's the plan we have, and we're executing that plan that we had at that time.

Okay, that's fine. My next one is on oilfield services deflation in the deep water. Are you seeing plumbing products come down? Obviously, rigs have come down. Or - I mean, how does that change your thinking?

Well, I mean, it's from a service cost perspective, I mean, 35% of our capital is under really no risk of increasing. I see that business is not really an increase in rig count. It's very, very outstanding time to work in deep water today across all of the service spectrum there. And I don't see it getting much cheaper, but I don't see it going up for the foreseeable future in my personal view.

Great. Thank you.

Thank you. I appreciate it.

Thank you. Our next question comes from Peter Kissel from Scotia Howard Weil. Your line is open.

It's Howard Weil, good morning.

Thank you, Roger. Quick questions for me. First of all, you mentioned that the drilling and completion costs are both coming down in the Duvernay. Can you please remind us, where they are now or where they've been, and kind of where you see them going and, I guess, the puzzle pieces to get there, please?

We are getting wells below 3 million now, and we're drilling almost 23,000-, 24,000-foot wells there. We're drilling 9,500-foot laterals. And for comparison in the Eagle Ford, which is a much easier place to drill, we are drilling in there for this year average around 1.4 to 1.6. And we're drilling in there in the twos now. And just this morning, we set another record setting well there. It's really going well, because we're now doing some pad drilling. And I see it long term in the twos there. And we've improved it 20% and 30% over the last three months.

Got you, okay. And then what about on the completion side?

Completion side there is - we're probably total cost on these things in the $8s right now, needing to get it to $6.5, which D&C combined. We're probably in the $6 range on the completions and need to pull that down into the $4.5 range. And the whole issue is really around more pad drilling and completion that we're doing this year, but we need to build water management systems. It's not a very large amount of CapEx, but the permitting and organizing that, we're working on now. And we can - when we pull the water and not have to deal with the trucking of the water, it's going to be the next step change in the Duvernay. And actually, some of our 2,000-pound or the big Eagle Ford or U.S. size fracs work well for us more on the infield of a pad. We've been using a lower sand per foot of around 1,100, and of course, those completions are a lot cheaper. So it's - we're not finding that the entire field is going to need to be developed with a 2,000-pound frac at this time. So the water management and the reduction, and you're still getting the results out of the lower sand, which is a positive surprise for us, it's going to lead us to get to this range. And when we do, we're going to have some really, really nice breakevens there, because if the royalty is 20% less, that, Pete, as you know to the…

Yeah, okay. Great. Thank you, Roger. That's helpful. And then second, forgive me if I missed it, but how much cost inflation are you baking into your capital budget in the Eagle Ford in 2018?

Well, way we have it today, our current long range plan and budget is based in the low-50s. And we have our service cost based on what we were seeing in the fourth quarter for all those services. We also have some unique procurement arrangements that puts us in a pretty good situation. And as I said earlier, we're not just an all-onshore company, as everyone knows, and so where not all of our CapEx is exposed to that. But when we look at what's going on there, we have around $480 million in North America on drilling and completions. On our Eagle Ford Shale market, our inflation, what we see outside from our study is around eight, and we feel from our procurement agreements, we're at risk of about five. We have not seen that yet. And the same on operating expenses. And what's really the big driver is disposal of fluids, and we're really good shape on our rigs. And while the fracking could go up slightly, we're in pretty good shape on that. So all in all, we see a risk here of our total business of OpEx, Canada and U.S., around $40 million to $45 million. The way we got things procured right now, we can easily handle that with a couple of dollars, increase in our $52 or $50 to $55 budget. So I think we're pretty well positioned from what we see at this time.

Okay. Thank you, Roger.

Thank you, Pete. Appreciate it.

Thank you. Our next question comes from Pavel Molchanov from Raymond James. Your line is open.

Thanks for taking my question, guys.

No problem.

You're working to begin an actual exploration program in the Mexican portion of the Gulf. I'm curious what the fiscal terms look like. Obviously, a lot of question marks about the Mexican government's willingness to provide acceptable terms. So what's kind of the framework that you're operating under?

We have a royalty agreement that we bid on the particular block we have. So, our block came with a well commitment and a royalty commitment, that we feel that we can make above 30% full cycle at low-$50 that we would have - could not have participated. So it's a situation involving a royalty straightforward and an additional royalty that you bid. And it places us - and I don't have the specific royalty in front of me right now, but we are in a good position to make the rates of return that we're looking for there. I just found the royalty. It's 26.9 tax royalty type scheme that we have there today on our block.

Okay, okay, interesting. And then, on Vietnam if you are to reach final investment decision on the Cuu Long Basin, number one, what's kind of a development CapEx that you're anticipating for that project? And secondly, what timetable to reach first production on that?

Yeah, it's a fairly going-to-happen project. We have 20 some odd millions of success payments to the - to our partner, PetroVietnam, because we farmed into the well very inexpensively during the oil collapse, which is our game. And we will have to pay a payment on commerciality and on fuel development plan, which is in the money that I spoke of earlier today in offshore. And we're dealing with an 80 million to 100 million barrel field here. There's a big upside to it, when we drill the exploration well later this summer. And it will have of course a competitive development cost in the $15 range. And if you multiply $15 times 100 million barrels and take out 40%, that's the kind of cost we're dealing with at this time. But it's a really nice startup project for us, and we really feel that we can build up to a 20,000 a day business in Vietnam over the next few years. And this project will be around 9,000, our share, starting in 2021.

Got it, appreciate it.

Thank you.

Thank you. Our next question comes from Ryan Todd from Deutsche Bank. Your line is open.

Hey, Ryan, how are you doing?

Good. Thanks. How are you doing, Roger?

All right.

So, a couple of questions for you, maybe one follow-up on Eagle Ford CapEx. What's the - I guess can you walk me through the drivers of the CapEx? I mean, the well-count is down 50% year-on-year. The CapEx is down a lot less. Is that a function of increased lateral length? Or what are the drivers of spend there?

Well, if we look at our detail of our capital in Eagle Ford this year, we have $330 million in there and then we have in drilling and completion $230 million. So I think if you'd back that out, you'll find the costs are averaging like we said earlier, $5.5 million each. And then we have, in the Eagle Ford Shale, $94 million of additional field-development of batteries, separators, facilities. And we're doing a major electrification project there that lowers our operating spend and we've been very successful at doing that. And we're little behind on field development there in the last couple of years there. And again, the capital allocation is around starting with our cash flow, in the low 50s and needing to do our required work in Kaybob, which we're glad to do, and have our offshore spend that I talked about earlier, which are incredibly economic projects, best you can ever have, over 100% primarily. And you go back to what we need to do and it leaves the Eagle Ford short, wish that wasn't the case, but that's the case we have. And then, we're going to allocate capital temporarily out of it and then back into it strongly. We're also going to deliver lot of free cash flow and maintain that business around a 46,000 a day business. And I think that's a pretty good business. So that's what we're doing today with it, Ryan.

Okay, thanks. That's helpful. And then, maybe...

I know you're really excited about it.

You mentioned the Kaybob. I mean, can you talk about - within your Duvernay position, I guess the relative priority or the preference of the - you got a number of different operational areas listed there in your slides. I mean, is there - where is the relative priority and preference within those areas? And how do you think about the - as you shift the development, both in 2018 and 2019, what would that look like? And is it a function of broader capital allocation and availability at this point in the portfolio or are there other kind of technical drivers that you need or thresholds that you need to meet to move towards greater development there over the next couple of years?

We're in an agreement to drill across various parts of the play before we go and just spend all of the money on development. So drilling a well in the Eastern area called Two Creeks, it's on Slide 15 and then some more there in Kaybob East. We've greatly de-risked the dark blue area, Kaybob West this year. And I - my personal feel that over time the Simonette and the Kaybob West and the Saxon will be the better places to allocate capital. And we're seeing very good start in our Simonette area. It's near some of our prolific peers in that area. And we see the project getting oilier; see costs coming down. We just - every well we drilled on the dark blue is over our expectation. And now from the very early days in the yellow area, the Simonette area, we're going to be in really good shape there too. The more risky areas in my mind are the Two Creeks and Kaybob East areas. We have a requirement to drill some wells there. We're going to do it, then make plans around which areas to allocate capital to going forward. And that's in our plan now, that's more weighted towards those other areas. And we'll go forward with the results there at this time.

Okay. And your ability to push towards development mode is…

Well, this year, we are - I guess, one way to look at it, if you look at the wells we're delivering this year. And you start seeing one or two well pads and then you see a mixture of three, four and five well pads, those are development things if you're drilling full wells. You must feel confident about having to add up that money. I'd say it's probably overhyped for money is on development mode primarily in the locations of D, E and F at this time. Both D and E are greatly de-risked by peers nearby, because all this acreage is leased. So we're already moving to a bit of that this year. And I'm saying over time, I believe the Kaybob West and Simonette will be bigger locations and bigger areas for us, based on what I know today. But I could be surprised with some of the results we see in the other areas. It is possible with all the areas we worked, because so far most of the wells have been oilier and have been above our expectation. I think we're in really good shape on it.

Okay, thanks. That's helpful. And then, maybe one last one, I mean of the - I know at heart you love to drill exploration wells as well. And when you look at your new exploration opportunities, what gets you most excited at this point? I know it's early.

It's not that I love doing that. I mean, it's a part of making money and doing business. That's where we made an enormous amount of profits in our company through the year, with enormous full-cycle rates of return. That's why I like it. We have a really nice position in Mexico and our seismic is really coming together there to de-risk our prospects. I'm not sure if you followed the lease sale yesterday. We failed to pull together groups that we like, because it got so expensive. And there were hundreds and hundreds of millions of dollars of bonus paid down there yesterday, making our original block now very, very promising, because we didn't pay those said bonuses and have a better economics in our friends there. Our tieback system in the Gulf, our Samurai well has really come together with a lot of success around that area. But one of our partners has a lot of knowledge about that said success and has entered with us. I'm not discussing who that is and what's going to unfold, but that's looking very favorable. And our King Cake prospect has all the amplitudes where we've now partnered with a group of very successful explorers in Houston. They're in search of an operator, which fits our background, where our geologic teams work with theirs. And they need an operator to execute these wells. And we're very proud of these new relationships, a totally different way for us working in the Gulf. And, of course, Brazil with Exxon, technical meetings ongoing there, very, very happy with what we see there, very near major fields. And Mexico, we'd be near major fields. And our two wells in the Gulf are near success. And then in Vietnam, we already have a discovery, and we're in the move and just going forward there. And our blocks in Australia, home - built in the Vulcan Basin are very, very good as well. But right now, I'd say Mexico, late this year, our two Gulf things are very promising. And then down in Brazil in 2020 should be a really good situation for Murphy.

Great. Thanks, Roger.

Thank you.

Thank you. [Operator Instructions] Our next question comes from Brian Singer from Goldman Sachs. Your line is open.

Thank you. Good morning.

Good morning.

Hi, Brian.

I wanted to touch on - hey, want to see if you could touch a little bit more on Slide 12. You mentioned in your comments and highlighted the improvement that you've seen over the last couple of years in Eagle Ford well performance. And wanted to see what your outlook was on the program that you have and the broader portfolio for 2018. And then also beyond the 30-day IP, whether this type of increase is translating into EURs directly or whether it is a different level of increase.

The trending is getting better on the EURs, but we are getting the oil out of the ground sooner. I think some of our peers are boring wells down probably harder than us through the last few years. But it is leading to a different profile of the curve. And I'd - off the top of my head, I'd say the EUR curves are going up 10% or something in that effect. But the real action is getting the oil out of the ground earlier. Kelly has the breakdown of where we're drilling this year in 2018. Down there, we have 30-something wells we talked about earlier. I'm not sure how many in Catarina. Kelly, you have that?

Right. So the well cadence for the year, Brian, is in the first quarter, we have 10 wells that we're bringing online, and those are all in Karnes. And then, in the second quarter, we have six Tilden wells and four Catarina wells, for a total of 10 also. And then moving into the second half of the year, for the third quarter there are eight wells, two in Tilden and six in Catarina. In fourth quarter, there's 10 wells, four in Tilden and six in Catarina, for a total of 38.

The Catarina has taken a good bit of our capital. And going forward, we have hundreds of locations there. We have some downspacing we can work on there and it's going well for us. I think the main thing, from the well count and the perspective, is it's not just Lower Eagle Ford Shale. The Upper Eagle Ford Shale wells are delivering there as well. And it opens us up for hundreds of our locations to be further de-risked that already have a low breakeven count.

Hello.

Looks like you went off, Brian, you can call back if you'd like. Sorry, about that.

Thank you. And our next question comes from Leo Mariani from National Alliance Securities. Your line is open.

Hello, Leo. Good morning.

Hey, good morning here, guys. Just wanted to follow up quickly on your Eagle Ford comments there. Just kind of looking at your - your fourth quarter production is around 51,000 BOE per day. You guys talked about 46,000 to 47,000 in 2018. Can you talk a little bit about the production cadence this year? Is it going to kind of slowly decline throughout 2018? And, obviously, you guys are talking about it's starting to ramp back up in 2020 to 2022. How should we see that production progress throughout 2018?

We're looking this year, if I rattle off the quarters to you, around 45,000 to 46,000, 47,000 second quarter, 45,000 third, 46,000 47,000 in the fourth, very similar to last year. We had a severe offset, frac impact to this at both Catarina and Karnes at the same time, right around the end of the year, knocked out five of our best wells and around 12 wells in Catarina. These are recovering, but takes some time to recover. These things happen. We haven't been exposed to it in a while, and it also happened at two places at once. We're experimenting now with these real mega large pads, do a 10 - we decided to do a 10-well pad in Karnes, across two leases. We're at 10 wells on a contiguous line. And that's going to put that production not coming on until later. So we offset the frac and the - and then switching to a 10-well pad, which of course is very economic for us, has pushed down our production starting off the year. It's kind of led to this even style of production we have. But I think keeping production in this level and a CapEx of $330 million kind of CapEx, only 200-and-something drilling. It's pretty monumental actually. And I think even at low 50s, it makes $500 million of free cash or something that effect.

All right, no, that's helpful. And I guess, just another sort of production-related question. So looking at your guidance here, you guys are talking about 164,000 to 168,000 BOE per day in the first quarter, full year guide of 166,000 to 170,000. Just wanted to get a sense of whether or not you expect sales volumes to be different than production. And maybe you can just kind of talk to that as that's something that you guys, I know, have spoken to in the past.

Yeah, our - sorry, our sales volumes are holding at slightly above based on our lifting schedule that we have so far for the year. So it looks really good, and then looks to be impacted negatively at all. It's probably slightly better than our production forecast.

Okay, that's helpful. And, I guess, you guys obviously were kind enough to provide this five-year forecast. You talked about significant free cash flow. After your dividend, you certainly spoke about keeping a strong balance sheet. Undoubtedly, if oil prices creep higher and your production goes up, your balance sheets can continue to improve. What do you guys see as kind of the best uses of that $500 million in incremental free cash flow? Is it - are you guys committed to starting to increase the dividend in a material way? What can you kind of say to that?

Well, we haven't had a plan for that. We had two years of a total collapse beginning in 2016. It went down almost the whole year. And so, we have about five weeks here, glory, I suppose. And we - typical to any company, as I said earlier, we had cash on the balance sheet, we're looking at accretive to free cash flow, providing M&A at this time. We always have one of those opportunities going, which will reduce our cash quite a bit, of course. And we would have the typical go-to things. We have some bonds that are due in 2022. We could de-lever and improve all the debt-adjusted share-type metric things very easily with that. We can have a combination of that with dividend. We've been a strong dividend-playing company, and I hope that people recall all the write-ups that I hear about around here about free cash flow. We do pay a very large dividend. So if we had a much smaller dividend, we'd have much larger free cash flow, so the typical things, de-levering, opportunities. As I've mentioned earlier, I'm very excited about exploration. Exploration success could drive a good bit of capital. We have a risk. And it's very important in our plan to realize that that CapEx has a risked development without the production. Moving that production lift will require some more capital to do that, which we'd be able to do easily without taking on additional debt, trying not to take on debt, trying to de-lever, want to reward our shareholders and have a strong balance sheet. Among all those three, we'll prove that out as we go. We'll need more than five weeks in the $60s for me to do that right now.

Okay, that's helpful. And I guess you guys did speak about cash repatriation in Canada here in 2018. Obviously, these tax laws are pretty beneficial that were just passed. Any other material tax-free repatriations expected over the next couple of years and if you guys still have quite a bit of overseas cash here?

I'm going to let John address that. He's just really helped us out on all of the retained earnings and all of the cash that we have abroad, and where we can move with some things we're changing and some intercompany issues we had through the tax reform matter to close all this out. So we can touch all the money when we need, move Malaysia straight to the U.S. And then our only out will be a 5% Canadian withholding tax, which will not go away and is part of the law. But we've accrued now some money to allow that for lot of cash to be moved over the next few years, and we're greatly positioned by this tax reform. John, could you add something there?

I think that Roger has pretty much said it. I mean, Malaysia is going to be generating a significant amount of cash flow over the years. We can tap that money. No impact from withholding tax, because we do have the 5% withholding tax in Canada. Canada has a good bit of cash and so that's available too. Just have to pay the toll of bringing it home, but that optionality exists for us, and it's all in the nature of good news for us in terms of what we need for U.S. operations.

And also, it's very beneficial for us to have a 21% tax rate over a 35%, because we look at increasing in this plan our Eagle Ford business. And we're looking to drill wells in the Gulf and developing the Gulf. And those two businesses get a - while people may not like the Eagle Ford Shale CapEx, there's still a lot of capital between there and the Gulf, and we can have great returns with the 21% rate and compete internationally well now. So there's a big NAV help for us, this tax reform as well, so very positive.

All right, well, that makes sense. Thanks, guys.

Okay.

Thank you. And I'm showing no further questions from our phone lines. I would now like to turn the conference back over to Roger Jenkins for any closing remarks.

Thanks, everyone, for calling in today. Appreciate it. And we'll be seeing you at the end of the next quarter, and thank you very much.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a wonderful day.