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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 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 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. 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 on risk factors, see Murphy's 2017 Annual Report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.
I will now turn the call over to Roger Jenkins.
Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. First quarter production was 168,000 barrels 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 the first quarter was $300 million. Our program for 2018 is front-end loaded, with the majority of the 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 at Brent/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 countercyclical move. We're turning to focused strategic offshore exploration with low-cost entries that have no well commitments, with the lowest cost for drilling we've seen in decades.
Since we operate in 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 $4 premium to WTI, a very strong position for us. Our unique strong netback price position coupled with the top quartile cost structure allowed us to achieve an EBITDA per Boe of near $22 a barrel for 2017, which is number one in our TSR peer group.
Moving on this our first quarter 2018 EBITDA per 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 167,000 to 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're 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 Looney, for his maiden voyage this morning. David, I turn 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 31, 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 31, 2018, we had no outstanding borrowings under our $1.1 billion revolving credit facility. Worldwide cash and invested cash balances totaled $940 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 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 second 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 million 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 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 9. During the quarter, we brought six wells online in Eagle Ford Shale, all of which in the Lower Eagle Ford Shale wells in the Tilden area. These wells are completed using our Gen 5 completion technique, which resulted in significantly higher IP30s 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 reduction we've been able to maintain even with upward pressure and service costs. For example, our 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 pacesetter 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 was 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 the Tupper Montney including transportation were CAD 2.20 AECO per MCF, well ahead of spot prices. We're continuing to have competitive returns in this play as 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 Malin, to the Midwest to 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're continuing 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. In the Kaybob Duvernay asset, we increased 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 us apart from other North American unconventional plays, was approximately 7% for the first quarter.
During the first quarter, we drilled 12 appraisal wells with 4 pacesetters, about 8 wells online, including our first wells in the Simonette, Saxon and Kaybob East areas. We continue to see high production rates well above our initial expectations upon entry in 2016. We have 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 the Duvernay in 2016, we've lowered our drilling and completion cost by 25% and costs are now proven to be competitive with costs in the Eagle Ford Shale on a per foot basis. Our pacesetter 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 compared to current drilling and completion costs in the 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, continue to build our infrastructure in order to ensure market access, in the first quarter, we constructed nearly 50 miles of pipelines in that region.
Slide 12, 2018, we're going to drill a minimum 17 wells and bring 23 wells online as per original plan. Our development activity will be concentrated in the already derisked Kaybob West area and we will continue to appraise the other areas of the play. Our drilling activity at Simonette during the first quarter allowed us to derisk approximately 60% of that area, and in Kaybob East, we were able to derisk another 40%. We will execute on our 2018 plan, including accelerating a number of wells in the first quarter due to readily available services, labor and takeaway capacity to work in that region.
Slide 13, on offshore business. In Gulf of Mexico, we carried out a workover at our Medusa field. And in 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 Kikeh DTU gas project, which will offset the natural decline of this 10-year-old-plus field, is now approximately 80% complete and expect to bring it on line 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 LDV field and we expect to declare commerciality in the second half of this year.
Slide 14, on 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. The working interest in this block 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 million of barrels on a gross basis with an upside of some 200 million barrels for a net well cost to Murphy of only $30 million.
Also, in the Gulf of Mexico, we were the high bidder with partners on two blocks in Lease Sale 250. In addition, we farmed-in to the Highgarden prospect, which is a Miocene AMP2 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, the Sergipe-Alagoas Basin, adjacent to our existing acreage in that play. In Vietnam, we're progressing the approvals to become the 40% operator of Block 15-1 and increase our working interest as we mentioned. This acreage additions 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 of equivalent and resource for less than $50 million 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 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 full-year production CAGR of approximately 10%, leading to a strong full-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, that's the end of our prepared remarks today and we open up for our questions. Thank you.
Thank you. Your first question is from Brian Singer from Goldman Sachs. Brian, please go ahead.
Thank you. Good morning.
Morning, Brian.
I wanted to pick on the exploration points 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? 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 million net well cost to us, it's really nice net, mean barrels and very nice metrics on a dollar per barrel basis.
So, what happened there, our partner is very successful in this play and the upside of this is we'll 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're back to the mean barrels, there's a lot of infrastructure, and by including our own frontrunner, we should 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.
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, we've lots of opportunity for smaller development, and of course opportunity for a big discovery here, but it'll take slightly more time. So, this is pretty fast cycle time. Actually, even on a bigger project of three years, I feel comfortable with that.
If we look at King Cake, that's a well we moved to and spud in the third quarter. We expect to be finished with 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&D of $15 a barrel, full cycle, 30% returns at the price that we use. And this, 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, an incredible structure. One of the best-looking structures I've seen in a long time in the Gulf of Mexico, has many positive, Miocene 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 of 2019. This too is an opportunity to be a very, very big project. And there we'll be starting over and probably looking again at the three, four-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'm sorry. So, new days there and 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 would probably be close to 80 million to 100 million barrel development when we get that sanctioned later on in probably early 2019 now. And this is an enormous upside of an area of fractured sand on top of granite play there. That's seen very visible. It will have a really big upside that has never seen a water level.
And these two are probably – this whole area, there's many, many discoveries in this area seen by the map in our call today. These are developed with small four power platforms, very similar to what we do in Sarawak, Malaysia, which is why we're 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. We should put those online probably in two-year timeframes, a little longer than the Gulf of Mexico. So, that's a run through of it, if that answers your questions.
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, the other limitations either in terms of acreage, scope or scale to increasing activity there, or is that something that you would consider?
Yeah. Our Eagle Ford business is – 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.
Yes.
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 or 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 reviewed this very closely in Houston a couple 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, and 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. And it's caused a big impact to our production that we had to recover from. Drilled out sand and our wells produced a high level of water and it impacted our OpEx in the Eagle Ford. Now we have those wells recovered.
And 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. So, it's a real perfect storm for us there that knocked us back in the first quarter quite frankly.
And now, our capital allocation there, it's about the same as we had, but we did note today that we moved $21 million from the Montney because the wells are so prolific in the Montney. And we moved money from Canada down to that asset and adding seven wells, primarily weighted toward late quarter two and quarter three.
And we have a certain cap allocation, Brian, that we had and we discussed that a lot in the first quarter. And we're pretty much fixed there of 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, which is really a regulatory well that was required for us to do, but also we had workover option in which we have very nice well there to produce that we flowed 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're probably unlikely to add a lot of into Eagle Ford Shale. Of course, it's a big go-to place for us to do so. But 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 the cash carry arrangement we have 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 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 conventional business and in our offshore business as well because we have a lot of work to do there as well. But not to try and 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.
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 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, 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'll work with them there. And our team is concentrated with data sets up in the Mississippi Canyon area, all focusing on Middle Miocene tiebacks and larger low-salt type prospects as well.
So, 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, 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're attacking that 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 in 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 exploration misses by not only Murphy but others.
So, we go into that block now with 3D data, that's vintage 3D, but 3D. And now, have reshot and have better processed 3D. And the prospects are looking better and better and bigger and bigger and some of the best tieback to the purchased seismic we've had probably in Murphy history here. So, that has great datasets, a lot of great data shot during the collapse in Mexico.
In Vietnam, this is a drape structure, a different type of the total plays, probably the closest thing the 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 lots 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 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. So, 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 the entry, just 180 degrees from the prior year's. 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 sound like the 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 is 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 discovered this zone does exist off that original structure. So, one the largest four-way structures in Green Canyon. It's the most sought after block in lease sale years and years ago. And we are now drilling our structure for the missing M14, and then delineating the zones that were drilled up that were discovery. And then, we will take – either both will hit, one will hit. And there's also a new zone, deeper than this, that have been found and other wells in the region we'll be drilling too. 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 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 – the well count for you.
Sure. Arun, so we're looking at completing a total of 45 wells that are operated by Murphy. And so 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 Tilden wells. And then, in the third quarter, we're going to have 4 Tilden wells. And in the fourth quarter, 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 quarter. So I think that kind of drives the production. So, first, second and third quarters are fairly steady eddy. And then, that's going to drive our fourth quarter production in the Eagle Ford to be, I think, in the neighborhood of...
45,000.
45,000. Yeah.
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.
No problem.
So, you guys are part of that consortium that won the Alagoas Basin blocks in Brazil. I think Block 430 and Block 573. You do not have any well commitments as I understand. So, given that you're not tied to a particular spending rate, what's kind of 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. So, 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 it a whole lot quite frankly.
And so, 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. We've many prospects there, many prospects near, big discoveries there, very close by, very tight geologically. And we're 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're very, very pleased to have it.
Understood. And 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 CapEx and the dividend, would you be more inclined to maybe getting the dividend back to where it was before the haircut a couple 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 2016, one of the only companies not to do that. I hope people will remember that. And our dividend policy was 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've discussed this with our board. It's always a discussion we will have primarily later in the year. I wouldn't see just 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 impacted by that, which are off to a good start, making $40 million of adjusted income and a good bit of income from that tax. And while it's adjusted out, we earned that income from that tax. And 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.
So, we need to get back to make sure we're making the net income levels to cover the 100 and something plus dividend, and 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 we'll be studying that and looking forward to these processes, making that backwardation pull up a little bit before making that call. And it's one of our focuses 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 are 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, 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, or are they more projects that have come to the fore since then? Just trying to understand kind of 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 kind of little help there.
The way we do our exploration budget is that we have about four, five opportunities sometimes across the world. And we put them in as a factor of are we going to do those wells, like, one well may be 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's a very sought after opportunity with a lot of success in that area. And BHP took out one of our partners there. And then we had four, five 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 wanted 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, but really it's the delineation back to my answer over prior call of some prior pay that we drilled in that area. So, then, when we pull out the ones we're not going to do, pick the ones we're going 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, it had to be abandoned. So we're going to abandon that well, but we have another zone we can recomplete into, which would be slightly more expensive. And we'd 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 two or three days of flow early in this quarter, but the well had to be shut in due to a planned downstream constrain at Medusa that's taking place from Shell, shutting in some platforms in the Eastern Gulf of Mexico, has been known about for a long time.
So those are the two 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 first quarter to get our production back to the level we wanted, also the opportunities are very, very good. So all of these wells have a high – Samurai is a exploration well, but the Medusa well clearly will pay out and be a very, very nice well.
And also, 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, 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, allows us to be operator of the original development that we formed into with PetroVietnam.
So all this $50 million 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 two maybe more basic questions. One, the longer-term outlook you laid out, $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, a long range plan we call it for this year lay over, but we do have some hedging in there. Our current plans are below strip. I think we're probably looking at a quarter two WTI $64, $63 in the third quarter, and $61 in the fourth 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're pretty conservative still on that and I think pretty well positioned on that. And what was your next question, Roger?
Service cost.
No, everybody is keep crying about service cost, and we really are rolling along pretty well. I think if you look in what I said in the script, it's mindboggling really for our Eagle Ford business as it 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 completions. But 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, 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 frac company for all of North America now. This brought us incredible savings with some really, really good rig rates, with some rig rates tied to oil prices that's nicely positioned for our company. And we're just not seeing it. And if we do, it might would be around – I calculated it yesterday, it probably be around $20 million to $25 million. It could go up on completion through the rest of the year. But, Roger, we can afford it, so.
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 you need to get back with our IR team if you have any questions. And we look forward 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.