William A. Featherston - UBS Investment Bank, Research Division
All right, we're going to get started with our next presentation, Noble Energy which, within our coverage the universe of the largest caps, is the highest growth story from a very visible backlog of projects over the next 5 years, as well as an exciting exploration program that can only add to that growth.
Presenting from the company we have Dave Stover, Executive Vice President. I'd like to hand it over to Dave.
David L. Stover
Appreciate it, Bill. And it's always good to be back in Austin, even though it's still a little warm, or starting to warm up now, as we've also seen in Houston.
Again, I want to start off with just a reminder of who we are and then talk a little bit on just some of the overview items and then dive in, in just a brief detail on each of our core areas and some of the big exploration catalysts that we have coming up. When you look at here it talks about Noble Energy, Unique. By Design. That's actually the theme and cover of our annual report this year, and what it alludes to is what we've done as we've built and created a company, as Bill said, with a significant growth profile, but it's a substantial growth profile and sustainable growth profile, not just for the near-term, but for the long-term. And I'll show you in a little bit what underpins that.
It's really made up of concentrating on 5 core areas, each with tremendous running room. It's building off some significant exploration impact, I'd call it, exploration success, over the last few years, and taking that exploration success and then delivering some significant major project execution, the latest example being the Tamar project that just recently came on in offshore Israel.
Here's just a reminder of what we've laid out as our 5-year growth outlook, looking at it on a debt adjusted per share basis. You can see, even with significant production growth on the debt adjusted basis of 18% per year over the next 5 years, you can see cash flow is even growing faster. It's this growth in cash flow, relative even to production, and focusing on the high returns and especially the large investment in the DJ Basin, that's going to drive that return on capital employed by 2017, up to around 17%. And again, positioned for actually double-digit -- visible double-digit growth over the next 10 years.
Underpinning this is our net risked resources. Actually when we showed this in December, year-on-year comparison to 2011, this was up actually 34% from the prior year. You can see some of the split out or splits here on some of the pie charts, looking at what makes up the exploration, wedge of that risk resource, the total risked resource just under 10 billion barrels of oil equivalent. And then what's been discovered but not yet booked, down there, close to a little over 5 billion barrels and how that's divided between, really the DJ Basin, Marcellus and Eastern Mediterranean, that's the significant components.
You can also see on the unred portion, the large impact potential of some of these new ventures that we'll talk about in a little bit.
A significant contributor to the growth, especially over the next 5 years and beyond, is our onshore programs. Recently, we did some organizational adjustments to tie these programs even closer together, as one onshore business. Again, the 2 big components there, the DJ Basin and Marcellus -- actually, if you look at them, over the next 5 years on an absolute net basis, they're growing about the same amount on barrels equivalent per day from '12 to '17. Each of them have the same, I'd say category or impact, from the standpoint that both of them have seen a tremendous improvement and expansion of the resource base as we've continued to unlock and develop each of these key core areas.
The other big component is the major projects, the major offshore project, and here's a line up: and the first 2, on the left, Tamar and Alen, these are the 2 major projects we're bringing on this year. This is on the heels of Aseng, a little over a year ago, and Galapagos last year. We just brought on Tamar late March, early April. It's done a tremendous job of contributing to what Israel needs for gas supply in the country. And then the next big project's Alen in West Africa. Alen will come on in the third quarter and should be fully ramped up by the end of third quarter.
The next phase, the next generation of projects, if you will, are shown on the right. These are all projects that are a possibly for sanction actually this year, as we continue to move forward. Things in the Gulf of Mexico like Gunflint and Big Bend, in Israel, the next phase of Tamar, and Leviathan, initial phase, and a Carla project in West Africa.
When you look at discretionary cash flow for the company and the outlook, we mentioned cash flow growing faster actually than production, it's really based on the quality of assets that we're developing, but here you can see, starting in -- from '13 to '14 and then going out through '17, you're growing it about $1 billion per year in discretionary cash flow. And you can see how that cash flow changes, the contribution changes, from '12 to '17 in the different areas. In the U.S, for example, cash flow contribution is about -- just under 50% it was last year. By 2017, it'll be about 2/3 of the company's contribution. A large portion of that driven by the continued expansion in the DJ Basin and the Marcellus.
So let's visit just a little bit on each of these core areas. When you look at the DJ Basin, it's undergone an amazing transformation for us and then you go back to -- in 2005, is when we really picked up our anchor position there, if you will, which was the Wattenberg Field. That came as a result of the Patina transaction. At that point in time, we built on that with a USX [ph] acquisition and an acquisition from Petro-Canada, and then we continued to build on that as this Niobrara play heated up and we saw the potential for the Niobrara play with some additional acreage acquisitions out in the area.
Our net resources as of December around 2.1 billion barrels of oil equivalent. I think that was up from around 1.3 billion barrels the year before that. We got a tremendous growth profile and we've continued to accelerate the activity, and I'll show you that in here in a minute.
When you look at what we've been focusing on in the DJ Basin and I talked about the transformation of the basin. Back in 2005, this was really thought of as a gas field where you drilled vertical wells, continued to decrease the density, do things like refracs, trifracs, a lot of it was focused on the Codell with the Niobrara almost as a secondary objective at that point in time.
As we got more into it and started to understand the potential of the Niobrara, especially the resource potential of the Niobrara, we started to focus more on breaking out a horizontal program. So the last 3 years, we kind of ramped up our activity from about 90 horizontal wells a couple of years ago, to last year about 200 and this year, we'll drill about 300 horizontal Niobrara wells.
The whole transformation of the field, it's pretty much now an oilfield. What you're seeing now is a move from about 35% liquid content to over 50% liquid content in the field, which highlights how the activity is focused on, and continues to focus on, more of what we would call the oil rim in Northern Wattenberg and now up into a new breakout area that we've been working on the last year, what we call Northern Colorado.
But what we've done in the last year is we've accelerated the program probably a year from what we originally anticipated a couple of years ago. And that's kind of shown on the top left graph of horizontal wells.
The other thing I'll mention, and I'll show you some examples of it later, we have actually changed the components of the program that where last year, in the 200 horizontal Niobrara wells we drilled, about 5%, or 10% or so of them, were longer laterals, longer than our base normal program of 4,000- to 4,500-foot laterals, we started to do some 9,000-, and even 7,000-foot extended-reach laterals. This year, our program of 300 wells will actually be made up of close to -- 20% of our program will be those longer laterals, extended laterals, and I'll show you why here in a minute.
The other thing that's kind of dramatic here in this play is the free cash flow picture. It's ramped up pretty quickly to where this is going to be cash flow generating here by next year. And you can see that down there on the bottom right, you can see how our outlook for that cash flow picture in this basin is -- has changed just over last year or 2, as we've continued to learn in this -- as we've gone in this field.
So you can see, just by accelerating the program a year or so, we've added into the plan now over 1,000 wells, over that 5-year period, or 6-year period, actually, when you go back to 2011.
When you look at that 2.1 billion-barrel resource potential, and here's how we came up with that, and allocated that at the end of the year: you've got 3 different areas, shown here on the map, you've got what we call the gas window, in kind of pink; and then that first green bar, as you go up, on the right, is actually what we call the oil window, in the Greater Wattenberg area; and that elliptical in the far right is the Northern Colorado portion. So
you can see the number of locations here, that all adds up to about 9,500 locations, based, essentially, at that time, on completing one vertical interval, if you will, mainly the B Bench of the Niobrara, on different spacing in the different portions of the field. The tightest spacing being in the oil window, around 40-acre spacing, or 16 wells per section, and portions of that.
So you can see it is the area that is drawing the most capital for the company, it's about 45% of our capital program, with a tremendous growth rate, and we're actually accelerating the program as we speak here this quarter.
Show you a couple of examples of some of the well results. I mentioned breaking out Northern Colorado. And here we have about 45,000-acre position that we've tested and actually moved into the full development, what we call our East Pony area.
And you can see some of the well results there, and they've continued to improve, as you can see, kind of bringing that purple curve up, down on the bottom right. So this is an area that we'll drill and expand probably to 80 of our 300 wells this year, will come in this area.
Extended-reach laterals. I mentioned the program this year will have a much larger component of extended-reach laterals, being these ones here in particular are 9,000-foot -- we've actually done some 7,000-foot laterals. What really started to catch our attention was the shape of the curve on some of these, as we started to bring these on, get some extended production history. You can see we're starting to get out towards the year, up production on some of these. And we started with a type curve for this 9,000-foot laterals, or about 750,000 barrels oil equivalent, and some of the performance of the couple of these 9000-foot laterals, you can almost match up to 1 million-barrel-type well out here. So that's part of the amazing transformation in this field where you now have the potential for 1 million-barrel wells in a field where the whole focus a few years ago was on 40,000 to 60,000 barrels per well on a vertical world.
So how it's evolved and how our thinking's evolved and where we're going with this, is continuing to evaluate the optimum patterns in the field. It started with our plan, originally with 160-acre spacing. They''ve all been to 80-acre and I even mentioned some of the 40-acre in the B Bench that went into our resource. The real future prize in this, and as a future near-term prize, is continuing to unlock recovery on a vertical sense than this 300- to 350-foot interval from the top of the Niobrara down through the Codell. So there's a tremendous oil in place here. It's now up over 70 million barrels per section, approaching 90 million in some parts of the field from what we can tell.
And so the prize here is moving your recovery up in the double-digits and to do that, you probably need something on the order of 30, 32 wells per section, something like this. So the focus right now is looking at these patterns on the right. These kind of different patterns where you're completing in different benches of the Niobrara and also involving the Codell in that, to where the future, potentially, out here, could be multiple horizontal layers in these sections, which is what's going to increase your overall density and increase your overall recovery.
So that's the exciting part we're working on now. We've had a few wells in there that have tested this. I'd say, we've been very pleased that we haven't seen an impact to our basic B Bench wells and it seems to tie to the geology and the various thickness of the intervals so a lot more to come and we'll do a lot more testing on that this year.
Let's go around the horn, in the Marcellus shale, just a reminder for our position out there, there's a significant position in partnership with CONSOL. It's been a great partnership, as far as matching up and aligning on capital allocation and program going forward, and focusing right now on increasing the activity in the wet gas portion of the play, this is a portion that we operate, kind of highlighted in green on the map there, while maintaining a base program, about a 2-rig program in the dry gas portion of the play.
In the deepwater Gulf of Mexico, the story is really around bringing Galapagos on last year, which was a big contribution and that discovery of Big Bend in the end of last year, we're appraising Gunflint now. We'll move from Gunflint over to Troubador, which is a prospect right adjacent to Big Bend, and then after Troubador, we should still have time for another significant exploration well in the fourth quarter this year. A lot of focus this year on bringing Gunflint and Big Bend to sanction. So we can bring on production by the earliest in 2015.
Just have some example of where Gunflint is, as a reminder, and also the Big Bend and Troubadour area, how close they are together. The nice part about both of those, you have tieback options in the area, you have the infrastructure in the area to help accelerate that, if we elect to go the tieback route.
Eastern Med, the big story is Tamar, having come online in April. We've actually -- we have 5 wells producing over there. We've cycled each well to clean those up to the point that we're comfortable each well can produce over 250 million cubic feet per day. We've actually, a period, had the field producing over 900 million cubic feet per day. I think the expectation is, we get in into the summer peak season here in the third quarter. We'll be bumping up against our onshore and physical limitation of the capacity of a Bcf a day at a number of periods of time. So tremendous field, tremendous reservoir out there. I mean, this is with very little drawdown in this reservoir, the reservoir makes a huge difference.
And then, it's a growing market over in Israel. This is an example of how we see some of the growth in that market and this doesn't even reflect the potential over there for additional coal conversion down the road. This is what's already planned and there's potential for, at least, another plan or 2 of potential coal conversion down the road.
So if you go back to when we announced our Karish discovery today, that actually -- this map's outdated. Add that now, we're up to 7 consecutive discoveries, 38, 39 Tcf. Actually, this year alone, we've increased the resource size, offshore Israel, by about 4 Tcf between Karish, Discovery and then the increase from -- at Tamar and then increase at Leviathan, from the additional development and appraisal work at both of those, which is not insignificant when you remember that Mari-B, our previous producing field, was only 1 Tcf. We've added 4x that much this year alone over in Israel.
Here's just a picture of the project. The next phase, over here, is really the expansion of our onshore Ashdod facility, compression there. Storage in the field enable us to get up to capacity of around 1.5 Bcf a day by 2015, or in 2015, so that we can deliver, on average, something over 1 Bcf a day, still leaving some availability and capacity for a swing production.
Just a picture of Leviathan. I'd say, the one piece to mention after Karish were actually taken here. Very shortly, we'll be taking the rig over to Cyprus to start our appraisal well in Cyprus. We're excited to get back on that project.
West Africa, tremendous cash flow provider. After the Aseng project, we're bringing on Alen. Alen will more than offset any decline in Aseng later this year, so anxious to get that online. That will add about 18,000 barrels equivalent per day of condensate and, like I said, that should be fully ramped up by the end of the third quarter. Picture of Alen, and then working on the next set of developments to continue to bring in behind now the infrastructure that we'll have in place with both Alen and Aseng, to handle both gas and liquid.
Mention just briefly the big new venture impact exploration programs. We've got about 5 billion-barrel-type growth prospect things that we're going to be moving forward here. The first 2 I'll mention are in Nevada. We've got a large play position. It's been a new play concept. We're going to start testing that here in the third quarter. We'll start to drill our first vertical well, we'll drill a couple of vertical wells there, targeting 1,000- to 2,000-foot interval and then, based on what we see, as far as hydrocarbon content and distribution on a -- up and down that wellbore, we'll decide where we want to go on a completion and testing program and additional exploration. So that will kick off here in the third quarter. We're excited to get that started.
The same thing with Nicaragua. We've got a couple of billion-barrel-play opportunities down there. The first one of which we'll test here in the third quarter, or start to drill in the third quarter. We currently have 100% interest in this prospect. I'd say, we'll probably in that 40% to 60% range by the time we drill that. And we're excited to get down there and start to test that prospect.
So a lot to do, a lot on the plate. Again, each of the areas continue to expand and accelerate. You've got the combination of the 2 onshore programs that underpin the near-term and long-term growth. You got the major projects that we continue to bring on and many more in the queue to be sanctioned. And then you got the big inventory of -- big impact exploration program to continue to focus on, continue to bring in earlier in that system, and we'll be testing over the next couple of years.
So we're excited about where we're at and what we're doing right now. I think it was just last year that we really kicked off the growth of this program and we see that accelerating this year and into the future years, and a very long-term growth profile, underpinned by things that are in the portfolio, already with the opportunity for some big impact plays for the future.
With that, Bill, a standard disclaimer here, and we'll go on to the questions.
William A. Featherston - UBS Investment Bank, Research Division
Are there any questions for Dave? Yes.
David L. Stover
Yes, it's a good question. And the question is on the longer laterals, how do you think about that on a per section basis? And where we're talking about going from 16 to 32 wells per section, that's based on your normal 4,000- to 4,500-foot lateral. So the density per section may change a little bit with the longer laterals because you are actually -- for 9,000-foot lateral, you're going across couple of sections. So the reason we've kind of concentrated up in the northern part, that's where we have the access to the big ranches, where you got big contiguous programs and acreage positions laid out and we can test those pretty quickly. And so we'll be continuing to focus on that, especially in that oil rim up there, at this time, and then -- so the real question will be then, how do you match up the potential for longer laterals with the opportunity to get multi-laterals in different vertical intervals on that? And how do we match that piece up? And that still could be in that range of 16 to 30-some wells per section when you go through that whole process. But that's a piece continuing to work on unlocking that recovery because, I mean, if you think about it, on your basic 16-well per section, 40-acre spacing, just focus on the B Bench of the Niobrara, from what we can tell and we've got pretty extensive core work and petrophysical analysis, that's probably only recovering 7% to 8% of the oil in place. So that prize is doubling that recovery out there and there's -- the opportunity is there.
David L. Stover
About -- they've seem to average -- drilling complete, everything included, about 8.3 million. That's compared to the 4,000-, 4,500-foot laterals, about 4.5 million. So you actually see a pretty sizable, about 20% improvement on an F&D basis, if you will. And that's used in the 750, as the type curves are -- has potential to see more improvement than that, with some of the results we've seen.
William A. Featherston - UBS Investment Bank, Research Division
With the new Israeli government in place for 2 months, can you bring us up to speed on where you think they are with export policy? And how soon would you need export policy or what would be the deadline to get the Leviathan domestic production online in 2016?
David L. Stover
Yes, I mean, it's a good question, Bill. One of the things the Shemik [ph] committee came out with a recommendation last year and then that was tabled until they put the new government together. Now that that's back in place, they got the new ministers in place and so forth, our expectation that fairly soon they'll be bringing that to the cabinet for follow-up and recommendation from the government. So what we're hoping for and what we'd like to see and need to see for -- keep Leviathan in country delivery on schedule for 2016, we'd like to see some clarity here by midyear on some of that, because you need to start making some significant investments before the end of the year to keep on that schedule. I was just over there 2 weeks ago, I know that one of the things that's taking a lot of the time from the new government is the budget and so forth that they're working through. But I know this whole export piece is near and dear to them, and it's on their agenda. So we're hoping and we're expecting to see something on that in, hopefully, the next few weeks to months.
When you think about the export opportunity of Leviathan, you factor in the increased capital spending for export to mark the price volatility, how did the adjusted -- risk adjusted return on capital compare to just domestic where you have stable rising pricing. What's the uplift there you see on the exports? Or how...
David L. Stover
Yes, I mean, you actually need to get further into the development phase of that and through the FEED work to get the better estimate on cost, to see how that's going to shake out. Really, what you'd like to have with an export is something that gives you another marker, like price marker, to compare against. I'd say, the one thing about over there, there's going to be a lot need for gas. Whether it's exporting to, and have the ability to export to, Asia and Europe, in country expansion, regional potential deliveries. I think, the thing for Israel, the benefit for Israel, now that they have this expanding gas resource, and like I mentioned, it's gone up just 4 Tcf this year, the benefit of having the ability to use both in country and export, some type of export scenario, provides a big financial windfall for the country that they can use for a lot of things. Whether it's a sovereign wealth fund for the future, defense funding, a lot of different things, let alone establishing different relationships around the world, where you got economic ties with different countries that you didn't have economic ties with before. And I think that's all part of that discussion.
Any other questions for Dave? If not, please join me in thanking Dave and Noble Energy for the presentation.
David L. Stover
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