Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Second Quarter 2018 Earnings Call and Webcast Conference Call. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thanks, Pamela. Good morning, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer; and David Looney, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we have placed 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.

Good morning, Kelly. Good morning, everyone, and thank you for listening to our call today. Our second quarter results clearly validate the strength of our diversified portfolio, as robust production from our oil-weighted onshore and offshore plays continued to drive high margin realizations. This enables us to return 13% of our operating cash flow to our shareholders through our longstanding dividend policy. We've also achieved an annualized EBITDA per capital employed of 20%. Our adjusted net income was $63 million and we maintained our balance sheet strength. Production for the second quarter averaged 171,000 barrels equivalent per day at 59% liquids. Production exceeded the high end of guidance by 2,000 barrels of oil equivalent per day. This beat was driven by outperformance on our onshore Canada and Gulf of Mexico assets with the liquids production accounting for 50% of this beat. As we look to the strengthening of our portfolio, we achieved exploration success at our Samurai-2 well in the Gulf of Mexico, and our onshore business were able to show continuous improvements in cost reductions by achieving our drilling and completion cost goals in the Kaybob Duvernay of $6.5 million per well which is well ahead of our target date. In the second quarter, on slide 4, we continue to successfully execute our focused strategy. We've returned to offshore exploration with successful Samura-2 well just mentioned. And in Vietnam, we've worked with our partner to assume operatorship for the 15-1/05 Block which shows the existing LDV discovery and will increase our working interest there to 40%. Our teams delivered excellent operational performance in the second quarter, and the Gulf of Mexico production exceeded guidance by some 1,700 barrels equivalent per day driven by better performance and uptime. The Kaybob Duvernay continues to exceed our expectations with production increases by…

Thank you, Roger, and good morning. We're now on slide 7. Consolidated results in the second quarter of 2018 included net income of $46 million or $0.26 per diluted share compared to a loss of $17 million or $0.10 per diluted share in the same quarter one year ago. Our adjusted net income was a profit of $63 million or $0.36 per diluted share in the second quarter 2018 versus a loss of $19 million in the comparable quarter last year. The adjusted income varies from our net income primarily due to a $10 million after tax mark-to-market loss on open crude oil hedge contracts and foreign exchange losses of $7 million after tax. At June 30, 2018, Murphy's total debt amounted to $2.8 billion excluding capital leases or 38% of total capital, while net debt amounted to slightly less than 30% of capital at $1.9 billion. As of June 30, we had no outstanding borrowings under our $1.1 billion revolving credit facility. Worldwide cash and invested cash balances totaled $900 million at quarter end. In keeping with our stated goal of living within cash flow, slide 8 is a snapshot of our six-month cash flow statement presented on a GAAP basis and displays how certain one-off items negatively impacted us during this period, primarily two things: number one, the $35 million withholding tax on funds repatriated from Canada earlier this year; and number two, an inordinate amount of 2017 CapEx being paid in 2018 led to a greater-than-expected reduction in our cash balances at June 30. As we begin the second half of the year with $900 million in cash on our balance sheet, we expect that we will rebuild a good portion of this first half deficit over the remainder of the year given current pricing, production and CapEx mechanics. With that, I'll turn it over to Roger to review the company's operations.

Let's move to slide 10. During the quarter, we brought 26 wells online in the Eagle Ford Shale, 10 in Karnes, 10 in Catarina, and 6 in Tilden area. In the second half of 2018, we plan to bring an additional 13 operated wells all in Catarina for a total of 45 operated wells online this year. 10 well pad in Karnes at an average IP30 of 1,750 barrel oil equivalent per day, seven of these wells produced at the highest peak rates that Murphy's ever achieved in the Karnes to-date. The 24-hour peak rate for the Lower Eagle Ford Shale was some 2,300 barrels of oil per day, not BOE. And while the average 24-hour peak rate for the Upper Eagle Ford Shale was some 1,800 barrels of oil per day, again, not BOE. We have over 240 remaining locations in the Karnes area including the Upper and Lower Eagle Ford Shale, and plus our very successful Austin Chalk formation. We're also pleased with encouraging results from staggered lateral tests in Catarina, as well as recent IP30 improvements in the Tilden area. Our team also continues to lower drilling and completion costs, as well as operating expenses in this play. On slide 11. In the Tupper Montney, we brought a five-well pad online during the quarter. We continue to be impressed with the outstanding well performance in the play with these wells producing in line of our 18 BCF type curve. In the second quarter, our realizations in Tupper Montney were CAD 1.84 per MCF compared to an average AECO price of CAD 1.19 per MCF. During the second quarter, we approved the Tupper expansion project, a long-term project. It's 200 million cubic feet per day of production beginning in late 2020. The project is expected to increase reserves…

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session.

Hello? Roger, is that you?

Oh, I'm sorry. I didn't hear anything. Yeah, Roger here. Good morning. Strange price action off the quarter, but I thought your results were good, and the guidance was certainly favorable. Can you walk us through...

Yeah, Roger. Exactly right.

Can you walk us through how you're looking at the Gulf of Mexico exploration? And I'm just curious, the Kosmos transaction announced earlier this week, did you look at it, or is that the type of thing you might be interested in? And maybe a quick compare and contrast to doing a transaction like that versus the farm-ins that appear so far have been pretty favorable.

We really don't discuss ins and outs of business development too much, but you can safely say that any significant cash flow accretive, very good EBITDA multiple asset in the Gulf of Mexico, that Murphy is involved and looking at those as best as we can because we feel that's the best way for us going forward with all the value we can have with our operating ability and our long-term history of working in the Gulf of Mexico. In general, the Gulf of Mexico, for us, is really building up nicely. We've – working with a new group of an exploration shop to deliver prospects to us which we're drilling next to King Cake. We had this asset for a very long time at Samurai. We had to refigure all of our partners. And when we talk about our exploration strategy, it's really so – it's changed so much and so different now, if we could just get (17:52) people to recognize that. For example, we changed out all the partners in Samurai and brought in the new experience holder in the area that has great success and great acreage position in the area. That's what we call working with better partners. Our next well at King Cake has involved a successful exploration shop that has over 78% success. Through that, they're looking at the southwestern part of the Gulf and our teams are looking at the northeastern parts of the Gulf, building a nice portfolio to drill two or three wells every year. They range in size from tieback on everything to tieback plus facilities if they're larger. And they're building a very nice position and tying that in and managing that with the same team in Houston and our Mexico Block 5, one of our most prolific blocks, appraised in the nicest prospects I've seen in my career. And then we have the Brazil upside in that same hemisphere. So, a lot of positive action in the Gulf for us and momentum building in the Gulf, and we're very, very pleased with our Gulf of Mexico business.

Appreciate that. And then maybe just taking a quick look at the Eagle Ford Shale, you mentioned if I wrote the number down correctly, 248 well locations. I'm not sure if I got that right as we go through everything pretty quickly. But can you give us an idea – sorry.

That's just Karnes, Roger, I think it's 240.

Okay. Sorry about that. So, 240 in Karnes. You mentioned also the Austin Chalk. Can you give us an idea of maybe how that's evolved over the last several at least quarters if not years, and then maybe an idea of – we hear from a number of the companies, the core keeps expanding kind of how your core in Karnes County and some of the other parts has maybe expanded as you've delivered obviously record wells this quarter and continue to prosecute on that.

Well, we're doing very well and I think all of our acreage is prolific there. We've had some – our best well ever is in Austin Chalk well there, and we have some 50-something locations remaining which we're very happy about. It's just a matter of getting to them and staggered completions with that with the Upper Eagle Ford and Lower Eagle Ford and how best to minimize offset frac impacts, how best to drill a wine rack-type design which we're all over right now in all of our pads today are, even in Catalina and Karnes, are both drilling Lower and Upper Eagle Ford Shale with great success and just right to the curves that we have. And I don't know about the core expanding. We think of all of our acreage as core, and I think it's pretty clear where our acreage is located, it's core. It's also a real misnomer that I have about two locations left there which I think some people believe. I have hundreds left and it's getting better all the time, downspacing all the time. And it's a great part for us to work in there. But other areas are working, too. Our Catarina and the oil-weighted area is very, very successful. And our Tilden area is really coming on with lots of issues around staying in zone, better designing wells, better drilling, longer laterals, more completion, and positive moves there. And, all in all, it's a very good business and going to continue to be one for us for a long time.

All right. Thank you.

Thank you.

Your next question comes from Paul Cheng with Barclays. Please go ahead.

Hey, guys.

Good morning, Paul. How are you doing?

I'm doing very good. Hey, Roger, when you talked about the 240 in Karnes and if I'm looking at your presentation on page, I think, 29, it seems like it is 325, is that just the difference between the gross well and the net well for the working interest?

I would say so, Paul, yes.

All right. And you haven't talked anything about the Permian wells that you drilled early in the year. Are those wells that are being tied in or that you are still doing – or does it mean – is there any update that you can give us?

Paul, we drilled a couple of wells that didn't work out to our expectation there, and we have been really – with capital allocation like it is, we had some capital there, but with a $20 advantaged price over Permian to Eagle Ford, we felt like through the earlier part of the year we moved some money down there, and it's involved in the capital that we have today.

So...

But today in the press, you might have seen that one of the companies, FANG, has purchased acreage there which touches our acreage that we purchased on a lease sale there a couple of years ago. So now we have to re-evaluate that, and they paid a lot of money for that acreage right next to where we work. And this year, we were focused on our capital in the Eagle Ford due to the incredible price advantages that we have there over the Permian. And so that's the situation. I find it incredible that we ask the question about two wells in the Permian when we have a significant discovery in the Gulf of Mexico, Paul, but that's your question. That's your – yeah.

Yeah. We still want to get an update that on Mexico, are you going to drill one well in the fourth quarter and for the next year that in total, how many wells are you going to drill in Mexico, or that's just the only well?

That is the only well planned at present. We have many, many prospects there. We have many, many prospects there. We have many amplitude pay prospects with direct hydrocarbon indicators around our first well, and we have some very nice subsalt prospects there as well, and we'll be drilling additional wells there in the future. But we need to get our first well in and get that executed, and I'm sure we'll – based on that success and we're hoping for that success, I believe we'll be successful. We'll be looking at other wells to drill there.

How about in Brazil? Any kind of current plan has been formulate?

We are taking seismic there with our partner group. I think we're over 65% with the seismic across all the blocks in a very large seismic acquisition. And my big partner there doesn't like me to talk about it. So we're very, very proud of it, and it's a great position for us, and we'll be disclosing those plans at a later time.

Should we assume there is probably – any tuning (24:35) is probably 2020 or 2021 given that you...

That's a safe assumption on that, Paul.

Okay. And then a final one, I know it's early, on 2019 CapEx versus 2018, should we assume to be up somewhat or a lot a whole more or flat? Any kind of direction that you can give?

What was the question about 2019, Paul? What was (25:03)

2019 CapEx outlook versus 2018. Is it going – I assume...

Paul, your conference hasn't even come yet. I mean, we haven't even got football season going, real football. And I mean, it's going to be in a $1.2 billion range probably, Paul. I don't know. We're standing by our long range plan which is about that number. I don't see it to be significantly different from that, and we'll be disclosing that in January. But that's – there's nothing in our long-range plan, that I don't see it won't be the same or positive at this time.

All right. Thank you.

Your next question comes from Arun Jayaram, JPMorgan. Please go ahead.

Yeah. Good morning.

Arun, how are you doing this morning?

I'm doing well, sir. Roger, I wondered if you could spend a little bit more time on Samurai. On page 15 of the slide deck, it looks like the aerial extent could kind of extend into Block 476. So, I just wondered if you could give us your thinking about the sidetrack and down-the-road potential development options for the discovery.

Well, thank you for asking. No one's asked about it yet. We appreciate at least someone focusing on it, Arun. Yes. I mean, you can see all the green dots, and it's quite clear there could be a very large structure here. We're very happy with the results we have. We have a commercial discovery today with what we found and have many, many flowback options. We are contemplating and planning a sidetrack with our partner. It's a matter of the displacement. We're actually involved with some logging now that could pick what's the best depth and azimuth to drill that. It's highly likely the sands do thicken in the 476 block that we feel good about, so do our partner. And I would be surprised if we didn't do a sidetrack here. And there is a possibility of larger accumulations. We laid out originally a 75 million barrel of mean with an upside to 200. I mean 200 is a quite a big number. But it's not out of the question with what we have, but we're very pleased with 75 million barrels and I can tell you that your NAV estimate in your report for that on a per share basis is probably about what we lost today. So, yes, you're spot on with that share price improvement. It's a nice discovery, super economic discovery, great full cycle returns and low F&D costs, with just what we have today. So, we're very, very excited about it.

Yeah. And, Roger, I don't know if you could just walk us through what are potential development options. I know a frontrunner is somewhat in the area. Just talk us through what could in timing and what you're thinking about for development options here?

Well, what we're seeing are highly likely you have to drill another appraisal well because we've been successful, and a lot of these small tie-backs are just drill one zone and you'll bring them back. So prior to drill a well, you're finishing a year from now. Of course, that's what – they're partners and all that. And then if we sanction at that time, we could have an early production two-well system flowing in 2021, mid to third quarter 2021, some of that effect. The Christmas trees for something like this takes 18 months, if we're able to have continued success and want to buy some long lead items early, we could move that forward a bit, I suppose. Again, we'll have to work with our partners on that. And we would probably be going back to – there are three different host facilities. We have one of our own, and our partner has one, of course, in some nearby – a new facility being built by some other folks. So there'll be a lot of options for tiebacks, and it would be that type. And it could turn into a facility here, but that's not – till we get a lot more information and get ahead of this mean number where we are, we're just – we're talking tieback game here. But all of these are very, very accretive and very, very income providing and great F&D metrics for our company.

Great. Roger, you did increase your capital allocation, I think, to Kaybob. What's your current thinking about that play and thoughts on how active you could be here in 2019?

Well, I mean, I was taught when I was a young man, if you earn, pay to keep drilling, and that's what we do with Samurai and that's what we do there. And it's going very, very well. This is part of a long-term business that we bought there. Where bought this at the total collapse in February of 2016. At that time, this involved a very low amount of money. And let's go back up to what the goal was. The goal was there was to replace the production from Syncrude at lower operating expenses as an operator and lower total costs between DD&A plus OpEx. At the end of the year, we would have done that with the Placid asset plus us. So we've accomplished all of our goals, hitting all of our targets. In that deal with a low amount of money paid upfront was a carry that we needed to drill wells in certain locations over a certain period of time. It had a cost oil price index associated with that. That that carrier to be spent all the way to 2020. Oil prices are a grade higher requiring the capital carry to be spent now between now and the end of 2019. So we're just executing that original purchase. We held the money of CapEx until the team showed further ability to execute. The team executed all the way through. We have this carry. We're very successful. And we put capital in to get this carry behind us and then put us in a situation of perfect capital allocation, if you will between, the Eagle Ford and that asset and that's what we're working on. And that's why the capital was allocated to that.

Hi, Roger. My final question is kind of a housekeeping question. I was looking at your guidance for 3Q. The pricing in Malaysia is a little bit light of our model just given how it's tied to Brent particularly at Sarawak. Could you give us some color around that?

That all involves capital spending timing and liftings and loadings as per the capital for the quarter, and we base this hugely on a – these assets in Malaysia usually about a $3.75 to $4.25 positive over Brent, then we work through the PSC. But I still would say even after all PSC effects, we're probably ahead of WTI. And Kelly will give me the number now, but – so on a realized price basis, that's – the quarter has to do with timing of capital spend projects and production that we're doing, and these things move around. But I still think these realized prices are pretty good compared to a big hunk of United States.

All right. Fair enough. Thanks, Roger.

Okay. Thank you.

Your next question comes from Muhammed Ghulam, Raymond James. Please go ahead. Muhammed Ghulam - Raymond James & Associates, Inc.: Thanks for taking the question. So, Obrador won the election in Mexico recently, and before the election, he had made several comments about his opposition to the country's energy reform. Since his victory, have you guys heard anything new from the government?

Well, we did receive an approval that we highlighted in our highlights today, and we continue to progress that along. I think in recent statements by this leader, he's now pulling back a lot of that rhetoric and saying he's positive about the synergies. There are some 50-plus wells to be drilled there, with enormous amount of capital to be spent in the country and personnel to be hired in various support of these vessels. And it's our view that his latest statements have been recanting a lot of that and back supporting the PSC – not PSCs, but the leases that we have today. I'm not sure about where the future leases will be, but we have ours. We feel good about it. We feel good about what we're hearing. And we're progressing through an approval process to drill, and we're moving full on with that and do not see anything that will actually prevent that at this time. Muhammed Ghulam - Raymond James & Associates, Inc.: So in other words, you guys don't think this victory is really going to change your plans anyway, and you're pretty confident that the new government is going to reflect the permit?

Yes, we are. Muhammed Ghulam - Raymond James & Associates, Inc.: Okay. That's all for me. Thank you.

Okay. Thank you.

Your next question comes from David Meats, Morningstar. Please go ahead.

Hey. Good morning. In response to an earlier question, you guys talked about low F&D cost for the potential development of Samurai, and I was wondering if you can put a range on what you consider low for F&D at this point.

Well, we placed in our original program that all of our exploration wells has a target F&D of $15, and even on an example of this – if the field is only $50, then the F&D would be not even $15 a barrel. So there's no outcomes here greater than like $12 at this time. So, we feel that a bigger development would be around $1 billion gross, and we feel that a smaller development would be around $500 million. So the $15 F&D which is outstanding which means that the ultimate DD&A of the project would be $15. It's good and industry-leading and it's good as anything there is onshore, I can tell you. And so, that's where we are. I'd say this would be in the $10 to $15 with $15 at the ultimate top, and that's industry-leading, too.

Okay, that's super helpful color. So, in the, I guess, the exploration upside case where you have the development of Samurai or other discoveries like Samurai, is there any kind of scenario where that exploration's success and the resulting development justifies going away from living in within cash flows for a short period while you ramp up on the development?

I suppose that could happen. We have lots of capital allocation options and the different ways to execute these projects where we may not own a facility for facilities built and things that nature. But that's when things happen and things get sanctioned. You make decisions on capital allocation. We surely can afford it. And so that would just have to be with the timing at that particular time and how our other assets are performing, but we're not going to hold this back if it's a very successful project that we believe we have at this time.

Okay. That's super helpful. Thanks a lot.

Well, thank you.

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.

Well, that's all we have today. Had a good quarter. Real happy with it. We'll be right back here the next time I think on Halloween day, lowering costs, raising EBITDA, drilling successful wells, and hitting all our targets again. And we appreciate people calling in today and see you next time. Thank you.

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