Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2018 Earnings Conference Call. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Good morning, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer and new to the Murphy team, David Looney, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we have posted on the Investor Relations section of our website as you follow along with our webcast today. 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 thanks for listening to our call today. 1st quarter production was 100 and 68,000 barrel equivalents per day at the high end of our guidance at 58% liquids. We achieved adjusted income of 40,000,000 dollars our highest level in 12 quarters. Capital expenditures for the Q1 was $300,000,000 Our program for 2018 is front end loaded with majority of capital in the Q1 allocated to drilling activity in our North American unconventional plays.
We expect to spend about $55,000,000 of our 2018 capital for 2018 and the first half of the year. Our diverse oil weighted asset base primarily at Brent and Malaysia Crude Oil's selling price which is a premium to Brent and LLS delivers high margins generating a very competitive Q1 EBITDAX of approximately $27 per barrel equipment. Murphy has always been focused on returning cash to our shareholders through our 50 year dividend policy. In the Q1, we returned 16% of our operating cash flow to shareholders. We're creating long term value low cost entries that have no well commitments, the lowest cost for drilling we've seen in decades.
Since we're operating plays that are not pipeline constrained and our production has minimal pricing exposure to WTI, Our diversified oil weighted portfolio oversees premium pricing. In the Q1, our weighted average price is over $63 per barrel for oil sold with oil comprising 52% of our sales, the small volume VINGLs comprising 6%. This represents a 24% increase over full year 2017 weighted average price. Our Brent barrels are now receiving a $7 premium to WTI and our LLS weighted barrels are near $4 premium to WTI, a very strong position for us. Our unique strong netback price position coupled with tough quartile cost structure allowed us to achieve an EBITDA per BOE of near $22 a barrel for 2017, which is number 1 in our TSR peer group.
Building on this, our Q1 2018 EBITDA per BOE was nearly $25 a barrel. Our differential spread is significant advantage for us and we expect this to last for the remainder of the year as differentials from WTI to Brent are expected to remain wide. We also see high LLS differentials with our easy access to the Gulf Coast from our Eagle Ford Shale position. Because of our strong production performance in the Q1, we've increased the low end of our guidance range by 1,000 barrel equivalent per day for 2018 with full year production guidance now at 167,000 to 170,000 BOEs per day. Our production levels are stable and we'll be maintaining our strong Q1 production levels into the 2nd quarter.
We've increased our annual CapEx guidance by $55,000,000 take into account a non budgeted well work at our high margin Medusa field, solidifying our exploration program with increased working interest in 2 exploration wells and bringing 7 additional wells online in the Eagle Ford Shale. We're able to reallocate $21,000,000 of capital from our Tupper Montney asset to our Eagle Ford asset with Tupper Montney production guidance unchanged due to continued very strong performance on all fronts in that asset. I'd now like to introduce our new Chief Financial Officer, David Looney for his maiden voyage this morning. David, I'll turn it on to you to discuss our financials.
Thank you, Roger, and good morning to everyone. Consolidated results in the first quarter of 2018 included income from continuing operations of $169,000,000 or $0.97 per diluted share compared to $57,000,000 or $0.33 per diluted share in the same quarter 1 year ago. Our adjusted net income was a profit of $40,000,000 or $0.23 per diluted share in the Q1 of 2018 versus a loss of $10,000,000 in the comparable quarter last year. The adjusted income varies from our net income primarily due to a $120,000,000 credit associated with the clarification
of the
2017 U. S. Tax reform along with foreign exchange gains of $12,000,000 and an $11,000,000 mark to market loss on
open crude oil hedge contracts.
At March 31, 2018, Murphy's total debt amounted to $2,900,000,000 including capital leases or 38% of total capital employed, while net debt amounted to slightly less than 30% of capital employed at $1,900,000,000 As of March 31, 2018, we had no outstanding borrowings under our 1 point Worldwide cash and invested cash balances totaled $40,000,000 at quarter end. I will now walk through some of the nuances of our Q1 results. Operating expenses for the Q1 were up over full year 2017 due to workover expenses at Kodiak and additional expenses associated with offset frac impacts in the Eagle Ford Shale. Looking ahead, scheduled routine maintenance at several of our offshore facilities are expected to drive company wide LOE per BOE slightly higher in the 2nd and third quarters of this year, offsetting the solid progress that is being made in our onshore plays with respect to LOE. However, we still expect full year 2018 LOE per BOE to be in our usual range of $8 to $9 per BOE.
And notwithstanding the impacts of these maintenance projects, due to our excellent crude netbacks, these offshore properties are still some of the highest margin properties in our portfolio and a major reason why we are once again able to record EBITDA per BOE at the top of our TSR group as Roger has already mentioned. The $120,000,000 net income benefit in the deferred tax provision was partially offset by a provision for current taxes in both Malaysia and a small one in Canada. Additionally, a one time withholding tax payment of $35,000,000 in Canada due to the repatriation of $700,000,000 to the U. S. Had the effect of lowering our cash flow for the quarter, which came in at $278,000,000 even after this one time payment.
Roger will now present a review of the company's operations.
Thank you, David. We're on Slide 9. During the quarter we brought 6 wells online in Eagle Ford Shale all of which in the lower Eagle Ford Shale wells in Tilden area. These wells are completed using our Gen 5 completion technique which resulted in significantly higher IP30 than previous wells in that area. For the remainder of 2018, we plan to bring on additional 39 operated wells, which includes 7 more Catarina wells than originally guided.
Our drilling performance has dramatically improved since 2012. We have lowered our drilling cost per foot by approximately 50% to $115 increased our penetration rate over 135 percent to almost 1800 feet a day, driven in this play. These improvements have led to structural cost reduction we've been able to maintain even with upward pressure and service costs. For example, the 2017 cost per foot was approximately $117 while our Q1 2018 drilling costs were below that at $115 per foot. Slide 10, our Tupper Montney continues to prove itself to be one of the lowest cost dry natural gas plays in North America.
During the quarter, we drilled the remaining 3 wells of 5 well pad with 4 consecutive pace set of wells. The best well achieved a drilling cost of $83 per foot just over 12 days at a measured depth of over 17,500 feet. All five wells with an average EUR of approximately 18 Bcf we brought online in the Q2. Murphy's Marketing Group continues to do an outstanding job moving our natural gas off of AECO market pricing. In the Q1, our netbacks and tougher monthly including transportation were CAD2.20 per Mcf well ahead of spot prices.
We continue to have competitive returns in this play with our full cycle breakeven price now approximately CAD1.90 AECO per MCI. These strong price realizations are due to a combination of gaining physical access to West Coast through Malin, to the Midwest through Chicago and Emerson and to the East Coast through Dawn as well as our current long term hedge strategy. This means that 60% of our planned 2018 production will not be exposed to spot or unhedged AECO pricing. We continue to progress our feet at the Tupper Expansion project with an investment decision expected during the Q2. We expect this particular project to have better cost structure and our current tougher assets with breakeven prices approaching CAD1.75 per Mcf.
On slide 11 on the Kaybob Duvernay area, the Kaybob Duvernay asset will increase production 92% in the Q1 of last year while Kaybob Duvernay and Placid Montney combined production grew by 137%. More importantly, the royalty for this asset which sets it apart from other North American unconventional plays was approximately 7% for the Q1. In the Q1, we drilled 12 appraisal wells with 4 pacesetters, brought 8 wells online including our first wells in the Simeonette, Saxon and Kaybob East areas. We continue to see high production rates well above our initial expectations upon entry in 2016. We had wells in 3 different areas flow with IP30 rates at or above 1,000 barrel equivalents per day.
Our early production rates in the new section area are exceeding 2,000 barrel equivalents per day. Since ending the Duvernay in 2016, we've lowered our drilling and completion costs by 25% and costs are now proven to be competitive with costs in Eagle Ford Shale on a per foot basis. Our PACE Settle wells in Duvernay now have a drilling cost between 110 dollars $150 per foot and completion costs between $600 $700 per completed lateral. These levels compare to current drilling and completion costs in Eagle Ford JL just mentioned. Our vision of achieving $6,500,000 per well is now in sight and we have recently broken the $8,000,000 total cost threshold.
As we move into development mode, we continue to build our infrastructure in order to ensure market access. In the Q1, we constructed nearly 50 miles of pipelines in that region. Slide 12, 2018 we drill a minimum 17 wells and bring 23 wells online as per original plan. Our development activity will be concentrated in the already de risked Kaybop West area and we will continue to appraise the other areas of the play. Our drilling activity at Semonet during the Q1 allowed us to derisk approximately 60% of that area and in Kaybob East we're able to derisk another 40%.
We're able to execute on our 2018 plan including accelerating a number of wells in the Q1 due to readily available services, labor and takeaway capacity to work in that region. Slide 13, in offshore business. Gulf of Mexico we carried out a work over at our Reducer field during the Q1 production resumed at our non operated Kodiak well and our Habanero field during the quarter as well. We're seeing strong rates at both especially at Kodiak which is now producing at a gross rate of over 22,000 barrels equivalent per day. Our Malaysia assets continue to be stable cash flow generating business delivering approximately $105,000,000 of free cash this quarter.
Our Teekay DTU gas project which will offset the natural decline of this 10 year old plus field is now approximately 80% complete and we expect to bring it online in the Q3. Our Block H ROTON FLNG project also remains on track with first production expected in 2020. Vietnam, we continue to progress the field development plan for LDV field and we expect to declare commerciality in the second half of this year. Slide 14 in exploration, the Gulf of Mexico we recently spud our Samurai appraisal well which will test our previous Samurai discovery in a new middle Miocene objective. Working interest in Splunk has increased from 35% to 50% with the new partner in BHP, the largest data holder and most experienced company in the play as our sole partner.
The continued low service cost environment for offshore project means we're able to access approximately 75,000,000 of barrels on a gross basis with an upside of some 200,000,000 barrels for net well cost to Murphy of only $30,000,000 Also in the Gulf of Mexico, we were the high bidder with partner in 2 blocks from lease sale 250. In addition, we formed into the High Garden prospect, which is a Miocene amplitude supported three way structure against salt. We're joining a group of successful exploration companies as operator of this block. In Brazil, our co venture group was a high bidder in 2 blocks with Sergipe Alagosa spacing adjacent to our existing acreage in that play. Vietnam are progressing approvals to become the 40% operator of Block fifteen-one and increase our working interest as mentioned.
This acreage additions fits within our focused exploration strategy of pursuing lower risk, low cost with appropriate work and interest opportunity. On slide 15, for the remainder of the year we will be drilling an additional 3 exploration wells. These fit well into our focused exploration strategy and expose us to approximately 125,000,000 net barrels equivalent and resource for less than $50,000,000 net in well costs. Success at any one of these wells will be meaningful to our company. Now moving to slide 17.
Our shareholder focused strategy provides long term oil weighted measured production growth within cash flow. The 5 year plan also returns over $800,000,000 of cash to shareholders with our current dividend policy. Production from diversified portfolio receives premium pricing generating cash flow of more than $500,000,000 after paying our dividend. Our current plan which is conservative price deck compared to today's prices delivers a full year production CAGR of approximately 10% leading to a strong full year EBITDA CAGR of approximately 15%. Looking ahead just 2 years, we expect to generate over $1,800,000,000 of EBITDA in 2020 with an assumed WTI price of $57 with over $9,000,000,000 of cumulative EBITDA generated over the course of this plan.
Finishing off with takeaways on slide 18 today. We're off to a good start in 2018. We continue to hit our production targets while maintaining disciplined approach to capital allocation. A diverse oil weighted portfolio helps us achieve high cash margins, which drives strong EBITDA for our company. We remain focused on reducing costs across our business, returning cash to our shareholders through our dividend policy.
We're also implementing a new exploration strategy at a great time. Our prudent management and financial resilience has us well positioned to achieve these goals we've laid out in our multiyear plan and to continue creating value for our shareholders. With that, that's end of our prepared remarks today and we open up for our questions. Thank you.
Your first question is from Brian Singer from Goldman Sachs. Brian, please go ahead.
Thank you. Good morning.
Good morning, Brian.
Wanted to pick up on the exploration points that you made here as certainly with the costs that have come down in the offshore, it's very, very unique. Can you talk about the cycle times for the type of prospects that you're planning to drill? And if you are successful in the Gulf of Mexico, Mexico and Vietnam, what are the next steps that we should be
looking out for?
Thank you, Brian. I appreciate that question. Starting off with our Samurai well, we are drilling that well today. We're probably over a third of the way finished with the well. We expect that well to TD in mid June.
And for a $30,000,000 net well cost to us, it's really nice net mean barrels and very nice metrics on a barrel dollar per barrel basis. So what happened there, our partner is very successful in this play and the upside of this is will this be into a larger structure in that region and a real big successful upside would put that into a pretty large development. If not and we are back to the main barrels, there's a lot of infrastructure by including our own front runner which would put this thing probably in production in 2 years tops. If it gets into a larger production probably 3.5 year type basis. But there's a lot of infrastructure there, a lot of facilities there.
There's also another party that's now our partner in other wells that have a success nearby that are also in the development mode. So lots of opportunity for smaller development and of course opportunity for a big discovery here It will take slightly more time. This is pretty fast cycle time actually even on a bigger project of 3 years I feel comfortable with that. If you look at King Cake, that's where we moved to and spud in the Q3. We expect to be finished that well around mid September.
Again, this is a smaller size opportunity, but very, very economic, fitting all of the measures we're looking for F and D, the $15 a barrel, full cycle 30% returns at the share at the price that we use. And that too again would be a typical tieback opportunity in the Gulf would be 18 months to 2 years to resolve as well. Mexico is a big well for us and an incredible structure, one of the best looking structures I've seen in a long time. And the Gulf of Mexico has many positive seen attributes similar to our Gulf side. It will not spud until probably December of this year and we will have results of that in March 2019.
This too is an opportunity to be a very, very big project. There we will be starting over and probably looking again at the 3, 4 year time range on something of that size. And the infrastructure is coming in with the Talos discovery to our Southwest there which is southeast rather, I am sorry. So new days there in a new area without the infrastructure we have at King Cake and Samurai, of course. At Vietnam, this is a very simple well we're drilling in the 3rd quarter.
As you know, we have a development in Vietnam in the LDV area which would probably be close to 80,000,000 to 100,000,000 barrel development when we get that sanctioned later on and probably early 2019 now. And this is enormous upside of an area of a draped sand fractured sand on top of granite play there that's very seen, very visible. It will have a really big upside that has never seen a water level. And these 2 are probably this whole area, there many, many discoveries in this area seen by the map in our call today. These are developed with small for tile platforms, very similar to what we do in Sarawak, Malaysia, which is why we brought in by PetroVietnam.
And this thing, they have active FPSOs and active FPSOs and much infrastructure. They're very similar to the Gulf, very similar to our SARE WACC, which you could put those online probably in 2 year timeframes. They're a little longer than the Gulf of Mexico. So that's a run through of it, if that answers your question.
That's really helpful. My follow-up is with regards to the Eagle Ford. Can you talk to A, the production trajectory? I know there were some timing issues associated with wells that were temporarily off, but just how the production trajectory looks through the year. And then also, are there limitations either in terms of acreage scope or scale to increasing activity there?
Or is that something that you would consider?
Yes. Our Eagle Ford business is going to we've been touting this as a flattish production profile now for some time. We are probably I believe David $135,000,000 of free cash in there this year at least at very conservative prices, probably around $4 less than we see in the Strip today. So I would anticipate that the Eagle Ford business will be a $44,000 $45,000 kind of business for us for the rest of the year. Just got off to a and the point of that is that I viewed this very closely in Houston a couple of weeks ago.
This is a very unique circumstance that happened to us. In Catarina, if you could picture an L shaped acreage that we had there and we had 9 of the best wells we've ever had there. And our nearby operator, Chesapeake, great company came in next to us and paralleled 4 of our best wells and went toe to toe with 5 of our best wells and it's caused a big impact to our production that we had to recover from. Drill out sand and our wells produced a high level of water and impacted our OpEx in Eagle Ford. Now we have those wells recovered.
And on the other end of the spectrum in Collins County, BHP went in next door, our partner in Samurai and killed our best Austin Chalk wells, they are some of the best wells in the play and did not produce the wells causing us to take the water off. So it's a real perfect storm of forest there that knocked us back in the Q1 quite frankly. And now our capital allocation there is about the same as we have, but we did note today that we moved $21,000,000 from the Montney because the wells are so prolific in the Montney and we moved money from Canada down to that asset and adding 7 wells primarily weighted toward late quarter 2 and quarter 3. And we have a certain cap allocation, Brian, that we had and we discussed that a lot in the Q1 And we're pretty much fixed there with what we have right now because we're trying to honor our capital commitments and the capital we increased today was for a well at Medusa. It's really a regulatory well that was required for us to do, but also we had a workover option, which we have a very nice well there to produce that we flow just a limited number of days.
And then the rest is taking all of our exploration and getting the latest information and fixing our partnerships. So without continuing to add capital at this time we are probably unlikely to add a lot into Eagle Ford Shale. Of course it's a big go to place for us to do so. On the other side, our Duvernay shale is doing very well. We have commitments to spend capital there which we are proud of and a cash carry arrangement we had at the bottom of the market.
All these wells are doing extremely well for us, probably earlier than we thought originally by far and our costs are greatly coming down. We're drilling these wells as I previously mentioned at the same cost per foot that we have in Eagle Ford. So we have a lot of good things going for us in our unconventional business and offshore business as well, because we have a lot of work to do there as well. But not trying to get over the cash flow CapEx parity too much here, Brian, post the dividend, if you follow me.
Thank you very much. Appreciate it.
Thank you.
Thank you. Your next question is from Aaron Jaram from JPMorgan.
Roger, I was wondering if you could comment a little bit as you get more active on the exploration front. How do you assess data, your interpretation, your team as you progress on this next set of exploration versus where you had a couple of 2, 3 years ago?
Well, we have a lot of things changed in our company. If you really look back and look at our slides that we published today about our new strategy, it's a totally different strategy and the number one part of it is focusing just in 4 places. In the Gulf of Mexico we have 2 things going on. We formed an exploration alliance with a privately held exploration company that has about an 80% success rate on amplitude tiebacks, smaller opportunities. We've expanded that into a certain acreage area, let's call it divide the Gulf between Lake Charles, Louisiana and Tampa and you take the bottom half and we work with them there and then our teams concentrated with data sets up in the Mississippi Canyon area, all focusing on middle of the high seen tiebacks and larger below salt type prospect as well.
So that's a new change. We are working with another party that has enormous access to seismic which they deliver prospects to us and they do not operate and we're going to be their operator. There's been some very, very successful firms that do this in Houston and we are an operator of choice and a preferred partner to do that due to our long term history of drilling and executing and producing globally in deepwater for a long time. So that's how we are tackling on that front. The seismic data in Mexico, again when we look at going into these plays, what's changed in exploration this time post the oil boom is that there's an enormous amount of data that you can purchase very inexpensively.
Mexico, In the past you were leasing acreage on 2 d data with a commitment to shoot 3 d data and making well commitments without 3 d data. This is taking place all over the world and probably led to some exploration misses by not only Murphy but others. So we go into that that block now with 3 d data that's vintage 3 d but 3 d and now every shot and have better process 3 d and the prospects are looking better and better and bigger and bigger. Some of the best tie back to the purchase seismic we've had probably in Murphy history here. So that has great data sets, a lot of great data shot during the collapse in Mexico.
In Vietnam, this is a draped structure, a different type of the total plates, probably closest thing to shale offshore which you can have more of a granite wash play which has been very successful in the region with the fractured sandstone on top which is a new play that we have had a lot of success in. So that's a different type of data. And then in Australia, we have total coverage of all of our basins in great three d data. We actually were instrumental in reshooting seismic in the Vulcan Basin with our team there to add to a better outcome and also really nice prospects there. So the data there's more data available.
The data is much cheaper than it was. A lot of data was shot in the collapse and the data is now used in entry just 108 degrees from the prior years, if that answers your question.
That's great. And just at Samurai, this is I understand an appraisal well. Can you remind us about the discovery well, what you found there and kind of just set the stage of what we're looking for? It sounds like results will be end by the end of 2Q.
Yes. We discovered with our partnership group at that time, I guess around 8 years ago or so, probably almost 240 feet of pay. There's a series of upper zones called M9, M10, up in the shallower part of the well that was a discovery. And then we drilled through the middle Miocene section and found one of the zones to be tight and one of the main prolific M14 zones of that region was faulted out in that particular well. So after a lot of work on seismic and working with our new partner, we've discovered this zone does exist off that original structures, one of the largest four way structures in Green Canyon was the most sought after block and lease sale years years ago and we are now drilling off structure for the missing M14 and then delineating the zones that we drilled up that were discovery.
And then we will take either both will hit, one will hit and there is also a new zone deeper than this that we have been found in other wells in the region we will be drilling to and have about 3 different choices here to find hydrocarbon in this well.
Great. Final question would be, can you just help us a little bit, Roger, with how the sequential production could play out in the Eagle Ford. I think you're going to have some more Karnes wells in 2Q, but just give us a little sense with some capital allocation coming back to the Eagle Ford, what the quarterly trends could look like in the Eagle Ford?
Kelly is going to go with the well counts for you.
Sure, Arun. So we go we're looking at completing a total of 45 wells that are operated by Murphy. And so in the Q2, there's going to be 22. 10 of those are Catarina, 10 of those are Karnes, and we're going to have 2 Chilton wells. And then in the Q3, we're going to have 4 Chilleden wells.
And in the Q4, we're going to have 13 Catarina wells. And so I think it's important to note that when you look at the well cadence that in the second and the third quarter, about 60% of all the wells that we're going to have are going to come online in those quarters. So I think that kind of drives the production. So first, second and third quarters are fairly steady Eddie, and then that's going to drive our 4th quarter production in the Eagle Ford to be, I think, in the neighborhood of
40,000. 45,000, yes. Okay. Thanks a lot.
Thank you. Appreciate it.
Thank you. Your next question is from Pavel Molchanov from Raymond James. Please go ahead.
Thanks for taking the question, guys. So you guys are part of the consortium that won the Alagoas Basin blocks in Brazil, I think 430 and 573. You do not have any well commitments as I understand. So what given that you're not tied to a particular spending rate, what's kind of the plan for those blocks?
I have, there is no well commitments anywhere in Brazil. There is one well commitment in Mexico, none in the Gulf and one in Vietnam. So really don't have many commitment wells in our company. I have a real good friend, partner in this project that really does want me to talk about a whole lot quite frankly. And so I have a big partner there and we're going to be going through seismic.
There's 3 d seismic being shot there today, a big shoot across all this acreage. We have many prospects there, many prospects near big discoveries there, very close by, very tight geologically and we are very, very pleased to have it, but probably not going to be talking a whole lot about the drilling cadence at this time. But it's a big exploration project that's being executed by ExxonMobil and our partner in Brazil and we are very, very pleased to have it.
Understood. Then in terms of capital allocation, you've talked about your EBITDA targets based on your price stack. If we look at strip pricing, you'll more than cover the full CapEx budget and your current dividend payout. To the extent that you have surplus cash flow beyond that beyond CapEx and the dividend, would you be more inclined to maybe getting the dividend back to where it was before the haircut a couple of years ago? Or would you be more inclined for resuming share buyback?
Well, we didn't issue any at the bottom. So that's why we're not buying any back. So we didn't issue any in 'sixteen. We are the only companies not to do that. I hope people will remember that.
And our dividend policy is a long term policy. It was reduced. I think now naturally we consider and we'll look at harder to go back at some level. I wouldn't see us jumping right back to that level. Of course, I have discussed this with our Board.
It's always a discussion we will have primarily later in the year. I wouldn't see us jump right back to that level, but we have to get back in the net income making business here and our retained earnings account being positively impact by that which are off to a good start making $40,000,000 of adjusted income and a good bit of income in that tax. And while it's adjusted out, we earn that income from that tax and we deserve that net income that we have received on a rolled up basis like we used 2 years ago before we went into adjusting everything there is to mankind. So we need to get back to make sure we are making the net income levels to cover the 100 and something plus dividend that we need to make every year. We're on our way of doing that.
That's the first step. And we clearly have the cash to do it. And they will be studying that and looking forward to these process making that backwardation pull up a little bit before making that call and it's one of our focus times for the rest of the year, sure. All right.
Appreciate the color. Thanks.
Your next question is from Roger Read from Wells Fargo.
Well, we're hitting towards the end of earnings season, so doing a little bit better. But we're
You're right about that, Roger.
Hey, can we come back
to the CapEx rise, roughly $50,000,000 5%. Just curious about the projects that you're going to fund here. Were these projects that were sort of the next ones on the queue when you were laying out your budget in the last year beginning of this? Or are they more projects that have come to the 4 since then? Just trying to understand kind of maybe the ranking of things and maybe your if anything has changed in the returns either because oil prices are up or the projects look better, just kind of a little help there.
The way we do our exploration budget is that we have about 4, 5 opportunities sometimes across the world. We put them in as a factor of all we're going to do those wells like one well maybe chance of doing that at 30%, 40%, 50%, sometimes 100 if it's a commitment well something to that effect. So that gives us so much capital for exploration. Then as the year goes by we solidify that. So Samurai is a very sought after opportunity with a lot of success in that area.
And we and BHP took out one of our partners there. And then we had 4 or 5 companies wanting to take the other piece from the other partner that left. And we then were able to look at some information through our partnership group and make a decision we want to go up on that 50% and that drove a good bit of our CapEx move. And because we do that, we want to be around 35% in exploration. It really is a delineation back to my answer of a prior call of some prior pay that we drilled that area.
So then when we take and pull out the ones we're not going to do, pick the ones we're going to do and increase our working interest on a delineation type well, our capital went up. At Medusa, we had a well had a regulatory problem on a casing pressure issue that had to be abandoned. So we're going to abandon that well, but we have another zone we can re complete into which would be slightly more expensive. And we also didn't have the abandonment in our capital plan. So we went ahead and completed the well and it was flowing at a very, very nice rate with just 2 or 3 days of flow early in this quarter, but the well had to be shut in due to a planned downstream constraint at Medusa is taking place from shale shutting in some platforms in the Eastern Gulf of Mexico has been known about for a long time.
So those are the 2 big drivers of it. And then we added some capital from Montney to Eagle Ford and some additional capital allocation to Eagle Ford due to these problems we had in the Q1 to get our production back to the level we wanted. Also the opportunities are very, very good. So all these wells have high Samurai is an exploration well to produce a well clearly payout and be a very, very nice well. And also in Vietnam, we have an opportunity to increase our working interest there too.
So that's another part of those exploration wells that we then by May or June you say well I'm going to do this, this and this and you round all the capital up and increase the capital to do what you need to do. That's a great opportunity for us to take over as operatorship in that block. It allows us to be operator of the original development that we formed into with PetroVietnam. So all this $50,000,000 is a great value add for our company and positions us really, really well. But it wasn't a list of things, it's more about solidifying exploration and handling a regulatory matter that turned into a good well in the Gulf.
Okay.
Thanks for that. And then just kind of 2 maybe more basic questions. 1, the longer term outlook you laid out, dollars 57 WTI. Are you assuming a similar price for Brent? And then the second question, just service cost trends as you see them across kind of give us what you want, but thinking mostly lower 48 in Gulf of Mexico.
Well, I mean, obviously our prices are used in our LRP, our long range plan, we call it this year way over. And but we do have some hedging in there. Our current plans are below strip. I think we're probably looking at a quarter 2 WTI 64, 63 in the Q3 and 61 in the 4th quarter, conservatism to that bit of backwardation there, probably really good position compared to that. And our Brent, we normally take it about $4 over, but today it's $7 So we are pretty conservative still on that and I think pretty well positioned on that.
And what was your next question Roger? Everybody keeps crying about service costs and we really are rolling along pretty well. I think it's if you look in what I said in the script, it's mind boggling really for our Eagle Ford business as they continue to drill. I mean we know there's we thought there's a 10% chance of cost going up in the Eagle Ford on drilling and probably 10% to 15% on completion. But at the end of the day, the cost per foot of the 18 wells we drilled in the Q1 versus what we had in 2017 is slightly lower.
So we continue to execute there. And we're really well positioned. Our procurement teams and our management team for Eagle Ford have done a great job. We have a one fight company for all of North America now. It's brought us incredible savings with some really, really good rig rates.
There's some rig rates tied to oil prices that's nicely positioned for our company. And we are just not seeing it. And if we do, it might would be around I calculated yesterday that probably around $20,000,000 to $25,000,000 it could go up on completions the rest of the year. But Roger, we can afford it.
Well, that's good to hear. Thank you.
Thank you.
Thank you and see you soon.
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.
Appreciate everyone calling in today and need to get back with our IR team if you have any questions and we look forward to seeing you in the next quarter and thanks for everything. Appreciate
it. Ladies and gentlemen, this concludes your conference call today. We thank you for participating and ask that you please disconnect your lines.