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Murphy Oil Corp (MUR -1.74%)
Q1 2019 Earnings Call
May. 02, 2019, 10:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
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 -- Vice President, Investor Relations and Communications
Thank you, Silvia. 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 informational 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 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 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 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.
Roger W. Jenkins -- President and Chief Executive Officer
Thank you, Kelly. Good morning, everyone. And thank you for listening to our call today. First quarter was an extremely busy quarter, Murphy as we continue to execute on transformative transactions. Our results illustrate our commitment to being an oil weighted company with production from our US onshore and North American offshore assets that continue to generate robust netbacks.
Production from continuing operation in the quarter averaged 148,000 barrels equivalent per day with 60% oil. Our US 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 high oil mix production located primarily in the Gulf Coast drove robust netbacks for our US oil production achieved an average netback of just over $56 per barrel, as compared to first quarter WTI price of $54.90.
Our US 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 a 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 the four quarters and the 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've made tremendous strides in transforming our company with acquisitions, divestitures and all weighted discoveries. We signed an agreement to monetize Malaysia business at 4.4 times in 2019 EBITDA and redeploy the capital into signing an agreement to acquire Gulf of Mexico assets at 3.5 times 2019 EBITDA. Both the real value creating transactions, which allow us significant free cash flow generation in future. We also continue to have exploration success. The two discovery wells were drilled in the first quarter, one in Mexico deepwater Block 5, the Cholula well and others Vietnam Cuu Long Basin Block 15-1, the LDT-1X well.
Slide 4, we worked very hard to transform Murphy, we do best, our Malaysian assets were $2.1 billion, a 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 of coming less favorable. Last fall, we are 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're able to benefit from meaningful synergies in 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 US and utilize our net operating losses, essentially voting cash taxes in the United States for years to come. These three deals together accretive transaction and drive significant shareholder value.
On slide 5, we continue to successfully execute in the five tenants of our strategy. We dramatically strengthened our oil weighted portfolio while increasing operatorship. There are two recent Gulf of Mexico transactions placing Murphy is 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 remained committed to exploration or pleased our recent discoveries. In the Gulf of Mexico we were able to lower 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've able to grow our production reserves in the basin, while adding minimal costs through our business.
On slide 6, as review our production CapEx maybe to keep in mind that these volumes are amount from continuing operations, net to Murphy unless otherwise noted. The first quarter, we produced 148,000 barrels equivalent per day. First quarter production is 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 shutting a new well pad in some in that 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 production is impacted result of royalty adjustment due to production exceeding cumulative threshold levels and 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 aim for 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 a 143 to 147,000 barrels equivalent as expected to experience significant planned 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 by near 4,300 barrels equivalent day for third-party platform turnaround and shut-ins related to tie-in of new wells flow later in the year. In Canada offshore is a 400 barrel equivalent per day, downtime event the 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 will provide annual update of our guidance at that time.
I'll now turn the call over to David our CFO is going to give the financial update.
David R. Looney -- Executive Vice President and Chief Financial Officer
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 non-controlling 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 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 are covered 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 hit 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 non-cash mark-to-market adjustment of our potential contingent payment liability. And $13 million for the write-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 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 in 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 today of hedges at AECO for CAD2.81 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 -- President and Chief Executive Officer
Thank you, David. Slide 10, in the first quarter of our 13 operated wells online in the Eagle Ford Shale, which fall until the line Karnes. Karnes, we brought on late in the quarter only flowing for two days. As we are just beginning to allocate sustainable and appropriate level of capital of this asset production began to ramp up as we move through the year. This is illustrated by our well cadence from the prior three quarters with a total of 30 wells online. Looking forward to the next three quarters, we expect bring online a total of 79 wells. 30 versus 79 with a consistent quarterly cadence I think that says it all, you know, get the asset back in growth mode again.
Side 11, we continue 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 EURs assumptions. In the Karnes area, for instance, our early production for the recent drilling pad is very strong. Although 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 four wells tracking above the 492,000 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 deliverable 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 Medicaid our AECO spot exposure through hedges in all AECO sales for the first quarter we realized near CAD3 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 brought four wells online and three wells in Simonette were curtailed due to midstream specification constraints and we plan to be shut in for the remainder of the year. As market conditions in the play remain below prices in US basins, we have decided to revise our annual plan and bringing 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 .As we look at slide 15 and our Gulf of Mexico portfolio, here is 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 provide synergies to future exploration projects and our Samurai projects.
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.
In Slide 16 and the Gulf of Mexico assets continue to perform well with very low operating costs. At Dalmatian, we 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 front-runner rig moving in for three well program, expect to start in the third quarter.
Samurai project commenced pre-FEED with development plans to be disclosed, mid-year. Non-operated Lucius our partner will add three wells, two in the second quarter and one in the third quarter. We are also adding up to 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. 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. We are currently evaluating future appraisal plants, too early to quantify volumes with additional appraisal. We're excited to have successfully encountered pay in all of our objectives and the upper Miocene area and in all charge system. Especially look forward to incorporating the well results into multiple look like prospects for the upper Miocene that are near the Cholula well. Offshore Vietnam on Slide 19, driven another discovery in the Cuu Long Basin, the LDT 1X spud 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 in the primary objective and additional 62 feet of net oil in the secondary objective.
The LDT 1X discovery being incorporated which is available as the adjacent LDV field, which we're operator and progressing toward the first oil in late 2021. This will further derisk many similar accumulated plays near our LDV field as illustrated on the Slide 20 and the Gulf of Mexico plan to spud our Hoffe Park 2 exploration well in the third quarter. Looking forward to drilling this wells. We have the ability to tie back now to our newly acquired LLOG infrastructure.
On Slide 22, I'm very proud of the deal metrics across the board that we've been able to generate with the recent M&A transactions. Along each of these transactions are very meaningful and are putting them together extremely powerful from Murphy and our shareholders. We're able to invest in a combined basis, we divest Malaysia at 4.4 times 2019 EBITDA and around -- turnaround and acquire assets combined at 2.6 2019 EBITDA, on a dollar per flowing Metro, we are able to sell a 45,000 per flowing and by for 28,000 per flowing and the assets that are oil weighted with lower operating expenses.
On the reserve basis, we're 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 equivalent, 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 loans, the divestiture of Malaysia, we are swapping assets with 58% oil production by volume to assets with 77% production by volume of oil.
LLOG 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 is no question of generate significant value for shareholders or exit of Malaysia buying two accretive deals in the Gulf of Mexico.
Slide 23, moving into our long wage plan, I would like to step back and look at where we've come in the last 5 years, we greatly reduced our global footprint and exploration. 2013 we explored worldwide. Today after much work and focus, we're in 6 fewer countries and we are in 13 far few basins increasing our oil focus. We lowered our back office expenses in these regions by over 70%.
Operationally, we've made significant changes. We have 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 US and Canada. The streamline has led to lower cost and increased exploration focus which has been seen in recent success and a robust program going forward. So focus we've never lost our competitive advantage of execution and our ability to negotiate accretive deals that adds shareholder value.
Slide 24. Let's review where we see Murphy going in the next five years. Recently, we updated our five year long-term plan of our company involved in the sale 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 two accretive Gulf of Mexico transactions more than replacing Malaysia with higher amounts of production all significantly oil-weighted. To 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, the rollouts 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 derisk their acreage positions and is always 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
Thank you, sir. (Operator Instructions) And your first question will be from Arun Jayaram at JPMorgan. Please go ahead.
Arun Jayaram -- JPMorgan -- Analyst
Good morning, Roger and team. I wanted to start with new drill bit.
Roger W. Jenkins -- President and Chief Executive Officer
Good morning.
Arun Jayaram -- JPMorgan -- Analyst
Good morning. You mentioned in Mexico these were oil charge reservoirs, I was wondering if you could comment, if this shows on the Cholula well were oil or gas or maybe a combination of both, but just trying to understand maybe the oil potential Cholula?
Roger W. Jenkins -- President and Chief Executive Officer
The well has 108 feet of pay in it, 2019 as a way this is just backup a second about this well, it was a low risk well and very high on the structure, that's a very interesting seismic flat spot, they're called an industry original indicate hydrocarbon and water -- hydrocarbon or oil or gas type interfaces. All the amplitudes are successful, all showed pay. There is gas pay and well in the most upper part of the pay count around 29 feet and then after that we are in gas condensate and oil the remainder of the way on the rest of the way and the well toward that 185 foot number. We're 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 ton field, not field, but discovery nearby Cholula that's around the 3,500 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 approved we can evaluate it very, very inexpensively. And look 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 and it's significantly most of the oil very high quality, a lot of oil sampled in the area, 25 degree oil and average API there. And after 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 to around $25 million to net to the company and that's a pretty rare and I think a very important.
Arun Jayaram -- JPMorgan -- Analyst
Okay. Did you say the first 29 foot was gas and the rest was a combo? I just wanted to--
Roger W. Jenkins -- President and Chief Executive Officer
The rest are condensate or oil, primarily oil.
Arun Jayaram -- JPMorgan -- Analyst
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?
Roger W. Jenkins -- President and Chief Executive Officer
Well, the LDV field and Vietnam are under some rigid, the requirements around field development is a Declaration of Commerciality phase. And there isn't tied 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 is we've described many times, you have a Granite Wash type system where there's lot of granite basements 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 and this reservoir section then we did LDV. And what we're looking at now 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 the small accumulations all around would be very small platforms, very similar to our Sarawak oil developments in Malaysia. We're very economic. One big facility, if you will -- in the middle of the field with several small platforms. We are developing what we believe is some unique multilateral technology to add more well counts to wellbore. This is about 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, so yeah, there have been many successful flow tests here. 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 on this well we had a found pay and an upper amplitude and upper-page section that ties to a large amplitude pay of a pent-up pay similar to the 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 until a year from now to go back as we're concentrating on the development that 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 to it. So it's another accumulation and we can easily add in there. Like I said, we're pleased with what we found and pleased with the quality, that was better than we've seen before, may already have a successful field with lower quality. So we feel pretty good about the cost and very good about the success we had in this well.
Arun Jayaram -- JPMorgan -- Analyst
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 -- President and Chief Executive Officer
I'll let Eric handle that question for me, Arun.
Eric M. Hambly -- Executive Vice President, Onshore
Thanks for the question. So we had three 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 we are not able to sell through the existing oil pipeline contract 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.
Arun Jayaram -- JPMorgan -- Analyst
Great , thanks for that.
Roger W. Jenkins -- President and Chief Executive Officer
Thank you. I appreciate.
Operator
Thank you. (Operator Instructions) And your next question will be from Brian Singer at Goldman Sachs. Please go ahead.
Brian Singer -- Goldman Sachs -- Analyst
Good morning, wanted to follow up on Mexico and the Cholula discovery in the area around it. You mentioned the exploration program in 2018. 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 -- President and Chief Executive Officer
This particular well targeted two things, Brain, 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 reserves associated with it, that area came in all charge throughout. There was oil charge all the way down getting oilier starting as I said, with Arun's question around 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 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 folded base 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 it down there, we could have a thickening of that reservoir. And I also have some additional amplitudes pinch up against that -- that would be probably one of the choices we work on a two to three well program to do that. And one of the nearby amplitudes that ties to this well from an ample to 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 and 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 merged permitted only a single well. We got that approved and worked 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. The 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 designed, it was a totally trouble-free well like very highly executed well we can probably change our casing programs and also really make the well cheaper and also this is dramatic cost improvement on development, so there's a lot of positives from the well, we should had more pay as suppose and lower section. But it is quite nice and that derisked some things for us. I'm real pleased about it.
Brian Singer -- Goldman Sachs -- Analyst
Great, thanks. And then my follow-ups in the Eagle Ford, couple issues impacting the first quarter in terms 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 with the execution issue on the 10 well pad just timing or was there any impact on the well performance?
Roger W. Jenkins -- President and Chief Executive Officer
I'll let Eric Hambly. But in general, these are offer. This is a higher pressured part of Eagle Ford, some the highest flow rate wells in the Eagle Ford with some of the more difficult drilling in the entire Eagle Ford Shale in Hampshire EOG and other people around this is very prolific area. We do large 10 well pad here due to offset frac because there's a lot of well activity in the region. These were mechanical things when you're getting along. These are two-five well pads adjacent to each other and you get into a linear construction system if 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. And 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 artificial lift matters.
Eric M. Hambly -- Executive Vice President, Onshore
So we had a -- 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 bit of water from the adjacent fracs, the wells weren't 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 allover about the same time, which was a significant impact that's a one-time 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 with the challenging area, it's been drilled, 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 -- President and Chief Executive Officer
But one more comment Brian on the Eagle Ford, do you know, it really is very simple. We have not put enough CapEx in here our new change company of buying Petrobras and LLOG is to get a consistent approach Eagle Ford Shale expert and no, it's very hard to run a big shale business with seven-eight 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, this is actually three 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 of a big wall of wells coming with the 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 we had some capital allocation throughout our company that we needed to do it that time to arrange for other things for long-term.
We've done that now and we've changed our business one at Western Hemisphere to get this capital allocation to this asset. It's been a very successful asset for us and Eric and his team got big wall wells coming starting even this weekend and they get and back in this cadence from and do a lot better in the play. I think it's more about in consistent capital front-end loaded over two to three years that's calls this and we're going to get beyond that with some well adds here.
Brian Singer -- Goldman Sachs -- Analyst
Great, thank you.
Roger W. Jenkins -- President and Chief Executive Officer
Thank you.
Operator
Thank you. Next question will be from Pavel Molchanov at Raymond James. Please go ahead.
Pavel Molchanov -- Raymond James -- Analyst
Thanks for taking my 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 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 -- President and Chief Executive Officer
Well, I mean dividend is something that 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 Murphy about by far in the lead on percent of cash flow, operating cash flow, paid out dividends were brought in there, if not one of the top two all the time.
So the dividends are quite high in big part of our investment, I think over the last four years and especially accumulation of '16, '17 and '18 you will see Murphy has done well on a relative basis to our peers. I think the calls 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 and 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, they do a great job at getting to the goal line on these projects. And when we get all that in place, we oftentimes if you look back to history of Murphy for many, many years, the dividend in the August or our October Board meetings and when we get in line with 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 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 have never issued equity really of any -- anything we can find on Bloomberg in our history since the '50s.
And when we do these buybacks, there are very significant and that we did some major buybacks back and all is 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 an annualized basis and you put the buyback in there, we're the king of 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 and we're doing a lot more and I think that the buyback with the dividend is pretty damn good from my view.
David R. Looney -- Executive Vice President and Chief Financial Officer
Let me also ask about Vietnam when you sold Malaysia one of 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 -- what you were seeing in your Malaysian operations?
Roger W. Jenkins -- President and Chief Executive Officer
It's a very similar higher tax regime, much higher than US, probably approaching that same 38% to 40% as I recall, but the thing about Malaysia, we've been there for almost 20 years, this is 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 in here in Vietnam is a better situation because it built up exploration expenses through the years to have us a tax cushion, if you will, then we'll be recovering our costs and through that we will have help on the taxes. Malaysia had taxes with each specific PSC. This would be a tax regime for the country as I recall. So it's going to be a while for 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 Dean repatriation and the setback to Canadian subsidiary This has been part of our five-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 that bring -- 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, it's pretty big home run for us. And we're in good shape in Vietnam and pay taxes there for a while. And so that's just the way it goes internationally same will be -- so that the tax basis in Mexico as well, and then we'll go through that, but make a lot of money, pay a lot of taxes. And then in that being the case back in Malaysia.
Pavel Molchanov -- Raymond James -- Analyst
Understood, appreciate it guys.
Roger W. Jenkins -- President and Chief Executive Officer
Thank you.
Operator
Thank you. Next question will be from Roger Read at Wells Fargo. Please go ahead.
Roger Read -- Wells Fargo -- Analyst
Hey, good morning. Hey, good morning, 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 can 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 to what you laid out for us. So just curious, is that a six months later, is that a 12 months later, kind of the thought process there?
Roger W. Jenkins -- President and Chief Executive Officer
I said six months later, I mean, what we do in these processes and we have a team that's very experienced subsurface and we looked at these CME work in the bodies, this thing for three years. And with the assets come in and come out. We understand that 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 is significant yield that LLOG discovered in the Gulf along with their partners, very near 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 better for us, probably so. We have partners there, we have to talk to and meet with him on the revised field development plan. All that's the first thing that we will work on the sanctioning of that would be the first thing that come, we course know about that is one of the big assets in the field. So the assets are some flatter assets and ours are too. But we are in the Gulf make a lot of money there. We've made a lot of money is on the highest full cycle return businesses, we've ever had globally, of course you'll never be lazy again, but historically very good.
We've had declined and keeping 85,000 a day business flat in the high 300s 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 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 got people 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, so this is all going well and we, of course, we turned out, but I'm very happy with the 2P that we risked and how we're going to do the developments in order to make the purchase. And now like anything else we'll be trying to improve it. And we are working toward doing that informing, but it's a six month thing minimum there, Roger.
Roger Read -- Wells Fargo -- Analyst
Okay, thanks. 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 is still 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 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 in the treadmill in the shale area?
Roger W. Jenkins -- President and Chief Executive Officer
Well, we have both and we're doing, we're getting our shale business back in order with the appropriate capital, but I am just speaking about the maintenance CapEx. I mean you have to admit that it's fairly well. It will be lumpier but it will be good, really not in the selling business, just in the buying business in the Gulf, happy with what we have a lot of its historic production with infrastructure with other operators flowing to us. We are actively exploring, we went to lease sale and picked up five blocks here just last month, we barely last two or three 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 are meeting new partners through them and working at some well. So what I would say would 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 and offshore exploration, which is why I'm so glad we never abandoned 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 five years, we've done a lot of deals in Murphy. And that we certainly have it through the emails to my CFO and business we have leader certainly -- have slowed down my crazy thought. So we are going to keep working at it and we will as usual, we'll let you know when you wake up in the morning.
Roger Read -- Wells Fargo -- Analyst
Crazy like a fox, I'm sure. Thanks, Roger.
Roger W. Jenkins -- President and Chief Executive Officer
Thanks, Roger.
Operator
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.
Roger W. Jenkins -- President and Chief Executive Officer
Okay. Thanks everyone for calling in today. I appreciate the questions and looking forward to another quarter and we'll update you then, and thanks a lot.
Operator
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.
Duration: 48 minutes
Call participants:
Kelly L. Whitley -- Vice President, Investor Relations and Communications
Roger W. Jenkins -- President and Chief Executive Officer
David R. Looney -- Executive Vice President and Chief Financial Officer
Arun Jayaram -- JPMorgan -- Analyst
Eric M. Hambly -- Executive Vice President, Onshore
Brian Singer -- Goldman Sachs -- Analyst
Pavel Molchanov -- Raymond James -- Analyst
Roger Read -- Wells Fargo -- Analyst
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