Murphy Oil Corporation
Q2 2017 Earnings Call Transcript

Published: 3 Aug 2017

[Operator:]

Good day and welcome to the Murphy Oil Corporation's Second Quarter 2017 Earnings Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Kelly Whitley, Vice President, Investor Relations & Communications. Please go ahead.

[Kelly L. Whitley:]

Good morning, Andrew. Good morning, everyone, and thank you for joining 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 that we have placed on the Investor Relations section of our website as you follow along with our webcast today. John will begin the call by providing a review of the second quarter financial results highlighting our balance sheet and strong liquidity position, followed by Roger with second quarter highlights and operational update, of which questions will be asked afterwards. 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 discussions of risk factors, see Murphy's 2016 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publically update or revise any forward-looking statements. I will now turn the call over to John for his comments.

[John W. Eckart:]

Thank you, Kelly, and good day to everyone. Murphy Oil's consolidated results in the second quarter of 2017 were a loss of $17.6 million, $0.10 per diluted share. That compares to net income of $2.9 million, $0.02 per diluted share, in the same quarter a year ago. Excluding discontinued operations, our continuing operations had a loss in the second quarter of 2017 of $17.4 million, also $0.10 per diluted share. Our adjusted loss, which adjust our GAAP numbers for various items that affect comparability of results between periods, was a loss of $19.1 million, $0.11 per share, in the second quarter of 2017. Our schedule of adjusted loss is included as part of our earnings release and the amounts in this schedule are recorded on an after tax basis. Our balance sheet continues to show low leverage with ample liquidity and manageable debt maturities. At June 30, 2017, our total debt was $2.9 billion, or 37% of total capital employed, while net debt was 27% of capital employed and amounted to $1.83 billion. At the end of the second quarter, we had no outstanding borrowings under our $1.1 billion revolving credit facility, and cash and invested cash balances totaled $1.1 billion at quarter end. Following the December 2017 bond maturity of $550 million, Murphy does not have further debt maturities until 2022. Our oil and natural gas revenue for the quarter totaled $509 million. That's a 24% increase from the same quarter in 2016. In order to underpin our cash flow, we hedge a portion of our oil and forward sell a part of our natural gas production. At the end of the quarter, we had 22,000 barrels per day of oil hedged at $50.41 per barrel WTI for the second half of 2017. On the natural gas side, we had 124 million cubic feet per day forward sold at AECO at CAD 2.97 per MCF for the balance of this year, and as well we had 59 million cubic feet per day at AECO at CAD 2.81 per MCF for 2018 through 2020. We have also contracts for 20 million cubic feet per day at Chicago City Gate priced at $3.51 per MCF for the period from November 2017 to March of 2018. That concludes my comments. And I will now – Roger will now present a review of the company's operations.

[Roger W. Jenkins:]

Thank you, John. Good morning, everybody, and thanks for listening to our call today. In second quarter we produced 163,000 barrel equivalent per day comprised of balanced mix between onshore and offshore production, with our onshore business producing 51% liquids and our offshore business producing 71% liquids. For the quarter, the company invested $201 million in capital projects, in line with our 2017 capital budget of $890 million. A conservative balance sheet management, ample liquidity, and cash on hand will continue to build positive financial momentum as we progress through the year. Our diverse asset base provides a competitive margin, near $18 EBITDA per BOE for the second quarter. We're continuing to maintain our top quartile dividend yield in this challenging commodity price environment, while paying our way and living within our cash flow. Operationally, we're successfully accomplishing all of our 2017 goals. We're progressing our Kaybob Duvernay appraisal plan, and we're pleased with our above plan early results. In Eagle Ford Shale play we continue to cost effectively capture additional resource for using our Cube multibench completion design. And our Tupper Montney asset, we're committed to bring forward value by accelerating long-term growth through additional takeaway commitments. In our offshore assets we continue to execute on highly economic, production optimization projects, and enhance our exploration portfolio. In Malaysia, we're achieving stable, high margin production implementing innovative projects, such as surface jet pumps and Dry Tree Unit gas lift subsea equipment. In Vietnam, we drilled a discovery well in the Nam Con Son Basin. In the Gulf of Mexico, we continue to progress evaluation of our Mexico Deepwater Block 5, which is near a recently announced major discovery. I'll now look at the second quarter in more detail. Production in the third quarter is expected to be in the range of 156,000 to 158,000 equivalents per day. Third quarter production guidance is below our second quarter actuals due to pre-planned downtime work at our Sarawak oil and gas fields and our non-operated Terra Nova field in Eastern Canada, as well as the loss of the non-operated Kodiak well in the Gulf of Mexico, which is awaiting repair work. There's also planned downtime at Keyera processing plant in Kaybob Duvernay. These temporary production outages are approximately 10,000 barrel equivalents per day are partially offset by new wells we're planning to bring on in our North American Onshore business and better performance in offshore totaling approximately 4,000 equivalents per day. The annual 2017 capital budget is being maintained at $890 million. The full-year 2017 production guidance is being tightened to 163,000 to 167,000 equivalents per day, with North American Onshore production expected to increase by over 15% from fourth quarter 2016 to fourth quarter 2017 as a result of continued ramp-up of activity in our onshore unconventional business as we progress through the year. Our teams continue to be focused on creating substantial cost efficiencies that have and will continue to lead toward lower operating expenses, and data analytics is one of the tools that helps us do that. Our use of data management is one of the reasons we see the lowest level of quarterly operating expenses per BOE in over a decade. In our offshore operations, we have (07

[Operator:]

Thank you. Our first question comes from Arun Jayaram with JPMorgan. Please go ahead.

[Roger W. Jenkins:]

Good morning, Arun.

[Arun Jayaram:]

Good morning, Roger. I was wondering if you could either help us think about your – initial read of your Duvernay results. Looks like some of the wells are outperforming your type curves. I just wanted to – maybe if you could give us some baseline on where D&C costs are today. What kind of EURs do you need to see that – where is your hurdle away kind of EUR and what do you think these most recent – or your early completions are tracking towards in terms of EUR basis? Pardon me.

[Roger W. Jenkins:]

Thanks, Arun, for that question. This year we've drilled these wells, we've been very successful at understanding and managing and drilling very long lateral wells. As a matter of fact, this week we just drilled a well almost over 9,000 feet for around US$2.5 million, so we're very successful at consistently drilling the wells below $3 million the longest laterals ever drilled up in that region. Unfortunately, on some of our wells we've had a problem with casing failure that had to be repaired, and some of our wells had to do with some corrosion, some pipes stored inappropriately. That has caused us some setbacks in the timing of the completion. And those costs when neutralized out, which are one-off current, as we put these costs of these wells, they're around $10 million. We've yet to have – we've pad drilled three wells together, but the completions are all extremely different. So yet to set a water management infrastructure. We've yet to go to full pad drilling and get into a motion of manufacturing, if you will. And we feel very confident about over time lowering these costs by 30% to 40%, which we've done in all of our plays, Montney and Eagle Ford, where we've drilled thousands of wells. And we see that getting into the – our goal of $6.5 million. We see that fully in range. I see the drilling greatly improving of late, like I said with actual data. And that's going to lead to some really nice full cycle, again, economics here, breakeven process is around $40, and this is probably due to our low cost entry, low royalty, and moving to pad development. The EURs will be various across the play. We've proved up pretty solid to around 900 EURs in some of the volatile oil condensate regions. We're working around 600,000 EURs in our more northern part of Kaybob West. We're consistently seeing this perform – saw this 05-29 perform with a very low frac volume for a long time. And if you look at our EURs in the Eagle Ford, this is similar that are larger than that, but the royalty is much, much less. So this is a value creating thing, low-entry, old Murphy strategy at work and the work we do, and very pleased with what we're doing.

[Arun Jayaram:]

Great. That's helpful. My second question, Roger, is as you have now secured some midstream or takeaway in the Montney, could you talk about capital allocation to that place and where you're kind of moving capital as the Montney looks like it's going to take an increasing part of the pie on a go-forward basis?

[Roger W. Jenkins:]

All of our capital plans for the last couple of years have included our drill-to-fill strategy. We have some peers that flow to some of our facilities today, both the Tupper Main and Tupper West. These two strong gas peers have – will be pulling off some of their capacity between now and late 2019. So we're going to be replacing that and that's always been planned. The new bring-forward values to actually add on top of that original plan another $200 million a day into a situation we could continue to add $200 million increments if we choose to do so. The cash flow from this asset with an infusion of around $100 million above the cash flow of the asset only will allow us to get to this new $200 million and can expand from then on with the cash flow provided by the asset. And this very low AECO breakeven price with that ability of free cash to build is going to be very much accretive for us to bring forward this cash now.

[Arun Jayaram:]

Great. Thanks a lot, Roger.

[Roger W. Jenkins:]

Thank you.

[Operator:]

And our next question comes from Ben Wyatt with Stephens. Please, go ahead.

[Roger W. Jenkins:]

Good morning, Ben.

[Ben Wyatt:]

Hey. Good morning, guys. Hey, Roger, I'll hop over to the Eagle Ford if we can.

[Roger W. Jenkins:]

Sure.

[Ben Wyatt:]

You guys had some commentary on the new completion design over there. Just curious if that was all tested in Tilden or if you were able to go to other assets within Eagle Ford and try that. Just trying to get a sense of how confident you are in this completion design, how affordable it is to the other Eagle Ford assets.

[Roger W. Jenkins:]

We see it to be real affordable. For the quarter – I'll get my sheet here. For quarter two, in quarter – let me see, I have a wrong page here. The quarter two wells we delivered. Let me just go ahead and answer your question, I'm fairly confident of the answer. It's very affordable and can be moved between Tilden and Eagle Ford Karnes pretty easily. I'd say the wells are around – 50/50 around where we experimented both in Tilden and Karnes area, and made both of them very helpful.

[Ben Wyatt:]

Got it. Good stuff. And then maybe just now thinking kind of on the offshore international, you guys are clearly excited about that. It seems like costs are really coming down and are competitive now. Just curious if you guys could – if we think out to maybe next year, maybe how the budget looks, how that capital is allocated maybe as a percentage of the total budget, like I said, as we think about 2018.

[Roger W. Jenkins:]

I would imagine exploration spending for drilling wells be like 7% to 10% of the budget, because that similar cost today, the 30% to 40% of the budget. So it's very inexpensive to participate in these opportunities. We've completely changed our exploration team over the last several years, total different strategy. We're bidding in places that have lot of competition with lot of success. Our partner in our block is the same partner with a major successful block in Mexico. We're going to drill two to three wells next year, for sure, and targeting to drill in Mexico in late year. We're working through the permitting process they have. And very excited about where we're working, who's following us around where we're working. Our partnership levels, our working interest not at a high working interest anymore to have more opportunities, and it's going really well for us.

[Ben Wyatt:]

Very good. Well, I appreciate the time, guys. Keep up the good work. Thanks.

[Roger W. Jenkins:]

Thanks, Ben. I appreciate it.

[Operator:]

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

[Roger W. Jenkins:]

Hello Paul. How are you doing?

[Paul Cheng:]

Very good. Roger, in Eagle Ford, I think your last estimate is you have about 800 million barrel of resource still remaining. What will be the sweet spot in longer term? Are you still looking at just 50,000 barrel per day or that is going to be 60,000 or 70,000? I mean, how should we look at it longer term?

[Roger W. Jenkins:]

The – of course, we're not – we're revitalizing our budget and long range plan. I'm also pleased with that. But I think you need to think about that business next year around a $47, $48 business, might get into the low 50s for 2019 and 2020, and then all in up into the high 50s in 2021, 2022, and probably staying at that level.

[Paul Cheng:]

So it would be somewhere between $50 to $60, you believe is the sweet spot for you?

[Roger W. Jenkins:]

Yeah. Yeah.

[Paul Cheng:]

And do you actually have a preliminary outlook for 2018 CapEx and production?

[Roger W. Jenkins:]

No, Paul. I mean, it's not even time for your conference yet, Paul. And I won't say it there either. Let me just make a statement about that. We're like anyone else here of late and around what we work. We have very successful wells in our onshore business too. And we're increasing the EUR per well and doing very well with that, increasing IP30 per well, ahead of where we were a year ago in that. Our offshore assets, especially in Malaysia, are holding up better than we thought a year ago. And we're progressing our new Block H LNG project. That's coming along nicely with that situation. So a solid long-term Sarawak gas business, it's going well for us. And with that backdrop, we're, of course, reworking our plans. And looking at oil prices, et cetera, I'd say today at a high level, WTI in the $48 to $49 2018-2019 number, keeping our debt levels the same as they are today, and ending up around $52 in 2022, we still deliver our single-digit 7% to 10% CAGR there. Paying our dividend. And we're happy about where that's positioned and we will have the ability to do that and we're working toward finalizing and working through those plans over the next few months.

[Paul Cheng:]

Roger, but if we are looking at the in and out on CapEx, I mean, look like that in Duvernay you're going to spend more money, in Eagle Ford probably not, in Montney in the Canadian gas you're probably spending more money for the growth. So should we assume that the CapEx is going to be up at least for next year maybe by a couple of hundred million dollars?

[Roger W. Jenkins:]

We're working towards trying to get to $1 billion, yeah.

[Paul Cheng:]

Okay. On the – I just want to clarify that based on you press release, so should we assume by the – towards the end of 2020 your Canadian gas will be roughly about 500 million cubic feet today?

[Roger W. Jenkins:]

That's exactly where it will be.

[Paul Cheng:]

Okay. Two final one real quick. Do you have a pre-drilled resource estimate you can share for CT-1X discovery and so far do you see is any different than that number?

[Roger W. Jenkins:]

What we have here is a series of very small fault blocks. We probably have 10 million to 12 million barrel discovery, where we originally drilled the well we announced today. This is shallow water jack-up territory, very similar some of our Sarawak field that we put online and been very, very successful there. And we're drilling another fault block of similar sizes, around four other of these fault block opportunities. These are around $8 million net to Murphy to drill these wells, very inexpensive, very low F&D, very low breakeven. There's another discovery by another party in the southern part of this block, a large gas discovery that goes into our block. It's possible we would work with that party in the development or that – or sale to that party or monetizing through capital allocation where we want to do several of these small fields at this time. And we're real happy. This well had a lot of pay in it, over several hundred feet of pay in a very small fault block. And it made us change our drilling position to where we are today and just a small very high margin shallow water business that we've been very successful at running in Malaysia for a long time, for over 10 years.

[Paul Cheng:]

Great. Final one, Malaysia Block K, the floating LNG – or flexible LNG, are we still talking about 2020 startup or that has been changed?

[Roger W. Jenkins:]

No, it's maintained.

[Paul Cheng:]

Okay. Thank you.

[Roger W. Jenkins:]

Thank you, Paul.

[Operator:]

We'll take our next question from Muhammed Ghulam with Raymond James. Please go ahead.

[Muhammed Ghulam:]

Hey. Good morning. This is Muhammed on behalf of Pavel. Thanks for taking the question. My first question is regarding Vietnam, the discovery you announced there earlier today or, I guess, last night. How much future activity do you have anticipated before you're going to assess the resource base present within the country?

[Roger W. Jenkins:]

Well, we have two blocks there, one at the Nam Con Son Basin, with the Cuu Long Basin. Nam Con Son is a block we've had for a few years. We have four to five similar size opportunities. So what we're drilling today are well – recently was a discovery in a small fault block area. It's just a matter of tying together smaller fault blocks, which we've done very successfully before in our shallow water business. In our 15-1 business, we see this field that we've discovered as near 100 million barrel discovery gross recoverable resource. We're working with our partners towards the final clear development running (33

[Muhammed Ghulam:]

Second one is on CapEx. We've seen various operator reporting that service costs increase (33

[Roger W. Jenkins:]

We, of course, have seen some completion costs. I think we've made it through half the year without as much impact on that. It's coming more to bear primarily in Eagle Ford Shale. Nowhere else in our business are we seeing it, primarily around fracking, probably talking around a 20% increase in our completion costs of the wells. Drilling is hung in there very well. We continue to do optimization and ability to drill pacesetter wells primarily in Catarina, where we're actually drilling these wells for barely $1 million in only four days, four-and-a-half days in some situations. Our total CapEx we have reflects the rest of the year. These costs have been – completion is going up. We've managed that through CapEx efficiencies in some of our artificial lift and electrification projects and other projects that we have in the Eagle Ford. They will stand by our CapEx for the year and actually deliver few more wells in Eagle Ford than planned, and pleased with our handling of that situation. Canada, we're not seeing a problem with it and this is more about efficiency in Canada, lining up to do the same completion repeatedly, and we will then have a nice situation there, where our ability to lower days efficiency is just getting started.

[Muhammed Ghulam:]

And last one for me, can you talk about your Australian operations and what your plans for the country? And what's going on over there right now?

[Roger W. Jenkins:]

Well, we have some very nice exploration blocks. We have a very small team that works on that in our company. They are true experts around these two regions. We have all of our 3D seismic shot in our Ceduna Basin fully loaded in our workstations, enormous prospects here, very large prospects. We just need some drilling to go in the area, and we're hoping that super majors nearby will go through with their plan that they reorganizes, which is very positive for us. Vulcan Basin, no well commitment, seismic, very inexpensive, built a very nice business there, ground floor, grassroots old-styled exploration with a very experienced team there work in this region for another major company. And we're looking to drill there probably in the 2019 to 2020 timeframe, and will be monitoring what goes on in the Ceduna Basin during that period. So it's probably a 2020 plus kind of deal for that, but very pleased with the prospectivity we're seeing right now.

[Muhammed Ghulam:]

Yeah. That's all for me. Thanks.

[Roger W. Jenkins:]

Thank you. I appreciate it.

[Operator:]

And it appears there are no further questions at this time. I'd like to turn the conference back over to our speakers for any additional or closing remarks.

[Roger W. Jenkins:]

No. We have nothing left today. It was a nice call. We appreciate everyone calling in and I look forward to talking to you later this fall. Thank you. Appreciate it.

[Operator:]

This concludes today's conference. Thank you for your participation. You may now disconnect.