Murphy Oil Corp (MUR) 2018 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2018 Earnings Conference Call. (Operator Instructions)

I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Good morning, everyone, and thank you for joining us on our call today. With me are Roger Jenkins, President and Chief Executive Officer; and leader of 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. No further discussion of risk factor -- 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, and thanks for listening to our call today. First quarter production was 168,000 barrel equivalents per day, at the high end of our guidance and 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 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've returned 16% of our operating cash flow to shareholders. We're creating long-term value by participating in highly economic offshore projects, and in countercyclical move, returning to a 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'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. First quarter, our weighted average price is over $63 per barrel for oil sold. With oil comprising 52% of our sales, the small volume of NGL is 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 the top quartile cost structure allowed us to achieve an EBITDA per BOE of near $22 a barrel for 2017, which is #1 in our TSR peer group. Building on this, our first quarter 2018 EBITDA per BOE was nearly $25 a barrel.

Our differential spread has 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 barrels equivalent per day for 2018, with full year production guidance now at 167,000 to 170,000 BOEs per day. Our production levels have stabled, 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 to account a nonbudgeted 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 were able to reallocate $21 million of capital from our Tupper Montney asset through 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 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 1 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 balance has 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 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 at 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 onetime 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, 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 IP30s 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, and increased our penetration rate 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 is 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 3 wells of 5-well pad with 4 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 5 wells with an average EUR of approximately 18 BCF, we've 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 continue to have competitive returns in this play as our full cycle breakeven price is 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 through Chicago and Emerson and to the East Coast through Dawn as well as our current long-term hedge strategy. This means that 6% of our planned 2018 production will not be exposed despite our 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 and our current Tupper -- than our current Tupper assets with breakeven prices approaching CAD 1.75 AECO per MCF.

On Slide 11, on the Kaybob Duvernay area. At the Kaybob Duvernay asset, we increased production 92% in 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 4 pacesetters, brought 8 wells online, including our first wells in the Simonette, Saxton 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 a 1,000-barrel equivalents per day. Our early production rates in the new Saxton area are exceeding 2,000-barrel equivalents per day.

Continuing to Duvernay, in 2016, we've lowered our drilling and completion costs by 25% and costs are now proven to be competitive with the costs in Eagle Ford Shale on a per-foot basis. Our pacesetter wells in Duvernay now have a drilling costs 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 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 and ordering share market access, in the first quarter, we construct nearly 50 miles of pipelines in that region.

Slide 12. 2018, we're going to drill a minimum of 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're able to derisk another 40%. They 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, in offshore business. Gulf of Mexico, we carried out a work over at Medusa Field, and the first quarter production resumed at our nonoperating Kodiak well and our Habanero field during the quarter as well. We're seeing strong rates at both especially 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 we expect to bringing it online in the third quarter.

Our Block H Rotan 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. 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% to 50% with the new partner, 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 mean, we're able to access approximately 75 million of barrels on a gross basis, with an upside of some-200 million barrels per net well cost to Murphy is only $30 million.

Also in the Gulf of Mexico, we were the high bidder with partners in 2 blocks from Lease Sale 250. In addition, we farmed into the Highgarden prospect, which is a Miocene [AMP2] supported 3-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 2 blocks. 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 15-1 and increase our working interest, as mentioned. These -- 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 3 exploration wells and 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 of net well cost. 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 million of cash to shareholders with our current dividend policy. Production from diversified portfolio received 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 4-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 $1.8 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 '18. We continue to hit our production targets while maintaining a 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 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 questions. Thank you.

(Operator Instructions) Your first question is from Brian Singer from Goldman Sachs.

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 -- they're 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?

Brian, I appreciate that question. Starting off with our Samurai well, we are drilling that well today, we're probably over 1/3 of the way finished with the well. We expect that well to TD in mid-June. And for $30 million 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're back to the mean barrels, there is a lot of infrastructure by including our own front runner, which should 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. It's also another party that's now our partner in other wells that have success nearby that are also in the development mode. So lots of opportunity for a smaller development and of course, opportunity for a big discovery here that'll take slightly more time. So it's just 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 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, the $15 to barrel, full cycle 30% returns at the share -- at the price that we use. And that's 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 in the Gulf of Mexico, there's 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 of '19. This too is an opportunity to be a very, very big project, and then 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'm 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 third quarter. As you know, we have a development in Vietnam in the LDV area, which would probably be a close to 80 million to 100 million-barrel development when we get that sanctioned later on in probably early '19 now. And this is enormous upside of an area of a great sand, fractured sand, on top of granite play there, it'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's many, many discoveries in this area seen by the map in our call today. These are developed with small 4 power platforms, very similar to what we do in Sarawak, Malaysia, which is one we brought in about PetroVietnam. And this is staying there as active SPSO's and active SSOs and much infrastructure, very similar to the Gulf, very similar to our Sarawak, wish we could put those online, probably in 2-year timeframe. So a little longer than the Gulf of Mexico. Such a run-through, I believe, 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, in other words, timing issues, let's say, with wells that were temporarily off that's just had a production trajectory and looks through the year? And then also are there limitations either in terms of acreage scope or scale to increasing activity there? Is that something that you would consider?

Yes. Our Eagle Ford business is kind of, -- we've been counting this as a flattish production profile now for some time. We are probably, I believe, Dave at $135 million of free cash in there this year, at least, at very conservative price, it's probably around $4 less than we've seen in the script today. So I anticipate that the Eagle Ford business would be a 44,000, 45,000 kind of business for us the rest of the year. Just got off to a -- and the point to that is, is that our (inaudible) is 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 have there, and we had 9 of the best wells we've ever had there. And nearby operator, Chesapeake, great company came next to us and paralleled 4 of our best wells and went toe-to-toe with 5 of our other best wells. This 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 that 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 [often shopped] wells, they're some of the best wells in the play and did not produce the wells, causing us to take that 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 is about the same as we have, 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 7 wells, primarily weighted toward late quarter 2 and quarter 3. And we have a certain cap allocation, Brian, that we had and we've discussed that a lot in the first quarter. And we're pretty much fixed there is what we have right now because we're trying to honor our capital commitments and the capital 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 the week flow just to limit to 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, we have commitments to spend capital there, which we're proud of and the cash carry arrangement we had at the bottom of the market. All of these wells are doing extremely well for us, probably more here 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 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. But not trying to get over the cash flow CapEx parity too much here, Brian, post the dividend, if you follow me.

Your next question is from Arun Jayaram 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're at a couple, 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 #1 part of it is focusing just in 4 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, tie-back, 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 within there and then our teams concentrated with datasets in the Mississippi Canyon area, all focusing on Middle Miocene tie-backs 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, 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 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, they're 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 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 block now with 3D data that's advantage 3D but 3D and now every shot and have better process 3D, and the prospects are looking better and better and bigger and bigger. And some of the best tie-back to be purchase seismic we've had probably in Murphy history here. So that has great datasets, lot of great data shot during the collapse in Mexico. In Vietnam, this is a drape structure, a different type of a total place by the closest thing, the shale offshore that you can have. More of a Granite Wash play which have 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. So that's a different type of data. And then in Vietnam -- 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 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 the entry just 180 degrees from prior years. That answers your question.

That's great. And just at Samurai. This is -- I understand an appraisal work, can you remind us about the discovery well? What you found there? And kind of just set the stage at what we're looking for with some of that results will be -- by the end of 2Q?

We've 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 in discovery, and then we drilled through the Middle Miocene section and found one of the zones to be tied 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 structure. One of the largest 4-way structures in Green Canyon, it was the most sought after Bakken lease sale years and years ago. And we are now drilling a structure for the missing M14 and then delineating the zones that were drilled up that were at discovery. And then we'll take either both will hit, one will hit, there's also a new zone deeper than this that we've found in other wells in the region that we'll be drilling, too. And to have about 3 different choices here to find the 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 (inaudible), 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 through the well count for you.

So we go -- 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 2 children wells. And then in the third quarter, we're going to have 4 children 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 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-eddy. And then that's going to drive our fourth quarter production in Eagle Ford to be I think in the neighborhood of...

45,000.

45,000, yes.

(Operator Instructions) Your next question is from Pavel Molchanov from Raymond James.

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's one well commitment in Mexico, none in the Gulf, and 1 in Vietnam. So we really don't have many commitment wells in our company. I have a real good friend, partner in this project, that really doesn't want me to talk about a lot, quite frankly. And so I have a big partner there and we're going to be going through seismic, there's 3D seismic that's being shot there today, a big shoot across all this acreage. We've many prospects there, many prospects and new 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 there'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 will 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 '16, one of the only companies not to do that, I hope people will remember that. And our dividend policy is the long term policy, it was reduced. I think now, naturally, we consider and we'll look out 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 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 to net tax. And while it's adjusted out, we earn net income from that tax. And we deserve that net income that we've received on a relative basis like we used to years ago before we went into adjusting everything there is to mankind. So we needed the gap 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 at 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 process, making that backwardation pull up a little bit before making that call, and it's one of our focus on for the rest of the year, sure.

Your next question is from Roger Read from Wells Fargo.

Well, we're getting towards the end of earnings season, so doing a little bit better. But we are...

You're right about that, Roger.

Can we come back to the CapEx rise of roughly $50 million, 5%. I was 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 fore since then? Just trying to understand kind of maybe the ranking of things and maybe if anything has 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 4, 5 opportunity sometimes across the world. When we put them in as a factor of, are we going to do those wells like 1 well maybe chance of doing that at 30%, 40%, 50%, sometimes 100% if it's a commitment well, something a matter of fact. So that gives us so much capital for exploration. Then as the year goes by, we solidify that. So Samurai's are very sought after opportunity with a lot of success in that area and we -- BHP took out one of our partners there, and then we had 4, 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 little 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 to the prior call or some prior pay that we drilled in that area. So then when we take and we pull out the ones we're not going to do, pick the ones we're going to do and increase of working interest on a delineation-type well, our capital went up. At Medusa we had a well, had a regulatory problem on -- casing pressures had to be abandoned. So we're going to abandon that well, but we have another zone, we can recomplete into, which should 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, but 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 platform from 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 first quarter to get our production back to the level we wanted, also the opportunities are very, very good. So all these wells are high, Samurai is an exploration well, the Medusa well clearly play out to 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've done 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 operator ship in that block, it allows us to be operator of the original development that we formed into with PetroVietnam. So all that $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 paneling a regulatory matter that turned into a goodwill in the Gulf.

Okay. And then just kind of 2, 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, our long-range plan we call it, this year lay 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 third quarter and 61 in the fourth quarter, conservatism to that bit of backwardation there, probably really good position compared to that. And at 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...

Everybody's keep talking about service costs, and we really are rolling on pretty well, I think it's -- if you're looking -- 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 first quarter versus what we had in '17 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 had done a great job. We have a 1 frac company for all of North America now, it's brought us some credible 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 calculated yesterday, it'd probably be around $20 million to $25 million, it could go up on completions for the rest of the year, but Roger, we can afford it.

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, and thanks for your time. Appreciate it.

Ladies and gentlemen, this concludes your conference call today. We thank you for participating, and ask that you please disconnect your lines.