Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2018 Earnings Conference Call and Webcast. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Thank you, Jessica. Good morning, everyone, thank you for joining us on our fourth quarter earnings call today. With me are Roger Jenkins, President and Chief Executive Officer, and David Looney, Executive Vice President and Chief Financial Officer. 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 non-controlling interests in the Gulf of Mexico. 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. 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 2017 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, thank you for listening to our call today. 2018 was an excellent year, both financially and operationally for Murphy Oil. Our strong results illustrate our commitment to diversified portfolio as oil-weighted production from our onshore and offshore assets continue to generate high margin realizations and cash flow. We produced 176,000 barrels equivalent with 61% liquids in the fourth quarter, full-year production was 171,000 barrels equivalent at 59% liquids. We're seeing the immediate impact of the MP GOM transaction and enhanced profitability, oil-weighted production, and reserves. In the fourth quarter, we generated $103 million or $0.59 per share of earnings, on an annual basis, we recorded net income of $411 million or $2.36 per share. This is our highest annual net income in over four years.
Our disciplined capital allocation enabled us to return 14% of our annual operating cash flow to shareholders. Our diversified portfolio generated EBITDA for BOE of over $25 per barrel. EBITDA per average capital employed was notable at 21%. Through the energy cycles, we've maintained our ability to execute deepwater offshore projects with success found in the record-breaking Dalmatian project and a unique gasless solution in Malaysia. In our North American onshore business, we achieved an annual lease operating expense of just over $6.50 a barrel equivalent. We simultaneously delivered on our growth plans while spending within cash flow and growing our Cave Hill Duvernay shale by almost two and a half times year-over-year. Slide four. We continue to successfully execute on our strategy. We returned to offshore exploration with success in Samurai project.
Our low-cost innovative offshore projects in Malaysia and in the Gulf are now installed and beginning to demonstrate production uplifts. We executed a transformational transaction in the Gulf of Mexico, increased our footprint in the region, affording us access to world-class assets such as the St. Malo field. In Vietnam, we work closely with their national oil company, PetroVietnam, to negotiate operatorship while increasing our working interest in the Cuu Long Block 15-01 area, where we just received a declaration of commerciality for the LDV field, another step toward project sanction. In our North American onshore oil-weighted assets, over 50% of our future locations are break even at less than $40 per barrel. In Eagle Ford Shale, we decreased the cost per completed lateral foot over 10% while maintaining drilling costs as measured by cost per foot in the face of continued oilfield service cost inflation.
Our offshore team set a record in the Gulf of Mexico with successful installation of the longest multi-phase subsea pump distance in the world. Slide five. As we review our 2018 production, we need to keep in mind that starting in the fourth quarter of 2018, we'll be reporting 100% interest, including the 20% non-controlling interest in our new subsidiary, MP GOM. For discussion purposes, we will exclude the non-controlling interest and only highlight the amounts attributable to Murphy, unless otherwise noted. In the fourth quarter, we produced 176,000 equivalent, and fourth quarter production was 47% offshore and 53% onshore. On our reserve slide, page six, I'm especially proud of our team's work to replace and add valuable proved reserves in 2018. Our proved reserves increased to 816 million barrels equivalent, a 17% increase from 2017, and most importantly, our proved oil reserves increased by 24%.
Simultaneously, we lowered our organic finding and development costs to $10.92 per BOE and maintained a reserve life index of over 10 years. We have lowered our three-year average F&D cost by 50% since 2014. I will now turn the call over to our Chief Financial Officer, David Looney, for his comments. Thank you.
Thank you, Roger. Consolidated results from the fourth quarter of 2018 included net income of $103 million, which is $0.59 per diluted share, compared to a loss of $287 million or $1.66 per diluted share in the fourth quarter of last year.
Our adjusted income was a profit of $54 million, or $0.31 per diluted share in the fourth quarter, versus a profit of $13 million in the comparable quarter last year. The adjusted income this year varies from our net income due to the following after-tax items. Number 1, the impact of tax adjustments in the quarter of $30 million. Number 2, an unrealized mark-to-market gain on crude oil derivative contracts of $28 million. Lastly, an impairment of select Midland properties of $16 million. Another highlight that I would really like to note for 2018 is that our full year accrued CapEx of $1.19 billion came in $40 million below our guidance. Again, full year accrued CapEx $1.19 billion, which was $40 million below the guidance.
At December 31st of 2018, our total debt amounted to approximately $3.2 billion, including capital leases, or 40% of total capital, while net debt amounted to 37% of total capital. During the quarter, we closed on a new $1.6 billion senior unsecured revolving credit facility with more favorable covenants than the previous credit facility. When we closed the Gulf of Mexico transaction, we paid $470 million cash drew down $325 million on the new facility for a total consideration of $795 million. Cash and cash equivalents were approximately $390 million at year-end. In the quarter, we received rating agency upgrades. Moody's increased their rating to Ba2, and Fitch Ratings increased to BB+. We view these upgrades as a clear indication of our financial strength and another step on our path back to investment grade.
In keeping with our longstanding goal of living within cash flow, slide 8 is a snapshot of our full year 2018 cash flow statement, presented in such a way as to segment out the impact of the MP GOM transaction from our normal business operations. Starting with the GAAP measure of cash provided by operations and reviewing our various cash uses, it might appear we did not generate enough cash to cover our dividend and CapEx obligations, which has always been a Murphy hallmark. However, it should be pointed out that the fourth quarter, and in fact, the month of December, was quite unique in that we had a one-month increase in working capital of approximately $170 million, which had the effect of lowering our cash flow by a similar amount.
Absent this aberration, which occurred primarily due to a number of late December crude liftings in our offshore businesses and the inclusion of MP GOM revenues for the first time, we would have generated excess cash flow after dividends of approximately $87 million for the year. As the chart indicates, however, the negative working capital change actually resulted in a shortfall of about $83 million. When you combine this $83 million outflow with the approximately $495 million of cash used to close the MP GOM transaction, you can easily see the $578 million cash reduction that's reflected on our cash flow statement. Truly a unique quarter with the transaction and the working capital changes. We remain on track as always to continue to deliver free cash flow to our investors. With that, I'll turn it back to Roger to review the company's operations.
On slide 10, the addition of immediately free cash flow providing Gulf of Mexico assets complements our current portfolio and leverages our deepwater operating expertise. In this asset, we grew our reserves by 70 million barrels, of which oil in the Gulf increased by approximately 150%. Also, we gained operator of Chinook and Cascade that will add value as our goal is to streamline and improve operations. In the Gulf of Mexico, on slide 11, our assets continued to perform wells. We were able to achieve a quarterly low lease operating expense of below $10 per barrel. Dalmatian is currently delivering production of 10,000 barrel equivalent gross, an increase of 250% from the prior quarter. Unique execution example that sets Murphy apart with another industry first, has implemented a new technology we believe can be used long-term in the Gulf, especially in our new MP GOM assets.
The Samurai-2 appraisal sidetrack was completed, and the project has transitioned to pre-FEED, with development plans to disclose later this year. Our Malaysia assets continue to generate free cash flow. Our Kikeh gas lift project is now complete, with the next focus on a field wide subsea gas lift project. Our Block H floating LNG project also remains on track for the first production in mid 2020, with many milestones achieved. The FLNG vessel construction remains on schedule, with all major process modules installed. The vessel's expected to sail away in the first quarter of 2020 for final hookup and commissioning. In Vietnam, our LDV field received an approval for declaration of commerciality, and a development team is in place to start the project execution. On slide 13. In the fourth quarter, we drilled the King Cake exploration well, which encountered non-commercial quantities of hydrocarbons and was plugged and abandoned.
The well, which Murphy operated at 35% working interest, was drilled 35% below the expected AFE for a net cost to Murphy of $16 million. Looking forward to our 2019 exploration plan, where we expect to spud three key wells for net cost of near $54 million. This will enable us to touch over 109 million of barrels equivalent net mean resource potential. An update on the first quarter exploration wells. First, in Offshore Mexico, on our Cholula prospect, we've received all of the approvals we need and should spud the well in the next few weeks. Secondly, in Vietnam, we expect to spud the LDT prospect and our 15-105 well in the first quarter as well. In the Gulf of Mexico, we plan to spud the Hoffe Park 2 well in Mississippi Canyon 165 in the third quarter. Moving to slide 15, discussing the Eagle Ford Shale.
According to our plan during the fourth quarter, we brought eight wells online in the Eagle Ford, all in Catarina. The IP30 average rate for eight wells was 860 barrels equivalent per day gross. Eagle Ford Shale team has done a good job continuing to lower completion costs while holding drilling costs flat in spite of service cost inflation. Our completion costs per lateral foot decreased 13% year-over-year, while drilling per foot was flat while we increased our laterals drilled. We continue to lower completion costs, as our 2018 costs are now approaching those seen in 2015 in the backdrop again of overall cost inflation, but driven by performance improvements and per foot increases during this timeframe. This all from continued outstanding execution, and especially some key procurement work by our Eagle Ford Shale team.
This asset generated over $185 million of free cash flow over the course of 2018, a metric we're quite proud of. Slide 16. Tupper continues to deliver reliable well performance with low operating costs of just over $0.60 per Mcf for all of 2018. Even as we continue to experience challenging prices, we were able to generate free cash flow in this asset. Our marketing team continues to mitigate our AECO spot price exposure through hedges and off-AECO sales. For the year, we realized CAD 2.39 per Mcf. In the first quarter of 2019, we have just over 40% of Tupper Montney natural gas priced at AECO. Slide 17. In the Kaybob Duvernay, we finished off 2018 completing the five planned wells in the fourth quarter.
At this time, we feel that our appraisal of the play is complete with the exception of the Two Creeks area, which is ongoing with very encouraging early results. Slide 18. We continue to have strong well performance in Duvernay, leading to production steadily increasing over the course of the year with fourth quarter production exceeding 11,000 barrels equivalent per day with 59% liquids. Our lease operating expenses continue to trend down in this play. We've achieved an all-time low of $5.74 per barrel in the fourth quarter. This is outstanding work of our team in Calgary. On Slide 18, we're showing some of our outstanding results from our full well pads we have executed early in the year and in the fourth quarter, clearly illustrating value creation as we move to full development mode with outstanding IP30 rates and cumulative production volumes. Slide 19 and Slide 20.
Before moving into our 2019 plan, I'd like to step back as to where we've come over the last five years. We've greatly reduced our global footprint and exploration. Prior to 2013, we explored worldwide for oil and natural gas. Today, after much work and focus, we're in five fewer countries than we were in 2013 and far fewer basins, all oil-focused. We've lowered our back office expenses for exploration 70% during this time. Operationally, we've made significant changes. We've divested heavy oil sands in Canada, South Louisiana, and Alaska. We've become a North American unconventional only player while still producing in our big three areas, the U.S., Canada, and Malaysia, where we have a 20-year history. This streamlining has led to lower costs and increased exploration focus, which is seen in recent success and a very robust program going forward.
While focused, we've never lost our competitive advantage of execution seen in our onshore assets and our long history of offshore operational success and our ability to negotiate accretive deals that add shareholder value. Slide 21. As we look to 2019, we're planning a full year CapEx to be in the range of $1.25 billion-$1.45 billion, and annual production being in the range of 202,000 to 210,000 equivalent per day. We're growing production by approximately 20% from last year, with all production growth coming from oil. Both CapEx and production exclude the non-controlling interest in MP GOM. Our 2019 capital expenditure is to really set the foundation for future growth with 64% of our capital at production this year, 15% will drive production within two years, and 12% is for long-term future production growth.
First quarter production is expected to be in the range of 198,000 to 202,000 barrels equivalent per day. Slide 22 on our capital allocation. In 2019, we'll be shifting our CapEx priorities from last year. This year, our overall budget will have 91% of the capital on drilling and field development while paying attention to commodity prices. We have moved Kaybob Duvernay into land retention mode post appraisal success. We've altered capital allocation by reducing our onshore Canada budget by 19%. In turn, our main focus is increasing capital in our high margin oil-weighted plays, namely the Eagle Ford Shale by 38%, and increasing our capital in the Gulf and offshore Canada by 70%, while spending a modest 10% of capital on exploration will generate increased profitability with added oil-weighted production and reserve growth. Slide 23.
I really feel that we're taking the right step in the right direction to position the company for true long-term value creation. I'm especially proud to be one of the select companies generating free cash flow and returning cash flow to shareholders today. We have the unique ability to create upside to our shareholders through continued focus on strategic exploration. We're allocating capital to our assets that will generate profitable growth and our high margin oil-weighted assets. As you look back on 2018 and start a new year, I want to thank all of our dedicated Murphy employees all over the world who continue to deliver our goals and strategy. They are the key driver behind our total shareholder return, ranking in the 93rd percentile over the last three years. Thank you for all your hard work and dedication.
At that point, I'd like to open up the lines for our questions in our usual formats, and we'll go with that now. 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 your questions will be polled in the order they are received. Should you wish to decline from the polling process, please press the star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. Your first question comes from Ryan Todd of Simmons Energy. Please go ahead.
Good morning, Ryan. Go ahead. Good to hear from you.
Great. Good morning. Sorry, I was getting myself off mute. How are you doing? Thanks for the question. Maybe if I could start out with a question on Canada. You have CapEx, effectively the maintenance CapEx there as we look in the Duvernay. I know you finished the appraisal program. Can you talk about where you are in terms of asset understanding and delineation there at the Duvernay? What would you need to see to allocate more capital there going forward? Is it just a question of commodity price and cash flow?
Yes, it is strictly that. When we set out with this MP GOM transaction, our role was to take the cash flow from those assets and greatly improve our Eagle Ford capital allocation. It is really about that more than about Canada. We pulled back greatly in 2016. It all goes back to the collapse in oil prices and the non-issuing of equity at that time, being one of the only people to not do that in all of industry. When you do that, we cut back our Eagle Ford too much. We were in a situation of keeping our acreage in Duvernay and some commitments in the Duvernay at that same time.
That commitment has continued to go down. Now you have to look at what are the prices there versus the prices in the U.S., the cash flow from the U.S., the tax advantages we have in the U.S., and that led to a different capital allocation. We're very happy about the Duvernay in that really haven't drilled a bad well there. You can see in the slide deck today many examples of the wells leading their EUR. We're very excited about this new Two Creeks area because it's more of a Catarina type of Eagle Ford place, black oil, where we think can leave off strings of casing and lower costs there. We have a very good, nice early start. That project's working for us.
We've moved now. Last year, during our last long-range plans, we felt that we were going to go, some of the acreage would be let go, and we'd be moving more into development mode. We've now changed our mind there and going into land retention mode, which is critical for this year to keep nearly 90% of all that acreage. If we pull the development CapEx out of it and transfer that down to Eagle Ford with our cash flow from MP GOM and really change our capital allocation quite a bit. This is what came about through the years. Things change, and that's where we're going forward with that, if that answers your question, Ron.
Think that's great. That's helpful. Maybe just a follow-up. As we look at your portfolio, you've been active in both monetizing and acquiring assets in recent years. You've got quite a few assets, or quite a few pans in the fire as you look forward over the next few years. There have been rumors about a potential sale of additional interest in Malaysia. Are you happy with the current portfolio mix? Would you consider further disposals? As you think about the excess cash you're generating and/or proceeds, how would you think about the attractiveness of additional acquisitions, and is it more interesting to acquire undervalued free cash flow generating assets like the Petrobras deal or onshore in this story?
We've been very active in business development, which shows we will move off of things aggressively during my time here. Quite proud of that, actually. We do not comment on rumors on big, major transactions that show up in some news service. As you know, looking back and knowing Murphy for a long time, Ron, we rarely get out ahead of ourselves on business development, things of that nature. You read about it in the paper as things happen. Our portfolio is something we like. We really don't have a lot of low-hanging fruit in the portfolio at this time. We're very used to working there and understand that asset. We'll look at our assets as we see fit, and we have some very sought-after assets in our company and some very high review of our probable reserves in our company as well by external folks.
We go through every day. We're key on business development. It's a real key focus of my time in the company, and we'll do that, but we can't really comment on or think about what would happen with the proceeds or rumor type of acquisitions. Really not our game plan.
All right. Thanks, Roger.
Thank you.
Your next question comes from Brian Singer of Goldman Sachs. Please go ahead.
Good morning, Brian. How you doing? Hello, Brian, you there?
Oh, hi there. Good morning. I'm sorry. I had the mute bug as well. Roger, you mentioned in the press release that your Gulf of Mexico reserves from the new assets were higher relative to your original estimates at the time of the acquisition. Can you talk a little bit more about what drove that and any implications for either a production or future reserve bookings there?
We originally thought during the data room at the time that we were looking at around $60 million. As it came to fruition through all the work and the EUR curves and the review of some of these key assets, especially St. Malo and some of the other assets, our reserve team will review that also. As you see in our 10-K, 75% of our fields are audited by a third party every year. We have a very close tie to that, quite proud of where we are on corporate reserves and our corporate reserve history. They insinuated we need to take a closer look at that. We did. We made an additional reserve booking. The asset's doing very well. Quite happy with it. Just real pleased with the overall process. Everything's going well there, Brian.
Okay, great. You talked just to, I think, Ryan's question on the trade-off between investing in Canada versus in the Eagle Ford and in your case, for accelerating the Eagle Ford. How do you think about the decision on accelerating the Eagle Ford versus drilling less, having more free cash flow, potentially, and giving even more back to shareholders? How did you look at the decision to the 40% increase versus some greater increase or lesser increase?
Well, one thing, we're one of the leaders in returning to shareholders. 14% of cash flow year after year. At times, 17%. I take the high ground on returning cash to shareholders over anyone during all this call period, I'll assure you. Actually, what it is that we have a really good asset there. We've done a lot of good work in the asset. We need to get a more consistent delivery of our wells, and we're doing well with our Upper Eagle Ford Shale delineation, doing very well with that in the Karnes area. When you go into these five, six, seven wells a quarter, it's very difficult to drive your costs down, stay with improvements, lower operating expenses. We're setting this thing up to be quite a big cash flow player in the next few years.
This time we'll probably be at a below strip number and slightly positive, not a big amount we had this year. We have to uplift this project and get this production up in a very profitable way, with very profitable and very nice prices and also a big tax advantage in the U.S. for us. That's the reason we're just jump-starting it and getting this thing back to a level that we were before, and we have a really good situation there. It just had too much capital. As I got through talking to Ryan, it's about what you got to do that day, and we got into the Duvernay to build up another set of low breakeven costs. We have a history of executing in North America. We run this as one team.
It needed capital that time for that reason, pulling back from the Eagle Ford. As soon as I saw that I could keep all the land and have lower prices there, I reverted and put my capital change back into the Eagle Ford. The whole basis of MP GOM is to build a free cash flow providing United States business that is very tax advantaged for us, and that's part of that transition back into a real profitable oil-weighted U.S. business at this time.
One last follow-up on that. Would you expect that as a result of the scale that you're bringing with the greater activity in the Eagle Ford, that would bring down your drilling cost per foot? It looks like it's flattened in the last couple of years as seen on slide, it's the bottom left of slide 15. Would that mean lower costs, or would it mitigate costs going up?
I think it's going to mitigate. There's starting to be an industry, and the Catarina area is working very well for us. It's very low cost. We're starting to see some massively long laterals drilled by some competitors there, and we are too. I believe it would lead to support flattening for sure. I think the main thing for us and the focus for us in Eagle Ford is we're going to continue to execute in drilling and completion. We have a history in our company of being a very good driller. That's something we're quite proud of. We're really focusing on a new operating model for how we operate the field remotely with data, operate by exception. We're really into driving OpEx is our big focus there at this time.
Thank you.
Thank you.
Your next question comes from John Herrlin of Société Générale. Please go ahead.
Yeah. Hi, Roger. When you mentioned-
Hey, John. Good morning. I'm sorry.
Hello?
Yeah, go ahead.
Okay. Sorry. When you mentioned Dalmatian, you talked about the positive aspects of using the subsea pump and that you could do it in other operations within the Gulf. Can you expand upon that a little bit? How much sustained production do you get, and what kind of return does that type of activity entail?
That project is very unique. Again, Murphy, it was around $112 million project. We were able to finance that through the provider of that service, Schlumberger and Cameron combo there. It went very, very well. They're willing to do that more in a pay-as-it-works kind of a format instead of upfront capital. We know that there are subsea pump not working so well on some of the MP GOM assets that we transacted on. Some that we might could repair or change. This is something that I've been personally after for a long time. These are multi-phase pumps, pumping everything, if you will, and it lowers the system pressure dramatically and just adds reserves. I think the reserves at Dalmatian, I don't know exactly, probably increased by 30%. It's a very small field compared to by doing this transaction.
I feel that it's a big thing coming in the Gulf, and I think one of the big issues around it is this is over about a 23-mile umbilical power cord, if you will. We're looking at that at Samurai. We're looking at it at the MP GOM, and I think it can really add a lot of positive. It's pure delta P to the reservoir. Bringing the reservoir pressure down is what it does and allows for reservoirs to be depleted further over a very long tieback distance. It's going to make tiebacks longer, and it's very helpful, and we have about three things we're looking at now. I think it's going to be a big deal in the Gulf and in Brazil and other places in this hemisphere.
Great. Last one for me is on King Cake. Can you give us a little postmortem?
Yeah. Of course, that's disappointing. This is the deal we made two years ago. Due to schedule changes on Samurai, it was pushed out a little bit. It's a little bit small from the beginning for my taste. I like a little larger that we're going to be drilling in Hawkpark and some of our opportunities. The amplitude was some type of artifact in the seismic and didn't turn up. We did find about 50 feet of pay in the well, both oil and gas. Where we were in the structure would not work. Probably could have suspended the well and looked at it longer, but I went ahead and do not believe we're going to focus our personnel and capital going forward there.
There is some unique things we learned about some deeper sands around the region aspect of the well and the Lower Miocene and Middle Miocene section. Just one of those things. I think the key thing in this business today, what I say in my remarks today, it is a small amount of capital, if you will, for exploration. Get a lot of money, get a lot of value for exploration today. The idea that we can drill a well offshore Vietnam, a brand new wildcat in Mexico, and 50% working interest in a go-to amplitude well that is greatly reviewed by peers in the Gulf for only $50 million is really incredible. These rigs, the ultra-deepwater rigs, are similar in nature. The big players have them, and we are drilling like hell with these rigs, John.
This well is, I think Murphy's drilled two of the fastest wells ever drilled in the Gulf on the original TD of Samurai and the TD of this well. This idea that only improvements are in onshore is just an absolute falsehood there, and these big rigs are rolling in the Gulf and internationally. We are going to really be able to do a lot of value for the rigs that we have today and their ability and what you can get out of a small exploration program. That is why we are so glad we did not leave it, is that you can get so much opportunity for a small amount of capital compared to 2013.
Great. Thanks, Roger.
Thank you.
Ladies and gentlemen, as a reminder, should you have a question, please press star followed by the one. Your next question comes from Paul Sankey of Mizuho. Please go ahead.
Morning, Roger.
Morning, Paul. Haven't talked in a while.
Yeah. Hi, hope you're well, and all the best for 2019.
Thank you.
Roger, I'm sure you feel like you've answered this, but I was wondering about your CapEx sensitivity to oil prices and the extent to which, you said you'll spend within cash flow if we did get upside in oil prices relative to your expectations. I would be interested to know what your expectations have been regarding planning for this year. Would you be spending more, and where would you be spending it? Thanks.
Well, that's a difficult question. We all know that we're trying to not do that immediately, spend every nickel. We do have a bit of a balance on our revolver that we want to pay off. At strip prices today, we'd probably be able to do that as well above the free cash flow that this plan will deliver. Be really working not to do that as best we can. I think it's best to have the discipline of what we have and continue on with the program we have. One of the things I've been wanting to do in the last few years, you could see it a little bit in 2018, was get more capital into our Eagle Ford. The Eagle Ford has been struggling with this low and haphazard up and down well count that we have there.
Now we have a more streamlined, big approach there to get this asset back kicked off like it needs to be. Now we're able to accomplish that with this plan. Very happy about the capital in Canada. We'll not be increasing there. I'm not going to say what we're looking to do. We do have a lot of opportunities. There are some unique opportunities around the MP GOM assets on failed components and wells that could be worked over. The equipment to fix those are 9-10 months away. That would be my go-to thing first, but we're at all costs trying to avoid doing that, Paul.
Understood, Roger. Thank you. The follow-up is, historically, you've been very levered to Brent. You've also equally talked this morning about how you've reshifted the portfolio.
I was just wondering how your leverages and exposures to crude differentials are shifting and if there was anything particular about the Gulf of Mexico realizations relative to some market prices that you would share with us. I think we were a little bit surprised the numbers weren't quite as high as we might expect.
Yeah.
Sorry.
That'd be one of the few surprises in this. I mean, I knew about this, what's going to happen with these new assets, you take a St. Malo asset, which is incredible. It has a below $2 OPEX there, that's just absolutely phenomenal in deep water. A big Kakap field in Malaysia is around $5 or $6. They are opportunities, very rare to have super low OPEX. These facilities are very far offshore, and they have a very large pipeline headed to shore in Louisiana. There's a pretty big tariff on those lines compared to some of our mid deepwater Gulf that we're used to operating. There's been a pullback in the realization there.
Some unique things, this Cascade Chinook is an FPSO where crude is offloaded and traded into Mobile and had some loadings in December, which we all know is not a good time. Also in our realized pricing, you have to realize that the more weighting of those assets from the 20% of Petrobras is into that number, as we have this NCI issue that we have to go through for GAAP. I think the issue for us is we're going to be closer to WTI. Our realized price in the Gulf is going to be closer to WTI, and our Eagle Ford will probably be a little better than the Gulf in that regard. Our OPEX in the Gulf should be where we are now or lower. We're making a trade-off.
Also in Murphy, as we disclose prices, our realized prices has transportation in. If you look, as you know, Paul, in the company for decades now, we don't have transportation on the side. The realized price has the transportation in. I think for you to back that out, be quite good. That's what's going on with the Gulf. I don't think delivering at WTI is the end of the world with the OPEX to go along with it.
Understood. Thank you very much, Roger.
No, thank you.
Your next question comes from Muhammed Ghulam of Raymond James. Please go ahead.
Thanks for taking the question, guys. Following up on one of the recent questions, just to confirm, if we were to, let's say, see crude bounce back to late 2018 highs, we shouldn't expect any increase in the capital budget, right?
I'll be doing all I can to avoid that.
Okay. Understood. One other question. You guys mentioned you have a prospect spudding in Mexico this quarter, the first quarter. Given the new administration, I'm curious, are you guys seeing any changes in terms of the relationship with Pemex or the fiscal terms?
Well, it's really not Pemex. Pemex is more of a competitor in Mexico. It's the CNH or the governing party that grants permits to drill and approves them, and then there's an approval of environmental permits and safety ability, et cetera. All that's going forward, and we're looking to go in there pretty quick. I've seen no pullback. It's no different than operating anywhere else in the ocean where we work all over the world, and real happy with it. There's going to be a lot of wells drilled in Mexico, and I think the administration wants to see them drilled.
We have a great block there that's the size of 110 Gulf of Mexico blocks, and we have different types of prospects, subsalt, and we have a play here that's just a closure feature, and very happy about drilling that well, very happy about the nearby results reported by other folks, and it's all systems go to drill in Mexico as far as I'm concerned.
Okay. Understood. Thank you.
Thank you.
Your next question comes from Paul Cheng of Barclays. Please go ahead.
Hey, guys.
Morning, Paul. How you doing?
Good. Very good, thank you. Just several quick question on I have to apologize first. I came in a little bit late, so if you already answered, just let me know. I will check the transcript. For Eagle Ford, should we assume that with the increase in CapEx, you will be able to reach maybe somewhere in the, Pat told, say, 65,000 barrel per day a couple year down the road? If you do, once you get there, to sustain it, how many rig program that you need, and also how long you will be able to sustain based on your resource?
We have a long way to go there, Paul. 800 or 1,000 locations. It's somewhere been disclosed before, so we got plenty of years of running room. Our current plan, we're not disclosing a long-range plan today. As you see, we're still working on various parts of that. Our Eagle Ford business is going to get into the 60s, heading into the 80s, hopefully, and it has the ability to get into the 100s. Probably going to be running three rigs this year on an average. We have four today, three next year, then we'll get into the five-rig game, even at these prices. Our idea, again, is to build a very strong oil-weighted, tax-advantaged, pretty good global price portfolio that's operated out of this building in Houston with low cost.
That's the kind of change. That's why we did the Gulf of Mexico deal. That's why we have very proud of our Eagle Ford. The Eagle Ford's going to have a long way to go on EOR-type opportunities, refrac opportunities, technology. We're spearheading continuing with improvements there. We have the army there to fight the war. We're going to continue on doing that. It's a big asset for us and a very valuable one. We have the ability to do a lot of things with this asset. Our Gulf business being a solid 50K plus. That's business too for several years as well.
In Kakap and Duvernay, the 25% decline. How many wells that we plan to complete next year? Or this year, I should say.
Hang on one second, Paul. We have that right here. I believe it's 12 wells. It's in our release, Paul. 12 wells coming on, four in quarter one, six in quarter two, two in quarter three, and zero in the fourth quarter.
With this, if we assume that this will be the new level of baseline on the CapEx, what is the production trend we should assume in this field?
What's going to happen there is it's going to increase this year from, I believe last year was around 8,500, and we're going into the 12,000-13,000 range this year. Then into probably 2020 getting into the 17,000 range. This is for Duvernay and Placid combined. Also, if you look at our production, our partner at Placid has delayed all of their capital to the second half of the year, which is hurting production levels as may have been perceived a year ago. Then it's going to be a lot of questions around capital allocation between all the land will be retained, some of the development mode will go on, and do we want to make it a solid 15,000 a day business that can grow into the 30,000s, and then play it against our other assets we have in the company at that time.
This is built to be a low cost, inexpensive way to add valuable low breakeven price wells. You can see in our slide deck on page 18, all kinds of varying results that are quite positive compared to where we are. It's a series of hundreds of 550,000-650,000 gross EUR wells. We feel we're absolutely going to achieve our $6.5 million cost there, and these wells are profitable.
Right.
We built this from scratch, and it's going to go well. Canada has a lot to do, and it'll be a big positive improvement, but not till 2020 and beyond due to pipeline constraints on other things, and LNG leaving, and those kind of things, Paul, is driving us to a temporary pullback, but that's what we're so proud of, is we have multi things to invest in in our company. You'll very rarely find Murphy all eggs in one basket, all eggs in one kind of service, one kind of pipe. Now we're able to allocate capital into something else. Again, tax advantage, decent priced, U.S. weighted is the flavor of the day for us. Because of our portfolio, we're able to do that now that we've protected all the eggs.
Flexibility is good.
Yeah.
Montney, what's the CapEx? Maybe I miss it. What's the CapEx that we expend in Montney?
We're this year gonna spend a little more than last year. I think the CapEx is $55 million. If you want to think about it in a maintenance CapEx, the production's anticipated to be flat. We have $55 million in all of the Tupper assets, but $10 million of that, or more, is on field development. There's a big water project working on to lower our cost long term there. Really only about $35 million's on D and C from a maintenance perspective.
I know-
We had free cash flow in the Montney in 2018. The key we need to point out as well.
Right. Roger, maybe I get confused, but I thought maybe a year ago that we were talking about maybe want to expand and increase it. Is that plan currently is put on the back burner because of the limitation on the infrastructure that you're just going to get it through?
No. I'm glad you asked that question. We have an expansion project we participated in with the company that purchased Enbridge recently. I can't recall their name. We have a plant being built, and we have all the wells and all the reserves we'd ever need there. We were going to increase this to around, probably in 2021, of right now the current plan would probably be 330 and then 450-475 a day in 2020 and 2022 kind of a thing. The real thing for people to understand, again, about Murphy and our flexibility and our portfolio is that if we stop drilling in the Montney and never drilled another well to 2021, we can avoid $400 million of CapEx and only pay $60 million of fees.
The fee amount of what we owe for this is very low compared to the capital allocation, and we can wait out and slow back the Montney some as we look for 2020 to be an infection price on. All we need is just a small improvement. As a matter of fact, the prices in forward cover date will allow breakeven. Drilling there, we wouldn't be drilling at all. This idea that we have to expand and have to spend those capital is not true, and that we have the flexibility to stop things and hike for a year, the entire year, or do whatever we need to do because of the negotiation of how we enter into the pipes and the facility.
Right. on a going forward.
That's how we're thinking about that.
Thank you. On a going forward basis on Gulf of Mexico with your expanded footprint, what is the exploration program target going forward you'll be annually that you expect to drill, what, five wells, six wells, or is there any kind of.
No, this year, if you break out our exploration expenses around $108 million. Last year was $138. That's G&G of around $20. Our other exploration expenses would be personnel and what it costs to be an explorer of around $28 or so. For $50 million or $60 million, if the rig rates stay where they are. We will probably drill, as we do this year, four to five wells a year. I'd like to get the Gulf into two wells, we run the Gulf as the entire Mexico as well. We run it with one team. When I say, want to get to this year, we're drilling two wells, one in Mexico, one in the Gulf of Mexico. We'd be at that range of three every year would be the goal. It's going to depend a lot on exploration in Mexico.
Of course, the block is very large, probably 30 prospects on there, because our Mexico acreage is the exact footprint of our Gulf of Mexico acreage on the U.S. side. I'd like to see the Gulf of Mexico in a three-well-per-year game at 15%-35% working interest sort of thing. Under current costs, you can go a long way with that, Paul.
Finally, just a clarification. You say Gulf of Mexico, going forward, you expect price realization on the WTI. Is that based on the LLS WTI spread, the current level at the $7 or so, or are you based on a more maybe narrower on a normalized, say, four or $5?
Well, there's a lot going on. As you know, LLS is becoming less traded. A lot of pipes built out of the Permian. There are differing terminology being used by traders today. Today in our forecast, we would describe the Gulf due to the net back and realizations, due to the transportation of the weighting of our MP GOM assets to be a WTI base, realized to Murphy. As you know, every day is a new day in this game. With the Venezuela shut-ins and the need for heavy and sour crude, some of the famous crudes in the Gulf, such as Mars and some other things that are more designed for U.S. Gulf Coast, this thing's gone six bucks above WTI today. This issue around Venezuela and the idea that they may be under sanction for a while will improve what I said.
When I say that near WTI realization, that doesn't account for issues in Venezuela. We all know that there's too much light oil needing more heavier, old school Gulf of Mexico-based oils into the system. While I'd say that's in our plan, we're upgraded from that today.
Okay. Thank you.
Thank you, Paul.
There are no further questions.
Okay.
Excuse me. 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.
Thanks, everyone, for calling in today. We had some good dialogue. We appreciate it. We're heading back to work now. Wish everyone a good day. Thank you.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating. Ask that you please disconnect your lines.