Noble Energy, Inc. (NYSE:NBL) Q1 2019 Results Earnings Conference Call May 3, 2019 9:00 AM ET
Brad Whitmarsh - IR
Dave Stover - Chairman and CEO
Brent Smolik - President and COO
Ken Fisher - EVP and CFO
Hodge Walker - SVP, Onshore
Keith Elliot - SVP, Offshore
Conference Call Participants
Brian Singer - Goldman Sachs
Arun Jayaram - JPMorgan
Scott Hanold - RBC Capital Markets
Michael Hall - Heikkinen Energy Advisors
Doug Leggate - Bank of America
Irene Haas - Imperial
Welles Fitzpatrick - SunTrust
Charles Meade - Johnson Rice
Gail Nicholson - Stephens
Nitin Kumar - Wells Fargo
Jeanine Wai - Barclays
David Deckelbaum - Cowen
Good morning, and welcome to Noble Energy's First Quarter 2019 Earnings Results Conference Call. Following today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded.
I would now like to turn the conference over to Brad Whitmarsh. Please go ahead.
Thanks, Gary, and thank you all for joining us for our first quarter conference call. I hope you've had a chance to review the news release and presentation deck that we published this morning. These materials are available on the Investors page of our website and they highlight strong first quarter performance versus expectations. Later today, we plan to file our 10-Q with the SEC.
I want to remind everyone that today's discussion contains projections and forward-looking statements, as well as, certain non-GAAP financial measures. You should read our full disclosures in our latest news releases and SEC filings for a discussion of those items. Following our prepared remarks, we will hold the question-and-answer session. I would ask that analysts limit themselves to one primary and one follow-up and we plan to wrap up in under an hour.
Our planned comments this morning will come from Dave Stover, Chairman and CEO; as well as Brent Smolik, President and COO; Ken Fisher, EVP and CFO; Hodge Walker, SVP of Onshore; and Keith Elliott, SVP of Offshore are here to participate in the Q&A session.
With that, I'll turn the call to Dave.
Good morning, everyone, and thanks for joining us.
I'm excited to share with you a number of accomplishments already realized during the first quarter, including driving sustainable capital and cost savings and quarterly production ahead of expectations. In fact, our first quarter net organic cash flow was significantly better than the plan we outlined last quarter.
In the earnings release and slides, we have provided detailed information to illustrate our strong level of execution from the beginning of the year. For the third quarter in a row, our total capital came in below expectations with first quarter capital below the low end of the range, due to lower well and facility costs and lower Leviathan spend.
Despite the reduction in capital, we delivered sales volumes above the upper end, upper range of guidance. Operating costs also came in below expectations and these per barrel efficiencies will drive further improvements in profitability.
Going into this year, we set out to drive sustainable cash flow growth by challenging the organization to reduce the capital intensity of our business and deliver more for the same or less capital. As we continue to progress through the year, we expect to build upon these capital efficiency gain. I can say that we're off to a great start with better operational efficiencies across all three onshore basins. Brent will discuss this in more detail, but I'm pleased with the execution of our onshore teams and the efficiency results.
The leadership focus on innovation and continuous improvement, creates the opportunity to decrease the long-term capital needs for the company. Despite the acceleration in oil prices through the first quarter, we remain disciplined.
Our plan was set at a $50 WTI oil price for 2019. We are committed to operate within our budget of $2.4 billion to $2.6 billion. And as I stated on the year-end call, as commodity prices move higher, we expect to have the ability to further strengthen the balance sheet and return additional cash flow to investors.
In the DJ Basin, our business continues to outperform our expectations. Last month, Colorado passed Senate Bill 181, which provides additional oversight for oil and gas activity at the local level. Through the strategic repositioning of our acreage and state approval of our comprehensive drilling plan, we're well positioned to work with both state and local authorities. We have line of sight to years of activity and are set to execute on our multi-year plan and to build upon our industry-leading returns in the basin.
In Texas, the Delaware Basin has maintained production and growing cash flow, despite a lower activity level and capital outlay for the last three quarters. Our Eagle Ford operations continue to benefit from better base production performance as well as the initial tranche of ducts coming online.
As our U.S. onshore completion activity picks up in the second quarter, we are positioned for a pronounced second half volume ramp, while capital spending trends lower throughout the year.
Before we move to the international assets, I'd like to take a minute to discuss Noble Midstream. Operationally NBLX had another strong quarter. Their service and support of Noble's activities in the DJ and Delaware Basins has been a key to our success.
The NBLX team has built a strong asset base and third-party businesses in both basins. They recently announced the addition of three very attractive assets the EPIC Y-grade and crude interests and the Delaware Crossing pipeline to Wink Texas, which support Permian growth, while assisting our upstream development.
You may have seen that we filed an 8-K last week to disclose an ongoing strategic review of our midstream assets. This is consistent with our earlier disclosures and our practice of continually evaluating all options to create an increase value.
Our midstream assets within Noble and NBLX are very valuable. And we do not believe this is sufficiently reflected by the markets for either entity. As we evaluate potential scenarios, we will keep in mind the investor sentiment around MLP structure and IDRs. I won't speculate on the potential outcomes. However, Noble as the largest unit holder in NBLX has a vested interest in the success of both entities.
Turning to our international business. We outlined goals this year to maximize cash flows of our existing businesses, while progressing our major project developments that Leviathan and Alen. Operationally, it was a strong quarter for both our Equatorial Guinea and Israel operations.
In the Eastern Med, volumes continue to outperform through higher domestic demand. With Leviathan now 81% complete, the project remains on time and on budget. With the platform, getting ready to set sail in the summer.
Bringing Leviathan online, will provide another source of gas in the growing domestic and regional demand centers. In West Africa, the team delivered volumes above expectations. We sanction the Alen gas monetization project, which we see as the first step in creating an offshore natural gas hub in the area.
I'm excited about the potential for decades of incremental sustainable cash flow through the backlog of discovered resources in this area. With Leviathan and Alen, Noble Energy has a unique opportunity to access global natural gas markets and drive further high margin, cash flow growth internationally.
Over the last few years, we've also been focused on building an exploration portfolio of high quality drilling opportunities. Our teams have targeted matured low cost material opportunities both on and offshore. I'm excited to be able to talk about our recent entry in Colombia, where we are operator with 40% working interest on two offshore blocks with Shell. We will likely test a prospect in 2020.
Additionally, our onshore exploration team has captured over 140,000 acres of low cost material exploration inventory in two Wyoming basins. In 2020 consistent with our multi-year plan, our offshore and onshore exploration programs will begin to test up to 1 billion barrels of net risked exploration inventory.
Overall, I'm extremely pleased with how the company has started 2019. We are well on our way to accomplishing the goal set out earlier this year. We're focused on three key drivers of shareholder value to position Noble as an attractive investment across all sectors.
These are; number one, generating a competitive free cash flow yield with significant return to investors; two, maintaining a strong balance sheet; and three, delivering a 5% to 10% long-term annual production growth rate supplemented by periodic additions of the major projects.
In addition, our high return, high quality opportunities I'm sure our investments drive increasing corporate returns. We are uniquely positioned to our low decline production base and high return opportunity set to deliver these outcomes and create sustainable value growth and return to investors.
Over time, we plan to grow the dividend with cash flows and provide additional opportunistic shareholder returns. To that end, we recently announced an increase to the quarterly dividend of 9%, reflecting the confidence in our cash flow outlook.
Now I'll turn the call over to Brent Smolik, our President and COO, to talk about the operations and the efficiencies gained already in 2019.
Thanks Dave, and good morning, everyone.
As Dave mentioned, the first quarter was a strong start to 2019, with good execution globally, across our operations. Our U.S. Onshore business improved capital efficiency coming in under budget on capital and above on first quarter production volumes.
On the international side, the quarter was equally rewarding, where we continue to produce above expectations, progressed Leviathan 81% completion and sanction the Alen gas monetization project.
So I'll begin - little deeper dive this morning with the U.S. Onshore on Slide 5. Our key operational focus in this part of our business has been to improve execution and capital efficiencies. While still early in the year, I'm happy to report that we've made significant strides to streamline cost, create more efficient well designs and increase our pace of execution.
We've accelerated our completion tempo across all three basins with meaningful gains in completion stages per day and total pumping hours per day, while decreasing the transition time between frac stages. The frac hours pump per day increased 5% to 10% in the DJ, Permian and Eagle Ford versus Q4 '18 and that's a meaningful improvement in the quarter.
Our teams also continued to improve drilling efficiencies and delivered a best-in-class pacesetter Permian well in 16 days from spud to rig release for nearly 10,000 foot lateral. In the DJ Basin Row 2 wells at Mustang were drilled 10% faster than Row 1 wells, as we leverage learnings from the 2018 drilling campaign.
There is a cost benefit to those efficiency gains and there is a production benefit because new wells are brought online ahead of schedule. And I expect that momentum to continue in the second quarter. While these results were a good start and we're continuing to look for ways to capture further savings and improved returns.
For example, in the DJ Basin, we continue to test and evaluate frac designs, employing lower fluid volumes, which reduces the pumping time per stage. Successful application of this design can sustainably reduce capital costs and improve well returns. We also plan to test this concept in other basins.
These capital improvements and reduce cycle times puts Noble in a great position to either complete our planned activities quicker for less capital or accomplish more activity within the approved 2019 capital budget. Either option is a positive outcome. We also continue to closely monitor service cost and year-to-date, we've not experienced inflationary pressure in any category in the U.S. Onshore.
Turning specifically to the DJ Basin. Over the past several years, Noble has strategically positioned itself within the basin, we built a high quality contiguous acreage position, which allows for optimal development and we're seeing the results of those efforts.
In the first quarter, the DJ generated record production of 144,000 barrel equivalents per day, up 21% versus the first quarter of 2018. The efforts of our teams to create offtake optionality are paying off by improving the reliability and predictability of gas in NGL sales volumes. This exceptional performance has allowed the DJ to generate cash flow in excess of capital spend and we expect this trend to continue as we efficiently develop the asset.
During the quarter, we brought online our initial wells from the second row of Mustang, which brings Row 1 and Row 2 to nearly 50,000 barrel equivalents per day of gross production and just nine months from the startup of Row 1. These 21 wells were drilled and completed faster than Row 1, an early production trends are in line with Row 1.
With more than half the 29 activity focus in Mustang, we're encouraged that our program will continue to deliver on expectations. As we expected and guided the wells in the western portion of Row 2 produce with higher gas oil ratios. Going forward, we expect the GORs to decrease as we move east and north in the DJ development.
In the second quarter, we'll will have the highest number of TILs planned in the DJ Basin supporting second half 2019 production growth. The company still plans to operate one to two rigs and two frac crews and bring 95 to 100 wells online in the DJ this year.
In the Delaware Basin, production was essentially flat with Q4, despite the announced divestiture and a low TIL count in the first quarter. Well performance remained strong bringing online nine wells with an average 30-day rate of over 1,500 barrel oil equivalents per day. Two of the nine wells were in the Southwest portion of our position adjacent to the recently divested acreage. Excluding those two wells, the average new well production was over 200 barrel equivalents per day for per 1,000 foot of lateral.
As we move forward this year, our near-term plans are primarily focused on executing row style development in our core Reeves County acreage position near our central gathering facilities. We anticipate further improvements as we bring 15 to 20 wells online in Q2. The timing of the second quarter TILs will contribute significantly to third quarter production growth, which aligns well with our EPIC early crude service.
The Permian basins received some recent attention regarding gas transportation and WAHA spot pricing and that issue, does not have a meaningful impact on Noble for several reasons; Permian gas only makes up approximately 1% of our company revenues; we have a firm gas sales agreement in place to move 100% of our gas and NGL volumes out of the basin; and we've had 75% of our 2019 and 2020 WAHA basis.
In the Eagle Ford, we generated significant asset level free cash flow last year and we plan to continue harvesting cash this year. Late in the first quarter, we brought online seven DUCs and thanks to our improved cadence of operations, we've accelerated additional TILs into the second quarter.
We anticipate a slight increase in production volumes in the second quarter before stepping up in the third quarter as a remainder of our DUC inventory comes online. Overall, we're pleased with Q1 performance in the U.S. Onshore business.
Now shifting to offshore. We continue to see strong performance from our producing assets with a great quarter from both Eastern Med and West Africa. In Israel, Tamar continue to exhibit why it's a world-class natural gas asset, again produced a record volumes of over a Bcf per day gross production in Q1.
And the second quarter, we expect slightly lower volumes due to some holiday seasonality, and then we expect third quarter production to be similar to Q1. We expect Tamar production to be essentially flat to 2018 or said another way, no base decline year-over-year.
As Dave mentioned, the Leviathan project is now 81% complete and we achieved a few key milestones in the quarter. We completed the jacket installation, the subsea manifold installation and the subsea pipeline installations as we continue to derisk the project.
The next major operational milestone will be the delivery of the production deck, which is scheduled for mid-year. From a marketing standpoint, the key near-term focus is the EMG pipeline, which will facilitate natural gas sales into Egypt. We're diligently progressing this project and we plan to flow test with gas and complete inspection this month.
Following the flow test, we expect to close on the pipeline purchased by mid-year. What's operational, the pipeline will primarily allow for gas sales from Leviathan and will provide flexibility for gas sales from Tamar.
As we've communicated previously, we expect to sell an average of 800 million cubic feet a day from Leviathan in 2020. We anticipate significant regional demand growth and we're excited that the Noble EMEA gas can satisfy a portion of that growing demand. In West Africa, the sanction of the Alen gas monetization project was the major highlight for the quarter.
The declining production from the Alba field creates capacity at the existing putting Europe plant infrastructure and that capacity creates an unique opportunity to extend the life of the Alba field and to monetize the Alen gas, it's currently re-injected for pressure maintenance. The project capital is estimated to be $165 million net to Noble and we expect the initial sales of LNG and incremental liquids in the first half of 2021.
The economics benefit from global LNG pricing and the project is a significant step forwards towards monetization of over three Tcf of discovered gas in the area. It's also important to note that the governments of E.G. and Cameroon recently completed a pre-unitization agreement, which will further support development of discovered resources.
In the second quarter, we plan to spud the Aseng 6P well, which will further mitigate production declines and assist in reservoir management. This well is expected to begin drilling in June and be online in the third quarter.
Now let me provide some guidance for the second quarter, which is still in line with our previous plans. Capital for the quarter is estimated to be in a range of $675 million to $750 million, with most of the capital spend in the U.S. Onshore and the Eastern Med regions.
Total company sales volumes in the second quarter expected to be between 332,000 and 347,000 barrels oil equivalent, reflecting increasing U.S. Onshore volumes and essentially flat international production. Internationally, we expect our Israel volumes to be down slightly in the second quarter due to Israeli holidays and West Africa volume should increase slightly due to plant Alba maintenance, which was completed in the first quarter, right at the end of March. Full-year production and capital guidance remain unchanged.
Before I wrap up my commentary, I want to just reiterate how pleased I'm with our operational performance and execution. Across our U.S. Onshore and international assets, we saw higher production and a path to lower sustainable cost and we expect to drive efficiencies further across our organization. I expect this operational momentum to continue into the second quarter and throughout the year, as we bring online our highest TIL count in 2019 and the onshore ramp up in the back half of the year.
In West Africa, the Alen gas monetization project will add to the low decline production base and free cash flow profile of our company. And in Colombia, we finalize the exploration opportunity as we seek to build out our inventory of discovered offshore resources.
Slide 15, summarizes some of our Q1 accomplishments and other key 2019 deliverables, which are leading us to year-end and to the defining moment of Leviathan first production.
We'll now open the line for questions. Operator?
[Operator Instructions] The first question comes from Brian Singer with Goldman Sachs. Please go ahead.
You highlighted a number of the cycle time in capital efficiency improvements in your comments. Do these represent the entirety of the below guidance capital spending for the first quarter or the timing of activity play a role as well? And you mentioned in your comments, Brent, I believe, that you may have a choice to make on more activity for the same budget or same activity for lower CapEx. How would you frame which route to take given the goal of free cash flow?
Yes, let me tackle in the order you asked them. So there was a number of things that we benefited from in the first quarter from capital, we definitely have improved efficiencies or shorten cycle times and our drilling and completion and our facility activities. I might get Hodge to comment on that in a moment. But we also had different – lower discounts that we negotiated with our suppliers. And then there was primarily in the case of the Eastern Med some timing where we delayed some of the – or the spend will come in the second, third quarters as we move toward first production in Leviathan.
But also remember to offset that, we've accelerated effectively about four, four wells. They're not – parts of wells, but about four, four wells into the first quarter. So our savings have overcome incremental activity in the U.S. because of the efficiencies and lower cost. So and in terms of how we think about – at the asset level how we think about the incremental capital is that, if we decide to deploy it, it's going to be based on the merits of the projects that we have in front of us. So based on the safety performance, the well performance, the cost performance, the returns at the well level, we'll debate that how we allocate that capital at the well level between the assets.
And I think, Brian, just back up and take a higher level view of the cash flow portion, don't forget the way I've laid it out, what we're looking at on incremental cash flows continuing to strengthen the balance sheet or accelerate strengthening the balance sheet shareholder returns. We highlighted that with the dividend increase here just recently. And then we look at the activity and how that plays out.
And then my follow-up is on industry consolidation and applicability to Noble as you see more of these moves here and the push for scale. Do you think Noble's Permian assets are sufficiently positioned to be industry-competitive with scale? Or do you see the opportunity and/or need to participate in consolidation in some way in the basin?
Well, I think what you've seen us do on the Permian was around getting the scale and consolidated position that's important. I mean, scale and especially a consolidated contiguous position in any basin is important. And I think that was a big driver that helps us to generate very competitive and our expectation drive industry-leading returns over time in the basin based on where the assets are located and how we position that.
So I'd say, we're very comfortable with what we have and the thought process that went into building that, and the quality of what we have, and the results we're seeing there. So I think we're in a good position there and our focus is on continuing to prove the folks that we can get more out of these assets than anybody else.
The next question comes from Arun Jayaram with JPMorgan. Please go ahead.
I wanted to start in the Eastern Med there has been news in the press recently around Jordan and the gas price that underpins the Leviathan export contract. What are your thoughts there? And any potential risk here in terms of the Jordan contract?
I think you go back to the Jordan contract that's been a fully executed and binding contract. I think everything that everybody is focused on their and everybody we’re engaged with has been towards moving to first production. So that's been the continued focus from our standpoint. I think there is a lot of anticipation and desire to get this thing on production, Leviathan on production and that's where we're maintaining the focus.
And then my second question is just, I was wondering, Dave if you could help us maybe frame the cash flow potential for Noble for the Alen project. And I did note that the pipe that you're building will be a pretty large pipe and what are some additional opportunities to monetize gas resources that you have in that part of the world?
Yes, let me, start with that and Brent, can add anything that he wants to. But the Alen project and we rolled out with the sanction some of the parameters around that. One thing, not to forget, there's a number of thing that's important with that project. One, it's the backfill in Punta Europa on the LNG facility and the ability to move gas into a contractual arrangement that provides us access to the global LNG market and a significant portion of that value that our partnership will share in.
The other couple of things to it, there is also not insignificant condensed liquids volume, I'd call it condensate NGLs that will be part of this. And then the third nice value component of this, before we get into the longer-term portion, is that it extends the life of Alba and there is a nice value proposition for the Alba field itself which we get to share in obviously. The second part of that is the longer-term picture of this and we have about three Tcf of discovered gross resources in the region.
And as, Alba field declines over time and more room becomes available in the plant, we'll have the ability now as you said with some of this pre-investment at very little extra cost, to size the pipe to be able to tie in these very close proximity, projects. And Brent may be able – want to talk a little bit more about how that fits going forward.
I think it’s great summary, Dave. The only thing I might add is, if you think about we're backfilling the capacity this opening up from field decline. So to our project early on, it's going to look like a growing wedge of production and cash flows over the first few years. And then it will look like a very long-term stable set of cash flows with relatively low investment rates to bring on the discovery gas. So it's got a very appealing cash flow profile to us.
The next question comes from Scott Hanold with RBC Capital Markets. Please go ahead.
Couple things, one in the Permian Basin and appreciate giving some capital spend detail by area. It looks like Permian Basin costs have come down to maybe below $10 million, is that right? And is that something you all think could be fairly sustainable or improve going forward?
We do Scott, I think your math's right. We talked about targeting $1 million to $1.5 million a well. And we're well on our way to realizing that from the combination of a faster, shorter cycle times, faster operations and lower cost. And so I think, if you think about the type well as a 7,500 foot type well you can use $9.5 million or so per well. And remember some of these will be longer laterals, quite a few will be longer laterals. So we may average above that, but we're – the message is, we're realizing the cost savings that we targeted.
And then you all did identify that you've picked up some acreage in Wyoming now. And it sounds like in a couple different basins is, is there any more specifics you can get on what area you're targeting is that Powder River Basin. Is that Green River Basin, what are you all looking at up there?
Yes, I mean we're still doing some leasing. But I can say probably little less than 50% of it in the Powder just to give you some feel. And it's probably about as far as we want to go at this point. What I'd say is we'll probably be ready. I expect we'll be ready to drill a couple wells in both basins next year, so that will give us some good insight.
And I would assume you all are targeting in oil, oil play right?
Liquids rich plays for sure.
The next question comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead.
Just wanted to I guess maybe get a little bit - just kind of timing of TILs. I think you alluded to 15 to 20 I think in the Delaware, in the second quarter. You also had accelerated TIL schedule in the DJ relative to what we are expecting in the first quarter. And I'm just trying to think through kind of the timing of how those TILs plays out over the rest of the year and how to Q2 and compares to the second half?
Yes, I think the best way to summarize it would be the second quarter will be our highest TIL activity for the year that's partly by design. It's also partly because of the increased pace of development this bring, some of those into the quarter.
And then, remember that that there's about a quarter lag generally from when the, you know the production versus the TIL the highest TIL counts. And you can see that even in the charts that we included in the materials, you can see as our TIL count start to increase. The production picks up about a quarter or two later that we get the benefit of it. So first three quarters loaded on completion activity, back half loaded on production profile.
And just to follow up on that. On the DJ, how many would you expect to see in the second quarter?
30, we're bringing on about 30 wells in the second quarter in the DJ.
And that's largely and they are staying still?
The mix of Mustang, I think we've got some East Pony wells in there also.
And then I guess, I just wanted to kind of follow up a little bit on Brian's question around scale, just to make sure, I heard you right, I suppose. So like relative to the acreage position you guys - you're going to had assembled post the Clayton Williams deal, obviously with the acreage sale you highlighted this quarter and alluded to last quarter that total acreage position is down somewhat. Are you at all open to continuing to expand that position or at this point is the position as it stands today sufficient from your thinking?
So, Michael, a couple of things. Just as a reminder, our current full year pace of development is 50 to 60 wells in the Permian. So we've got plenty of running room. So we don't feel compelled that we have to do something right away.
And as Dave mentioned, our view on it is if we can demonstrate to ourselves into the market that we are the low cost, most efficient, highest productivity, highest per well return operator, then I think that would make sense to everybody that we would be the larger consolidator of it. And so we're not opposed to that, but if we do it, I think you - we'll make the case that we did some day would make the case to you that we're logical operator to do. But we're not compelled to do it, because we're in good shape right now.
And as Brent said, if we've got over a decade easily of opportunity, high quality opportunity here. And so the focus near term is on the blocking and tackling, the coring up with trades and so forth, like we've done in the DJ in and around our position. So we can have more efficient row development and longer laterals.
Okay, clear enough. So not in a hurry today but opportunistic, if the environment presented itself.
I like it, as Brent said, you've got to earn it.
The next question comes from Doug Leggate with Bank of America. Please go ahead.
I've got a couple. Couple of quick ones hopefully. Dave, you walk through your thoughts on NBLX and I understand you probably don't want to elaborate too much, but assuming you did generate a reasonable amount of cash out of that in some form or another. How would you describe your priority for use of cash in terms of whether it be buyback or other users if you could consider?
Well, yes, I'm not going to speculate obviously on anything with NBLX because all kinds of ways that can play out has a tremendous value there. But I think in general, when we look at incremental cash flow, I tie it back to what I said previously where it's accelerating strengthening of the balance sheet, returning additional value to shareholders, whether it's through dividend increase, the sustainable cash flow increases or opportunistic buybacks, things like that. And then, those are really the two at the top of the list for us.
I thought, I'd give a go Dave. I wonder if could just dig a little bit on the midstream, - sorry, on the cost guidance, the midstream element of this marketing. I think it's like kind of legacy liability. I wonder if I can ask, Ken, maybe just to walk us through what the mitigating options are for you to maybe eliminate that cost over trend. My guess is, it's related to some legacy Marcellus issues, but obviously there is other ways for you to offload that at some point. I just want to get a handle as to what will happen to those costs going forward?
Yes, Doug. This is Ken. In the quarter we offloaded about $350 million of transport commitment to Southwestern at about 100,000 MMBTU a day from 2021 to 2032 we recorded a liability for that of $92 million. And so that commitment and transport cost that transfers to the counterparty. So going forward, we'll continue to work that balance and probably the cost is in the range of $30 million a quarter this year of transport commitment that we'll continue to work to mitigate.
The good news is, Doug, that a lot of that transports located in parts of the world where from time-to-time it's going to be valuable. So that's going to give us options like we had in the first quarter.
I appreciate that. I wonder if I could squeeze just one really last quick one. And it's just when you get the East Med gas pipeline up and running. I'm just wondering if - can you maybe give was the prognosis as to what that does to the line of sight on further expansions in Israel going forward? And I'll leave it there. Thanks.
Yes, Doug. I think the way to think about the further expansions in Israel is really focused on selling out the full capacity of Leviathan. So if you think about it right now, we've kind of got the 900 million a day contracted there and that's against the 1.2 Bcf a day capacity.
So think about 300 million a day of essentially free capacity to be expanded by accessing additional contracts, expect those contracts are most likely you need, but certainly we're seeing demand across all three of the major markets that we're in there Israel, Jordan, as well as Egypt. So watch this space.
Yes, I think, I'll just add on little. I think, as we've talked in the past. Our objective here is probably to contract maybe around 1 Bcf a day and not the full 1.2 Bcf a day. I think when Leviathan comes online, we're going to be very pleased with the fact that we've got a little more capacity there, because it will be interesting to see how quickly some of this demand ramps up pretty fast as Keith said, when you talk to the customers and you look at what's going on in the area. My expectation will see that capacity demand fill up pretty quickly after we start getting things online and get a year or so into this.
Seems you've got a lot of low cost options Dave, going forward to that. Thanks a lot.
The other thing, I'd add it's very similar to the discussion we had in Alen is that we start off at an average of 800 million a day next year as that market demand grows, that's going to look like an inclining production profile and set of cash flows. So I think that's the long-term huge competitive advantage for us.
The next question comes from Irene Haas with Imperial. Please go ahead.
I'm happy to see you guys going back offshore again. So I have one question on your offshore Colombia project, which is on the Caribbean coast and it comes in five parts, any existing discovery on trend? Number one, number two is this production sharing contract and what's your minimal ore commitment. How much it cost to drill the first well? And then also how many years of delineation and ultimately with the infrastructure build - would it be a FPSO type situation when it comes to development?
Yes, I'm not sure, I got all of those, Irene, I'll try with some of this. But it's a - what we're excited about here is, it's a opportunity that we've been working on for a period of time here. And to get in, with a high quality partner or joint venture, co-venture as Shell, I think will work well for us. We've matured this thing enough to whether it will be ready to drill next year, probably half of the total depth is in water. So I don't remember the actual cost per se. But it's a reasonable cost for a prospect with a high geologic chance factor. I think the geologic chance factor is probably 40% or more.
And so I think the big thing that we'll be looking at here is, liquid versus gas type of a thing, I think, we think there is a very good case to be made based on our regional view, our seismic understanding and some of the analysis of other items in the area that this could be a very high likelihood of an liquid project. And it creates the opportunity with success to derisk other opportunities, just like we've done in the Eastern Med and West Africa.
So it ties in very well with the types of things we've been successful in the past, and it gives us an opportunity for something that's relatively low risk, fairly decent chance of hydrocarbons and something that could be very material with some success here. I don't know if I answered all of those or even a part of those type of things, but that kind of explains why we're there and what we're looking for, and I'm excited to get chance to drill it next year.
I have a follow-up. Are there any discovery of fields on trend offshore there?
Not specifically tied into this what we call this depositional environment, I think if you go further South, if I remember right. There is some gas down there. So there's hydrocarbon indicators, if you will, but based on our analysis and our thermogenic review of this and so forth. We think there is still a pretty decent likelihood that this is going to be more of a liquid play. That's our target objective.
The next question comes from Welles Fitzpatrick with SunTrust. Please go ahead.
But I'm not going to ask on any predictions on NBLX obviously, but is there any way we could get an update on an approximate cost basis of the assets NBL given the distribution stream?
No, I don't think here.
Fair enough. Thought I would give it a shot.
Then so Weld County on Monday they obviously move towards designating unincorporated wells as a local control County area. Does that you are you guys still looking at additional CDPs you don't already have in progress or does that basically derisk the regulatory environment enough yours acreage?
Well, I think you saw the impact of our first CDP and so we're continuing to look at, if there are some areas that makes sense to pull another CDP together. Again that really only works when you've got the highly contiguous large positions like we've pulled together over time. So I think all that work to consolidate our acreage position stay in rural areas is going to payoff significantly. As we move forward and that may provide the opportunity to have another CDP or so over time here.
Yes this is Brent. As Dave mentioned in his in his comments, I think that our objective is to be able to extend our planning horizon, as long as we can and get ahead of any of the regulatory changes that are going on and be prepared to be able to work effectively at all levels of government and regulatory bodies.
The next question comes from Charles Meade with Johnson Rice. Please go ahead.
I just have one question, can you give us a little bit more detail on the quarterly CapEx specially for the Leviathan specifically I imagine that lot of the CapEx is up the 2019 CapEx is behind us with all the subsea work that's been done. But I wanted to just check, that assumption to get an idea of how it's going to progress 1Q, 2Q, 3Q, 4Q?
We have an updated Charles on the full year yet. We guided to 500 – we commented 500 million to 550 million for the year.
The next big update the logical next update time would be when we install the production index. That's a big events, it’s a big lift and once we get those in place. We'll have a better estimate and that'll be third quarter time we'll be able to tidy up everything for the year. But hopefully picked up on all of our comments and all phases, we're on track on the project.
I think, behind the scenes, some of the things are doing on the function testing, getting things ready to tie in. If you go back and remember why did tomorrow come on so well and so reliable was all the function testing that was done before you even hooked everything up on the platform. So I think we found, that's been a key in all our major projects has given that exemplary track record that Keith and his folks have been able to exhibit.
The next question comes from Gail Nicholson with Stephens. Please go ahead.
Your LOE we improved quarter-over-quarter. But I was curious just diving into the U.S. portion LOE what is the delta on a per BOE basis and LOE and the DJ versus the Permian. And do you think that there is more improved for LOE reduction in the Permian, as you progress in this full growth development process?
Yes, we do - you got to keep in mind the DJ, is an older more mature development. And so we've been able to drive more efficiencies into all aspects of including the production operations. Delaware is less mature and was growing very aggressively last year and we were putting a lot of the infrastructure in place and building out the production capability last year. This year we're focused on being able to drive efficiencies through that program. So there is that difference that makes Delaware higher. And then the other differences we handle more water in the Delaware. And so, those two issues are the differentiators and the two basins cost structures.
And then my follow-up in the DJ you guys are doing in East Pony activity PILs in the second quarter. Are you guys doing anything different in the completion style design up there that previously you just kind of discuss that the East Pony?
Not really. The thing that we're looking at across the basin is the application of some lower fluid volumes per stage and some different classifiers that may have an application up there. But otherwise it's business as usual.
The next question comes from Nitin Kumar with Wells Fargo. Please go ahead.
I just wanted to touch on the well results in the Delaware Basin this quarter, obviously a nice tick up in average productivity from the Southwest Reeves wells, you did highlight that two wells were drilled. I'm sorry the northern wells, but two wells were drilled in Southwest these were HBP they seem to be quite a bit weaker. Anything going on with the geology or the completions in that area?
Yes, they weren't drilled. They were tilled there were completed and tilled so they are older wells that we've drilled that we completed in the first quarter. But yes, it's different geology, when we've talked about a fair amount when you move to the far Southwest and that's consistent with that area that we divested in the first quarter. And so it's a different performance, you can see it across all operators in the region.
And then just maybe following up on some of the other questions around Noble X. Leading aside, you mentioned the two uses of free cash flow in terms of returns to shareholders. Where does the exploration fit into that prioritization, last quarter you had mentioned about I think about $100 million to $200 million, but you'd also disclose a new play in the PRB and Wyoming. Could you help us just think about the cost involved that exploration effort?
I think it's a good question, because I don't want to leave any confusion but the exploration capital and our plans for exploration is consistent with what we laid out in our plan last often change there. We outlined our sight to these opportunities and activities and had planned for that. So that's all contained within that wedge of bucket or I call it bucket of capital that we allocate the major projects and exploration. So no change to that. And the big difference is, as we move our exploration dollars into 2020, a large much larger portions now moving into drilling in 2020. So looking forward to that.
And if you’re going to sneak just one last one in. Nice tick down in well costs, particularly in the Permian, as you mentioned earlier. Was any of this coming from discounts from vendors or is this all operational?
It's a combination as you would expect, if you look at the completion services in the Permian, there is a quite a lot of excess capacity still and so therefore, we're getting better pricing. And then remember last year, if you look across the full year, 2018 it was pretty, pretty busy out there and the cost had inflated. So we're definitely lower cost on the completion side, but it's also a function of us operating faster. So if we can increase stages per day and we can minimize the dead time and the waste in the completion activities. Then we get the dual benefit of lower cost and accelerated schedule, accelerated production coming online. So it's always a combination of both.
The next question comes from Vin Lovaglio with Mizuho. Please go ahead. Vin your line is open. Is it muted on your end?
And the next question comes from Jeanine Wai with Barclays. Please go ahead.
I just wanted to follow up on Tim’s question real quick on the Permian. Can you talk about the differences in oil, well productivity between your northern and southern positions in the Delaware. I know you mentioned you had some attention wells, you let go some acreage in the Southwest portion. So just kind of wondering the difference between the two and whether when you look at the lateral lengths, whether they are longer in the north or longer in the South and where your inventory kind of lie to go sometimes I guess the acreage maths can be a little deceiving on that.
Yes, on in terms of lateral lengths, we are going to drill on anytime we could drill two section links or 10,000 foot laterals. It's going to be our preference to drill them longer. If you look at the average well performance for the first quarter, including the four wells, on average we're happy with the outcome, but if you look at the difference between the northern and southern wells, we were well over 200 barrels, barrel equivalents per 1000 foot of lateral and as for a 10,000 foot lateral that'd be close to 2000 barrels a day. And so those are clearly the core of overcoming, the core of Reeves County is clearly the best that we have in our position and I think competes really well with the rest of industry there.
And then I guess along those lines, 95% of your activity is focused in this northern core acreage CGF this year and as you look over the next year or two, kind of, how does the geographic spread of where you think activity is going to be, how does that change. And is it more related to the CGF or is it something about maybe getting the well cost down or tweaking the completion design to have the southern acreage being a little more competitive with the north?
But the southern acreage is already competitive with the north, it's the far southwest in the far maybe the South acreage that's different. So everything that we have remaining, we consider core and we'll always look to optimize Jeanine anytime, we can find a way to do either improve the completion design or change the frac design, change perforation designs, we are always looking for ways to do that. But we're happy with the bulk of the rest of the acreage position.
And I think it's fair to add as Brent alluded to earlier that, a lot of the activities tied to taking advantage of the CGFS that we have in place because we get a real economies of scale as we continue to take advantage of that. So the activity will be focused around there.
Maybe we ask Hodge to just give you a few examples of how he is doing it. I'm really proud of the accomplishments of the team in just a quarter to be able to drive these efficiencies. So Hodge give them a few examples of how you are doing it.
Yes, thanks, Brent. Our teams are really been focused on driving out waste and identifying efficiencies, strong alignment between our service providers, our field team our office teams on continuously improving and we're not done.
As Brent mentioned earlier, we drilled a well in the Permian in 16 days. This is below our average, if we've done it once we can do it again. So areas that we're focusing. We talked about pumping hours that improved between 5% and 10% and we've seen examples on a given day where we've been pumping over 20 hours in a day. So these are examples of things that we've seen and examples on where we're going to keep striving for continuous improvement.
The next question comes from David Deckelbaum with Cowen. Please go ahead.
Just wanted to ask when you write off your original plans here divesting $500 million to a $1 billion were you specifically thinking about NBLX just opportunistically at that time. Or will you more thinking high level of just in absolute dollar amount that you wanted to arrive at and with NBLX achieve that for you. Are you still looking at another source of monetizations throughout the year?
I think what we reflected was we're always looking at the portfolio and it wasn't specific to NBLX but it was tied to the number of things we continue to look at whether it's some of the things on - in the onshore space that we can accelerate value on.
Sell down of midstream assets, we talked about Leviathan potentially monetizing a small portion of that when it comes online or sometime after. So it's just the whole mix of continuing to look at the portfolio and with that, what we saw is a reasonable expectation on what we should be thinking about this year? So nothing specific. And don't forget, we've already completed 15% to 20% of that target in the first quarter. So we've already progressed that.
And then shipping in the DJ, as you progress through road to a new move I suppose further east, how does the GOR shifts as we get into 2Q and 3Q here. Should we be expecting a greater gas cut on moving into the sort of a higher GOR area or should we think of sort of your 1Q being the highest GOR in that row?
Yes. So a couple of things in there. So at the well level and there is a chart on Page 6 in the materials we put out that might be useful reference for everyone, where we actually show the gas oil ratio trends across the greater part of the DJ there where our acreage is located.
At the well level what we'd expect, as we move east and north. If you think about where East Pony is up in the north, that we move east and north, we should see higher oil cuts or lower GORs at the well level.
And then we're going to be averaging added to the total field production. So the trend should modestly trend up as we continue to develop this year. We guided originally, I think to 48% to 50% will be trending toward probably the lower end of that range through the rest of the year. The other thing noticed, I hate to talk about things out of period, but we did have two things that affected the oil percentage in the quarter.
One of them is that we had a fairly sizable gas PPA that came in that was positive. So that has the effect of lowering our oil percentage. The other is, we've done a good job of improving the recoveries of NGLs. So we had higher actual NGL recoveries, so when you look at those things together, they reported 46% oil would be a little by 47%. So I think it's, think of it as 47% trending up to 48 plus.
This concludes our question-and-answer session. I would like to turn the conference back over to Brad Whitmarsh for any closing remarks.
Yes, just want to thank everybody for joining us today. As I wrap up, I want to mention that Noble has recently issued its 8th Annual Sustainability Report covering a variety of social environmental and governance topics. That report is available on our website on the sustainability tab, and I hope you have a chance to look at the continued advancements that Noble is making in these areas. Should you have any follow-up questions for us today, please don't hesitate to reach out to Park, Kim or myself. Have a great day.
The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.