Nov 6, 2009
Executives
Mark Papa - Chairman & Chief Executive Officer Tim Driggers - Vice President & Chief Financial Officer Gary Thomas - Senior Executive Vice President, Operations Loren Leiker - Senior Executive Vice President, Exploration
Analysts
David Tameron - Wells Fargo Michael Jacobs - Tudor, Pickering, Holt Leo Mariani - RBC Brian Singer - Goldman Sachs Joe Allman - JP Morgan Scott Wilmoth - Simmons & Company Monroe Helm - Cimarron Capital Irene Haas - Canaccord Adams Shannon Nome - Deutsche Bank
Operator
.
Mark Papa
’
’
The SEC currently permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates on this conference call and webcast, including those for the Barnett Shale, North Dakota Bakken, Horn River and Haynesville may include other categories of reserves.
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 Web site.
An updated investor relations presentation and statistics were posted to our Web site this morning. With me this morning are Loren Leiker Senior EVP Exploration, Gary Thomas, Senior EVP Operations, Bob Garrison, EVP Exploration, Tim Driggers, Vice President and CFO, and Maire Baldwin, Vice President of Investor Relations.
’
’
’
’
’
’
’
’
’
’
Majority of our 2010 gas growth will come from the Haynesville Play. Our 50% total company year-over-year expected 2010 liquids growth will primarily emanate from the Barnett Combo, the Bakken and Waskada horizontal plays with some contributions from other plays.
All other liquids growth will occur in North America and the majority will be from the US.
’
Majority of our 2010 gas growth will come from the Haynesville Play. Our 50% total company year-over-year expected 2010 liquids growth will primarily emanate from the Barnett Combo, the Bakken and Waskada horizontal plays with some contributions from other plays.
All other liquids growth will occur in North America and the majority will be from the US.
’
Majority of our 2010 gas growth will come from the Haynesville Play. Our 50% total company year-over-year expected 2010 liquids growth will primarily emanate from the Barnett Combo, the Bakken and Waskada horizontal plays with some contributions from other plays.
All other liquids growth will occur in North America and the majority will be from the US.
’
Recently I have received some analyst questions regarding how this “shale” oil is actually recovered. The answer is we simply perforate and frac the oil wells in a manner similar to the shale gas plays.
’
Recently I have received some analyst questions regarding how this “shale” oil is actually recovered. The answer is we simply perforate and frac the oil wells in a manner similar to the shale gas plays.
’
Recently I have received some analyst questions regarding how this “shale” oil is actually recovered. The answer is we simply perforate and frac the oil wells in a manner similar to the shale gas plays.
’
During the third quarter we closed on another acquisition in the Combo Core area whereby we acquired 7800 net acres and 350 barrels of equivalent oil per day of net production for $63 million. Following the acquisition reported last quarter this provides us near total dominance in the 90,000 acre Combo Core area of Eastern Montague and Western Cooke Counties.
’
’
’
’
’
The Dontress [ph] B1H and C1H, and IP rates of 380 barrels of oil per day with 250 Mcf per day of gas and 360 barrels of oil per day with 225 Mcf gas respectively. Our average horizontal per well reserves have increased with experience similar to our gas results in Johnson County.
’
’
’
’
’
’
In the mid-continent EOG continues to achieve solid results in horizontal Cleveland oil play in the Texas, Panhandle. The two most recent wells are the Cooper 436-3H which began producing at a rate of 515 barrels of oil per day, plus 2 million of residue gas and 185 barrels of NGLs, and Cooper 436-4H which went on production at a rate of 540 barrels of oil per day plus 3.3 million cubic feet of gas and 310 barrels of NGLs.
We have a 100% working interest in both wells. We expect to drill 30 wells in this play over the remainder of 2009 and in 2010.
Our Manitoba Waskada horizontal oil project is performing better than expected and we expect to average 6000 barrels of oil per day net from this project in 2010 at a 100% after tax reinvestment rate of return.
’
’
Remainder of the acreage is primarily in Nacogdoches and San Augustine Counties in East Texas. And our recent well results confirm a second core area in Nacogdoches County.
Our Gammage #1 exploration well which we had not addressed publicly kicked off a lot of analyst speculation about this area. Actually the Gammage turned out to be a decent well as the short lateral, but we follow that up with several outstanding wells that rivaled the best sound in Louisiana core area.
’
Remainder of the acreage is primarily in Nacogdoches and San Augustine Counties in East Texas. And our recent well results confirm a second core area in Nacogdoches County.
Our Gammage #1 exploration well which we had not addressed publicly kicked off a lot of analyst speculation about this area. Actually the Gammage turned out to be a decent well as the short lateral, but we follow that up with several outstanding wells that rivaled the best sound in Louisiana core area.
’
’
’
We plan to run 10 Haynesville rigs in 2010 and increase our Haynesville net gas production from the current 40 million cubic feet a day to 200 million cubic feet a day by year-end 2010. The Haynesville will be the primary driver of our 2010 North American gas production increase.
’
We plan to run 10 Haynesville rigs in 2010 and increase our Haynesville net gas production from the current 40 million cubic feet a day to 200 million cubic feet a day by year-end 2010. The Haynesville will be the primary driver of our 2010 North American gas production increase.
’
We plan to run 10 Haynesville rigs in 2010 and increase our Haynesville net gas production from the current 40 million cubic feet a day to 200 million cubic feet a day by year-end 2010. The Haynesville will be the primary driver of our 2010 North American gas production increase.
’
In the Horn River Basin we completed seven wells this summer in the program focusing on improving operational performance and completion techniques along with determining optimum spacing patterns.
’
In the Horn River Basin we completed seven wells this summer in the program focusing on improving operational performance and completion techniques along with determining optimum spacing patterns.
’
We produced these wells throughout the winter to evaluate the efficacy of each pattern. We believe the three high rate wells are among the best in the play topping out 16 million cubic feet a day well completed last year.
’
’
’
’
’
’
We also achieved 100% rate of returns drilling three oil sand directional wells under Nueces Bay near Corpus Christi, Texas. Two recent wells are the State Tract 788 Gas Unit #1 and 692 #1.
Each of these will produce about 20 Bcf of gas with 1 million barrels of liquids per well. Regarding our activities outside North America, we will be fracture-treating our first horizontal gas well in China this quarter, but it will be mid 2010 before we can declare whether this project is successful or not.
We will be drilling several East Irish Sea and North Sea oil prospects during the first quarter as a follow up to our success reported last quarter. I will now turn it over to Tim Driggers to discuss financials and capital structure.
Tim Driggers
Thanks Mark. For the third quarter exploration and development expenditures were $969 million, excluding asset retirement cost.
In addition, expenditures for gathering systems, processing plans and other property plant and equipment were $89 million. Acquisitions during the quarter were $199 million.
Year-to-date through September 30, exploration and development expenditures were $2.5 billion excluding asset retirement costs. In addition expenditures for gathering systems, processing plants and other property plant and equipment were $241 million.
Through September acquisitions were $206 million. Capitalized interest for the quarter was $13 million.
At September 30, total debt outstanding was $2.8 billion and the debt to total cap ratio was 23%. At September 30, we had $609 million of cash giving us non-GAAP net debt of $2.2 billion or net debt to total cap ratio of 19%.
The effective tax rate for the third quarter was 8%.
’
’
Mark Papa
Thanks Tim. Our review of the North American gas and oil markets is directionally consistent with our previous earnings call, we still expect North American gas prices to remain low through the end of this year, start out 2010 weak and end 2010 strong due to supply declines that will occur throughout 2010.
Quantifying the magnitude of the domestic supply decline is becoming more opaque. You may have noticed that the EIA recently revised downward their estimates of 2008 gross production by about half a Bcf a day but did not adjust our 2009 data.
Given these revisions, our supply model can match the EIA 2008 volumes but not the 2009 numbers.
’
Storage injection since mid June have been running about 2 Bcf a day less than last year and 0.5 Bcf a day less than five year average. Our financial gas hedge position is shown in our 8-K is unchanged from last quarter.
We have 44% of our fourth quarter 2009 North American natural gas hedge at $9.43 and then we are likely hedged for the first half of 2010.
’
’
’
Let me summarize, in my opinion there are six important points to take away for this call. First, the impact of our horizontal oil play is just gaining momentum.
Our year-over-year total company organic liquids growth for 2008-2009 and projected 2010 is 42%, 27% and 50% and we expect further growth in 2011 and later years. Using a 10 to 1 equivalency basis to account for economic evaluation, our 2010 North American liquids to gas ratio will be 44%, up from 36% in 2009.
We previously estimated that EOG would organically evolve to a 50-50 mix by 2013. We now project that will occur in the 2011-2012 timeframe.
’
Our horizontal oil inventory is a key differentiator and will likely allow EOG to outperform peer companies in ROCE for the next decade similar to our out performance during the past decade.
’
’
’
’
’
’
David Tameron - Wells Fargo
A couple of questions, can I get a 2010 CapEx number to those that 13% growth? Can you give us the range or what you are thinking, you said you see the growth number out there?
Mark Papa
’
David Tameron - Wells Fargo
’
Mark Papa
’
’
’
’
’
’
’
’
’
’
’
’
David Tameron - Wells Fargo
’
Mark Papa
’
’
Operator
Your next question comes from Michael Jacobs - Tudor, Pickering, Holt.
Michael Jacobs - Tudor, Pickering, Holt
’
Mark Papa
’
’
’
’
’
’
Michael Jacobs - Tudor, Pickering, Holt
Okay. Recognizing that some places are earlier than others, how would you rank Bakken Core by Barnett Combo horizontal Cleveland oil and what you have heard others are doing in the Eagleford in terms of rates of return kind of your favorite areas from a rate of returns standpoint?
Mark Papa
’
’
’
’
’
’
’
’
’
Michael Jacobs - Tudor, Pickering, Holt
That makes sense. One point of clarification if I can move to East Texas the 10 Bcf per well is that for the middle and the lower Bossier or is that just for the lower Bossier.
Mark Papa
’
’
Michael Jacobs - Tudor, Pickering, Holt
’
Mark Papa
Yes, you cut out a little bit testing the concept where?
Michael Jacobs - Tudor, Pickering, Holt
Kind of when you think about Montana, Bakken or Three Forks whatever it is?
Mark Papa
’
Loren Leiker
Yes, really not sure Michael we are asking about the Bakken is whole as we dividing the Core area which is in North Dakota. In a Lite area which is primarily North Dakota as well although it is sloppier and handle little bit.
Our 500,000 acres includes large portions of core area I think we talked about at 90,000 to 100,000 acres in the core area.
’
’
Operator
Your next question comes from Leo Mariani - RBC.
Leo Mariani - RBC
A question on the Horn River, just trying to get a sense of when you guys expect it to ramp up production and you talked about adding 12 wells. I think previously you talked about kind of a 2011, 2012 ramp, just curious have anything is changed obviously there has been lot of industry activity over there and just wanted to get a sense of what you think the timing could be on Kitimat project?
Mark Papa
’
’
’
’
’
’
Leo Mariani - RBC
Okay thanks. Jumping over to your Horizontal Cleveland oil play sounds like it get some pretty good results there.
Trying to get a sense of what do you guys think that running rim is there in terms of your acreage and well of an inventory?
Mark Papa
’
’
Leo Mariani - RBC
’
Mark Papa
’
Again, as mentioned on previous earnings calls we own this play you will get zero information from other peer companies, leading to results for this play because they have zero position in the play. So its one or you may have some trouble triangulating on but if you have some questions about that play just look at our 50% year-over-year liquids growth were anticipating for 2010.
’
Again, as mentioned on previous earnings calls we own this play you will get zero information from other peer companies, leading to results for this play because they have zero position in the play. So its one or you may have some trouble triangulating on but if you have some questions about that play just look at our 50% year-over-year liquids growth were anticipating for 2010.
’
Again, as mentioned on previous earnings calls we own this play you will get zero information from other peer companies, leading to results for this play because they have zero position in the play. So its one or you may have some trouble triangulating on but if you have some questions about that play just look at our 50% year-over-year liquids growth were anticipating for 2010.
Leo Mariani - RBC
’
Mark Papa
Yes, small amount. It was 350 barrels of oil related equivalent.
There was a modest amount of proved reserves we acquired from that.
Leo Mariani - RBC
’
Mark Papa
’
-
’
’
’
Operator
Your next question comes from Brian Singer - Goldman Sachs.
Brian Singer - Goldman Sachs
Can you add a little more color on you Barnett oil play in terms of the percent of your acreage that is in the vertical of the thicker section where you are using more vertical wells versus the less thick horizontal section?
Gary Thomas
’
’
’
Brian Singer - Goldman Sachs
’
’
Mark Papa
’
’
Operator
Your next question comes from Joe Allman - JP Morgan.
Joe Allman - JP Morgan
’
’
Mark Papa
’
,
’
’
Joe Allman - JP Morgan
Then still in the Bakken, what are the cost per well for the Bakken Lite section?
Mark Papa
That’s $4.4 million and you get about 300,000 barrels of oil for a Bakken Lite well.
Joe Allman - JP Morgan
Then moving on to the Haynesville of your 150,000 net acres how much is in East Texas and how much in the Louisiana?
Gary Thomas
60% to 40%. Probably 60% Texas and 40% Louisiana.
Joe Allman - JP Morgan
’
Mark Papa
Very half percentages in the core.
Joe Allman - JP Morgan
Okay that’s helpful. And then, earlier you talked about your unreserves and PUDs, because of the gas price the way the new calculation works, would you expect any write-downs yourself or impairments yourself.
And how do you think you going to handle the PUDs and probably this year?
Mark Papa
’
Because I expect with the variance it’s the forwarded companies on PUD booking that those that select the book liberally can have or show up with extremely low finding cost and those that book more conservatively for PUDs could have higher finding costs and as far as trying to evaluate across companies in my opinion it’s just going to be invalid from this point forward.
’
Because I expect with the variance it’s the forwarded companies on PUD booking that those that select the book liberally can have or show up with extremely low finding cost and those that book more conservatively for PUDs could have higher finding costs and as far as trying to evaluate across companies in my opinion it’s just going to be invalid from this point forward.
’
Because I expect with the variance it’s the forwarded companies on PUD booking that those that select the book liberally can have or show up with extremely low finding cost and those that book more conservatively for PUDs could have higher finding costs and as far as trying to evaluate across companies in my opinion it’s just going to be invalid from this point forward.
Joe Allman – JP Morgan
Then just lastly I think it’s probably for Tim, I know it’s the capitalized interest was higher than it typically is this quarter, the third quarter, could you describe that first please?
Tim Driggers
Well, the capitalized interest is just a factor of our unproved property over our debt, so our unproved property continues to increase the capitalized interest will continue to increase.
Operator
Your next question comes from Scott Wilmoth - Simmons and Company.
Scott Wilmoth - Simmons & Company
Just following up on the Bakken light acreage, what percentage have you already delineated, could you put some numbers on that?
Mark Papa
In the light, it’s a small percent of that 400,000 acres where we really tested. We’ve tested primarily it’s kind of north of our core area.
In our presentation we put out this morning is little math that kind of shows some of our acreage and we’ve been testing primarily to the north of that we have a significant amount of acreage count to the west of our core area and that’s where we will be evaluating next.
Scott Wilmoth - Simmons & Company
Okay. And then on the $4.4 million well cost, can you talk about what lateral or frac stages you guys are using for that?
Gary Thomas
We’re drilling generally 5000 foot laterals on most of our horizontal wells. And generally, we’ve been increasing the number of stages, so right now we’re somewhere around the 15 stages on those Bakken Lite wells and plan to rise it to 17.
Mark Papa
Yes, it’s fair to interject the statement here, you know there are some companies that have very initial production rates has been reported and one thing there is kind of technical question is kind of unanswered across the industry there some companies are drilling liquid of 1280 laterals were they’re basically trying to drilling two sections, two 640 acre sections with one well. So they are drilling very long laterals and the cost for those wells would be considerably more than the $4.4 million recorded.
Once you would expect to get higher production rates, we’re kind of in a count at this point were we are talking about basically 640 kind of wells we want to drilling them 640 acres or less with the laterals so our laterals are shorter. So just comparing IPs across companies, you almost have to tie in what’s the well cost for one versus another and what the optimum depletion mechanism is there as far as 640 or 1280 laterals, it’s probably just an open technical question the industry and EOG will solve over the next year or two.
Scott Wilmoth - Simmons & Company
Okay and then keeping on the spacing. What are the well spacing you guys are currently using in the horizontal Combo wells?
Mark Papa
We are still experimenting on that, we’ve quoted in our previous remarks. That on the vertical wells we’re basically looking at 20 acre or possibly more than spacing and we are drilling someone 20 acres spacing right now and some one are more dense pattern.
In terms of the combo wells of sales on horizontal side we’re still trying to sort out what is the proper spacing, but you will recall that a fair amount of jobs in kind of which is gas ended up commonly 40, 50 acres spacing in there. We don’t know yet on oil, but we’ll know that the next up to distant future.
Scott Wilmoth - Simmons & Company
Okay. And then lastly can you just give us an update on Marcellus activity in plans for 2010?
Mark Papa
I have just say modest activities plans for 2010, we really up until a couple of weeks ago we had zero sales from the Marcellus, simply because of just delays on pipeline connects and just over the last few weeks we’ve got our first wells actually flowing to sales. So as we related multiple times we think this is an infrastructure challenged area and we’re going to go fairly slow pace relative to our acreage position, we’re just in two rig programs next years, two rigs will get us probably about 45 wells next year.
Scott Wilmoth - Simmons & Company
Can you give us any color on roughly the time it took to get those first wells on production?
Mark Papa
Yes, at least a year. So, I really think that in the macro view from North American gas, it’s going to be 2013 or so before the Marcellus plays any significant roles.
Operator
Your next question comes from Monroe Helm - Cimarron Capital.
Monroe Helm - Cimarron Capital
You made the comment early on that of course on drilling gain change your, horizontal oil drilling anyway seems to me like horizontal gas drilling has been a better game change than people thought. And I’m just wondering if in your models you kind of continue to push out to the right when we’re going to get gas supply and demand at a balance, I’m just wondering if this the game changing horizontal gas drilling isn’t making most of these models that people are looking at incorrect as far as forecasting supply and demand coming under belt?
Mark Papa
Yes, that’s a dollar question Monroe, and we’ll admit that we’re a bit puzzled by the recent EIA data particularly the obvious data that just came out few days ago. And we kind of what’s the proper thing to say on the earnings call regarding our macro view, but I really come down to the point that drilling has slowed dramatically and we believe that production will flow and if you look at the Canadian production situation, the Canadian production kind of levitated for six months maybe nine months longer at relatively stable levels before it started to fall.
There was a longer lag time between when the drilling really slowed down and when the production slowdown and that may will be just due to un connect the wells and what we believe is that’s probably the situation here in domestic gas right now, it was a backlog of unconnected wells and that we’ve probably work the way through that. I know that EOG was pretty well worked away through that.
But I would have to comment that we have a degree of range of possibilities just what’s going to happen on gas supply and we don’t see that our number is likely to be 100% accurate at this time.
Monroe Helm - Cimarron Capital
You all have this, about the only company I have heard of it has a luxury of diverting a significant part of their CapEx next year into oil drilling, most companies are announcing if they are planning on increasing their CapEx to gas next year, partly because they have place else to put the cap, the cash flow. And a lot of it’s going into these higher productivity on conventional horizontal wells and, I don’t know you want a name.
Can you talk about what, those companies have a difference of the economics and you do and if you are in one those companies and you’re looking at something like the Haynesville and that was all you can focus that and that was your best position. What kind of gas price would you need to meet your minimum rate to returns on something like the Haynesville?
Mark Papa
I would look at the Haynesville in terms of gas price or reinvestment rate of return the Haynesville is about equivalent to a Barnett, which is roughly equipment that we believe will ultimately come into Marcellus. So we don’t buy the notion that the Haynesville is clearly head and shoulder is about gas play that’s an economics, but certainly hedge to build economics or what gas price need if you really look at and it oil and cost including the land cost, seismic cost and everything else.
We still continue to believe unique up and like about $6 gas price for these things to work. That’s the input we give you Monroe.
Operator
Your next question comes from Irene Haas - Canaccord Adams.
Irene Haas - Canaccord Adams
You guys undisputed leader in low permeability oil play. I would like to ask two simple questions.
Firstly is, there isn’t always kind of up tick of these shale gas play which you expect to find possible shale oil plays, should I expect Haynesville, Combo play from you guys. Secondarily, can it be replicated outside the US in Canada and elsewhere?
Mark Papa
Yes, Irene I think the idea that the emptied and buried to all the gas play should hold an oil play, conceptually correct and it just last mature if rocks should be in oil window not the gas window, but the timing is really more torturously right in that. In Haynesville, I won’t comment specifically, the Haynesville Marcellus certainly these are the shale plays do not have a oil window, in other words the shale does not exist physically and they have setting any oil window.
Other plays probably do have an oil window. And we’re currently prospecting heavily and a number of those are the plays right now.
Internationally its harder to say, I mean we’ve looked at lot of different kinds of international projects in various parts of the world and the cost structure is always one element that makes it more difficult to see how those can work unless you find something head and shoulders above the typical kind of rocks that we’re seeing in North America, the cost structure is going to be a bit prohibitive we think.
Operator
Your last question comes from Shannon Nome - Deutsche Bank.
Shannon Nome - Deutsche Bank
A following up from Monroe’s question, the comment you made Mark on the macro picture with the industries well completions backlog which you seem to think is largely cured, lot of my other companies say the same, but when you ask each individual company how many wells they have waiting on completion, it actually adds up to pretty significant number. You have to think over the last few months as gas prices have towed around with $4 levels, is there have been companies continuing to drill on deferred.
Do you have any more precise thoughts on that, can you speak to what the achieved backlog is for example on the Barnett Shale of uncompleted wells?
Mark Papa
Your question is that is big conundrum and the other ancillary part of that is if you add up all the public companies as to what their legend are going to grow gas volumes in the US next year. It’s bigger number than its consistent with the production declines and we would project.
So we don’t have a lot of specific is to what other companies have in terms of backlogs, we know our backlog is really a relatively modest in terms of wells uncompleted. I believe it’s probably be about three or four months from now when to get EIA there and it’s not got a lot of noise in it, but we believe it is just inevitable that production is going to decline in 2010 and the magnitude of that is I believe it really be in the range of about 4Bcf a day for the full year, but we have to say that we have some questions as to we can’t pound a table and say it’s going to be exactly for because a lot of opaqueness out there right now.
Shannon Nome - Deutsche Bank
Okay. And then back to EOG, more importantly I hear you on your no habla Eagleford comment But $1.3 billion is a lot of money to spend even over several years, can you give us any feel for general geography regions of some of this inventory that you’ve been it’s mostly Rockies one would think given just where that oil is in the US or just more widespread?
Mark Papa
What we can say, we think is fairly geographically spread across North America, the only play we were pursue oil play horizontally we’re pursuing outside North America is in China. We have a zone that we will be testing year in 2010.
So it’s all in North America, but I have a really don’t want to go within in more specific.
Shannon Nome - Deutsche Bank
And my sense is on unconventional oil stuff, unlike maybe a Hayneville or Barnett kind of discovery that we are talking about maybe I don’t know you the numbers doesn’t but a collection of smaller areas that collectively add up to a lot. Is that a fair assessment of how unconventional oil plays are going to be unfold or are our talking about just a few larger discoveries that you’ll be taking the ramp up of over the next few years?
Mark Papa
If you just look at the basement deposition models, the oil plays in the shale are in the positive similar to the gas plays and I think that we’ve all been surprised by the huge magnitude of these North American horizontal gas plays. So we believe potentially some of these oil plays are going to have a very meaningful size.
Shannon Nome - Deutsche Bank
And then in terms some of the petro physical properties of these new place in our – are in very early testing stages a bit. You experienced so far to just that you said earlier that the combos one of the more prolific wells that resources you encountered would be fair to say that the rest of what your testing is probably not going to be quite impressive in terms of oil and place recovery factor or do you think that’s good chance that some will be competitive?
Mark Papa
The answer is we’ve just don’t know at this point, but let me there all be characterized by a relatively low recoveries of oil and plays. The Bakken we’re talking about 10% the combos are going to be less in 10% at least with current technology.
So one characteristic is generally going to be all the plays that for 640 acres that pretty significant amount of oil and gas in fact but the percentage of that we recover will be economic, but it would be fairly low percentage of what’s actually in place.
Shannon Nome - Deutsche Bank
Exactly, and you just spoken to 2% equity factors in the combo previously, it sounds like 280 Mboe per well number that doesn’t towards three is that correct?
Mark Papa
We now believe it’s going to be higher 2%, we don’t want to get into that, we just have to get some more data before we can open what exactly we think it will be Shannon. I think that would conclude the questions.
I want to thank everyone for staying with us way over time a little bit there, but we believe 2010 is going to be a very exciting year for EOG. Thank you.
Operator
This does conclude today’s conference call. Thank you for your participation.