Dave Stover – President, COO
Bill Featherston – UBS
Noble Energy Inc (NBL) UBS Global Oil & Gas Conference Call September 18, 2013 11:00 AM ET
Bill Featherston – UBS
And if I could ask everyone to get seated; we’re going to move on to our next presentation. I’ve been asked to remind everyone that these presentations are being webcast. So, when we do move to the Q&A, if you could wait for the microphone to ask your question.
Our next presentation will be Noble Energy, which has been one of the top E&P picks at UBS for over the last year. Specifically, we’re attracted to its cash flow per debt-adjusted share growth, which we see at over 25% per-annum growth over the next five years; yet the stock trades at a discount to peers on price to NAV.
They’ve got a very broad portfolio that’s driving this growth, and we’ve the good fortune of having Dave Stover, the President and Chief Operating Officer to tell us about it. Dave?
Okay. Thanks. Thank you, Bill, and it’s great to have the chance to come back and visit with everybody again.
I wanted to start with – and it's something probably a little different, maybe unique in its own, right – is just starting with the cover of our annual report, which is unique by design and our purpose, which is Energizing the World and Bettering People's Lives.
But you know, the design part of that, I wanted to start with first – for those of you that have been with us or that have followed us for a number of years, you’ve seen a lot of change in the Company. I know we’ve built something that 10 years ago was a little over $2 billion market cap to now $23 billion or more market cap.
And that isn't by accident. I mean, that has been a focused effort on creating and building a sustainable long-term future. And what I’m probably even more excited about what is still ahead of us or what’s in front of us, and we’ll show you a little bit about that. Bill alluded to some of our outlook on growth, and we’ll talk about that, but really underpin what are the assets that are driving this and driving this future.
When you think about the unique aspect of the Company, we believe we’ve assets that are probably more indicative of something of a much larger company, but yet we’ve a growth rate and an outlook that’s, I’d say, unique for a company our size, and we’ll talk about that and really talk about what underpins that and what underpins our confidence in delivering.
Again, we put about 20% of our capital into exploration. We’ve had a tremendous success rate on exploration. I’ll walk through some of those areas, and we’ve a large portfolio of big-impact material items that are coming up, some of which are drilling today.
At the same time, we’ve really concentrated on taking discoveries, new discoveries, especially big offshore discoveries and quickly monetizing them and executing on major projects. We’ve now brought about four big, significant major projects online over the last two years, and we think that’s unique – especially unique for a company our size.
So, you look at it and you start with this year. Our growth rate this year, when you take the midpoint and adjust for divestments is up about 20% over last year, and you see that is underpinned when you just look at third quarter to third quarter on there. A large part of it is driven by our onshore US resource development, essentially our activity – horizontal activity in the DJ Basin and horizontal activity in the Marcellus; two of what we would consider premier horizontal plays in the US. And I’ll get into much more detail on each of those as we walk through the discussion.
At the same time, I mentioned some of the new major projects that we’ve brought online, and these are truly major world-class projects. The one earlier this year at Tamar, and I’ll get into that a little bit, and then the one that we started up at Alen, actually started up earlier than originally anticipated.
At the same time, we’re progressing a number of additional major projects, part of what will underpin this future growth. Significant sanctions coming yet this year, some have already happened, some will still be coming down the road in, for example, the Gulf of Mexico at Gunflint in the Rio Grande area, and then in West Africa an additional expansion in the Eastern Med.
I mentioned the exploration upside and some of the activity going on. We’ve got a couple of wells – Dantzler in the Gulf of Mexico, I’ll show you a little bit more color on that as we walk through the discussion. That should start to drill here yet late this quarter into beginning of next quarter, and we should really be positioned to have results on that by the end of the year.
At the same time, we’ll have results on our first prospect in Nicaragua, which spud recently; so that will be an exciting opportunity to follow. And at the same time, we’ve started our first drilling activity in our large resource play, and we’ve about a 350,000-acre position in northeast Nevada. So, we’re starting our first vertical well there right now. So, a lot of exciting things going on in the Company.
Here is what we’ve mentioned earlier. When you look at our five-year growth outlook and you look at it on a debt-adjusted basis taking into account what it is going to cost to develop this, on a production, it’s just a little under 20% – around 18% is our projection, but you can see on reserves, that it is a little higher. And then on cash flow, it’s up even further. So what we’re saying is we actually expect cash flow to grow faster than production. And you will see that is underpinned by the quality assets that are coming online, and especially the reservoir quality and produceability and deliverability of some of these fields.
Another key point is the return on capital employed and how we expect it to grow. Again, a large part of that growth into the mid-teens or higher by 2017 is underpinned by really $10 billion or more of investment we’re putting into the DJ basin over that period of time on returns that continue to grow – or returns that have been higher than what we’ve had even in the past also is reflective of this growing cash flow or growing increase in the margins of the business over that period of time.
And then, the sustainability part, which we've mentioned, that was the five-year outlook. When you really look through the end of the decade, we see double-digit growth really positioned from the discoveries that we’ve had and the continued acceleration of these onshore plays in both the DJ Basin and the Marcellus.
We start with the onshore – we’ll call it unconventional development areas, the plays in the DJ and the Marcellus. It’s about 60%. When you look at what we depicted at the end of last year, it’s about 60% of our discovered resources, and it’s taking about 60% of our capital program right now. And I think the forecast, even if you look out through the five-year period, is about that 60% to two thirds of our capital will be put into these two plays.
Both depicted by as we’ve gotten into them, we've continued to move up the EURs in these fields. And we’ll kind of highlight each of these areas as we talk about it.
And performance continues to improve. I mean, we’re still – as folks will continue to ask what inning are you in these plays – and I’d say we’re still in the early innings of both of these, probably even earlier innings in the Marcellus than the DJ, but both with a tremendous amount of running room and opportunity yet to unlock in each area.
Here is a depiction of how production or volumes have grown through the combination of these two areas. And we’ve actually broken it out. In the gray bar, you can see how we’ve really moved from a vertical world and impact in the DJ to a horizontal program in the DJ Basin. It’s been amazing to look at and to follow just how quickly that program has become extremely significant. It’s now overtaking on a volume basis. In just a little over two years, it has overtaken the vertical contribution in the basin.
And the reality here, when you look at it, I think we were somewhere between 105,000 and 110,000 for last quarter on total combined volume from our onshore. I think looking at it here in early September; we were already up to around 125,000 barrels of oil equivalent per day. So we’ve already seen a significant increase in the third quarter in contribution from the onshore program, and a lot of that’s been driven by the new wells being brought online in both areas.
Start with the DJ Basin. I’m sure everybody has got on their mind the flooding situation up there late last week and into the weekend. I mean we’ve been extremely fortunate that it hasn't been a significant impact to our operations.
But you can't say the same thing for the surrounding communities. I mean, it has been a significant impact to the surrounding communities, and we’re very sensitive to that. And I am extremely proud of what our employees and the folks working with us and how they’ve responded to that situation up in Colorado.
You’ve probably seen some pictures of the flooding in the communities and the inability in some places to move around, to have basic emergency needs. I mean, a couple of the things we’ve concentrated on has been delivering portable toilets, if you will, portapotties, and bottled water to the communities.
I mean, one example, just over the weekend, we had 40 employees, because they ran out of portable toilets, that actually got kits of I think about 80 of them, and were actually sitting there building these things and then delivering them over the weekend.
So, a tremendous – it speaks tremendous volumes to the connection with the community, the responsibility we feel to the areas where we work. And I think it just says a lot about the industry's reaction to adversity. We’ve seen it other places around the world offshore, and now in some of the onshore communities, but I think it speaks volumes about the industry's ability to react to adversity and truly care about where we work.
So, I wanted to start with that, before we get into the future of the DJ Basin operations. It’s an extremely bright future. If you look at what we did this year or what we’ll do this year as far as activity level, I think on a pure well basis, we’ll be up 50% over what we did last year. On a horizontal footage, which is probably the piece to look at closer, we’ll be up over 50%, probably closer to 60% to 70%, over activity last year, as we continue to expand the lateral length on some of this program.
You can show our – you can see our position on the map, what we now call the Greater Wattenberg area. And you just think about the transformation of this. I mean, when we first got into this play through the Patina transaction in a large way in 2005, I mean, this was a vertical program, probably considered a vertical gas program, more dominated or predominantly the production was out of the Codell, and just starting to test the Niobrara.
As we started to test the Niobrara, we got more and more intrigued by the potential, especially as you saw some of the horizontal work going on across the country, or just the potential to unlock and break out a new play here. And that is exactly what has happened. And that has transformed this basin, if you will, from a vertical gas world to now a horizontal oil play. And I’d say a top-tier oil play, especially when you look at the economics of the play. So, it has been a tremendous change and is extremely interesting to watch, but yet there is a lot of things yet to do.
What we found is the way we were initially approaching this on a horizontal layer in this B interval. And again, you’ve got 300, 350-foot interval, with the B interval kind of in the middle of it. You know, you’re still getting a very low recovery, even when you get down to 80-, 40-acre density on this.
So, what we’ve spent some time this year is actually looking at what is the optimum pattern for the future. And we’re looking at various staggered patterns that take into account different layers, if you will, of the formation. So, I think that’s something you will continue to hear us talk about more as to just how do we optimize recovery and impact economics out there. But we’re putting in around $1.7 billion or close to 45% of our capital this year, and I have mentioned the forecast is for closer to $10 billion over five years.
One of the things that I think will be very intriguing and exciting as we continue to move through this, we’ve got the opportunity with our positions kind of in the northern part of the field and up into northern Colorado to have some fairly large contiguous acreage positions, things that are 20,000 to 40,000 acres. And one of the things we’re looking at now and we’re actually moving towards, which I think will help unlock additional value going forward – well, I know it will – are these integrated field development plans, almost like hubs of production, if you will, around the field. I mean, Wells Ranch being one of those. East Pony that we’ve talked about in northern Colorado being another opportunity for that type of thing, where you’ve got large hubs of production gathered in central places, and also coming in off of very large pads.
Now if you think about it, what you’re really looking at is managing this field in different areas on everything from the subsurface through the surface and transportation beyond that. What it will enable us to do is take more trucks off the road, have a smaller footprint, if you will, and consolidate through pipelines and so forth how we move both water and oil up here. Effectively get some synergies in the system, more synergies down the road, but it will also enable, as we go down the road on this, more acceleration of the program by things not having to move as far. So more usage or more efficiency per equipment, if you will.
So this is a pretty exciting concept that we’re moving through and where we’re going with this. And It’s kind of an expansion, if you will, of our EcoNode concept that we started a year or two ago.
Again, one of the things that has really opened our eyes up here has been the performance of the extended reach laterals. And you can see on this curve our original base, 750,000 barrel equivalent type curve in black. And then you can see a 1 million barrel type curve up there in red. And our average of these first 11 wells of extended reach length kind of in green, kind of hovering right in between those two, with some – definitely a few million barrel look like wells, and then, like I said, on average, somewhere in between there.
So this is something we’ll continue to look at pretty close. And if you really look at how we bring these wells on, we bring them on slowly to begin with, try to minimize any formation damage, and then I really had to question our folks for that 30- to 120-day period where they stayed pretty flat. I wanted to make sure we weren't adjusting chokes or anything, it was an impact of that, and they’ve sweared we’re not.
So this is true well performance out there. And what you’re seeing actually is out at the toe of these long laterals, just very little drawdown and really probably enhanced performance out there. So all about minimizing any formation damage.
Shifting to the Marcellus active program. We’ve actually increased our wet gas activity this year. If you recall, we’re the operator in our joint partnership with CONSOL of the wet gas part of the program, and CONSOL operates the dry gas. The dry gas has been more concentrated in southwestern Pennsylvania, while the wet gas program so far has been focused in West Virginia.
And you can see we’re bringing on a number of new pads right now, and we’ll continue through this year. So you see actually a nice increase of volume through the whole second half of this year to where we’re now targeting an exit rate at the end of the year of around net 210 million cubic feet equivalent per day, which is double what we actually averaged in 2012. So the program continuing to grow. As I mentioned, we’ve actually ramped up the wet gas activity this year from last year and actually scaled back the dry gas. But I’d say the economics of both have held in very stellar through actually the lower gas price environment.
Let's turn to the offshore and spend a little time on that activity. Part of what we did earlier this year when we were looking at how do we want to run the Company five years or 10 years from now, we structured how some of these assets are combined. I should have mentioned actually in the onshore we’ve now have got all the onshore set up under one senior executive, to where we’re able to transfer more easily the learnings from the DJ to the Marcellus or Marcellus back to the DJ. We actually now have an individual running the Marcellus who was instrumental in getting the DJ horizontal program kicked off.
Here in the offshore, now we’ve put everything together with the exception of the Eastern Med, Israel, Cyprus portion, into one piece, now to where we can get the overlap and learnings between and transfer of knowledge even more quickly from, say, the Gulf of Mexico to West Africa to some of the new projects we’re doing, things like Nicaragua, where we’re drilling.
But when you look at it, exploration success has been a key driver of the growth in our offshore business, whether it has been in the Gulf of Mexico, whether it has been breaking out a new play in West Africa, like we did a few years ago, or just unlocking a whole new industry in the Eastern Med, in offshore Israel and offshore Cyprus.
We’ve now brought four major projects online at cost or below, and in timeframe or accelerated. Two of those actually were offshore West Africa. Tamar and Alen, this year, I’ll talk about each of those in another minute. And then we’ve had additional discoveries that continue to expand this growth profile and add to that, and an inventory of projects. And I’ll finish the discussion today on some of these exciting new impact exploration potential catalysts.
Start in the Gulf of Mexico, in the Deepwater Gulf. You know, It’s an area that the experience we’ve had there. We’ve been able to transfer to some of the other places around the world. Our most recent discovery was this Rio Grande area combination of a Big Bend well and a Troubadour well. Even though Troubadour was more of a gas discovery, it really gave us a lot of information on the Big Bend area that indicated and provided insight that that Big Bend area was probably actually on an oil column a little thicker than we originally anticipated, and probably a larger aquifer in the area, to give you, at the end of the day, a little better recovery.
So we now have discovered – not anticipated, but actually discovered, resources of 50 million to 100 million barrels equivalent, 75% of that oil. We’ll sanction the project yet this year, I expect, with the idea and the expectation that we’ll bring on one to two wells – these, again, are highly prolific Miocene producers – bring on a well or two by late 2015.
Talking about one of our other key projects bringing online this year in West Africa, offshore Equatorial Guinea. We brought Aseng on last year, an oil project. We brought Alen online now; it started up earlier – actually started up much earlier than we had originally forecasted when we approved the project, and it's continuing to ramp up. And it’s actually a condensate project – It’s actually a gas recycling project, if you will, strip out condensate.
Actually send it down to Aseng. And here is a place where we’re using existing infrastructure to enhance the economics of the new project. We’ll take the condensate down to Aseng for offloading and reinject the gas in the reservoir, keep reservoir pressure up, and at some time then blow down the gas part of the field down the road.
I’d say as far as that concept of utilizing existing infrastructure, we’ll now have in place infrastructure at Alen, infrastructure at Aseng that can help on future development, things like what we’re continuing to test at areas like Diega and Carla and other opportunities in this part of the region.
Eastern Mediterranean, I mean, that has been a tremendous success story. We had our first field online in the Mari-B, which looked kind of down in the southeastern part of that map, which at the time seemed like a significant, trillion cubic foot, discovery and project. And we brought it online in 2004, and then followed that up with some very substantial discoveries over there. We’ve now found probably 35 trillion to 40 trillion cubic feet of gas in the area. And the two largest being Tamar, which we brought online this year, a 10 trillion cubic foot discovery; and then Leviathan, which is almost twice that size, at estimated now around 18 trillion cubic feet.
So probably as eye-opening as anything has been since we brought Tamar online and started to really – this started a little before that – but started to really get a better feel for the market opportunity in this part of the world, the eye-opening piece has been the regional opportunity that exists over there and opportunity in neighboring countries or the need for gas, if you will, in the area.
So when you think about the market over here in this part of the world, you’ve got a growing demand in Israel. You still have at least a couple of coal plants to be converted at some point in time over there, along with the growing need in country for additional gas. You’ve got this regional need that has been extremely eye-opening in the area, and the opportunity to use that to change relationships even over there between countries.
And then you’ve a longer-term LNG potential for – whether it’s floating LNG or an onshore facility that's either in one of the countries or that is combined between countries, between Israel and Cyprus.
So it has been an exciting piece that we now have significant volume online. We’re drilling an appraisal well in Cyprus and testing that. At the same time, we’ve Tamar online, with capability up to 1 billion cubic feet per day. Again, you talk about world-class reservoir; with very little drawdown, you can deliver through each well 250 million to 300 million cubic feet a day.
And the reliability of the field, I mean, I think we’ve been down – since we came on in April, the only period we haven't been producing has been measured in probably a few hours, a couple hours, out of that whole period. We’ve actually seen volumes on different swing periods that we’ve actually gotten up to that Bcf a day. So we know we can deliver that as the demand continues to increase. Now we don't deliver that full-time because there is seasonal demands and swings even during the day, and it can swing from 400 million to 800 million during a day, depending on the demand and need in country.
But it’s something that the expectation is the next piece of this is an expansion that we already have ongoing at our Ashdod onshore facility. I mean, we see a need in gas by the middle of this decade, 2015, 2016, just in country that they will be needing up to 1.5 Bcf a day. So that is what we’re keeping on our horizon, on our planning of what we need to have ready to deliver in country, while we’re working on these other options out of the country.
You think about the overall exploration portfolio, I mentioned some of the impact pieces. Our inventory, as it’s mentioned here, is at the highest level we’ve ever had it in the Company. And obviously, that is appropriate in a growing company, but it’s building off success we’ve had. I think when you look at it over the last five years, we’ve discovered through our exploration program slightly under 3 billion barrels of oil equivalent – I think the number is around 2.8 billion. And yet we’ve got an inventory now of 3.7 billion barrels equivalent of net risk resources. A large portion of that, we’ll start to get some real insight over the next couple years.
Right now, I mentioned we’re going to be moving over to Dantzler on the Gulf of Mexico, which will be followed next year by similar type prospects. Again, these are a little of the larger size than what we’ve been drilling in the Gulf where we’ve had success.
Nevada, in the US, I mentioned we’ll start testing that play; we’re actually in the process of drilling our first well now. Nicaragua, I mentioned; we’ll talk about each of those. The ones I really won't get into today, Falkland Islands, we’ve got a position in 10 million acres down there that we’re excited about. We’ve been shooting 3D. The quality of the 3D that we’re getting in is outstanding. I’d expect we’ll come up with a prospect inventory that we’ll work to have a rig down in that part of the world by the end of 2014, drilling into 2015 on multiple prospect activity, would be my guess.
The Mesozoic oil in the Eastern Med, we talked about all the gas opportunity in the Eastern Med. The next breakout for us in that part of the region is some deeper oil drilling that we’re very enthused about. And we’ve actually contracted the Atwood Advantage drillship, that the expectation is we’ll bring that into that region by the end of the year – or show up over there about the end of the year or early next year, to start a program over there, say, by midyear next year. So that is something that is pretty exciting for us.
But again, these are things that with the success of any of these will add substantially to what we’ve built into our outlook. When you go back and look at that five-year outlook and growth projection, very little of that, almost none of that, is expected to be delivered from our future exploration program at this point. It’s all underpinned by things that we’re doing now or discoveries we’ve already had. So these are things that are setting up that growth up to the end of the decade and beyond.
I mentioned Nicaragua. We’ve got just under 2 million acres down there. We've started the drilling. We’re focusing in the area where we shot 3D. This is an example of how we work through a stage-gate process on exploration, especially these big offshore explorations, where we understand the cost of entry and the cost of exit at any point in time.
For example, we got into this and we knew what the cost of entry was into it at that point of time. We knew what the commitment was for a 2D program and what it was going to cost to evaluate that. We shot that program, we evaluated that to decide we wanted to make the next step to move forward with a 3D program. We shot the 3D, evaluated that, saw some very nice prospectivity, very large oil play prospectivity, coming out of it, things that could be up to 1 billion barrels or more. So that is what we’re moving forward now on our first well to test.
We’ve an option on the rig; depending what we see, we could follow that up with a second well or we could decide to just absorb what we learn and then step back and see where we go from there. But It’s a carbonate play that, again, we should have this first well down by the end of the year.
I mentioned Dantzler here in Mississippi Canyon, Gulf of Mexico, and it’s a little larger play. It has got upward potential around a couple hundred million barrels equivalent. Again, it’s that Miocene interval that we’ve played with success in the past. And it’s another one where we expect to have results by the end of the year. Again, targeting an oil play here.
I mentioned Northeast Nevada. It kind of highlights here where in northeast Nevada we’re drilling it. We always get the question how close is it to Vegas. It's not that close, thankfully, probably. But it’s a tight oil play. The information we’ve right now – and the team has done a great job of putting a lot of science to this. What we pride ourselves is kind of using an underground laboratory to apply science and technology; for example, what we’ve done in the DJ and what we’re transferring to the Marcellus and what we’re using to start with out here.
But if you go back through the old history, this is a play that hasn't been played in this state before. So it’s not one of the ones where we’ve all had history on in the State. So this is a new concept that is based partly on what we’ve learned from some surface outcrop coring, and also from some old logs and DSP in the area. I mean, I’ll say – and I have been telling folks – why do we’ve a high geologic chance of success? Because I am going to be surprised if we don't find hydrocarbons.
The challenge and the question will be what is the reservoir quality? What is the distribution of hydrocarbons? If we find hydrocarbons, over a very large section? Because what we’re targeting is thousands of feet of section; I have heard it described anywhere from 2000 to 5000 potential growth foot of section that we’re going to be looking for hydrocarbons in.
So the real question – we’re actually going to go in and drill two vertical wells this year to get some real infield, modern understanding. And then based on what we see from that and this distribution of hydrocarbons and reservoir quality, if you will, we’ll decide how we’re going to move forward on testing this.
I’d say information will trickle out slowly on this, but we’ll learn a lot initially with the first couple of wells this year. Again, it’s a large potential resource, we’ve got a large position focusing on three areas, if you will, in the play. And starting with the center area where we’ve got 3D across it to begin, and we’re actually going to be shooting some more 3D out there this year.
We mentioned what we’re calling the Mesozoic oil play in the Levant Basin, the offshore Israel, offshore Cyprus. Our belief is that there is actually structures underneath a lot of these original gas discoveries, everything from Cyprus over through Tamar, Leviathan. And we had some – an idea of this play when we were drilling the Leviathan well, where we actually tried to deepen that original Leviathan discovery. It gave us some interesting information on pressure ramp below us, below the gas interval that bodes well for a potential field in the area. And also give us some information on some hydrocarbon content and the thermal system that's working, a different system than what the gas play was below us.
We’ve seen some other items of interest, if you will, on some of the additional drilling. We saw higher liquid content in Karish. So there is a feeling there is a liquid component in this basin deeper than what we’ve tested so far. We don't know if It’s held there, if It’s passed through, if you’ve reservoir, but those are the things we’re going to test. And again, this is substantially deeper than what the gas play has been, so on seismic, you’re not going to be able to see it as well, other than structures, because it gets masked somewhat by the bright amplitude of the gas plays above it.
So, that brings us back to kind of the summary, and hopefully you’ve seen why we feel we’ve a position that is somewhat unique. Hopefully, you’ve seen it’s not by accident, but design. We’re creating and building what we believe will be a high-growth, long-term sustainable Company. And again it starts with the assets, and then it’s driven by the people and the organizational capacity to deliver that.
I guess with that, Bill, I’ll stop. I’ll put the disclaimer in on forward-looking statements in case I happen to make any.
Bill Featherston – UBS
And we’ll take some questions.
Bill Featherston – UBS
Sure. Going to open it up for questions. If everyone could wait for the microphone, and maybe I’ll just start with a couple of quick ones.
You’ve spud the Paraiso prospect in Nicaragua. Are you drilling that 100% or were you able to bring in a partner? And then the follow-up question is if you could just give us an update on where we’re in Israel with the Supreme Court and all of it?
Yes. Starting with Nicaragua, it won't be at 100%. We can't get into the specifics on partner or partners at this point, as it’s going through some of the paperwork with the government. So we’re adhering to their need not to divulge anything until it gets completely through there, but yes, we won't be at 100% on this well.
I’d say on…
Bill Featherston – UBS
Can you say if you will have net CapEx in the well? Or are you being…?
Yes. We’ll still have some CapEx in it. We won't get into how much at this point until we get the partnership announcement.
I’d say the – on the Israel piece, the question is around where are we on the export policy. And if you back up, the cabinet approved an export policy. It was kind of a 40% export overall, but when you looked at the larger fields like Leviathan, it was really a 50%, and we could build on that by moving pieces around or reallocating pieces from some of the smaller fields.
But then that got questioned as far as to whether did the cabinet have the ability to make that decision, and so it got pushed to their High Court. Originally, the High Court was going to meet on that here in September. I think it would have been earlier this week. That got pushed back due to some personal conflicts with some of the judges is my understanding. To be able to get them all together now is targeted for kind of mid-October or so.
So we need – it has got to run its course to them, and then they’re going to decide do they uphold the authority of the Cabinet to make that decision or do they feel they need to push that to the Knesset, so that is kind of what is on hold right now as far as finishing up the transaction with Woodside and then solidifying what is going to be that next investment in Leviathan – or that initial big investment in Leviathan.
Bill Featherston – UBS
We have a question over here?
On the topic of Leviathan, could you comment on the reservoir characteristics of that resource play versus Tamar? Would you expect to see similar 250,000 cubic feet per day of production per well?
And are the economics broadly similar just from a broader perspective, if you’re doing a 50% gas – 50% domestic, 50% exported gas proposition?
Yes. I’d say, first, when you start on the reservoir quality, It’s very similar. It’s not what we expected to see, but what we’ve seen. I mean, we’ve drilled four wells or so in Leviathan already, and the reservoir quality is very similar – big, thick gas, sand, deliverability. We’ve actually tested the well over there and deliverability looks very similar.
So, again, the limit is the size of the pipe we’re putting in the well. So, I’d expect to still see that 200 million to 300 million a day, very confident we’ll see that 200 million to 300 million a day there. So from a reservoir standpoint, they’re very similar.
Economics are going to depend on the type of project. I mean, you’re going to have different economics depending on the amount of investment that you put into something. Is it an add-on in country, is it a regional investment where you can utilize some existing pipeline or tie into something? I mean, when you think about the opportunities, there is existing LNG plant, for example, in the area that need a lot of gas. Is there a way to tie into that thatdoesn't require a huge upfront investment in that portion of the business?
Now, longer-term, some other things. If you get into floating LNG or an LNG facility on-site, there is still a potential. There is a great location in Cyprus for an LNG terminal on land. There is still discussions and potential to have some interaction between Cyprus, and say, (inaudible)Leviathan where you share a facility. So, those are all the types of discussions that is going to drive what are the actual economics at the end of the day on each portion of that type of play.
But it’s pretty exciting when you look at the different type opportunities. The optionality in this part of the world has done nothing but increase over the last year or two. That is what has been exciting to us.
In Nicaragua, can you just speak to the reservoir being a carbonate reservoir? Is this the first deepwater exploration that you’ve done that is a carbonate? And what’s kind of the risk of that versus your Miocenes?
Yes. I’d like – when you think about the carbonate, the question is going to be how conclusive from one well are you going to understand the reservoir distribution, if you will, continuity, connection. So, more than likely, even if you had a very positive result, you’re not going to come out and declare victory over the whole area. It’s going to take some additional appraisal drilling to understand what the consistency of reservoir quality is as you move across that very large area and potentially very large resource.
Could you just comment on the Wells Ranch slide you had there? I was just wondering where that is within the play.
It’s – I’d consider it kind of northern part of Wattenberg Field. It’s not up into what we call northern Colorado; it’s south of that, but it’s kind of the northern part of the Wattenberg Field, kind of east of Greeley, Southeast.
Okay. And the 750,000 to 1 million barrels, what does the product mix look like? I don't know if that was on the slide or not, but I didn't catch that.
On the which?
The product mix of 750,000 to 1 million barrel (inaudible)?
Okay. Yes. On that, those wells were in that Wells Ranch area, the majority of those long laterals. And so, I think in that area it has been running probably 65% – 60% to 70% liquid, with over 50% oil.
50% of the 60% or 50% or the 100%?
50% of the 60% to 70%.
Got you, okay.
Yes. So, 50% plus oil and 15% or so NGL.
Okay, okay. Thank you.
Yes. Just to clarify that. Good question.
Just following up on those questions, have you drilled extended reach wells in the East Pony area?
We’re starting that now. We’re just getting started. So we don't have any production history here yet on any East Pony, but we’ll probably by early next year.
Okay, thanks a lot.
Yes. So – but just to go back to the other question and make sure I am clear, because I may have confused it. In that Wells Ranch area, when you look at the product mix, it’s a little over 50% oil, 15% or so NGL.
Bill Featherston – UBS
Yes. I – I think Marcy had a question.
Yes, can you talk a little bit more about your brownfield opportunities? You’re talking about for Alen, you’re using some of the Aseng infrastructure. It sounds like in the Rio Grande area, you will look forward to doing that. So as you find more resources there, do you ramp up the infrastructure and ramp up production? Or do you kind of time the development so that you maintain the level of existing production? And what are those opportunities around that, especially if you find some smaller resources that wouldn't support greenfield development?
Yes. It's a good question and it kind of depends by area. You think about it, say, in West Africa. I think the way we’ve talked about that is these new developments, say, at Diega or something out there, they will start to fill in – by the time they’re ready to come online, they will start to fill in and continue to keep the infrastructure usage up, as some of the original field start to decline off.
So the way we’ve kind of talked about our infrastructure in West Africa is kind of keeping it fairly level loaded out through time by continuing to add new opportunities into the mix and bringing those on as other start to decline off somewhat.
Now in the Gulf, there is so much infrastructure in place now that a lot of these new discoveries in this 50 million to 100 million barrel or so range, you can tie back to existing infrastructure, and you usually have more than one choice out there. And what that enables you to do is take something that on its own may have been somewhat marginal trying to put the investment into a full new infrastructure, but actually has tremendous economic – I mean, you think about that Rio Grande complex, when you look at 50 million to 100 million barrels and 75% oil. And I know Chuck has talked about it – but you take the midpoint on that and you apply $90 to $100 per barrel, and you’re in $5 billion or so of revenue for a cost of $1 billion or so. So I mean, It’s hugely profitable.
But that is another reason why we’ve continued to focus in that Mississippi Canyon Miocene or Green Canyon Miocene area, to take advantage of infrastructure, even on things as a fallback that aren't significant enough to put your own infrastructure in.
Just going back to the Wattenberg, as you move, say, from the Wattenberg field to Wells Ranch to East Pony, should we assume that the spacing should be consistent, or do you think there will be different spacing patterns between each of the three areas?
That is a good question, and it depends yet, I’ll say. I’d say we’re still looking at it by area on what is the right spacing and what is the right mix of different layers, if you will.
What I’d say will change probably – I don't know whether the spacing will change at the end of the day on some of this. It probably will in some of the areas. But probably what will change somewhat from area to area is the mix of vertical component. For example, you’ve got a B interval that is fairly consistent, but the Codell changes on thickness in different areas. The A interval changes on thickness in different areas, and the C also. So in some areas, you may have a mix of B interval and Codell. In some areas, it may be B interval and A interval, or B and C.
Now, the one thing that you’re looking at different as you go up into East Pony and so forth, getting back to that mix, you’re up – in that area, you’re 80% oil.
So do you think because you’ve got a higher oil cut up there, do you think your drainage is less on a pool, or is it – how do you think about that…
It could be. That is what we’re going to continue to test. Because you know, initially, we started with 80-acre spacing up there. So the next evolution is to move to 40, test some of these other vertical layers and also mix in some of the longer laterals. But that all points to why I say we’re still in the early innings of completely solidifying what is the actual optimum pattern in every single place we’re in.
And that 80-acre spacing, that is just for one zone.
So that is the B zone, and then you can also drill Codell, C or whatever is existing there.
Right. Right. I mean, because if you go back to – we’ve talked about the little over 2 billion barrels of resource in the DJ Basin. You go back to what we talked about in December, most of that, if not all of that, was based on a different spacing, if you will, for that B interval.
Maybe as a follow-up to Rod's question, have you done enough testing this year so that at the December meeting you will be able to tell us, we think spacing is 40 in certain areas and in different areas, in addition to the B zone, the A, C and the Codell might work?
And then sort of related to that, with the integrated development plan, is that going to – is the idea to try, given how high the returns are, to enable you to exceed that 500 well per year target?
Well, yes, let me start with the first part. I’d say the expectation is we’ll update what our resource outlook is and how we’ve come up with that and what the assumptions are for different areas, spacing assumptions, contributions of different intervals, that type of thing. Will we be at the place where we finalized all that? No. I mean, we still – we’ve started to drill some of these different spacings and different staggered patterns, if you will, but you still want to get some history of production on some of this and continue to test this.
I imagine what we’ll do is lay out how this whole thought process has evolved and what we’re moving to in different areas as we get into it. So it will be an update of the detail that we provided last year that makes up where we’re at that point in time. The second question –
The second question was given how high the returns are in the integrated development plan, do you think there is a way to drill more than 500 wells per year, or are you…
I think over time – I think what that integrated development plan will be beneficial, besides just the true underlying economics of consolidating things, is it will allow you per rig, if you will, to do more because you’re not moving them as much over time. So I’d anticipate over time – and we’re going after see where we go – it will continue to allow us to accelerate and bring forward some of that value. Because I mean, even if you end up with a higher resource, the true value is in how do you bring it forward, and I think part of that is going to be in how we lay out these integrated development plans.
Could you go back and clarify and add some detail on your hub development structure? Is that where – I have heard of companies that have, for instance pipes, that they can move as they move the pads from a central location. And can you talk about the impact on the cost?
Well, I mean, we’ll get into a lot more of that later in the year. But when I can give you conceptually is where It’s heading, is that you end up with – say, on a section, you end up with a pad or two of drilling with a number of wells, potentially up to 16, possibility. And then you’re taking these sections and you’re taking this and bringing it into a centralized production facility, which will gather product from a number of surrounding sites – it could be 20,000 to 30,000 acres. So you could end up conceptually with a facility that will handle 50,000 to 100,000 barrels a day at some point. And again, I am talking conceptually on this.
But what it will enable you to do is set up a pipeline network to where you’re moving water around the field for what you need water usage, for fracking, et cetera. And you’re also moving your oil around the field, so you’ve much less transportation. You’re taking vehicles off the road, which is a big impact in the community up there, and you’re ending up with a much smaller surface footprint versus a number of individual facilities that the old vertical world was at every drill location. So that is something that as we get into December discussion, we’ll give you a better picture.
Not that we’re ready to go through. I’d say the thing we’ve talked about in the past, when we looked at conceptually the Wells Ranch, for example, area, you know over the development life of that area, we had sketched out a potential for $1 billion of savings, just in that one area alone. So the prize is enormous, but we need to do some more work to quantify that and look at how many of these we may have in place.
Just on Leviathan, how critical is the LNG as the sort of development option? Or will this sort of field ever be just sort of a domestic Israel and regional development story?
I think from the country's standpoint and ours both, I think it will play a role. Probably the difference is it wasn't – I don't think now It’s as solely dependent as that, as maybe the impression was going in. And it never had been solely. There was always going to be a mix of in-country use of Leviathan. I mean, it just makes sense to use a portion of it in-country to have the redundancy of supply from two big sources.
But I think when you’re looking at the additional delivery piece before, I think the focus was all on LNG, and I don't think that is the case anymore.
And just on the DJ Basin, can you just give us a sense of not just your production targets, but if you look at the peer group as well, what do you think the Basin can deliver or what It’s likely to deliver, let's say, in that five-year timeframe that you talk about?
Yes, I mean, I think when you go back and look at what we talked about last year, we talked about kind of a 20% – plus or minus 20% growth rate over that five-year period. I haven't seen lately the updates on other activity. But that is something we’ll be looking at a little more as we get ready to update information at the end of the year.
Can you just give us an update on your delineation efforts when you step outside of East Pony proper?
Yes, the delineation efforts outside of East Pony, we’ve probably not over-focused on that this year. We’ve done a little bit, but there isn't a real drive from a standpoint of loss of acreage or anything like that up there. So we’ve tested a few things. Probably still early stages of production results.
The one that we mentioned at the last earnings call was in one of the areas up there – I think It’s southwest of East Pony – where we actually went into an area that we drilled a couple, say, standard laterals a few years ago, and had, I’d say, kind of marginal performance from those, especially when you compare them to some of the other results we had in there.
We went in there with longer laterals and really made that very economic. That was kind of eye-opening to us. We put about three wells – longer laterals in there, close enough so you had a baseline from some of the standards to compare it to. And we were seeing 2.5 to 3 times what looked like performance improvement along the laterals. Now, we need to see how that stays up over time. And that may be something that right now as we’re thinking about delineating other areas, the question is do you do a standard lateral or do you just go in and start to test some of these with longer laterals. So that is something we’re still working through.
Bill Featherston – UBS
Are there any other questions for Dave?
Dave, what do you think the most important factor is that drives the shallower decline that you’ve seen in the longer lateral wells to date? And just in terms of pushing the envelope even further, when you guys look to drill past 7500 feet – I know in the Williston basin some guys are talking about three-mile laterals and so forth. Where does the – ?
Where is the limit?
I don't know if we’ve found the limit yet, but we’ve – a number of these long laterals are 9000 feet. I think we’ve actually gotten out to 10,000 both there and in the Marcellus. So that has been interesting. I’d say go back to – the first part of the question was…
Yes, the shallower decline and what do we attribute that to on these long laterals? And that is a question I have been asking our folks continuously also. What we’re seeing – and when you look at the production on the different intervals of the stages out here, you’re actually seeing a little better production out in the toe, the longer portion of the lateral out there.
And I think it ties into how we’re producing these wells, where you really try to minimize the drawdown. You’re getting so far out from the vertical reservoir, you’re really getting a natural – just a natural feed from the matrix out there. As such, you’re not pulling it in very hard, and It’s not over time or even instantaneously getting anything into the pore throats that could potentially plug it. So you really have drainage out there.
You’re also setting up that toe, if you will, so you get some gravity effect on that and some gravity drainage on some of that. So I think It’s really – and our folks are fairly well-convinced It’s minimizing your drawdown and potential damage on that. And you’re getting additional benefit from that by being further away from the vertical wellbore. As long as you can effectively frac it as well out at that extended region, we’ve found we’ve been able to.
Bill Featherston – UBS
I think we’ve time for one more question. If not, for those on the webcast, we’re going to take a 15-minute break before Tidewater comes back. And for those of you in the room, please join me in thanking Dave and Noble for their presentation.
Thank you, Bill.