U.S. Markets closed

Edited Transcript of MUR earnings conference call or presentation 2-May-19 2:00pm GMT

Q1 2019 Murphy Oil Corp Earnings Call

EL DORADO May 8, 2019 (Thomson StreetEvents) -- Edited Transcript of Murphy Oil Corp earnings conference call or presentation Thursday, May 2, 2019 at 2:00:00pm GMT

TEXT version of Transcript

================================================================================

Corporate Participants

================================================================================

* David R. Looney

Murphy Oil Corporation - Executive VP & CFO

* Eric M. Hambly

Murphy Oil Corporation - EVP of Onshore

* Kelly L. Whitley

Murphy Oil Corporation - VP of IR & Communications

* Roger W. Jenkins

Murphy Oil Corporation - CEO, President & Director

================================================================================

Conference Call Participants

================================================================================

* Arun Jayaram

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Brian Arthur Singer

Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst

* Pavel S. Molchanov

Raymond James & Associates, Inc., Research Division - Energy Analyst

* Roger David Read

Wells Fargo Securities, LLC, Research Division - MD & Senior Equity Research Analyst

================================================================================

Presentation

--------------------------------------------------------------------------------

Operator [1]

--------------------------------------------------------------------------------

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2019 Earnings Conference Call. (Operator Instructions)

And I would like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

--------------------------------------------------------------------------------

Kelly L. Whitley, Murphy Oil Corporation - VP of IR & Communications [2]

--------------------------------------------------------------------------------

Thank you, Sylvie. Good morning, everyone, and thank you for joining us on our first quarter earnings call today. With me are Roger Jenkins, President and Chief Executive Officer; David Looney, Executive Vice President and Chief Financial Officer; Mike McFadyen, Executive Vice President, Offshore; and Eric Hambly, Executive Vice President, Onshore.

Please refer to the information on slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude the noncontrolling interest in the Gulf of Mexico, and also our assets in Malaysia will be characterized as discontinued operations.

Slide 2. Additionally, please keep in mind that some of the comments made during this call will be forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurance can be given that these events will occur or that 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 2018 annual report on Form 10-K on file with SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

I will now turn the call over to Roger Jenkins.

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [3]

--------------------------------------------------------------------------------

Thank you, Kelly. Good morning, everyone, and thank you for listening to our call today. First quarter is an extremely busy quarter at Murphy as we continue to execute on transformative transactions. Our results illustrate our commitment to being an oil-weighted company with production from our U.S. onshore and North American offshore assets that continue to generate robust netbacks.

Production from continuing operations in the quarter averaged 148,000 barrels equivalent per day with 60% oil. Our U.S. onshore production's 36,000 barrels equivalent per day with 72% oil, and our North America offshore production was 62,000 barrels of oil equivalent per day with 92% oil.

Our high-oil mix production located primarily in the Gulf Coast drove robust netbacks, where our U.S. oil production achieved an average netback of just over $56 per barrel as compared to our first quarter WTI price of $54.90. Our U.S. oil production represents 76% of our total company production with more to come following the closing of our LLOG transaction.

We remain focused on aligning our financial strategies with shareholders' priorities. Through our disciplined capital allocation process, we were able to return 20% of total operating cash flow from continuing ops back to our shareholders and achieve the strong North America offshore EBITDA per barrel of $36 a barrel.

Our Board of Directors approved a $500 million share repurchase that we intend to commence before quarter's end, and a central part of our ongoing strategy is to responsibly develop oil and natural gas while investing in our local communities where we work. With that, I'm proud that we recently published our inaugural sustainability report.

Over the past several months, we made tremendous strides in transforming our company with acquisitions, divestitures and oil-weighted discoveries. We signed an agreement to monetize Malaysia business for 4.4x 2019 EBITDA and redeployed the capital into a signing agreement to acquire Gulf of Mexico assets at 3.5x 2019 EBITDA. Both are real value-creating transactions, which allow us significant free cash flow generation in the future. We also continue to have exploration success at 2 discovery wells we drilled in the first quarter, one in Mexico Deepwater Block 5, the Cholula well; and the other is Vietnam Cuu Long Basin Block 15-01, the LDT-1X well.

Slide 4. We've worked very hard to transform Murphy. We divested Malaysian assets for $2.1 billion, a place that's been most successful in the company's history generating billions of dollars of cash flow. Production in the region was coming increasingly gas-weighted, which is going to cause margins to decline. Our in-country taxes were subject to a 38% cash tax rate with production-sharing contract terms becoming less favorable. Last fall, we were able to strike a deal with Petrobras to form a joint venture in the Gulf of Mexico. Again, very attractive deal metrics. Combine this with our latest Gulf of Mexico acquisition from last week, we're able to benefit from meaningful synergies in the play and generate significant free cash flow. We were able to repatriate primarily all the proceeds in Malaysia to a more tax-advantage regime in the U.S. and utilize our net operating losses essentially avoiding cash taxes in the United States for years to come. These 3 deals together are accretive transactions and drive significant shareholder value.

On Slide 5. We continue to successfully execute on the 5 tenets of our strategy. We dramatically strengthened our oil-weighted portfolio while increasing operatorship with our 2 recent Gulf of Mexico transactions placing Murphy as one of the Top 5 Gulf of Mexico operators. As we see many repeatable low-cost tiebacks in play, we'll be able to execute.

Also remain committed to exploration, we're pleased with our recent discoveries. In the Gulf of Mexico, we were able to lower our operating costs, as evidenced by our first quarter OpEx of $8.10 per barrel, the lowest in a very long time. Also through our Gulf of Mexico transaction, we were able to grow our production reserves in the basin while adding minimal costs to our business.

On Slide 6. As we review our production and CapEx, we need to keep in mind that these volumes are amounting from continuing operations net to Murphy unless otherwise noted. The first quarter, we produced 148,000 barrels equivalent per day. First quarter production was 58% from onshore and 42% from offshore. Our production was lower than expected in onshore Canada, primarily from a third-party midstream specification constraint causing us to shut-in a new well pad in Simonette area. We will not be able to flow this pad for the remainder of the year, which is impacting annual production in this play.

In the Gulf of Mexico, the majority of our production is impacted as a result of royalty adjustment due to production exceeding cumulative threshold levels in one of our new fields. The Eagle Ford Shale was lower than forecasted, primarily due to significant delay in bringing online of a new 10-well pad along with offset fracs. We're in the early stages of ramping up our Eagle Ford business and are now just experiencing meaningful growth as current production is approaching 44,000 equivalents per day.

We now expect our full year 2019 CapEx to be in the range of $1.15 billion to $1.35 billion after adjusting downward for the Malaysian capital. Capital range for continuing ops has not changed. Our second quarter production guidance is 143,000 to 147,000 barrels equivalent as we expected to experience significant plant downtime in the quarter. Our Tupper Montney has a 2,800 barrel equivalent per day shut in due to third-party facility maintenance. The Gulf of Mexico is impacted a near 4,300 barrels equivalent a day for a third-party platform turnaround and shut-ins related to tie-in of new wells to flow later in the year. And Canada Offshore has a 400 barrel equivalent per day downtime event due to plant facility turnaround.

Second quarter guidance does not include production from the recent Gulf of Mexico transaction with LLOG we expect to close prior to quarter end and provide annual updates of our guidance at that time.

I'll now turn the call over to David, our CFO, to give the financial update.

--------------------------------------------------------------------------------

David R. Looney, Murphy Oil Corporation - Executive VP & CFO [4]

--------------------------------------------------------------------------------

Thank you, Roger, and good morning. For the first quarter, Murphy generated net income of $40.2 million or $0.23 per share, with adjusted income of $26.5 million or $0.15 per share. These results exclude the noncontrolling interest or NCI related to our MP GOM business and our first quarterly results to reflect Malaysia as discontinued operations. Since we agreed to sell our Malaysian business in March, the operations of this segment are carried into discontinued operations for the entire quarter pursuant to GAAP rules.

Similarly, all of the balance sheet accounts related to the Malaysian business are rolled up into 1 of 2 accounts, either assets or liabilities held for sale. And lastly, the cash flow statement excludes the Malaysian operations until you get to the very bottom of the statement, where all such cash flows are covered in the section titled cash flow from discontinued operations.

In addition to the complexity caused by the MCI and discontinued operations treatment, we had several unusual items all hit in the first quarter totaling over $57 million pretax. These included $15 million in noncash G&A charges related primarily to the upward movement in our share price from December 31 to March 31; $27 million in total expenses related to our MP GOM transaction, of which $14 million was a noncash mark-to-market adjustment of our potential contingent payment liability; and $13 million for the write-off of suspended well costs related to 2 wells drilled in Block 11-2 in Vietnam during 2017.

Turning now to Slide 8. Once again, we generated free cash flow, when adjusted for working capital differences, of approximately $45 million more than our CapEx in the quarter. The working capital change was primarily driven by a buildup of receivables in our MP GOM subsidiary as a result of the structure of our transition services agreement. We expect this anomaly to be gone beginning in the second quarter as that agreement has now expired.

Lastly, in order to protect -- to partially protect our increasing exposure to oil prices resulting from our greatly expanded Gulf of Mexico portfolio, we entered into a series of hedges at the WTI level for the remainder of 2019 and all of 2020. Specifically, we hedged via swaps 20,000 barrels per day for each of these periods at a level of $63.64 per barrel for the remainder of 2019 and $60.10 per barrel for 2020. And finally, as a reminder, we do still have until December of 2020 over 59 million cubic feet a day of hedges at AECO for CAD 2.81 per Mcf, well above current market levels.

With that, I'll turn it back over to Roger to review the company's operations.

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [5]

--------------------------------------------------------------------------------

Thank you, David. On Slide 10, the first quarter. We brought 13 operated wells online in Eagle Ford Shale, of which 4 were in Tilden and 9 in Karnes. Karnes wells were brought on late in the quarter only flowing for 2 days. As we're just beginning to allocate sustainable and appropriate level of capital to this asset, production will begin to ramp up as we move through the year. This is illustrated by our well cadence from the prior 3 quarters with a total of 30 wells online. Looking forward to the next 3 quarters, we expect to bring online a total of 79 wells, 30 versus 79 with a consistent quarterly cadence, I think that says it all, and we'll get the asset back in growth mode again.

Slide 11. We're continuing to see strong well performance in our acreage as I believe we have been conservative with our spacing for a long time, our type curves and our EUR assumptions. In the Karnes area, for instance, our early production for the recent drilling pad is very strong. The Lower Eagle Ford wells are producing IP30 rates exceeding 2,100 barrels equivalent per day, the Upper Eagle Ford Shale wells are producing IP30 rates exceeding 1,400 barrels equivalent per day with cumulative production from majority of the 4 wells tracking above the 492,000-barrel equivalent type curve, becoming another positive data point supporting our codeveloping of Upper and Lower Eagle Ford Shale intervals. All impressive results.

Slide 12. The Montney. This site continues to deliver reliable well performance, first quarter pricing was relatively strong in the play. And along with our strong well performance, we expect to generate modest free cash in 2019. Our marketing team continues to mitigate our AECO exposure through hedges in all AECO sales. For the first quarter, we're realizing near CAD 3 Mcf as compared to an average AECO price of CAD 2.62. We will continue to benefit from our pricing and diversification strategy going forward.

Slide 13. In the Kaybob Duvernay, we brought 4 wells online. The 3 wells in Simonette were curtailed due to midstream specification constraints and are planned to be shut in for the remainder of the year. As market conditions in the play remain below prices in U.S. basins, we have decided to revise our annual plan and bring online 7 wells as compared to the original 12 in the plan. We still expect to drill 18 wells as part of our acreage-retention strategy.

As we look at Slide 15 and our Gulf of Mexico portfolio, here's a map of the Gulf of Mexico assets, including our recently announced acquisition. The new additions to our Gulf of Mexico portfolio complement our current holdings and leverages our deepwater operating expertise as well as provides synergies to future exploration projects and our Samurai project. Also, we gained approval from federal regulators to operate Cascade Chinook that will add value as our goal is to streamline and improve operations. We remain on track to close the LLOG acquisition before the end of the second quarter.

On Slide 16. And the Gulf of Mexico assets continue to perform well with very low operating costs. At Dalmatian's, we're currently planning for a new 1-well program that should flow in the fourth quarter. At Medusa, we have a workover rig in the second quarter. And at Front Runner, a rig moving in for a 3-well program expected to start in the third quarter. Samurai project commenced pre-FEED with development plans to be disclosed midyear. At nonoperated, Lucius, our partner will add 3 wells, 2 in the second quarter and 1 in the third quarter. We also adding up to 5 new wells in nonoperated East Coast Canada business in the second and third quarters. In Vietnam, our LDV field received approval for Declaration of Commerciality, and our development team is in place to start the project execution phase.

Slide 18. We drilled discovery of our first exploration test in Block 5 in Salinas Basin offshore Mexico. The Cholula well reached a total depth of 8,800 feet. The well was drilled for approximately $12 million net to Murphy. Exploration well discovered hydrocarbons in the Upper Miocene target objectives, encountering approximately 185 feet of net pay. The results of the wells have significantly derisked the block, and we're currently evaluating future appraisal plans. It's too early to quantify volumes without additional appraisal. We're excited to have successfully encountered pay in all of our objectives in the Upper Miocene area in an oil-charged system. We especially look forward to incorporating the well results into multiple look-alike prospects for the Upper Miocene that are near the Cholula well.

Offshore Vietnam on Slide 19. Drilled another discovery in the Cuu Long Basin, the LDT-1X is spud in March and completed drilling operations in April. We drilled a total depth of 14,000 feet for $13 million net to Murphy. The well successfully encountered approximately 320 feet of net oil pay in the primary objective, an additional 62 feet of net oil in secondary objective. The LDT-1X discovery will be incorporated until development of the adjacent LDV field, which we're operating and progressing toward First Oil in late 2021. This will further derisk many similar cumulated plays near our LDV field as illustrated on the slide.

Slide 20. In the Gulf of Mexico, we plan to spud our Hoffe Park 2 exploration well in the third quarter. Looking forward to drilling this well as we have the ability to tieback now to our newly acquired LLOG infrastructure.

On Slide 22. We're very proud of the deal metrics across the board that we've been able to generate with our recent M&A transactions. Alone, each of these transactions are very meaningful, and now putting them together is extremely powerful for Murphy and our shareholders. We're able to invest in a combined basis when we divest Malaysia at 4.4x 2019 EBITDA and turn around and acquire assets combined at 2.6 2019 EBITDA. On a dollar per flowing metric, we're able to sell for 45,000 per flowing and buy for 28,000 per flowing, and assets that are oil-weighted with lower operating expenses.

On a reserve basis, we were able to monetize our 2P for $11 per barrel of oil equivalents, becoming a more gas-weighted entity, and acquire for $10.59 per barrel oil equivalents. All very impressive metrics, and considering selling 2P with 40% oil weight and buying 2P for 82% oil weight.

Combining the Gulf of Mexico transactions along with our divestiture of Malaysia, we're swapping assets with 58% oil production by volume to assets with 77% production by volume of oil, all while focusing on Western Hemisphere assets are expected to drive overall lower costs and higher margins per barrel equivalent. As discussed in the previous disclosures, there's no question we'll generate significant value for shareholders with our exit of Malaysia and buying 2 accretive deals in the Gulf of Mexico.

Slide 23. Moving into our long-range plan, I would like to step back and look at where we've come in the last 5 years. We've greatly reduced our global footprint in exploration. 2013, we explored worldwide. Today, after much work and focus, we're in 6 fewer countries than we were in '13 and far few basins, increasing our oil focus. We've lowered our back-office expenses in these regions by over 70%. Operationally, we've made significant changes. We've exited Malaysia heavy oil, oil sands in Canada, Alaska, South Louisiana. We acquired Gulf of Mexico assets at attractive metrics and focused primarily in the Western Hemisphere with production in the U.S. and Canada.

This streamlining has led to lower costs and increased exploration focus, which has been a -- seen in recent success in a robust program going forward. Focus, we've never lost our competitive advantage of execution and our ability to negotiate accretive deals that add shareholder value.

Slide 24. Let's review where we see Murphy going in the next 5 years. Recently, we updated a 5-year long-term plan of our company involving the sale of Malaysia, the growth from Eagle Ford. Now with our recent LLOG transaction, we have an even stronger long-term plan to generate significant free cash in addition to our strong dividend. Graphically, we can see this coming to fruition with all -- with our 2 accretive Gulf of Mexico transactions more than replacing Malaysia with higher amounts of production, all significantly oil-weighted. We maintain our spending plans in the Eagle Ford that offers growth in addition to these transactions, leading to a truly transformed company, with again our oil CAGR being generated primarily from Western Hemisphere operating areas and always with balance sheet strength and providing for our shareholders.

Slide 25. In closing, we're in position for the company for long-term value creation. By producing oil-weighted assets that realize premium pricing, we're transforming the company with new assets to drive further profitable oil-weighted growth. We're making significant strides toward closing 2 outstanding deals that we expect to close before the end of the quarter. Our recent exploration success in Mexico and Vietnam further derisked our acreage positions. And as always, we remain focused on aligning our strategy with shareholders.

With that, I can turn the call over back to our operator and take on your questions. Thank you.

================================================================================

Questions and Answers

--------------------------------------------------------------------------------

Operator [1]

--------------------------------------------------------------------------------

(Operator Instructions) And your first question will be from Arun Jayaram at JPMorgan.

--------------------------------------------------------------------------------

Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [2]

--------------------------------------------------------------------------------

I wanted to start with the drill bit. You mentioned in Mexico these were oil charged reservoirs. Was wondering if you could comment if the shows on the Cholula well were oil or gas or maybe a combination of both. But just trying to understand maybe the oil potential at Cholula.

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [3]

--------------------------------------------------------------------------------

The well has 185 feet of pay in it, 29 -- just to back up a second about this well. It was a low-risk well, very high on the structure. Had some very interesting seismic flat spots, they call it in the industry, which normally indicate hydrocarbon and water or hydrocarbon or oil or gas type interfaces. All the amplitudes were successful. All showed pay. There is gas paid in the well in the most upper part of the pay count, around 29 feet, and after that, we're in gas condensate and oil the remainder of the way -- or the rest of the way in the well toward that 185-foot number. Very excited about amplitude means pay in the Upper Miocene area, which is very common, of course, in the Gulf of Mexico.

And now we're able to get a look at our Comitán field -- not field but discovery nearby Cholula. That's around a 75 million-barrel equivalent type thing, and around us is around 130 million of tieback Gulf of Mexico amplitude prospects that we can evaluate. And we also prove we can evaluate it very, very inexpensively. Look to go down there next year and drill that in the combination and also have an option for a true subsalt Miocene test that would be very common to the normal Gulf of Mexico as well. And so this is an Upper Miocene discovery. Has oil in it. Significantly most of the oil, very high quality. A lot of oil samples in the area, 25 degree oil and average API there. And they're off to a good start on the well that really -- if you really look at our exploration program, we drilled a couple of wells and added some nice resources and derisked a lot of things, for around $25 million net to the company. And that's pretty rare and I think very important.

--------------------------------------------------------------------------------

Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [4]

--------------------------------------------------------------------------------

Okay. Did you say the first 29-foot was gas and the rest was combo? I just wanted to...

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [5]

--------------------------------------------------------------------------------

The rest are condensate or oil, primarily oil.

--------------------------------------------------------------------------------

Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [6]

--------------------------------------------------------------------------------

Okay. Great. Second question is just to maybe give us a sense of the resource opportunity between the LDV and LDT fields. And maybe just some thoughts on the potential to sanction this development later this year.

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [7]

--------------------------------------------------------------------------------

Well, the LDV field in Vietnam were under some rigid -- the requirements around field development, there's a Declaration of Commerciality phase, and there's some type -- what we call an area development plan. We're well into that for the big field LDV. It's around 100 million barrel field with our partner group. What we have here as we've described many times, you have a granite wash type system where there's a lot of granite basement pay throughout the Cuu Long Basin, very prolific. And this is a fractured sandstone that drapes on top of that granite basement. We have lots of oil, that we found these wells, actually found higher quality in this reservoir section than we did in LDV. And what we're looking at now is some low-risk inexpensive structures that we can drill again for $12 million or $13 million.

Our share are cheaper now that we understand the well program. This was quite an up-dip structure to LDV, but we now have derisked these small accumulations all around. That these would be very small platforms, very similar to our Sarawak oil developments in Malaysia, very economic. One big facility, if you will, in the middle of the field with several small platforms. We're developing what we believe is some unique multilateral technology to add more well counts to wellbores. This is about a fractured sand that you drill high-angle wells through. This structure came in a little higher, and we didn't get as much pay as we'd like because we didn't have the angle built at the time. But through high-angle wells, there's been many successful flow test here. And this is some low-risk exploration potential here that's all been in every well to the desired -- to the spill point of the reservoir. And then also in this well, we hit a -- found pay in an upper amplitude, an upper pay section that ties to a large amplitude pay of a pinch-out play, similar to other places in the world. The LDH here, which is quite a large accumulation on a mean-type, exploration-type size. And these wells can easily get to -- we probably won't get in there till a year from now to go back as we're concentrating on the development.

Then we're going to have a lot of add too. This will come in right behind the development and will not be difficult to go. But we need to stay with the one big field and add this to it. So it's another accumulation that we can easily add. And like I said, we're pleased with what we found and pleased with the quality that was better than we've seen before, and we already have a successful field with lower quality. So feel pretty good about the cost and very good about the success we had in this well.

--------------------------------------------------------------------------------

Arun Jayaram, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [8]

--------------------------------------------------------------------------------

Okay. Roger, my final question, just some of the midstream disruptions at Kaybob. What's the situation here? When do you get -- expect to get this resolved?

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [9]

--------------------------------------------------------------------------------

I'm going to have Eric handle that question for me, Arun.

--------------------------------------------------------------------------------

Eric M. Hambly, Murphy Oil Corporation - EVP of Onshore [10]

--------------------------------------------------------------------------------

Thanks for the question. So we had 3 new wells in the Simonette area of Kaybob that are tied into a third-party operated battery. The oil from that battery is priced on a condensate type of contract, not an oil type of contract. And the liquids from our well came in with an oil density that more resembles an oil type of density than a condensate. So the -- we're not able to sell through the existing oil pipeline contract that, that third-party operator has at the battery.

We're developing options to sell that oil through other means, through other contracts. All those will take a little bit of time. For the forecast going forward, we've assumed that those wells are not flowing this year, but it's possible that they could come on a little bit earlier if we're able to resolve it through commercial discussion or through an alternative outlet for the crude sales.

--------------------------------------------------------------------------------

Operator [11]

--------------------------------------------------------------------------------

(Operator Instructions) And your next question will be from Brian Singer at Goldman Sachs.

--------------------------------------------------------------------------------

Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [12]

--------------------------------------------------------------------------------

Wanted to follow up on Mexico and the Cholula discovery and the area around it. You mentioned the exploration program in 2020. Can you add a little bit more color on what that could look like, how widespread it could be or how many wells? And you mentioned the derisking of the Upper Miocene area. What about the other horizons like the Mesozoic and some of the prospects you list here in that portion of the block?

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [13]

--------------------------------------------------------------------------------

This particular well targeted 2 things, Brian, a Upper Miocene very similar to Gulf of Mexico that we normally work in area and a Lower Miocene area that had a pretty large amount of reserve associated with it. That area came in oil-charged throughout. There was oil charge all the way down getting oilier starting, as I said with Arun's question, around some gas in the utmost part of the well. And from thereon down was continuing to get oilier. Just not enough reservoir development at the crest of the structure. So we derisked that oil is in the Lower Miocene.

And next year, we're probably looking at a program to delineate probably this well because one of our pay zones in the well was full debase of oil and did not have a flat spot of seismic, if you will, meaning a contact, and we saw no contact. And we believe down dip, which happens a lot. In the Gulf of Mexico, it's down dip. We could have a thickening of that reservoir and also have some additional amplitudes pinched up against that. That would be probably one of the choices. We're working on a 2 to 3 well program to do that and wanted the nearby amplitudes that ties to this well from an amplitude, depth, age, seismic response, and then we're also looking further outboard at a larger subsalt project to be very similar also to the Gulf of Mexico in the northern areas of the Gulf. But are intrigued about the Upper Miocene area about the cost, how we got started there and what we can do there and what we've derisked. So it's an important program, get back in there next year with permitting. And our first step of going down there, last year, we permitted only a single well. We got that approved and worked through all of that, learned how to operate there and now going back with another program and excited about it to get down and drill some wells. The best thing about it for us is we can go into a place and expose $10 million to $15 million.

Now that we've seen the well design, it was a totally trouble-free well, a very highly executed well. We can probably change our casing programs and also really make the well cheap. And also this is dramatic cost improvement on development. So there's a lot of positives from the well. Wish I've had more pay I suppose in lower section, but it was quite nice, and that derisked some things for us. I'm real pleased about it.

--------------------------------------------------------------------------------

Brian Arthur Singer, Goldman Sachs Group Inc., Research Division - MD & Senior Equity Research Analyst [14]

--------------------------------------------------------------------------------

Great. And then my follow-up's on the Eagle Ford, couple issues impacting the first quarter in terms of artificial lift. And then the execution on 10-well pad. Were these one-offs that are done? And was there -- or any risks as the year progresses? And then was the execution issue on the 10-well pad just timing? Or was there any impact on the well performance?

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [15]

--------------------------------------------------------------------------------

I'll let Eric handle that, but in general, these are -- this is a higher-pressured part of Eagle Ford, some of the highest flow rate wells in the Eagle Ford, some of the more difficult drilling in the entire Eagle Ford Shale. And I'm sure EOG and other people around this, this is very prolific area. We do large 10-well pads here due to offset frac because there's a lot of well activity in the region. These are mechanical things. When you get in a long -- these are 2 5-well pads adjacent to each other.

And you get into a linear construction system and something happens to one part of the assembly line, you hurt yourself greatly. And this high-pressured nature of these fracs makes the drill out to be more difficult. We've had some problems with it about a year ago, had a similar problem again this year. Got it fixed. We're doing a new 10-well pad, very near here. That's absolutely complete and will flow any day now, and mechanical work is behind it. So I feel that there was an impact in the quarter, and I'll let Eric comment about the artificial lift matters.

--------------------------------------------------------------------------------

Eric M. Hambly, Murphy Oil Corporation - EVP of Onshore [16]

--------------------------------------------------------------------------------

So we had a bunch of wells that came online last year that were fairly near this drilling pad that the wells came online late in the quarter. And those wells made a transition from flowing to artificial lift. We installed in the initial completion tubing with gas lift mandrels. And we found that we had a batch of gas lift mandrels that failed. So as the wells needed artificial lift and maybe saw a bit of water from the adjacent fracs, the wells weren't keeping up with production. We had to go in and replace those valves. They were fairly high volume wells, and they were all -- got work overall about the same time, which was a significant impact.

That's a onetime event that's a batch of gas lift mandrels that was fairly unique for us. It's not something that's pervasive. As Roger described, our well delivery for the new wells, the issue is largely behind us, so the challenging area has been drill completed online. And don't expect any of the issues that plagued us in the first quarter to carry over into the second quarter or beyond.

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [17]

--------------------------------------------------------------------------------

One more comment, Brian, on the Eagle Ford. It really is very simple. We've not put enough CapEx in here. Our new change company of buying Petrobras and LLOG was to get a consistent approach. You're a shale expert and know it's very hard to run a big shale business with 7 to 8 wells a quarter. So this has been a problem for us with front-end loaded CapEx, inconsistent well cadence, in an area that we actually do fairly well but the team struggles with this, it's actually 3 quarters in a row of low well adds due to front-loading of CapEx. But if you look at the slide we have in the deck today, we have a big wall of well that's coming with a big high quarterly add that I think is going to change the world for us. You got to have new wells in shale. You got to have them all the time.

We knew that with some capital allocation throughout our company that we needed to do at that time to arrange for other things for long term. We've done that now. We've changed our business more in the Western Hemisphere to get this capital allocation to this asset. It's been a very successful asset for us, and Eric and his team has got a big wall of wells coming, starting even this weekend, and they'd get in -- back into this cadence. We're going to do a lot better in the play. I think it's more about inconsistent capital front-end loaded over 2, 3 years that's caused this, and we're going to get beyond that with some well adds here.

--------------------------------------------------------------------------------

Operator [18]

--------------------------------------------------------------------------------

Next question will be from Pavel Molchanov at Raymond James.

--------------------------------------------------------------------------------

Pavel S. Molchanov, Raymond James & Associates, Inc., Research Division - Energy Analyst [19]

--------------------------------------------------------------------------------

Can I ask about the dividend? We've seen companies kind of debate the question of what to do with excess cash flow, whether to look at more buyback or in some cases, a higher dividend payout. You guys already have a significantly higher than kind of peer group yield as it stands. That being said, you have, of course, cut it a few years back. So I'm curious what your thoughts are on the current level of payout, how appropriate it is.

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [20]

--------------------------------------------------------------------------------

Well, I mean, dividend is something that's a long-term history of our company, we are one of the leaders in cash flow, percent cash flow paid. If you look back to the past, Apache and Murphy are by far in the lead on percent of cash flow, operating cash flow, paid out as dividends. We're right in there if not one of the top 2 all the time. So the dividend is quite high and a big part of our investment. I think over the last 4 years especially accumulation of '16, '17 and '18, you will see Murphy has done well on a relative basis to our peers I think because of rewarding shareholders and that issue of not issuing equity in '16. So we did reduce our dividend, but it's still very large and very high yield. After we get our new assets in, we're going to have significant cash flow.

We have a lot on the table right now. I'm very pleased with how these closings, these complex transactions are going. They're going very well. Our legal and business development teams do a great job at getting to the goal line on these projects. And when we get all that in place, we've -- oftentimes, you look back at the history of Murphy, for many, many years, reviewed the dividend in August or October Board meetings. And when we get in line with our long-range plan and our budget for the next year, we'll be reviewing that. As a consistent dividend-paying company, which we are, it is more appropriate to have a slight increase in your dividend every year. I think it's stagnant to keep it for a long, long period of time. But we'll be reviewing that. And you have to also keep in mind that we've never issued equity really of anything we can find on Bloomberg in our history since the '50s. And when we do these buybacks, they're very significant.

And we did some major buybacks back in -- when oil was much higher. So we removed a lot of the shares of the company in the last 10 years. And so when you look at our dividend this year and the EBITDA we're going to have on the annualized basis, and you put the buyback in there, we're the king of the road at that parade, Pavel. And so we're real pleased about that, and these buybacks are very meaningful, we don't issue equity at the bottom. And so we're -- we've done a lot for shareholders. We're going to do a lot more, and I think that the buy back with the dividends, pretty dang good from my view.

--------------------------------------------------------------------------------

Pavel S. Molchanov, Raymond James & Associates, Inc., Research Division - Energy Analyst [21]

--------------------------------------------------------------------------------

Let me also ask about Vietnam. When you sold Malaysia, one of the rationales you said at the time was the tax rate in Malaysia was less attractive than, for example, Gulf of Mexico. Do you have a sense of the fiscal terms in Vietnam and how those compare to what you were seeing in your Malaysian operations?

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [22]

--------------------------------------------------------------------------------

It's a very similar higher tax regime, much higher than U.S., probably approaching that same 38% to 40%, as I recall. But the thing about Malaysia, we've been there for almost 20 years. It's our 20th year actually. And we went there in 1999, at another oil crash at the time. And so for years and years, we paid no taxes at all. And if you're in Vietnam, it's a better situation because we built up exploration expenses through the years to have us a tax cushion, if you will, and then we'll be recovering our costs. And through that, we'll have help on the taxes. Malaysia had taxes with each specific PSC. This will be a tax regime for the country, as I recall. So it's going to be a while before we pay taxes there.

You stay in place for a long time. You make $22 billion of cash like we did in Malaysia, you got to pay taxes at the end. So we're moving on, but this is a long-term strategy of moving out of there with -- started with a lot of work with government affairs around the NOL and the deemed repatriation and the setup back to a Canadian subsidiary. This has been part of a 5-year plan to have no tax leakage. Our tax team and our finance team has done an incredible job. It's been a long time coming to do this.

And to bring -- to make all of that money and to bring that money home without being hit on it and keep your NOL and go to cash tax 0 for several years, pretty big home run for us. And -- but we're in good shape in Vietnam, won't pay taxes there for a while. And so that's just the way it goes internationally, saying we'll be setting up tax bases in Mexico as well, and that will go through there. But when you make a lot of money, you pay a lot of taxes, and that ended up being the case back in Malaysia.

--------------------------------------------------------------------------------

Operator [23]

--------------------------------------------------------------------------------

Next question will be from Roger Read at Wells Fargo.

--------------------------------------------------------------------------------

Roger David Read, Wells Fargo Securities, LLC, Research Division - MD & Senior Equity Research Analyst [24]

--------------------------------------------------------------------------------

Roger, I guess maybe we could talk a little bit more about the Gulf of Mexico. Obviously, having closed the second transaction, I get that, but what would be your real hard thoughts on timing for when you're able to share something with us in terms of where you think it could go. And I don't mean that we don't understand the layout for the next several years of where production basically stay flat. But we would anticipate you bought these assets, you see some other opportunities and some potential to probably outperform what you laid out for us. So just curious, is that a 6 months later, is that 12 months later kind of a thought process there?

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [25]

--------------------------------------------------------------------------------

That's 6 months later. I mean what we do in these processes, and we have a team that's very experienced subsurface and looked at these -- working their bodies, this thing, for 3 years. And then assets come in and come out, we understand the 2P here and have risked the 2P the way we do our BD business. This asset has some differing workovers and sidetracks to do that we've risked in the plan I think appropriately. There's significant field that LLOG discovered in the Gulf, along with their partners, very near Samurai. It's 166 million-barrel oilfield there. We're 34%.

They are -- have started a process to develop that through the selection of a floating production system. Our team is now involved in the middle of that. Is their way of scheduling the wells different to make it -- to make it better for us, probably so. We have partners there we're going to have to talk to and meet with them over the last field development plan. All that's the first thing. We will work on the sanctioning of that, be the first thing to come. We of course know about that. It's one of the big assets in the field. So the assets are some flatter assets, and ours are too but be in the Gulf, make a lot of money there. We've made a lot of money. It's one of the highest full cycle return businesses we've ever had globally. Of course, you'll never beat Malaysia again but historically very good. You'd have decline, and to keep an 85,000 day business flat in the high 300s CapEx is really good and way better than shale, way better than shale. So it's a situation of it's still a really good business to overcome that, do we think we can add IRR and NPV by developing one of their new field slightly differently and working with our partners? Sure. But really in the middle of that, I've got people at their office today. They're a great partner to work with. We've been working with them very well.

Some of the other partners in the fields are partners with us, and other exploration very near some other infrastructure we bought. So this is all going well. And we -- of course, [we turned out], I'm very happy with the 2P that we risked and how we're going to do the developments in order to make approaches. And now like anything else, we'll be trying to improve it and are working toward doing that, informing -- but it's a 6-month thing minimum there, Roger.

--------------------------------------------------------------------------------

Roger David Read, Wells Fargo Securities, LLC, Research Division - MD & Senior Equity Research Analyst [26]

--------------------------------------------------------------------------------

Okay. Appreciate that. And then the other question. Within what you've -- you're going to be able to put together here, and again, I recognize we haven't closed the transaction -- the second transaction just yet. But as you think about sort of optimizing assets and what -- I guess it's still a relatively fertile Gulf of Mexico market for kind of smaller M&A. Other things you'd want to do here, other things you feel you'll need to do to kind of optimize your overall footprint out there. Just what else are you seeing in that area in terms of growing especially given your comments that structurally it's a little better business to run than the treadmill on the shale area?

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [27]

--------------------------------------------------------------------------------

Well, we have both, and we're doing -- we're getting our shale business back in order with the appropriate capital. But I'm just speaking about the maintenance CapEx, I mean you have to admit that it's fairly well. It will be lumpier, but it'll be good. Really not in the selling business, just in the buying business in the Gulf. Happy with what we have, a lot of historic production with infrastructure with other operators flowing to us. We're actively exploring. We went to a lease sale and picked up 5 blocks here just last month. We barely lost 2 or 3 more. There's forming opportunities, with super majors.

The group that we are purchasing continuing on to work and have an active business. We have a close relationship with them. We're meeting new partners through them and working at some wells. So I would say we'll be more on exploration inside our typical $100 million capital where we continue to be able to do a lot of things for $100 million in offshore exploration, which is why I'm so glad we never abandon offshore. So not -- today, not looking to sell or optimize. Happy with what we have, but we're in the business development business. If you look back over the last 5 years, we've done a lot of deals in Murphy, and we certainly haven't -- see the e-mails to my CFO and business development leaders, I certainly haven't slowed down my crazy thoughts. So we're going to keep working at it. And we'll, as usual, we'll let you know when you wake up in the morning.

--------------------------------------------------------------------------------

Operator [28]

--------------------------------------------------------------------------------

There are no further questions from our phone lines. I would like to turn the call back over to Roger Jenkins for any closing remarks.

--------------------------------------------------------------------------------

Roger W. Jenkins, Murphy Oil Corporation - CEO, President & Director [29]

--------------------------------------------------------------------------------

Okay. Thanks, everyone, for calling in today. Appreciate your questions and looking forward to another quarter, and we'll update you then, and thanks a lot.

--------------------------------------------------------------------------------

Operator [30]

--------------------------------------------------------------------------------

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending, and at this time, we do ask that you please disconnect your lines. Enjoy the rest of your day.