Good day, ladies and gentlemen, and welcome to today's EOG Resources 2010 Third Quarter Earnings Call. And at this time, I would like to introduce Mr. Mark Papa. Please go ahead, sir.
Good morning and thanks for joining us. We hope everyone has seen the press release announcing the Q3 of 2010 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 contains certain non GAAP financial measures.
The reconciliation schedules for these non GAAP measures to comparable GAAP measures can be found on our website at www.eogresources.com. Effective January 1, 2010, the SEC now 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 disclosures on this conference call and webcast, including those for the South Texas Eagle Ford Barnett Combo and New Mexico Leonard plays, may include potential reserves or estimated reserves not necessarily calculated in accordance with 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 Lauren Leiker, Senior EVP Exploration Gary Thomas, Senior EVP Operations Tim Driggers, Vice President and CFO and Marva Baldwin, Vice President of Investor Relations. An updated Investor Relations presentation was posted to our website last night and we included 2010 and revised preliminary volume estimates for 20112012. We've reduced our full year 2010 growth guidance from 13% to 9%. About 70% of this reduction relates to North American natural gas volumes, where we're now projecting -2% growth versus the previous estimate of plus 2%.
Obviously, in this price environment, we're not incented to grow gas volumes. Our conversion from a natural gas to an oil company is still on track and we expect total crude, condensate and natural gas liquids to comprise approximately 67% of our 2011 North American revenues. However, because of lower cash flows from weak gas prices, higher frac costs, delays in frac equipment availability and the pattern drilling used to maximize resource plays, we've also reduced our 2011 2012 liquids growth targets to better reflect real world conditions. Even with these reductions, we expect to grow crude and condensate 36%, 53% and 30% in 2010, 2011 and 2012. We've also made progress regarding asset sales and I'll report on that later in the call.
I'll now review our Q3 net income and discretionary cash flow, then I'll provide some operational highlights and discuss our capital structure. Jim Driggers will provide some financial details and I'll close with comments regarding our macro hydrocarbon view and concluding remarks. As outlined in our press release for the Q3, EOG reported a net loss of $70,900,000 or $0.28 per share. For investors who follow the practice of industry analysts who focus on non GAAP net income to eliminate mark to market impacts and certain one time adjustments as outlined in the press release, EOG's 3rd quarter adjusted net income was $46,600,000 or $0.18 per share. For investors who follow the practice of industry analysts who focus on non GAAP discretionary cash flow, EOG's DCF for the 3rd quarter was $755,400,000 I'll now address operational results and I'll start with the South Texas Eagle Ford.
The bottom line here is that our confidence in individual well results and the total 900,000,000 barrels of oil equivalent net after royalty reserve estimate have increased since our April analyst conference. Because this is such a huge net oil accumulation and I believe investors have undervalued this asset, I'm going to take several minutes and provide an update based on our results from the last 6 months. Our press release provided details from a number of good wells, most of which have only commenced sales in the last month. Here's what we know right now about our asset after drilling 77 wells, 59 of which are either producing or shut in for offset fracs or waiting on frac. First, the Eagle Ford formation is not a typical shale, but instead it's a borderline conventional carbonate reservoir.
Pressure and flow data from our wells indicate we're seeing a lot of matrix flow, I. E, a significant amount of flow from the rock fabric itself, which is a produce sign. 2nd, the Eagle Ford is a predictable play. We've now drilled a large enough 120 mile extent of our acreage block. 3rd, we've had a 100% well success rate within the acreage and the horizons we originally defined to contain our estimated 9,000,000,000 barrels of estimated reserves, the mix is 77% black oil.
The oil on our portion of the reservoir has some unique characteristics that enhance the recovery factor. We've kept this information proprietary until now, but with our acreage tied up, we can now talk without losing a competitive advantage. Will apologize in advance for getting too technical. This is a very important point because some analysts have expressed concern regarding recovery factors from a pure oil reservoir. Specifically, there is an extraordinarily high differential between the initial reservoir pressure and the pressure at which solution gas breaks out of the oil, technically called the bubble point pressure.
Across our acreage, the original reservoir pressure averages 7,200 PSI and the bubble point pressure averages 2,500 PSI. This unusually high spread provides for a larger than normal fluid expansion recovery factor. That's why we're so confident with our 0 point 0 2 targets, the Upper and Lower Eagle Ford. These zones are relatively thick and high quality. A typical well here is the Harper 10H well, which IP ed at 10.70 barrels of oil per day and 9.80 Mcf per day.
In this same area, the CUSAT Clampett wells, which were highlighted in the press release, IP'd at rates ranging from 860 to 1800 barrels of oil per day with 1,000,000 to 1,800,000 cubic feet a day of rich gas each. We have 100% working interest in all these eastern wells. In this eastern area, we typically drill 4,000 foot laterals and expect average reserves per well of 460 MBOE net after oil. The Western area has only one target, the Lower Eagle Ford and the rock is a bit thinner. Typical wells here are the Haynes 1H and Hoff 6H wells, which IP ed at 9 79 and 6.29 barrels of oil per day, respectively.
We have 100% working interest in these wells also. To maximize our economics in the West, we'll drill 6,000 foot long laterals and expect 430 MBOE per well net after royalty. These per well recoveries are considerably higher than we noted in April. 6th, the typical decline curve for both areas indicates we'll produce 40% of the wells reserves in the 1st 5 years. We originally thought we need roughly 2,800 wells to capture the 0.9000000000 barrels of oil equivalent, But now it will take us a lot fewer wells to monetize this asset.
Overall, we believe we can achieve $12 to $15 per BOE direct finding cost across the entire play. We plan to run 14 rigs and drill 231 net Eagle Ford wells in 2011. And 7th, the direct rates of return that we expect to achieve from both the East and Western wings of our sweet spot will return to the same rate of return goals as we gave at our April Analyst Conference. As we exit the science stage and enter the program drilling phase in 2011 and 2012, we achieved we expect to achieve between 66% 95% direct after tax rates of return. In order to decrease our average completed well cost back to the original range by the end of next year on a normalized lateral length basis, We're implementing drilling enhancements and completion design modifications as well as contractual and self sourced frac solutions.
Let me take a minute here to discuss our volume growth projections. This applies not only to the Eagle Ford, but also to our other oil resource plays. EFG is a company that has rarely missed its volume targets over the past 11 years, yet now we're revising our 20 ten-twelve numbers downward. Part of this is very simple. At current and projected gas prices, we have no interest in growing gas volumes.
Regarding oil, our individual wells are performing as expected, but we underestimated the downtime for Pattern Drilling, the delays for frac equipment. As we previously stated, optimizing shale oil or gas recovery requires drilling 5 or 6 side by side wells, fracking them simultaneously and only then turning all wells to production. Therefore, if frac equipment is delayed, it doesn't affect only one well, but cascades to 5 or 6 wells and the associated production. We believe our updated volume is does not properly account for this methodology. To give you a little more color on these frac equipment delays, we're currently experiencing delays in almost every one of our divisions and have about 100 wells experiencing delays.
Since most of our budget is oil wells, this disproportionately affects oil volumes. These delays won't go away anytime soon and our new 20112012 growth forecasts assume the frac delays continue until at least mid-twenty 11. Moving to an emerging oil play, we're pleased to report success on additional acreage in our New Mexico Leonard Shale. Last quarter, we told you we'd proven up 31 proven up 31,000 or 120,000 net acres and we can now report we've proven up an additional 18,000 acres. Our Wallow 11 1H and 2H wells are producing at 3.375 505 barrels of oil per day with 3 point 1,000,000 and 4,800,000 cubic feet of rich natural gas, respectively, from an upper and lower Leonard interval, indicating we have 2 separate targets in this area.
We have 100% working interest in these wells. We expect our Leonard reserves will likely increase from the original 65,000,000 barrels of oil equivalent in our estimate. Because acreage expirations aren't as critical here, we'll develop this asset at a relatively slow pace in 20 11. Our Barnett combo results continue to be consistent and we're in a steady manufacturing mode. For the Q2 in a row, we've expanded the core area, this time from 150,000 to 160,000 acres.
This play keeps getting bigger. Earlier this year, we highlighted our first very good horizontal well in the eastern portion of our acreage where we previously targeted only verticals. Since then, we've completed many successful eastern area wells with horizontals and verticals. Recent successful horizontals are the Strickland A2H Settled C3H and the Christian C3H with IP rates of 1118, 731, 954 barrels of oil per day with 1,600,000 to 2,100,000 interests varying from 90% to 98% in these wells. 2 successful vertical wells in the East are the Strickland 1 and Slagle 1, which IP ed at 865-539 barrels of oil per day.
We have 96% and 100% working interest in these wells respectively. We also achieved good results in the western portion of Montag County with the Posey C3H testing at 5 36 barrels of oil today. We're currently operating 16 rigs in the combo and plan to run 16 rigs here in 2011. One other interesting feature here, although the combo produces about 1 third oil, 1 third NGLs and 1 third residue gas, the current revenue split is over 90% liquids and less than 10% gas, consistent with our liquids shift. Plan to drill 258 Barnett combo wells in 2011.
On our Barnett gas activity, essentially all of our Johnson County acreage is now held by production. So we plan to drill 0 gas wells in 2011. Moving to the Bakken, per well results continue to be as expected and we continue to prove up acreage outside our core area. The newest area is southwest of the core where we've drilled several 6 40 Acres with good IPs. The Mandere 415, 29, 10.5 and 6 20 wells I feed at maximum gross rates of 14.90, 13.58, 8.40 and 11.75 barrels of oil per day, respectively.
We have 63% to 90% working interest in these wells. Our drilling within the Parcel core area has also yielded the expected results and we've seen no unusual declines here. Overall, we're happy with our North Dakota results and this asset is currently our single largest oil contributor, although that will change within a year or 2 as the Eagle Ford ramps up. We plan to drill 10 to run, excuse me, 10 Bakken and Three Forks rigs in 2011. Also about 25% of our 1010 wells were 12 80 Acrespace Laterals and that 25% will grow to about 70% next year.
Manitoba, once SCADA oil volumes are finally growing after one of the wettest summers in 60 years, which inhibited our activity. Net production has increased from 4,600 barrels of oil per day in January and we expect year end exit rate of 7,700 barrels a day. The last oil play I'll mention is in Niobrara in Southeastern Colorado. Excuse me, that's Northeastern Colorado. We're currently running 3 rigs here.
2 recent wells, the Critter Creek 5-10H and 9-15H at IP rates of 690 and 748 barrels of oil per day on restricted chokes and we have 100 percent working interest in both of these wells. Even though natural gas isn't currently in vogue, we have some upbeat news from the Marcellus and good news from the HaynesvilleBossier, where we are drilling to hold acreage. In the Marcellus, we've modified our frac program in our first four wells on the EOGNFG joint venture acreage with these new style completions are very strong. The Clearfield County Pungsten 34H, 35H, 37H and 38H wells IP ed at 9.2000000, 8.5000000, 7.1000000 and 8000000 cubic feet a day, respectively. EOG has 50% working interest in these wells.
In our HaynesvilleBossier area, we continue to make good wells such as AC LCO 1, Blackstone 4 5 and Freeman Farms 1 wells, which IP ed at 34, 23,000,000 and 26,000,000 cubic feet a day respectively. We have 48%, 75% and 75% working interest in these wells. We've refined our mapping of the play sweet spots. And although we're not known as a major Haynesville player, we believe EOG has a HaynesvilleBossier sweet spot acreage position that's as good or better than any other operator into play. Current Investor Relations presentation has a chart showing EOG with 67% of our total acreage position in the sweet spots of this play.
During of completing several wells and early results from 3 wells completed in the EV section show IPs between 16,000,000 and 22,000,000 cubic feet a day. We won't be as active here in 2011 as we've been in 2010. Outside North America, our Trinidad asset is currently in a production mode and we will begin development drilling on our Tucan discovery in the Q4. This will provide deliverability to beat our 20 eleven-thirteen gas contracts. In China, expect to frac another well the 3rd by year end.
Outside of operations, part of our business plan involves selling some assets to partially cover our expected 20 10 2011 operating cash flow shortfall. At our April Analyst Meeting, our goal was to sell assets this year and maintain a maximum 25% net debt to cap total ratio. Since April, gas prices have obviously collapsed, so we've come up with a new capital plan. We expect to sell between 600,000,000 dollars 1,000,000,000 of acreage and or producing assets this year with almost all of that expected to close in the 4th quarter. I want to stress most of these deals are not yet closed.
For 2011, we plan to sell at least $1,000,000,000 of primarily gas acreage or producing properties and we've raised the conceptual upper limit on our net debt to total cap ratio from 25% to between 30% 35%. Unlike others, we don't intend to sell or JV any of our horizontal oil plays. We intend to emerge from this transformation retaining 100% of the oil and combo assets that we've captured and we're willing to liquidate gas assets, gas acreage or assets to achieve that goal. I'll now turn it over to Tim Driggers to discuss financials and capital structure.
For the quarter, capitalized interest was $19,500,000 For the Q3 2010, total 2010, total exploration and development expenditures for the quarter were $3,000,000 In addition, expenditures for gathering systems, processing plants and other property plant and equipment were 100 and $7,000,000 During the Q3, we accepted bids to sell a portion of our Canadian shallow natural gas assets for net proceeds of $320,000,000 Additionally, these assets were considered to be held for sale and we recorded a pre tax impairment of $280,000,000 to write down these assets to fair value. At quarter end, total long term debt was $3,800,000,000 and the debt to total cap ratio was 27%. At September 30, we had $28,000,000 of cash giving us non GAAP net debt of 3 point $7,000,000,000 and a net debt to total cap ratio of 27%. Yesterday with press release, we included a guidance table for the Q4 and the updated full year 2010. For the full year 2010, the effective tax range is 40% to 50%.
Note that this is on a GAAP basis. We have also provided an estimated range of the dollar amount of current taxes that we
we're still rationally bullish based on the fact that global oil demand is currently 86,000,000 barrels a day, the same as in 2,008. And the demand has rebounded very nicely from last year. It's worth noting that 2010 global oil demand growth is the 2nd greatest in the past 30 years. We've increased our 2011 hedge position slightly and currently have 10,000 barrels of oil a day hedged at $90.39 Regarding North American natural gas, the question is, can it get much lower? And I guess time will tell.
I expect the gas rig count to fall by about 200 rigs by mid-twenty 11. We currently have 150,000,000 cubic feet head 2011 at a $5.44 price and $200,000,000 a day hedge for 2012 at a $5.57 price. Now let me summarize. In my opinion, there are 3 points to take away from this call. 1st, beginning in 2011, we are now predominantly an oil company based on our anticipated revenue mix and there is no other company our size that's growing oil and NGL volumes similar to EOG's rate.
2nd, our oil assets are generating consistent and repeatable results. I'm particularly pleased with the results this quarter from the Eagle Ford, Barnett Combo, Leonard and Bakken. Regarding the Eagle Ford, 2 recent industry transactions for acreage in the oil window have ratified our asset value, particularly when noting that we were the 1st mover and have a premier oil window acreage. And 3rd, although our capital plan has changed a bit since April, we're on track to sell significant natural gas properties in 2010 and have additional sales planned for 2011. Additionally, we've paired our 2011 dry gas CapEx to the absolute minimum level to hold our Haynesville, Marcellus and Horn River acreage positions.
Our goal is to retain and develop 100% of our oil assets without incurring excessive debt. And if we lighten up on some natural gas assets in the process, so be it. Thanks for listening. And now we'll go to Q
And we'll go to our first question from Joe Allman from JPMorgan.
Thank you. Good morning, everybody.
Hey, Joe.
Mark, just a question on a gas asset. You mentioned the Horn River Basin activity will be less next year than this year. Could you just talk about the development that you plan at the Horn River? And do you have any obligation at this point related to the LNG facility?
Yes. The status of the Kitimat LNG facility is we're still teaming up with Apache and working on that. And we're making, I'd say, consistent progress, but I believe it's going to be year end 2011 before we truly know if we have a firm project or not. So over the last 3 months, we've clearly made some headway. But it's just going to be a slow progress.
I believe the project's got a pretty strong chance of actually happening. I think all the elements are in place for it, but we still got a ways to go. And so what we've adopted in light of these very dismal North American gas conditions is we've done enough science wells now in the Horn River to have a pretty good feel for reserves, potential per well deliverability, so on. And we're just going to, for 2011, just take a minimalist approach in terms of our CapEx related to Horn River Drilling in that particular area.
Okay. That's helpful. And then regarding the asset sales, in the Q2 conference call, you mentioned acreage amounts that you were going to sell in various places like the Marcellus, Eagle Ford and Haynesville. Have there been changes to those plans?
Yes. And we don't really want to talk about anything specifically until we get some firmer situations. But generally, I'd say in either 20 10 or 2011, it's likely that we'll be divesting ourselves of a portion of the Marcellus acreage and a portion of what we call kind of our non core Eagle Ford acreage.
Okay. And what about the Haynesville? And you were also going to sell some Niobrara?
Yes. The Haynesville, we've got a small amount of acreage there that we'll probably liquidate. That's not going to be a substantial amount. And the Niobrara, we have divested a little bit of the 400,000 acres, but we'll definitely be keeping the majority of that 400,000 acres. The best way to explain all this, Joe, is our on the natural gas front, we've got a huge gas inventory clearly in the HaynesvilleBossier in the sweet spot, we think between 9 and 10 Tcf.
We're quite encouraged now with the Marcellus on our combined EOGNFG acreage. We know we've got a ton of gas in the Horn River and certainly a bunch in the Uinta Basin and some in Johnson County and the Barnett. And what we'll be looking at selling over the next 18 months are properties that perhaps are long life existing gas properties that maybe time to pass down to another operator. We're a company that accumulating mode that whole time. So we've got a pretty good inventory of existing properties to liquidate.
And there are buyers out there even at these kind of gas price conditions. And so we'll be liquidating some of those and also on some acreage that either we'd have to invest in drilling wise or before it expires or something along those lines. So what we want to do is we want to emerge from this with the horsepower for gas of all those core plays I just mentioned to you. So if it turns out that the gas turns out to be a bullish commodity over the next 5 or 8 years that we've got a tonne of horsepower there And we want to emerge from this with essentially 100% of all of our oil and combo plays. We believe we can do that during the next year or 2 even while we're liquidating some gas producing assets and some portions of some acreage.
Okay. All right. Very helpful, Mark. Thank you.
We'll take our next question from Richard Dearnley from Longport
Partners. Good morning. Could you talk about your Permian activity in the southeastern region, Irion and related counties, please?
Yes. I mean, what we can say about that, particularly in those areas and it's no secret that there's a play that's active out there called the Wolfcamp play, horizontal play. We're aware that at least 2 public companies have made press releases recently and their press releases are basically predicated on an EOG well or wells in that area. And what they're saying is based on EOG's well results, we Company A and B have a new oil play. And we're as is typically our case, we'll talk about any new potential plays whenever we have sufficient data to provide an intelligent assessment to our Wall Street.
And at this point, it's just too early for us to comment, but we do have to recognize that our names out there in public given on previous plays in the past.
As they use, is the 40-fourteen well as good as the rumors have it?
Yes. I really can't comment on that at this time, Richard, except to say that at some point down the road when we really feel that we've got our acreage position locked in and we have sufficient data from sufficient wells and we can provide you a comment.
Okay. Thank you.
And we'll take our next question from Scott Wilmoth from Simmons and Co.
Hey guys. You alluded to some increasing your self sourced frac solutions and I know you guys have sourced sand in the Barnett. Are you thinking of continuing to do that in other basins? Or are you actually considering buying into pressure pumping equipment?
Yes. Kind of our current situation, Scott, is that we are indeed self sourcing our fracs, if you will, in the Barnett, particularly in the combo play. We're not going in the business of buying pressure pumping equipment, but we are we very much recognize that the cost and the availability of equipment from major suppliers is just flat avenues we'll just say that we expect to have those in place approximately mid-twenty 11. And at that time, we'll discuss exactly what those other avenues are. But it's if I'd give you one primary reason why we've had to lower our volume estimates here, it's been lack of availability, frac equipment.
And as I mentioned earlier, we are literally just in essentially every division, we're literally waiting months, not weeks, not days, months for availability of frac equipment. And the cost of those that equipment when it does show up is, I'd say, has increased dramatically from our April analyst conference. And that's just a situation that we have to come up with a plan to ameliorate that and we have a plan and we'll articulate it more clearly as we get to midyear next year.
Okay. Just jumping over to the Eagle Ford. You guys have had success with increasing the EURs. Have your down spacing assumptions changed at all since your Analyst Day? 125 to 140 acre spacing?
Can you kind of talk through how that's progressed?
Yes, Scott. At the conference we were talking about I think 120 25 acres spacing for the eastern or northeastern portion of Eagle Ford and I think it's 140 acres for the southwestern portion. And we're still experimenting with that. We have lengthened our laterals because we now have really excellent quality 3 d shot in both those areas Northeast and Southwest. And we now know how long we can drill a lateral before we get in trouble with faulting and that sort of thing.
So we have extended our lateral lengths probably from an average of say 3,005 100 feet in both areas in the past to maybe 4,000 feet in the Northeast and as Mark said earlier about 6,000 feet in the Southwest. And the uplift that we're showing on our EURs is really you can tie almost all that uplift just to these longer laterals at this point. So the bottom line is we're not yet calling on increased recovery efficiency or down spacing or anything like that to improve our EURs per well. We think that's still in the future for
us. Okay. And then lastly just on the rig count in general heading into 2011, it seems like you're going to stay flat in the combo and the Bakken picking up in the Eagle Ford. Are there any other moving pieces up or down on the rig count that I'm missing there?
No. We're going to we're running 75 rigs and it looks like 2011 will be in the 75 to 80 rigs as well.
Okay. Thanks guys.
And we'll take our next question from Biju Bernayshail from Jefferies and Co.
Good morning, B. G. Thank you. Good morning. Couple of questions.
First on the Canadian sale, if I read what was in the queue correctly, I think what you sold is about half of what I thought you were producing up there. So is there more Canadian solid gas production to be sold? And number 2, from what you said earlier, are you now leaning towards monetizing more of your producing properties as opposed to raw acreage?
Yes. Relating to the Canadian sale, yes, the answer is it's likely that over the next 12 months that there will be additional Canadian shallow gas sold. We only sold a portion of it or basically what's announced in the press release is only a portion of that gas. And in terms of monetizing some gas assets, yes, I would say that relative to our April analyst conference, we are now more likely, particularly in 2011, to monetize some producing gas assets more than were previously. If you look at our projected volume growth in North American Gas for 2010, 2011, 2012, it's negative 10%, 11% and I think it's plus 1% for 2012.
And so that And so that's one of the why you're seeing negative North America volume growth. Our feeling is just on a macro view, I'd love to be more optimistic on gas. I hope I'm wrong, but we are so long on gas assets in this company that we can liquidate some of these gas assets and still retain tremendous horsepower if we decide to grow gas assets in 2013, 2014 or 2015.
Okay. That's fair. And then in the Eagle Ford, you talked about the lower and upper zones. Are you accessing can you access both zones with one lateral? Or are you looking at 2 separate wells down the road?
Yes. It's not a case where we're talking about a lateral that have one branch that goes to the upper and then one to the lower, that's not what we're doing. Those Keysight Clampett wells that we highlighted in the press release, those wells have next well is in the upper. That's kind of similar to what we've done in the Barnett. So the way to look at it is that upper requires a separate well from the lower.
Got it. Got it. And then if you look at that trend, I mean, some of your best wells are towards the northeastern part of your acreage. Any thoughts on the acreage extending? What happens as you go further northeast?
Yes. We on last quarter's call, we mentioned that we'd gotten the 3 d shot over that Northeast and the 3 d imaged a new fault block that could extend the 160 mile length of this play another 20 miles to the Northeast. So we have not yet drilled that fault block, but certainly we'll do so in the next multiple months. And if that fault block works, then we do have a 20 mile extension potentially of the 160 miles.
Okay, got it. Thanks. That's all I had.
Okay.
And we'll take our next
And then we'll take our next question from David Tamarin from Wells Fargo. Hi, good morning. A couple of questions. If I think about 2011 CapEx, you said a little bit of an outspend. I mean, should we assume that the outspend is equivalent to the projected asset sales?
Is that the right way to think about that?
Yes. We will furnish, David, a CapEx number on our next earnings call for 2011. But the way I'd suggest you think about it is, we'll be targeting this 30% to 35% debt range. And to us, the 35% is kind of a red zone. That's kind of a zone we don't want to go north of.
So we'll be managing the asset sales. We'll be looking at what are the product prices for next year and trying to sort all that out. But the predominant determinant there is going to be the debt level. And if we have to, we'll sell more assets to keep within that debt level or less assets depending on kind of where we stand on the product prices or capitals.
Okay. Another question. If I went back and read the transcript from the Q2 last night and you guys not you guys, but you made a number of comments about you said infrastructure was tight. It looked like there's some delays on the frac side. What how has the market changed between August November?
Yes. That's a good point. Let me correct one thing. I misspoke a little bit earlier. I said 160 miles for the Eagle Ford.
That's really 120 miles with a possible 20 mile extension. In terms of the frac situation between April and today, it's really gotten worse. I mean, worse from a producer's viewpoint. It's literally at the point now where if we want to frac well and we call upon the major service companies, typically they'll say, well, we can get to you maybe right after the 1st of the year and the price will tell you the 1st of the year, but it's going to be even higher than your worst case scenario to frac this well. And if you don't like that particular price availability, we've got a lot of other people that are needing fracs.
So it's I would say, we certainly had a peak drilling activity several years ago when gas was $9 or $10 and it was a frenzy of activity, but the frac situation was not as tight then as it is today, in
my opinion. We said quarter that the cost would and stimulation was up 20% to 40%. Today, we would say at 40%, maybe as high as 50% more.
Okay. One more big picture question. If I think about the PV and the impact of pushing some of that drilling back out years, obviously the value is still there, but it takes a couple of years to get it. How do you guys have an internal NAV model and assume you do care to share what the next 2 years the slowdown in production does to that model or how should we think about value creation other than being pushed back a couple of years? Because obviously the CapEx, I mean, it's costing more to drill.
Anyway, I'll shut up. Yes.
We're not going to try and give you an NAV for any of our assets or so. But I mean the only point I'll say is there's nobody else in North America other than maybe the heavy oil guys who've captured essentially in one play close to 1,000,000,000 barrels. And this discovery were made in a deepwater Gulf of Mexico, it would be highly discovery were made in a deepwater Gulf of Mexico, it would be highly heralded newspaper headlines, so on and so forth. We can beat the breaches off on a direct finding cost of whatever a deepwater finding cost is and we can beat the bridges off a heavy oil project. And so we have a gem of a project and yes, maybe the PV has been pushed back potentially a year or 6 months.
But when you look at it in a bigger picture scale, that's not all that meaningful in terms of deferred PBs as far as we look at it. That's as far as I'll go, David, given you. All right.
Worth a shot. All right. Thanks. Yes.
And we have our next question from Leo Mariani from RBC.
Hey, Leo. Hey, guys. A couple of quick questions here for you. Previously on the debt cap side, you guys were at 20%, 25%. Mark, you talked about 35% sort of being your max red zone.
Does that factor in the effect of the asset sales? So I guess what I'm asking is post asset sales next year, are you still going to be at 35%?
Well, our game plan is between now and 2012 to be no more than 35% and that does factor in. That assumes we do have asset sales in 2011, yes.
Okay. Obviously, you guys cut your oil and liquids production guidance for 2011 and 2012 and clearly you've articulated a lot of the reasons. Do you expect to also see a reduction on oil and liquids related CapEx as well in the next couple of years?
Yes. We'll I mean, we'll answer that when we provide CapEx guidance on the next earnings call, Leo. Okay.
Jumping over to Eagle Ford, what are
you guys seeing right now in terms of well costs over there?
Yes. They're currently higher than what we forecast in our April analyst conference and we're working to get those down. I mean the primary reason is the frac costs there are in rough terms maybe as much as $1,000,000 higher than what we would have estimated previously. And we hope by mid-twenty 11 with some of this self sourcing that we're talking about that we can get those costs more in line. But the costs have gone up, but also the reserves have gone up because we're drilling longer laterals.
So in terms of the returns, this is likely to be an awesome project on returns Niobrara
acreage. I know you haven't declared victory on that, but is that Niobrara acreage. I know you haven't declared victory on that, but does that indicate that you've got some optimism about the play here?
Yes. It's still I mean, what we promised is at year end, we give an update on Anaya Barrera, which would really translate to the next earnings call. The issues are we've been articulating the same as on the last call. It's a much more heavily fractured play. So the initial production rates are going to be quite good.
The question is what do those production rates look like 6 months, 12 months after the initial rates. And so we just need a bit more time to watch it before we really give you specifics on that.
Got you. Okay. Jumping over to trend out real quick. I noticed that you guys reduced your international gas volumes for 2011. Is this just some slippage there in the start up of Toucan and when you're going to be selling some of the gas there?
No. It's really due to the our projection of the internal markets. What happened when we had this big recession worldwide recession in 2009 or the anticipated growth of new methanol and ammonia plants that we assumed would be built on the country of Trinidad, Well, those all got put on hold. And so we anticipate that there may be some just some internal demand restrictions. We may not have as high a contract takes next year as we've enjoyed this year.
So it's we've got a little bit of factor built into our numbers there for that Trinidad.
Okay. And it sounds like you sold a portion of the shallow Canadian gas. Could you let us know how much volumes were sold and
what the reserves were associated with that?
No, we just do not say that because we're in the process of working to sell the remainder of the gas and we don't want to set any particular parameters out there, benchmarks. Okay. Parameters out there benchmarks.
Okay. But in your new production guidance for 2011, have you factored in the sale that you've already made there?
Yes, that is correct.
Okay. Thanks guys.
And we'll take our next question from Steve Emerson from Emerson Investment Group.
Good morning, Steve.
Mr. Emerson, we can't hear you. Mr. Emerson? And hearing no response, we'll move on to Brian Singer from Goldman Sachs.
Thanks. Good morning.
Good morning, Brian.
As you highlighted, one of the key drivers in the change of your oil guidance is the result of the greater completion, tie in delays and the key resource plays. Can you provide more color on how long it takes to drill complete and tie in wells in the Eagle Ford Net Combo and Bakken today, what you assumed that that could get to previously in 2011 2012 and what you're assuming today?
That's pretty broad question there. As far as the time you spud a well then you bring it on production, it could be anywhere from depending on the play anywhere from 60 to 90 days, probably on the higher end of that. And as far as yes going forward here, Mark had mentioned that we expect maybe have some relief on available pump services mid year 2011 that may drop back from the 90 days to the 60 days, Brian. That answers your question?
It partially does. And so I guess what then changed relative to where you were previously? Were you assuming that could have gone from 60 to 30 and now you're assuming it goes from 90 to 60. Is that essentially the kind of key change in how you're thinking about things here?
Yes. I guess one I'll take the crack step, Brian. We all knew that we wanted to complete these wells in bunches, 4, 5 or 6 wells together. But what we assumed back in April was, if we called up a service company and said, we need you to frac the well in 3 weeks that they'd show up in 3 weeks and we then frac 5 or 6 wells simultaneously. Now what we're finding is, you have to schedule this 4 or 5 months in advance.
And instead of 3 weeks, you're really looking at 4 or 5 months to get those things done. And what it does is it sets you back the whole not one well, but 6 wells production comes online many, many months later than what you expected. And then what it does for you is, we assumed we'd have an exit rate in December of this year, let's say, X back in April. Now we know that exit rate is going to be less than that. And so that's why the gross volumes that were projected now for next year in 2012 are going to be less.
We're still going to have pretty dramatic year over year production growth, but we're compounding off a lower base than what we previously expected because we didn't achieve our goal this year. And then we build into it the fact that miraculously these frac equipment does not become instantly available on January 1, 2011. It's we don't see any real improvement there. The biggest improvement we're going to see, we believe in the frac equipment short of our self sourcing is if the gas rig count drops by a couple of 100 rigs. And we believe by mid next year, my guess is 200 rigs, Gary Thomas is guessing 300 rigs, a drop in the gas rig count.
But when that happens, if that happens, then all of a sudden whatever frac equipment is tied up there, it aggregate gas market and 2 is just bank up the free up equipment. Hopefully, that gives you a little more color there, Brian.
Yes. That's helpful. And then when we look at the change in your gas production expectations, how should we think about the organic impact from a combination of reduced activity outside the Marcellus and Haynesville combined with the stronger results you've seen in the Marcellus and Haynesville? Is it still kind of an organic decline or do the 2 off each other?
No, they don't we'll be selling more gas, we believe, over the next 18 months than we're developing new gas. So it's a I would say it's a sale related decline more than anything else. In other words, the impact of the total volume of gas we're likely to sell in 1,000,000 cubic feet a day is going to overwhelm our organic growth and the net is going to be those slightly negative North American gross numbers.
Got it. Thanks. And then lastly, just a follow-up on one of the earlier CapEx questions. I know you have guidance officially for next year, but is the way we should just back into what you would be assuming today to assume the 10% growth, assume $1,000,000,000 in asset sales, 30% or 35% net to total cap, assume strip commodity prices and then back into what CapEx implies? Is that essentially a good way of thinking about what you may be modeling internally?
No.
I don't think we want to give that much clarity at this point in time, because the asset sales we're looking at next year are probably a minimum of $1,000,000,000 as we think about it today. But we'll give you more clarity by the next earnings call on that one.
Great. Thank you.
Okay, Brian.
And we'll take our final question from Brian Lively from Tudor, Pickering, Holt.
Good morning. Just trying to get a little more color on the new debt to cap target. What are the primary drivers again for the increase from 25% to the 30 percent range? I'm just wondering if that's a price issue or realization versus hedges or is it related to higher spending or some other reasons?
I'd say that the two clear reasons are a collapse in gas prices relative to what we saw in April. And also in April, I believe if you looked at the oil price expectation or the NYMEX that existed in April versus what we've actually achieved so far this year, we've actually gotten a lower oil price than what the NYMEX would have indicated in April. So part of it is clearly the hydrocarbon prices have provided less cash flow this year than we hoped for. And then the other part of it is just the, I'd say, cost escalation primarily in the fracs. It just cost us more to get done what we anticipated.
And that's not new news. I think most everybody who's reported earnings so far has indicated some cost pressure issue relating to the fracs. So those are the 2 big components of it, Brian.
That's helpful. And then when you think about the Leonard Hill and the Eagle Ford, do you think directionally lateral lengths are getting longer, more stage fracs? Is that sort of Bakken concept going to be applied do you think or being applied to some of these new oil prone shells?
Very definitely. Yes. I mean it's if you project that 2 or 3 years when you look at the Bakken, when we started out in the Bakken, you're looking at maybe 4,000 foot laterals and now we're kind of routinely talking about 9,000 to 10,000 foot laterals and the industry is doing the same thing up there. And we started out in Eagle Ford. The data we had back in April were really based on 2,900 foot laterals and today we're talking about 4000 foot foot to 6000 foot laterals.
So if you go out a couple of years for say the Eagle Ford, it wouldn't surprise me if we end up talking about routinely 8000 to 10000 foot laterals because the reserves one thing we found in pretty much all these resort plays are the reserves are just a linear function of the lateral length. You drill a well with twice the lateral length, you're likely to get twice the reserves. And the same thing would hold true true for any of the other plays, whether it be the Leonard Shale or the combo play or some of these things. So, in many cases, you've got some limitations there if you've got a lot of fault patterns. So more highly faulted an area is, I mean, you can't go out and drill a 10,000 or 14,000 foot lateral, but the direct the sense of the industry moving to longer laterals and all the plays, I think, will barely definitely occur.
Great. And then last question is just on LOE and as you shift to a higher percentage of liquids, where do you think directionally the LOE trends for the company over 2011, 2012?
Yes. I mean, there's no doubt. I mean, we certainly can't deny the fact that if you take just a dry gas well versus an oil well, the LOE is going to be higher for an oil well. And so we clearly have that that we'll be working against. But of course, obviously, the margin profit margin on oil well is much higher than the gas well.
But I can't give you a percentage or a number other than again to defer to the next earnings call, we'll give some LOE guidance for the full year of 2011 relating to that. So that hopefully will give you a little bit of input anyway, Brian.
Thanks. Appreciate it.
Okay. I'd like to thank everyone for staying with the call. And once again, it's a case where EOG has been one of the most accurate companies on hitting volume targets for 11 years, but we've just had a confluence of events here. But even once you get through the sticker shock of the lower volume growth that we're projecting, I don't think there's a company out there who's going to match our liquid volume growth for the next several years. And I also mentioned that the volume growth doesn't stop in 2012.
It continues in 2013, 2014, 2015, clearly on liquid side. We just haven't forecast that far out. So thank you very much.