Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2018 Earnings Conference Call. At this time, all lines are in a listen-only mode. But following the presentations, we will conduct a question-and-answer session. This call is being recorded on Thursday, November 8, 2018. And I would 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 third quarter earnings 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 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 exists that may cause actual results to differ. For further discussion of 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.

Thank you, Kelly. Good morning, everyone. I have a bit of a cough today, so bear with me. Thanks for listening in today. 2018 has been an excellent year both financially and operationally for Murphy. Our excellent third quarter results illustrate our commitment to a diversified portfolio as robust production from our oil-weighted onshore and offshore plays continued to drive high margin realizations. Production in the third quarter averaged 169,000 barrels equivalent per day at 58% liquids. Production exceeded the high end of guidance by over 1,200 barrels equivalent per day. This beat was driven by outperformance in our onshore Canada Tupper Montney and our offshore Sarawak Malaysia assets. In third quarter, we generated $94 million and $0.54 per share of earnings. Our disciplined capital allocation enabled us to return 12% of our operating cash flow to our shareholders. We achieved an annualized EBITDA per capital employed of 21% and maintained our balance sheet strength with $2 billion of liquidity. In the quarter, we also paid our own way while building our cash position. In early October, following the announcement of our accretive Gulf of Mexico transaction, we've received an upgrade from Fitch Ratings to BB+. We view this as a step in the right direction on our path back to investment grade. Through the cycle, we've maintained unique ability to successfully execute deepwater projects offshore. We installed the Kikeh gas lift project in offshore Malaysia as well as the Dalmatian subsea pump in the Gulf of Mexico. We also successfully drilled the Samurai-2 sidetrack well, and after early analysis of well logs and core data, we now believe we have approximately 90 million barrels equivalent of discovered resource. In our North American onshore business, we're able to show continuous improvement in cost reductions by achieving lease operating expenses just…

Thank you, Roger. I'll be starting on slide 8. Consolidated results in the third quarter of 2018 included net income of $96 million or $0.55 per diluted share, compared to a loss of $66 million which is a loss of $0.38 per diluted share in the same quarter one year ago. Our adjusted income was a profit of $61 million or $0.35 per diluted share in the third quarter of 2018 versus a loss of $6 million in the comparable quarter last year. The adjusted income varies from our net income due to the following after tax items. Number one, an unrealized mark-to-market gain on crude oil derivative contracts of $21 million. Two, proceeds from an Ecuador arbitration settlement of $21 million. The Ecuador arbitration settlement relates to a change in fiscal terms for a block previously owned by the company. Number three, a prior period net income adjustment of $9 million for the reconciliation associated with the unitization of the Gumusut-Kakap Field in Brunei working interest income. This settlement, which was signed in 2017 relates to the reconciliation of accounts amongst the Malaysia and Brunei parties. It is important to note that there was no change in the quarter to Murphy's working interest in the Gumusut-Kakap Field. And finally, a loss on foreign exchange of $18 million. At September 30, Murphy's total debt amounted to $2.8 billion excluding capital leases or 38% of total capital, while net debt-to-total capital was 30%. At the end of the third quarter, we had no outstanding borrowings under our $1.1 billion revolving credit facility, and cash and equivalents were approaching $950 million at quarter-end. Moving to slide 9, one of the hallmarks at Murphy over the years has been our disciplined approach to capital spending within our cash flow. As slide 9 indicates,…

Thank you, David. Let me start on slide 11. In Malaysia, assets continued to be a reliable free cash flow generating business. Our Kikeh DTU gas lift project is now complete. In the third quarter, we achieved a milestone with the Kikeh FPSO completing over 600 liftings since we started production with that asset. In Sarawak and South Acis, we completed an infill 3-well drilling campaign with the wells now online. Sarawak we completed a 9-well gas recompletion project that allowed for continued gas deliverability up to 300 million cubic feet per day gross. Our Block H-Rotan FLNG project remains on track with manufacturing completed for flexible flow lines and dynamic riser section. In Vietnam, our LDV development team continues to progress the field development plan and progressing approvals aiming to declare commerciality by year-end. In the Gulf of Mexico, we commenced installation of the Dalmatian Subsea Pump late in the quarter. Early in the fourth quarter, the installation was completed and it's currently delivering incremental production of 7,000 barrels a day equivalent gross with the rates exceeding 11,000 barrels equivalent per day gross. This is a increase of 250% from prior quarter production. Also this pump installation sets a record. It's the longest umbilical used in subsea pumps at over 22 miles. This again is an example that sets Murphy apart. Another industry first as we implemented a technology we believe we can use long term in the Gulf of Mexico including our new joint venture fields. Slide 12 on the Eagle Ford Shale. During the quarter, we brought nine wells online in Eagle Ford all in Catarina. In the fourth quarter, we plan on bringing an additional 4 Catarina area wells online. Eagle Ford Shale team continues to lower drilling cost while maintaining completion costs in spite of…

Thank you, sir. One moment, please, for your first question which will be from Arun at JPMorgan. Please go ahead.

Arun, good morning.

Good morning, Roger. I heard the word free cash flow mentioned a number of times in the commentary, which is encouraging, but post the Petrobras deal in our model, we see over $800 million of free cash flow generation for Murphy at a recent price stack. So, I guess the question we have is what are your thoughts on deploying that free cash flow, how do buybacks, debt reduction, where is your thought process behind free cash flow in 2019?

Well, we want to use a portion of that cash flow and get CapEx into the Eagle Ford. You can tell in our call today that we still have pretty good results there. But delivering four wells a quarter just won't make it in a oil-rich play like that. It's low-entry cost working well and executing well. So, we want to get a lot of CapEx into that next year and increase the CapEx for that. I would say just to get the budget type things behind this year. We're going to release that in late January, which is not so far away from now. We have a significant accretive cash flow providing business to get closed by then. I feel really good about that closing and about that change. And so, our budget's going to be different from last year but in a very positive way. We're going to be using low 60s WTI, low-70s Brent. We're not focusing on growth, but we're going to have production growth. We're going to have significant oil CAGR. We're going to have probably a 50% increase in CapEx in the Eagle Ford alone. And we again will have free cash flow ahead of our dividend there. We're not putting all this free cash flow right back to work and focusing it really just on Eagle Ford Shale with the rest of our businesses being maintained and our exploration probably slightly less than this year. And those are the things we're working on. And so, it's not that we're putting all that capital to work. Our CapEx will be higher, production will be higher, oil CAGR will be higher, our oil-weighted production will be higher and our free cash flow yield's going to be higher. So, it should be a very positive budget when we disclose it. We'd like to get disclosed, go through our board and do that then. So, that's a roundabout way of answering your question. At this time, we're maintaining our dividend and having additional free cash flow yield. We have the option of paying back some of the draw on our revolver with that over the next couple of years as we see fit, as oil prices behave and have a lot of optionality around that. But we're very proud about how our budget's going to look and how we're looking once we get this asset in our control here real soon, Arun.

All right. Two other quick ones for me. Regarding the Petrobras deal, I know it had a 10/1 effective date. Any estimate of how much cash that asset would generate between 10/1 and closing, and thoughts on maybe hedging the oil price just to reduce your overall volatility, the cash flow stream from the Petrobras deal.

It's probably $50 million, $60 million a month kind of thing, Arun, something to that effect. Of course, you've got to get to the final closing statement. This is a complex transaction involving a bunch of assets, but I feel pretty good about that number. And we're not hedged in 2019. We're using a low 60s WTI right now. I'm still comfortable with that because I'm comfortable with the outcomes that I have in my budget as I just went through the high level budget discussion of our pillars for our budget. So, we're not hedging that and we don't think we need to in our liquidity and our revolver situation which is improving. It doesn't require that in our mine and we are hopeful that this oil price will return to more stable times after we get through everything that's been going on of late and not hedged today.

Okay. And just final question is, you reported just in Q4 some kind of quarter specific items, weather, et cetera. Is there any knock-on effect to some of the fourth quarter items that you highlighted in the press release towards 2019?

No, I wouldn't anticipate that at all.

Okay. Thanks a lot, Roger.

No, thank you.

Thank you. Next question will be from Leo at NatAlliance Securities. Please go ahead.

Hello, Leo. Good morning.

Hey, guys. Hey. Good morning here. Couple questions for you guys here. On Kikeh, you guys obviously got that gas lift project working here. Just trying to get a sense of whether or not you actually see production uplift at Kikeh or is that more of a maintenance of production? And if there is uplift, can you take a stab at quantifying that?

There is some uplift from it, probably in the 2,000 range. This is one of the sources of some mechanical issues we had where if you follow back on our prior calls, we were doing some – an infield work over, some subsea wells and that's been flowing in. We've been doing a debottlenecking and lowering system pressure on a compressor, on the platform, the main FPSO, all along (23:15) trying to get our DTU to work. Don't really have the uplift today because it's hurt by some water injection problems and some issues inshore with the gas plant where we sell gas. So, hasn't been a good time to get that kicked off but it's performing very well and we're going to add, I believe, up to five more tubing strings between now and the end of the year. I'm anticipating kind of a 2,000 increase. But then overall a maintenance-type deal in a field that's produced now for 11 years.

Okay. That's helpful. I guess similar question around Dalmatian. You guys obviously talked about 7,000 BOE per day of incremental production. Do you guys see that as sort of incremental flush production in the short term that might start declining lower than that 7,000 BOE or do you think that could be maintained for some periods? What can you tell us about that?

I think it's going to be maintained for a while. This is a mechanical situation. There will be no evacuation of oil from the reservoir as we go through. We're looking in the budget today in our draft budget to drill another well out there because this is performing so exceptionally well. This is a pretty much a pressure drawdown of the long pipeline system to allow the wells to evacuate oil at a lower pressure. It's working incredibly well. It's industry leading. It's an outstanding project executed here in our Houston office. And so, I'm not seeing major decline coming out of that because it's a mechanical uplift, it's overriding that well into 2019.

Okay. That's helpful. And I guess you just mentioned potentially drilling another well there. I think in your prepared comments, you talked about two wells in the Gulf of Mexico in 2019. Would that be one of the wells (24:57)?

That would be in addition to that. That would be a well from a reservoir we have in that field. It's not a exploration well.

Okay. So it'd be two exploration wells potentially in the budget in the Gulf for next year.

Plus the finishing off of the Mexico and the Vietnam well. Correct.

Okay. And then at Samurai, any initial thoughts on development program there? I know you guys just finished doing some appraisal of the size, but any initial thoughts as to where it might go?

We are very pleased with the outcome, very pleased that this is a very nice resource to us to use in the tie-back system. We have to work with our partner there. We just developed our pre-AFE to study various development plans, probably looking at a three or four-well type of development with probably six or seven different completions in the various reservoirs we've discovered. We outlined in early October a series of slides that shows how a development like that would work, probably 18 months from drilling a well next year. We may not have to drill the well. We're in the middle of deciding that now. We could just drill a development well later. So, looking at drilling the well late 2019, flowing oil two years from that point, 18 months to 2 years from that point, and these things are going to probably on a gross production basis kind of top out in a couple of years at 30,000 gross. We're 50-50 and decline from there, and it's a very nice asset with outstanding economics that can compete with any capital in the world.

All right. Thanks for the color.

Thank you, appreciate it, Leo.

Thank you. And next question will be from Muhammed at Raymond James. Please go ahead. Muhammed Ghulam - Raymond James & Associates, Inc.: Hey. Thanks for taking the question. So, if I'm reading this correctly, Eagle Ford production is going to be down pretty significantly next quarter. What exactly is the driver behind that?

Well, we had a pretty rough start and continued into this week, we've removed hundreds of yards of segments of roads going into some of our newer pads in the Catarina and Karnes area. With water we had to get some actual boats there to go service and turn the wells. We're afraid to leave the wells where we can't attend to them as the road is washed out. So, it's put a hurt on that. Not so much on completions and drilling. We happen to be in a drier area where we're doing that, and just a very limited well count. And when you're delivering nine wells in one quarter and four coming up in the next in a shale play, it doesn't take much to have the production decline. So, again, our focus is to get our accretive business in the Gulf and order a tax advantage business, take that free cash flow and up our capital gain to have more consistent non-front end loaded Eagle Ford business that will not allow for those type of pullbacks primarily is the issue. Muhammed Ghulam - Raymond James & Associates, Inc.: Okay. And in Mexico, say, with the prospect there next year, is there any risk to the timetable given the new administration that's going to come in in December?

What was that again? In what area? Mexico? Muhammed Ghulam - Raymond James & Associates, Inc.: Yeah. (28:11).

No, we're progressing well. We had a milestone of the exploration program approved. There are some nearby peers that are gaining approval with theirs that are slightly ahead of us, and they've been able to do it. We're communicating with them. Our relationship with the government and the quality of the permit that we turned in has helped us. We have a outstanding team that's used to working internationally here at Murphy. And the quality of our work and able to get in, and our relationship with them and we feel that we're going to get the permit in December and drill our well. Muhammed Ghulam - Raymond James & Associates, Inc.: Okay. Can you remind us of the pre-drill estimate cost for that well and also one in Vietnam? Do you guys have it in front of you?

It should be here. Just one second. It's on the slide that we're using this morning. I was reading at it and – here it is. Here we go. The well in the Gulf of Mexico will be $25 million for Murphy, the well in Mexico will be $15 million, and the Vietnam well will be around $20 million. And what else is your question on that, Muhammed? Muhammed Ghulam - Raymond James & Associates, Inc.: Pre-drill estimates, if there are any?

The King Cake well has a gross mean of 50 million barrels. We're 31%. The Mexico well is 200 million barrels. We're 30%. The Vietnam well is 35 million barrels, we're 40%, but it hasn't – and all these have enormous upsides ranging from 100 million barrel to 250 million barrel to 500 million barrel improvements. These are very big upside opportunities for us and our company. Muhammed Ghulam - Raymond James & Associates, Inc.: Okay. Thank you. That's all from me.

Thank you. Talk to you soon.

Thank you. Next question will be from Luke (29:56) at Energy Intelligence. Please go ahead.

Hi. Thanks for taking my call. I was just wondering if among the exploration wells you're planning next year, if any of that involves further appraisal at Hoffe Park? I know you guys just acquired full operatorship there from Chevron. I'm just wondering what your plans might be for that discovery going forward?

Yes. In our current budget draft a well to be drilled at Hoffe Park is included and we're very excited about it.

And you got any resource estimate for that?

It will probably be around 100 million barrel prospect at this time.

Okay. Thanks.

Mean.

Did you have any further questions, sir?

That's it for me.

Thank you.

There are no further phone questions at this time. I would like to turn the call back over to Roger Jenkins for any closing remarks.

Appreciate people calling in today, and if you have any further questions, contact our IR team and we'll get those lined up for you and appreciate it and we'll talk to you soon. Thank you.

Thank you, sir. Ladies and gentlemen, this does conclude your conference call for today. Once again, thank you for attending. We now ask that you please disconnect your lines.