Good day, everyone, and welcome to the EOG Resources first quarter 2013 earnings results conference call. Just as a reminder, this call is being recorded. And at this time for opening remarks and introductions, I would like to turn the call over to Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, and thanks for joining us. We hope that everyone has seen the press release announcing first quarter 2013 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call. This conference call also contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to comparable measures can be found on our website at www.eogresources.com. The SEC permits oil and gas companies in their filings with the SEC to disclose not only proved reserves but also probable reserves as well as possible reserves. Some of the reserve estimates on this conference call and webcast, including those for the Delaware Basin and Eagle Ford, may include potential reserves or other estimated reserves not necessarily calculated in accordance with or contemplated by the SEC's latest reserve reporting guidelines. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. With me this morning are Bill Thomas, president; Gary Thomas, chief operating officer; Tim Driggers, vice president and CFO; and Maire Baldwin, vice president, investor relations. An updated IR Presentation was posted to our website yesterday evening, and we included second quarter and full-year 2013 guidance in yesterday's press release. This morning we’ll discuss topics in the following order. I’ll first discuss our 2013 first quarter net income and discretionary cash flow, then Bill Thomas and I will provide operational results. I’ll then discuss our 2014 to 2017 business plan and Tim Driggers will discuss financials and capital structure. Finally, I will cover our macro view, hedge position, and concluding remarks. As outlined in our press release, for the first…

Thanks, Mark. I will start with our good news from the Bakken/Three Forks. We have two important items to report for the first quarter. First, we continue to have excellent results from our 160-acre downspacing test in the Parshall Core area, and second, we tested the second bench in the Three Forks on our Antelope Extension acreage with outstanding results. Two recent 160-acre downspace wells in the Parshall Core area are the Van Hook 20-107H and 127-107H, which came on production for only 2,375 and 2,170 barrels of oil per day respectively. We have 55% working interest in these wells. Along with the new wells, our previously reported 160-acre wells continue to outperform our expectations, and the vast majority of the planned 53 completions in 2013 will be drilled on 160-acre spacing. As we continue to gain confidence in downspacing results over the course of 2013, we will likely increase the level of drilling activity in 2014. As I noted, we just completed our first well in the second bench of the Three Forks in the Antelope Extension area with outstanding results. The River View 3-3130H came online, producing 3,150 barrels of oil per day. We have 94% working interest in this well. We also completed another Three Forks well in the first bench, or our uppermost zone. The West Clark 101-2425H had initial production of 2,205 barrels of oil per day. We have 100% working interest in this well. The Three Forks and Bakken results on our Antelope Extension acreage continue to look strong, and we are particularly excited about the potential of the Three Forks second bench. Early looks indicate that this target may have better potential than the first bench and the Bakken phase in this area. We plan to test the third bench of the Three…

Thanks, Bill. I’ll briefly discuss our plays outside North America. In Trinidad, our first quarter production was as projected. We’re in the midst of a drilling program off our Osprey platform that will help to maintain flat over production in 2013 and 2014. In the East Irish Sea, the startup of our Conwy oil project has been delayed until early 2014. For this reason, we’re keeping our full year total company oil growth target at 28%, even though we significantly outperformed in the first quarter. We have, however, increased our U.S. oil growth estimate by 4% this year, due to our Eagle Ford strength. In addition to having captured sweet spot positions in crude oil resource plays, another EOG differentiator is our domestic crude oil realizations in margins. During the quarter and currently, our Eagle Ford crude is priced off an LOS index as is our Bakken and part of our Permian crew, which is being railed to our St. James terminal. The majority of our domestic crude volumes are linked to LOS rather than WTI prices. This access to premium markets resulted in a $12.23 per barrel premium over WTI during the first quarter for EOG’s U.S. crude oil volumes. We expect to achieve a $9.25 premium in the second quarter using the midpoint of yesterday’s guidance. Now I’ll discuss some longer term implications emanating from our asset base. On this call we’ve described our three main domestic oil assets in the Eagle Ford, Bakken, and Delaware Basin. We feel the addition of the Delaware Basin Leonard and Wolfcamp assets that we announced in February moves EOG past a key threshold and allows us to talk with confidence about what EOG will look like five years out. Today we have sufficient confidence in our asset base to provide directional…

Thanks, Mark. Capitalized interest for the quarter was $10 million. For the first quarter of 2013, total cash exploration and development expenditures were $1.6 million, excluding asset retirement obligations. In addition, expenditures for gathering systems, processing plants, and other property plant and equipment were $92 million. As compared to the first quarter of 2012, total cash expenditures decreased by $315 million. There were no acquisitions during the quarter. Through May 1, we have closed on asset sales of approximately $500 million. At the end of March 2013, total debt outstanding was $6.3 billion, and the debt to total capitalization ratio was 31%. At March 31, we had $1.1 billion of cash on hand, giving us non-GAAP net debt of $5.2 billion, or net debt to total cap ratio of 27%. The effective tax rate for the first quarter was 35%, and the deferred tax ratio was 75%. Yesterday, we included a guidance table with the earnings press release for the second quarter and for full year 2013. For the second quarter, the effective tax rate is estimated to be 30-40%. For the full year, the effective tax rate is estimated to be 35% to 45%. We’ve also provided an estimated range of the dollar amount of current taxes that we expect to record during the second quarter and for the full year. Now I’ll turn it back to Mark.

Thanks, Tim. Now I’ll provide our views regarding the macro environment, hedging, and crude by rail. Regarding oil, we believe full year WTI prices will average in the low 90s, similar to the past two years. However, as our total company cash flow becomes more dependent on oil, we have changed our oil hedging philosophy such that we plan to target an approximate 50% hedge position for the full year. For the second half of this year, we had 93,000 barrels of oil a day hedged at $98.44. Currently, we have 42,000 barrels of oil a day hedged for the first half of 2014 at $95.86. These numbers exclude options that are exercisable by our counterparties. Regarding North American gas, we recently added some May through October 2013 and some full year 2014 hedges. We don’t have a target hedge percentage, and have viewed the April gas price upsurge as a hedge opportunity. Our crude by rail continues to be a highly profitable venture and although the WTI-LOS differential has recently contracted from $20 to $11 a barrel, it’s still very advantageous for us to move oil by rail from the Bakken, Permian, and Barnett combo to St. James. Additionally, we have contracted capacity on a Houston Tahoma pipeline later in the year, and will have the flexibility to move our Eagle Ford oil east from Houston to refineries in Louisiana, which are priced off the LOS index. I’ll now briefly address our 2013 business plan, which is consistent with what we outlined on our February call. We still expect our total capex to be between $7.0 and $7.2 billion, and proceeds from dispositions to be approximately $550 million. Our full year production growth targets are unchanged at this time, and we slightly reduced our full year LOE and DD&A…

[Operator instructions.] We’ll take our first question from Leo Mariani with RBC.

Question on your second bench well in the Three Forks. It looked like a very strong well. I think you guys drilled out in the Antelope Extension area. Do you guys think that the second bench can be prevalent across a lot more of your acreages trying to get a sense of your geologic mapping and where you think that might exist on your acreage.

We certainly think it’s prospective across our Antelope Ridge area. We have enough logs and data there to kind of verify that. On the remainder of our acreage, like in the core area, it may be prospective. We’re taking additional looks at that as we speak. But it’s not as clear there as it is in Antelope. But you know, we’re really excited about the second bench, and we’re going to be testing another second bench well down the road, and then I think next year we’ve got plans for drilling down in a third bench. So we’re very excited about the Three Forks potential there at Antelope.

And then I guess in terms of gas production, you guys said you weren’t drilling any more dry gas wells this year, but you did say that you’d probably see gas production flat in North America to slightly up next year. Would you anticipate any dry gas drilling next year? Or is that going to be exclusively from associated gas?

The outlook through 2017 that we gave you we generally are assuming no dry gas drilling, or essentially no dry gas drilling, throughout 2017 in the outlook we provided.

And I guess you guys obviously didn’t quantify overall growth. Should we think of the EOG as firmly being in double digit growth of the company over the next four years?

We don’t want to give specific numbers, but I’d just say that some of the numbers that might have been penciled in previously for overall growth are probably too low, and I think we’ll have surprising overall growth during the next four or five years, really. The 4% growth that we’re projecting this year is not what you should expect in the 2014 to 2017 period.

Next we’ll hear from Doug Leggate with Bank of America Merrill Lynch.

My question is on your guidance. Obviously the costs have been pretty strong here relative to what you were expecting in the first quarter. But you’re guiding us higher again for the back end of the year on a whole number of levels. What’s different? Why should costs move back up again given the level of success that you’re having? And are you just being conservative? Or should we be thinking about Q1 as the more repeatable?

In terms of the budget expenditures? Capex?

More the unit costs. The LOE and the transportation and the exploration guidance and so on.

We’re a little bit surprised by how well we came in on our overall costs for the first quarter, so we’re a little bit conservative in the guidance that we’ve given for the remainder of this year, although we do think it will be a little bit back end loaded. So I’d say on the unit costs, there is a possibility we may beat the full year guidance on some of those, but we’re going to wait another quarter to see how repeatable this first quarter really is.

And that would apply to the other guidance actions as well? The impairment charges and the exploration charges, you’ve guided that back up as well. [unintelligible] a big ticket item. Is there any reason why that should be trending higher?

We’ll just be looking at it at the end of the second quarter. We just want to see what the trend is. But right now we just want to be fairly conservative. On the production side, though, we’re not signaling that we may beat on production on there, at that time, so we would guide you to the full year production of the 28% oil growth and not higher than that at this time. There may be some room on some of the costs, and we’ll reevaluate that at the end of the second quarter.

Next we’ll hear from Irene Haas with Wunderlich Securities.

Sounds like a lot of good news coming out of the Bakken. My question is what’s your feeling on the Bakken differential as it stands now, understanding that [unintelligible] has come down a little bit. Just want a little color from you.

It’s hard for us to guess on these differentials kind of where they’re going. I’d be hard press to really hazard a specific guess. We do believe that the differential, Gulf Coast to WTI, is likely to stay more compressed than it was in the first quarter. We don’t see that ballooning out. But where the Bakken is relative to the WTI or the Gulf Coast, I can’t give you any specific guidance on that that would be very specific, unfortunately.

And how about on natural gas? I know you guys put on some hedges, so your general view probably still has not changed?

I guess our view at this point is we don’t see any return to the high twos or low threes for gas in terms of 2013 or 2014, or 2015. We think we’re now in a timeframe, in 2013, 2014 and 2015, we’re somewhere in the range of likely $4-5 gas prices. So we have become slightly more bullish than in the past, but we certainly are not in hyper-bullish mode.

Next we’ll hear from Joe Magner with Macquarie.

Just curious how we should think about the guidance through 2017. I know you don’t want to get into specifics, but should we expect to see a rolling update on what you’re going to guide to on an annual basis? Or will there be more framework to it if you have more visibility on future commodity price?

We will probably continue just to give an annual update. It’s been our experience that companies that try and give a three- to five-year guidance, they almost immediately miss their guidance the first or second year, and so we’re not likely to do that. So it will be likely that in February we’ll give full year 2014 guidance and we might give a little more framework around the 2015 to 2017 guidance, but don’t look for us to provide firm numbers for more than one year out as we go forward.

And along those lines, how should we start to think about capex required to support that growth? To date you’ve been pretty disciplined with the balance sheet, but if you have continued confidence in the quality of your assets, will your treatment of the balance sheet change, or will this growth be supported by internally generated cash flow?

I’ll just say that we ran a case at a flat WTI oil price of $85 and we believe that over the aggregate period of 2014 to 2017, we will generate some significant free cash flow during that period at a flat $85 WTI oil price. So during that entire period, we’ll be guided by the same maximum debt limit of no higher than 30% net debt to total cap, and we think that we should be in a free cash mode during this period, certainly at current oil prices. If you just take flat oil prices, current levels, through 2017, we will be at significant free cash flow [unintelligible] based on our internal growth projections.

Next we’ll hear from Pearce Hammond of Simmons & Company. Pearce Hammond - Simmons & Company: In a prior forecast, you had put out some slides where you talked about total U.S. oil production growing by like 2 million barrels a day by 2015?

We still are of the belief that total U.S. oil production growth that happened in 2012 was perhaps the peak that is going to occur. That production growth was about 800,000 barrels of oil a day, and we expect that the total growth in 2013 to be less than that, and 2014 to be less than that. We’re already seeing a lesser rate of growth in the Bakken. The Eagle Ford, of course, is still steaming ahead at a quite high rate of growth. And so we believe that we’re not going to see stupendous overall U.S. growth rates as we go forward. We think there’s only really two major driving forces of U.S. oil growth: Bakken and Eagle Ford. Eagle Ford is going to surpass the Bakken likely this year as the biggest oil growth rate. Bakken is slowing down. Permian is really not on that fast of a track. And then there’s what I would classify as all others. And the all others are not growing at a very fast pace at all. So we’re not as concerned as others that U.S. oil growth is going to flood the total market and ruin global oil prices. Pearce Hammond - Simmons & Company : And then you my follow up, in the earnings release, related to the Eagle Ford, you stated that if crude oil prices remain at or above current levels, that you’ll further augment your drilling program in 2014. How many rigs do you think that augmentation might imply?

In terms of rigs, not all that many rigs. I mean, to give you an idea of rigs, in the first quarter of ’12, we ran up to 76 rigs. In the first quarter of ’13, we ran 52 rigs. Now, some of those rigs last year were drilling some gas wells. This year we weren’t drilling hardly any gas wells. But what we’re seeing is the rig count’s probably not going to go up that much, even if we ramp up the number of wells we plan to drill, because we continue to drill at a faster pace in days per well. So what I would say is, if the constant oil price continues to occur in 2014, we’ll probably ramp up activity in the Eagle Ford, the Bakken, and the Permian from the activity level that we expect to achieve in 2013. And we expect we can do that and still have significant free cash flow in 2014.

Next we’ll hear from Charles Meade with Johnson Rice.

Just a clarification. With respect to the increased activity in both the Bakken and the Eagle Ford in ’14 in current prices, does current prices mean $95? Or are we talking more the flat $85 that you referenced in your five-year plan?

The current prices I was just referring to would be the $94-95.

And then the second question I had, on those Karnes County well, I think the general impression has been that that has been maybe a tier below the fabulous acreage you have up there in Gonzalez County. But with the results that you turned in here, it seems like the rate of change of the results there, the second derivative of what you’re getting there, is better. And I’m curious, has your view evolved on the relative prospectivity of these two areas? And does Karnes have a chance to be as good as Gonzalez?

As an overview, I’d say Karnes is still not as good as Gonzalez. But on the rate of change, while we’re continuing to make better wells, given equal acreage, the rate of change is still quite positive in the Eagle Ford. In other words, if you take essentially any piece of our acreage, whether it’s in the west, the middle, or the east, are we making better wells today than we were a year ago, than we were two years ago or three years ago? The answer is unequivocally yes. So that’s why you’re seeing the fact that we continue to beat our production targets relating to the Eagle Ford. Because we project and say, okay, based on what we think the productivity is going to be, based on drilling X wells for the rest of this year, we project a number and give it to you as our 8-K estimate. And then what we find out is gee whiz, the productivity of those wells is better than projected based on typically our completion efficiency. So I can’t overestimate the quality of this Eagle Ford asset. And I think a lot of people, when we purposely restricted the money in the fourth quarter, to the Eagle Ford, and we had clearly signaled this to the investment community before we did it, we said we’re going to slow down activity in the fourth quarter to the Eagle Ford because of budget constraints, and then production slowed down. I think a lot of people misread the production slowdown in our fourth quarter and felt that the Eagle Ford rate of change had inflected downwards, and that was clearly not the case. It was just that the capital, the coin operated machine received less coins in the fourth quarter. So we upped the coinage in the first quarter and you see the results. So that’s why we’re so optimistic, not only of what we can do this year, but what we can do in the period 2014 through 2017.

Next we’ll hear from Arun Jayaram with Credit Suisse.

I wanted to elaborate a little bit more on that rate of change topic. I guess going to your slides on 21, saw a real noticeable improvement in the 30-day averages, and just wondering if you can put this in context given your shift towards tighter spacing patterns and the move out west. So I was just wondering if you could put that into context.

Yeah, that’s a new slide we put in there, and glad you caught that. It’s pretty impressive, really, as to what we’re seeing on these averages. And this is on our IR slides we posted on our website this morning. And you can see a steady increase, if anyone wants to go take a look at that. We’ve got a chart there that shows the 30-day production average and then on the right hand side of that chart, it shows the number of drilling days versus time, and you can see improvement in there. Generally, the 30-day average is a function of the completion efficacy of what we’re doing, and it also could be a function of the location of the wells. And so on the completion efficacy, I’d say that we do have a bit of a secret sauce in our fracks that we really aren’t going to talk much about, but we are doing some things differently than other operators down there. This has been a change that we’ve fully implemented, really in just the last six months. And we are seeing clearly differentiating results from that, and at this point we’ll just call it our own secret sauce.

And the follow up is if this continues, do you see some upward momentum perhaps to your EUR that you updated last quarter?

Yeah, but we won’t update that. I wouldn’t look at that EUR. First point is, at the current 400 MBOE net after royalty, and our current well costs, we are achieving greater than 100% after-tax direct reinvestment rates of return. So that, for a large hydrocarbon play, I would say is likely the absolute best rate of return anyone’s achieving, clearly, in North America, perhaps the world, except for the NOCs. And so it’s very adequate returns, certainly more than adequate. And we will look maybe annually at whether we could bump that reserve estimate, but that’s not something we’re going to adjust on a quarterly basis.

Next we’ll hear from Brian Singer with Goldman Sachs.

In the fourth quarter, you slowed activity in the Eagle Ford, to stay within your capex budget. But when we see how strongly you grew production during the first quarter, wanted to see if there are any operational benefits to an end of year slowdown and whether for financial or operational reasons, you’re expecting any slowdown in activity and completions this year.

Well, at this juncture, no, we’re not anticipating any year-end slowdown, as we would see it. There probably was kind of a catch your breath kind of advantage, particularly in the Eagle Ford last year, in the fourth quarter, and we were running so hard and so fast that there probably was a bit of an advantage to just slowing down for a period. But I would say at this point, it would be best to project that we would not slow down at this point. In terms of our capex burn rate, if you check the numbers, we consumed almost exactly 25% of our capex in the first quarter. So right now, our burn rate is pretty much, if we continue to burn at that rate, we’ll be exactly on our budget plan. So right now that’s pretty much our plan.

And much has been made so far here on the call about the end of the period of negative free cash flow and the forthcoming positive free cash flow. In your expectations for superior growth as well as free cash flow, assuming $85 a barrel, what’s your plan on what to do with that free cash flow? Would you have even more superior growth by reinvesting back in the ground to further accelerate activity? Would you more meaningfully reduce your debt or debt to tangible capital below the 30-35%? Or would you more actively return cash to shareholders? And how soon could we see some manifestation of that?

That’s a high-class problem to have. At this juncture, I would say that our priorities would likely be to establish some kind of meaningful dividend increase, whether it’s a percent per year or something linked perhaps to cash flow increases or something like that. The second thing would be we’d potentially might set some sort of floor as to what would be the minimum net debt to cap debt leverage that we think would be reasonable for an E&P company. And we wouldn’t just plan to pay our debt down below a certain minimum level. We’re not aiming to be a debt-free company or anything like that. And the third thing that would be likely, once we hit that minimum debt level, would be to look at ramping up the capex. We have so many projects, at these kind of reinvestment rates of return, ramping up the capex further might be the proper path. But that would be an evolutionary type decision. Obviously on a year-to-year basis, it would depend on the price of hydrocarbons. But the key takeaway, I think, that we want to convey to you at this point, is that during this forthcoming four-year period, that the company would be able to achieve, even at a flat $85 WTI oil price, twin goals: a very robust production growth, particularly oil growth, as well as significant free cash flow. And so that’s pretty important to note. I’m not sure there’s many companies at a flat $85 oil price that would be able to say they could achieve those dual objectives.

Next we’ll hear from David Tameron with Wells Fargo.

In the Bakken, can you just talk about the downspace wells, how much production historically you have, and what those wells are doing as you get up to 60 and 90 days? Do you have any color there?

We’ve got 15 or so wells that are in various phases of production that we’ve completed as downspace wells. And certainly as we talked about earlier, the original wells, which were more like 320-acre spaced wells, they certainly, with the improved frack techniques that we use, they’re certainly, on a per-foot of lateral basis, when you normalize that, they’re outperforming our older wells. And it’s still really early on the tighter spacing wells. They’re equivalent, really, of 160-acrew wells. And of course these are long laterals, and the per-acres per well is variable. But they’re tighter spacing. We don’t have a lot of production history on those. We put the first ones online early in the first quarter, and so we’ve only got maybe 90 days of production on those. And we’re really watching that carefully, because we certainly want, before we do a lot of accelerated drilling, we want to be careful and make sure that we’re adding [MPV], and we’re not overdrilling or sharing production between wells. So we’re watching that, and our plan is to drill the remainder of the wills this year. It’s about 53 wells we’re going to complete this year. Most of those will be the 160-acre type downspace wells. And so it’s really kind of a pilot program, and we’re going to watch the production throughout the year. And it usually takes like 6 to 9 months to kind of verify that you’re doing things correctly. So we’re kind of in the first part of that process, and so hopefully by the end of the year, we’ll know a whole lot more about that, and be able to give you more color on that. But certainly, we think the improved frack techniques certainly, at this point, we’re very positive about it. We’re contacting more rock, and we’re really enhancing the recovery factor of the Bakken on our core acres. So it’s going well right now.

And then as a follow up to that, if I start to think about the industry, obviously, whether you believe the land grab or not is over, it seems like it’s moving much more toward a manufacturing type phase as opposed to an exploration phase. And I wanted to see what you think about that concept, and what North America looks like three years down the road, just lower 48, however you want to run with that. I just wanted to throw that out there and see if you had any comments on that.

Certainly as far as the oil plays, as we talked about, and I think we’re not really expecting to get another Eagle Ford or Bakken resource play of that quality and that size all tied together. So we have a decent list of new greenfield plays we’re working on on the oil side. But the quality of rock for oil plays and shales is really limited. And then the thermal maturity of the oil, the window there, of the right maturity of the oil, is really critical too. So the sweet spots are really small, and so what I think you’re going to be seeing is, and I think you’re correct on this, you’re not going to be seeing people announcing billion barrel new oil play discoveries. But hopefully we’ll be able to announce some success in some plays that would be maybe in the 50-100 million barrels, or maybe even bigger than that, which is a significant value in North America. So we’re not going to lose our exploration edge. The industry as a whole, I think, is certainly at a point right now where they really have a lot of acreage [leased], and people are testing a lot of ideas and plays. I think as we’ve talked about all along, you’re seeing the cream of the crop of the plays rise to the top, which are certainly the Bakken and the Eagle Ford. And we feel very fortunate that we have very large, substantial positions in those, and we hope to add a few more smaller ones as we go along.

I’ll just add one thing to that. There are some combo plays that we hope to uncover that could be substantially larger in terms of oil content, that I think are yet to be found, and we’re still chasing those. So there are still some substantial plays, I think, that will be uncovered, that may be similar to what we’re talking about out there in the Delaware Basin.

Next question will come from Joe Allman with JPMorgan.

In the core of the Bakken, what kind of Three Forks drilling have you done so far? And is it possible that the Three Forks two or three could be prospective without the Three Forks one being prospective?

In the core, I believe we’ve only completed like maybe three or four wells in the Three Forks there, and those I believe are the first bench. And so I think what we’re noticing, industry wide, that there’s a bit more success on the Three Forks than what maybe we had anticipated a few years ago. And so we’re really taking a second look at all that. And we’ll just have to see how that goes as we move on down the road. I’m sure that we’ll be analyzing that and thinking about maybe drilling, on Three Forks, our core acreage as we go forward.

And then in the Midland Basin, in the Wolfcamp, you indicated that it’s more technically challenging than the Delaware Basin. Could you talk about in what way it’s more technically challenging, and what would you expect to be the outcome after you do your analysis? And are your wells overall there in line with your 430,000 BOE type curve, or EUR estimate?

The answer to the first question is yeah, we haven’t changed our EUR per well. It’s still a growth, 430 MBOE per well. The challenge there is just kind of twofold. Number one is the rock quality in the Midland Basin is not quite as strong as what we see in the Wolfcamp and the Leonard plays in the Delaware Basin. And then the second thing is that frack containment is more of an issue in the Midland Basin. As you know, they have, at least in the areas we’re working, we have three potential [pay zones], and so you drill a lateral in one of the pay zones and you frack a well, and it has a tendency to grow up into the other pay zone. And then also, laterally, horizontally, away from the well bores, we’re seeing that you have the interference between wells there if you’re not careful. But I would say this, we’re optimistic that we’ll be able to solve those issues, and to be able to contain the frack better vertically and horizontally. And that’s what it’s going to take to add the multiple pays to the play, multiple pay targets, and also to decrease the spacing size. So we’re working diligently on that, but it’s certainly more challenging than the plays in the Delaware Basin.

And that is all the time that we do have for questions today. Mr. Papa, I’ll turn things over to you for any additional or closing remarks.