EOG Resources Inc at UBS Houston Energy Bus-less Tour

Houston Sep 15, 2016 (Thomson StreetEvents) -- Edited Transcript of EOG Resources Inc presentation Wednesday, September 14, 2016 at 4:15:00pm GMT

TEXT version of Transcript

Corporate Participants

   * David W. Trice

      EOG Resources, Inc. - EVP, Exploration and Production

   * David Streit

      EOG Resources, Inc. - Director of IR

Presentation

Unidentified Participant [1]

 We're going to move on to our next presentation, which is EOG Resources. And similar to Anadarko, we have great timing in having EOG here after their recently announced acquisition of Yates Petroleum.

 We have two members from management -- David Trice, who's Executive VP of Exploration and Production; and David Streit from the Investor Relations department. So with that, I will hand it off to the Davids.

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [2]

 All right. Thanks, Bill. Appreciate you having us out today. What I want to do is just start off and go through about 20 or so slides, and then open it up for Q&A.

 So really, just start off with the new news for EOG, which -- the biggest piece of news that's come out lately is this merger with Yates. And so just wanted to run through some of the highlights of that.

 What really drives the transaction here? The number-one part that drives it is the Delaware Basin. So Yates had a very large position in some of the very best parts of the oil window, the Delaware Basin. And so that's really what drives this transaction.

 And then secondarily is the Powder River Basin. We see a lot of emerging potential in the Powder River Basin, and there's a very good fit there in the Powder.

 So really, the total net acres in this transaction is 1.6 million net acres. And what this does is it really helps us upgrade our inventory. So this isn't a transaction to where we were looking to just add inventory. We were actually looking to upgrade. And so we added 1,700 premium net locations there. And really helps us enhance our position.

 So some of the other parts of the deal is, I mean -- like I said, it was a very good fit on acreage. The infrastructure is going to help us really increase the capital efficiency going forward and give us really good returns. And again, this competes within our existing portfolio. So we'll be drilling on this starting late 2016. So very soon after the deal closes, we'll be moving rigs in and drilling on it.

 So it's a unique deal. I think has been described as kind of a once-in-a-lifetime deal for EOG. And we don't typically do these kind of deals. But we've always said that if the absolute right deal came along that we would be interested in doing this type of deal.

 And so in this case, really both partners, both parties, were looking to generate long-term value. Yates has been in business for 92 or 93 years. And so they look at things from a long-term perspective. And so when they've looked to make a change, they've looked at EOG and felt like EOG could be the very best at developing the assets that they'd acquired over all these years.

 So prior to the Yates announcement on our second quarter call, we came out, and we had increased our premium count, our premium location count, by 1,100 -- from 3,200 to 4,300. Of course, with the Yates transaction, that goes up to more like 6,000. And we increased the reserves up to 3.5 billion barrels of equivalent. And then, I'll show you in a second, once you include Yates, that goes to 5.1 billion.

 And we also introduced our 2017 to 2020 growth outlook on oil, which shows a 10% to 20% compounded annual growth rate. We beat all the high-end guidances in the second quarter, and we reduced our per-unit lease and well cost [about] 23% year over year. So we had an outstanding quarter.

 And then, for the full year, we increased our US oil forecast about 2%. We've lowered really all of our forecasts on transportation LOE. And in addition, we sold $425 million worth of properties year to date. So we're always looking to dispose of properties that are non-premium. So as we've looked to add, kind of at the top end of our premium, kind of the modern part of our inventory we'll always be looking to sell.

 So the first quarter, we didn't sell a whole lot, just due to prices. But in second quarter, we were able to sell quite a bit. And that process will continue.

 And then, the other thing we note there is we're shifting to longer laterals in the Delaware Basin and in the Eagle Ford. We've always been really focused on, really, on the technology side up front on these plays, so we really focus hard on completion technology and on targeting.

 And so early on in the days of Delaware Basin, we had actually been drilling longer laterals. But we figured out that we were not quite completing those wells as good as we'd like. So we dialed them back and started drilling one-mile laterals, really focused on enhancing the targeting and completions, and really came up to speed on the completions. And so now we're able to take those high-density EOG fracks and push those out to 1.5- and two-mile laterals. So that's a big step change there.

 And then, we're going to end up completing 80 more wells and drilling 50 more wells within our sale CapEx for the year. And that's just due to ongoing efficiencies, being able to drill and complete the wells for a lot less money.

 So one thing, when you think about EOG, just always think of rate of return. We're always focused on giving a good return for every dollar we invest. And really, we have the best and most diverse assets in the lower 48. And so that allows us to have the scale we need to really lower cost and leverage the technology we have across the Company.

 So if you look at our position, we have a large footprint in the Eagle Ford, Bakken and Delaware Basin. And then, like I mentioned previously, the Powder River is an area where we see a lot of upside in the future.

 So we're a technology-focused company. We're always looking to really push the envelope on the completion side, targeting, and really doing a good job of integrating all the geoscience information with the engineering. And I think that's one of the things that sets EOG apart is just being able to integrate all that data in a very good fashion. Just from, anecdotally, my experience talking to associates at other companies, there's a lot of lip service to that. But in many cases, that falls short. But within EOG, we're very focused on collecting the data and integrating that really throughout all disciplines.

 And we're a low-cost operator. We have the highest production per employee. We're vertically integrated. We've been in the sand business a long time. We have seen a lot of benefit to that over time, a lot of reductions in cost. And we've seen that as a real advantage as we look to the next up cycle, being able to control our own sand supply, as well as the other lines of products there.

 We are known as organic growth machine through exploration. We continue to always look to come up with new ideas and to get out in front and lease at a very low cost.

 And then really, kind of the last point on the slide there, just our organization and our culture really sets EOG apart. We're a decentralized company. We have division offices. And really, all of the decision-making and really the innovation happens in the division offices. And so it's really very much a bottom-up-driven company. And everybody is compensated based on returns. So everybody knows that the way to really be funded and rewarded within EOG is through returns.

 So we've talked a lot in the last few months about premium drilling. And so just wanted to talk a little bit about premium drilling, and just a definition. I mean, this is a means by which we can really be much more disciplined as far as our capital investment. And to us, what defines a premium location is a well that will generate at least a 30% after-tax rate of return at $40 [lateral] well.

 And so the key thing to note there is that the benchmark does not change, that that's the definition, and even as prices change, that the definition will not change. And so what that does is gives us a significant increase in capital productivity. So as we look in the future to shift to more in a growth mode, you'll not need nearly as many wells to see a very strong growth performance out of EOG.

 And so we can add new premium locations in one of three ways. We can either convert the existing inventory -- so we'll do that through either technology, such as better completions or better targeting -- we can also do that through lower costs. One way there is, like I mentioned before, longer laterals. As long as we can maintain the productivity throughout the lateral, then we can drill longer laterals and lower the cost.

 Exploration is another way we can add to that. And then, tactical acquisitions is also a way that we can do that.

 And then, as far as what we would do with the remainder of inventory, if we see that it will not have an opportunity in the future to make it into premium status, then we'd be able to monetize that in some way.

 So this chart just shows, on the right-hand side, shows what these premium wells will generate at various oil prices. It seems to be that, at $40 oil, the minimum that each of these wells will generate, these premium wells will generate, is a 30% rate of return. But as oil prices go up, you'll see a tremendous increase in the rate of return of these wells. So at $50, it'd be at least 60% rate of return. And at $60, it'd be much over 100% rate of return.

 And on left-hand side just shows the percentage of premium wells drilled by year. So this year, we estimate approximately 60% of the wells that we're drilling are premium, going to 80% next year, and then essentially 100% from 2018 onward.

 And then, like I did mention before, with the Yates transaction, we have about 5.1 billion barrels of equivalent in our premium inventory. And that represents about 6,000 locations. So much more than 10 years' inventory there.

 So this is a new chart that we put out this last quarter. And this is just to give the investors a look at what our production could do over the next several years into 2020. And so what we show here is that at $50 oil, we could grow at an annual rate of 10%. And then, at $60 oil, that would jump to 20%. And this is all within cash flow. And we define cash flow as CapEx plus dividend. So we could do this without increasing the net debt.

 And this slide does not include anything in regards to dispositions. And it also does not include anything relates to Yates.

 So just a little more detail on the Yates transaction -- again, it was 1.6 million acres total. One hundred eight-six thousand net acres of that was in the Delaware Basin. And like I mentioned before, this is very prime acreage in the oil [is] part of the basin. It's located in Southern New Mexico -- 138,000 net acres on the North West Shelf, 200,000 acres in the Powder River Basin. And so that's just kind of the main exploration fairway within the Powder River Basin.

 And then, the other basin, the other Western basins, is about 1.1 million acres. And with this deal, we get 1,700 premium locations, which represents about 1.6 billion barrels of equivalent.

 And on the production side, it's about right under 30,000 barrels a day of equivalent production -- 44 million barrels of equivalent approved reserves. And the transaction value on that was about $2.5 billion, almost all in stock; about $151 million in cash, mainly for debt, just to assume the debt.

 So closing on this is expected to be in early October. So we filed a Form 8-K with SEC last Friday that includes the summary of the terms of the transaction agreements. This was a straightforward corporate transaction. EOG and its advisors will provide a sufficient time to conduct a full due diligence review and risk assessment prior to the signing of the transaction agreements.

 There are no make-whole tax payment provisions in the transaction agreements as would be typical for a corporate transaction. EOG would expect to record a noncash-deferred tax liabilities after closing, as required under the Generally Accepted Accounting Principles.

 So to look a little bit more in detail on the acreage, the map there at the bottom in green shows an outline of the Delaware Basin. And EOG acreage is in yellow, and Yates acreage is in blue. So you can see there's a very good fit between the two companies there really across the basin. And so what this gives us is a leading position on the Delaware Basin of 424,000 net acres total. Yates brings 186,000; EOG brings 238,000. So a very, very good position, and really the hottest basin in the country. So this is going to enable us to drill longer laterals, and then concentrate our development in the key areas.

 So prior to this deal, we had about 50%, maybe a little bit more than 50% of our acreage was amenable to longer laterals. And so post-Yates merger, that number will certainly increase.

 So we'll be able to utilize the existing infrastructure. And then, Yates -- about 74% of it's held by production. And then again, we do plan to start drilling on this here at the end of the year.

 Another piece that we picked up in this transaction is the North West Shelf. And EOG has not been active in this area; some industry has been active in this area. But we do end up with a 150,000-acre position in this area. And so this is perspective mainly for the Yeso, the number of companies have been up -- have been drilling in this area; but also to Abo, Wolfcamp and Cisco. And so the real goal here is to be able to lower the cost. And we think, with EOG technology and cost structure, that this has a lot of potential to add premium locations in the future.

 And like I mentioned before, the Powder River Basin is an area that we've been more and more excited about. So this transaction does help us there.

 So can see on the map at the bottom of the slide there that there's a very good fit between EOG and Yates. This is -- the darker green here is really what we refer to as kind of the development core. And if you look at the map on the top of the slide, there's kind of a lighter green area that's more the exploration fairway. And so within the development core, the combined company has about 200,000 net acres there. And then, in the larger exploration area, there's about 400,000 net acres.

 And again, this area is very prospective. We have about 4,000 to 5,000 feet of stack pay here. It's kind of a similar setup to the Delaware Basin. But we're fairly early on. But we're already drilling quite a few premium wells here. And a lot of our Turner wells we've talked about recently are very, very good wells. And then, 83% of the Yates acreage is held by production.

 So if you look at the total premium counts that we have -- so in February, we came out, we announced 3,200 premium wells, without about two billion barrels of equivalents. Then, just this past month, in August, we updated that. So we added 1,100. So that brought us up to 4,300 premium wells at about 3.5 billion barrels of equivalent. So not only did the count increase, but the reserves per well also increased.

 And then, with the Yates transaction, we had another 1,700 wells, at 1.6 billion barrels of equivalent. So once you total it all up, that ends up giving us 6,000 premium wells at 5.1 billion barrels of equivalent. So just over the course of six or seven months, we've been able to nearly double the location count.

 So this is another new slide that we've got this last quarter on the Wolfcamp and the Bone Springs and the Delaware Basin. So one thing to note here is that we did put our 750,000-barrel equivalent top curve on here. So you can see over the last couple years that we've been doing a very good job of beating that. And that's just through just better targeting and better completions.

 So these are very, very good wells. The majority of these wells are either in Southern New Mexico or just within a couple miles south of the state line. And this is some of the very best wells in the industry. Probably a couple of these wells, some of the ones we've announced the last couple quarters -- the Thor and the Rattlesnake -- may actually be the best wells in the entire premium.

 And so this is what we were really focused on on the Yates transaction was to add more Wolfcamp, Second Bone Springs and Leonard inventory here. And we do see quite a bit of potential in the Wolfcamp in Southern New Mexico.

 You go to the next slide -- this is a slide we've had out for some time. This just shows 90 days' production for EOG's Wolfcamp wells versus the rest of the industry. So the wells in blue are Delaware Basin, and the Wells in green are Midland Basin. So you can see that EOG wells normalized, on a 5,000-foot lateral, about twice as good as the rest of the industry. And so that's another driver for the [etch] transaction.

 I also mentioned that we were shifting to doing longer laterals. So this is an example from the Eagle Ford. So here's an example of where we've taken two one-mile sections, and we've been able to combine those into a unit and drill longer laterals. And the key here is that the one-mile laterals were not quite premium. They're at 24% rate of return. But if you do the two-mile laterals at a $40 flat price, that increases to 49% rate of return. So this is one of the ways that you can increase the premium inventory. And so we'll be doing this in the Delaware and in the Eagle Ford.

 On the Eagle Ford, we have a lot of wells, just like that past example, that are very close to the premium threshold. And so this slide here shows that we could essentially double the premium count in the Eagle Ford by either lowering the cost 10% or increasing the EOR by 10%. So again, that goes back to the cost side of it, lowering the cost or increasing the reserves.

 This slide just shows our (inaudible) [TD days] in the Delaware Basin, and the Eagle Ford and the Bakken. And the main takeaway from this is that you can see the track record in the other plays. I mean, over time, we continually drill the wells faster. We're a little bit earlier on in the Wolfcamp. But you can expect to see a similar trend over time in reducing the days to drill.

 This is the slide that goes along with the previous slide. This just shows the cost. So you can see over time, as we've reduced the days of drill, we're also lowering the cost. And these are actual costs, so you can see the first half of 2016. We were at $6.7 million for the Wolfcamp, $5.1 million for the Eagle Ford, and $6.3 million for the Bakken. And so you can see the target cost on there as well. So really, in all cases, we're very close to the target cost.

 And so over time, you'll see us continually improve on the cost side of it. And this really includes all costs. This is drilling completion that includes onsite well facilities and flow-back. So the only thing this doesn't have in it are the central tank batteries that are shared between wells. But it's really all the costs associated with any individual well.

 This is an example from the Wolfcamp, just showing how we continue to lower costs mainly through efficiencies. So on the left-hand side, you kind of see the diagram of how three-quarters of the cost reductions are through efficiency gains. And that's either from better water handling, faster completions, faster drilling time, et cetera. And then really, only about 25% of the cost savings are through pricing, through lower day rate and such.

 And really, as we look forward, we don't really see costs coming up as far as our total well costs. Because we think we'll continue to get better at reducing cost through efficiency. And we still have quite a bit of higher costs on the service side that are left over from, say, 2013 or 2014. We still have a lot of the drilling contracts that are at the old rates. We have a lot of inventory items that were purchased back in 2013, 2014. So as we work off all those items, we'll actually see a reduction in those costs going forward.

 Now, on the operating side -- we've seen tremendous progress on lowering LOE. This has been just tremendous work by everyone. So we've lowered our LOE by 30% over the last couple years. And we still see a lot of room to run there. We've got a lot of ideas to continue to lower costs.

 And then, this is a slide we've had for a while. It was put out by [Pyrum]. And it just shows that our focus is to be competitive on a global basis. Oil is a global commodity. And so, really, the competition is the world.

 And so this just shows breakeven costs that essentially has a 10% direct after-tax rate of return, what [the] oil price does that take. And of course, you've got Russia and the Middle East are some of the lowest-cost. And then, that cost goes up as you go to some of the oil sands and the arctic projects. But we really see the marginal cost of oil longer term being more in that $60 to $70. And so our goal is to be one of the lowest-cost providers in the world.

 And so right now, we can generate a 10% after-tax rate of return at $30 oil. So that will allow us to ultimately compete with everybody on a global basis.

 So finally, the main thing that we've been focused on really throughout this downturn is to reset the Company. We were the leaders in the horizontal resource plays, the oil resource plays, coming into the downturn. We've been very focused on retooling the Company. And we believe that we will be far and away the leader coming out of this downturn.

 We've done that through just continuing to improve the well productivity and the technology that we employ -- persistent targeting, high-density completions, enhanced oil recovery. We're lowering cost through efficiency gains and infrastructure. And we're adding better and better inventory. The Yates transaction is an example of that. We want to keep adding inventory that competes at the top. And then, we want to do all this and maintain a strong balance sheet. So we want to be able to match our CapEx to our cash flow and monetize all of our non-premium inventory.

 That's it. Thank you.

Questions and Answers

Unidentified Participant [1]

 Plenty of time for questions. Maybe I'll start with a quick one (inaudible). You've seen so many transactions in the Permian in the last several months. And seemingly, every single one is done at 25,000 per acre or more. And then, the Yates deal, if you make some adjustments, it's pretty clear that you got the Delaware at less than 10,000 per acre. Could you just give us some background about how that transaction is put together and help us understand how the price can be so attractive?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [2]

 Yes. I think, really, this was a private deal. It was a negotiated deal. The Yates family were -- they were very keen on doing a corporate deal and doing a stock deal. And they really wanted EOG stock. And so really, what this transaction represents is -- I mean, it really is a merger in the sense that Yates family's been in business for a very long time. And they're looking at a longer time horizon. And so they're wanting to fully maximize the value of their acreage. And they felt that EOG was the very best to do that.

 And the reason why we haven't historically been an acquirer is because typically these transactions are very low rate of return. But this is just one of those situations where the two parties were aligned. Yates family was -- in addition to being long-term players, they're very concerned about their legacy, and they want to be partnered with a good company. So it all came together, and we were able to have kind of a win-win situation there.

 But I agree that the transactions that are going on in the basin -- I mean, they're very high-priced. I certainly wouldn't expect EOG to do any of those kind of deals. Because we don't really feel like if you're paying $30,000 or more an acre, it's going to be very, very hard to get a good all-in rate of return on that.

Unidentified Audience Member [3]

 Hey, David. On slide 10, where you kind of show the map of the acquired acreage from Yates, when I think about -- I guess it's 186,000 acres and looks mostly in Lea and Eddy -- do you have the split on kind of Lea versus Eddy County within the Delaware Basin?

 And then, want to back into locations per acre implied as [six] wells per section. What's the kind of -- how much prospectivity did you put on the Northern Delaware, how many zones per section did you guys kind of apply to that broad brush of Northern Delaware acreage?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [4]

 Yes. On that, really, we just -- for the most part, it's really just the Leonard, the Wolfcamp and the Bone Springs. And so as far as the valuation in a deal like this, it's somewhat of a rough cut. But we feel very confident on the 1,700 locations being premium. And we're confident that that will grow over time.

 So we did -- spacing-wise, it's kind of typical of what we've had in the past, 700, 750 on the Wolfcamp and probably something similar in the Bone Springs. And Leonard is more like 300 to 500 feet, something like that.

 But on the acreage, I mean, just from the map -- on a gross basis, there is quite a bit in Eddy County. But the acreage in Lea County fits very well with our acreage there and really where we've been drilling some very, very large wells. And so we think it's an excellent fit.

Unidentified Audience Member [5]

 But in terms overall prospectivity, how much of the acreage has no premium locations on it? Do you have that rough percentage?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [6]

 Yes, I would say -- I don't have that exactly that for. We probably -- if it's in an area where we haven't drilled wells much, then we wouldn't have put premium locations on that. Again, I think there's quite a bit of upside that we have there. But we mainly focus on the areas where we've been drilling.

Unidentified Audience Member [7]

 How much of the acreage did you say is comparable to your Red Hills acreage? And I guess, can you talk about really where you'll be focusing your rigs and your drilling activities in the next year or so?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [8]

 Yes. I think the activity will be around Red Hills. If you look at the map, you can see that Red Hills is -- Red Hills is block here. And so we've got a really good fit with Yates there. And that's one of the main drivers of the transaction. So that's where you'd expect to see quite a bit of activity. But then, even in the Southeastern part of Eddy, that's also very good. And so you see a really good fit with Yates there as well.

 And then, as you move up to the north, there's been a lot of really good wells drilled in both the Second Bone Springs and Third Bone Springs. And so there's quite a bit of potential there.

Unidentified Audience Member [9]

 I think one of the reason Yates wanted to sell to you guys was because you were going to kind of maintain the office in Artesia. What's kind of the ongoing cost of that? Is it material or not in terms of keeping that corporate infrastructure?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [10]

 Yes, I think that is a good point. We have committed to maintaining an office there. But it fits. Again, it's a situation where the merger really fits between the two companies. Because as I mentioned, we're a decentralized company. So we have all of these division offices. And so having an office in Artesia kind of fits our philosophy.

 Most of our peers tend to centralize. So they'll have everything in Houston or some other city. And so that certainly wouldn't have been a fit for the Yates family, but it was a fit for us.

Unidentified Audience Member [11]

 Got you.

 And you may have mentioned this already, but was Yates active at all in this area? Or were they pretty much shut down?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [12]

 Historically, they've been very active.

Unidentified Audience Member [13]

 Sure.

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [14]

 But recently, they have not had any rigs running. So there are no commitments or anything. But they've been pretty much shut down.

Unidentified Audience Member [15]

 And then, when do you get started on the acreage?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [16]

 Yes, I think as soon as we close. We will plan to close first part of October. We plan on having a rig on the Yates acreage before the end of the year.

Unidentified Audience Member [17]

 Dave, could you comment a little bit on how the Yates cost structure compares to EOG in terms of operating costs or well costs? And where they were drilling, were they using long laterals similar to the EOG? Or is there opportunity for a big step function change in efficiencies?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [18]

 Yes. And I think there's a chance for a huge step change there. We've been associated with Yates for a long time. I mean, we've been in Southeast New Mexico for a long time, so we've dealt with Yates quite a bit over the years.

 But they're not really -- certainly not as far down the road on learning, on completion technology and on drilling, and that sort of thing. So I think you'll see a big step change there on productivity.

 And then, I think just on the overall development patterns, I don't think they've been doing a whole lot of long laterals. And they really haven't drilled any of the Wolfcamp. So there's a lot of -- like I mentioned before, there's a lot of upside there.

Unidentified Audience Member [19]

 Do you think we're going to see another step change in sand usage as we go into these wells? You're talking about the longer laterals; obviously, you'll see more sand there. But if you think about the step change we've already seen in the last several years on sand, do you think that we're starting to hit the ceiling on sand for a while? Talk a little bit about that? And then, the availability of sand for you?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [20]

 Okay. Yes, that's a good question.

 On the sand, we've always been aggressive users of sands. I mean, we got into the sand business a long time ago, and that was the reason. Because we use a lot of it.

 I think going forward, we always look for kind of the optimal level. And generally, more is better. But there is a point where you kind of hit that peak.

 I think here in the Delaware, you probably still have some room to run. We've been -- we continue to experiment with higher and higher sand loading. We probably don't pump quite as much sand per foot here as we might in, say, an Eagle Ford to date. But we keep experimenting with that.

 And again, each play is different. So certain plays, you kind of top out at a lower sand volume. But I don't really think we've seen the top quite yet here in the Delaware Basin.

 And then, on the sand supply side -- again, we own our own sand mines. We've been in that business for a long time. We're very good at the logistics. And so we don't see any, say, bottleneck here in the future as far as growth from sand.

 I do think you will -- if oil prices strengthen, you probably will see some strain on the rest of the industry. If other operators really start increasing sand content, you could see a strain across the industry. But again, that's really where we have an advantage, just being in the sand business for so long.

 Marcy?

Unidentified Audience Member [21]

 You talked about better targeting on the wells. Can you talk a little bit about that? Because you mentioned that you had the integration of your geoscience and engineering department. So is it more of just the kind of value you add in-house? Or is it an outside technology? Because I've heard that more precise targeting with a number of companies. But I'm wondering if that's something developed internally with EOG or if it's in industry technologies.

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [22]

 No, I think really, all of that is internal. And again, it goes back to being a fully integrated group. And it really -- I think that's the strength of the divisions, the decentralized structure. So each division is fully staffed with reservoir engineers, geologists, completion engineers, petrophysicists, the whole group. And they all work as a team. So it's almost like all these little football teams out there that are working together.

 And so we collect a lot of data. We're not shy about taking cores. We run a lot of logs. And we always integrate that. And so what you have to do is, when you target the wells, you have to always fully integrate that with the completion and reservoir data. And it's kind of an iterative process.

 But some of the things that we've done is we've developed a lot of in-house software that also helps with that. So in addition to collecting all the data, we build a tremendous amount of software in-house that really helps all the disciplines to do a much better job on identifying the right target in the first place, and being able to steer the wells in a very narrow window, at the same time while we're drilling very, very fast. And so we've done a lot of work on that side. Some of these guys are drilling hundreds and hundreds of feet an hour or something. And you got to be able to keep the bid in a very tight target.

 So really, it's kind of all of the above. But it's an all-in-house process.

Unidentified Audience Member [23]

 Billy (inaudible) so on the [U] transaction, from a production perspective, pretty close to 30,000 barrels a day, what's the breakout of that production between each of the kind of the basin that you all [acquired in]?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [24]

 It's mostly in the Delaware, and then secondarily in the Powder River. I don't have the exact numbers off the top of my head. Do you have the exact numbers, David?

 David Streit, EOG Resources, Inc. - Director of IR [25]

 About half Delaware, about 40% [ERV], and then the rest (inaudible).

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [26]

 So about 50%-40%, and 10% for the rest.

Unidentified Audience Member [27]

 Okay, great.

Unidentified Participant [28]

 Are there any other questions for EOG? John?

Unidentified Audience Member [29]

 When you think about dispositions, can you just talk about how the gas assets fit inside the portfolio on a go-forward basis, and how you guys think about potentially monetizing those, if at all?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [30]

 Yes, I think on the disposition side, really, the thing that comes to the top of the list generally are gas. So most the stuff that we've sold have been gas properties, or maybe some of the lesser-quality combo properties. So really, that's been the focus for most of the dispositions is gas, especially if it's more of a fully developed property.

Unidentified Audience Member [31]

 (Inaudible question -- microphone inaccessible)

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [32]

 Yes. As far as -- what's your question again?

Unidentified Audience Member [33]

 You guys continue with the program, I think we should expect to see either one-off or larger transactions over the course of the next 12 to 24 months?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [34]

 Monetization of the dispositions?

Unidentified Audience Member [35]

 Gas assets. Yes.

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [36]

 Yes. I think over time, you'll see us continue to sell those assets. Again, if we don't see something working up into the top of our inventory over time, then we would certainly look to sell that asset.

Unidentified Audience Member [37]

 David, just on your [duck] inventory, you guys had kind of alluded to potentially drawing down pretty aggressively in fourth quarter. I know prices have kind of been bouncing around lately. Latest thoughts on price, you would do that? Or you [doing] that in price?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [38]

 What price, is that the question?

Unidentified Audience Member [39]

 Yes, what price would you continue to blow down [all your reduction] fourth quarter? (Multiple speakers) --

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [40]

 Yes, I think on that side, I mean, we have, just from the efficiency gains we've had, we've been able to draw it down a little bit more. I mean, the reason in the past we haven't drawn it down in a more aggressive manner was we were trying to stay within cash flow. And at lower prices, we weren't -- we couldn't really be quite as aggressive on drawdown.

 So as we get better, as we are able to save a lot more dollars, then we've been able to draw it down aggressively. So we'll keep doing that. If we can continue to lower costs, then we can draw them down faster. But the main focus there is we want to live within cash flow.

 And so this time, I mean, we're kind of standing at that level and keeping our CapEx the same.

Unidentified Audience Member [41]

 Could you talk a little bit more about the North West Shelf, what it is that you -- maybe just talk a little bit about the geology and what it is you hope for in terms of cost reductions? Or what would make it economic, what would make it premium?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [42]

 Yes, so the North West Shelf -- like I mentioned, I mean, we haven't really worked that area. Historically, we've always been -- even when I was working this area, we were down in the basin. So we've never really -- we've never had a position up there, you know, for one thing. It's always been tightly held.

 And so really, the geology on the Shelf -- it seems to be dominated by carbonates, limestones and dolomites. And it's very shallow. So a lot of the drilling up there has been -- the competitors that have been drilling have been like 3,000 feet or something in that range.

 But some of the wells are pretty decent, as people have looked to apply some of the more modern completion technologies there. There's certainly been an improvement.

 So again, we haven't really worked this part of the world. And really, none of the 1,700 locations are in this area. But we do see it as an area where we would like to look to grow. And a lot of it's going to depend on the cost structure, being able to drill the wells and complete them cheap enough, and what kind of uplift would you get on the newer fracks.

Unidentified Audience Member [43]

 Could you offer any comments on your anticipation for service cost increases in 2017? I believe Schlumberger noted that you rejected recent small price increases they [reflect].

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [44]

 Yes. In 2017, obviously, it's going to be purely a function of oil prices. If oil prices are strong in 2017, then I do think there would be some pressure on service costs going forward as activity picks up.

 But again, like I noted, for us, we're still carrying a lot of the older service costs. A lot of the rigs we're running, they're still at the old day rate -- 26,000, 27,000 a day. I mean, they're very good rigs. And we're drilling really fast with them. But those same rigs, now, you can pick them up for 16,000, 17,000 a day.

 So as those contracts roll off throughout the year, then we'll actually see a lower day rate. And like I mentioned, even on some things like tubulars, I mean, we're still carrying a higher cost on some of that, just because a lot of that was bought back in 2013, 2014. So as we go through that, we'll get back to market-based rates on that side.

 So where you would see some increase potentially is on the completion side. And we are pretty much at market rate on all that now. So that could be -- there could be a little bit of pressure there. But overall, once you put it all together, we think we'll still see reductions in cost going forward.

Unidentified Audience Member [45]

 Yes, I wanted to ask you a little bit about the EOR projects. We haven't heard much about that lately. And I was just wondering if we should think about it as something really long term, or is it something that you might announce more as you move forward in the next quarters? Maybe if you could touch on where it works and where it doesn't work?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [46]

 Yes. So on the EOR -- we talked about it a couple quarters ago, and we kind of gave you an idea of where we were on individual pilots across the field. And the success on that has been great to date on really all of them.

 So going forward, what we're in the process of doing now is we're doing a larger pilot, 32-well pilot. And we're in the process of doing that. So once we get that done, and we get the data on that, then we'll certainly come out with an update.

 But we wouldn't be talking about it if we weren't excited about it. We think it has a lot of potential. We're trying to determine right now how broadly applicable it is within the Eagle Ford. And like I did mention, we've tried it on a pretty broad area across the Eagle Ford, and it's been successful. So we feel fairly good about that. But we just want to make sure we get all the data in on this 32-well pilot before we update it.

 And the reason why we started on the Eagle Ford is because we feel like it's the best from a geologic standpoint, because we want to -- for the EOR process to work, you need to make sure that the gas stays in contact with the reservoir and the zone. And the Eagle Ford, from all of our microseismic data collection over time, shows that really all of the completions do a very good job of staying in the zone.

 And so what we've seen with the EOR process is that the gas has done a very good job of staying in the zone, too. So it stays in contact with the reservoir. So that's a real key. If you're going to do this process, you have to make sure that you're able to stay in contact with the reservoir, and you don't leak off through faults or fractures.

Unidentified Audience Member [47]

 Can you talk just a bit about what your planned activity is in Reeves County go forward?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [48]

 Reeves County? Yes. So in Reeves County, we've got a pretty good position there in the northern part of Reeves County. And we've got 40,000-acre block in the northernmost part. And so we've got a lot of options on that block, and we drill really good wells. That's really part of what we call our combo play. So we kind of break the Delaware out into the oil play and the combo play.

 So as you come south, you get a little bit shallower and have a little bit less pressure and a little bit more gas. And so the wells there tend to be a little bit less cost. But like I said, they're more gas and a little bit less oil. But the economics are very good there on those.

 And so we do -- on that large acreage position, we do have the ability to drill long laterals. And the good thing is we can actually kind of drill them the way we want to, exactly on the orientation that we want to put them on.

 So it's been a good area for us, and we haven't been quite as active there as we have back up to the north, in more of the oily part of the play.

Unidentified Audience Member [49]

 Can you comment just a bit about any leading-edge improvements in the Bakken, particularly with regards to larger fracks? And I think you guys in the past year have done some 20 million-pound fracks there. Is that proving out to be -- to improve efficiencies in productivity?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [50]

 Yes. I think, of course, we've been the leader in the Bakken for a while in the completion technology. Really, going forward, we continue to enhance our completion from the Bakken. We haven't done as much lately on the Bakken. But we're seeing very good results on that. And it's not just about the amount of sand you pump, although we do pump a lot of sand there. It's a little bit more about how you place the sand and how you deal with the offset wells. And so we've gotten a lot better over the last year or two at being a lot more effective on that. We've announced within the last year some very big wells in the Bakken.

 So I think going forward, that's going to continue to be a key place for us.

Unidentified Audience Member [51]

 Maybe just bring us up to speed with where you are right now as far as spacing and stack staggered pilots or spacing in the Eagle Ford, and how you plan to drill wells going forward there?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [52]

 Yes. So we continue to stagger -- kind of do the stagger program between targets within the lower Eagle Ford. And we tested a pretty good range of spacing there. I mean, we've obviously done some at 300 feet. And we've done quite a few at quite a bit less than 300 feet. And so really, all the results there look good. And one key thing there is that as you -- one way to think about it is as you do the primary development of fields, you need to be thinking about the secondary development, the EOR process.

 And so what we're trying to dial in is exactly the right spacing and the right completions for the full development of the field. And what we've seen is that wells that are completed better, wells that are placed at the proper spacing, tend to yield better results on the EOR as well.

 But we're continuing to work that. It's kind of all the above. We're working the spacing and the targeting and completions, along with the EOR process.

Unidentified Audience Member [53]

 So the typical Eagle Ford program going forward is going to be done on 300-foot spacing? And --

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [54]

 It could be. It depends on where you are within the play. I mean, it could be less than 300 feet, depending on how many targets you have. I'm talking about from a map view standpoint. So you may be putting wells in different landing zones within lower Eagle Ford. And then, they will be, in some cases, tied up in 300 feet.

Unidentified Audience Member [55]

 David, it seems like most of the [EURs] you have given us haven't changed much since you've shifted to premium drilling. And you've given us the 90- or 120-day IPs, which are much higher than those [legacy type] curves. When will you have enough production history across the various plays to come out with the updated EURs?

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [56]

 Yes. We admit that a lot of the numbers are stale. So in the case of the Wolfcamp, we showed those examples, and the Second Bone Springs as well. Just the progression of that play has been so rapid. I mean, we just came out with the 750-nBoe on the Wolfcamp, I think, in the last year. And so we're already well ahead of that. And that's just a function of just the rapid progression of the completion technology and the targeting.

 So we hope to soon come out and be able to update some of that.

Unidentified Participant [57]

 There any other questions for EOG? If not, please join me in thanking David.

 David W. Trice, EOG Resources, Inc. - EVP, Exploration and Production [58]

 All right, thank you.