EOG Resources Inc (EOG) 2010 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to today's EOG Resources 2010 third-quarter earnings call. 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 third-quarter 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 South Texas Eagle Ford, Barnett Combo, and New Mexico Leonard plays, may include potential reserves or 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 US investors that appears at the bottom of our press release and investor relations page of our website.

With me this morning are Loren Leiker, Senior EVP, Exploration; Gary Thomas, Senior EVP, Operations; Tim Driggers, Vice President and CFO; and Maire Baldwin, Vice President, Investor Relations.

An updated investor relations presentation was posted to our website last night. We included 2010 and revised preliminary volume estimates for 2011 and 2012. 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 are now projecting minus 2% growth versus the previous estimate of plus 2%.

Obviously, in this price environment we are 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 have also reduced our 2011 and 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, '11, and '12.

We have also made progress regarding asset sales, and I will report on that later in the call. I will now review our third-quarter net income and discretionary cash flow, then I will provide some operational highlights and discuss our capital structure. Tim Driggers will provide some financial details, and I will close with comments regarding our macro hydrocarbon view and concluding remarks.

As outlined in our press release, for the third quarter EOG reported a net loss of $70.9 million 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 third-quarter adjusted net income was $46.6 million 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 third quarter was $755.4 million.

I will now address operational results, and I will start with the South Texas Eagle Ford. The bottom line here is that our confidence in individual well results and the total 900 million barrels of oil equivalent net after royalty reserve estimate has increased since our April analyst conference. Because this is such a huge net oil accumulation and I believe investors have undervalued this asset, I am going to take several minutes and provide an update based on our results from the last six months.

Our press release provided details from a number of good wells, most of which have only commenced sales in the last month. Here is 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 fraccing.

First, the Eagle Ford formation is not a typical shale; but instead it is a borderline conventional carbonate reservoir. Pressure and flow data from our wells indicate we are seeing a lot of matrix flow, i.e., a significant amount of flow from the rock fabric itself, which is (technical difficulty) good sign.

Second, the Eagle Ford is a predictable play. We have now drilled a large enough population of wells and we are getting very repeatable results across the 120-mile extent of our acreage block.

Third, we have had a 100% well success rate within the acreage and the horizons we originally defined to contain our estimated 0.9 billion barrels. For a start-up play, this is outstanding.

Fourth, for our 0.9 billion barrels of estimated reserves, the mix is 77% black oil. The oil in our portion of the reservoir has some unique characteristics that enhance the recovery factor. We have kept this information proprietary until now, but with our acreage tied up we can now talk without losing a competitive advantage.

I will apologize in advance for getting too technical, but 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 is why we are so confident with our 0.9 billion barrel reserve estimate.

Fifth, the reservoir can be broken into two zones, East and West. In the East, we have two targets, the upper and lower Eagle Ford. These zones are relatively thick and high quality.

A typical well here is the Harper number 10H well, which IP-ed at 1,070 barrels of oil per day and 980 Mcf per day. In this same area, the Cusack Clampit Wells, which were highlighted in the press release, IP-ed at rates ranging from 860 to 1,800 barrels of oil per day with 1 to 1.8 million cubic feet a day of rich gas each.

We have 100% working interest in all of these Eastern wells. In this Eastern area we'll typically drill 4,000-foot laterals and expect average reserves per well of 460 MBOE net after royalty.

The Western area has only one target, the lower Eagle Ford, and the rock is a bit thinner. Typical wells here are the Haynes number 1H and Hoff number 6H wells, which IP-ed at 979 and 629 barrels of oil per day respectively. We have 100% working interest in these wells also.

To maximize our economics in the West, we will 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.

Sixth, the typical decline curve for both areas indicates we will produce 40% of a well's reserves in the first five years. We originally thought we would need roughly 2,800 wells to capture the 0.9 billion barrels of oil equivalent; but now it will take us a lot fewer wells to monetize this asset.

Overall, we believe we can achieve a $12 to $15 per BOE direct finding cost across the entire play. We plan to run 14 rigs (technical difficulty) drill 231 net Eagle Ford wells in 2011.

Seventh, 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 '12, we expect to achieve between 66% and 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 are 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.

EOG is a company that has rarely missed its volume targets over the past 11 years, yet now we are revising our 2010-12 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 five or six side-by-side wells, fraccing 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 five or six wells and the associated production.

We believe our updated volume estimates now properly account for this methodology.

To give you a little more color on these frac equipment delays, we are 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 2011 and 2012 growth forecasts assume the frac delays continue until at least mid 2011.

Moving to an emerging oil play, we are pleased to report success on additional acreage in our New Mexico Leonard Shale. Last quarter we told you we had proven up 31,000 of 120,000 net acres and we can now report we have proven up an additional 18,000 acres. Our Elk Wallow 11 number 1H and 2H wells are producing at 337 and 505 barrels of oil per day, with 3.1 and 4.8 million cubic feet of rich natural gas, respectively, from an upper and lower Leonard interval, indicating we have two 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 million barrels of oil equivalent NAR estimate. Because acreage expirations aren't as critical here, we will develop this asset at a relatively slow pace in 2011.

Our Barnett Combo results continue to be consistent, and we are in a steady manufacturing mode. For the second quarter in a row we have 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 had previously targeted only verticals. Since then we have completed many successful Eastern area wells, both horizontals and verticals.

Recent successful horizontals are the Strickland A 2H, Settle C 3H, and the Christian C 3H, with IP rates of 1,118, 731, and 954 barrels of oil per day, with 1.6 to 2.1 million cubic feet a day of rich gas. EOG has working interest varying from 90% to 98% in these wells.

Two successful vertical wells in the East are the Strickland 1 and Slagle 1, which IP-ed at 865 and 539 barrels of oil per day. We have 96% and 100% working interest in these wells, respectively.

We have also achieved good results in the Western portion of Montague County with the Posey C 3H testing at 536 barrels of oil per day. We are 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 one-third oil, one-third NGLs, and one-third residue gas, the current revenue split is over 90% liquids and less than 10% gas, consistent with our liquids shift. We 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 zero Barnett 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 have drilled several 640-acre-spaced wells with good IPs.

The Mandaree 4-15, 2-9, 10-5, and 6-20 wells IP-ed at maximum gross rates of 1,490, 1,358, 840, and 1,175 barrels of oil per day respectively. We have 63% to 90% working interest in these wells.

Our drilling within the Parshall Core area has also yielded the expected results, and we have seen no unusual declines here. Overall, we are happy with our North Dakota results, and this asset is currently our single largest oil contributor, although that will change within a year or two as the Eagle Ford ramps up.

We plan to run 10 Bakken and Three Forks rigs in 2011. Also, about 25% of our 2010 wells were 1,280-acre-space laterals; and that 25% will grow to about 70% next year.

Our Manitoba Waskada oil volumes are finally growing after one of the wettest summers in 60 years, which inhibited our activities. Net production (technical difficulty) have increased (technical difficulty) 4,600 barrels of oil a day in January, and we expect a year-end exit rate of 7,700 barrels per day.

The last oil play I will mention is the Niobrara in Southeastern Colorado -- excuse me, that is Northeastern Colorado. We are currently running three rigs here.

Two recent wells, the Critter Creek 5-10H and 9-15H, had IP rates of 690 and 748 barrels of oil per day on restricted chokes. We have 100% 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 continued good news from the Haynesville Bossier, where we are drilling to hold acreage. In the Marcellus, we have modified our frac program, and our first four wells on the EOG/NFG joint-venture acreage with these new-style completions are very strong.

The Clearfield County Punxsutawney 34H, 35H, 37H, and 38H wells IP-ed at 9.2, 8.5, 7.1, and 8 million cubic feet a day, respectively. EOG has 50% working interest in these wells.

In our Haynesville Bossier area we continue to make good wells such as the ACLCO number 1, Black Stone 4 number 5, and Freeman Farms number 1 wells, which IP-ed at 34, 23, and 26 million cubic feet a day, respectively. We have 48%, 75%, and 75% working interest in these wells.

We have refined our mapping of the plays' sweet spots. And although we are not known as a major Haynesville player, we believe EOG has a Haynesville/Bossier sweet spot acreage position that is as good or better than any other operator in the play.

The current investor relations presentation has a chart showing EOG with 67% of our total acreage position in the sweet spots of this play. During 2011, we plan to drill the minimum number of wells here that is necessary to maintain our acreage position.

In the Horn River Basin, we are in the process of completing several wells. Early results from three wells completed in the [EB] section show IPs between 16 and 22 million cubic feet a day. We won't be as active here in 2011 as we have been in 2010.

Outside North America, our Trinidad asset is currently in a production mode and we will begin development drilling on our Toucan discovery in the fourth quarter. This will provide deliverability to meet our 2011-13 gas contracts.

In China we expect to frac another well, the third, by year-end.

Outside of operations, part of our business plan involves selling some assets to partially cover our expected 2010 and 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 have come up with a new capital plan. We expect to sell between $600 million and $1 billion of acreage and/or producing assets this year, with almost all of that expected to close in the fourth quarter. I want to stress, most of these deals are not yet closed.

For 2011, we plan to sell at least $1 billion of primarily gas acreage or producing properties. And we have raised the conceptual upper limit on our net debt to total cap ratio from 25% to between 30% and 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 in Combo assets that we've captured, and we are willing to liquidate gas assets, gas acreage, or assets to achieve that goal.

I will now turn it over to Tim Driggers to discuss financials and capital structure.

For the quarter, capitalized interest was $19.5 million. For the third-quarter 2010, total exploration and development expenditures were $1.5 billion excluding asset retirement obligations.

Total acquisitions for the quarter were $3 million. In addition, expenditures for gathering systems, processing plants, and other property plant and equipment were $107 million.

During the third quarter, we accepted bids to sell a portion of our Canadian shallow natural gas assets for net proceeds of $320 million. Additionally, these assets were considered to be held for sale, and we recorded a pretax impairment of $280 million to write down these assets to fair value.

At quarter end, total long-term debt was $3.8 billion and the debt to total cap ratio was 27%.

At September 30, we had $28 million of cash, giving us non-GAAP net debt of $3.7 billion and a net debt to total cap ratio of 27%.

Yesterday with the earnings press release we included a guidance table for the fourth quarter 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 for of the dollar amount of current taxes that we expect to record during the fourth quarter and for the full year. Now I will turn it back to Mark.

I will now provide a few macro comments. Regarding oil we are still rationally bullish based on the fact that global oil demand is currently 86 million barrels a day, the same as in 2008. The demand has rebounded very nicely from last year.

It is worth noting that 2010 global oil demand growth is the second greatest in the past 30 years. We have 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? I guess time will tell.

I expect the gas rig count to fall by about 200 rigs by mid 2011. We currently have 150 million cubic feet hedged (technical difficulty) 2011 at a $5.44 price and 200 million a day hedged for 2012 at a $5.57 price.

Now let me summarize. In my opinion there are three points to take away from this call.

First, 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 is growing oil and NGL volumes similar to EOG's rate.

Second, 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, two recent industry transactions for acreage in the oil window have ratified our asset value, particularly when noting that we were the first mover and have the premier oil window acreage.

Third, 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 have pared 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 will go to Q&A.

(Operator Instructions) Joe Allman, JPMorgan.

Thank you. Good morning, everybody. 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 obligations at this point related to the LNG facility?

Yes. The status of the Kitimat LNG facility is we are still teaming up with Apache and working on that. We are making I would say consistent progress, but I believe it is going to be year-end 2011 before we truly know if we have a firm project or not.

So over the last three months we have clearly made some headway. But it is 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 have still got a ways to go.

So what we have adopted in light of these very dismal North American gas conditions is we have done enough science wells now in the Horn River to have a pretty good feel for reserves, potential per-well deliverability, and so on. And we are 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. Then regarding the asset sales, in the second-quarter conference call you mentioned acreage amounts that you were going to sell in various places like the Marcellus, Eagle Ford, and the 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 would say in either 2010 or 2011 it is likely that we will be divesting ourselves of a portion of the Marcellus acreage and a portion of what we call our non-core Eagle Ford acreage.

Okay. What about the Haynesville? And you were also going to sell some Niobrara.

Yes, the Haynesville -- we have got a small amount of acreage there that we will probably liquidate. That is not going to be a substantial amount.

The Niobrara, we have divested of a little bit of the 400,000 acres, but we will definitely be keeping the majority of that 400,000 acres.

You know, the best way to explain all this, Joe, is on the natural gas front we have got a huge gas inventory clearly in the Haynesville/Bossier, in the sweet spot. We think probably between 9 and 10 Tcf.

We are quite encouraged now with the Marcellus on our combined EOG/NFG acreage. We know we have 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.

What we will be looking at selling over the next 18 months are properties that perhaps are long-life existing gas properties that may be time to pass down to another operator. We are a Company that over the last decade we have not sold much. We have been in an accumulating mode that whole time, so we have got a pretty good inventory of existing properties to liquidate.

And there are buyers out there even at these kind of gas price conditions. So we will be liquidating some of those. Also on some acreage that either we would 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 gas turns out to be a bullish commodity over the next five or eight years, that we have got a ton of horsepower there. And we want to emerge from this with essentially 100% of all of our oil in our Combo plays.

We believe we can do that during the next year or two, even while we are liquidating some gas-producing assets and some portions of some acreage.

Okay, all right. Very helpful, Mark. Thank you.

Richard Dearnley, Longport Partners.

Good morning. Could you talk about your Permian activity in the Southeastern region, [Erie] and related counties, please?

Yes. I mean what we can say about that particularly in those areas -- and it is no secret that there is a play that is active out there called the Wolfcamp play, a horizontal play. We're aware that at least two public companies have made press releases recently, and their press releases are basically predicated on an EOG well or wells in that area.

What they are saying is, based on EOG's well results we, Company A and B, have a new oil play.

We are, as is typically our case, we will talk about any new potential plays whenever we have sufficient data to provide an intelligent assessment to Wall Street. And at this point, it is just too early for us to comment.

But we do have to recognize that our name is out there in public relating to this play. So that is kind of a circuitous answer, but it is consistent with what we have given on previous plays in the past.

Is the 40-14 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 have got our acreage position locked in and we have sufficient data from sufficient wells, then we can provide you a comment.

Okay, thank you.

Scott Wilmoth, Simmons & Co.

Hey, guys. You alluded to some increasing your self-sourced frac solutions. 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, 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 are not going in the business of buying pressure pumping equipment.

But we very much recognize that the costs and the availability of equipment from the major suppliers is just flat unacceptable to us, really, and we are pursuing other avenues. The other avenues -- we will just say that we expect to have those in place approximately mid-2011 and at that time we will discuss exactly what those other avenues are.

But it's -- if I would give you one primary reason why we have had to lower our volume estimates here, it has been lack of availability of frac equipment. As I mentioned earlier, we are literally just -- in essentially every division we are 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 would say has increased dramatically from our April analyst conference.

That is just the situation, that we have to come up with a plan to ameliorate that. We have a plan, and we will 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? I think you guys are at 125- to 140-acre spacing. Can you kind of talk through how that has progressed?

Yes, Scott, at the conference we were talking about I think 125-acre spacing for the Eastern or Northeastern portion of the Eagle Ford; and I think it is 140 acres for the Southwestern portion. We are still experimenting with that.

We have lengthened our laterals because we now have really excellent quality 3D shot in both those areas, Northeast and Southwest. 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 for an average of say 3,500 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.

The uplift that we are showing on our EURs is really -- you can tie almost all of that uplift just to these longer laterals at this point. So the bottom line is we are not yet calling on increased recovery efficiency or down-spacing or anything like that to improve our EURs per well. We think that is still in the future for us.

Lastly just on the rig count in general heading into 2011, it's 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 am missing there?

No, we are going to -- we are running 75 rigs and it looks like 2011 we will be in the 75 to 80 rigs as well.

Okay. Thanks, guys.

Biju Perincheril, Jefferies & Co.

Thank you, good morning. A couple of questions. First on the Canadian sale, if I read what was in the Q 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?

Number two, from what you said earlier, are you now leaning towards monetizing more of your producing properties as to raw acreage?

Yes, relating to the Canadian sale, yes. The answer is, it is 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 is announced in the press release is only a portion of that gas.

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 we were previously.

If you look at our projected volume growth in North American gas for 2010, 2011, and 2012, it is negative '10, '11; and I think it is plus 1% for 2012. Those projected sales are reflected in those volumes, so those volumes that we provided are not pro forma.

We are assuming that we sell Property X, say, first quarter next year; Property Y by midyear. So that is one of the reasons why you are seeing negative North American volume growth.

Our feeling is, just on a macro view, I would love to be more optimistic on gas. I hope I am wrong. But we are so long on gas assets in this Company that we can liquidate some of these gas assets and still retain a tremendous horsepower if we decide to grow gas assets in 2013, '14, or '15.

Okay, that's fair. 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 two separate wells down the road?

Yes, it is not a case where we are talking about a lateral that has one branch that goes to the upper and one to the lower. That is not what we are doing.

Those Cusack Clampit wells that we highlighted in the press release, those wells have alternating; one well is in the lower, then the next well beside it is in the upper, than the next well beside it is in the lower, and next well is in the upper. That is similar to what we have 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. Then if you look at that trend, some of your best wells are up towards the Northeastern part of your acreage. Any thoughts on the acreage extending? What happens as you go further Northeast?

Yes, on last quarter's call, we mentioned that we had gotten a 3D shot over that Northeast. The 3D 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 will 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.

David Tameron, Wells Fargo.

Hi, good morning. A couple questions. If I think about 2011 CapEx you said a little bit of an outspend. 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 would suggest you think about it is we will be targeting this 30% to 35% debt range. And to us the 35% is kind of a red zone. That is a zone we don't want to go north of.

But we will be managing the asset sales. We will 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. If we have to we will sell more assets to keep within that debt level, or less assets depending on where we stand on the product prices (technical difficulty) [or CapEx levels].

Okay. Another question. I went back and read the transcript from the second quarter last night. You guys -- not you guys, but you made a number of comments about -- you said infrastructure was tight. It looked like there were some delays on the frac side. How has the market changed between August and November?

Yes, that is a good point. Let me correct one thing. I misspoke a little bit earlier. I said 160 miles for the Eagle Ford. That is really 120 miles with a possible 20-mile extension.

In terms of the frac situation, between April and today it has really gotten worse. Worse from a producer's viewpoint. It is literally at the point now where if we wanted to frac a well and we call up one of the major service companies, typically they will say -- well, we can get to you maybe right after the first of the year; and the price we will tell you the first 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 or availability, well, we have got a lot of other people that are needing fracs.

So it is -- I would say we certainly had a peak drilling activity several years ago when gas was $9 or $10 and there was a frenzy of activity. But the frac situation was not as tight then as it is today, in my opinion.

We said at the second quarter that the cost in stimulation was up 20% to 40%. (multiple speakers) Today, we would say it is 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 more years to get it.

Do you guys have an internal NAV model? I assume you do. Care to share what the next two years, the slowdown in production, does to that model?

How should we think about value creation other than being pushed back a couple years? Because obviously the CapEx -- I mean, it is costing more to drill. Anyway, I will shut up.

Yes, we are not going to try and give you an NAV for any of our assets or so. But the only point I will say is there is nobody else in North America other than maybe the heavy oil guys who have captured essentially in one play close to 1 billion barrels. If this 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 britches off on a direct finding cost of whatever a deepwater finding cost is. And we can beat the britches off a heavy oil project. So we have a gem of a project.

And yes, maybe the PV has been pushed back potentially a year or six months. But when you look at it in a bigger picture scale, that is not all that meaningful in terms of a deferred PV as far as we look at it. That is as far as I will go, David, with giving you any (multiple speakers).

All right. Worth a shot. All right, thanks.

Leo Mariani, RBC.

Guys, a couple quick questions here for you. Previously on the debt-to-cap side you guys were at 20%, 25%. Mark, you talked about 35% being your max red zone.

Does that factor in the effect of the asset sales? So I guess what I am 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 '11 and '12, and so you 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 years?

Yes, we will answer that when we provide CapEx guidance on the next earnings call, Leo.

Okay. Jumping over to the Eagle Ford, what are you guys seeing right now in terms of well costs over there?

Yes, they are currently higher than what we forecasted in our April analyst conference, and we're working to get those down. I mean the primary reason is the frac cost there in rough terms may be as much as $1 million higher than what we estimated previously.

We hope by mid 2011, with some of this self-sourcing that we are 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 are drilling longer laterals. So in terms of the returns, this is likely to be an awesome project on returns unless oil prices collapse.

Got you, okay. One comment you guys made is that it doesn't sound like you are selling much of your Niobrara acreage. I know you have not declared victory on that. But does that indicate that you've got some optimism about the play here?

Yes, it is still -- I mean what we promised is at year-end we'd give an update on the Niobrara, which would really translate to the next earnings call. The issues are -- we articulated, and the same as we did on the last call, that much more heavily fractured play. So the initial production rates are going to be quite good.

The question is will, what do those production rates look like six months, 12 months after the initial rates? 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 Trinidad real quick. I noticed that you guys reduced your international gas volumes for 2011. Is there some slippage there in the startup of Toucan and when you're going to be selling some of the gas there?

No, it is really due to our projection of the internal markets. What happened when we had this big recession, worldwide recession in 2009, are the anticipated growth of new methanol and ammonia plants that we assumed would be built on the country of Trinidad, those all got put on hold. So we anticipate that there may be just some internal demand restrictions.

We may not have as high a contract takes next year as we have enjoyed this year. So we have got a little bit of a cautionary factor built into our numbers there for Trinidad.

Okay. 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 would just as soon not say that because we are in the process of working to sell the remainder of the gas; and we don't want to set any particular parameters out there or benchmarks.

Okay, but in your new production guidance for 2011 have you factored in this sale that you have already made there?

Yes, that is correct.

Okay. Thanks, guys.

Steve Emerson, Emerson Investment Group.

Good morning, Steve.

(Operator Instructions) Hearing no response we will move on to Brian Singer from Goldman Sachs.

Thanks, good morning. 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, Barnett Combo, and Bakken today; what you assumed that that could get to previously in 2011 and 2012; and what you are assuming today?

That's a 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.

As far as -- yes, going forward here, Mark had mentioned that we expect maybe to have some relief on available pump services midyear 2011. That may drop back from the 90 days to the 60 days, Brian. Does that answer your question?

It partially does. So I guess what then changed relative to where you were previously? Were you were assuming that could have gone from 60 to 30 and now you are assuming it goes from 90 to 60? Is that essentially the kind of key change in how you are thinking about things here?

Yes, I guess one -- I will take a crack at that, Brian. We always knew that we wanted to complete these wells in bunches, four, five or six wells together. But what we assumed back n April was if we called up a service company and said we need you to frac a well in three weeks, that they would show up in three weeks and we'd then frac five or six wells simultaneously.

Now what we are finding is you have to schedule this four or five months in advance. And instead of three weeks you're really looking at four or five months to get those things done. What it does is it sets you back the whole -- not one well but six wells production comes online many, many months later than what you expected.

Then what it does for you is we assumed that we would have an exit rate in December of this year of, let's say X, back in April. Now that we know that exit rate is going to be less than that. So that is why the gross volumes that we are projecting now for next year and 2012 are going to be less.

We're still going to have pretty dramatic year-over-year production growth; but we are compounding off a lower base than what we previously expected because we didn't achieve our goal this year.

And then we built into it the fact that miraculously this frac equipment does not become instantly available on January 1 of 11. We don't see any real improvement there.

The biggest improvement we are going to see, we believe, in the frac equipment -- short of our self-sourcing -- is if the gas rig count drops by about a couple hundred rigs. And we believe by mid next year, my guess is 200 rigs; Gary Thomas is guessing 300 rigs 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 becomes available for oil plays. So we are kind of hoping that happens for multiple reasons. One is the aggregate gas market; and two is just frac up, free up the equipment.

Hopefully that gives you a little more color there, Brian.

Yes, thanks. That's helpful. 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 have seen in the Marcellus and the Haynesville? Is it still an organic decline or do the two offset each other?

No, they don't. We will be selling more gas, we believe, over the next 18 months than we are developing new gas. So I would say it is a sale-related decline more than anything else.

In other words, the impact of the total volume of gas we are likely to sell in million cubic feet a day is going to overwhelm our organic growth; and the net is going to be those slightly negative North American growth numbers.

Got it, thanks. Then lastly, just a follow-up on one of the earlier CapEx questions; I know you don't 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 billion in asset sales; 30% or 35% net debt 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?

I don't think we want to give that much clarity at this point in time because the asset sales we are looking at next year are probably a minimum of $1 billion as we think about it today. But we will give you more clarity by the next earnings call on that one.

Great, thank you.

Brian Lively, 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% range? Just wondering if that is a price issue, a realization versus hedges; or is that related to higher spending; or some other reasons?

I would say that the two clear reasons are a collapse in gas prices relative to what we thought 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 have actually achieved so far this year, we have 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 I would say cost escalation, primarily in fracs. It just costs us more to get done what we anticipated.

That is not new-news to you. I think most everybody who has reported earnings so far has indicated some cost pressure issue relating to fracs. So those are the two big components of it, Brian.

That's helpful. Then when you think about the Leonard Shale and the Eagle Ford, do you think directionally lateral links 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 shales?

Very definitely, yes. If you project that two or three years -- when you look at the Bakken, when we started out in the Bakken, you are looking at maybe 4,000-foot laterals. And now we are routinely talking about 9,000 to 10,000-foot laterals. And the industry is doing the same thing up there.

We started out in the Eagle Ford, the data we had back in April were really based on 2,900-foot laterals and today we are talking about 4,000 to 6,000-foot laterals.

So if you go out a couple years for say the Eagle Ford, it wouldn't surprise me if we end up talking about routinely 8,000 to 10,000-foot laterals. Because the reserves -- one thing we found in pretty much all these resource plays are the reserves are just the linear function of the lateral length.

If you drill a well with twice the lateral length, you're likely to get twice the reserves. And the same thing would hold 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 have got some limitations there if you have got a lot of fault patterns. So more highly faulted an area is, you can't go out and drill a 10,000 or 14,000-foot lateral. But the sense of the industry moving to longer laterals in all the plays I think will very definitely occur.

Great. 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 is no doubt -- 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. So we clearly have that that we will be working against.

But of course obviously the profit margin on an oil well is much higher than a gas well. But I can't give you a percentage or a number rather than, again, to defer to the next earnings call; we will give some LOE guidance for the full year 2011 relating to that.

So that hopefully will give you a little bit of input anyway, Brian.

Thanks. Appreciate it.

Okay. I would like to thank everyone for staying with the call. Once again it is a case where EOG had been one of the most accurate companies on hitting volume targets for 11 years, but we just had a confluence of events here. But even once you get through the sticker shock of the lower volume growth that we are projecting, I don't think there is a company out there who is going to match our liquid volume growth for the next several years.

I will also mention that the volume growth doesn't stop in 2012. It continues in '13, '14, '15 clearly on the liquids side; we just have not forecast that far out. So thank you very much.

Once again, ladies and gentlemen, that concludes today's conference. We appreciate your participation.