EOG Resources Inc (EOG) 2006 Q3 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources third quarter 2006 earnings release conference call. As a reminder, this call is being recorded. At this time I would like to turn the call over to Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, and thanks for joining us. We hope everyone has seen the press release announcing third quarter 2006 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 in 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 the comparable GAAP measures can be found on our website. The SEC permits producers to disclose only proved reserves in their security filings. Some of the reserve estimates in this conference call and webcast including those for the Barnett Shale Play may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appear at the bottom of the Investor Relations page of our website, an updated Investor Relations presentation with statistics was posted to our website this morning.

With me this morning are Ed Segner, President and Chief of Staff; Loren Leiker, EVP exploration and development; Gary Thomas, EVP operations; and Maire Baldwin, Vice President of Investor Relations. We filed an 8-K with fourth quarter and full-year 2006 guidance yesterday afternoon. As usual, there were no changes to our game plan which is focused on high returns, low debt and strong organic growth with attention to cost control. We did revise our Trinidad fourth quarter production estimates, and I'll address that in a moment. I will now review our third quarter net income available to common and discretionary cash flow, and then I'll discuss operational highlights.

As outlined in our press release for the third quarter EOG reported net income available to common of $297 million or $1.21 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common to eliminate the mark to market impacts outlined in the press release, EOG's third quarter adjusted net income available to common was $277 million or $1.12 per share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's Bcf for the third quarter was $680 million or $2.76 per share versus $659 million or $2.69 per share a year ago.

I will now address our operational highlights. We hit the midpoint of our third quarter 8-K guidance by nailing our North American gas volume spot on and overachieving on our liquid volumes, which made up for lower gas sales from Trinidad. For the first part of the year our Trinidad gas sales considerably exceeded contract quantities. But during the third quarter sales only slightly exceeded contract amounts, and we now expect fourth quarter sales to be limited to contract amounts. Therefore we've reduced our fourth quarter estimate of Trinidad sales which is the primary reason we are reducing our full-year total company year-over-year growth estimate to 9%. The good news is that these Trinidad cutbacks were the lower valued volumes, so the full-year impact to overall earnings and cash flow will be small.

I will commence our operational review with the Fort Worth Barnett, then I'll discuss our traditional North American ex-Barnett activities and I will conclude discussing Trinidad in the North Sea. I will add one caveat at the front end. As many of you know, our annual analyst conference is scheduled for November 29th in Fort Worth. At that meeting we intend to provide an in-depth analysis of the Fort Worth Barnett Shale as well as data on some of our other Stealth shale plays. At that time we will also update our IR charts relating to the Barnett in terms of total reserve potential and individual county breakouts regarding well costs and reserves. The only updates made to the Barnett Shale slides that are part of the IR presentation that was posted on our website this morning are to simply adjust the well economics using current NYMEX pricing. Consequently, today I'll provide only a broad overview of the Barnett and I leave the specifics until November 29th.

The overall conclusion I will leave you with is that the Barnett is doing even better than we expected. In September we averaged 174 million cubic feet a day net. All organic, and I'll note that out of the large producers in the Barnett we are the only company that is producing 100% organic results. While our original plan anticipated a year end exit volume of 155 million cubic feet a day, average well results from both Eastern and Western Johnson County have been remarkably consistent and repeatable by area, which greatly increases our comfort factor and confidence level projecting forward.

Our press release noted several monster wells that we would define as having initial production rates greater than 5 million cubic feet a day. In fact, these wells have become somewhat routine now, particularly in Eastern Johnson County. We continue to make progress in the Western counties, and we will provide specific details in late November. Now I will switch to the North America ex-Barnett portion of our portfolio which continues to perform well. Our 2006 production growth from these assets has been impacted by some downstream issues. Notably continued delays in hurricane related infrastructure repairs in the offshore Gulf of Mexico that are currently affecting us to the tune of 20 million cubic feet a day net. A delayed processing plant in East Texas, which is affected us to the tune of 30 million cubic feet a day net and weather-related issues in Canada. For 2007 we expect to be back on track to achieve a 5 to 8% production increase from this portion of our portfolio.

In South Texas during the third quarter we drilled six wells in the Sterling field at depths of around 11,500 feet from the Lobo formation. The Slater Ranch W2 tested 17 million cubic feet a day and is currently producing over 9 million cubic feet a day. The Slater Ranch U4 tested 13 million cubic feet a day and is currently producing 8.7 million cubic feet a day. We have 87.5% working interest in these wells.

In the East Texas operating area, which also includes Mississippi, we completed our 15th successful well at our South Williamsburg discovery in Mississippi. The Green 2616 number one well was completed at 4.1 million cubic feet a day, and this offsets the Freeman 26.8 number one well which is producing 8.6 million cubic feet a day. We have 91% working interest in both wells. This field is estimated to be a 75 to 100 net Bcf discovery.

Our Rocky Mountain activity is on track to deliver 17% year-over-year organic growth generated by drilling in the Uinta, Williston and Green River basins. Natural gas production increased 19% in the third quarter 2006 relative to the third quarter 2005. In the mid-Continent operating area we drilled several successful new 6500 foot Morrow gas wells in Southwest Kansas and the Oklahoma Panhandle. One of these wells, the GPCU25 number one is an upper Morrow discovery that is currently flowing at a 15 million cubic feet a day rate, and we have 100% working interest. This region remains a significant growth area for us where we have successfully drilled 1000 wells since 1996.

In our Midland operating area we recently completed two strong oil wells that are worth highlighting. In West Texas the Shannon hospital one number one is a 6000 foot Wolfcamp completion. The well IP'd at a 980 barrel of oil per day rate and is currently producing about 600 barrels of oil a day. EOG has 100% working interest in this well.

In New Mexico the Cimarron 18 state number two is producing 620 barrels of oil a day and 1.5 million cubic feet a day from the Bone Springs formation at about 9000 feet. And we have a 75% working interest in this well.

Our Canadian 1200 well Shallow Gas program is about 90 days behind schedule due to early season wet weather issues. We'll likely get the program executed by year end but the production timing is slipped a bit. Now let me move to Trinidad and the North Sea. As I mentioned earlier, our fourth quarter Trinidad sales volumes will be likely limited to contract quantities unlike the first part of the year. EOG's return to contract sales volumes was caused by additional supply becoming available from other producers.

On another front we are currently negotiating an incremental sales contract serving the indigenous Trinidad market for our block 4A discovery made earlier this year. In the UK our 2007 activity will be a function of binding a rig window. We'd like to drill three exploration wells next year subject to rig availability. I will now turn it over to Ed Segner to review CapEx and capital structure.

Thanks, Mark. For the third quarter total exploration and development expenditures including asset retirement obligations were $804 million, which included $8.6 million of property acquisitions. Total discretionary cash flow for the quarter was $680 million. Year-to-date total exploration development expenditures including asset retirement obligations were $2,073,000,000 with $14 million of property acquisitions. Capitalized interest for the quarter was $5.2 million. For 2006 as indicated in yesterday's 8-K our current estimate for capital expenditures is between $2.75 billion and $2.9 billion, and both of those members include acquisitions. An increase from the July 8-K filing reflecting higher activity levels in Fort Worth and the Rocky Mountain area and some higher service cost.

With respect to capital structure at September 30th total debt outstanding was $830 million, and the debt to total capitalization ratio was 13%, down from 19% at year end 2005. At quarter end we had $596 million of cash on the balance sheet for a net debt to total capital ratio of 4%. The effective tax rate for the quarter was 36%, and the deferred tax ratio was 63%. For the full-year 2006 the guidance 8-K has an effective tax range of 31% to 34% and a deferral percentage of 50 to 60%. Guidance for detailed modeling of the fourth quarter and full-year 2006 was provided yesterday in form 8-K filing. We plan on filing the third quarter 10-Q tomorrow. I will turn it back to Mark.

Let me talk a little bit now about our marketing and hedging position, and then I will move into some concluding remarks. Our view of the gas macro hasn't changed much from our last earnings call. In my view there were three lessons we can all assimilate from the 2006 gas market. Lesson one is that the North American gas market always balances just like free markets are supposed to. For the first five months or for the past five months through all the extraneous noise we've been preaching that the market would balance and start the heating season at approximately 3.5 Tcf. This wasn't because we were clairvoyant but because we've seen time and time again that the gas market finds a way to rationally sort itself out. Lesson two is that when Henry Hub prices go above $10 demand evaporates, and lesson three is in 2006 North American production growth was piteously tepid considering the vast amounts of capital and drilling intensity the industry employed. We believe domestic production grew one-half of 1% and Canadian production increased 1% this year. This tepid growth underpins our moderately bullish 2007 view. We expect the likely full-year 2007 Henry Hub range to be between 750 and 950, depending on winter weather with the most likely 850 price. Our financial swap position was articulated in recent SEC filings. We have swaps in place for 19% of North American production for the fourth quarter. For 2007 we have financial swaps for 105 million cubic feet a day at a 974 Henry Hub price. On the oil side we have 4000 barrels a day of financial swaps for 2007 at a $78.22 average price.

As I previously mentioned, our 2006 analyst conference is being held in Fort Worth on November 29 and 30, and the meeting will be webcast live. I want to spend a little bit of time now letting you know what to expect. We plan to give an update on our overall operations and provide a specific 2007 volume growth and CapEx target. Although we will have a specific 2007 volume growth number at the meeting, I can tell you know that directionally we are still projecting an average overall company 9% per year 2007 through 2010 organic growth number with our North American gas growth number being a higher annual percent.

At the meeting we also plan to update the Fort Worth Barnett Shale related data with new information, specifically we plan to update the acreage and reserves per well data by county where we have sufficient data available to make the information meaningful. We also plan to provide some reserve information on the Johnson County down spacing activity. Regarding the other six Stealth plays we expect to have at least preliminary results on four of these. As you are aware, the Barnett Shale Play in Culverson County is the most mature of our Stealth shale ideas. We'll have some test information from Culverson on additional wells, but we won't have actual production history because we don't yet have a pipeline connection. We will have new [slow] in varying states ranging from preliminary to more detailed regarding three other Stealth plays.

Now let me summarize; in my opinion there are five important points to take away from this call. First, as always, the game plan remains consistent with a focus on peer leading ROEs, ROCEs, low net debt and high debt adjusted per share volume growth. We think it is important that investors focus on production per share growth on a debt adjusted basis, instead of simple absolute growth, and we will compare our two-year, 2005 and 2006 record, with anybody's. I'll also remind everyone that our third quarter net debt to total cap ratio was 4%, by far the lowest in the group.

Second, we think we are doing a good job controlling overall year-over-year unit cost relative to the industry for the second year in a row, and we believe our 2005 and 2006 year-over-year unit cost increases will be among the lowest in the peer group. Using one sell-side analyst calculation, our two-year 2005 and 2006 overall unit cost increased an average of 8% per year versus the peer group average of 20% per year. Additionally, we believe our absolute overall unit cost ranked either the lowest or among the lowest in the peer group, and consequently the gap is increasing each year.

Third, the Fort Worth Barnett Shale production results have been better than expected. Importantly, this production overachievement has been generated by consistent average well performance and not by drilling increased numbers of underachieving wells. Fourth, we expect our North American ex-Barnett assets to generate 5 to 8% production growth in 2007.

And finally, we've continued our search for other resource plays focusing on both shales and other rocks, and we'll have more specific details on November 29. Thank you for joining us today, and we will now go to Q&A.

(OPERATOR INSTRUCTIONS) Ben Dell, Sanford Bernstein.

I wonder if I could ask a couple of macro and then a specific question. The first is you talked about on the onshore growth of 0.5%, but we've now seen Texas up 7% and the U.S. onshore up $0.05 and the overseas being part of achieving. And I was wondering how do you tally that with next year 0.5% growth? Because obviously this year you are using years of the offshores had a big hurricane impact.

Yes, again on the macro side I guess the first thing we will say is we are not using the EIA data. I don't want to get into a big discussion on it here on the call, but I would say we are not entirely convinced that the new EIA 914 data is entirely accurate. We go back to some of the IHS data and use it. And we come up with data that tells us that for 2006 production growth is more like about a half of 1%. So our projection for 2007 is that production may grow about 1%. But it is -- I would say that we are in violent disagreement with people who are projecting overall production growth to be up 3% or something like that. We just don't see that.

Okay, and when you look at your cash flow third quarter you spent $760 million on CapEx and you generated $600 million. Obviously going into fourth quarter you are not now as I understand it talking about $800 to $1 billion in CapEx, and I am assuming your operating cash flow will be less given the big rig pricing we've seen so far. How do you look at your debt equity going forward, and will you be ratcheting that up to sort of meet your capital plans?

Just a couple thoughts on the fourth quarter. It is out there. We have about $100 million of preferred stock that we have a tender offer to close out that preferred stock. So if that is consummated in the quarter, that will be closed out and we will have $100 million of debt as opposed to preferred stock and our preferred stock at the end of the year will be zero if that is done. And we will be in a cash deficient position in the fourth quarter. So in rough terms we may end the year at a net debt to total capital ratio of about 10%. But you have to factor in that part of that is taking $100 million of preferred and just eliminating it.

And as we look out into next year if we are correct with our midrange 850 gas price, we are looking at a situation where we will likely be looking at something of probable neutrality for CapEx next year. We'll discuss CapEx in more detail on November 29 but right now based on our midrange case we are looking at exiting '07 in a neutral situation. But one of the reasons -- you've got two situations on the CapEx side. One is that we have extremely low debt and we always said that we're going to use our balance; we are not going to run at absolutely extremely low debt for ever and ever. So if we have great reinvestment opportunities we're going to take advantage of it. And right now I think it will become more clear on November 29 we have a plethora of pretty amazing reinvestment opportunities that look good at either 750 gas price or obviously the 950 gas price for the range we have. And based upon our underpinning assumption that production in North America is growing only slightly, we remain pretty bullish on the reinvestment opportunities. And I know that is different from a lot of the sell-side thesis out there but that is the way we see it right now.

And lastly, just on the rig side, your cost inflation looks accelerated a little bit quarter on quarter versus theirs, as you mentioned as being low historically. I was wondering can you give some indication what you're seeing on rig rates and do you expect them to fall into '07 or stay flat? What is baked into your assumptions as they currently stand?

Rig rates have continued to go up through the year. We've logged in quite a number of new build rigs, and as far as just rig rates here into '07 we expect them to remain pretty flat with where they are currently.

Okay, great. Thank you very much.

Tom Gardner, Simmons & Co.

Can you talk about the commodity price environment gas transportation situation in the Rockies, how you guys dealing with it and what are you thinking? Are you thinking differently with respect to capital allocation?

Yes, we escaped any real messy situation in both September and October up there. If you look closely at our 8-K for the third quarter you notice that our gas prices in the U.S. beat the proposed differential that we had given for guidance in the 8-K. And a big part of that is that in June and July we presold a lot of physical gas in the Rockies. So basically we had most of our gas in the Rockies sold for September and October at prices considerably higher than the spot prices turned out to be. So we had kind of anticipated that September and October would be pretty ugly in the Rockies. So we pretty much avoided that situation. So consequently we didn't have to deal with any production curtailments or face any of those ugly issues about whether to sell gas at $2 wellhead price or anything during that situation there. So my own opinion is we are probably past that situation, and I don't think we will have to deal with it from this point forward.

That's great. And that cost control statistics you threw out earlier with respect to your peers is also good news. Can you address some of the specific actions you've taken to enjoy that advantage?

Yes, I think number one I think that is a very underreported asset point and if you call up the slide on our website we've got one up there, I believe, that is a point that I think is pretty key. The fact that our unit costs have gone up 8% over the '05 and '06 period relative to industry average of 20% is one that we would hope everyone would pay a lot of attention to. Because we started the period with the lowest unit costs -- we believe the lowest unit costs in peer group, and all we've done is just widen that gap over the last two years.

The way we've done it really is I think one of the most advantageous ways we've done it, is we haven't engaged in buying a lot of producing properties or in M&As. And when you actually go those two routes, you typically end up with a lot of high-cost properties, high operating cost properties in the mix that you get. And by going the organic route you basically kind of get to pick and choose what you have and you don't get a lot of high-cost other stuff in there. So I think that has been one portion of it, and the other has just been our company culture which really hasn't changed over time.

One last question. With respect to the Western County Barnett development, there was a mention of a step function completion change under way. Could you give us some more specifics with respect to where you are on the cost curve and what needs to go right to get to that target $1.4 million a well?

Yes, I figured that question would come up and what we'd really like to do is defer a specific answer on that until November 29th. But what I can give you is a warm and fuzzy feeling that we are moving in the right direction. What we are seeing in the Western counties is that we are definitely converging in pretty much all the counties toward the reserve range of the net of 0.8 to 1.0 Bcf per well. And we are converging toward the well cost of approximately the $1.4 million. And that is where we are heading, not just in Jack County that we reported last quarter but pretty much in all those Western counties. And we've had to make some step function changes in how we drill and complete the wells to get the cost there. But as far as specifics, I think we'll just hold off on specifics until November 29th.

I will see you there. Thanks, Mark.

David Tameron, Wachovia.

Quick question for you and just to get back to Tom's point, in Uinta do you feel fairly safe going forward, as far as you don't anticipate any pullback in activity, lingering effects from the price effects in October? It sounds like your October program is fairly safe. Is that fair to say?

Yes, in fact the Uinta program up there is one of our higher reinvestment rate of return programs we have in the company. The Johnson County Barnett is absolute highest, but as a rank other programs in the company Uinta always comes up in the top tier, and we will share a lot more details about the Uinta program again on November 29th, but there is very little chance that we will cut back on the Uinta program in terms of activity level anytime soon.

And maybe just answer this last question but the Deep Mancos, my understanding is you drilled a couple of those tests. Is that -- care to comment on those at this point?

Yes, we haven't really drilled any to the Deep Mancos yet at all. There are other people up there, other companies who have tested the Deep Mancos, but we haven't really drilled any to that depth yet. The deepest we've taken it is to some zones called the Black Hawk and some zones like (indiscernible) in the Mason Berg, but not to the Mancos yet.

Okay and results from the Blackhawk then, my understanding was you drilled the Deep Mancos, but obviously that was incorrect. But what about results of the Blackhawk?

That is part of the Mesa Verde interval and it's part of our program, and I would just as a summary I would say we've had absolutely outstanding results in our Uinta program and the Blackhawk is part of that Uinta Mesa Verde program. It has been one of our flagship programs in the company really.

And then back to Trinidad, and you touched on this a little bit in your comments but as far as '07, is the expectation that you're going to be more in contract volumes? For '07?

Yes, when we generate a specific production volume forecast that we will give you on November 29th inherent in that will be the assumption that we are in contract quantities for the Trinidad volumes. What happened in 2006 was that we started out initially with the assumption that we would be at contract quantities, and then there was basically a deliverability shortfall from some of the other producers on the island, really starting in January. And basically the gas company in Trinidad called on us to kind of make up for some of the shortfalls, and that make up we initially thought was going to be short term. But then it just went month after month after month and we kind of got used to it and said hey, this is a pretty good deal, it is probably going to last all year.

But then what happened were some of the other producers in Trinidad were able to generate additional deliverability. They had just had some logistical problems with getting pipelines connected and platforms online, and during the third quarter they got the logistical issues pretty well fixed up. So we got cut back to more of our contract quantities pretty much in the third quarter, midway in the third quarter. And the expectation is that we will be whacked back even moreso strictly to contract quantities in the fourth quarter. But I'll say that is a soft number.

There is upside to our forecast. In the 8-K guidance we've given for the fourth quarter for Trinidad, we are basically saying we're going to be just strictly a contract quantities. But we may beat that; we may beat that. And really it's out of our control. We just produce what the national gas company in Trinidad tells us to produce on a day-to-day basis. We are in the position, fortunately, if we have surplus deliverability in Trinidad right now -- in other words, our well capacity is considerably greater than the contract amount -- we can get it on pretty quickly for the government. So we are kind of first in line when they do need extra deliverability.

So I am kind of hoping that we come in and actually beat the fourth quarter in Trinidad volumes for the guidance we've given you. But it is something that we just decided to be cautious on the 8-K for the fourth quarter and give you the contract numbers.

All right. Thank you.

Gil Yang, Citigroup.

Just to follow up on Trinidad, is there any situation where you could be below contract volumes in Trinidad?

We don't -- I guess in an abstract point, is there any situation? Yes, I guess there would be a situation where if we had a pipeline break or some major facility crater or something, we could be there. But in a pragmatic world, we don't have any indication from the government or the gas company there that that would happen. So short of a kind of force majeure situation or something like that, we don't believe that would happen, Gil.

So they are not allowed to come and tell you to produce less than your contract? Or it's take-or-pay, so you get paid for it anyway; is that --?

We have no indications that, for example, in the fourth quarter or 2007 that the government gas company has any intention to undertake the contract quantity.

Okay. If they did, is it a take-or-pay, or do you get less revenue if they do take less?

If they did, it would be a take-or-pay situation.

All right, so you are floored at the contract volume?

Yes.

All right. And Ed made a comment about -- I think Ed made a comment about the terms of those volumes being relatively low margin. Is that -- was that in the context of the overall portfolio or that was in the context of the Trinidad volumes; this is a relatively low margin in the context of Trinidad?

Yes, I think I made that comment. It was in context to the overall portfolio. If you had to basically say we're going to reduce our target, I would much rather reduce the target on the basis of the Trinidad volumes than say on any other volumes.

Okay. How does it compare within the whole context of Trinidad?

In Trinidad, it will be the -- for the fourth quarter it will be about at an average price for the Trinidad volumes.

If I can turn -- I know you want to save the good stuff about the Barnett Shale for a month from now, but since you made a comment about it in the press release I just wanted to ask a question about the spacing in Johnson County. Because you seem to have changed the wording where you had said previously that you would downspace 500 feet between laterals everywhere, and now you are saying just below 1000 feet. So what has changed in the body language there?

Not that much. We are -- in Johnson County, we are basically drilling everything on downspaced acreage. So pretty much every single well we are drilling in Johnson County is being downspaced. And currently everything is being downspaced on 500 foot spacing, which in the context is about 37.5 acres or roughly 40 acres spacing on there. We are still studying whether 500 foot spacing or perhaps 660 foot spacing is optimal, and we're doing reservoir model studies and doing a few pilots on 660 foot spacing versus 500 foot spacing to try and sort out what is best. But at this stage I think the conclusion that you need to take away is that basically everything we're doing in Johnson County is downspaced. So there is, we are not entirely sure, now we are just down to the point of what is the optimum exact spacing that needs to be there, and we will shed some light on that as we get in the meeting. The key points that came out of the press release, those two monster wells that we highlighted there are actually on drilled on the 500 foot spacing. So the interesting points are that where we're getting some of these monster wells are actually in some of the downspace locations, and we wanted to highlight the one well that is in Western Johnson County also because we have run across some sweet spots in the Western half of the county that are generating monster wells. Although the ratio of monster wells is still predominantly in Eastern Johnson County but we are getting some in Western also.

When you have a monster well and you have downspaced it closely to an adjacent well, do you find the adjacent wells tend to be a monster well, as well?

Yes, but -- yes. But I don't want to get too much of the thunder stolen, so I'm going to go mum on you here. We will tell you more on November 29th.

Thanks very much.

David Snow, Energy Equities.

This is getting to be a frustrating call. Can you hear me? What percent recovery do you think you are getting on your 500 foot spaced simultaneous fracs?

We will probably address that in rough times on November 29th, David, but probably not good to try and address that on the call here. It's a complex issue. So we'll just add to your frustration on the call.

Okay. Well, thanks very much.

Leo Mariani, RBC Capital.

Quick question here on your Cotton Valley activities. I know you guys have kind of been aggressively drilling some stepout locations and some exploratory stuff. Just wanted to get an update of what you have been going on and what your plans are.

I assume you're talking about the expanded Cotton Valley stuff over there, which is the more I guess exciting stuff over there in North Louisiana. We continue to develop the existing areas over there, the Driscoll Mountain field and over there in the Eros area. We haven't really tested anything new over and above what we have talked about there yet. So it has been -- we haven't highlighted anything in the press release or so. So I would say it was a quarter over in North Louisiana more like business as usual as opposed to having anything dramatic to report to you.

Anything on the upcoming schedule for the next six months or so that you guys are going to be targeting any structures that you guys have on the seismic or anything?

Yes. We do have one other structure there that we just spud a well on, so we should have some, hopefully we will have some results certainly by the end of the year, be kind of touch and go whether we will by the time the analyst conference arrives. Appraisal drilling going on at Eros and leasing on other structures.

Okay. Any update on the Wolfcamp carbonate play in New Mexico?

It is just continuing. We've got two rigs running in there, and just continuing to reduce our well cost and have continued good results with that program.

Yes I would say that one is just pretty much in the bag. I would say that is 100 to 200 net Bcf development program now, that is just being implemented really. It is a typical well, is IP'd it between 1 and 3 million a day typically, and we are really now just in an implementation mode on it. So we've got the right recipe for the horizontal drilling out there and the right completion practices. I would say it is pretty much routine now.

Okay, any plans in the future for some additional exploration in Trinidad, any wells you guys have slotted to drill?

We've got a rig down there right now, and actually we are doing some basically just development drilling to set up some additional deliverability. It will probably be some time in '07 when I would guess we finish our development drilling there. We will probably have I would say one and maybe one to two exploration wells in '07. But I would say look for a modest level of exploration activity in Trinidad in '07, not a dramatic burst of it. So in both for '07 in both Trinidad and the North Sea it is going to be a I'd say a pretty modest level of activity. In the North Sea it is really going to be a function of can we get a rig window with the extreme tightness of jack up rigs there? If we can get a rig window -- kind of a drive-by deal, we've got a couple ideas that we want to get drilled. But it has really been tough. We've been trying to get a rig window for the last six months and haven't been able to do it. And in Trinidad we may pop down one or two exploration wells. But I suspect most of the highlights you are going to see in '07 from us are really going to relate to our U.S. activities, and that is where you will see most of the focus being placed on November 29th at the analyst meeting.

Okay. Great. Thanks a lot.

David Heikkinen, Pickering Energy Partners.

Just had a question on your property acquisitions, $14 million todate. Do you have larger acquisitions on the properties side? Does that include land, or is that just pure straight property associated with reserves?

That $14 million would have been just pure straight properties associated with reserves, and I think it just gives you a scope, David, for we're talking about spending 2.7 or 2.8 a billion this year and out of that 14 million is a minuscule amount. And it just gives you an idea one, our feeling for the relative economics of buying producing properties relative to our drilling activities. And two, how overwhelmingly organic our production growth is. And I suspect as we look into 2007 whatever our CapEx level is I would suspect the same percentage distribution between organic growth and producing property acquisitions will prevail.

And how much of the 2.75 to $2.9 billion is on leasehold acquisition now?

About 175 million is for the full-year is on leasehold.

Okay, and then I am sure you are probably not trying to steal the founder of the analyst day. Any areas you would highlight that you've been leasing?

Not going to say right now.

Fair enough. I didn't think so. And in the Wolfcamp, can you just remind me that 100 to 200 net Bcf, how many acres do you own there, like how many wells would that be, just trying to get remembrance of that.

35,000 acres and we're probably going to be drilling 50 wells a year here for 2, 2.5 years.

That's perfect. Thanks a lot and I will see you guys at the end of November.

Tom Covington, A.G. Edwards.

Thank you, and good morning. A question on your growth rate for next year ex-Barnett, which is I think 5 to 8%. You were able to sustain some growth this year based on in my view is pretty exceptional performance from the Rocky Mountains. How do you sort of view the distribution of growth as you look at ex-Barnett going into 2007?

The Rocky Mountain piece will continue to be pretty extraordinarily high. I am not sure it is going to be 17% or so, but it will be double-digit growth next year, and we will have production growth in the Gulf of Mexico, not that -- only because the production was so pitifully small this year coming out of there. I would expect that our South Texas growth will be in a range of about 6% or so. West Texas growth will probably be just a small number, perhaps 2 to 3% or so. And our East Texas or our Tyler division growth, which should be pretty significant, somewhere up in the range of 10 to 15% because of this Branton Field, that is the one where we are waiting on the gas processing plant, where we've got the 30 million a day that is basically waiting on the plant. That should be significant. So it will be most heavily coming and Canadian growth will be rather tepid. I would guess it will be 3%, 4% or so. So that gives you a rough idea. I am not sure if all that weighs out to be 5 to 8%. My guess is we're going to be a lot closer to 8 than 5 on a number for next year.

What are your current well costs on the Mesa Verde and the Uinta Basin these days?

Mesa Verde, it is at $1.6 million for this price river wells.

That's just for the Price River?

Aha.

And in terms of just a question on the Barnett what is your current rig count there? I think you said you were going to be at 18 by year end on your prior call.

We're at 14 today; we will be 15 here mid-November, and then we will be adding another couple of new builds here by end of year.

Thank you very much.

John Herrlin, Merrill Lynch.

You had good sequential production growth of natural gas in the U.S. You talked about percentage gains in your release and on the call in the different regions. But if you are going to split it out U.S., non-Barnett, Barnett, what was your sequential gains of second quarter to third quarter, about half and half?

Let us look it up, and from second quarter to third quarter I would guess that -- Maire is pushing some numbers here, so we will give you an exact number. Give us another question here, John, and we will push the numbers when I give you --

With equipment when costs go down you tend to lock in or do term contracts. You've been going to more efficient rigs in places like the Barnett. Chances are you are going to get a rollover here on services cost. Will you do the same sort of thing?

Yes, we've been working on that just in the last couple of months here, John, trying to get locked in certainly through 2007 on our vendor agreements.

Last one for me as Maire calculates away, how about LNG, Mark? You haven't mentioned anything about that in a long time. What is your kind of current view in terms of North America and LNG?

In terms of North America and LNG I think for next year LNG will just be a function of what, how cold a winter it is in the U.S. as far as how much LNG really comes to the U.S. And I guess my current view is you are really looking at 2009 2010 before we get too far out on the LNG curve before it really affects us that much. So to me I still think the most significant thing we've learned this year is that there is just not a lot of -- we haven't grown deliverability in North America as much as I really thought here. Maire has got this calculation done. Maire, do you want to --?

It was over 5% sequentially from the second quarter to the third quarter, and that is U.S. gas excluding the Barnett.

Okay. Thank you.

Robert Morris, Banc of America.

In addition to Trinidad you learned North American Gas got in to it here by about 1%; the Gulf of Mexico $20 million a day in Branton. That was in your outlook last quarter, and Barnett is running ahead of schedule, Rocky is running ahead of where you were last quarter. So the incremental change really seems to be Canada weather delays and I calculate that is probably on the year about $30 million a day. So my first question is is that correct. And you said that everything would be back on schedule by year end so I would expect that Canada would exit the year at around 255 million a day. Is that correct also?

No, I don't think Canada is going to exit the year that high. What we did with Canada, Canada has basically a -- we did slip Canada for the fourth quarter and the full-year in the estimate there from what we had before, and so that just.

That seemed to be the only change other than Rockies and the Barnett being ahead of schedule. So that probably slipped a little bit more than you might otherwise think, too.

Yes, I mean the changes that we really made, the Rockies were a little bit ahead of schedule. We basically slid the Gulf of Mexico completely out of the year as far as we had hoped that we were going to get that infrastructure fixed. That the infrastructure would get fixed; but now we are pretty much pondered and said we don't know when it is going to get done. So those two offset each other and then the Canadian side it just took -- we are basically now assuming that the Canadian stuff is going to slide even more than what we had assumed three months ago in the estimate there.

So the exit rate may be closer to -- I don't know -- I assume 255 but it sounds like a lot lower than that.

Actually Gary is just looking -- if you're saying gas, gas we are saying is 245; equivalents is 255 for December, is what we are -- is what we have in our projection so depending on what you use there. Yes, so basically the two that we slipped down were Canada and obviously Trinidad.

So does that answer your question?

Yes, I guess Canada exit rate then --

Exit rate we are expecting for December on gas alone is 245 for the month of December.

Okay, great. Thank you.

[Sonil Jaguani], Citadel.

Good morning Mark, congratulations on a good quarter. I had a quick question that was a follow up to the question Gill asked earlier about the downspacing. As you've downspaced in Johnson County has that led to a change in the mix of puds that you drilled versus the original plan? Instead of say on book locations?

I'm not sure on the mix of puds. What we know about the downspacing or what we can disclose to you right now is, if we have a suite of so many wells that were in Johnson County on 1000 foot spacing, and I think our website is currently showing -- let me look it up real fast so I don't misquote to you here, the website is saying in Johnson County we have 750 wells on 1000 foot spacing with a reserve a range of 1.8 to 2.4 Bcf per well. And then on 500 foot spacing if we basically are saying we could have another 750 wells, and those 750 foot wells what we have determined is that the reserves per well for those incremental 750 foot wells will be less than the 1.8 to 2.4 Bcf per well. And what we will tell you at November 29th is kind of how much less. But basically it kind of tells us that if we went to 500 foot spacing we could have somewhere roughly in a range of maybe 1500 locations totally. So the downspacing would give you a lot more [pellets] if you will then if you didn't downspace, if I understand your question right.

That answers it. Thank you.

Christopher George, Capital One.

Just a couple cleanup questions on New Mexico. Was that 35,000 net or gross acres?

Net.

Okay, very good, and then that 1 to 3 M's a day, can that be applied to -- was the Hasburg A 35 wells?

I'm not familiar with that well. Which one?

The Hasburg A 35, that is a couple leases on just north of the Savez Eddy County line on the north --

That's not our well.

I don't think that's our well. There are a couple other operators that are kind of to piggybacking on our PR out there, so we are not recommending anybody take our conclusions and apply them to any other E&P companies out there.

Oh, no, I am not thinking of them, I am just trying to --.

Our IP's have been pretty consistent here, though, for the last four to six months.

Yes. That rock quality is very variable and out of our acreage; what we found is there is some of our acreage is pretty good and some of our acreage is pretty weak. So that area seems to have generated a lot of interest because there were some other smaller cap companies out there who have nearby acreage. And we don't know anything about their acreage or their wells. So no comment on that.

Fair enough. I just applied it I guess the wrong well to the company there. Very good. Thank you.

Jeff Hayden, Fischer-Seitz Capital.

Hi, actually Mark Fischer. Mark, could you compare and contrast a little bit at this juncture your strategy versus Chesapeake type strategy where I guess both companies onshore gas, large, bullish on the commodity. And they are so inquisitive, kind of on fear if you don't buy it now, a year or two from now you will be paying a lot more for it, EOG much more conservative on that front. But I assume not concerned that you will be running out of opportunities to drill two or three years down the line. How do you see that?

Is that a loaded question, Mark? I am not sure I completely followed or would purport to be able to try and explain any other company strategy, but our strategy is really based on we are bullish long-term on the commodity. And it is our belief that the future of gas in North America is really unconventional gas, and a big driver of that is going to be horizontal drilling and whether it is horizontal drilling for shales or even horizontal drilling in other kinds of rocks, such as sandstones or carbonates. And we believe that if you kind of scientifically look at it that there are going to be a lot of other opportunities, such as the Barnett Shale to find half a T or Tcf of gas. So our game plan is to kind of do all the science first and then go after the acreage. But to kind of pinpoint the acreage and not try and buy a zillion acres but to kind of get the science done and then go and try and buy the 50 or 100,000 acres that seems to be the best stuff. And to do that without really leveraging the company. So that is why we have really pretty concerned about our relative debt ratio. But the game plan is that we are on is to attempt to double the reserve size, double or triple the reserve size of our North American reserves from the current 4.8 Tcf to a much bigger number over the next three to five years by capturing several incremental of these resource plays. But to do it in what I'd say is a fiscally very conservative manner. So I'll leave it to you to see how that contrasts or comports with other companies.

That's actually very helpful. Thank you, Mark.

David Snow, Energy Equities.

I'm just trying to -- you're thinking about 320s for the spacing in that New Mexico Wolfcamp play?

160's.

Okay and about 1.4 Bcf a well or something?

Yes, 1.2, 1.4.

Okay. Thank you very much.

There appears to be no further questions at this time. I would like to turn the call back over to Mr. Mark Papa for any additional or closing remarks.

I want to thank everyone for listening in today, and again for the questions that we ducked today I promise you we will have responses for on November 29th. Thank you very much.

That concludes today's teleconference. We thank you for your participation, and have a great day.