Murphy Oil Corp (MUR) 2018 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2018 Earnings Conference Call and Webcast. (Operator Instructions)

I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thank you, Jessica. Good morning, everyone, and 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 noncontrolling interest 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. 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 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, and thank you for listening to our call today.

2018 is an excellent year, both financially and operationally for Murphy Oil. Our strong results illustrate our commitment to a diversified portfolio as oil-weighted production from our onshore and offshore assets continue to generate high margins realizations and cash flow.

We produced 176,000 barrels equivalent with 61% liquids in the fourth quarter. And 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. And on an annual basis, we recorded a net income of $411 million or $2.36 per share. This is our highest annual net income in over 4 years. Our disciplined capital allocation enabled us to return 14% of our annual operating cash flow to shareholders. Our diversified portfolio generated EBITDA per BOE of over $25 per barrel and EBITDA per average capital employed was notable at 21%.

To the energy side, we've maintained our ability to execute Deepwater offshore projects with success found in the record-breaking Dalmatian project and the unique gas lift solution in Malaysia. In our North American onshore business, we achieved an annual lease operating expense of just over $6.50 barrel equivalent. We simultaneously delivered on our growth plans while spending within cash flow and growing our Kaybob Duvernay shale by almost 2.5x year-over-year.

Slide 4. We continue to successfully execute on our strategy. We have 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 transformational transaction in the Gulf of Mexico to increase our footprint in that 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 weighted -- oil-weighted assets, over 50% of our future locations are breakeven of 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, successful installation of the longest multiphase subsea pump distance in the world.

Slide 5. As we reveal our 2018 production, you need to keep in mind that starting in the fourth quarter of '18, we'll be reporting 100% interest, including the 20% noncontrolling interest in our new subsidiary, MP GOM. For discussion purposes, we will exclude the noncontrolling interest and only highlight the amounts attributable to Murphy, unless otherwise noted. In the fourth quarter, we produced 176,000 equivalent. And the fourth quarter production was 47% offshore and 53% onshore.

On reserves, slide -- Page 6. I'm especially proud of our teams' work to replacing that valuable proved reserves in 2018. Our proved reserves increased to 816 million barrels equivalent, a 17% increase from '17. And most importantly, our crude oil reserves increased by 24%. Simultaneously, we lowered our organic finding and development cost to $10.92 per BOE and maintained a reserve life index of over 10 years. We have lowered our 3-year average F&D cost by 50% since 2014.

I'll 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 one, the impact of tax adjustments in the quarter of $30 million; number two, an unrealized mark-to-market gain on crude oil derivative contracts of $28 million; and 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 '18, 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, and then 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.

Also 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 long-standing 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 in 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 1 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 as reflected on our cash flow statement. Truly a unique quarter with the transaction and the working capital changes, but 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 mainly free cash flow providing Gulf of Mexico assets complements our comp 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 the 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 continue to perform well as we're able to achieve a quarterly low lease operating expense of below $10 per barrel. Dalmatian's 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 DTU 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 is expected to sail away in the first quarter of 2020 for final hookup and commissioning. In Vietnam, our LDV field received a verbal -- received an approval, rather, 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 noncommercial quantities of hydrocarbons and was plugged and abandoned. The well which Murphy operated at 35% working interest was drilled 35% below the expected ANP for a net cost to Murphy of $16 million. Looking forward to our 2019 exploration plan where we expect to spread 3 key wells for a 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 received all of the approvals we need and should spread the well in the next few weeks. Secondly, in Vietnam, we expect to spread the LDT prospect in our 15-01/05 well in the first quarter as well. In the Gulf of Mexico, we plan to spread the Hoffe Park 2 well and 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 8 wells online in the Eagle Ford, all in Catarina. In IP30, the average rate for 8 wells was 860 barrels equivalent per day gross. The Eagle Ford Shale team has done a good job continuing to lower completion costs or holding drilling costs flat in spite of service cost inflation. Our completion cost per lateral foot decreased 13% year-over-year while drilling per foot was flat while 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 improvement, sand per foot increases during the time frame. This, all from continued outstanding execution and especially, some key procurement work of 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 continued to experience challenging process, we were able to generate free cash flow in this asset. Our marketing team continues to mitigate our AECO spot price exposure through hedges in all of 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 price at AECO.

Slide 17. In the Kaybob Duvernay, we finished off 2018 completing the 5 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 the outstanding results from our 4 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 in 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 5 years. We've greatly reduced our global footprint in exploration. Prior to 2013, we explored worldwide for oil and natural gas. Today, after much work and focus, we're in 5 fewer countries than we were in '13 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, oil sands in Canada, South Louisiana and Alaska. We've become a North American unconventional only player while still producing in our big 3 areas, United States, Canada and Malaysia, where we have a 20-year history.

The streamlining has led to lower costs and increased exploration focus, which is seen in recent success and a very robust program going forward. For our focus, 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 to $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 noncontrolling interest in MP GOM.

Our 2019 capital expenditure has really set the foundation for future growth with 64% of our capital at production this year, 15% will drive production in 2 years and 12% is for long-term future production growth. First quarter production we expect 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 in 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 Canada, our main focus is decreasing capital in the high-margin oil-weighted plays, namely the Eagle Ford Shale, by 38%, an increase in our capital in the Gulf and offshore Canada by 70%, while spending a modest 10% capital on exploration. This shift in allocation would generate increased profitability with added oil-weighted production and reserve growth.

Slide 23. We feel that we are 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 to shareholders today. And 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 would generate profitable growth in our high-margin oil-weighted assets.

As we look back on '18 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 3 years. Thank you for all your hard work and dedication.

With that point, I'd like to open up the lines for our questions in our usual format, and we'll go with that now. Thank you.

(Operator Instructions) Your first question comes from Ryan Todd of Simmons Energy.

Maybe if I could start out with a question on Canada. You've got a CapEx that's like totally the maintenance CapEx there as we look into Duvernay. I know you finished the appraisal program. Can you talk about where you are in terms of asset understanding in Duvernay? And what would you need to see to allocate more capital there going forward? Is this just a question of commodity price and cash flow?

Yes. It's strictly that. We -- 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's 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 the industry. And 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 is -- that commitment has continued to go down. Now you have to look at what are the prices there versus the prices in the United States, the cash flow of the United States, the tax advantages we have in the United States. And that led to a different capital allocation. We're very happy about the Duvernay and 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 than Eagle Ford play's black oil where we think can leave off strings of casing and lower cost there, and we have a very good nice early start. So that project is working for us and so we've moved now. And 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'll be moving more into development mode. We've now changed our mind there in going into land retention mode, which is critical for this year to keep nearly 90% of all that acreage. But then if we pull the development CapEx out of it and transfer that down to Eagle Ford with our cash flow from MP GOM and that really changed our capital allocation quite a bit. This is what came about through the years. Things change. And that's where we're going forward there without it. If that answers your question, Ryan.

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, quite a few pans in the fire to look forward to over the next few years. There's been rumors about potential sales, additional interest in Malaysia. Are you happy with the current portfolio mix? Would you consider further disposals as you think about your -- or the excess cash you're generating and then and/or proceeds? How would you think about the attractiveness of additional acquisitions? And would it be -- is it more interesting to acquire undervalued free cash flow generating in assets like the Petrobras deal or onshore [exploration]?

Well, as you know, we've been very active in business development, which shows we will move this -- off of things aggressively during my time here, quite proud of that, actually. But we do not comment on rumors on major transactions that show up in some news service. I mean, as you know, looking back and knowing Murphy for a long time, Ryan, we rarely get ahead of ourselves on business development, things to that nature. And you kind of read about it in the paper as things happen. I mean, 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. But we've -- 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, thanks to our folks. So we go through every day, we're key on -- business development is the 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 acquisition is really not our game plan.

Your next question comes from Brian Singer of Goldman Sachs.

Roger, you mentioned in the press release that your Gulf of Mexico reserve from the new assets were higher relative to your original assets 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. And then as it kind did fruition through all the work and the EUR curve and the review of some of these key assets, especially St. Malo and some of the other assets, that our reserve team will view that also. As you see in our 10-K, we do a lot of our -- 75% of our fields are obviously by third-party. Every year, we have a very, very close tie to that and quite proud of where we are in corporate reserves and our corporate reserve history. And they insinuated we need to take a closer look at that. We did, and we made additional reserve booking. And the assets are doing very well and quite happy with it. And we're just real pleased with the overall process. Everything's going well there, Brian.

Okay, great. And then you talked to just, I think Ryan, the question on the tradeoff between investing in Canada versus in the Eagle Ford in the -- in your case, you're accelerating in the Eagle Ford. How do you think about the decision on accelerating in the Eagle Ford versus drilling less, having more free cash flow potentially and giving even more back to just shareholders? How do 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. I mean, 14% of cash flow year after year at time, 17%. So I'll take the higher ground on returning cash to shareholders over anyone during all this call period, I assure you. So actually, what it is, is that we have a really good asset there. We're doing a lot of good work in the asset and this -- 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. And when you go into these 5, 6, 7 wells a quarter, it's very difficult to drive your cost down, stay with improvements, lower operating expenses. And we're setting this thing up to be quite a big cash flow player in the next few years. And this time, we'll probably be at a below strip number in slightly positive, not a big amount we had this year. But we have to uplift this project and get the -- get this production up in a very profitable way, we're very profitable and very nice prices and also a big tax advantage in the U.S. for us. So that's the reason. We're just jump-starting it and getting this thing back to a level that we were before and that we have a really good situation there. And it's just -- it doesn't have too much capital. Although I've got to talking to Ryan, it's about what you got to do that day, and it -- we got into the Duvernay to build up another set of road breakeven cost. We have a history of executing in North America. We run this as a 1 team. So it needed capital at that time for that reason, pulling back from the Eagle Ford. And soon as I saw that I could keep all the land and have lower prices there, I've reverted and put my capital changed back into the Eagle Ford. And 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 a part of that transaction -- that transition, rather, back into a real profitable oil-weighted U.S. business at this time.

One last follow-up on that. Would you expect that the -- as a result of the scale that you're bringing with the greater activity in Eagle Ford, that would bring down your drilling cost per foot, like -- it just looked like it's kind of flattened in the last couple of years, as seen on the slide, it's at the bottom left of Slide 15. Would that lower cost or would it mitigate cost going up?

I think it's going to mitigate. We do have some -- there's starting to be an industry in the -- 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. We are, too. I believe it would lead to support flattening for sure, but we also -- I think the main thing for us and the focus for us in the 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. But we're really focusing on a new operating model for how we operate the field remotely with data, operate by exception. And we're really into driving OpEx as our big focus there at this time.

Your next question comes from John Herrlin of Societe Generale.

Okay. When you mentioned Dalmatian, you talked about the positive aspects of using the subsea pump and that you could do it in other operations from the Gulf. Could 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, at Murphy. It's around $112 million project. We were able to finance that through the provider of that service, Schlumberger Cameron combo there and went very, very well. And there's -- they're willing to do that more in a pay-as-it-works kind of a format instead of upfront capital. We know that they are a subsea comp, not working so well in some of the MP GOM assets that we transacted on, some that we might could repair or change. This is something that I've have been personally after for a long time. These are multiphase pumps, pumping everything, if you will. And it lowers the system pressure dramatically and just adds reserves. I think the reserves that Dalmatian -- I don't know exactly, probably increase about 30%, it's a very small field compared to by doing this transaction. So 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. And we -- 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 to make tiebacks longer. And it's very helpful. And we have about 3 things we're looking at now. And I think it's going to be a big deal in the Gulf and in Brazil and other places in this hemisphere.

Great. The last one from me is on King Cake. Can you give us a little post-mortem?

Yes. The -- of course, that disappointed us is the deal we made 2 years ago and 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'd like a little larger that we're going to be drilling at Hoffe Park and some of our opportunities. The amplitude with some type of artifact and the seismic, it didn't turn up. We did find about 50 feet of pay in the well of both oil and gas. And about where we were in the structure would not work as a -- 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. But there were some unique things we learned about some deeper sands around the region aspect of the well and the Lower Miocene and Middle Miocene section. And we're just one of those things. I think the key thing in this business today -- what I'll say in my remarks today is a small amount of capital, if you will, for exploration. We have a lot of money. We have 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% work [niche] and a go-to amplitude well that's 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're drilling like hell with these rigs, John, and as well as -- I think Murphy's drilled 2 of the fastest wells ever drilled on the Gulf and the original TD at Samurai and the TD of this well. So this idea that only improvements are in onshore is just an absolute false. A falsehood there, and these big rigs are rolling in the Gulf and internationally. And we're going to really to be able to do a lot of value for the rigs that we have today in their ability and what you can get out of a small exploration program. That's why we're so glad we didn't leave it, is that you can get so much opportunity for a small amount of capital compared to 2013.

(Operator Instructions) Your next question comes from Paul Sankey of Mizuho.

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. And 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?

Well, it'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 strict prices today, we'd probably be able to do that as well. As far as the free cash flow that this plan will deliver, we'd 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 '18, was get more capital in our Eagle Ford. The Eagle Ford has been struggling with the slow and haphazard up and down well count that we have there. And 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. We're very happy about the capital in Canada. We'll not be increasing there. And 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 sale components and wells that could be worked over. But the equipment to fix those are 9 to 10 months away, so it will be in my go-to thing first. But we're -- at all costs, trying to avoid doing that, Paul.

Understood, Roger. And then the follow-up is your -- yes, historically, you've been very leveled to Brent, but 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 surprised that the numbers aren't quite as high as we might expect but...

Yes. Probably one of the few surprises in this. I mean, I knew about this. So what's going to happen with these new assets? If you take a St. Malo asset, which is incredible, it has a below $2 OpEx there. Such as the absolutely phenomenal in Deepwater, a big Kakap field in Malaysia has around $5 or $6. So they are opportunities, but 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. And so there's been a pullback in the realization there. Also some unique things as 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. And 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 to for GAAP. So 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, but our OpEx in the Gulf should be where we are now or lower. And so we're making the trade-off. And also, in Murphy, as we disclose prices, our realized prices has transportation in. And if you look -- as you know, Paul -- Paul, in the company for decades now, we don't have transportation on the side. So the realized price has the transportation in. And I think if you back that out, it'd be quite good. But that's what's going on with the Gulf. And I don't think delivering at WTI is end of the world with the OpEx to go along with it.

Your next question comes from Muhammad Ghulam of Raymond James.

So following up on one of the recent questions, just to confirm, if we were to -- let's say, crude -- say, crude bounced back to late 2018 highs at current, we shouldn't expect any increase in the capital budget, right?

I'll be doing all I can to avoid that.

Okay. Understood. And one other question. So 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 government party that grants permits to drill and approves. And then there's an approval on environmental permits and safety ability, et cetera. All that's going forward. And we're looking to go on there pretty quick. And seeing no pullback, it's no different than operating anywhere else in the ocean where we work all over the world. And we're happy with it, and there's going to be lot of wells drilled in Mexico. And I think the administration wants to see them drilled, and 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 we're 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.

Your next question comes from Paul Cheng of Barclays.

I just have a quick question on -- I have to apologize first. I came in a little bit late, so if you already answered, you just let me know, I will check the transcript. For Eagle Ford, should we assume that with the increase in CapEx, you would be able to reach -- maybe that's somewhere in the -- say 65,000 barrels per day a couple of years down the road? And if you do, once you get there to sustain it, how many rig programs that you need? And also, how long you would be able to sustain based on your resource?

Oh, we have a long way to go there, Paul. 800 or 1,000 locations that Sam Rubin disclosed before. So we've got plenty of years or run room. In 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. We're probably going to be running 3 rigs this year on an average. We have 4 today, 3 next year and we'll get into the 5-rig game even at these prices. And there are -- 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. So that's the kind of change that we're -- that's why we did to the Gulf of Mexico deal, that's why we're -- we are very proud of our Eagle Ford. The Eagle Ford has got a long way to go on the deal or type opportunities, refrac opportunities. The technology we're experimenting is continuing with the improvements there. We have the army there to fight the war, and we're going to continue on doing that. It's a big asset for us and a very valuable one. And we have the ability to do a lot of things with this asset and our Gulf business as being a solid 50K plus, 55-plus business, too, for several years as well.

And in Kaybob and Duvernay, the 25% decline, how many well there 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: 4 in quarter 1, 6 in quarter 2, 2 in quarter 3 and 0 in the fourth quarter.

And so with this, if we assume that this will be the new level or base now 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. And then into probably 2020, getting into the 17,000 range. And this is for Duvernay and Placid combined. And 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. But then there'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 30s, and then play it against our other assets we have in the company at that time. But 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. And it's a series of hundreds of 550,000 to 650,000 gross EUR wells, we feel we're absolutely going to achieve our $6.5 million cost there. And these wells are profitable. And we built this from scratch. It's going to go well. But the price and -- but Canada has a lot to do and will be a big positive improvement, but not until 2020 and beyond due to pipeline constraints and other things and LNG leaving, and those kind of things, Paul, is driving us to a temporary pullback. But that's -- what's we're so proud of. So we have multi things to invest in. And in our company, you're very -- you'll very rarely find Murphy all eggs in one basket, all eggs in one kind of service, one kind of pipe. And now we're able to allocate capital into something else. And again, tax advantage, decent priced, U.S. weighted is the flavor of the day for us. And because of our portfolio, we are able to do that.

At Montney, what's the CapEx in the guidance? Is it -- what's the CapEx that we spend in Montney?

We're, this year, going to spend a little more than last year. I think the CapEx is $55 million. If you want to think about it in the maintenance CapEx, the production is expected to be flat. We have $55 million in all of the tougher assets. But $10 million of that is -- or more -- is on field development. There's a big water project workout to lower our cost long term there. And so really, only about $35 million is on D&C from a maintenance perspective.

And also, we had free cash flow on the Montney in 2018, also is the key that we need to point out as well.

Right. And what's your latest -- I -- get confused -- but I thought maybe a year ago that we were talking about maybe you want to expand and increase it? So is that plan currently just put on the back burn because of the limitation on the infrastructures that you're just going -- getting into?

No. We have enough -- I'm glad you asked that question. We have a expansion project we participated in with the company who 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. And we were going to increase this to around a 3 -- probably in 2021 of -- but now, the current plan is probably $330 million and then $450 million to $475 million a day in '20 and '22 kind of a thing. But 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. So 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 inflection price on. All we need is just a small improvement. As a matter of fact, the prices in forward curve today will allow breakeven drilling or we wouldn't be drilling at all. So this idea that we have to expand and have to spend those capital is not true, and we have this flexibility to stop things and hide for a year, the entire year or do whatever we need to do because of the negotiation of how we enter into the pipes on this field. So that's how we're thinking about that.

And 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 well, 5 well, 6 well? Or is there any kind of...

No. I mean, this year, if you break out our exploration expenses, around $108 million. Last year, it was $138 million. But that's everything. That's G&G of around $20 million. Our other operating -- our other exploration expenses would be personnel and what it cost to be an explorer of around $28 million or so-so. For $50 million or $60 million, if the rig rates stay where they are, we will probably drill, as we do this year, 4 to 5 wells a year. I'd like to get the well -- the Gulf into 2 wells, but we run the Gulf as the entire Mexico as well. We run it with one team. So when I say, I want to get to -- this year, we're drilling 2 wells: 1 in Mexico, 1 in the Gulf of Mexico. We'd be at that range or 3, every year will be the goal. And it's kind of depend a lot on exploration in Mexico. Of course, the block is very large, probably 30 prospects in there. Because our the Mexico acreage is the exact footprint of our Gulf of Mexico acreage on the U.S. side. So I'd like to see the Gulf of Mexico in a 3-well per year gain at 50% -- to 35% working interest sort of thing. And under current costs, you can go a long way with that, Paul.

And finally, that on -- just a clarification, you see a strong Mexico. Going forward, you expect price realization on the WTI. So is that based on the LLS WTI spread, the current level at the $7 or so? Or you based on a more -- maybe narrow -- on a normalized, say, $4 or $5?

Well, there's a lot going on, as you know, Paul. LLS is becoming less traded, a lot of pipes built out of the Permian, there are differing terminology being used by traders today. And today, in our forecast, we would describe the Gulf due to the netback and realizations, due to the transportation of the weighting of our MP GOM assets to be at WTI base realized to Murphy. But as you know, every day is a new day in this game. And with the Venezuela shut-ins and the need for heavy and solid crude, some of the things, crudes in the Gulf such as Mars and some other things that are more designed for U.S. Gulf Coast that these things gone $6 above WTI today. So this issue around Venezuela and the idea that they may be under sanction for a while will improve what I said. So when I stated near WTI realization that doesn't account for issues in Venezuela. And we all know that there's too much light oil, needing more heavier old school Gulf of Mexico based oils into the system. So while I'd say that's in our plan, we're upgraded from that today. Okay. Question?

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.

Thank you, everyone, for calling in today. We had some good dialogue. We appreciate it. We're heading back to work now and wish everyone a good day. And thank you.

Thank you.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.