Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2018 Earnings Conference Call. I would now like to turn the conference over to 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 new to the Murphy team, David Looney, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we have posted on the Investor Relations sections 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 2017 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 Roger Jenkins.

Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. First quarter production was 168,000 barrels equivalents per day, at the high end of our guidance at 58% liquids. We achieved adjusted income of $40 million, our highest level in 12 quarters. Capital expenditures for the first quarter was $300 million. Our program for 2018 is front-end loaded, with the majority of the capital in the first quarter allocated to drilling activity in our North American unconventional plays. We expect to spend about $55 million of our 2018 capital for 2018 in the first half of the year. Our diverse oil-weighted asset base, primarily at Brent/Malaysia Crude Oil selling price, which is a premium to Brent, and LLS delivers high margins, generating a very competitive first quarter EBITDAX of approximately $27 per barrel equivalent. Murphy has always been focused on returning cash to our shareholders through our 50-year dividend policy. In the first quarter, we returned 16% of our operating cash flow to shareholders. We're creating long-term value by participating in highly economic offshore projects in a countercyclical move. We're turning to focused strategic offshore exploration with low-cost entries that have no well commitments, with the lowest cost for drilling we've seen in decades. Since we operate in plays that are not pipeline-constrained and our production has minimal pricing exposure to WTI, our diversified oil-weighted portfolio receives premium pricing. In the first quarter, our weighted average price was over $63 per barrel for oil sold, with oil comprising 52% of our sales with a small volume of NGLs comprising 6%. This represents a 24% increase over full year 2017 weighted average pricing. Our Brent barrels are now receiving a $7 premium to WTI and our LLS weighted barrels are near $4 premium to WTI, a very…

Thank you, Roger, and good morning to everyone. Consolidated results in the first quarter of 2018 included income from continuing operations of $169 million or $0.97 per diluted share compared to $57 million or $0.33 per diluted share in the same quarter one year ago. Our adjusted net income was a profit of $40 million or $0.23 per diluted share in the first quarter of 2018 versus a loss of $10 million in the comparable quarter last year. The adjusted income varies from our net income primarily due to a $120 million credit associated with a clarification of the 2017 U.S. tax reform, along with foreign exchange gains of $12 million and an $11 million mark-to-market loss on open crude oil hedge contracts. At March 31, 2018, Murphy's total debt amounted to $2.9 billion, including capital leases, or 38% of total capital employed, while net debt amounted to slightly less than 30% of capital employed at $1.9 billion. As of March 31, 2018, we had no outstanding borrowings under our $1.1 billion revolving credit facility. Worldwide cash and invested cash balances totaled $940 million at quarter-end. I will now walk through some of the nuances of our first quarter results. Operating expenses for the first quarter were up over full year 2017 due to workover expenses at Kodiak and additional expenses associated with offset frac impacts in the Eagle Ford Shale. Looking ahead, scheduled routine maintenance at several of our offshore facilities are expected to drive company-wide LOE per boe slightly higher in the second and third quarters of this year, offsetting the solid progress that is being made in our onshore plays with respect to LOE. However, we still expect full year 2018 LOE per boe to be in our usual range of $8 to $9 per boe. And notwithstanding the impacts of these maintenance projects, due to our excellent crude netbacks, these offshore properties are still some of the highest margin properties in our portfolio and a major reason why we are once again able to record EBITDA per boe at the top of our TSR group, as Roger has already mentioned. The $120 million net income benefit in the deferred tax provision was partially offset by a provision for current taxes in both Malaysia and a small one in Canada. Additionally, a one-time withholding tax payment of $35 million in Canada due to the repatriation of $700 million to the U.S. had the effect of lowering our cash flow for the quarter, which came in at $278 million even after this one-time payment. Roger will now present a review of the company's operations.

Thank you, David. We're on slide 9. During the quarter, we brought six wells online in Eagle Ford Shale, all of which in the Lower Eagle Ford Shale wells in the Tilden area. These wells are completed using our Gen 5 completion technique, which resulted in significantly higher IP30s than previous wells in that area. For the remainder of 2018, we plan to bring on additional 39 operated wells, which includes seven more Catarina wells than originally guided. Our drilling performance has dramatically improved since 2012. We have lowered our drilling cost per foot by approximately 50% to $115 and increased our penetration rate by over 135% to almost 1,800 feet a day drilling in this play. These improvements have led to structural cost reduction we've been able to maintain even with upward pressure and service costs. For example, our 2017 cost per foot was approximately $117, while our first quarter 2018 drilling costs were below that at $115 per foot. Slide 10, our Tupper Montney continues to prove itself to be one of the lowest cost dry natural gas plays in North America. During the quarter, we drilled the remaining three wells of a five well pad with four consecutive pacesetter wells. The best well achieved a drilling cost of $83 per foot in just over 12 days at a measured depth of over 17,500 feet. All five wells with an average EUR of approximately 18 BCF was brought online in the second quarter. Murphy's marketing group continues to do an outstanding job moving our natural gas off of AECO market pricing. In the first quarter, our netbacks in the Tupper Montney including transportation were CAD 2.20 AECO per MCF, well ahead of spot prices. We're continuing to have competitive returns in this play as our full cycle breakeven…

Thank you. Your first question is from Brian Singer from Goldman Sachs. Brian, please go ahead. Brian Singer - Goldman Sachs & Co. LLC: Thank you. Good morning.

Morning, Brian. Brian Singer - Goldman Sachs & Co. LLC: I wanted to pick on the exploration points that you made here, as certainly with the costs that have come down in the offshore, it's very unique. Can you talk about the cycle times for the type of prospects that you're planning to drill? And if you are successful in the Gulf of Mexico, Mexico and Vietnam, what are the next steps that we should be looking out for?

Thank you, Brian. I appreciate that question. Starting off with our Samurai well, we are drilling that well today. We're probably over a third of the way finished with the well. We expect that well to TD in mid-June. And for a $30 million net well cost to us, it's really nice net, mean barrels and very nice metrics on a dollar per barrel basis. So, what happened there, our partner is very successful in this play and the upside of this is we'll be into a larger structure in that region and a real big successful upside would put that into a pretty large development. If not and we're back to the mean barrels, there's a lot of infrastructure, and by including our own frontrunner, we should put this thing probably in production in two years tops. If it gets into a larger production, probably three-and-a-half-year-type basis. But there's a lot of infrastructure there, a lot of facilities there. There's also another party that's now our partner in other wells that have a success nearby that are also in the development mode. So, we've lots of opportunity for smaller development, and of course opportunity for a big discovery here, but it'll take slightly more time. So, this is pretty fast cycle time. Actually, even on a bigger project of three years, I feel comfortable with that. If we look at King Cake, that's a well we moved to and spud in the third quarter. We expect to be finished with that well around mid-September. Again, this is a smaller size opportunity, but very, very economic, fitting all of the measures we're looking for, F&D of $15 a barrel, full cycle, 30% returns at the price that we use. And this, too, again would be a typical tieback opportunity in…

Yeah. Our Eagle Ford business is – we've been touting this as a flattish production profile now for some time. We are probably, I believe, David, $135 million of free cash in there this year at least.

Yes.

At very conservative prices, probably around $4 less than we see in the strip today. So, I would anticipate that the Eagle Ford business will be a 44,000 or 45,000 kind of business for us for the rest of the year. Just got off to a – and the point of that is that I reviewed this very closely in Houston a couple weeks ago. This is a very unique circumstance that happened to us. In Catarina, if you could picture an L-shaped acreage that we had there, and we had nine of the best wells we've ever had there, and a nearby operator, Chesapeake, great company, came in next to us and paralleled four of our best wells and went toe to toe with five of our other best wells. And it's caused a big impact to our production that we had to recover from. Drilled out sand and our wells produced a high level of water and it impacted our OpEx in the Eagle Ford. Now we have those wells recovered. And on the other end of the spectrum in Karnes County, BHP went in next door, our partner in Samurai, and killed our best Austin Chalk wells. They're some of the best wells in the play, and did not produce the wells, causing us to take the water off. So, it's a real perfect storm for us there that knocked us back in the first quarter quite frankly. And now, our capital allocation there, it's about the same as we had, but we did note today that we moved $21 million from the Montney because the wells are so prolific in the Montney. And we moved money from Canada down to that asset and adding seven wells, primarily weighted toward late quarter two and quarter three. And…

Thank you.

Thank you. Your next question is from Arun Jayaram from JPMorgan. Please go ahead.

Good morning. Roger, I was wondering if you could comment a little bit, as you get more active on the exploration front, how do you assess data, your interpretation, your team, as you progress on this next set of exploration versus where you're at a couple, two, three years ago.

Well, we have a lot of things changed in our company. If you really look back and look at our slides that we published today about our new strategy, it's a totally different strategy and the number one part of it is focusing just in four places. In the Gulf of Mexico, we have two things going on. We formed an exploration alliance with a privately-held exploration company that has about an 80% success rate on amplitude, tiebacks, smaller opportunities. We've expanded that into a certain acreage area. Let's call it, divide the Gulf between Lake Charles, Louisiana and Tampa, and you take the bottom half, and we'll work with them there. And our team is concentrated with data sets up in the Mississippi Canyon area, all focusing on Middle Miocene tiebacks and larger low-salt type prospects as well. So, that's a new change. We're working with another party that has enormous access to seismic, in which they deliver prospects to us, and they do not operate and we're going to be their operator. There's been some very, very successful firms that do this in Houston and we are an operator of choice and a preferred partner to do that due to our long-term history of drilling and executing and producing globally in deepwater for a long time. So, that's how we're attacking that on that front. The seismic data in Mexico, again, when we look at going into these plays, what's changed in exploration this time post the oil boom is that there's an enormous amount of data that you can purchase very inexpensively in Mexico. In the past, you were leasing acreage on 2D data with a commitment to shoot 3D data and making well commitments without 3D data. This was taking place all over the world and…

That's great. And just at Samurai, this is, I understand, an appraisal well. Can you remind us about the discovery well? What you found there? And kind of just set the stage of what we're looking for. It sound like the results will be in by the end of 2Q.

Yeah. We discovered with our partnership group at that time, I guess, around eight years ago or so, probably almost 240 feet of pay. There is a series of upper zones called M9, M10 up in the shallower part of the well that was a discovery. And then, we drilled through the Middle Miocene section and found one of the zones to be tight and one of the main prolific M14 zones of that region was faulted out in that particular well. So, after a lot of work on seismic and working with our new partner, we discovered this zone does exist off that original structure. So, one the largest four-way structures in Green Canyon. It's the most sought after block in lease sale years and years ago. And we are now drilling our structure for the missing M14, and then delineating the zones that were drilled up that were discovery. And then, we will take – either both will hit, one will hit. And there's also a new zone, deeper than this, that have been found and other wells in the region we'll be drilling too. And have about three different choices here to find hydrocarbon in this well.

Great. Final question would be, can you just help us a little bit, Roger, with how the sequential production could play out in the Eagle Ford? I think you're going to – have some more Karnes wells in 2Q. But just give us a little sense with some capital allocation coming back to the Eagle Ford, what the quarterly trends could look like in the Eagle Ford?

Kelly is going to go with the well – the well count for you.

Sure. Arun, so we're looking at completing a total of 45 wells that are operated by Murphy. And so in the second quarter, there's going to be 22. 10 of those are Catarina, 10 of those are Karnes and we're going to have two Tilden wells. And then, in the third quarter, we're going to have 4 Tilden wells. And in the fourth quarter, we're going to have 13 Catarina wells. And so I think it's important to note that when you look at the well cadence, that in the second and the third quarter about 60% of all the wells that we're going to have are going to come online in those quarter. So I think that kind of drives the production. So, first, second and third quarters are fairly steady eddy. And then, that's going to drive our fourth quarter production in the Eagle Ford to be, I think, in the neighborhood of...

45,000.

45,000. Yeah.

Okay. Thanks a lot.

Thank you. Appreciate it.

Thank you. Your next question is from Pavel Molchanov from Raymond James. Please go ahead. Pavel S. Molchanov - Raymond James & Associates, Inc.: Thanks for taking the question, guys.

No problem. Pavel S. Molchanov - Raymond James & Associates, Inc.: So, you guys are part of that consortium that won the Alagoas Basin blocks in Brazil. I think Block 430 and Block 573. You do not have any well commitments as I understand. So, given that you're not tied to a particular spending rate, what's kind of the plan for those blocks?

There's no well commitments anywhere in Brazil. There's one well commitment in Mexico, none in the Gulf and one in Vietnam. So, really don't have many commitment wells in our company. I have a real good friend, a partner in this project that really doesn't want me to talk about it a whole lot quite frankly. And so, I have a big partner there and we're going to be going through seismic. There's 3D seismic being shot there today, a big shoot across all this acreage. We've many prospects there, many prospects near, big discoveries there, very close by, very tight geologically. And we're very, very pleased to have it, but probably not going to be talking a whole lot about the drilling cadence at this time. But it's a big exploration project that's being executed by ExxonMobil and our partner in Brazil and we're very, very pleased to have it. Pavel S. Molchanov - Raymond James & Associates, Inc.: Understood. And then, in terms of capital allocation, you've talked about your EBITDA targets based on your price stack. If we look at strip pricing, you'll more than cover the full CapEx budget and your current dividend payout. To the extent that you have surplus cash flow beyond CapEx and the dividend, would you be more inclined to maybe getting the dividend back to where it was before the haircut a couple years ago, or would you be more inclined for resuming share buyback?

Well, we didn't issue any at the bottom, so that's why we're not buying any back. So, we didn't issue any in 2016, one of the only companies not to do that. I hope people will remember that. And our dividend policy was a long-term policy. It was reduced. I think now, naturally, we consider and we'll look at harder to go back at some level. I wouldn't see us jumping right back to that level. Of course, I've discussed this with our board. It's always a discussion we will have primarily later in the year. I wouldn't see just jump right back to that level, but we have to get back in the net income, making business here. And our retained earnings account being positively impacted by that, which are off to a good start, making $40 million of adjusted income and a good bit of income from that tax. And while it's adjusted out, we earned that income from that tax. And we deserve that net income that we've received on a rolled up basis like we used to years ago before we went into adjusting everything there is to mankind. So, we need to get back to make sure we're making the net income levels to cover the 100 and something plus dividend, and we need to make every year. We're on our way of doing that. That's the first step. And we clearly have the cash to do it. And we'll be studying that and looking forward to these processes, making that backwardation pull up a little bit before making that call. And it's one of our focuses for the rest of the year. Sure. Pavel S. Molchanov - Raymond James & Associates, Inc.: All right. Appreciate the color.

Thanks.

Thank you. Your next question is from Roger Read from Wells Fargo. Roger, please go ahead.

Yeah. Thank you. Good morning. Good morning, Roger.

Hey, Roger. How are you doing?

Well, we're getting towards the end of earnings season. So, doing a little bit better.

You're right about that, Roger.

Hey, can we come back to the CapEx rise, roughly $50 million, 5%. I'm just curious about the projects that you're going to fund here. Were these projects that were sort of the next ones on the queue when you were laying out your budget end of last year, beginning of this, or are they more projects that have come to the fore since then? Just trying to understand kind of maybe the ranking of things and maybe if anything's changed in the returns, either because oil prices are up or the projects look better? Just kind of little help there.

The way we do our exploration budget is that we have about four, five opportunities sometimes across the world. And we put them in as a factor of are we going to do those wells, like, one well may be chance of doing that at 30%, 40%, 50%, sometimes 100%, if it's a commitment well, something to that effect. So, that gives us so much capital for exploration. Then as the year goes by, we solidify that. So, Samurai's a very sought after opportunity with a lot of success in that area. And BHP took out one of our partners there. And then we had four, five companies wanting to take the other piece from the other partner that left. And we then were able to look at some information through our partnership group, and make a decision, we wanted to go up on that 50%, and that drove a good bit of our CapEx move. And because we do that, we want to be around 35% in exploration, but really it's the delineation back to my answer over prior call of some prior pay that we drilled in that area. So, then, when we pull out the ones we're not going to do, pick the ones we're going do and increase our working interest on a delineation-type well, our capital went up. At Medusa, we had a well, had a regulatory problem on – a casing pressure issue, it had to be abandoned. So we're going to abandon that well, but we have another zone we can recomplete into, which would be slightly more expensive. And we'd also didn't have the abandonment in our capital plan. So, we went ahead and completed the well. And it was flowing at a very, very nice rate with just two or three…

Okay. Thanks for that. And then just kind of two maybe more basic questions. One, the longer-term outlook you laid out, $57 WTI. Are you assuming a similar price for Brent? And then the second question, just service cost trends as you see them across – kind of give us what you want, but thinking mostly lower $48 in Gulf of Mexico?

Well, I mean, obviously, our prices are used in our LRP, a long range plan we call it for this year lay over, but we do have some hedging in there. Our current plans are below strip. I think we're probably looking at a quarter two WTI $64, $63 in the third quarter, and $61 in the fourth quarter, conservatism to that, bit of backwardation there, probably really good position compared to that. And our Brent, we normally take it about $4 over, but today it's $7. So, we're pretty conservative still on that and I think pretty well positioned on that. And what was your next question, Roger?

Service cost.

No, everybody is keep crying about service cost, and we really are rolling along pretty well. I think if you look in what I said in the script, it's mindboggling really for our Eagle Ford business as it continue to drill. I mean we know there's – we thought there's a 10% chance of cost going up in the Eagle Ford on drilling and probably 10% to 15% on completions. But at the end of the day, the cost per foot of the 18 wells we drilled in the first quarter versus what we had in 2017 is slightly lower, so we continue to execute there. And we're really well positioned. Our procurement teams and our management team for Eagle Ford have done a great job. We have a one frac company for all of North America now. This brought us incredible savings with some really, really good rig rates, with some rig rates tied to oil prices that's nicely positioned for our company. And we're just not seeing it. And if we do, it might would be around – I calculated it yesterday, it probably be around $20 million to $25 million. It could go up on completion through the rest of the year. But, Roger, we can afford it, so.

Well, that's good to hear. Thank you.

Thank you.

Thank you and see you soon.

There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks.

Appreciate everyone calling in today. And you need to get back with our IR team if you have any questions. And we look forward seeing you in the next quarter and thanks for everything. Appreciate it.

Ladies and gentlemen, this concludes your conference call today. We thank you for participating and ask that you please disconnect your lines.