Murphy Oil Corp (MUR) 2018 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Second Quarter 2018 Earnings Call and Webcast Conference Call. (Operator Instructions)

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 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 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 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 continue to drive high margin realizations. This enables us to return 13% of operating cash flow to our shareholders through our long-standing dividend policy. Also achieved an annualized EBITDA for capital employ 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 exceed the high end of the guidance by 2,000 barrels of oil equivalent per day. This beat was driven by our performance on our onshore Canada and Gulf of Mexico assets with 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. In our onshore business we were able to show continuous improvements in cost reductions by achieving our drilling and completion costs goals in the Kaybob Duvernay, at 6.5 million per well, which is ahead of our target date.

In the second quarter, on Slide 4, we continue to successfully execute our focus strategy. We've returned to offshore exploration with successful Samurai-2 well, just mentioned. In Vietnam, we've worked with our partner to assume operatorship of the 15-1/05 block, which shows 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 expectation with production increases by more than 100% year-over-year, while simultaneously achieving record low drilling and completion costs.

During the second quarter, we benefit from the strength of our diversified portfolio, achieving high-margin realizations with a weighted average of $68 per barrel of oil sold.

Slide 5. Over the first half of the year, we delivered strong EBITDA per BOE from 3 core areas. These areas received premium pricing, which is a key of our high-margin generation, and account for 70% of our production and 70% of our capital. First, in Malaysia, achieved an EBITDA of over $36 per BOE. Second, North America offshore, EBITDA of $39 per BOE. And thirdly, Eagle Ford Shale achieved an EBITDA of $38 per BOE. These assets have a full year CAGR of 7% production growth as per disclosed long-range production plan.

On Slide 6 now. We're increasing our full year CapEx guidance by $65 million to $1.18 billion. We're allocating $55 million to onshore Canada, primarily in Kaybob Duvernay for additional wells and required infrastructure. We're planning to bring the additional wells online later this year.

The remaining $10 million is for the deepening and successful welding program of our Samurai-2 well in the Gulf of Mexico.

Production for the third quarter expected to be in the range of 165.5 to 168.5 thousand barrels equivalent per day. Third quarter production is lower than the second quarter due to the annual turnaround of our non-operated offshore Canada fields and to executing operated capital projects in Malaysia, accounting for some 7,400 barrels equivalent per day. The decrease will be partially offset for onshore production growth in the Eagle Ford Shale and Kaybob of 3,900 barrels equivalent per day.

Because of our strong production in first half of 2018, we're also increasing the midpoint of our full year guidance by 1,000 barrels equivalent per day to a range of 168.5 to 170.5 thousand barrels equivalent per day.

I now turn the call over to our CFO, David Looney, who will give a financial update for us this morning.

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 1 year ago.

Our adjusted net income was a profit of $63 million or $0.36 per diluted share in the second quarter of 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 6-month cash flow statement presented on a GAAP basis and displays how certain one-off items negatively impacted us during this period. Primarily, 2 things. #1, the $35 million withholding tax on funds repatriated from Canada earlier this year. And #2, 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 operating wells online this year. 10-well pad in Karnes had an average IP30 of 1,750 barrel oil equivalent per day, 7 of these wells produced at the highest peak rates that Murphy has 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, lower Eagle Ford Shale and plus our very successful Austin Chalk formation. We're also pleased with encouraged 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 5-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, the long-term project, that's 200 million cubic feet per day of production beginning in late 2020. The project is expected to increase reserves by more than 400 BCF. The Expansion has strong economics with full cycle breakeven prices of CAD 1.75 AECO per MCF. Our assumptions are based on a very conservative AECO price of CAD 2 in 2020, with modest price increases to slightly above CAD 3 in 2030. Together, these assumptions, our new tariff and outstanding execution, are able to deliver an income-producing long-term project expected to generate approximately $125 million of free cash flow per year every year going forward.

This project under this set of assumptions has an NPV10 of over $600 million with an IRR of over 25%.

In our Kaybob area, on Slide 12. We brought a 4-well pad on at the 03-33 online at Kaybob West late in the second quarter. We're also currently producing with an initial rate approaching 800 barrels equivalent per day at 80% liquids.

We're allocating $50 million of additional capital to the Kaybob due to outstanding execution and production results and achieving lower and drilling completion costs well ahead of schedule. We now plan to drill and complete 25 wells, and bring a total of 27 wells online during the year.

With this plan, we're on track to deliver a fourth quarter exit rate of more than 11,000 barrels equivalent per day. We continue to reduce the remaining drilling carry, which will be completed by the end of next year.

Slide 13. In our Kaybob Duvernay asset, we increased production by 35% from last quarter and more than 100% from second quarter of '17. Since assuming operatorship of this asset 2 years ago, we've increased production by approximately 500%. At the same time, we've been growing production, we've been significantly reducing drilling and completion costs.

Early in the year, we laid out an aggressive well cost target to reach $6.5 million development cost by end of year 2019. I'm pleased to say that we met that target in the second quarter of this year, which is more than 1 year ahead of plan. We also drilled an industry-leading pacesetter well and competed for only $5.9 million. We expect cost to continue decreasing as we move the asset further into development mode.

Slide 14. In the Gulf of Mexico, we finished the recompletion of Medusa 5 well during the quarter and recompletion improved the producibility of a new zone in that field, and Malaysia assets continue to be a reliable free cash flow generating business. Our Kikeh DTU gas project is now approximately 95% complete, and we expect to bring it online in the third quarter.

At South Acis Field, we've mobilized the jack-up rig for some infill drilling campaign and our Block H Rotan floating LNG project remains on track with first production in 2020.

In Vietnam, as expected, we received full approval to assume operatorship and increase our working interest to 40% in the Block 15-01/05 well. Our development team continues to progress the field development plan for the LDV field, and we expect to declare commerciality by year-end.

Slide 15. Returning to successful exploration. As we previously discussed, Murphy implemented a new focused exploration strategy and I'm very pleased that the first well drilled on this new strategy, the Samurai-2 appraisal well, is a success. As expected, we encountered thicker and better quality sand in the well than the original Samurai-1 well. So far, we've encountered more than 150 feet of pay, which is primarily from 2 zones and a sample of high-quality oil from each. We're also encountering additional pay zones that were not present in Samurai-1 well. As a result, we extended the planned total depth of the well to over 32,000 feet, and are currently logging deeper interval. Along with our partner, we're currently evaluating options to drill a sidetrack into the adjacent block to the south to further appraise this discovery.

We've exceeded our predrill resource estimate of 75 million barrel equivalent, however, we could see upside if the planned sidetrack as well as current evaluation prove successful.

Slide 16. For the remainder of 2018, we have an exciting exploration program, with 3 exploration wells. Expected spud the Gulf of Mexico King Cake well late in the third quarter, and the Vietnam LDT and Mexico Palenque wells in the fourth quarter. Success at one of these wells will be very meaningful to our company.

Slide 17. Finally, I'd like to leave you with a few points this morning. Our second quarter results demonstrate the advantage and strength of our diversified portfolio allowing us to increase our full year production guidance for the second consecutive year -- quarter, I'd rather say. In offshore business, we successfully returned to exploration with the Samurai-2 well, while on our onshore business we achieved record low drilling and completion costs in the Eagle Ford Shale and Kaybob Duvernay. In keeping with our long-standing focus on shareholder returns, we once again paid a competitive dividend to our shareholders, while achieving our goals on cash returns over invested capital. Looking ahead to our long-term plan, our production remains on track to deliver 10% to 15% CAGR over the next 4 years, while spending within cash flow.

Last, I'd like to thank our people who successfully execute our strategy every day for us here at Murphy Oil.

And that's all my comments today, and we'd like to now take your questions at this time. Thank you.

(Operator Instructions)

Hello. Roger, is that you?

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

Yes, Roger, exactly right.

Can you walk us through how you're looking at the Gulf of Mexico exploration, and I'm just curious, the Cosmo transaction announced earlier this week, did you look at it? 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 to have been pretty favorable?

We really don't discuss ins and outs of business development too much. 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 we can because we feel that's the best the way for us going forward, with all the value we can add 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 been 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, not 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 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 is 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, but in a nice portfolio to drill 2 or 3 wells every year that range in size from tie-back, on everything to tie-back 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 the most prolific blocks, probably some of the nicest prospects I've seen in my career. And then we have the Brazil upside in that same hemisphere. So a lot of positivity -- positive action in the Gulf for us and momentum building in the Gulf, and we are 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...

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 delivered, obviously, record wells this quarter and continue to prosecute on that.

Well, we're doing that very well, and I think all of our acreage is prolific there. We've had some -- our best well ever is an Austin Chalk well there, and we have some 50-something locations remaining, which we're very happy about it. 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 fracking packs, how best to drill a wine-rack type design, which we're all over right now in all of our pads today, even in Catarina and Karnes, are both drilling lower and in 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 its core. It's also a real misnomer that I have about 2 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 in the oil-weighted area, it's 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. All in all, it's a very good business and going to continue to be one for us for a long time.

Your next question comes from Paul Cheng with Barclays.

Hi, when you talk about the 240 in Karnes. And if I look in your presentation on Page, I think 29, it seems like this 325, is that just the difference between the gross well and the net well for the working interest?

I would say so Paul, yes.

Right. And you haven't talked anything about Permian wells that you drilled early in the year. Are those wells being tied in or that you are still doing with [them]. Is there any update they can give us?

Paul, we drilled a couple of wells there, it 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 advantage price over Permian to Eagle Ford, we felt like the earlier part of the year, we moved some money down there, and it's involved in the capital that we have today. And but -- so -- but today, in the press, you might have seen that one of the companies staying has purchased acreage there, which touches our acreage that we purchased on lease sale there a couple of years ago. So now, we have to reevaluate that and they paid a lot of money for that acreage right next to where we work. And this year, we were focusing our capital in the Eagle Ford due to incredible price advantages that we have there over the Permian, and so it's -- that's the situation. I find it incredible that we ask a question about 2 wells in the Permian when we had a significant discovery in the Gulf of Mexico, Paul, but that's your question.

We still want to get an update. That on Mexico, you're going to drill 1 well in the fourth quarter. And for the next year that, in total, how many well you're going to drill in Mexico, or that is the only well?

That is the only well planned at present. 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 sub-salt 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, and I believe it will be successful, we'll be looking at other wells to drill there.

Still any kind of current trend has been formulated?

We are taking seismic there with our partner group. I think we're over 65% with the seismic across all the blocks and 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.

So we assume that there's probably -- any drilling is probably 2020 or '21, given that you have a...

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 more or flat? Any kind of direction that you can give?

What was a question about 2019, Paul? What was your...

CapEx outlook versus 2018. Is it going higher?

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 the 1, 2 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. So -- but that's -- there's nothing in our long-range plan that I don't see that won't be the same or positive at this time.

Your next question comes from Arun Jayaram, JPMorgan.

Roger, I wonder if you can spend a little bit more time on Samurai, on Page 15 of the slide deck. It looks like the aerial extent, it could kind of extend into Block 476, I just wondered if you could give us your thinking about the sidetrack and down the road potential development options for the discovery?

Thank you for asking. No one has asked about it yet. Yes, I mean, you can see all the green dots. 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 throwback 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 that the sands do thicken in the 476 block that we feel good about, so do our partner. And I'd 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 mean with an upside to 200, I mean, 200 is quite a big number, but it's not out of the question with what we have and -- but we're very pleased at 75 million barrels. And I can tell you that's your NAV estimate in your report for that on a per-share basis is probably about what we lost today. So yes, your 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.

And, Roger, I don't if you can just walk us through what are potential development options. I know a front-runner is somewhat in the area, just talk us through what could, in timing, and what you're thinking about for developing options there?

Well, with what we're seeing, highly likely we'd have to drill another appraisal well because we've been successful and a lot of these small tiebacks are just Tier 1 zone and you'll bring them back. So price to drill a well a year, finishing a year from now, of course, that's with our partners on all that. And then if we sanction at that time, we could have an early production 2-well system flowing in 2021, mid to third quarter 2021, something to 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 can move that forward a bit, I suppose. Again, we have to work with our partners on that. And we would probably be going back to their 3 different host facilities. We have one of our own, our partner has one, of course, and some nearby, a new facility being built by some other folks so there will 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 -- until we get a lot more information and get ahead of this mean number where we are, it would be just talking tie-back game here, but all of these are very, very accretive and very, very income-providing and great F&D metrics for our company.

Great. And 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 told when I was a young man, if you're getting paid to keep drilling, and that's what we do at 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, we bought this at the total collapse in February of 2016. At that time, it involved a very low amount of money, and you have to go back up to what the goal was. The goal was to replace the production from the same crude at lower operating expenses, as an operator, and lower total cost between DD&A plus OpEx. At the end of the year, we would have done that, with the price of asset plus, that's the way we've accomplished all of our goals, meeting all of our targets. In that deal, with the 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 price, oil price index, associated with that, that allowed that carry 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 out of CapEx until the team showed further ability to execute. The team executed all the way through. We had this carry, we're very successful and we put capital in to get this carry behind us and it put us in a situation of perfect capital allocation, if you will, between the Eagle Ford and that asset, and that's what we working on and that's why the capital is allocated to that.

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 sell. Can you just give us some color around that?

That all involves capital spending timing and listings and loadings as per the capital for the quarter, and we base this usually on a -- these assets in Malaysia, usually about a 375 to a 425 positive over Brent, and then we work through the PSC. But I still would say, even after all PSC effects, we're probably ahead of WTI, and Kelly is giving me the number now. But so on a realized price basis, that -- as a quarter, has to do with timing of capital spent, projects and production and redoing, these things move around, but I still think these realized prices are pretty good compared to a big hunk of the United States.

(Operator Instructions) Your next question comes from Muhammad Ghulam, Raymond James.

So over the one election in Mexico recently, and before the election, you had made several comments about this opposition to the country's energy reform, so since is 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 an 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 -- 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 in that election to prevent that at this time.

So in other words, you guys don't think his victory is really going to change your plans anyway, and you're pretty confident that the new government was going to respect the permit?

Yes, we will.

Your next question comes from David Meats, Morningstar.

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

Well, we placed in our original program of all the exploration wells as a target of F&D of $15. And even on an example if 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 will 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, is good and industry-leading and as good as anything there is onshore, I can tell you. And so that's where we are, I'd say, this will be in the $10 to $15, with $15 at the ultimate top, and that's an industry-leading figure.

Okay. That's super helpful color. So in the, I guess, the exploration outside case where you have the development of Samurai or other discoveries like Samurai, is there any kind of scenario where that exploration success and the resulting development justifies going away from living 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 in the different ways to execute these projects. Where we may not own a facility, if a facility is built and things of that nature, but that's when things happen and things get sanctioned, you make decisions on capital allocation. We surely can't 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.

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 rolling calls, 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 your conference call for today. We thank you for participating, and ask that you please disconnect your lines.