Good afternoon, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2017 Earnings Conference Call. Today's conference is being recorded. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thank you, Dana. 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 first quarter financial results, highlighting our balance sheet and strong liquidity position, followed by Roger with first 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 the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2016 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, everyone. Consolidated results in the first quarter of 2017 for Murphy Oil were a profit of $58 million, $0.34 per diluted share, and that's compared to a loss of $199 million or $1.16 per dilute share a year ago. Results from continuing operations had a profit in the first quarter of 2017 of $57 million, or $0.33 per diluted share. The first quarter results from continuing operations for 2017 included a $96 million after-tax profit from the sale of Canadian Seal heavy oil assets in the quarter. Quarter one also included an approximate $55 million noncash tax charge related to an expected future U.S. repatriation of 2017 earnings in Canada and Malaysia. Adjusting our GAAP numbers for various items that affect comparability of results between periods led to an adjusted loss of $10 million, $0.06 per dilute share, in the first quarter of 2017. Our schedule of adjusted loss is included as part of our earnings release and amounts in this schedule are recorded on an after-tax basis. Beginning in the first quarter 2017, the company determined that current earnings from foreign subsidiaries with operations in Canada and Malaysia would not be considered and definitely reinvested in those local operations. A corresponding noncash tax charge of approximately $55 million was recorded in the first quarter of 2017 based on the expected tax impact under existing U.S. tax law from the future repatriation of these Canadian and Malaysian profits to the U.S. through dividends. The tax charge also includes the anticipated 5% dividend withholding tax applicable to all Canadian repatriations. Under current law, the future repatriation would be considered U.S. taxable income, which would reduce the future benefit or U.S. net operating losses generated by the company's domestic business. The company's average realized sales price for its crude oil production was $50.10 per barrel in the first quarter 2017. This average benefited from our historically strong market prices for our Malaysian oil. Also, our overall natural gas liquid prices in the U.S. and Canada averaged $17.01 per barrel. Natural gas sales prices in North America averaged $2.17 per 1,000 cubic feet in the first quarter. While realized oil-indexed natural gas prices offshore Sarawak averaged $3.50 per Mcf. At March 31, 2017, Murphy's total debt amounted to $2.98 billion, and that includes capital leases. This makes it slightly below 38% of total capital employed, while net debt amounted to slightly less than 28% of capital employed and amounted to $1.9 billion. As of March 31, we had no outstanding borrowings under our almost $1.1 billion revolving credit facility. Worldwide cash and invested cash balance totaled $1.1 billion at quarter-end. That concludes my comments. I'll pass it over to Roger.

Thank you, John. Good morning, everybody. Thanks for listening to our call today. Murphy started the year an all-around solid first quarter. We produced 169,000 equivalents comprised of a balanced mix between onshore and offshore production. Offshore production comprised of 73% liquids as compared to our onshore business which is 51%. Onshore developed plays continue to exceed our production expectations. Both our offshore and onshore liquids are high-value barrels, and they receive a premium pricing based on Brent for offshore business and LLS for U.S. onshore. And our new Kaybob Duvernay Shale play receives current condensate net-backs just below Eagle Ford Shale prices. For the quarter, the company spent just over $214 million in capital, which is in line with our capital budget of $890 million for the year. We continue to strengthen our capital efficiencies, which we worked hard to achieve over the last two years. With a solid balance sheet and ample liquidity and cash on hand, we continue to build financial momentum as we progress through the year. Our diverse asset base and oil-weighted premium pricing drives our continued strong EBITDA per BOE performance. In the first quarter, we achieved $29.50 EBITDA per BOE, and excluding our pre-tax gain on the Seal divestiture, we achieved just over $20 EBITDA per BOE. Operationally, we are successfully executing our 2017 plan across all our assets. The early appraisal of wells in the Kaybob Duvernay play are yielding positive results. We're now just beginning to drill and complete the wells with our plans and our way. In the Eagle Ford Shale play, we continue to de-risk the Austin Chalk and upper Eagle Ford Shale zones in the Karnes area and continue to see well results exceeding expectations across that play. Our Tupper Montney natural gas play has exceptionally low operating…

Thank you. And we'll go first to Paul Cheng with Barclays.

Good morning, Paul.

Good morning. How are you doing?

All right.

Roger, do you have a rough per well cost estimated for the wells you're going to drill in Vietnam and also Mexico?

The wells in Vietnam are two wells which would be approximately $20 million to $25 million our share. And the well in Mexico next year is probably set up for around that same spend.

And you're working interest, I'm sorry, can you remind me?

In the Vietnam areas, we're 60% and we're carrying part of the cost for our partner, paying around 80% on 60% in those wells, and at the end of those wells, there will be no further carry in that project.

Okay. And your Mexico?

The Mexico well will probably be – what we're trying to target now opportunities that are economically large and hit our F&D targets and our economic threshold. And we're probably looking at all the wells we're participating in around $18 million to $20 million our share. And that's top exposure we're willing to put into these plays and that will be no different in Mexico.

Okay. And can you share with us what is the end cost – I presume that even in Eagle Ford which start to seeing some cost inflation. What's the cost inflation we're seeing there now?

Well, as you frame that issue, I'm sure that would be asked today. If you look first quarter 2016 to first quarter 2017, we're actually lower on our costs in Eagle Ford, on our true average data about drilling and completion. So we haven't seen this break into us yet. We continue to see efficiencies in our drilling probably we've been doing 10% a year there. We just continue to set pacesetter wells. Now, a worst case scenario we see that the fracturing, just the fracturing side can go up 30% small increases in everywhere else. We sort of see this deal around a possibility of a 10% increase per well. That's around $400,000 a well for us. We want to drill 60, drill and complete 60 more wells this year. So for us that's like a $24 million possible change. As we look at the efficiencies, continue to set pacesetter wells, working on some new motor technology, we're also – I'm noticing that our stages per day is going up from a year ago, six stages a day to seven. We're also working on some other plans that we have on a technological basis to employ fractures and I see us being able to work that off and I see our fracturing costs in the deals that we have with various vendors concluding rigs and fracturing to place us in a pretty good situation there. It's not detrimental to the company at all. We can handle this. We'll go up and down with this as needed and it's going fine for us.

My final one is have you seen any cost inflation in your Canadian operation?

It's probably on a different scale. The equipment is – it's tight there but there's not as much activity with the break up season and various things of that nature. We're probably exposed there, probably $10 million to $15 million for the whole year. I just do not see this in our current procurement over the next couple of years, I'm just not that concerned on that issue at this time.

Thank you.

Thank you, Paul. Appreciate it.

And we'll take our next question from Guy Baber with Simmons.

Hey, Guy. Good morning. How you doing? Guy Baber - Simmons & Company International: Good morning, Roger. Thanks very much for taking the question. I was hoping you could talk a little bit more about the capital spending framework for this year. I understand you reiterated the full year guidance and the 1Q total CapEx number was generally in line. But there were some regional variances. CapEx in Canada was higher than we had expected. So can you speak to that at all? What might be driving that? On the other hand, Malaysia was much lower. So if you could put some color around some of the trends there, that would be very helpful.

I think these trends, from our original outlay that Kelly shared with you early in the year should not change. These are strictly timing issues. Actually, our capital's a little bit low in the first quarter as we didn't complete six wells in the Eagle Ford that would have cost probably around $3 million a well. And we'll be hitting that hard in the second and third quarter with a lower execution amount of wells in the fourth quarter. So I don't really see any regional change overall for the year. It's just strictly a timing issue, and not something we see as changing or a trend or anything like that, Guy. Guy Baber - Simmons & Company International: Got it. That's helpful. And then I wanted to talk a little bit more about the Eagle Ford as well. But it appears that while the first half of the Eagle Ford was maybe a little bit lower than we had assumed on completion timing, the second half is going to be a little bit stronger. Can you just talk about that trajectory for the Eagle Ford as we exit this year and head into 2018? And should we still be thinking about you guys holding the production in the low 50,000 range? Or given some of the well results, does that look like you could be growing it at some of these activity levels or do you have an opportunity to add activity there?

Actually, it's gone very well. We just had some delays in putting some wells fractured and made some different changes in who we're using and what we're doing in fracturing, leading to some higher well counts in the second and third quarter. We are looking at a higher exit rate than we originally had before in the play, probably looking at a pretty strong 58,000 coming out of in the fourth quarter. And originally, we thought it to be 2,000 to 3,000 less than that. And happy with how that's going. I think it's possible to have a slight increase next year, maybe not as flat as we originally thought. But then we have to look at capital and making the asset free cash flow. We're trying to make our developed Eagle Ford plays and Montney plays be free cash flow-providing, and we have that in the back of our minds as well. So haven't really worked into what it'll look like in 2018, but we're definitely not decreasing. We're flat to slightly growing at this time. We're just getting new wells into our plans at this time. Guy Baber - Simmons & Company International: Thanks, Roger.

No, thank you.

We'll go next to Roger Read with Wells Fargo.

Thank you. Good morning.

Hey, Roger.

Real quick, you talked about, it's been a consistent theme for I guess the last year or so, doing an acquisition or a way to buy into some of the offshore opportunities that others are trying to exiting. Have you seen improvement in, say, a bid-ask spread or a narrowing or broadening of opportunities over the last 12 months? I'm just kind of – since we haven't really seen a huge acquisition anywhere other than Anadarko's, I was just curious has there been much movement out there?

First, let me correct something I just told Guy. I told him that our fourth quarter in Eagle Ford would be 58,000. It's actually 53,800, Guy. I apologize. I misread that number. Didn't have my glasses on. No, we're very active, Roger, in looking at these opportunities offshore and onshore. We look at our strategy. We like to take a differentiated perspective, looking at basins and plays that we can have rate of return with strip, with a conservative view of EUR and conservative pricing. That's our mantra, that's our company, that's our history, that's what we do, and we continue to focus on these. And we have opportunities all the time that we're reviewing, both onshore and offshore, and looking to be an accumulator in the Gulf if we could find some acreage that we could operate well, looking for things in the onshore that would complement where we're working or very near where we work and a methodology of things we're executing. And all I can tell you is we're very active at doing it and see it as a key part of my focus at this time.

All right. Well I guess I could push harder than that, but I'm going throw it out to my other unrelated follow-up. The Austin Chalk wells in the Eagle Ford area, you gave a volume on that. Did you offer up a percent liquid gas content there or maybe how these first wells (29:39)

This is just like our – it's just like our Eagle Ford wells in high 80s. It's really no different. It's a different crude means coming and formulated in a different way but a slightly different gravity. It's very low, very high quality. But it's the same kind of crude percent. We have pretty strong oil for our business.

Okay. That's it for me. Thank you.

Thank you, Roger. Talk to you next time.

And we'll take our next question from Kyle Rhodes with RBC.

Good morning, guys.

Good morning.

A couple of questions on the Eagle Ford. Any chance you could break down the remaining six Eagle Ford wells expected to be turned online before year-end 2017 between Karnes, Catarina, and Tilden? Maybe just a rough split there?

Let me – I'll have to dig for that. Kelly's going to dig for that. Do you have another question you can ask while we pull that up?

Yes, sure. You mentioned base production kind of outperforming expectations. I know you restrict flow-back a little bit more than some of your peers there. Can you quantify maybe what you think your updated annual base decline in the Eagle Ford is?

Our Eagle Ford decline is very similar to what it's been. We're looking at a year one decline somewhere around 30,000; year two, around 15,000; and year three about the same. In these shale plays, it's not really a true decline rate like an offshore asset, and that's the decline we have from the wells. So that'd be like a new well on-line declines is those type of factors. New wells on top of our base, if you get me, is 31% and it depends on how many wells you add and how many older wells you have and things of that nature. That's where we have it today.

Okay. That's helpful. And then just maybe on the Montney, you mentioned some potential expansion opportunities up there. What are some of those opportunities? Is there a new planned capacity opening up? Just curious on what you're building to grow that asset is.

Yes. We are taking a very close look at it right now because we've been doing so well there. Our drilling is continuing to improve. Our recovery per well is outstanding. Our operating expenses there are very good there in the $0.60 range in that asset. What we're looking at is to build with a midstream partner an additional plant or series of 200 million a day plants. Originally, in our long-range plan, which is not included in the growth plans that we shared in the first quarter, we have the expansion of the Montney as late as 2023 and our business continuing on that way, and we're looking to advance that to 2020 and drilling additional wells in 2019. We're looking at around $100 million of additional capital we could build up the wells to deliver the new 200 and we're in feed stages with partners there to look at building the plant, where the plant would be and among our field there. And we really like how that's looking and like the moving forward of that cash flow, and hundreds of millions of dollars of free cash accumulation by 2030 by not doing status quo, the 2023 expansion, and moving it forward by three years. And, Kyle, it all depends about the price and what we do there and what you're kind of modeling C$2.90 AECO in 2024 around C$3.20 AECO in 2030. That's how it is today but I think that's out of bounds and see how that would look and compare that back to strip prices and compare that to other opportunities and review that with our board this year and gaining momentum in the company.

That's helpful, Roger.

Okay.

We'll take our next question from Arun Jayaram with JPMorgan

One second. Let me answer the prior question on the wells. In quarter two, we're looking at two Austin Chalk wells in Karnes, two wells in Catarina, 12 wells in Tilden. Quarter three, we're looking at three Austin Chalk wells, 14 Eagle Ford Shale wells, nine in Catarina. In quarter four, 14 wells in Catarina. In addition, in quarter two, we will have five Eagle Ford Shale wells partnered with the two Austin Chalk wells. So I'll go to your question now. Sorry for that delay.

Roger, I wanted to see if you could kind of set the stage for the Duvernay tests. Those are pretty important catalysts, I think, for the stock. I know you're going to be drilling and completing some longer laterals. But how would you gauge success with these early tests? What kind of KPIs are you looking for from your initial Duvernay tests?

We have some pre-planned EURs that we see as successful but it just depends on costs and how things change with the field, as you can imagine. We have, I think, from a production basis these wells we drill and you can see in our slide in our deck today in and other public decks. This 11 of 18 pad is looking for some thousand EUR-type wells in there and that would be something we need to be pulling to in the high 700 to 1,000 as to how that works. These are some pretty longer lateral wells and a condensate gassier region. I think if you look at this 05-29 well we have in here today under 6,000 feet type lateral performing on a 600,000 type curve and you put that in between nearby the 04-32 pad that's seen in our slides, you can kind of see that, that's in the 600,000 and 700,000 range. And in and around that, you have to keep in mind our Eagle Ford wells are 500,000, 600,000 and you accompany that with the low royalties. We've had very low royalties for several years and Duvernay costs coming down, pad drilling. This is working. There's enough data to show it's working now, and not going to be put off by singular pad results at this time. We're experimenting with about three different ways to frac, two different ways to flow-back, two different type of staging, doing a gel-type frac, slickwater type fracs, 3,000 pound per foot fracs, 2,000 pound per foot fracs. So we've got a lot going on in there in a planned way. On and off on one particular pad being the driver of our stock price in the middle of Canada, I don't see that as a big driver today. But overall, we're real happy with how we're doing and just got to look at our holistic year of delineation in that play.

Fair enough. But do you agree it could be a longer-term driver of growth at Murphy?

Oh, sure. Oh, sure. For sure.

Yes.

But we're trying to take all our learnings from our other plays, have a systematic approach into this instead of just jumping in and completing a 12-well pad in a certain way, a certain spacing, a certain frac design and find out later that wasn't the way to do it. And walk across this play and these different attributes of the technological changes in fracking that we learn from other areas is slowing this into something we can have a better value, better down-spacing, better total design of the pads going forward that we've learned from our other areas.

Fair enough. Two other quickies; one, as we think about the Q2 guide, there's kind of 8 MBOE per day of kind of quarter-specific items. How much of this is kind of known, guys, when you gave out your guide? Just trying to understand as we think about your full year range, is some of those unexpected is one that could also influence how I think about where we land in terms of our updated model?

Downtime comes and goes on schedules so do think the second quarter always has a lot of downtime for an offshore company. That's very typical. We absolutely knew and planned for the redetermination and for the entitlement change. On these entitlement changes, first off you have to make a lot of money for them to click in. And that's going very well for us on our revenue oversea basis overall. And that's been known and the only change in the second quarter from our original guidance would have been a change in the completion timing of Eagle Ford that's more backed into late May. We have another crew starting in Texas. And that's been the only change to our original plan. And now, with our better base production in Eagle Ford, looking at a pretty strong exit at the end of the year. And the only change is that timing of fracs. All the other issues are known and planned and no surprise to me in any way.

Okay. Fair enough. And just, Roger, as we think about Hoffe Park, which it sounds like you'll be doing a side-track there, can you give us a sense of – is that in the longer-term guidance for production that you issued?

No.

I think it's the 6% to 10% number? Okay. Okay.

No exploration is in that number.

Okay. Fair enough. Thanks a lot.

Thank you. Appreciate it.

We'll go next to Pavel Molchanov with Raymond James.

Pavel, good morning.

Hi. This is Michael (39:26) in for Pavel. I have a question about block size in Mexico. There's been about five or six months since you've won that block and ...

I'm sorry. I'm having trouble hearing you. Could you speak a little louder?

Yes. Sorry. We have a quick question about Block 5 in Mexico.

Sure.

We were just curious what the status was and if there's a timetable for the first exploration well and maybe any seismic that you'll be doing in advance of that?

We just purchased some new wide azimuth seismic over our block or a large portion of the block. The block is very large, over 100 Gulf of Mexico normal blocks in the U.S. side. Very happy with those images. This play is a very nice block for us. It would have classic Gulf of Mexico attributes, such as amplitude plays, three-way plays against salt, four-way closure. It would have every play type that we've seen in the Gulf of Mexico including subsalt which is very unexplored in that entire country compared to the U.S. And very pleased with those images, pleased with the prospects we have, our partnership group. Our exposure we have in the block will not be a high percent and got in ground floor in it and most contested block in the sale and we're looking to drill the well in late 2018.

Okay. Perfect. Thank you.

Thank you.

And we have a follow-up question from Paul Cheng with Barclays.

Yeah, Paul?

Roger, two quick ones. First Malaysia, the floating LNG, what's the status right now on that one? Are we still talking about startup in 2020 or that being further pushed out?

No. That's progressing well. If you know the history of these projects, there were two floating LNG boats produced by Petronas. Petronas is the leader is delivering these boats on time. The first boat is just like our vessel, (41:35), has been working in Malaysia now already and went through the critical de-risking of offloading LNG recently. There's a very large turret associated with this vessel that's manufactured out of the country and that's being transported to Korea now and we're all systems go for Petronas to place that vessel and produce in 2020. We then will spend money in 2018 and 2019 with the completion of the wells and we'll be delivering the gas molecules to the edge of the boat for Petronas just as we do in shallow water where we deliver LNG to them at the doorstep of their LNG plant onshore in Malaysia in Sarawak. So going well. They're back in line doing the project. I believe that Petronas sees advances and a possible ability of LNG price to increase past 2021, 2022 and that's helping with that project. That's helping bring – hopefully, we can bring forward our Brunei project. I think there's a little bit of improvement in LNG in that region. They're the leader. They're the king of the road in LNG in Southeast Asia, and I like following behind Petronas in that.

Is the scope of the project, any change or serious talk about 100 million cubic feet per day for you?

With our sell-down in Malaysia a few years ago, it should be about the same level of net production we have in Sarawak today and should go for several years.

Okay. And in Malaysia, when Block K and Sarawak are going to hit the 50% of the split go down to 50%, is it 2018?

The change-out in Block K that's been around the company for a long time. I believe now it's out in 2021 or something to that effect. And we have no additional changes in entitlement in Sarawak. We have an entitlement change in third quarter of 2018 and bought 309 oil. Nothing again until fourth quarter of 2019 for 311 oil. No change on 311 gas until 2021. And we just made a change in 309 gas, which is primarily the BOE benefactor of this reduction. And that won't change for – I don't have numbers long enough to know when the next change is there. So pretty stable for a good while in Malaysia at this time.

And maybe, Kelly, if you don't mind, maybe you can shoot us an e-mail maybe helping us in terms of when that happens, when the change happens, what kind of production impact are we maybe talking about? And then another one...

That's about seven today for you, Paul. It's a good thing you have a buy rating.

Absolutely. And on the M&A side, is there any other opportunity in the Duvernay that you can see?

In what area did you say?

In the Duvernay?

Oh, Duvernay? Yes. I've got 140,000 acres. There's a 2,000 acre in there now, and I've got my hands full doing that. I'm real pleased with it. We do see some opportunity. Just sometimes when things happen and we do not announce that we did something, it didn't mean we didn't bid for it. So we look at many things and try to get many things here, and we'll continue to do so.

All right. Thank you.

Thank you, Paul. Appreciate it.

And at this time I'd like to turn the conference back over to Roger Jenkins for any additional or closing remarks.

I have no further in line calls today. Appreciate everyone calling in. I know it's a packed time of earnings this week. And we'll get back to work here in El Dorado, and I appreciate it, and we'll talk to you at the end of next quarter. Thank you very much.

Thank you. And that does conclude today's conference. Thank you for your participation. You may now disconnect.