EOG Resources' CEO Presents at Bank of America Merrill Lynch 2013 Global Energy Conference (Transcript)

Nov.21.13 | About: EOG Resources, (EOG)

EOG Resources Inc. (NYSE:EOG)

Bank of America Merrill Lynch 2013 Global Energy Conference Call

November 21, 2013 11:15 am ET


Bill Thomas - President & CEO


Doug Leggate - Bank of America Merrill Lynch

Doug Leggate - Bank of America Merrill Lynch

My apologies, I think there is going to be some folks mulling in and out. But I'm sure you're all aware of how exciting news that of EOG has been recently in terms of what's going on with their quarter growth, their cash flow, and their completion changes. So it gives me great pleasure to introduce Bill Thomas, President and CEO. Bill?

Bill Thomas

Yes. Good morning. And I just want to certainly thank Doug and Bank of America for the opportunity to present the EOG story. It's obviously a very strong story. And I know many of you are all very familiar with the company and know that when you think about EOG, you want to think about oil, and you want to think about oil growth, and you want to think about rapid oil growth. And that's what the company has delivered over the last three really six years. For the last three years, we've averaged about 43% a year-over-year growth in just crude oil and that really came about because EOG was clearly the first mover in converting from the horizontal gas shale to the horizontal oil shale, a revolution has been going on. And so because of that we were able to acquire we believe the best, the strongest horizontal oil assets in North America, in the E&P business. And so we've been leading the sector in oil growth and we feel like through 2017 at least may be beyond that that we will continue to lead the sector in oil growth as we go forward. And so we will talk about all that, a little bit more as we go through these slides.

We have a very diverse portfolio of key assets in the company. And when you look at just these key assets, we believe that we have 10 years of inventory, 10 years of very high rate of return inventory, and of course the hallmark asset is Eagle Ford. We have the strongest obviously the best position in Eagle Ford 569,000 acres and we've been growing production really rapidly and we will talk about that in a minute. That's obviously the best horizontal oil discovery and field in the world presently and we have the largest position in that.

In the Bakken/Three Forks, we made the discovery well, horizontal oil discovery well back in 2006 and we have a strong position there particularly in the Parshall core area of the field. We've had a technical renaissance. We've tremendously increased our productivity of the well just in this last year and we have a big inventory on that, and I will talk about that.

Really the third leg of our oil inventory is in the Permian. And we have three plays in the Permian, but we're particularly excited about the Delaware side of the Permian, and in the Leonard play that we have, some people call it Avalon play, we -- year-to-date results on that are actually or directly 100% rates of return on that and it's a nice crude oil play for us. We have 1600 locations in inventory in the Leonard.

In all of these plays, all three of these plays we're generating 100% direct rates of return right now and we have more than 10 years of inventory in each one of those. And as we go forward, obviously, we are generating a lot more cash with oil growth like it is in the company, we're going to be putting most of our money back into and accelerating the drilling on all three of these play as we go forward.

Each one of these plays and also the additional plays we have in the company, the company is very focused on increasing the recovery factor. And so we're using new frac technology, drilling wells on a downspacing program, connecting more rock to the well and adding reserve potential as we go along in each one of these plays while also decreasing the cost of the wells dramatically too. So the efficiencies on cost reduction and the remaining upside on the play, we feel like it could potentially be very large.

Also, we've been a first mover over the years in the shale plays, and coming up with new greenfield plays. We did add the Delaware Wolfcamp play this year, that's about 800 million barrels equivalent net to the company and we have a 1100 locations in inventory in that play, it's a bit of a combo play, but it's just an example of being able to bring new plays to bear in the company and continue to add to the already big inventory that we have and already even in the first year we began drilling in that play. We're already generating after-tax rates of return of 60% in the play initially. And the play has got a lot of room to move on the upside as far as reserve recovery because it's really low recovery factor right now and certainly, we hope the economics will improve overtime.

So when you think about EOG, you need to think about a lot of oil, a lot of growth really fast and it's really high margin oil, is going to the bottom line very quickly. So when you think about through 2017, we can easily see that we will continue to be the best-in-class, the best in a large cap group in growing oil. We've been at a 38% compounded average growth over the last six years, 43% over the last three years.

Natural gas liquids, as you look forward in the company, there is a lot of associated gas with all these plays and so we will expect to be in the top tier on NGL growth as we go forward. And then on natural gas, the company has tremendous amount, multi TCS of gas that we discovered and captured when we first got in the horizontal shale gas. And we haven't -- since we have the opportunity to drill these high return oil, in the last couple year we're really not interested in drilling gas volumes. And we've actually sold some of the non-core gas properties to maintain our -- do not have a funding GAAP in the company.

As we go forward, we are in a free cash flow mode, no funding GAAP, we have to worry about and so we don't have to sell properties as we go forward. We haven't been drilling gas wells recently, so our gas decline rate and the company base decline ratio is really low and we believe with just the associated gas on the oil plays that we're going to have that we'll be able to have at least that flat to modest gas growth as we kind of go forward, so total growth in the company should be really good as we go forward.

What's new, I mean, if you listen into the earnings call, we increased our year-over-year growth rate in crude oil the second time this year from 35% to 39% because of the tremendous performance of the wells. NGLs went from 14% to 17% and then total company growth went from 7.5% to 9%. As I've said, we continue to achieve very strong direct ATROR rates of return in all three of the main plays, the Eagle Ford, the Bakken and the Leonard play this year.

And then in our Western Eagle Ford acreage, we drilled a large number of wells in that part of the play in this year 2013 and the results are excellent. I'll show you some specific examples on that. So we've now brought those direct rates of returns up in excess of 100% and they're really a big part of the production growth profile that we've seen in the Eagle Ford this year.

And our LOE costs and our DDNA costs because our production is going up so rapidly and our guys in the field have done a great job of holding those costs down, those are also trending downward, and we think that those will continue to go well too.

So obviously the company has been in a low net debt-to-cap ratio company for a long time and directionally we've already reduced that from 29% to 25% this year and that's the focus of the company going forward. We continue to think that that will move downward.

When you think about 2014 through 2017, when you think about EOG you're really thinking about that we're going to be one of the largest oil producers in the U.S., and that includes Alaska and offshore. We're already the largest producer this year in Texas, which is the largest producing state. We're near to being the largest producer of oil in the Lower 48 and we believe that we will be largest producer in the Lower 48 in the near future. And then we've got our sights set on being the largest producer in all of the U.S., so we have a tremendous inventory of oil to drill.

As again we talk about, this oil is very margin oil. It's going to be bottom line very quickly so that cash flow of the company is improving significantly each year as long as oil prices stay fairly good and earnings per share is going up and then we're beginning to generate a lot of cash flow and free cash flow.

And the priorities we've given for that is, number one; we want to continue to take care of the shareholders first. We've had 14 years of dividend increase. And as we go forward, we obviously want to continue that and may be have a little bit more healthy dividend increase than we've had in the past; we've got room to do that. We're not going to be a dividend company; we're a strong growth company, but we really want to continue to increase that as we go along.

We certainly as we talked about the net debt to cap is going to continue to go down as we go forward. And then really the bulk of the money, nearly all the money is going to go back in to the best play. And we have the inventory to do it and we have the capacity to do it. The company has a tremendous ability to execute in the field. We're a very decentralized company and we're already making plans to make sure we have enough people, enough equipment, enough infrastructure to properly directly that capital in each of our best plays as we go forward. So the company is in good shape to continue to roll the company strongly and continue to generate these really high returns that we've been doing.

So who is we again? Just to recap, best horizontal crude oil assets in North America. The last three years we've averaged 43% crude oil growth, much very, very strong. The differentiators, which is oil versus NGLs and gas, big uptick in the product price, we've been a leader in completion technology for years in the horizontal completion process that's been going on, and we can talk about that specifically more in a minute. We've been able to get the highest price available because we were early movers in the crude oil, crude-by-rail system. We've been hauling oil from our Bakken to the Gulf Coast and to Cushing since 2009, and we continue to have developed our crude-by-rail distribution system and it gives us a lot of flexibility as we go forward to get the highest prices.

And then cost. EOG typically in all of these plays is the lowest cost operator and that's because we do a lot of things like we self-sourced our own sand. But we really worked on cost on all parts of the process, so low cost, high price, high return that's EOG.

This is a slide that you're probably familiar with crude-by-rail system. Like I said, we've had five years of experience in that. And we've opened up markets in the East Coast or the West Coast, but still really we're really getting the best prices at Cushing and LLS and we own all of our loading facilities, we own those as a company and many of the unloading facilities we own or operate. And so we actually can move our oil at a lower cost than most folks because it speaks of ourselves sales volume. So it is going to give us a lot of flexibility as we go forward. We don't see their huge differentials between Cushing and LLS but may be we've had in the past, but it will still give us the flexibility to move our oil.

When you talk about -- this is an independent analysis on ROE and ROCE for this year estimates and you can see that as we produce this high margin oil it's going to the bottom-line and ROE and ROCE are improving and we expect that to continue to improve as we go forward.

And then U.S. horizontal oil. I think there is a big concern from some folks that we're going to drill horizontal oil production so much. We're going to outpace the capacity of the refinery system to actually refine all this white crude. We don't believe that that's going to happen. If you really look at all the data really closely there's two plays that are making nearly all oil that Eagle Ford and Bakken are continuing to make 80% of all horizontal oil produced. Now there's obviously a lot of information coming out of Permian. Permian has got a huge amount of reserve potential, but the quality of the Permian oil is not ever not going to be the quality especially of an Eagle Ford well and you're not going to see the Permian in our view ramp up like we've seen this rapid ramp up in the Eagle Ford.

So as we look forward we're already seeing the rate of growth in the U.S. beginning to slow. Last year was a little over million barrels per day per year. This year to-date when you normalize the first eight months to a 12 month projection it's about 600,000 barrels per day per year, it may go to 700,000 barrels per day per year, but we really don't believe there's going to be a million barrels per day per year. And as we go forward even with the Permian coming up a bit we believe the rate of growth of U.S. oil production is going to slow.

This is a chart that shows really the explanation of the quality of wells. It's now the production rate versus the number of wells, so simple plot that's deeper the slope, the better the well. And so the Eagle Ford is the red one. You can see the steeper slope there, because it's the best wells and that's the reason that the production has been so easily to ramp up really rapidly.

If you look at the Bakken it's a bit less than that and a little slower ramp up. And if you look at the average Permian well even taking into account some significant improvements in the Permian well, Permian wells it's still lower quality wells on oil production as is the Eagle Ford and Bakken so it's going to be slower to ramp up, takes a lot more wells, a lot more time, and a lot more money to grow oil in the Permian that it did especially at Eagle Ford.

If you look at EOGs production, cumulative production in the Eagle Ford versus the peer group and the Eagle Ford where we have over double the amount of production in the slope of the curve it's steeper than the rest of the group, so we're way out in the lead, and we're gaining on the lead in that. If you look at the cumulative production in the three big plays the Bakken, the Eagle Ford, and the Permian, again EOG has more than a two to one lead and the slope of the curve is steeper and so we're way out in front and our lead is only going to increase. And it's really because we have the higher quality acreage and the ability to execute as we go forward. That's why we're confident that we're going to be the peer leader in oil growth as we go forward.

Again, seven years of 38% compounded annual growth in oil and 37% in total liquids and when you look at our inventory it's very deep. Currently we have 12 years of inventory in the Eagle Ford; 12 years of inventory in the Bakken, if at current rate 83 acres of inventory in the Leonard and so forth as we go down the road. So the company is not running out of inventory and this does not include any increases in additional wells from downspacing recovery factor any of that. We've been more than replacing our drilling inventory each year by finding new ways, improving the recovery factor of all these fields, and we're very focused on that technically and hopeful that that will continue as we go forward.

Production growth in the company as we've talked about 39% last year, 39% this year in oil and in NGL 17% this year and as we talked about continue to be the best in large cap double-digit growth as we go forward through 2017. And then on gas, as we talked about earlier no gas sales, not any high decline gas wells in the last couple of years, so the associated gas in our oil properties we believe that will be have flat to modest growth in gas. And then the same thing internationally we believe we will have flat gas as we go forward internationally. So the total growth of the company should be a bit far more than the previous years.

This is just a revenue mix and EOG has changed from gas to oil. Currently it's 88% of our revenue is liquids and nearly all that is oil. As we did that the margins improved the red is the percent oil of our revenue, and you can see the cash margins are improving, as that has increased. Committed to the dividend 14 years, 20% compounded annual growth right on that as we go forward, may be a bit more healthy than the 10% last time.

And then let's talk specifically about the Eagle Ford EOG has the largest position 569,000 acres in the crude oil window, 639 includes the gas and the wet gas part of the acreage, up 64% year-over-year production growth in the Eagle Ford, from our position in the first nine months of this year and again we talked about the western acreage, we've been able to complete some really good wells this year in the western part of the acreage. So we've had two increases so far in the Eagle Ford. We went -- the last one was we went from 1.6 billion barrels to 2.2 billion barrels. We're currently at the 2.2 billion barrels and that's 8% -- that's only an 8% recovery of the 26 billion barrels we have net to the company captured under our 569,000 acres in the oil window.

So we have 26 billion barrels to work with, that's a lot. So we're very, very focused on trying to increase that as we go along, so we're on the third set of downspacing and we're always improving the recoveries with the frac technology and then on top of that we're also experimenting with secondary recovery in the field too. Again, this year the western acreage economics we brought those way up and there were big contributors for growth and we're now getting 100% rates of return on all that.

This is an example from the frac technology only that no geology involved here, just completion improvements. We've seen a 30% improvement just due to our completions just from year-over-year in the wells and a 20% over the first three quarters in the initial IP. This is in the west -- this is an example in the western side of our acreage.

The western side again, we've been able to drill a bit longer laterals that helped the wells a little bit and then as we've done that we've actually been able to drill wells even quicker so our drilling efficiencies have gone way up.

We started at 400 wells this year with 25 rigs. We're now up to 460 wells with 25 rigs, same amount of rigs but lot more wells just due to drilling efficiencies and that of course that's reducing the cost of the oil as we go along.

This is a map that just shows list of wells in the third quarter. There's a lot of data on here, but generally, we're making 2000 to 2800 barrels per day wells in the west and 3000 to 4500 barrels a day wells in the east.

In the Bakken/Three Forks we have just recently increased our inventory due to the success of downspacing from 7 years to 12 years. We are very focused right now on the core area where we have 90,000 acres. We're in there drilling our downspace wells basically four wells per unit and we're using the new completion technology. We brought the technology that we've learned from these other shale plays from the Bakken, from the Eagle Ford and from the other places and we're doing a lot better job at completing these new wells, a lot more sand, a lot more stages, a lot better distribution in the frac along the laterals and the IPs of the wells are excellent and more importantly the decline rates on these newer wells are much shallower. So we're now generating 100% rates of return on our Bakken drilling.

We're having really good success in our Antelope area and the Three Forks really. We've had a really good second bench and a lot of first bench wells there. And this is an example in the Core and Antelope area of just the improvements we've had on completion technology, went from 58% improvement just due to completion. This is normalized on 9200 foot lateral, so not a longer lateral, it's just really completion improvement and the 30 day IPs are up 50%, so tremendous improvements technically in the wells.

This is an independent analysis of the top 10 Bakken horizontal wells. EOG has seven of those and I think that will grow as we continue to use this new completion technology. This is an independent analysis of the average 30 day IPs from the top 20 operators. EOG is about 50% better than the average operator on the Bakken well.

In the Permian, we have three plays, the Leonard and the Wolfcamp and the Delaware side of basin and the Midland Basin and the Wolfcamp. In the Leonard, we've got 73,000 acres. We've got multiple plays there, two plays in some areas four, in others. It's really a office about 50% of the production is oil; our current target price for 5.5 million oil and we're generating 100% rates of return on that program right now. This program will get a lot more money we've talked about next year.

And then the Delaware, Wolfcamp, we continue to increase our acreage position. We did add 20,000 acres in the third quarter. We now have 134,000 acres there and it's got multiple type targets, a very thick section, some places over 2,000 feet thick and we just now started really defining all the different productive zones in it and trying to increase the recovery there as we go forward. But already we're generating 60% direct tax returns on this play.

And this is an independent chart that shows the average 30-day IPs on the Delaware side of the basin. You can see EOG is right up there and second place on that and certainly a lot better than the average in there and we just really just got started. In the Delaware lot of room to work on that and to continue to make that better.

And in the midland Basin Wolfcamp we have 113,000 acres there. We continue to kind of high grade our acreage; it's not been a strong part of the Permian as the Delaware side. We're generating about 30% a-tax rates of return in that, good place, good place to drill well but it just ranks a bit lower in our portfolio things to do.

And then internationally we have Trinidad production. We have a contract . there that we are -- as we just go forward we would be able to drilling up wells just to keep that flat. And then in the UK in East Irish Sea we made a oil discovery there a couple years ago. We have been in process of getting that hooked up and we believe that will be on the latter part of next year and that is about 20,000 barrels a day net to the company.

Again, just to wrap it up, as you know, EOG is a are very conservative company, whether you are talking about reserve potential on new plays and existing plays, are you taking about booked reserves, are you talking about the financial position of the company very, very conservative. We got a Moody's A3 and an S&P A minus rating, I think one of the only two companies that have A rating in our peer group, successful effort accounting, zero good well.

Again, 14 years of dividend increase and we are thinking about being a bit more healthy as we go forward. And then we've had 25 straight years where we have audited 80% of our proven reserves and move with 5% of the (inaudible). So very conservative company in all aspects.

Our hedge position. We have been targeting about 50% of our crude oil to be hedged, remainder of this year is a 126,000 barrels a day of 98.80. The first half of next year 123,000 of barrels of 96.44, very lightly hedged on gas.

And then just to wrap it up, the game plan this year, we are about to line that down and get it finished but it certainly has all been about oil, its going to be all about oil as we go forward. 39% this year, year-over-year growth we're going to -- we've been focused on these key assets that we have talked about and we will continue to do that. Very focused on improving recovery factors in each one of these plays and we will continue to do that as we go forward. We've been a leader in identifying new greenfield plays. We are very confident as we go forward that we will be able to continue to be a leader in that area. Don't think we're going to find another Eagle Ford that size and quality, but there are plays out in North America that we feel good about that we are hopeful that we will bring forward. We are not interested in drilling dry gas until dry gas gets a bit better price and certainly the net debt-cap ratio the company is going to continue to go forward. So that is the EOG story.

I appreciate your listening. And I guess we'll now turn it back to Doug.

Question-and-Answer Session

Doug Leggate - Bank of America Merrill Lynch

Bill, thank you very much. So again folks wielding microphones please make yourself available if you have any questions.

So Bill, maybe I could kick off with a couple -- I guess there are (inaudible). The first one is, it seems on our numbers anyway that EOG is going to move to substantial free cash flow position starting next year. How should be think about your priorities for allocating that cash flow (inaudible) dividend but clearly your inventory is still fairly robust? That is my first question. And my second one is, it is really more like a technical question I guess. Could you help us understand a little bit more of how repeatable you believe your initiatives in trying to improve recovery rates is across your portfolio particularly where you have already drilled up a lot of your acreage for example in the Bakken, can you go back to that?

Bill Thomas

Yes, sure. Yes, as we talk about, we did give some -- we have given a lot of guidance on our priorities for our cash flow, dividend and a bit more healthy going forward. We are not -- we are definitely going to not have a funding gap. We are not interested in an out spending our cash flows, so we are going to be able to have a significant amount of cash flow. If the oil process stay like we think they're going to stay, we're going to have significant amount of cash flow to reinvest each year in our best plays. And we have the inventory to do it. We have an immense high quality inventory to reinvest at very, very high rates return. And again, the plays that we talked about, the Bakken, the Eagle Ford and this Leonard play, we have more than 10 years of inventory in each one of those. And the inventory could go up on those as we work on -- continue to work on recovery factor, so there is no problem in inventory.

Then we have got a whole big set of what we call these combo plays that we have captured and basically held our production. And then we have -- on top of that we have multi TCFs of gas that some day when gas prices recover, we can be able to grow gas with the best of them. So the company has not a shortage of very high quality inventory to reinvest more money each year. And we have the ability to execute, I mean EOG has a history. If you know the company, we have been -- have a very strong history of execution. And we have a very decentralized structure. We are adding a bit more people all the time, we're able to add incremental amount of frac spreads, amount of drilling rigs. And as awe find out we do not have to add a whole lot more equipment because we the efficiencies are getting so much better, we can frac a lot more wells with the same equipment, we can drill a lot more wells with the same drilling rig.

So it does not take as much as people might think to really increase your activity level in each one of these really good play. So we have the ability and we're very confident we can execute on that.

On the frac technology, all these horizontal plays, as you all know, there is -- most of them are source rocks or near source rock, they have an immense amount of hydrocarbons in place. So you have a lot to work with, like the 26 billion barrels we have in Eagle Ford. So you're always trying to connect up more rock to the well. And our focus has been to connect up to more rock to the well or closer to the well so that we can drill additional wells without sharing production between the well.

And EOG is very much a technical leader in this, is big technical focus in the company. We have taken total ownership of all of that. We do not rely on any service companies to provide information or technology on how to do that. We have very, very highly integrated teams of geologists and geophysicists and engineers and have a lots of data, lot of rock data, a lot of 3D seismic data, a lot of what they call microseismic data that you can actually see the geometries of these fracs. And we're obviously getting real time data, production data and real time results and we're very, very forward looking on extermination all the time.

So we're always working on, how do you get more rock connected to these well, so that you can get a bigger recovery. And when you see the IPs on the rate -- on the well is going up is because you connected more rock. And so that's a really good indication that you are making good success. So we're very focused on that and we're hopeful really in all the plays that we're working, not just Eagle Ford that will continue to do that. We -- like I said, we have more than replaced our inventory every year just with that, so.

Doug Leggate - Bank of America Merrill Lynch

Again, if any have any questions from the floor please make yourself known. If I can peal the onion, may be just a little bit further bite, Bill, and forgive me for getting a little technical here. But so our understanding is you are keeping the frac closer of the well bore. How does that impact long term metrics contribution in terms of what it does for the specific clan[ph] curve, further out that you do not have any history on right now?

Bill Thomas

Yeah. No, I mean when you see the IPs going up that is a good indication, it's like I said that we're doing a better job connecting up more of the reservoir with the well. And then the initial IPs as we have shown in these graph, I mean the cumulative production of the first 30 days or 100 days, 120 days in some of these cases is very -- is higher. And so the initial part of this clan[ph] curve even though the RFE is higher is similar, okay. The key is when you are downspacing, putting the wells closer and closer together, you need a bit more time to see if there is any significant production sharing. And that is where we're in our third phase in the Eagle Ford right now. We've got a number of patterns drilled on tighter spacing and we completed them. We're now in the process of trying to get nine months to a year of production so that we can see what the ultimate EUR per well might be in the downspace situation with the improved frac technology too, it is all the combination. And in all of this process, we're also reducing the well cost. So it is really moving process that we're very, very focused on that and we're basically trying to increase the net present value.

And I want to make this clear, there were some questions on our third quarter call about this, we're not interested in taking the rates return down to real low. Even on our downspacing we're still looking at a 100% direct after-tax rate of return. So it is a balancing act between all the different metrics.

Doug Leggate - Bank of America Merrill Lynch

Anyone in the floor?

Unidentified Analyst

You used the word waterflooding, would you care to talk about what area is most enthusiastic about that potential and how that fits in with just return aspects you talked about (inaudible)?

Bill Thomas

Yes. No, that is a good question. Specifically on the waterflood, we have a waterflood pilot going on now in the Bakken and there has been a bit of -- quite a bit of studies from the universities and we have done our own in-house study. And when you put water on the Bakken, it absorbs the water and it expels oil, in the lab. So that's good in the lab but you got to figure out how to do it in the field. And we did our first pilot on our -- when we were on our 640 acres between spacing, one well per section and basically, we just did not get any answers there. It basically told us that 640 acre spacing is much too wide to try that kind of process.

So as we go into the core well per section, kind of senior that we're in now and we're doing a better job with the frac connecting up more reservoir, we'll go back in and retry these waterflood efforts there. But I think we're optimistic that in the better plays, again that's the advantage of having a better rock, the better the rock is the more conducive it is the secondary recovery. So in the Eagle Ford, we're doing dry gas injection pilots there and in the Bakken we're doing a waterflood pilot. So in at least those two playas we're optimistic that we'll find some mechanism to enhance the recovery over time. We haven't proven it yet but that is a process we're very much engaged in.

Unidentified Analyst

Okay. [Question Inaudible].

Bill Thomas

Yes. No, it's -- and I have done this, I have plotted up some of the recent data from some of the very best Permian wells and plotted that against some of the -- just again some of the Eagle Ford, our typical Eagle Ford well and what you see is you see the oil declining much steeper. In fact, they're pretty steep in Eagle, but it is even steeper in the Permian. And it lower -- it levels off at much lower level.

So those charts that I showed that compared the three plays, even with significant improvement in the average Permian well the rock quality in the Permian, in any of the plays is not nearly as good as Eagle Ford. And so it is just going to be a lot more difficult to grow volume in the Permian and I think than most people give a credit. That's the way we see it.

It is not that there is not a lot of reserve potential there, the reserve potential in Permian is huge. We're not saying that is not going to happen, it's just you're going to have to drill a lot more wells, it's going to take a lot more money, a lot more time to grow production. So you're not going to see the Permian just ramp up in two years from almost zero to 900,000 barrel per day, it's just going to be a slower growth rate.

Doug Leggate - Bank of America Merrill Lynch

Bill, I may close out with just a couple questions that maybe (inaudible) a little bit the guidance for next year or two. What proportion of your growing program do you expect to be on this more -- let us call this more aggressive fracturing approach to the -- particularly the Eagle Ford? And can you explain why you have not yet increased your EURs per your old design, if you like, particularly in the western part of the Eagle Ford?

Bill Thomas

Yes. I mean the program going forward in the Eagle Ford will be much the same. We've been on a pad drilling very, very fast pace and so the nature of the program and the Eagle Ford and the Bakken and now we will -- we have not been in the program mode in the Leonard up to date, but as we go in the next year we're going to be putting more capital on the Leonard. And so we have a continuous multi rig program there with at least one or two fracs spreads that will be continuously working there, so that will be more in a program mode. But I would say in Eagle Ford, we have been a strong program mode; we're just going to increase that. And then in the Bakken, we have been a bit testing to downspacing, we will be in a bit more program mode in the Bakken than we were in last year and in the Leonard certainly and a lot more program mode. And then, the second part of your question?

Doug Leggate - Bank of America Merrill Lynch

EUR is in the western part of Eagle Ford?

Bill Thomas

Oh, yes. That again is just, we have not had enough time to see the full effects of the downspacing, so we really need the 9 months to 12 months on multiple patterns to really make sure we know what the ultimate EUR per well on an average basis going forward will be. And so we have got a bit more time to work on that.

Doug Leggate - Bank of America Merrill Lynch

Thanks, Bill. Folks please join me in thanking Bill.

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