Good morning, ladies and gentlemen. Welcome to the Murphy Oil Corporation first quarter 2018 earnings conference call. If at any time during this call you require assistance, please press star zero for the operator. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Good morning, everyone. 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 sections 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. No assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2017 annual report on Form 10-K on file with the SEC.
Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins.
Thank you, Kelly. Good morning, everyone. Thanks for listening to our call today. First quarter production was 168,000 barrel equivalents per day at the high end of our guidance at 58% liquids. We achieved adjusted income of $40 million, our highest level in 12 quarters. Capital expenditures for first quarter was $300 million. Our program for 2018 is front-end loaded, with majority of capital in the first quarter allocated to drilling activity in our North American unconventional plays. We expect to spend about $55 million of our 2018 capital for 2018 in the first half of the year. Our diverse oil-weighted asset base primarily sets Brent from the Malaysia crude oil selling price, which is a premium to Brent, and LLS delivers high margins, generating a very competitive first quarter EBITDAX of approximately $27 per barrel equivalent.
Murphy has always been focused on returning cash to our shareholders through our 50-year dividend policy. In the first quarter, we returned 16% of our operating cash flow to shareholders. We're creating long-term value by participating in highly economic offshore projects in a counter-cyclical move, returning to focused strategic offshore exploration with low cost entries that have no well commitments at 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 receives premium pricing. In the first quarter, our weighted average price was over $63 per barrel for oil sold, with oil comprising 52% of our sales, with a small volume of NGLs comprising 6%. This represents a 24% increase over full year 2017 weighted average pricing.
Our Brent barrels are now receiving a $7 premium to WTI, and our LLS-weighted barrels are near a $4 premium to WTI. A very strong position for us. Our unique strong netback price position, coupled with top quartile cost structure, allowed us to achieve an EBITDA for BOE of near $22 a barrel for 2017, which is number one in our TSR peer group. Building on this, our first quarter 2018 EBITDA for BOE was nearly $25 a barrel. Our differential spread is a 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 first quarter, 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 167-170,000 BOEs per day. Our production levels are stable, and we'll be maintaining our strong first quarter production levels into the second quarter. We've increased our annual CapEx guidance by $55 million, taking into account a non-budgeted well work at our high margin Medusa field, solidifying our exploration program with increased working interest in two exploration wells and bringing seven additional wells online in the Eagle Ford Shale. We were able to reallocate $21 million 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 Lunney, for his maiden voyage this morning. David, I 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 million, or $0.97 per diluted share, compared to $57 million, or $0.33 per diluted share in the same quarter one year ago. Our adjusted net income was a profit of $40 million, or $0.23 per diluted share in the first quarter of 2018, versus a loss of $10 million in the comparable quarter last year. The adjusted income varies from our net income, primarily due to a $120 million credit associated with a clarification of the 2017 U.S. tax reform, along with foreign exchange gains of $12 million and an $11 million mark-to-market loss on open crude oil hedge contracts. At March 31st, 2018, Murphy's total debt amounted to $2.9 billion, including capital leases, or 38% of total capital employed.
While net debt amounted to slightly less than 30% of capital employed at $1.9 billion. As of March 31st, 2018, we had no outstanding borrowings under our $1.1 billion revolving credit facility. Worldwide cash and invested cash balances totaled $40 million at quarter end. I will now walk through some of the nuances of our first quarter results. Operating expenses for the first quarter were up over full year 2017 due to workover expenses at Kodiak and additional expenses associated with offset frac impacts into 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 second and third quarters of this year, offsetting the solid progress that is being made in our onshore plays with respect to LOE.
We still expect full year 2018 LOE per BOE to be in our usual range of $8-$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 million net income benefit in deferred tax provision was partially offset by a provision for current taxes in both Malaysia and a small one in Canada. A one-time withholding tax payment of $35 million in Canada due to the repatriation of $700 million to the U.S. had the effect of lowering our cash flow for the quarter, which came in at $278 million even after this one-time payment.
Roger will now present a review of the company's operations.
Thank you, David. We're on slide nine. During the quarter, we brought six 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 results in significantly higher IP30 rates than previous wells in that area. For the remainder of 2018, we plan to bring on additional 39 operated wells, which includes seven 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, and increased our penetration rate by over 135% to almost 1,800 feet a day drilling in this play. These improvements have led to structural cost reductions 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 first quarter 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 three wells of a five-well pad with four consecutive pace setter wells. The best well achieved a drilling cost of $83 per foot in just over 12 days at a measured depth of over 17,500 feet. All five wells with an average EUR of approximately 18 Bcf were brought online in the second quarter. Murphy's marketing group continues to do an outstanding job moving our natural gas off of AECO market pricing. In the first quarter, our netbacks in Tupper Montney, including transportation, were CAD 2.20 AECO per Mcf, well ahead of spot prices.
We continue to have competitive returns in this play with our full cycle breakeven price now approximately CAD 1.90 AECO per Mcf. These strong price realizations are due to a combination of gaining physical access to West Coast through Milan, 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 feed at the Tupper expansion project with an investment decision expected during the second quarter. We expect this particular project to have better cost structure than our current Tupper assets, with breakeven prices approaching CAD 1.75 AECO per Mcf. On slide 11, on the Kaybob Duvernay area.
The Kaybob Duvernay asset will increase production 92% from the first quarter 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 first quarter. During the first quarter, we drilled 12 appraisal wells with four pace setters, brought eight wells online, including our first wells in the Seminat, 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 three different areas flow with IP30 rates at or above 1,000 barrel equivalents per day. Our early production rates in the new Saxon area are exceeding 2,000 barrel equivalents per day.
Since entering into Duvernay in 2016, we've lowered our drilling and completion costs by 25%. Costs are now proven to be competitive with costs in Eagle Ford Shale on a per foot basis. Our pace setter wells in Duvernay now have a drilling cost between $110 and $150 per foot and completion costs between $600 and $700 per completed lateral. These levels compare to current drilling and completion costs in Eagle Ford Shale just mentioned. Our vision of achieving $6.5 million per well is now in sight, and we have recently broken the $8 million total cost threshold. As we move into development mode, we continue to build our infrastructure in order to ensure market access. In the first quarter, we constructed nearly 50 mi of pipelines in that region. Slide 12. In 2018, we drill a minimum of 17 wells and bring 23 wells online as per original plan.
Our development activity will be concentrated in the already de-risked Kaybob West area, and we will continue to appraise the other areas of the play. Our drilling activity at Seminat during the first quarter allowed us to de-risk approximately 60% of that area. At Kaybob East, we were able to de-risk another 40%. We're able to execute on our 2018 plan, including accelerating a number of wells in the first quarter, due to the readily available services, labor, and takeaway capacity to work in that region. Slide 13. In offshore business, in the Gulf of Mexico, we carried out a workover at our Medusa field during the first quarter. Production resumed at our non-operating 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 million of free cash this quarter. Our PKDTU gas project, which will offset the natural decline of this 10-year-old plus field, is now approximately 80% complete. We expect to bring it online in the third quarter. Our Block H Rotan FLNG project also remains on track, with first production expected in 2020. In Vietnam, we continue to progress the field development plan for our Lac Da Vang field, and we expect to declare commerciality in the second half of this year. Slide 14. In exploration, in 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 this block has increased from 35%-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 million of barrels on a gross basis with an upside of some 200 million barrels for net well cost to Murphy of only $30 million. Also in the Gulf of Mexico, we were the high bidder with partners in two blocks in Lease Sale 250. In addition, we farmed 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 the operator of this block. In Brazil, our co-venture group was a high bidder in two blocks in the Sergipe-Alagoas Basin, adjacent to our existing acreage in that play.
In Vietnam, we're progressing approvals to become the 40% operator of Block 15-01 and increase our working interest, as mentioned. This acreage addition fits within our focused exploration strategy of pursuing lower risk, low cost with an appropriate working interest opportunity. On slide 15. For the remainder of the year, we'll be drilling an additional three exploration wells. These fit well into our focused exploration strategy and expose us to approximately 125 million net barrels equivalent in resource for less than $50 million net in well costs. Success at any one of these wells will be meaningful to our company. Moving to slide 17. Our shareholder-focused strategy provides long-term, oil-weighted, measured production growth within cash flow. The five-year plan also returns over $800 million of cash to shareholders with our current dividend policy.
Production from diversified portfolio receives premium pricing, generating cash flow of more than $500 million after paying our dividend. Our current plan, which is conservative price deck compared to today's prices, delivers a four-year production CAGR of approximately 10%, leading to a strong four-year EBITDA CAGR of approximately 15%. Looking ahead just two years, we expect to generate over $1.8 billion of EBITDA in 2020 with an assumed WTI price of $57, with over $9 billion 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're continuing to hit our production targets while maintaining a disciplined approach to capital allocation. Our 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 multi-year plan and to continue creating value for our shareholders. With that's the end of our prepared remarks today. We open up for our questions. Thank you.
Thank you. Ladies and gentlemen on the phone line, should you have a question, please press star followed by one on your touch-tone phone. If you're using a speakerphone, please lift your handset before pressing any keys. One moment, please, for your first question. Your first question is from Brian Singer from Goldman Sachs. Brian, please go ahead.
Thank you. Good morning.
Morning, Brian.
I wanted to pick up on the exploration point that you made here. As certainly with the costs that have come down in the offshore, it's very unique. Can you talk about the cycle times for the type of prospects that you're planning to drill? If you are successful in the Gulf of 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. For a $30 million net well cost to us, it's really nice net mean barrels and very nice metrics on a dollar per barrel basis.
What happened there, our partner is very successful in this play, the upside of this is, will this be into a larger structure in that region? A real big successful upside would put that into a pretty large development. If not, we're back to the mean barrels, there's a lot of infrastructure nearby, including our own Front Runner, which would put this thing probably in production in two years, tops. If it gets into a larger production, probably three and a half year type basis. 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. Lots of opportunity for a smaller development and, of course, opportunity for a big discovery here, but it'll take slightly more time.
This is pretty fast cycle time, actually, even on a bigger project of 3 years. I feel comfortable with that. Look at King Cake. That's a well we moved to and spud in the third quarter. We expect to be finished that well around mid-September. Again, this is a smaller size opportunity, but very economic, fitting all of the measures we're looking for. F&D, the $15 a barrel, full cycle, 30% returns at the price that we use. This, too, again, would be a typical tieback opportunity in the Gulf, would be 18 months to two years to resolve as well. Mexico is a big well for us, an incredible structure, one of the best looking structures I've seen in a long time in the Gulf of Mexico. Has many positive seismic attributes, and similar to our Gulf side.
It will not spud until probably December of this year, and we'll have results of that in March 2019. This, too, is an opportunity to be a very big project. There, we'd be starting over and probably looking again at the three, four-year time range on something of that size. The infrastructure is coming in with the Talos discovery to our southwest there, which is Southeast rather. I'm sorry. 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 third quarter. As you know, we have a development in Vietnam in the LDV area, which will probably be close to 80 million to 100 million barrel development when we get that sanctioned later on in probably early 2019 now.
This is enormous upside of an area of a draped sand, fractured sand on top of granite play there, that's very seismic, very visible. It'll have a really big upside that has never seen a water level. These two are probably This whole area, there's many discoveries in this area, seen by the map in our call today. These are developed with small four-pile platforms, very similar to what we do in Sarawak, Malaysia, which is why we were brought in by PetroVietnam. In this thing, they have active FPSOs and active FSOs and much infrastructure. They're very similar to the Gulf, very similar to our Sarawak. Once you could put those online, probably in two-year time frames. They'll be a little longer than the Gulf of Mexico. 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. 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?
We've been touting this as a flattish production profile now for some time. We are probably, I believe, David, $135 million of free cash in there this year, at least, at very conservative prices, probably around $4 less than we see in the strip today. I would anticipate that the Eagle Ford business will be a 44,000, 45,000 kind of business for us the rest of the year. The point of that is that I reviewed 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 nine of the best wells we've ever had there.
A nearby operator, Chesapeake, great company, came in next to us and paralleled four of our best wells and went toe to toe with five of our other best wells. This caused a big impact to our production we had to recover from. Drilled out sand in our wells, produced a high level of water, and impacted our OpEx in Eagle Ford. Now we have those wells recovered. On the other end of the spectrum in Karnes County, BHP went in next door, our partner in Samurai, and killed our best Austin Chalk wells. They're some of the best wells in the play and did not produce the wells, causing us to take the water off. It's a real perfect storm for us there that knocked us back in the first quarter, quite frankly.
Now our capital allocation there is about the same as we had. We did note today that we moved $21 million from the Montney because the wells are so prolific in the Montney. We moved money from Canada down to that asset and adding seven wells, primarily weighted toward late quarter two and quarter three. We have a certain cap allocation, Brian, that we had, and we discussed that a lot in the first quarter. We're pretty much fixed there with what we have right now because we're trying to honor our capital commitments. The capital we increased today was for a well at Medusa, which 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.
The rest is taking all of our exploration and getting the latest information and fixing our partnerships. Without continuing to add capital, at this time, we're 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, and we have commitments to spend capital there, which we're 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. 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.
We have a lot of good things going for us in our unconventional business and in our offshore business as well, because we have a lot of work to do there as well. 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 Arun Jayaram from JPMorgan. Please go ahead.
Good morning. 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're at a couple, two, three years ago?
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 four places. In the Gulf of Mexico, we have two things going on. We formed an exploration alliance with a privately held exploration company that has about an 80% success rate on amplitude tieback 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. Our team's concentrated with data sets up in the Mississippi Canyon area, all focusing on middle Miocene tiebacks and larger low salt type prospects as well. That's a new change.
We're working with another party that has enormous access to seismic, in which they deliver prospects to us, and they do not operate, and we're going to be their operator. There's been some 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 deep water for a long time. That's how we're attacking 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 2D data with a commitment to shoot 3D data and making well commitments without 3D data.
This was taking place all over the world and probably led to some of the exploration misses by not only Murphy but others. We go into that block now with 3D data. This is vintage 3D, but 3D, and now I've reshot and have better processed 3D, and the prospects are looking better and better and bigger and bigger. Some of the best tieback to the purchase seismic we've had probably in Murphy history here. That has great data sets. A lot of great data shot during the collapse in Mexico. In Vietnam, this is a drape structure, a different type of a total place, probably the closest thing to shale offshore that 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've had a lot of success in. That's a different type of data. In Australia, we have total coverage of all of our basins and great 3D 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. There's more data available. The data's much cheaper than it was. A lot of data was shot in the collapse, and the data is now used in the entry, just 180 degrees from the prior years, if that answers your question.
That's great. Just at Samurai, this is, I understand, an appraisal well. Can you remind us about the discovery well, what you found there, and just set the stage of what we're looking for? It sounds like results will be in by the end of 2Q.
Yeah. We discovered, with our partnership group at that time, I guess around eight 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. 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. After a lot of work on seismic and working with our new partner, we've discovered this zone does exist off that original structure. This is one of the largest four-way structures in Green Canyon. It was the most sought-after block in lease sale years and years ago.
We are now drilling off structure for the missing M14. Then delineating the zones that we've drilled up that were discovery. We'll take, either both will hit, one will hit, and there's also a new zone deeper than this that have been found in other wells in the region that we'll be drilling to and have about three 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 gives 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's going to go over the well counts for you.
Sure, Arun. We're looking at completing a total of 45 wells that are operated by Murphy. In the second quarter, there's going to be 22. 10 of those are Catarina, 10 of those are Karnes, and we're going to have two Childress wells. In the third quarter, we're going to have four Childress wells. In the fourth quarter, we're going to have 13 Catarina wells. 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. I think that drives the production.
First, second, and third quarters are fairly steady eddy, and then that's going to drive our fourth quarter production in the Eagle Ford.
45,000.
45,000. Yeah.
Okay, thanks a lot.
Thank you. Appreciate it.
Thank you. Ladies and gentlemen on the phone line, should you have a question, please press star followed by one. Your next question is from Pavel Molchanov from Raymond James. Please go ahead.
Thanks for taking the question, guys.
No problem.
You guys are part of the consortium that won the Sergipe-Alagoas Basin blocks in Brazil, I think 430 and 573. You do not have any well commitments, as I understand. Given that you're not tied to a particular spending rate, what's the plan for those blocks?
There's no well commitments anywhere in Brazil. There's one well commitment in Mexico, none in the Gulf, and one in Vietnam. Really don't have many commitment wells in our company. I have a real good friend, a partner in this project that really doesn't want me to talk about a whole lot, quite frankly. I have a big partner there, and we're going to be going through seismic. There's 3D seismic being shot there today, a big shoot across all this acreage. There's many prospects there, many prospects near big discoveries there, very close by, very tight geologically, and we're very pleased to have it. It's probably not going to be talking a whole lot about the drilling cadence at this time. It's a big exploration project. It's being executed by ExxonMobil and our partner in Brazil, and we're very pleased to have it.
Understood. In terms of capital allocation, you've talked about your EBITDA targets based on your price deck. 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 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, that's why we're not buying any back. We didn't issue any in 2016. One of the only companies not to do that. I hope people will remember that. Our dividend policy was a long-term policy. It was reduced. I think now, naturally, we consider and will look at harder to go back at some level. I wouldn't see us jumping right back to that level. Of course, I have to discuss 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. We have to get back into net income, making business here, and our retained earnings account being positively impacted by that.
We're off to a good start, making $40 million of adjusted income, a good bit of income from that tax. While it's adjusted out, we earn that income from that tax, we deserve that net income that we've received on a rolled-up basis like we used to years ago before we went into adjusting everything there is to mankind. We need to get back to make sure we're making the net income levels to cover 100-something plus dividend that we need to make every year. We're on our way of doing that. That's the first step, we clearly have the cash to do it. They'll be studying that and looking forward to these processes, making that backwardation pull up a little bit before making that call. It's one of our focus items for the rest of the year, sure.
All right. Appreciate the color.
Thanks.
Thank you. Your next question is from Roger Read from Wells Fargo. Roger, please go ahead.
Yeah, thank you. Good morning. Good morning, Roger.
Hey, Roger. How you doing?
Well, we're getting towards the end of earnings season, so doing a little bit better.
You're right about that, Roger.
Hey, can we come back to the CapEx rise of roughly $50 million, 5%? I'm 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 end of last year, beginning of this? Are they more projects that have come to the fore since then? Just trying to understand maybe the ranking of things and maybe if anything's changed in the returns, either because oil prices are up or the projects look better. Just a little help there.
The way we do our exploration budget is that we have about four or five opportunities sometimes across the world. We put them in as a factor of are we going to do those wells. One well may be chance of doing that at 30%, 40%, 50%, sometimes 100% if it's a commitment well, something to that effect. That gives us so much capital for exploration. As the year goes by, we solidify that. Samurai is a very sought-after opportunity with a lot of success in that area. BHP took out one of our partners there. We had four or five companies wanting to take the other piece from the other partner that left. We then were able to look at some information through our partnership group and make a decision.
We wanted to go up on that 50%, and that drove a good bit of our CapEx move. Because we do that, we want to be around 35% in exploration, but it really is a delineation back to my answer of a prior call of some prior pay that we drilled at that area. 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 or capital one-up. At Medusa, we had a well that had a regulatory problem on a casing pressure issue that had to be abandoned. We go into abandon that well, but we have another zone we can re-complete into, which would be slightly more expensive. We also didn't have the abandonment in our capital plan.
We went ahead and completed the well, and it was flowing at a very, very nice rate with just two or three days of flow early in this quarter. The well had to be shut in due to a planned downstream constraint at Medusa that's taking place from Shell shutting in some platforms in the Eastern Gulf of Mexico. That's been known about for a long time. Those are the two big drivers of it. 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 first quarter to get our production back to the level we wanted. The opportunities are very, very good. All these wells have a. Samurai is an exploration well. Medusa well, clearly play out and be a very, very nice well.
Okay. Thanks for that. In Vietnam, we have an opportunity to increase our working interest there, too. That's another part of those exploration wells that we then, by May or June, you say, "I'm going to do this and this." 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 farmed into with PetroVietnam. All this, $50 million, is a great value add for our company and positions us really, really well. 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. Just two, maybe more basic questions. One, the longer-term outlook you laid out, $57 WTI, are you assuming a similar price for Brent? The second question, just service cost trends as you see them across, give us what you want, but thinking mostly Lower 48 and Gulf of Mexico.
Obviously, our prices are used in our LRP, our long-range plan, we call it this year, way over. We do have some hedging in there. Our current plans are below strip. I think we're probably looking at a quarter two WTI of $64, $63 in the third quarter, and $61 in the fourth quarter, conservatism to that bit of backwardation there. Probably a really good position compared to that. Our Brent, we normally take it about $4 over, but today it's $7. We're pretty conservative still on that, and I think pretty well positioned on that. What was your next question, Roger?
Sure.
Everybody keeps crying about the service costs. We really are rolling along pretty well. I think 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. We felt there's a 10% chance of costs going up in the Eagle Ford on drilling and probably 10%-15% on completions. At the end of the day, the cost per foot of the 18 wells we drilled in the first quarter versus what we had in 2017 is slightly lower. We continue to execute there. We're really well positioned. Our procurement teams and our management team for Eagle Ford have done a great job. We have one frac company for all of North America now. It's brought us incredible savings with some really, really good rig rates, with some rig rates tied to oil prices.
It's nicely positioned for our company. We're just not seeing it. If we do, it might would be around, I calculated yesterday, it'd probably be around $20 million-$25 million. It could go up on completions the rest of the year, Roger, we can afford it, so.
Well, that's good to hear. Thank you.
Thank you.
No, 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 you need to get back with our IR team if you have any questions, and we'll look forward to seeing you in the next quarter. 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.