Murphy Oil Corporation (MUR) Q1 2019 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2019 Earnings 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.

Thank you Cynthia. 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 of slides we have placed on the Investor Relations section of our website as you follow on with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude the non controlling 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 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 2018 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.

Thanks, Kelly. Good morning everyone and thank you for listening to call today. First quarter is extremely busy quarter at Murphy as we continue to execute on transformative transactions. Our results illustrate our commitment to being 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 is 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 hill oil mixed production located primarily in the Gulf Coast drove robust netbacks where our U.S. oil production achieved an average an average net back of just over $66 per barrel as compared to a 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’re able to return 20% of total operating cash flow from continuing ops back to our shareholders and achieved 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 quarters in. An essential part of our ongoing strategy is to responsibly developed oil and natural gas or 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 4.4 times 2019 EBITDA and redeploy the capital and to sign an agreement to acquire Gulf of Mexico assets at 3.5 times 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 to two 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 15-1, the LDT-1X well. Slide 4. We work very hard to transform Murphy. We divest some Malaysian assets for $2.1 billion, the place it’s been most successful in 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 coming 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. Combined this with our latest Gulf of Mexico acquisition from last week we are able to benefit from meaningful synergies and play and generate significant free cash flow. We were able to repatriate primarily all the proceeds in Malaysia to 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 three deals together, are accretive transaction to our significant shareholder value. On Slide 5, we continue to successfully execute in the five tenants of our strategy. We dramatically strengthened our oil way to portfolio while increasing operatorship at our two recent Gulf of Mexico transactions, placing Murphy as on the top five Gulf of Mexico operators. As we see many repeatable low-cost tiebacks in play, we'll be able to execute. Also we remain committed to exploration are pleased with our recent discoveries. In the Gulf of Mexico we are 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 are able to grow our production reserves in the Basin while adding minimal cost to our business. On Slide 6. As we review our production CapEx we need to keep in mind that these volumes are amount from continuing operations net to Murphy unless otherwise noted. First quarter we produced 148,000 barrels equivalent per day. First quarter production is 58% from onshore and 42% from offshore. Our production is lower than expected in onshore Canada primarily from a third-party midstream specification constraint causing us to shutting a new well pad in Simonette area. We will not be able to follow this pad for the remainder of the year which is impacting annual production in this play. In the Gulf of Mexico a majority of our productions is impact of result of royalty adjustment due to production exceeding cumulative threshold levels, 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 1.3 5 billion after adjusting downward for the Malaysian capital. Capital range for containing ops has not changed. Our second quarter production guidance is 143,000 to 147,000 barrels equivalent is expected to experience significant planning downtime in the quarter. Our Tupper Monteny has a 2,800 barrel equivalent per day shut in due the third party facility maintenance. The Gulf of Mexico has impacted near 4,300 barrels equivalent a day for third party, but from turnaround and shut ins related to tight in of new wells to slow later in the year. And Canada offshore is 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 who will give a financial update.

Thank you, Roger. And good morning. For the first quarter, Murphy generated net income of $40.2 million or $0.23 cents per share with adjusted income of $26.5 million or $0.15 cents per share. These results exclude the non controlling interest or NCI related to our MP Gom business and our first quarterly results to reflect in Malaysia as discontinued operations. Since we agreed to sell our Malaysian business in March, the operations of this segment are carried in the 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 one of two 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 recovered in the section titled cash flow from discontinued operations. In addition to the complexity caused by the NCI and discontinued operations treatment, we had several unusual items all hid in the first quarter, totaling over $57 million pre tax. These included $15 million in non-cash 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 right off of suspended well costs related to two 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 build-up 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 hedge the VS 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.

Thank you, David. Slide 10 the first quarter of our 13 operated wells online in the Eagle Ford Shale, which fall until the lines in Karnes. Karnes that what we brought on late in the quarter, only flowing for two days as we were just beginning to allocate sustainable inappropriate level of capital with this asset production begin to ramp-up as we move through the year. This is illustrated by a well cadence from the prior three quarters with a total of 30 wells online, but could forward in the next three quarters, we expect to bring all in line 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 contains these strong well performance on our acreage, is 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 pads is very strong, the Lower Eagle Ford 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 which came into production for a majority of the four wells tracking above the 419,000 barrel equivalent type curve becoming another positive data point, supporting our co-developing of Upper and Lower Eagle Ford Shale intervals, all impressive results. Slide 12, the Montney. Despite continued to deliver reliable well performance, first quarter pricing was relatively strong in the play and along with our strong well performance to expect to generate modest free cash in 2019. Our marketing team continues to mitigate our AECO exposure through hedges in all of AECO sales for the first quarter we realized near CAD 3 Mcf as compared to an average AECO price of $2.62. We will continue to benefit from our pricing and diversification strategy going forward. Slide 13, in the Kaybob Duvernay, we’ve brought four wells online, the three wells in Simonette were curtailed due to midstream specification constraints and applying to be shut in for the remainder of the year. This market condition is in the play remained below prices in U.S. basins, we have decided to revise our annual plan and bring online seven wells, as compared to the original 12 in the plan. We still expect to drill 18 wells as part of our acreage retention strategy. If you look at Slide 15 in 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 compliment, our current holdings and leverages are deep water operations expertise as well to provide 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. Slide 16, and the Gulf of Mexico assets continue to perform well with very low operating costs. Dalmatian's are currently planning for a new well program that should flow in the fourth quarter. At Medusa, we have a workover rig in the second quarter and the Front Runner rig moving in for a three well program, expect to start in third quarter. Samurai project commenced pre-fee with development plans to be disclosed mid-year. At non-operated Lucius, our partner will add three wells, two in the second quarter and one in the third quarter. We also bet adding at the five new wells in non-operated 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, the expression well discovered hydrocarbons in the Upper Miocene target objectives and countering approximately 185 feet of net pay. The results of wells have significantly de-risked the Block, 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 and all of our objectives and the Upper Miocene area and an old charge system. Especially look forward to incorporating the well results and to multiple look alike prospects for the Upper Miocene that are near the Cholula well. Offshore Vietnam on Slide 19. Drilled another discovery in Cuu Long basin the LDT-1X is quite in March and completed drilling operations in April. We drilled a total depth of 14,000 feet for $13 million net to Murphy, well successfully encountered approximately 320 feet of net oil pay and the primary objective an additional 62 feet of net oil and secondary objective. The LDT-1X discovery being incorporated, which is the development of the adjacent LDV field, which were operated and progressing towards First Oil in late 2021. This will further de-risk many cumulated plays near our LDV field as illustrated on this slide. Slide 20, on the Gulf of Mexico we plan to spud our Hoffe Pa 2 exploration well in the third quarter. Looking forward to drilling this well, as we have the ability to tie back now to our newly acquired LLOG infrastructure. On Slide 22, these transactions are very meaningful and now putting them together extremely powerful for Murphy and our shareholders. We’re able to invest in a combined basis and we divest from Malaysia at 4.4 times 2019 EBITDA and the turn around and acquire assets combined at 2.6 2019 EBITDA on a dollar per flowing metro, 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're able to monetize our 2P for $11 per barrel of oil equivalent becoming a more gas related entity and acquire for $10.59 per barrel all 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 as long as the divestiture of Malaysia, we're swapping assets to 58% oil production by volume to assets with 77% production by volume of oil. All while folks in a Western Hemisphere assets are expected to drive overall lower cost and higher margins per barrel equivalent. As discussed in the previous disclosures, there's no question of generate significant value for shareholders or their exit of Malaysia buying two creative 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 last five years we’ve greatly reduced our global footprint and expiration 2013, we explored worldwide, today after much work and focus we're in 6-Tier countries and we are in 13 in 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 where it's exited Malaysia, heavy oil, oil sands in Canada, Alaska, South Louisiana, we acquired Gulf of Mexico assets at attractive metrics and focus primarily in the Western Hemisphere with production in the U.S. and Canada. The streamline has led to lower costs and increased expiration focus, which has been a – seen a recent success in a robust program going forward. Focus, we've never lost our competitive advantage of execution and our abilities negotiated creative deals that add shareholder value. Slide 24, let’s review where we see Murphy go into the next five years, recently we updated a five year long-term plan of our company involving the sale of Malaysia, the growth from Eagle Ford, now with our recent LLOG transaction of an even stronger long-term plan that generate significant free cash in addition to our strong dividend. Graphically, we can see this coming to fruition with all – with our two 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. Once 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 they were allowed to premium pricing, we're transforming the company with new assets to drive further profitable oil-weighted growth. We're making significant strides toward closing two outstanding deals that we expect to close before the end of the quarter. Our recent exploration success in Mexico and Vietnam, further de-risks their acreage positions, as always remained focused on aligning our strategy with shareholders. With that, I can turn the call over back to our operator and take on your question. Thank you.

Thank you, sir. [Operator Instructions] And your first question will be from Arun Jayaram at JP Morgan. Please go ahead.

Good Morning, Roger and team. I wanted to start with drillbit. Good morning. You mentioned in Mexico these were oil charger reservoirs. But I was wondering if you could comment if the shows on the Cholula well were oil or gas or maybe a combination of both. Bt just trying to understand maybe the oil potential or Cholula.

The well had 185 feet of pay in it, 29 – by the way, this is to back up the second about this well. It was a low risk well and very high on the structure that's been very interesting seismic flat spots they're called an industry which only indicate hydrocarbon and water – hydrocarbon or all or gas type interfaces. All the amplitudes are successful, all showed pay, there is gas paid in the well in the most upper part of the pay count around 29 feet. Then after that we're in gas condensate and oil the remainder of the way – on the rest of the way and 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 look at our common time field – not field, the discovery nearby Cholula, that's around the 25 million barrel equivalent type thing. And around us is around 130 million of tie back Gulf of Mexico amplitude prospects that we can evaluate and we also approved we can evaluate it very, very inexpensively and we'll have to go down there next year and drill that in a 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 sampled in the area, 25 degree oil and average API there and off to a good start on a well that really – if you really look at our expiration program, we drill a couple wells and added some nice resources and de-risk a lot of things around $25 million to net to the company. And that's a pretty rare and I think very important.

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

The rest is condensate or oil, primarily oil.

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

Well, the LDV field in Vietnam were under some rigid, the requirements around field development as the declaration of commerciality phase. Then there's an tie, what we call an area development plan. We're well into that for the big field LDV it's around a hundred million barrel field with our partner group. And what we have here is 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 and this reservoir section than we did in LDV. And what we're looking at now in 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 programs. This was quite enough dip structure to LDV, but we now have de-risked these small accumulations all around but these will be very small platforms, very similar to our Sarawak oil developments in Malaysia be very economic, one big facility if you will, in middle of the field with several small platforms. We're developing what we believe with some unique, a multi-lateral technology to add more well counts to well bores, this was about a fractured sand that you drill high angle wells through the 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 when you drill high angle wells here, there's been many successful protests there and this is some low risk, exploration potential here. That's all been in every well to desire to the spill point of the reservoir. And then also in this, well we hit a found pay and 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, which is quite a large accumulation on it, a mean type, an exploration type size and these wells can easily get to, we probably won't get in there to a year from now to go back as we were concentrating on the development. Then we're going to have a lot of add to. 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 were pleased with what we found and pleased with the quality that was better than we've seen before. And I 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.

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

I’ll have Eric handle that question for me Arun.

Thanks for the question. So we had three new wells in Simonette area of Kaybob that are tied into a third party operated battery. The oil from that battery is priced on a common pay 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, then a condensate. So, we are 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.

Great. Thanks for that.

Thank you. Appreciate it.

[Operator Instructions] And your next question will be from Brian Singer at Goldman Sachs. Please go ahead.

Good morning, Brian.

Good morning. Wanted to follow-up on Mexico and Cholula discovery in the area around it. You’ve 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 – how many wells, and you mentioned the de-risking of the Upper Miocene area, what about the other horizons like the Mesozoic and some of the prospects you list here on the – in that portion of the block?

This particular well targeted two things, Brian, Upper Miocene very similar to the Gulf of Mexico that we normally work in area and a Lower Miocene area that had a pretty large amount of reserves associated with it. That area you came in oil charged throughout, this oil charge all the way down getting oilier starting as I've said with Arun’s question about some gas and the utmost part of the well and from there on down was continuing to get oilier, just not enough reservoir development at the crest of the structure. So, we de-risk that all is in the Lower Miocene and next year we probably be 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, is the down dip. We could have a thickening of that reservoir. And I also have some additional amplitudes pinched up against that. That would be probably one of the choices who work on a two to three world programs do that. And one of the nearby amplitudes that ties to this, well from an amplitude depth age, seismic response. And then we're also looking further out board at a larger sub salt 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 and how we got started there. And all we can do there and what we de-risk. So it's an important program to 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've got that approved and work through all that, learned how to operate there. And now going back with another program and excited about it to get down and drill some wells and best thing about it for us. As we can go into a place and expose $10 million to $15 million now that we see the well design, it was a totally trouble-free well at 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 all now on development. So, it was a lot of positives from the well wish I had more pay suppose in the lower section. But it is quite nice and de-risk some things for some, we’re pleased about it.

Great. Thanks. And then my follow ups in the Eagle Ford, couple issues impacting the first quarter in terms of artificial lift and then the execution on 10 well pad, with these one-offs that are done and was there any risk spread as the year progresses. And then was the execution issue on the 10 well pad just a timing or was there any impact on the wells.

, : And I let Eric comment about the artificial lift matters.

So we had a bunch of wells that came online last year that were fairly near this drilling pad that the wells came Dillon pad that well came online late in the quarter. And those wells made a transition from flowing to artificial lift. We installed in the initial completion to being with gas lift mandrels. And we've 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 fracks, the wells were keeping up with production and we had to go in and replace those valves. They were fairly high volume wells and they were all – got work over all 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 drilled completed online. And we don't expect any of the issues that plagued us in the first quarter to carry over into the second quarter or beyond.

One more comment Brian on the Eagle Ford do you know it really is very simple. We have a not put enough CapEx in here are our new change company of buying Petrobras and LLOG is to get a consistent approach. You’re a shale expert and know it's very hard to run a big shale business with seven, eight wells a quarter. So it’s been a problem for us with front end loaded CapEx and consistent well cadence in an area that we actually do fairly well, but the team struggles with this. This is actually three quarters in a row of low well hedge due to front loading of CapEx. So if you look at the slide we have in the deck today, we have a big wall of wells coming with a big high quarterly add, that I think is going to change the world for us. We got to have new wells and shale, we got to have them all the time. We knew that we had some capital allocation throughout our company and we needed to do at that time to arrange for other things for long-term. 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 in this cadence and we’ll do a lot better in the play. I think it's more about inconsistent capital front end loaded over or three years that's caused this and we're going to get beyond that with some well heads here.

Great. Thank you.

Thank you.

Thank you. Next question will be from Pavel Molchanov at Raymond James. Please go ahead.

Thanks for taking the question. 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 pure growth 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?

Well, I mean dividend is something that is a long-term history of our company. We are one of the leaders in cash flow, percent cash flow paid. If you look back at the past Apache and Murphy about far in the lead on percent of cash flow, operating cash flow paid out as dividends we’re writing there if not one of the top two all the time. So the dividend is quite high and a big part of our investment, I think, over the last four years, especially accumulation of 2016, 2017 and 2018, 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 2016. 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 of 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 to history of Murphy for many, many years you view the dividend in the August or October Board meetings. And when we get an alarm of our long range plan and our budget for the next year, we will 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 it 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 then we did some major buybacks back in and all is much higher. So you've 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 EBITDA we're going to have on an annualized basis and you put the buy back in there we’re the king of the road at that parade, Pavel. And so we're real pleased about that. And these buy backs are very meaningful. We don't issue equity at the bottom. So we've done a lot for shareholders we’re going do a lot more. And I think that the buy back with the dividends are pretty damn good from my view.

Let me, also ask about Vietnam. When you fold Malaysia one at time rationale was 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?

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. This our 20th year actually. And we went there in 1999 and another oil crash at the time. And so for years and years we paid no taxes at all. And in here in Vietnam is a better situation because we built up exploration expenses through the years that have us a tax cushion if you will. And then we'll be recovering our costs. And do that we will 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 for the 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 – started with a lot of work with government affairs around the NOL and the [indiscernible]. And the set up back to Canadian subsidiary, this has been part of a five year plan to have no tax leakage or tax team and our finance teams have done an incredible job. It’s been a long time coming to do this to make all that money and bring that money home without being hit on it and keep your NOL and go to cash tax zero for several years pretty big home run for us. And therefore we're in good shape in Vietnam we won’t pay taxes there for awhile. And so that's just the way it goes internationally saying well we set up the tax bases in Mexico as well and that will go through there but make a lot of money, pay a lot of taxes. And that ended up being the case and back in Malaysia.

I understood.

Thank you.

Thank you. Next question will be from Roger Read at Wells Fargo. Please go ahead.

I guess maybe we can talk a little bit more about the Gulf of Mexico. Obviously having close 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 is 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 six months later, is it 12 months later kind of the thought process there?

That's six months later. What we do in these processes is that we have a team that's very experienced subsurface and it looked at these [indiscernible], this thing for three years. And when assets come in and coming out, we understand that the 2P here and have risked the 2P the way we do our BD business. This asset has some differing work overs and side tracks 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 to Samurai. It's 166 million barrel oil field there, we’re 34%. They 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 there a way of scheduling the wells different to make it – to make it better for us? Probably so. We have partners that are going to have to talk to and meet with on our last field development plan. All that's the first thing that we'll work on the sanction of that be the first thing that come with course know about that it's one of the big assets in the field. So there's some flatter assets and ours are too. When you are in the Gulf, make a lot of money, there we've made a lot of money on the highest full cycle return businesses we've ever had globally. Of course you'll never be Malaysia again, but historically very good. They have decline and to keep an 85,000 day business flat and then in the high $300 CapEx is really good way better than shale, way better than shale. So it's a situation of – it's still a really good business to overcome that. We think we can add RRR and NPV by developing one of their new fields 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're 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. This is all going well and we of course [indiscernible], but I'm very happy with the 2P that we risked and how are we going to do the developments in order to make the approaches. And now like anything else, we'll be trying to improve it and working toward doing that, informing a bit. It's a six-month thing, a minimum there a Roger.

Okay. Thanks. Appreciate that. And then the other question within what you're going to be able to put together here and there 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 are the things you feel you'll need to do to kind of optimize your overall footprint out there. What else are you seeing in that area in terms of growing, especially given your comments to structurally it's a little better business to run than the treadmill and the shale area.

Well, we have both, and we’re doing them we’re getting shale business back in order with an appropriate capital. But I'm just speaking about the maintenance CapEx Scott backs. I mean, you have to admit that it's fairly, well. It’ll be lumpier, but it'd be good, really not in the selling business, just in the bond business in the Gulf. Happy of what we have a lot of historic production with infrastructure, with other operators flow into us. We're actively exploring we went to the lease sale and picked up five blocks here just last month. We barely lost two or three more. There's a forming opportunities and super majors. The group that we are purchasing, continuing onto work and have an active business with we have a close relationship with them, we’re meeting new partners through them and working at some wells. So I would say we’ve been more on exploration inside our typical $100 million capital where we continue to be able to do a lot of things for $100 million. An offshore exploration which is why I'm so glad we never abandoned off shore. So today not looking to sale or optimize happy with what we have. But we're in the business development business. If you look back over the last five years, we've done a lot of deals in Murphy. And we certainly haven't through the emails to my CFO and Business Development Leader, certainly haven't slowed down my crazy thoughts. So we’re going to keep working at it. And as usual we'll let you know when you wake up in the morning.

Alright, crazy like a fox, I'm sure. Thanks, Roger.

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

Okay. Thanks everyone for calling in today. I appreciate the questions and looking forward to another quarter. We’ll update you then. And thanks a lot.

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.