Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation third quarter 2019 earnings conference call. If at any time during this call you require assistance, please press star zero for the operator. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor and Communications. Please go ahead.
Good morning, everyone. Thank you for joining us on our third 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, Offshore. 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. Since divesting our Malaysia portfolio, please note these assets are characterized as discontinued operations. Slide one. Additionally, please keep in mind that some of our 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.
Thank you, Kelly. Good morning, everyone, and thanks for listening in for our call today. The third quarter was a very strong quarter at Murphy's. We began reaping the benefits of our newly transformed portfolio. We produced 192,000 barrel equivalent per day and achieved double-digit oil weighted production growth in our key operating assets while delivering free cash flow. With an average WTI price of $56.45, we achieved a solid $24 adjusted EBITDA per BOE corporate-wide, driven by 60% oil production with premium pricing. Proceeds from our Malaysia asset sale were used to repay $1.9 billion of debt during the quarter, primarily incurred during our two Gulf of Mexico transactions. In addition, we utilized excess cash from operations to complete our $500 million share repurchase program earlier this month, well ahead of plan.
Murphy also laid out the groundwork for additional exploration opportunities in Brazil through a successful bid on three blocks in the Sergipe-Alagoas Basin and farmed-in the three blocks in the Potiguar Basin. This acreage provides optionality for future development opportunities and supports Murphy's long-term exploration program. I'll now turn the call over to our Chief Financial Officer, David Looney, for some additional financial comments.
Thank you, Roger, and good morning, everyone. Turning to slide three. By any measure, the third quarter was a terrific one for the company. Not only did we achieve over $1 billion in net income, including the gain on sale of our Malaysian assets, but we also earned over $57 million in adjusted earnings, a recent high water mark for us. The adjusted earnings, as always, back out such things as mark-to-market gains on commodity hedges and contingent consideration, which between the two totaled over $61 million after tax. I will also note that the third quarter marked the first time we have broken out transportation, gathering, and processing expenses as a separate line item, and all comparative periods have been conformed to the current presentation. Slide four. The third quarter was also excellent in terms of free cash flow generation.
Whether it be a simple calculation of cash from continuing operations, less property additions and dry hole costs, or an adjusted EBITDA metric, the company continued its longstanding mantra of spending within cash flow. For the third quarter, cash flow from operations totaled approximately $498 million, while property additions and dry hole costs came in at $364 million, resulting in a positive free cash flow of $134 million for the quarter. Similarly, for the nine months year to date, cash flow from operations totaled $1.15 billion, with property additions at slightly over $1 billion, proof again of Murphy's commitment to generating positive free cash flow. Other highlights during and after the quarter close included increasing our hedge position with both WTI oil hedges and AECO physical sales contracts, as well as completion of our share repurchase program and repayment of approximately $1.9 billion in debt.
All of the items outlined above contributed to our strong continued financial condition, as exemplified by a net debt to annualized adjusted EBITDAX ratio of 1.3 times as of the end of the third quarter. Turning to slide five, you can see that once again, our strategy of moving more of our production to U.S. Gulf Coast markets has paid off in terms of premium prices relative to WTI. Once again, we sold approximately 94% of our oil production at a premium to WTI. Our core Eagle Ford Shale and North American offshore assets garnered premia of more than $2 and $4 to WTI respectively, while generating field level adjusted EBITDA per BOE of $35 and $37 per barrel. Clearly, our strategic transformation begun almost one year ago is reaping strong rewards for the company and all of our stakeholders. With that, I'll turn it back over to Roger.
Thank you, David. In line with guidance, we produced 192,000 barrels equivalent in the quarter, which more than 112,000 barrels were oil volumes. This is a level of oil production we've not seen since 2015. Our operated assets are performing well, with production volumes offsetting some downtime in our non-operated offshore assets. We're maintaining our full-year 2019 guidance range of 174,000 to 178,000 barrels equivalents per day, as well as maintaining our capital plans as previously disclosed at $1.35 billion-$1.45 billion. On slide seven, we have a long history of benefiting shareholders here at Murphy. We have upheld this philosophy even through the downturn, as noted on many occasions, as we did not issue equity in 2016, as did many peers. We're pleased to have completed the share repurchase program, leading to more than $3.9 billion of funds returned to shareholders since 2012 and over $6.5 billion since 1961.
Our financial discipline has led to consistent dividend, along with utilizing the excess cash flow rather than equity proceeds to finance operations and acquisitions that simplified and transformed our company. Now move to slide nine, on the Eagle Ford Shale. In the third quarter, we brought on 25 operated wells, 15 of which were in Catarina, 10 were in Tilden. We saw a 15% increase in total production volumes over second quarter 2019, and more importantly, a 22% increase in oil volumes. This is a result of our improved well-targeting and latest completion design, which achieved consistently higher oil cuts and IP rates than previously generated. When using our new frac-enhancing model and well placement plans over the last four years, our median well EUR have increased by an impressive 36% to 584,000 equivalents. We have not aggressively down spaced, and more importantly, we do not overbook reserves.
Even better, we achieved operating expenses less than $7 per BOE for the quarter, which is nearly 20% less than the second quarter of 2019. This is a true testament of our competitive advantage in the play, which leads to real value creation. The Eagle Ford team has done a tremendous job in execution this year with our enhanced capital allocation plan. We are looking forward to continued success in 2020. On slide 10. Looks like some highlights into further detail in the third quarter. Our well performance in Tilden and Catarina continue to be strong with out-performance at our Tyler Ranch and Stumberg locations, respectively. In Tilden, our 10 Lower Eagle Ford wells are on average performing above the pre-drill EUR type curve of 500,000 barrel equivalent. The 7,100-foot lateral wells with 500-foot spacing are yielding IP 30s that average 1,300 barrels equivalent per day.
Over in Catarina, nine Lower Eagle Ford wells were drilled with 7,800-foot laterals and 350-foot spacing. These wells are yielding average IPs of 1,400 barrels equivalent today. The initial results look promising with the new down spacing for us here from 400 feet to 350 feet. Moving into Canada on slide 11. The Kaybob Duvernay, our assets continue to perform to plan as we close out 2019 program. Importantly, our recent well performance in mid-80s liquids cut mirror our Tilden Lower Eagle Ford Shale wells. The strong initial rates from the new wells are a result of our applied learnings from the Eagle Ford, along with implementing methodical drilling strategy and continuing our acreage de-risking.
In the quarter, we drilled a pacesetter well here in under 13 days for less than $2.5 million with a lateral length of nearly 10,000 feet, which makes me greatly confident we'll be able to drill and complete wells in this play in the pad mode for less than our targeted $6.5 million goal. Over the long term, we expect that our best wells in Kaybob will continue to complete with Eagle Ford wells as we high-grade locations and move into multi-well pad development. Looking in the Gulf of Mexico on slide 13. Murphy's Gulf of Mexico assets performed well this quarter, producing 78,000 barrels equivalent per day, with operated production exceeding guidance. During the quarter, we completed the tieback of the new Dalmatian well, which came online at a gross rate of 5,400 barrels equivalent per day.
The Nearly Headless Nick well completion and Medusa workovers are finished now, with first oil volumes coming on shortly. The St. Malo waterflood is an exciting value-added long-term project sanctioned in the third quarter by Murphy and our partners, and is forecast to increase EUR by approximately 30 million barrels equivalent net to Murphy. Construction is on schedule for our King's Quay floating production system, where we continue to review sell down opportunities. Further on slide 14. As shown on this slide, we have numerous short- and long-term projects to implement in our offshore portfolio, primarily all with pre-drilled wells. Looking back, I am so thankful that we maintained our offshore operations ability. With our long history of deep water execution capability, we've seamlessly integrated these new assets into our existing portfolio and maintained all project timelines, which is no easy task.
These tiebacks, workovers, new wells in various stages of planning and preparation, and I'm confident we will safely execute them to plan, leading to significant value creation beyond our producing assets. This results in the Gulf of Mexico production being maintained between 80,000 to 85,000 over the next four to five years, with optionality for future brownfield expansion projects and near well tiebacks. Exploration, slide 16. Murphy remains focused on exploration Brazil, alongside excellent partners in the third quarter successfully bid with our partner group, including ExxonMobil as operator, on three additional adjacent blocks in the Sergipe-Alagoas Basin. Our total 20% working interest position across nine blocks covers approximately 1.7 million acres with more than 1.2 billion barrel equivalent reserves discovered nearby. We continue to progress our seismic program in the basin and hope to have full review completed within the next 12 months. Slide 17, the Potiguar Basin.
Our strategy of focused yet meaningful exploration at low-cost entry points continues as we expanded our position in Brazil this quarter by forming into three blocks in the Potiguar to gain a 30% working interest. The acreage is located near existing major oil discoveries with large successful operators and leverages our existing partnership with Wintershall Dea. Additionally, we'll meet our criteria on a success basis of near $12 per barrel finding and development costs. Vietnam, page slide 18. Our position in the proven and prolific Cuu Long Basin continues to provide long-term exploration upside along our two previous discoveries. We're taking the necessary steps for future development and receiving the required regulatory approvals to move this project forward. I'm very proud of our Murphy team on slide 20, and especially their execution over the course of the last 12 months.
We completed three large asset transaction, redeployed sale proceeds, and increased our high margin oil-weighted production volumes, resulting in the ability to provide significant free cash flow going forward. We implemented and completed our share repurchase program and are on track to deliver over 200,000 barrels equivalent per day in the fourth quarter. Most importantly, we're generating approximately 67% liquids-weighted production, with 94% of our oil volumes sold at a premium to WTI. All this has been achieved while maintaining our cash on the balance sheet. Slide 21. In closing, Murphy delivers long-term value following our transformation, provided by a stable growth platform with our Eagle Ford Shale and Gulf of Mexico assets, as we execute short cycle, high rate of return projects. These oil-weighted assets generate premium pricing and positive cash flow and allowance to maintain our dividend and strong balance sheet.
As always, we remain focused on benefiting shareholders and balancing financial discipline in a lower price environment. With that, I'd like to turn the call back over to our operator for questions this morning. Thank you.
Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on your touch tone phone. You will hear a three-tone prompt acknowledging your request, and questions are polled in the order received. Should you wish to decline from the polling process, please press star followed by two. Your first question comes from Leo Mariani from KeyBanc. Please go ahead.
Hey, guys. Just wanted to see if you had any updated high-level thoughts on the approach to 2020. Obviously, a lot of volatility in the commodity markets these days. Just wanted to conceptually get your thoughts on that. Would the plan be to have free cash flow in 2020 at all costs and then sort of adjust short cycle activity to get there? I know you've got some larger spending coming in the Gulf of Mexico next year. Maybe just frame that up a little, if you could.
Thank you, Leo, for the question. Last time we had a conference call, we talked about our production being 10%-15% higher than this year. Reaffirming that, I think, will be toward the highest end of that marker, toward the high end of the 10%-15% production increase off of the midpoint of our current guidance. As to capital, we also said at that time 10%-15% higher capital. Today, we would say that that increase would be only 5% above the current midpoint of our $1.4 billion that's in our guidelines today. This does not include capital for NCI. As you noticed in the call today, there was some hedging done. We are pretty well positioned at 45,000 barrels hedged at over $56. We are using a $55 oil price. We put all that in.
Even if oil goes to $50, we're at $53 something average for our oil production, which is the driver here. At our annualized EBITDA off of today at 1.3 net debt to EBITDA, I feel pretty well positioned there today, Leo. I think with our diffs situation, WTI, and a lot of flexibility we have in our onshore assets, we're looking at really good budgets here and feel very comfortable about free cash flow and covering our dividend. Have to keep in mind, when you cover the dividend at Murphy, it's a big number. It's not some small little bitty dividend that we throw around. It's a significant amount of money here, and free cash flow here above dividend is quite significant. I think it's going to be a very nice 2024.
Well, that sounds great for sure. Just kind of transitioning to a slightly different line of thinking. Obviously, you guys have been pretty acquisitive in the Gulf of Mexico over the last couple of years, which obviously has brought in significant high-margin barrels. Balance sheet's in good shape. Just wanted to get your thoughts on what the landscape looks like for potential other Gulf deals going forward.
Oh, we constantly have many deals that we look at. I would say today more of our deals are weighted toward international in this hemisphere at this time. We constantly keep 3 to 5 BD opportunities running. There's a lot of possibility for farm in at ground floor levels in the Gulf with super majors and others today. I would say the landscape for us from a size deal perspective would be more toward that today. We're looking at some longer-term deals in BD in the hemispheres. We know we are well positioned in Brazil. We also see Brazil attracting some of the largest money anywhere in the world, billions and billions of dollars exposed in Brazil by every super major there is today. We're very well positioned there, and we are positioned to do BD if we want to.
As we've shown clearly, Leo, as you know, we have no fear in changing the portfolio here. We look at several of those. I'd say today the hottest thing would be farm in on exploration today in the Gulf.
Well, that's helpful. Maybe just on the stock buyback. Obviously, you guys were aggressive, got it all done very quickly. Nice to see. To the extent there is more free cash flow, if prices do better next year, could you guys think about resurrecting that buyback, or how do you think about uses of free cash flow?
Well, we will probably be looking at, we are a company, Leo Mariani, as you know, we model our company with a buy rating. As you know, we have significant free cash flow coming to us over the next four to five years. We would probably be looking at a debt and buyback situation, splitting that, if you will. I would not be surprised to see us continue to have authorizations available in the future, in which we would get consistently into buying our stock, because our stock is severely undervalued. We have done very well at rewarding shareholders. As we had this large gain in Malaysia, we shared that with our shareholders immensely here. It is no small feat to return $600 million plus to shareholders in a year.
I would say we obviously would like to de-lever some along the way, but share repurchase is always going to be likely here.
Thank you very much.
Thank you.
Thank you. Your next question is from Arun Jayaram from JPMorgan. Please go ahead.
Morning, Arun.
Good morning, Roger. Good morning, sir. I was wondering if you could provide us some more detail on some of your longer-term projects in the Gulf of Mexico, including the St. Malo waterflood and the Khaleesi, Mormont, and Samurai projects.
Okay, sure. Thank you, Arun. On St. Malo, obviously, we're dealing with a super major here. Disclosure from super major is a little bit limited, let's say. This is not as big a project to them as it is to us. It is a significant project, maybe not for CVX. They're 51%, Equinor's 21%, MP GOM, our JV with Petrobras, owns 25%, making us own 20%. This is a very large oil field with over 2 billion barrels in place. It's been online since 2014. Only nine wells are flowing there. It's making over 90,000 barrels a day today after all that time. This project's going to increase the recovery from probably 20% to near 28%. We believe we'll get out a little over 30 million barrels net to Murphy on that.
It's a project where you do some producers early, have some small increases in production, then convert those producers into injectors. We're looking at 2,000-3,000 increase production for us from 2021-2024, then a solid 5,000-6,000 barrels a day net to Murphy from 2025-2031. What I like about the project, it's $50 million additional free cash flow to Murphy from 2023-2037, Arun. I'll be almost 70 years old then. Pretty good project for us. On Khaleesi/Mormont, that's important to understand on this project, this was drilled by LLOG, a company we purchased early this year. It's a large project. They've over near 170 million barrels reserves here. This is a project that has significant pay in several zones across several wells. There were six well bore penetrations at Khaleesi/Mormont.
Again, it's important to note about these assets and the ones that we have and are conducting on slide 14 today. Most of the wells are drilled. We're talking about pay on logs in wells that we're going to go and tie back. We're going to drill a couple extra wells there, if you will, into penetrations previously done by the other operator. These wells are four wells drilled and abandoned, temporarily abandoned, will be tied back to flow into the floating production system that we're going to build. This is a significant project, adding a lot of NAV here for us, over $300 million, a high rate of return in the 30s, and a very good project. That would be the update on those two, Arun. Does that answer your question today?
I just had one follow-up, would be just on the Gulf of Mexico CapEx. I think in September, you guys had outlined a five-year outlook, which was I think $325 million per year. There's obviously, it will move up and down in specific years given the major projects. The questions around that is, did that include the CapEx for St. Malo, and does that assume that you do a sale leaseback on the King's Quay facility? I think that your commentary said just $1.5 billion in CapEx in total in 2020.
Well, we didn't say that. We said our CapEx is around 5% of our current midpoint of $1.4 on top of that. It'd be less than $1.5 there, Arun. The assumption today of the 325 average does include St. Malo and does include the sell-down of King's Quay at this time, and our capital in the Gulf will be higher than this year. The average is maintained, and our significant free cash flow position through 2025 that we will build from our assets is being maintained.
Thanks, Roger.
Thank you.
Your next question comes from Gail Nicholson from Stephens. Please go ahead.
Good morning.
Good morning, Gail.
You guys posted a very nice improvement in LOE this quarter. Can you just talk about the drivers there and how we should also be conceptualizing LOE on a go-forward basis?
Well, it comes from real hard work, Gail, number one. That's how I've got there. $768 for the third quarter is very strong for us. I'll just walk through some few highlights. Eagle Ford's very strong, of course, done well in our Canadian assets as well, especially in the Gulf. Going forward, we're going to have a higher OPEX in the fourth quarter. We're doing a $40 something million gross workover at Cascade, Chinook field. This is a well that we inherited from our purchase of our JV formation, rather, with Petrobras, we have a drill ship there conducting that. It'll move up our OPEX on that a good bit. Our real star of the show is Eagle Ford OPEX, I'll let Eric here, who runs our onshore business, Executive Vice President, help you on that, Gail.
Okay. Thanks, Gail. I'm really happy with Eagle Ford operating cost, down $6.75 per equivalent barrel. Big things we've been working on there, we've been optimizing our field labor costs, reducing the number of operators in the field, and optimizing how we're using them. Obviously, production's up 15% quarter-on-quarter, which helps. The dollars are actually quite a bit lower due to field labor cost. We're doing more saltwater disposal on pipe versus trucking. We have lower maintenance and repair costs. We continue to do some infrastructure things like electrification, chemical program optimization, that kind of stuff.
Also, Gail, I'm going to have Mike McFadyen, who runs our offshore business, comment on our offshore as well, outside the workover that I mentioned. Go ahead, Mike.
Hi, Gail. We plan to maintain low operating costs with the addition of the LLOG assets into the Gulf of Mexico portfolio. Prior to that, MP GOM has provided a larger footprint for us to integrate shore-based logistics and other areas that impact operating costs. We plan to maintain a low operating cost with some lumpiness with expense workovers along the way.
Great. Thank you for that incremental color. I want to ask also about Vietnam. I feel like the market doesn't really appreciate the amount of resource there. With the progress that was made on the regulatory aspect, both with Block 105 and Block 17, can you just talk about timing, how we should think of Vietnam, and how that is developed over the next five-year period?
Well, Vietnam is a big swing for us internationally, and has a lot of optionality for a lot of things that could happen, where we can move in quickly. It's not the fastest regulatory place in the world. Sometimes we let that go because we have other capital allocations from our initial movement into Petrobras, into the Gulf of that JV, and placed a lot of capital allocation to the Eagle Ford, where now we're seeing very big increase in production at the capital that we described, low LOE and great execution here, headquartered in Houston. We, of course, know how to operate here. We are invited and very favored by Vietnam. You have to keep in mind that now Exxon has said they're selling out of Vietnam, one of their larger fields.
We've become the only American company there. That politics is helping us favorably there, as they want us to be there, and that will help approvals and things go forward. We have a very nice 100 million barrel discovery at the LDV field that's needed their approval on the development plan to allow for FEED to take place and the partners to pay accordingly there. We had a discovery at LDT-1X earlier this year. Could easily be tied back to that. We're picturing this to be a Malaysia, Sarawak sort of business, where we were very successful and the top operator there for two decades. As we look at small platforms flowing into FSOs in that region and a big prospect to drill nearby. We're also working to get another block there that's moving along very well. This block is adjacent.
It just gives us a lot of optionality to move into Vietnam easily and have played into the hands of our capital allocation at this time, and gives us a lot of upside in the future.
Great. Thank you so much.
Thank you, Gail.
Thank you. Your next question is from Ryan Todd from Simmons Energy. Please go ahead.
Hello, Ryan. How you doing?
Great, thanks. Morning, Roger. Maybe a first one. You highlight new well performance in the Duvernay, and how it's closed the competitive gap a little bit there. Can you talk about how it competes for capital right now in the portfolio? How we should think about activity there as we look towards 2020?
Well, we've stated earlier this year that what we have there are hundreds of wells that are going to be very good when the commodity improves on the macro in Canada. That can't go for forever. Over four to five years from now, we have an ability to move that play to 60,000 barrels a day. It'll probably be outside of the planning period of a 2024, 2025, but clearly can easily do that. We have the wells across this play that are starting to perform very well as we worked on the fracking, worked on the placement and all the things we do. As you know, we run our onshore business with one leader, Eric Hambly's over the business, and we're able to have one drilling team, one production team, one reservoir engineering team.
We're able to get all this data transferred back and forth, doing very well. As we see, it's really some Eagle Ford wells with a lower commodity price, a lower differential. When that differential moves or changes, we can move capital there. Next year, our capital program, as I said earlier, is looking at a 5% maximum increase. The capital for next year in our current plan is the highest capital we will have over the next three to four years, for sure. With that out there as well. When that capital allocation's really sort of what we're doing now, if you will, near the range we have today. When we do that, we're going to have more capital offshore for our big projects there that we talked about earlier for some other questions.
We're going to have significantly less capital in Canada. Canada's coming down, offshore's going up, Eagle Ford's going up slightly. That's the way to think about capital allocation. Next year is going to be, we still continue to be so pleased with the data that we got to keep all the acreage now. We got to go into an all drilling mode. This is not like Texas where we have continuous drilling clauses. It's quite favorable, but you've got to put wells in all these sections. You've got to have long reach, 10,000-foot wells, which we're now successfully executing, and you got to place those across those acreage to keep this acreage because it's too valuable to lose because it was an all-time low entry cost, typical Murphy kind of deal. That's where that's headed, and we're in really good shape there.
Just need the macro to get better, and that's what's in our plan, and we should be in good shape, Roger, on that.
Perfect. Thanks. Then maybe one follow or separate question. I know it's received a lot of coverage, how do you think about the market perception about the potential risk to your portfolio on federal leasehold in the Gulf of Mexico? How would you address the perception, and how would you potentially mitigate the risk if it became an issue?
Well, I think throwing Murphy into that is quite silly, actually, but let me talk about it here. First, let's look at what the tweet says from one of these individuals. It's a moratorium on all new fossil fuel leases for offshore drilling and public lands and ban fracking everywhere. First thing happened, oil's going to go almost to $100, and gas will probably go to eight or nine bucks. You just talked about Canada. That's going to be a great situation for us there. Can you imagine? That'd be incredible. We do not have, as you know, Ron, and everyone that covers us know, we do not have federal lands onshore. That was by design years ago. We are, of course, a big offshore player. We're the fifth largest producer in the Gulf. We do not see this as a stopping of future drilling.
Even if it does, let's be honest, what NAV would Murphy have from future leasing in the Gulf of Mexico? I would say below zero, what that would be. That's not really anything to worry about. We have a very large PDP position both in Eagle Ford and Gulf in these situations. Let's just take the offshore first. If you look at the Gulf, one of the things in the slide deck today, Ron, is all of our capital, primarily all of our capital on all the projects that we overtook in the purchase of these assets is spent before early 2021. All of the drilling and all the permits for the drilling will be done before early 2021. Primarily, all our work is on previously drilled wells, so all we are doing is completing wells.
As to a moratorium, on that we see little impacts on the projects we have and haven't disclosed any projects or any AV subscribed to anything outside of what we've put in here today. The Gulf of Mexico produces two and a half million barrels a day as an industry. I doubt very seriously that would be closed off. We feel positioned there. On the Eagle Ford, we have a large PDP production there. We'll be going into 2021 in the mid-60s, well-positioned. Of course, there'll be major lawsuits and litigation around the landholders and leaseholders in that. Very difficult to stop fracking on non-federal lands, I would say.
The real advantage that we have, if you look today, we're entering into two large basins in Brazil, getting bigger in one and into a brand new, and this is the hottest locations on the planet, Brazil today with capital allocation. We have success in Mexico. The success there is getting more described as thin bed pay, but a significant amount of pay with lots of work to do nearby and 34 leads. We discovered resources in Vietnam. There's just a call by Gail with Stephens. We can throw two jackup rigs into Vietnam like nothing to it, Ron. Very few people can do that. No other company has three to five live BD oil opportunities international today. We review it every Wednesday at 2:00. We're ready to go, ready to move. We have upcoming exploration.
All of our projects are going to be executed before the inauguration. Really, we're going to be very well-positioned because we never have eggs in one basket here. Also Canada and big gas in Canada. Even Trudeau allows fracking, Ron. We're in really good shape on that matter. I consider it a non-risk at all, to be honest with you.
Awesome. I appreciate the clarity there, Roger. Thanks.
Thank you. Ladies and gentlemen, as a reminder, should you have any questions, please press star followed by one. The next question is from Brian Singer from Goldman Sachs. Please go ahead.
Good morning, Brian.
Thank you. Good morning. Can you talk a little bit more on exploration? You've added some blocks in Brazil, Gulf of Mexico. Maybe there's other opportunities to do that, particularly in Brazil. How should we think about the capital allocation and your capital allocation towards exploration in 2020, 2021?
This year, I think our total CapEx of all exploration, including drilling and everything's $140. If you look in our disclosure here today, you'd probably get into the, I believe you'd see $75 million on exploration plus an additional $20. That wouldn't include the drilling for the capitalized wells that were successful. I would say next year, probably similar to that, $140, $150. That's what we have in our budget draft that we have today. I would say 2021 will be similar. We're hopeful to drill in Brazil in a year, and we're hopeful to drill in Mexico next year, a couple wells around this time of the year. We'll probably be drilling a well in the Gulf early next year. There's a lot of farming opportunities in the Gulf today by super majors, which we're greatly attuned.
What really feels good about our business is, we were small in the Gulf. We looked for opportunity to get much bigger. We see it as a big competitive advantage coming out of Malaysia because all of our executive management team are experts at working offshore, et cetera. Now the calls that we're getting, and the opportunities to partner, and the opportunities to farm in as we built up to the fifth largest operator in the Gulf, we're back at our legacy. A lot of people contacting us. We can operate. We're a great operator. Things are really going well for us on exploration opportunities, and what we bring to the table with just keeping that offshore ability is just really paying for itself now, Brian.
Great. Thank you. My follow-up's on the Eagle Ford. This has been a key area of flex, depending on commodity prices. Can you just talk about how you're thinking about activity levels, and how variable that could be in 2020, depending on where we end up from an oil and liquids perspective?
At this particular time, again, I disclosed some ranges on our capital this morning, that's a $55 budget, but we've supported that with hedging that I went over earlier on the call. I'm sure you're aware of that. That puts us pretty well-positioned. I'd say our program next year is going to be bigger and more CapEx than we have this year. We are working on probably about the same kind of delivered well count for us, but there's an opportunity with bpx nearby. They're going to be drilling a lot of wells, which are going to be non-op for us. Not a large working interest, but they're obviously significantly adding there. We're going to be meeting with them next week to talk about those plans. I would say, but it's greatly flexible.
We have no rigs today, and we can easily go down to that level if needed. We've done it before, and we have flexibility around this. We are looking to cover cash flow with dividend at $55, hedged at $56.42 on 45K per day. Like I said earlier, covering that dividend is no small feat today in this free cash flow world that we're in.
Great. Thank you.
Thank you, Brian.
Thank you. The next question is from Pavel Molchanov from Raymond James. Please go ahead.
Hey, guys. Good morning. Thank you for taking the questions. Obviously, a lot of pressure these days on U.S. onshore rig count and oilfield services generally. Can you guys give some perspective on what you are seeing in the Eagle Ford today?
I'll have Eric handle that, Muhammed, for you.
Sure. If we look at total drilling and completions costs, we expect to see a little bit of improvement there. Drilling costs are basically flat. Completion costs are probably improved in the low single-digit %, a little bit lower.
Okay. What about service costs offshore, both in the Gulf of Mexico and Canada?
All-time great. That's all I can tell you.
Okay. Thank you. That's all for me.
Best it'll ever be.
Thank you. There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks.
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