Good morning, ladies and gentlemen, welcome to the Murphy Oil Corporation first quarter 2019 earnings conference call. If at any time during this call you require immediate assistance, please press star 0 for the operator. I would like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Thank you, Sylvie. Good morning, everyone, 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. Also, our assets in Malaysia will be characterized as discontinued operations. Slide two. 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 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 SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins.
Thank you, Kelly. Good morning, everyone, 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 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 was 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 on 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 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 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 before quarter's end. An essential 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 oil-weighted discoveries.
We signed an agreement to monetize the Malaysia business for 4.4 times 2019 EBITDA and redeployed the capital into signing 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. The two discovery wells were drilled in the first quarter, one in Mexico Deepwater Block five, the Cholula well, and the other is Vietnam Cuu Long Basin Block 15-1, the LDT-1X well. Slide four. 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 play and generate significant free cash flow. We were able to repatriate primarily all the proceeds in Malaysia to a more tax-advantaged 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 that drive significant shareholder value.
On slide five, we continue to successfully execute in the five tenets of our strategy, which dramatically strengthen our oil-weighted portfolio while increasing operatorship with our two recent Gulf of Mexico transactions, placing Murphy as one of the top five Gulf of Mexico operators. As we see many repeatable low-cost tiebacks in play, we'll be able to execute. We also remain committed to exploration. We are pleased with our recent discoveries. In the Gulf of Mexico, we're 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 six.
As a review of production and CapEx, you need to keep in mind that these volumes are amounted 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 shutting 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, a majority of our production's impact is 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 thousand to 147 thousand barrels equivalent. It is 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 a day for a third-party platform turnaround and shut-ins related to tie-in of new wells to flow later in the year. In Canada Offshore is a 400-barrel equivalent per day downtime event due to planned 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's 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 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 are 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 one of two accounts, either assets or liabilities held for sale.
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 31st to March 31st. $27 million in total expenses related to our MP GOM transaction, of which $14 million was a 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 eight.
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 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.
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. In slide 10, the first quarter, we brought 13 operated wells online in the Eagle Ford Shale, which four were in Tilden, nine in Karnes. Karnes well were brought on late in the quarter, only flowing for two days. As we are just beginning to allocate sustainable and appropriate levels 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 three quarters, with a total of 30 wells online. Looking forward in the next three 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 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 EUR assumptions. In the Karnes area, for instance, our early production for the recent Dillon 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 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. This play continues to deliver reliable well performance.
First quarter pricing was relatively strong in the play. Along with our strong well performance, we expect to generate modest free cash in 2019. Our marketing team continues to mitigate our AECO spot exposure through hedges and off-AECO sales. For the first quarter, we realized near CAD 3 MCF Canadian 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 four wells online. The three wells in Salmon that 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 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. 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 provide synergies to future exploration projects and our Samurai project. 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. The Gulf of Mexico assets continue to perform well with very low operating costs. At Dalmatian, we're 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 a Front Runner rig moving in for a three-well program expected to start in the third quarter. Samurai project commenced pre-FEED 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're also adding up to five new wells in the non-operated East Coast Canada business in the second and third quarters. In Vietnam, our LDV field received approval for declaration of commerciality. 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 Salina 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 exploration well discovered hydrocarbons in the Upper Miocene target objectives, encountering approximately 185 feet of net pay. The results of the wells have significantly de-risked 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 charge system. We especially look forward to incorporating the well results into multiple lookalike 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 was spud in March and completed drilling operations in April. We drilled to 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 and additional 62 feet of net oil in secondary objective. The LDT-1X discovery will be incorporated into the development of the adjacent LDV field, which we're operator and progressing toward first oil in late 2021. This well further de-risks many similar accumulated plays near our LDV field as illustrated on the slide. Slide 20. In the Gulf of Mexico, we plan to spud our Hoff Part Two 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. I'm 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. Now putting them together extremely powerful for Murphy and our shareholders. We're able to invest in a combined basis when we divest Malaysia at 4.4 times 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 in 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 equivalents, becoming a more gas-weighted entity, and acquire for $10.59 per barrel oil equivalents. All very impressive metrics when considering selling 2P with 40% oil weight and buying 2P for 82% oil weight.
Combining the Gulf of Mexico transactions along with the divesture of Malaysia, we're swapping assets with 58% oil production by volume to assets with 77% production by volume of oil. All while folks in our 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've generated significant value for shareholders with our exit of Malaysia and buying two 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 five years. We've greatly reduced our global footprint and exploration. 2013, we explored worldwide. Today, after much work and focus, we're in six fewer countries than we were in 2013, 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 sands in Canada, Alaska, South Louisiana. We acquired Gulf of Mexico assets at attractive metrics and focused primarily on 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 seen in recent success and 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 five years. Recently, we updated a five-year long-term plan of our company involving the sale of Malaysia, the growth from Eagle Ford.
With our recent LLOG transaction, we have an even stronger long-term plan that generates significant free cash in addition to our strong dividend. Graphically, we can see this coming to fruition 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 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 that drive further possible 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-risked their acreage positions, and as 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.
Thank you, sir. Ladies and gentlemen, if you do have a question at this time, please press star followed by one on your touch-tone phone. You will hear a three-tone prompt acknowledging your request. If you should decide to withdraw your request, you will need to press star followed by two. We do ask if you're using your speakerphone, to please lift the handset before pressing any keys. Your first question will be from Arun Jayaram at JPMorgan. Please go ahead.
Good morning, Roger and team. I wanted to start with the drill bit. Good morning. You mentioned in Mexico, these were oil charged reservoirs. I was wondering if you could comment if the shows on the Cholula well were oil or gas, or maybe a combination of both. Just trying to understand maybe the oil potential at Cholula.
The well had 185 feet of pay in it. Let's just back up a second about this well. It was a low-risk well on a very high on the structure, it had some very interesting seismic flat spots, they're called 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 pay in the well in the most upper part of the pay count, around 29 feet. After that, we're in gas condensate and oil the remainder of the way, the rest of the way in 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. Now we're able to look at our Cometan field, not field, but discovery nearby Cholula.
That's around a 7,500 million barrel equivalent type thing. Around us is around 130 million of tieback Gulf of Mexico amplitude prospects that we can evaluate. We also approved we can evaluate it 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. This is an Upper Miocene discovery, has oil in it, significantly, most of the oil, very high quality, lot of oil sampled in the area, 25-degree oil and average API there. Off to a good start on the well.
If you really look at our exploration program, we drilled a couple of wells and added some nice resources and de-risked a lot of things for around $25 million to net to the company, and that's 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 clarify.
The rest are 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, we're under some rigid requirements around field development. There's a declaration of commerciality phase, and there's 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. This is a fractured sandstone that drapes on top of that granite basement. We have lots of oil that we found. These oils actually found higher quality in this reservoir section than we did in LDV. What we're looking at now is some low risk, inexpensive structures that we can drill, again, for $12 or $13 million our share, or cheaper, now that we understand the well programs.
This was quite an up-dip structure to LDV. We now have de-risked these small accumulations all around, these will be very small platforms, very similar to our Sarawak oil developments in Malaysia. It'll be 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 well bores. This is about a fractured sand that you drill high angle wells through. This structure came in a little higher, we didn't get as much pay as we'd like because we didn't have the angle built at the time. When you drill high angle wells through here, there's been many successful flow tests here, and this is some low risk exploration potential here that's oil been in every well to the spill point of the reservoir.
Also in this well, we had found pay in an upper pay section that ties to a large amplitude pay of a pinch out play similar to what you'd see other places in the world. The LDH area, which is quite a large accumulation on a mean type, exploration type size. 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. 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. We need to stay with the one big field and add this to it. 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, we already have a successful field of lower quality. 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 might have Eric Hambly question for me, Arun.
Excellent question. 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. The liquids from our well came in with an oil density that more resembles an oil type of density than a condensate. 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.
Great. Thanks for that.
Thanks, Arun. Appreciate it.
Thank you. Ladies and gentlemen, as a reminder, if you do have a question, please press star followed by one on your touchtone phone. Your next question will be from Brian Singer at Goldman Sachs. Please go ahead.
Morning, Brian.
Thank you. Morning. Good morning. 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? 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 in that portion of the block?
This particular well targeted two things, Brian. An Upper Miocene very similar to a 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 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 there on down was continuing to get oilier, just not enough reservoir development at the crest of the structure. We de-risked that oil is in the Lower Miocene. 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 to base of oil and did not have a flat spot of seismic, if you will, meaning a contact.
We saw no contact, and we believe down dip, which happens a lot in the Gulf of Mexico, is that 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 two to three well program to do that. And one of the nearby amplitudes that ties to this well from an amplitude, depth, age seismic response. We're also looking further outboard at a larger subsalt project that'd be very similar also to the Gulf of Mexico in the northern areas of the Gulf. 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 de-risked.
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 got that approved and worked through all of that, learned how to operate there. 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 see 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 cheaper. This is a dramatic cost improvement on development. There's a lot of positives from the well.
Wish I'd had more pay, I suppose, in the lower section, but it was quite nice and de-risked some things for us, so I'm real pleased about it.
My follow-up's on the Eagle Ford. A couple issues impacting the first quarter, in terms of artificial lift and then the execution on the 10-well pad. Were these one-offs that are done, and was there any risks for as the year progresses? Was the execution issue on the 10-well pad just timing, or was there any impact on the well performance?
I'll let Eric handle that. In general, this is a higher pressured part of Eagle Ford. Some of the highest flow rate wells in the Eagle Ford are some of the more difficult drilling in the entire Eagle Ford Shale. I'm sure EOG and other people around us, this is a 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 were mechanical things. These are two five-well pads adjacent to each other. 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. 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. Mechanical work is behind it. I feel that it was an impact in the quarter. I'll let Eric comment about the artificial lift matters.
We had a bunch of wells that came online last year that were fairly near this Dillon pad, that the wells came online late in the quarter. Those wells made a transition from flowing to artificial lift. We install in the initial completion tubing with gas lift mandrels. We found that we had a batch of gas lift mandrels that failed. 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, and we had to go in and replace those valves. They were fairly high volume wells, and they all got workover all 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. The challenging area has been drilled, completed, and online. 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 Eagle Ford. 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. You're a shale expert and know it's very hard to run a big shale business with seven, eight wells a quarter. 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. 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.
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 at that time to arrange for other things for long term. We've done that now. We've changed our business more to Western Hemisphere to get this capital allocation to this asset that's been a very successful asset for us. Eric and his team's got a big wall of wells coming, starting even this weekend. Getting 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 two or three years that's caused this, and we're going to get beyond that with some well adds 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 peer group yield as it stands. That being said, you have, of course, cut it a few years back. I'm curious what your thoughts are on the current level of payout, how appropriate it is.
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, it'd be Hess, Apache, and Murphy 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 two all the time. The dividend's quite high and a big part of our investment. I think over the last four years, and especially accumulation of 2016, 2017, and 2018, you'll 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. 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 am very pleased with how these closings of these complex transactions are going. They are going very well. Our legal and business development teams do a great job at getting to the goal line on these projects. When we get all that in place, oftentimes you look back at the history of Murphy, for many, many years, reviewed the dividend in the August or October board meetings. 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 is stagnant to keep it for a long, long period of time. We will be reviewing that.
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. When we do these buybacks, they're very significant. We did some major buybacks back when oil was much higher. We've removed a lot of the shares of the company in the last 10 years. 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 the road of that parade, Pavel. We're real pleased about that. These buybacks are very meaningful when you don't issue equity at the bottom.
We've done a lot for shareholders, we're going to do a lot more, and I think that the buyback with the dividend is pretty dang good from my view.
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?
It's a very similar higher tax regime, much higher than U.S., probably approaching that same 38%-40%, as I recall. The thing about Malaysia, we've been there for almost 20 years. This is our 20th year, actually. We went there in 1999 at another oil crash at the time. For years and years, we paid no taxes at all. Here in Vietnam, it is a better situation because we've built up exploration expenses through the years that have, say, tax cushion, if you will, and then we'll be recovering our costs. Through 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. 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. We are moving on. 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 deemed repatriation, and the set up back to a Canadian subsidiary. This has been part of a five-year plan to have no tax leakage. Our tax team and our finance team's 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. We're in good shape in Vietnam.
Won't pay taxes there for a while. That's just the way it goes internationally. Same will be set up the tax bases in Mexico as well, then we'll go through there. Make a lot of money, pay a lot of taxes. That ended up being the case back in Malaysia.
Understood. Appreciate it, guys.
Thank you.
Thank you. Next question will be from Roger Read at Wells Fargo. Please go ahead.
Hey, good morning.
Good morning.
Yeah. Good morning, Roger. I guess maybe if we could talk a little bit more about the Gulf of Mexico. Obviously, having closed the second transaction, I get that. 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? I don't mean that we don't understand the layout for the next several years of where production basically stayed flat. We would anticipate you bought these assets, you see some other opportunities, and some potential to probably outperform what you laid out for us. I was just curious, is that a six months later? Is that 12 months later, kind of the thought process there?
I'd say six months later. What we do in these processes. We have a team that's very experienced subsurface and have looked at these. We've been working to buy this thing for three years. 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 a significant field that LLOG discovered in the Gulf, along with their partners, very near Samurai. It's a 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're going to have to talk to and meet with on a revised field development plan. All that's the first thing that we'll work on. The sanction of that will be the first thing to come. We, of course, know about that. It's one of the big assets in the field. The assets are some flatter assets, and ours are too. When you're in the Gulf, make a lot of money there. We 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. Historically very good. They have declined. To keep an 85,000-a-day business flat in the high 300s CapEx is really good, way better than shale. 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 fields slightly differently and working with our partners? Sure. Really in the middle of that, 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. This is all going well. We, of course, will be trying to optimize. 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. Now, like anything else, we'll be trying to improve it. Working toward doing that and informing you. It's a six-month thing minimum there, Roger.
Okay, thanks. Appreciate that. The other question within what you're going to be able to put together here, and again, I recognize we haven't closed the second transaction just yet, but as you think about optimizing assets and what, I guess is 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 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 in the shale area?
Well, we have both, we're getting our shale business back in order with the appropriate capital. I'm just speaking about the maintenance CapEx. You have to admit that it's fairly well. It'll 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 it's historic production with infrastructure, with other operators flowing to us. We're actively exploring. We went to lease sale and picked up five blocks here just last month. We barely lost two or three more. There's farming 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.
I would say it 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 in offshore exploration, which is why I'm so glad we never abandoned offshore. Today, not looking to sell or optimize, happy with what we have. 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, see the emails to my CFO and business development leader certainly haven't slowed down my crazy thoughts. We're going to keep working at it, and as usual, we'll let you know when you wake up in the morning.
All right. Crazy like a fox, I'm sure. Thanks, Roger.
I think so.
Thank you. 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.
Okay. Thanks everyone for calling in today. Appreciate the questions and looking forward to another quarter, and 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.