Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation 4th Quarter 2018 Earnings Conference Call and Webcast. 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 Q4 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 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 ks 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 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 4th quarter and full year production was 171,000 barrels equivalent at 59% liquids.
We are seeing the immediate impact of the MP GOM transaction and enhanced profitability, oil weighted production and reserves. In the 4th quarter, we generated $103,000,000 or $0.59 per share of earnings and on an annual basis we recorded net income of $411,000,000 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%.
Through the energy cycles, we maintain our ability to execute deepwater offshore projects with success found in the Record Break and 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 barrel equivalent. We simultaneously delivered on our growth plans while spending within cash flow and growing our Kaybob Duvernay Shale by almost 2.5 times 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 and now installed and begin to demonstrate production uplifts. We executed transformational transaction in the Gulf of Mexico and increased our footprint in the region affording us access to world class assets such as the St. Malo field. Vietnam, we work closely with their national oil company Petro Vietnam to negotiate operatorship while increasing our working interest in the Cuu Long Block fifteen-one 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. 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 5. As we reveal our 2018 production, we need to keep in mind that starting in the Q4 of 2018, we will 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 4th quarter, we produced 176,000 equivalent and 4th quarter production was 47% offshore and 53% onshore. On our reserve slide, page 6, I am especially proud of our team's work to replace and add valuable proved reserves in 2018. Our proved reserves increased to 816,000,000 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 maintain a reserve life index of over 10 years. We have lowered our 3 year average F and 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 in the Q4 of 2018 included net income of $103,000,000 which is $0.59 per diluted share compared to a loss of $287,000,000 or $1.66 per diluted share in the Q4 of last year. Our adjusted income was a profit of $54,000,000 or $0.31 per diluted share in the 4th quarter versus a profit of $13,000,000 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 $30,000,000 number 2, an unrealized mark to market gain on crude oil derivative contracts of $28,000,000 and lastly, an impairment of select Midland properties of $16,000,000 Another highlight that I would really like to note for 2018 is that our full year accrued CapEx of $1,190,000,000 came in $40,000,000 below our guidance.
Again, full year accrued CapEx $1,190,000,000 which was $40,000,000 below the guidance. At December 31, 2018, our total debt amounted to approximately $3,200,000,000 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 $1,600,000,000 senior unsecured revolving credit facility with more favorable covenants than the previous credit facility. When we closed the Gulf of Mexico transaction, we paid $470,000,000 cash and then drew down $325,000,000 on the new facility for a total consideration of $795,000,000 Cash and cash equivalents were approximately $390,000,000 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 plus 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 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 Q4 and in fact the month of December was quite unique and that we had a 1 month increase in working capital of approximately $170,000,000 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 $87,000,000 for the year.
As the chart indicates, however, the negative working capital change actually resulted in a shortfall of about $83,000,000 When you combine this $83,000,000 outflow with the approximately $495,000,000 of cash used to close the MP GOM transaction, You can easily see the $578,000,000 cash reduction that's 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 will 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 70,000,000 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 continue to perform well as we are 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 2 50% from the prior quarter. Unique execution example that sets Murphy apart with another industry first has implemented a new technology we believe can use 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 KiK 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-twenty 20 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 Q1 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 4th quarter we drilled the King Cake exploration well which countered 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 $16,000,000 Looking forward to our 2019 exploration plan where we expect to spud 3 key wells for net cost of near $54,000,000 This will enable us to touch over 109,000,000 dollars of barrels equivalent net mean resource potential. An update on the Q1 exploration wells. First in offshore Mexico, on our Cholula prospect we 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 in our fifteen-one hundred and five well in the Q1 as well.
In the Gulf of Mexico, we plan to spud the Half Part II wells and Mississippi Canyon 165 in the Q3. Moving to slide 15, discussing the Eagle Ford Shale. According to our plan during the Q4 we brought 8 wells online in the Eagle Ford all in Catarina. The IP30 average rate for 8 wells was 8 60 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 cost 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, sand for foot increases during this timeframe. This is all from continued outstanding execution and especially some key procurement work by our Eagle Ford Shale team. This asset generated over $185,000,000 of free cash flow over the course of 2018, a metric we are 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 process, we are able to generate free cash flow in this asset. Our marketing team continues to mitigate our AECO spot price exposure to hedges and off AECO sales. For the year, we realized CAD2.39 per NCF. In the Q1 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 Q4. At this time, we feel that our appraisal of the play is complete with the exception of the 2 Creeks area, which is ongoing with very encouraging early results. Slide 18. We continue to have strong oil performance in Duvernay leading to production steadily increasing over the course of the year with 4th quarter production exceeding 11,000 barrels equivalent per day with 59% liquids. Our lease operating expenses continue to trend down in this play.
We have achieved an all time low of $5.74 per barrel in the 4th quarter. This is outstanding work by our team in Calgary. On slide 18, we are showing some of our outstanding results from our 4 well pads we have executed early in the year and in the 4th 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 would like to step back as to where we have come over the last 5 years.
We have greatly reduced our global footprint in exploration. Prior to 2013, we explored worldwide oil and natural gas. Today, after much work and focus, we are in 5 fewer countries than we were in 13 and far fewer basins, all oil focused. We have lowered our back office expenses for exploration 70% during this time. Operationally, we have made significant changes.
We have 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 three areas, United States, Canada and Malaysia, where we have a 20 year history. The streamlining has led to lower cost and increased exploration focus, which is seen in recent success and a very robust program going forward. While focused, we have 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 you look to 2019, we are planning full year CapEx to be in the range of $1,250,000,000 to $1,450,000,000 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 in 2 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 have 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% an increase in our capital in the Gulf and offshore Canada by 70%, while spending a modest 10% of capital on exploration. The shift in allocation will 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 are allocating capital to our assets that will generate profitable growth and our high margin oil weighted assets. As we look back on 2018 and start of 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.
At that point, I'd like to open up the lines for our questions in our usual formats and we will go with that now. Thank you.
Thank you. Your first question comes from Ryan Todd of Simmons Energy. Please go ahead.
Good morning, Ron. Go ahead. Good to hear from you.
Hey, 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've got 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 at Duvernay? And 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'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 all of 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 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 for 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 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 cost there and we have a very good nice early start. So that project is working for us and so we have 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'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.
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 really changed our capital allocation quite a bit. This is what came about through the years. Things change and that's where we are going forward with that, if that answers your question, Ron.
Thanks. 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 quite a few assets, quite a few pans in the fire as you look forward over the next few years.
There have been rumors about potential sale of additional interest in Malaysia. Are you happy with the current portfolio mix? Would you consider further disposals? And as you think about your the excess cash you're generating and or proceeds, how would you think about the effectiveness of additional acquisitions? And would it be is it more interesting to acquire undervalued free cash flow generating assets like the Petrobras deal or onshore in the story?
Well, 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. But we do not comment on rumors on big major transactions that show up in some new service. I mean, as you know, looking back and knowing Murphy for a long time, Ryan, we rarely get out ahead of ourselves on business development, things of 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 are very used to working there and understand that asset. But we will 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. So we go through every day. We are 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 rumored 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.
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 $60,000,000 and then as it came to fruition through all the work and 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 ks, we do a lot of our 75% of our fields are audited by 3rd party every year. We have a very, very close tie to that, 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 doing very well and quite happy with it and just real pleased with the overall process. Everything's going well there, Brian.
Okay, great. And then you talked just to I think Ryan's question on the trade off between investing in Canada versus in the Eagle Ford and the in your case for 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 shareholders? How do you look at the decision to the 40% increase versus some greater increase or lesser increase?
Well, one thing, we are one of the leaders in returning to shareholders. I mean 14% of cash flow year after year at a time 17%. So I take the high 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 are doing a lot of good work in the asset and this we need to get a more consistent delivery of our wells and we are 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 the cost down, stay with improvements, lower operating expenses and we are setting this thing up to be quite a big cash flow player in the next few years. And this time we will probably be at a below strip number and slightly positive, not a big amount we had this year. But 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 big tax advantage in the U. S. For us.
So that's the reason we are just jump starting it and getting this thing back to a level that we were before and we have really good situation there. And it just has been 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 cost. We have a history of executing in North America. We run this as one team.
So it needed capital that time for that reason pulling back from the Eagle Ford and as soon as I saw that I could keep all the land and have lower prices there. I have reverted and put my capital change 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 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 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 looks like it's kind of flattened in the last couple of years that's seen on slide at the bottom left of slide 15. Would that be 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 and the Catarina area is working very well for us. It's very low cost. We are 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.
But we also I think the main thing for us and the focus for us in Eagle Ford is, we are 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 are quite proud of. But we are really focusing on a new operating model for how we operate the field remotely with data operate by exception. We are really into driving OpEx is our big focus there at this time.
Thank you.
Thank you.
Your next question comes from John Herrlin of Sidoti NRL. Please go ahead.
Yes. Hi, Roger. When you mentioned Hey, John. Good morning.
I'm sorry. I'm
sorry. Hello?
Yes, go ahead. Okay. I'm 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 at Murphy. It was around $112,000,000 project. We were able
to finance
that through the provider of that service, Schlumberger Cameron combo there and went very, very well. And 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 subsea pump 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 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 were, I don't know exactly, probably increased 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 20 3 mile umbilical power cord, if you will. And we are looking at that at Samurai. We are looking at it at the MP Dom.
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 are 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. 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 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 from my taste of like a little larger that we are going to be drilling at Hauppauk Park 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.
But where we were in the structure would not work as probably could have suspended the well and looked at it longer. But I went ahead and do not believe we are going to focus our personnel and capital going forward there. But 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. And we are just one of those things. I think the key thing in this business today, what I say in my remarks today, it's a small amount of capital, if you will, for exploration.
You get a lot of money, you 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's greatly reviewed by peers in the Gulf for only 50,000,000 dollars 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. And this well is I think Murphy has drilled 2 of the fastest wells ever drilled in the Gulf on the original TD of Samurai and the TD of this well.
So 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 and 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's why we are so glad we didn't leave it is that you can get so much opportunity for a small amount of capital compared to 2013. Great. Thanks, Roger. Thank you.
Your next question comes from Paul Sankey of Mizuho. Please go ahead.
Good morning, Roger.
Good morning, Paul.
Yes. 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 with the 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? Thanks.
Well, that's a difficult question. We all know that we are 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 would probably be able to do that as well above the free cash flow that this plan will deliver. We are 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 in 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 are able to accomplish that with this plan.
Very happy about the capital in Canada, we will not be increasing there. And I am not going to say what we are 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. But the equipment to fix those are 9 to 10 months away.
So that would be my go to thing first, but we are at all costs trying to avoid doing that, Paul.
Understood, Roger. Thank you. And then the follow-up is, you're historically, you've been very levered 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 bit surprised that the numbers weren't quite as high as we might expect.
Yes. That's very that's one of the few surprises in this. I mean, I knew about this. What's going to happen with these new assets, if you take a Saint Malo asset which is incredible, it has a below $2 OpEx there. So it's just absolutely phenomenal in deepwater.
A big Kakai field in Malaysia is around 5 or 6. So there 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 is a pretty big tariff on those lines compared to some of our mid deepwater Gulf that we are used to operating. And so there has been a pullback in the realization there.
Also some unique things, this Cascade Chinook is an FPSO where crude is offloaded and traded into Mobile had some loadings in December, which we all know was 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 through for GAAP. So I think the issue for us is we are 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 a trade off. And also in Murphy, as we disclose prices, our realized prices has transportation in. And if you look, as you know, Paul, following the company for decades now, we don't have transportation on the side. So the realized price has the transportation in, I think we need to back that out be quite good. But that's what's going on with the Gulf.
And 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 Mohammed Ghulam of Raymond James. Please go ahead.
Thanks for taking the question guys. So following up on one of the recent questions, just to confirm, if we were to let's say crude, see crude bounce back to late 2018 highs, the 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 Q1. 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 and etcetera. All that's going forward and we are looking to go in there pretty quick and I have seen no pullback. It's no different than operating anywhere else in the ocean where we work all over the world and we are happy with it.
And there is going to be a 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, sub salt 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 am concerned.
Okay. Understood. Thank you.
Thank you.
Your next question comes from Paul Cheng of Barclays. Please go ahead.
Hey guys. Good morning, Paul. How are
you doing?
Good. Very good. Thank you. Several quick questions on I have to apologize. First, I came in a little bit late.
So if you already answered it, just let me know. I will check transcript. For Eagle Ford, should we assume that with the increase in CapEx, you will be able to reach maybe somewhere in the pet toll, say, 65,000 barrels per day, couple of years down the road. And if you do, once you get there, to sub sustain it, how many rig programs 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 that some have been disclosed before. So we have got plenty of years of running room. In our current plan, we are not disclosing a long range plan today as you see. We are 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 ability to get into the 100s.
Probably going to be running 3 rigs this year on an average. We have 4 today, 3 next year and then we will get into the 5 rig game even at these prices. And 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 are that's why we did the Gulf of Mexico deal. That's why we are very proud of our Eagle Ford.
The Eagle Ford is going to have a long way to go on EOR type opportunities, refrac opportunities, technology where spear being continuing with improvements there and We have the Army there to fight the war and we are going to continue on doing that. It's a big asset for us and very valuable one and we have the ability to do a lot of things with this asset. And our Gulf business being a solid 50 ks plus, 55 plus business too for several years as well.
And in K Pop and Dofuri, 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 that 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 4th quarter.
And so 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 are going into the 12%, 13% range this year And then into probably 2020 getting into the 17% range. And this is for Duvernay and Placid combined. And also 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. And then it's going to be a lot of questions around capital allocation between all the land will be retained, some of the development 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 and 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 100 of 550,000 to 650,000 gross EUR wells.
We feel we are absolutely going to achieve our $6,500,000 cost there and these wells are profitable. And we built this from scratch and 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 on other things and LNG leaving and those kind of things, Paul, is driving us to temporary pullback. That's what we are so proud of. We have multi things to invest in our company.
We are very rarely find Murphy all eggs in one basket, all eggs in one kind of service, one kind of pipe and now we are 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're able to do that.
Now that we protect all day.
Flexibility is good. Yes. Montney, what's the CapEx maybe I missed it. What's the CapEx that we expect in Montney?
We're this year going to spend a little more than last year. I think the CapEx is 55,000,000 dollars If you want to think about it in maintenance CapEx, the production is anticipated to be flat and we have $55,000,000 in all of the tougher assets. But $10,000,000 of that is or more is on field development. There is a big water project working on to lower our costs long term there. And so really only about $35,000,000 on D and C from a maintenance perspective.
And also we had free cash flow in the Montney in 2018, also it's a key we need to
point out as well. Right. And Roger, maybe I get confused, but I thought maybe a year ago that we were talking about maybe want to expand and increase it. So is that trend currently is put on the back burner because of the limitation on the infrastructure that you're just going to get it through?
No, we haven't I am 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. So we have a plant being built and we have all the wells and all the reserves we would ever need there. We were going to increase this to around 3 probably in 2021 of right now the current plan probably $330,000,000 and then $450,000,000 to $475,000,000 a day in 'twenty and 'twenty two kind of a thing.
But the real thing for people to understand again about Murphy and our flexibility in our portfolio is that, if we stop drilling in the Montney and never drilled another well to 2021, we can avoid $400,000,000 of CapEx and only pay $60,000,000 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 infection price on. All we need is just a small improvement. As a matter of fact, the prices in forward curve, they will allow breakeven drilling or we wouldn't be drilling at all. So this idea that we have to expand and have to spend on those capital is not true and that we have the flexibility to stop things and have 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.
That's how we're thinking about that.
Thank you. And on a going forward basis on Gulf of Mexico with your expanded footprint, what is the exploration program target going forward? It will be annually that you expect to drill, what, 5 wells, 6 wells? Or is there any kind of
No, I mean, this year if you break out our exploration expenses around $108,000,000 last year it was $138,000,000 but that's everything. That's G and G of around 20 dollars Our other operating our other exploration expenses would be personnel and what it costs to be an explorer of around $28,000,000 or so. So for $50,000,000 or $60,000,000 if the rig rates stay where they are, we will probably drill as we do this year 4 to 5 wells a year. I would like to get 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 want to get to this year we are drilling 2 wells, 1 in Mexico, 1 in the Gulf of Mexico, we would be at that range or 3 every year would be the goal and 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.
So I would like to see the Gulf of Mexico in a 3 well per year game at 50% to 35% working interest sort of thing. And under current cost, you can go a long way with that, Paul.
And finally, that on just a clarification. You say, Mexico going forward, you expect price realization on the WTI. So is that based on the LOS WTI spread at the current level at the $7 or so or you're based on a more maybe narrower on a normal line, say, dollars 4 or $5
Well, there's a lot going on. As you know, Paul, LLS is becoming less traded, 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 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 of a design for U.
S. Gulf Coast This thing's 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 say that 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 would say that's in our plan, we are upgrading from that today.
Okay. Thank you. Thank you, Paul.
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 with some good dialogue. We appreciate it. We're heading back to work now and wish everyone a good day and 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.