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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
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 a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions]
I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Good morning, 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 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 exists 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 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 fourth 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 fourth quarter, we generated $103 million or $0.59 per share of earnings and on an annual basis we recorded net income of $411 million or $2.36 per share. That’s 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 per BOE of over $20.5 per barrel and EBITDA per average capital employed was notable at 21%.
Through the energy cycles, we maintained our ability to execute deepwater offshore projects with success found in the record-breaking Dalmatian project and in the gas lift solution in Malaysia.
In the 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 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 and now on installed we begin to demonstrate production uplifts. We executed transformational transaction in the Gulf of Mexico, increase our footprint in that region applying its access to world-class assets such as the St. Malo field.
Vietname, we work closely with their national oil company PetroVietnam to negotiate operatorship while increasing our working interest in the Cuu Long Block 15-01area 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 or less than $40 per barrel. In Eagle Ford Shale we decrease the cost per completed lateral foot over 10% while maintaining drilling cost as measured by cost per foot in the face of continued oilfield service cost inflation. The 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, let’s review our 2018 production. I need to keep you in mind that starting in the fourth quarter 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 amount attributable to Murphy unless otherwise noted. In the fourth quarter, we produced 176,000 net equivalent and fourth quarter production was 47% offshore and 53% onshore.
Our reserves slide page six, I am especially proud of our team’s work to replace the net valuable proved reserves in 2018. Our proved reserves increased to 816 million barrels equivalent, a 17% increase from 2017, 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 three-year average F&D cost by 50% since 2014.
I now will turn the call over to our Chief Financial Officer, David Looney for his comments. Thank you.
Thank you, Roger. Consolidated results in 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 know 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 31, 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 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 yearend.
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 longstanding goal of living within cash flow, slide eight 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 usage, 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 and that we had a one month increase in working capital of approximately $170 dollars, which had the effect of lowering our cash flow by 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 generated excess cash flow after dividends of approximately $87 million for that 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, but we remain on track as always to continue to learn, 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 operation.
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. This asset regrew our reserves by 70 million barrels of which oil in the Gulf increased by approximately 150%. Also, we gained the operator 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 well as we are able to achieve a quarterly lease operating expense of below $10 per barrel. Dalmatian currently delivered production of 10,000 barrel equivalent grows, an increase of 250% from the prior quarter. Unique execution example 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 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 the 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 it’s plugged and abandoned. The well which Murphy operated at 35% working interest was drilled 35% below the expected AFE for net cost to Murphy of $16 million.
We are looking forward to our 2019 exploration plan or 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 and on 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 15-01/05 well in the first quarter as well. In the Gulf of Mexico, we plan to spud the [indiscernible] wells 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 bought eight wells online in the Eagle Ford all in Catarina. The IP30 average rage for eight wells is 860 barrels equivalent per day gross. Eagle Ford Shale team has done a good job containing to lower completion cost are holding drilling cost 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 increase our laterals drill.
We continue lower completion cost as our 2018 costs are now approaching those seen in 2015 and the backdrop again of overall cost inflation, but driven by performance improvement, sand-per-foot increases during this timeframe.
That’s 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 are quite proud of.
Slide 16, Tupper continues to deliver oil performance with low operating costs of just over $0.60 per Mcf for all of 2018, even as we continue to expand challenging process, we were able to generate free cash flow in this asset.
Our marketing team continues to mitigate our AYCO spot price exposure to hedges and off AYCO sales for the year, we realized CAD2.39 per Mcf Canadian. In the first quarter of 2019, we have just over 40% of Tupper Montney natural gas price an acre.
Slide 17, in the Kaybob Duvernay we finished off 2018 completing the topline wells in the fourth quarter. At this time we feel that our appraisal of the play is complete. The exception of the two creeks area which is ongoing was 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 the fourth quarter production exceeding 11,000 barrels equivalent per day with 59% liquids. Our lease operating expenses continue to trend down in this way, we 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 are showing some of the outstanding results from our four 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 have come over the last five years. We have greatly reduced our global footprint in exploration. Prior to 2013 we explored worldwide oil and natural gas. Today, after much working focus we are in five fewer countries than we were in 13 and far fewer basins all oil focused. We have lowered our back office expenses to exploration 70% during this time.
Operationally, we have made significant changes. We have divested heavy oil, oil sands in Canada, South Louisiana and Alaska, and become the North American unconventional only player of 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 has seen in recent success and a very robust program going forward. Our focus, we have never lost our competitive advantage of execution seen in our own share 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 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 equivalent per day to 210,000 equivalent per day. We are growing production by approximately 20% from last year with all production growth coming from oil. Both CapEx and production exclude the non-controlling interest and MP GOM.
Our 2019 capital expenditure is really set the foundation for future growth with 64% of our capital at production this year, 15% will drive our production in two years and 12% is for long-term future production growth. First quarter production expect to be in the range of 198,000 barrels equivalent per day to 202,000 barrels equivalent per day.
Slide 22 on our capital allocation. In 2019, we will be shifting our CapEx priorities from last year. This year, our overall budget, we 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 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 about 38% and increasing 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 2023, we feel that we are taking the right step in the right direction positioning the company for true long-term value creation. I am 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 shareholder through continued focus on strategic exploration. We are allocating capital to our assets to generate profitable growth and our high-margin oil-weighted assets.
As we look on 2018 and start 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 format and we will go with that now. Thank you.
Thank you. [Operator Instructions] Your first question comes from Ryan Todd of Simmons Energy. Please go ahead.
Go on, Ryan. Go ahead. Good to hear from you.
Hey. Good morning. Give myself [inaudible]. How are you doing? Thanks for the question. Maybe if you could start out with a question on Canada. Do you take CapEx actually with the maintenance CapEx there as you 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 the question of commodity price and cash flow?
Yes. Strictly, 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 cap allocation. It’s really about that more than about Canada.
We pull 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 oil 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 that same time.
That is -- that commitment has continued to go down and now 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 cap allocation.
We are very happy about the Duvernay and really haven’t drilled a bad well there and you can see in the slide deck today many examples of the wells leading to EUR. We are very excited about this new Two Creeks area because it’s more of a Catarina type of Eagle Ford place back all where we think we can leave all 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 should be let go and we’d be moving more into development mode. We have 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 change our capital allocation quite a bit. This is what came about through the years. Things change and that’s why we are going forward with that, if that answers your question, Ryan.
Thanks. That’s great. It’s helpful. Maybe just a follow-up, as we look at your portfolio. You have been active in both monetizing and acquiring assets in the recent years. You have got quite a view -- quite a few assets, quite a few fans into the fire as we look further over the next few years. There have been rumors about potential sales, additional interest in Malaysia. Are you happy with the current portfolio mix, would you consider further disposals and as you think about the excess cash you are generating 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 assets like the Petrobras deal or onshore inventory?
Well, we have been very active in business development which shows we will move off of things aggressively during my time here. I am 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 have ourselves on business development, things of that nature. You kind of read about it in the paper, things happened.
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 have -- 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 and our company as well by external folks.
So we go through every day. We are key on business development, a real key focus of my time in the company and we will do that, but we can’t really comment on or think about what would happen in the proceeds or rumored type of acquisitions is really not our game plan.
Sure. 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? Are you there?
Oh! Hi, there. Good morning. I am sorry. I have 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 there in the data room at the time that we were looking at around $60 million and then as it’s come into 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 review 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 of that, quite proud of where we are on corporate reserves and our corporate reserves history.
And they insinuated we need to take a closer look at that. We did and made additional reserve booking and the assets are doing very well and quite happy with it and just really pleased with the overall process, everything’s going well there, Brian.
Okay. Great. And then you talked to just I think Ryan’s question on the trade-off between investing in Canada versus in the Eagle Ford, and 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 sort of 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 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 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 Corhn’s [ph] area.
And when you go into these five, six, seven wells a quarter, it’s very difficult to drive your 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 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 jumpstarting it and getting this thing back to a level that we were before and we have a really good situation there.
And in this situation have too much capital though I have gotten to talking to Ryan to about what you got to do that day and if 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 at that time for that reason, pulling back from the Eagle Ford and as soon as I saw that could keep all the land and have lower prices there, I reverted and put my capital changed back into the Eagle Ford.
And the whole basis of MPGOM is to build a free cash flow providing the United States business that is very tax advantaged for us and that’s a part of that transaction -- 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 are 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 been on the slide -- at the bottom left of slide 15. Would that be the lower costs or would it mitigate costs 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 operated by exception and we are really into driving OpEx as our big focus there at this time.
Thank you.
Thank you.
Your next question comes from John Herrlin of Societe Generale. Please go ahead.
Yeah. Hi, Roger. When you mentioned…
Hi, John. Good morning.
I am sorry, Roger. Hello?
Yeah. Go ahead.
Okay. I am 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 from 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, mostly it’s around $112 million project. We were able to finance that through the provider of that service Cameron combo there, and it went very, very well and they are willing to do that more and pay as it works kind of this format is sort of upfront capital.
We know that they are subsea pump not working so well on some of the MP GOM assets that we transacted on. Some that we might could repay or change. This is something that I have been personally after for a long time. These are multi-phase pumps pumping everything if you will and it lowers the system pressure dramatically. It 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 23-mile umbilical power cord if you will. And we are looking it at the Samurai. We are looking at it at the MR GOM.
And I think it can really add a lot of positive that its pure piece to the reservoir, bringing the reservoir pressure down is what it does and allows for reservoirs to be completed further over a very long tieback distance to make tiebacks longer and it’s very helpful and we have about three things we are looking at now and I think it’s going to be a big deal to go and in Brazil and other places in this hemisphere.
Great. And the 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 and due to schedule changes on Samurai was pushed out a little bit. It’s a little bit small from the beginning for my taste of like a little larger that we are going to be drilling at Hawk and some more opportunities.
The amplitude was some type of artifact in the seismic and didn’t turn up. We did start fund about 50 feet of pay in the well for both oil and gas and about where we were in the structure would not work as probably could have suspended the wells 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 are 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 will say in my remarks today is a small amount of capital if you will for exploration get a lot of money, you had a lot of value for exploration today. The idea that we can drill a well offshore Vietnam, brand new wildcat in Mexico and 50% working go to amplitude well that’s greatly reviewed by peers in the Gulf probably $50 million is really incredible.
These rigs the ultra-deep water rigs are similar in nature, the big players have them and we are drilling like hell with these rigs, John and these wells, I think, Murphy’s drilled two of the fastest wells ever drilled in the Gulf, on the original of Samurai and the TD of this well.
So this idea that only improvements are onshore is just an absolute false, 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.
[Operator Instructions] Your next question comes from Paul Sankey of Mizuho. Please go ahead.
Good morning, Roger.
Good morning, Paul. Hope you are well.
Yeah. Hi. Hope you are well and all the best for 2019.
Thank you.
Roger, I am sure you feel like you answered this, but I was wondering your CapEx sensitivity to oil prices and the extent to which you said you will spend with the cash flow, if we could get upside in oil prices relative to expectations and I will 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, it’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 the revolver that we want to pay off at strip prices. Today, we will 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 this than what we have and continue to on with the program we have.
One of the things I have been wanting to do in the last few years you could see 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.
Now we have a more streamlined big approach there to get this asset back kicked off like it needs to be. Now we were 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 nine months to 10 months away, seven being my go-to thing first, but we are -- it all calls trying to avoid doing that.
Understood. Roger, thank you. And then the follow-up is, historically, you have been very levered to Brent, but you have also equally talked this morning about how you’d re-shifted 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 but…
Yeah. That’s being one of the few surprises in there. Somehow I knew about this, what’s going to happen with these new assets. If you take the St. Malo asset which is incredible, it has a below $2 OpEx there. That’s just absolutely phenomenal in deepwater, a big Kakap field in Malaysia is around 5 or 6. So they are opportunities. They are 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 are used to operating and so there’s been a pullback and a realization there. Also some unique things this Kakap is an FPSO where crude is offloaded and traded in Mobil and had some loadings in December, which we all know is not a good time.
And also, in our realized pricing, we 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 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 are making a tradeoff.
And also in Murphy, as we disclosed prices, I realized prices have transportation in and if you look, as you know, Paul, you are following the company for decades now, we don’t have transportation on the side. So the realized price has the transportation in. I think if we to 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 the end of the world with the OpEx to go along with it.
Understood. Thank you very much, Roger.
Yeah. Thank you.
Your next question comes from Muhammed 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, see crude bounced back late 2018 highs, we shouldn’t expect any increase in the capital budget, right?
I will be doing all I can to avoid that.
Okay. I 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 am curious, are you seeing any changes in terms of the relationship with Pemex or in the physical terms?
Well, for Pemex. Pemex is more of a competitor in Mexico which the CNH or the governing 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 are looking to go in there pretty quick.
And I see no pullback. It’s no different than operating anywhere else in the ocean where we work all over the world and grew happy with it and there’s 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.
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 you doing?
Good. Very good. Thank you. Just had a quick question on -- I have to apologize first, I came here 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 -- at close a 65,000 barrel per day a couple years down the road and if you do, once you get there to sustain that how many rig that program that you need and also how long you will be able to sustain based on your resource?
We have long way to go there, Paul, 800 or 1,000 locations that some have been disclosed before. So we got plenty of years of run 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 the ability to get into the hundreds. We are probably going to be running three rigs this year on an average. We have four today, three next year and then we will get into the five-rig game even at these prices and our idea, again, is to build a very strong oil-weighted tax advantage, 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 has got a long way to go on EOR type opportunities, refrac opportunities. Technology, we are experimenting continuing with improvements there.
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 50k-plus, 55-plus business to for several years as well.
And in Kakap and Duvernay the 25% decline, how many well that we intend to compete next year -- this year, I should say?
Hang on one second. Paul, we have that right here. I believe that’s 12 well, 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.
And so with this if we assume that this will be the new [inaudible] 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 to 13 range this year and then into probably 2020 getting it into the 17 range. 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.
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 though would 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 hundreds of 550,000 to 650,000 gross EUR wells. We feel we are absolutely going to achieve our $6.5 million cost there and these wells are profitable and that we built from scratch is going to go well.
But the price -- but Canada has a lot to do and will be a big positive improvement but not till 2020 and beyond due to pipeline constraints on other things and LNG living and those kind of things. Paul’s driving us to a temporary pool that’s what we are so proud of as we have multi-things to invest in our company.
You 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 is decent priced U.S. weighted is the flavor today for us and because of our portfolio, we are able to do that, now that we are protecting all the acreage.
That’s great. Good. Montney, what’s the CapEx, maybe I missed it. What’s that CapEx that we expect in Montney?
We are this year going to spend a little more than last year. I think the CapEx is $55 million. If you think about it in our maintenance CapEx, the projection is expected to be flat and we have $55 million in all of the topper assets. But $10 million of that is -- or more is on field development. There’s the big water project we are working on to lower costs long-term there and so really only about $35 million on D&C from a maintenance perspective and also we had free cash flow on the Montney in 2018 also to -- we need to point out as well.
Right. And what -- Roger, I was get some feels, but I thought maybe a year ago that we were talking about maybe want to expand and increase it. So is that trend currently put on the backburner because of the limitation of the infrastructure that you are just going to get your pool?
No. We are having -- I am glad you asked that question. We have an expansion project we participated in with the company approaches Embridge [ph] recently, I can’t recall their name. But we have a plant being built and we have all the wealth and all the reserves we’d ever need there. We were going to increase this to around 3 -- probably in 2021of -- right now, the current plan probably 330 and then 450 to 475 a day in 2020 and 2022 kind of a thing.
But the real thing for people to understand again about Murphy and our flexibility in our portfolios is that if we start drilling in the Montney never drilled another well to 2021, we can avoid $400 million dollars of CapEx and only pay $60 million in 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 zone, all we need is just a small improvement.
As a matter of fact, the prices in forward curve, they will breakeven drilling we wouldn’t be drilling at all. So this idea that we have to expand and have spin those capital is not true and that we have this flexibility to stop things and high 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 field.
Okay. And in those…
That’s how we are 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? You will be -- finally that you expect to drill, what, five wells, six wells or is there any kind of…
No. I mean, this year, if you break out our exploration expenses around $108 million, last year is $138 million, but that’s everything. That’s G&G of around $20 million. Our other exploration expenses would be personnel and what it cost to be an explorer of around $28 million 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 to Gulf and the two 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 two wells one in Mexico and one in the Gulf of Mexico.
We will be at that range or 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. So I’d like to see the Gulf of Mexico in a three well per year game at 50% to 35% working interest sort of thing, under current cost you can go a long way with that, Paul.
And finally that on -- that just a clarification, do you see Mexico going forward you expect high realization on the WTI. So is that based on the, however, WTI spread what at the current level at $7 or so or you are based on a more maybe narrow on a normal nice $4 or $5.
Well there’s a lot going on as you know our LLS is becoming less traded, lot of pipes built out in the Permian. Their 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 sour crudes some of the same screws in the Gulf such as Moores [ph] and some other things that are more designed for U.S. Gulf Coast that these things gone 6 bucks 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. We all know that there’s too much light or needing more heavier old school Gulf of Mexico based stores into the system. So volatility, that’s in our plan. We are upgrading from that today.
All right. Thank you.
Thank you, Paul.
Excuse me. There are no further questions from our phone line. I would now like to turn the call back over to Roger Jenkins for any closing remarks.
Thanks everyone for calling in today with some good dialogue. We appreciate it. We are 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.