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EOG Resources Inc. (EOG)

Q3 2007 Earnings Call

October 30, 2007, 10:00 AM ET

Executives

Mark G. Papa - Chairman and CEO

Timothy K. Driggers - VP and CFO

Gary L. Thomas - Senior EVP, Operations

Loren M. Leiker - Senior EVP, Exploration

Analysts

Brian Singer - Goldman Sachs

Thomas L. Gardner - Simmons & Company

Benjamin Dell - Sanford C. Bernstein & Co

David Heikkinen - Tudor Pickering

Robert Morris - Banc of America

Gil Yang - Citigroup

Leo Mariani - RBC Capital Markets

David Snow - Energy Equities

John Herrlin - Merrill Lynch

Ray Deacon - BMO Capital Markets

Joe Allman - JP Morgan

Joseph Magner - Tristone Capital

Richard Tullis - Capital One Southcoast

Jeff Hayden - Pritchard Capital

Presentation

Operator

Please standby, we are about to begin. Good day everyone and welcome to the EOG Resources Third Quarter 2007 Earnings Release Conference Call. As a reminder, this call is being recorded. At this time, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead sir.

Mark G. Papa - Chairman and Chief Executive Officer

Good morning and thanks for joining us. We hope everyone has seen the press release announcing third quarter 2007 earnings and operational results. This conference call includes forward-looking statements. Risks associated with forward-looking statements have been outlined in the earnings release, 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. The SEC permits producers to disclose only proved reserve in their securities filings. Some of these reserve estimates on this conference call and webcast including those for the Barnett Shale and North Dakota Bakken plays and include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our press release and Investor Relations page of our website. An updated Investor Relations presentations and statistics were posted to our website this morning.

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

We filed an 8-K with fourth quarter and full year 2007 guidance yesterday. Do note that our third and fourth quarter 2007 domestic gas production is lower than last quarter's implied guidance. This is entirely due to voluntary curtailment in the Rockies in September, October and partially into November due to low gas prices.

During this period, we have between 50 million and 140 million cubic feet a day of net volumes curtailed on any given day in the Rockies. Press release also includes EOG 2008 production growth expectations under both a $7 and an $8 or higher 2008 Henry Hub gas price assumption. I'll discuss on 2008 volume forecast and business plan when I review operations. I'll now review our third quarter net income available to common and discretionary cash flow and then I will give an operational overview. Tim Driggers will then discuss capital structure and I will close with gas macro comments and a summary. As outlined in our press release, for the third quarter EOG reported net income available to common of $202.4 million or $0.82 per share. For investors who follow the practice of industry analysts who focus on non-GAAP net income available to common to eliminate mark-to-market impact is outlined in the press release.

EOG's third quarter adjusted net income available to common was $195.7 million or $0.79 per share. I'll note that in this quarter we've recognized a write-down of our exploration acreage and wells in the Northwest territories of Canada due to a signed purchase and sale agreement expected to close in the fourth quarter. This resulted in a $0.06 per share after-tax expense. Given the delays and the likely tariff of the Mackenzie Valley pipeline and our mixed drilling results in this area, we decided we have better reinvestment opportunities elsewhere.

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 $724.8 million or $2.93 per share versus $2.75 per share a year ago.

I'll now address our operational highlights starting with our 2008 production growth forecast. Our baseline case assuming $8 or higher Henry Hub prices generate 17% total company production growth.

I'll note that 2008 NYMEX strip is currently $8.22. Our warm winter case assumes Henry Hub gas price averages $7. In the warm winter scenario we don't intend to drill for North American gas at maximum intensity, and we'll reduce our natural gas directed CapEx and gas production growth accordingly to achieve a 13% total company production growth.

In either scenario, there are four items in common. First, total company crude and condensate production is expected to increase 33%, driven primarily by the North Dakota Bakken but also by a shift to more oil projects in Canada and our Mid-Continent operating areas.

Second, we expect essentially flat or slightly declining year-over-year production from natural gas in Canada and our overall production in Trinidad and UK North Sea. So, essentially 100% of the EOG's total 2008 growth will be organically derived from the U.S.

Third, because of tax considerations we expect our Appalachian shallow gas property sale to close in the first quarter. 2008 production growth numbers cited previously are not pro formas. They include the reduction for the Appalachian volumes. Although we haven't finalized the exact 2008 CapEx budget for either the $7 or $8 gas case, taking into account the expected proceeds from the property sale, we expect to keep year end 2008 net debt flat with year end 2007. Therefore, the gross numbers I have quoted are essentially debt adjusted per share production growth.

And fourth, there is little likelihood that EOG will pursue a merger significant acquisition or significant disposition in 2008 other than Appalachia. This is consistent with our belief that organic growth yields intrinsically superior reinvestment rates of return compared to growth through mergers or acquisitions.

Now, addressing CapEx, what's the logic behind our capital allocation? Simply put, the EOG can be considered similar to our high performance engine capable of generating both strong organic oil and gas production growth in 2008 and subsequent years. In 2008 we'll give first priority to oil investments because most of these are 100% reinvestment rate of return. Hence the 33% year-over-year crude and condensate growth.

Regarding our level of 2008 activity, at $8 or higher Henry Hub prices we'll let our high performance engine run at a high RPM and will also generate very strong gas production growth. On the other hand, if gas prices are less robust we'll simply throttle back the gas engine and wait for a more propitious time to put the throttle down.

In the lower price $7 case, we'll focus on our high reinvestment rate of return assets and likely stay very active in the Barnett because of the high reinvestment rate of returns we get in the Barnett and also because of our lease obligation situation in the Barnett.

In this environment, we'd likely throttle back our Rockies and Canadian gas drilling. The key point here is that if 2008 gas prices average closer to $7, we do not intend to increase our debt by drilling excess gas wells. I've covered a lot of conceptual ground with you. For brevity today, I am not going to talk about individual well results but I will cover our two big highlight plays, the Bakken and the Barnett. North Dakota, we've now drilled 22 horizontal wells in our Mountrail County Bakken discovery and the overall results are very consistent with what I reported to you last quarter.

We are generating 100% reinvestment rate of return on this program with a direct finding cost of $7.50 per barrel. We're continuing to add acreage and now have more than 175,000 net acres. This is sweet oil with 42 degree API gravity. We are currently receiving that WTI price less $6 per barrel at the wellhead. The oil is being piped to the Clearbrook Minnesota market area and distributed from there and we don't expect the intrusion of Canadian oil to affect this differential. We expect this $6 deduct to shrink to $3 per barrel when a pipeline tie-in is completed at year-end 2007.

To date we have concentrated our drilling in a small area as we've continued to perfect our horizontal drilling and completion techniques. We've now begun to step up... excuse me, we've now begun to step out drilling to determine the size of this accumulation. Our press release highlighted the Austin #1-02 horizontal well which was a 9 mile northern step-out from our existing production. This well IPed [ph] at 2000 barrels of oil a day and is one of the best producers we've completed in the field.

We've confirmed the Austin results with the one mile offset well, the Austin #2-03H, as I said one mile to the west. We've also completed a step... we've also drilled a stepout well 6 miles to the south of our existing production. The southern well is waiting on completion but we don't expect it to be as strong as the Austin #1-02H. We now believe that this field is at least 20 miles long and several miles wide and we own the vast majority of the acreage underlying this particular area. We've increased our estimate of EOG's net revenue interest reserves on the prior midpoint of 60 million barrels of oil to approximately 80 million barrels of oil. And we believe this number will increase further with additional stepout drilling. The keys to determining the ultimate field size will be stepout drilling and downspacing. This field is analogous to the Barnett in that there is a large number of hydrocarbons, large amount of hydrocarbon in place per section and we only expect about 9% primary recovery with our horizontal wells.

We are currently drilling on 648 acre spacing and we will soon be drilling a pilot well on 328 acre spacing in an effort to better understand the potential to increase recovery. We intend to drill 47 net wells in 2008 with an 8 rig drilling program. This program will be the primary generator of our 33% total company crude and condensate volume increase. And the majority will be implemented at 100% reinvestment rate of return. We expect oil production from this field to continue to increase through at least 2010.

Now I'll switch to the Barnett which will be the big driver of our 2008 natural gas production growth. We expect to exceed our 2007 average production goal of 280 million a day and to exit the year around 350 million a day ahead of our original target.

In 2008, we expect to average 450 million cubic feet a day equivalent in the $7 case and slightly more in the $8 case. I'll note that all of these is organically derived from underdeveloped acreage acquired at very low relative prices since we were early movers in the play. This asset continues to perform very well as you can see from our 2008 production target. So I don't think I need to recite any specific monster well this quarter. I will note that I believe a 450 million cubic feet a day 2008 average rate is quite impressive when you consider this is 100% organic and EOG is the only large cap company that has grown in the Barnett with no acquisitions.

We've now begun to implement an additional Barnett cost reduction measure, which is significant to our economics. These cost reduction measures are important because we still have a multi-thousand wells drilling inventory in the Barnett, two largest cost components of this project are the drilling and fracture treating costs.

We've previously disclosed how we've reduced drilling costs using the automated rigs to reduce the number of drilling days. The second phase of cost reduction is on the frac side and we've now begun this implementation. We recently purchased our own sand mine for frac sand and we are contracting with a pumping service company to pump the fracs using our own sand.

Under this new arrangement, we estimate this will save $350,000 per well versus contracting with the major service companies for a frac. We will be able to use this equipment for about 35% of our Barnett fracs. So the effective per well savings will be $125,000 per well if you attribute that across all of our Barnett wells. But it will actually be $350,000 per well on the wells that we've applied this directly to. Combined with the drilling rigs, we believe this provides EOG with a discrete discernible cost advantage versus other operators in the Barnett. The full impact of both the drilling rig and fracture treating cost saving elements would be realized beginning in the first quarter of 2008.

As I mentioned, we'll likely implement a high level of Barnett activity next year, somewhat independent of the gas price within a reasonable range because the play yields high RORs even at $7 gas and because of our ongoing lease commitments. For brevity, I won't mention any specifics regarding other North American plays except to say that through the first nine months of this year, our North American ex-Barnett growth is 5.8%, essentially spot on our 6% target. And we expect a high level of growth likely between 5% and 8% depending on gas price from this area again in 2008. We expect particularly strong 2008 growth from our Rocky Mountain, Mid-Continent, East Texas and South Texas areas.

Now I'll briefly turn to Trinidad. During the third quarter, we again exceeded our contract takes. In 2008 we expect our sales to be essentially flat with 2007. The next Trinidad production uptick will occur in late 2009 when deliveries increase under the methanol 5000 contract and again in early 2010 when sales from our Block 4A field increase by about 60 million cubic feet a day net.

I'll now turn it over to Tim Driggers to review CapEx and capital structure.

Timothy K. Driggers - Vice President and Chief Financial Officer

Thanks Mark. For the third quarter, total exploration and development expenditures including asset retirement obligations were $945 million with $1 million of acquisitions. Capitalized interest for the quarter was $7.7 million. year-to-date, total exploration and development expenditures including asset retirement obligations were $2.772 billion with only $2.4 million of acquisitions.

At September 30, total debt outstanding was $1.283 billion and the debt to total cap ratio with 16%. At quarter-end, we had $302 million of cash on the balance sheet. The effective tax rate for the quarter was 36% and the deferred tax ratio was 91%.

Yesterday we filed the Form 10-Q for the third quarter and a Form 8-K with fourth quarter and updated full year 2007 guidance. For full year 2007, the 8-K has an effective tax range of 34% to 37% and a deferral percentage of 80% to 100%. The CapEx budget for the full year 2007 is approximately $3.7 billion.

Now I'll turn it back to Mark to discuss the gas macros and concluding remarks.

Mark G. Papa - Chairman and Chief Executive Officer

Thanks Tim. Regarding the North American gas macro, I am certainly more bullish than many people regarding 2008 prices. I believe 2008 domestic supply will grow 1.8%, Canadian supply will fall at least 4% and the LNG imports will be up only about three-tenths of a Bcf per day year-over-year.

This is essentially flat year-over-year overall North American supply picture. Regarding domestic supply there seems to be a lot of concern about Independence Hub and some unquantifiable pent-up Rockies supply that will be unleashed when the Rockies Express pipeline opens up January 1st. The offset to the Independence Hub ramp-up is the current Gulf of Mexico gas rig count which has dropped precipitously from 85 to 61 rigs this year due primarily to current negative shelf economics.

Because of the high Gulf decline rates, the impact from this drop in drilling activity will likely offset Independence Hub volumes within six to nine months. I personally think the Gulf of Mexico rig count drop is a very significant item, and that it is a harbinger of a longer term low rig count in the Gulf of Mexico shelf as more shelf rigs migrate to the Arabian Gulf and other higher price venues.

Regarding pent-up natural gas supply to be unleashed by rigs in the Rockies, I think the volume increase if any will be very small. Using the supply assumptions I've quoted I believe 2008 gas prices are likely to be more robust than 2007 depending of course on the winter weather intensity.

Our 2008 gas hedge position was articulated in yesterday's 8-K. We currently have 260 million cubic feet a day hedged for next year, at an $8.55 MMBtu average price. As a percentage of North American gas, we are currently about 18% or 19% hedge for '08 depending on which growth path we elect.

As I reported in last quarter's call, we will likely continue to add to our 2008 hedge position, market permitting. Regarding oil, we have no 2008 hedges and are less likely to hedge while the market is in backwardation.

Now let me summarize. In my opinion there are five important points to take away from this call. First, we have a flexible CapEx plan that will provide 13% to 17% debt adjusted per share production growth in 2008 depending on natural gas prices. I'll also note that we've increased our expected long-term growth estimate from average of 9% per year to an average of 10% per year for 2009 through 2011.

Second, our year-over-year crude and condensate production growth is targeted to be 33% in 2008 and will be generated primarily by investments yielding 100% after-tax rate of return.

Third, the bulk of our 2008 production growth will be generated from the Barnett which will yield a 40% to 90% reinvestment rate of return after-tax depending on the gas price. Because the bulk of our total investments will generate a very high reinvestment rate of return we expect to continue to generate one of the highest return on capital employed in the peer group.

Fourth, we expect to achieve the 13% to 17% total organic production growth without increasing 2008 net debt. That would put us on a track to maintain a mid-teens net debt to total cap throughout 2008 providing lots of balance sheet conservatism and flexibility.

And fifth, all of this growth will be generated domestically. So the political or creeping expropriation risk is much lower than with other growth stories. Thanks for listening. I will remind you that our 2008 analyst conference is February 28 in Houston and now we will go to Q&A.

Question And Answer

Operator

Thank you. The question and answer session will be conducted electronically. [Operator Instructions]. And for our first question we'll go to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you good morning.

Mark G. Papa - Chairman and Chief Executive Officer

Good morning, Brian.

Brian Singer - Goldman Sachs

On the Bakken play any initial thoughts on well communications at EURs as you start to pilot the 320 acre downspacing?

Mark G. Papa - Chairman and Chief Executive Officer

No I mean not so not any initial thoughts, we... our belief is that it is somewhat analogous to the Barnett in that the initial recoveries we're getting of total oil in place, in this case, it's oil of course, are very low. And it's our belief that give us sometime and we'll find a way to improve recoveries and certainly one way to improve recoveries is to have more intense spacing of wells and while we're talking in Johnson County of going to 40 acre spacing. In this case, the concept will be 320 acre spacing. So we will be drilling our first pilot well here within a month in the 320 acre spacing, and seeing how that turns out. It will probably be a kind of iterative process and it will probably take us, I would say about six months to get an understanding of 320 is the proper way to go or not. So it's not going to be a magic bullet where we drill one well Brian and say Eureka it works or it doesn't work.

But as I said our feeling on the overall play is that we think the play is probably going to be bigger in terms of size, in terms of how many miles long and how many miles wide, it is as we do more stepout drilling. So we think the play will likely get bigger that way and then we also think that in terms of how much oil or what percent of oil in place we will ultimately recover that we'll find some way to get that 9% up to a more robust number too. So there are two ways we think the ultimate recoveries will grow.

Brian Singer - Goldman Sachs

Thanks. And I guess secondly when you look at the swing in the 13% to 17% growth target for next year and essentially it sounds like Barnett is relatively flatter. There is a little of variability, Bakken is flat... it is fixed in terms of growth. On your various other plays could you talk to where you plan vary? Especially I guess ostensibly in the Uinta Basin.

Mark G. Papa - Chairman and Chief Executive Officer

Yes, Uinta Basin is one of the bigger swing plays. The Uinta is one that we can throttle down or ramp up. The advantage we have in the Uinta Basin is, we don't have any lease expiry deadlines or anything like that. It's all held by production. So if I had to pick one single area that would be our area where... would be our biggest lever to move up or down, it would be the Uinta Basin. But the leverage we'll also... that this other swing area will be Canada, as to how many shallow gas wells drilled in $7 versus $8 gas. But it will also occur in other divisions such as the South Texas to Mid-Continent area, East Texas area. But the single biggest player would be likely the Uinta Basin Brian.

Brian Singer - Goldman Sachs

Should we think then that the Uinta Basin needs 750 gas to be economic?

Mark G. Papa - Chairman and Chief Executive Officer

No it's... I mean the thing about it is, it flies at $7 gas, but it's just a case of do we want to run every single part of the company at maximum intensity, if we are seeing an oversupplied gas market, which would be the sign... if gas is $7 we basically are seeing an oversupplied gas market. So it's more of a case of do we want to further contribute to an oversupplied gas markets by pouring more gas onto that market. And so it would be basically a sign where EOG says we have already got an oversupplied market, do we in areas where we have the flexibility to just delay drilling, do we really want to create more supplies such as in Uinta Basin? Our answer would probably be... we're probably not going to push it that hard in '08.

Brian Singer - Goldman Sachs

Thank you.

Mark G. Papa - Chairman and Chief Executive Officer

Yes.

Operator

And for our next question we will go to Tom Gardner with Simmons & Company.

Thomas L. Gardner - Simmons & Company

Good morning guys. Mark, with respect to guidance, does your low end of 2008 production guidance imply a flat rig count?

Mark G. Papa - Chairman and Chief Executive Officer

I would say generally a flat rig count to where we're running now yes that's a pretty good direction. Yes we are running about 70 to 75 rigs right now. And to grow with the 13% we would probably keep it at relatively flat rig count, yes.

Thomas L. Gardner - Simmons & Company

So with respect to the Barnett then if you keep your rig count flat, at what point do you see the decline rate offsetting the positive production, impact of horizontal drilling?

Mark G. Papa - Chairman and Chief Executive Officer

The trick on... I always caution people Tom on using a rig count particularly in the Barnett because what happened is we are shifting a significant amount of our fleet from these conventional rigs to these automated single rigs, and we get more wells drilled with the same rig using this automated single rig because we are drilling them faster. So... we are getting more real wells drilled, say using 20 rigs than we were using 20 rigs a year ago. So it really boils down to more the well count. I mean what I give you is in our $7 case for the Barnett in '08, we intend to drill 350 wells, in the $8 case, we intend to drill about 415 wells.

Thomas L. Gardner - Simmons & Company

Okay and those drilling...

Mark G. Papa - Chairman and Chief Executive Officer

It's dangerous using how many rigs that you plan to use.

Thomas L. Gardner - Simmons & Company

Yes kind of... and the incremental I guess benefits not coming from rigs, is coming from what? Better stimulation techniques?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, I mean what differentiates us I believe from the other producers in the Barnett is, I continue to believe that we are getting better productivity per well and better reserves per well than likely the rest of the players in the Barnett. And we have used Railroad Commission data and other data particularly in Johnson County to get comparisons for that and our initial production rates per well appear to be anywhere from 30% to 50% better than pretty much the rest of the other companies up there. And we just believe we have more efficient completion technique that we don't disclose exactly what we will do. But I think the fact that we are talking about 450 million cubic feet a day next year, and we have made zero acquisition in the Barnett speaks for itself that we are the only the one to be generating that kind of production without making multi-hundred million or in many cases multi-billion dollar acquisitions in the Barnett. And it's because we are getting better well I believe.

Thomas L. Gardner - Simmons & Company

Got you. Given jumping over to the Bakken and given your recent success there focusing on growing liquid production. Can you give us some color on your recent view between the relative value gap between oil and gas? Do you see this changing over time and what are some of those drivers?.

Mark G. Papa - Chairman and Chief Executive Officer

Wow, yes, that's a tough question Tom. I personally believe that this value gap of close to a 2 to 1 BTU pricing disparity, I don't think it can last, say 5 years duration. But I think it can certainly last the next several years but I think long term people will find a way to make that gap converged by getting ways to utilize gas, where they are currently utilizing oil. But my sense is that over the next year, we will see some convergence between gas and oil, and I don't think it's going to be with seeing oil prices come down significantly. I don't think the convergence is going to come in that method. So I think the convergence and I'll just call it directional convergence because I am not saying they're going to converge in the next year or two. But I think directionally we will see gas prices move upwards.

But my sense is that if we have a winter that is a reasonable winter... like a 10-year average or 30-year average winter that we could see a startling surprise in natural gas prices this winter to the upside. So our... we could be... although we are hedging some gas, we will not be the kind of company that ends up hedging 50% of our gas or anything like that. The upper limit on our hedging might be 30%-35% as we currently see it. Because we think it is certainly possible, you could have a $9 Henry Hub price for calendar year 2008. That would not surprise me at all. All you would need is a winter that tends toward a somewhere between the 10 and 30 year winter and I think $9 a gas is pretty well assured in my opinion.

Thomas L. Gardner - Simmons & Company

Thanks Mark. That's very helpful.

Operator

And for our next question we will go to Benjamin Dell with Bernstein

Benjamin Dell - Sanford C. Bernstein & Co

Hi Mark.

Mark G. Papa - Chairman and Chief Executive Officer

Hi Ben.

Benjamin Dell - Sanford C. Bernstein & Co

I wonder if you could just give us some clarity on your assumptions around sales for the Appalachian. What sort of price range or maybe if you can't say that what sort of volume in terms of at 2P reserves you are looking to sell?

Mark G. Papa - Chairman and Chief Executive Officer

Yes. Gary Thomas you want to field that?

Gary L. Thomas - Senior Executive Vice President, Operations

Our PDP reserves there are somewhere around 200 to 250 Bcf.

Benjamin Dell - Sanford C. Bernstein & Co

Yes, right. Mark a follow-up question on the hedging. Sort of commented that you believe at least some convergence is likely. Doesn't that suggest you should be hedging the oil and not hedging the gas rather than the other way around?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, you could build case for that Ben. You could go crazy trying to figure out what it is. I mean I could go crazy trying to figure out what it is on there. In terms of things but yes there is some logic to what you say. I mean the way we view the natural gas market is, it's pretty much just the weather bet this winter. If you have... if we have a warm winter, gas prices could easily be $7 and if you have a winter that tends for the 30-year winter I think it's, in my mind it's pretty well a lock, you're going to have gas prices that will average $9 for the calendar year. And so, it's just kind of what we believe the weather, winter weather is going to be.

So we just kind of said, since it is the weather bet we'll... if we can hedge gas around the 850 price range and hedge perhaps 30% of it or so that's probably a comfortable position to be in. But I do believe that if you got a reasonable winter that we all will be surprised by the upside strength of the... how much the gas price moves up. On the oil side, I just believe that our own opinion is that while there might be some emotion in the oil price today certainly I just believe that you got worldwide demand it's 86 million barrels a day and you have worldwide capacity today it is 88 million barrels a day. The IDA is forecasting in five years that demand is likely to grow by 10 million barrels a day and I just don't believe that the world, the industry can grow supply by 10 million barrels a day in five years. And so I just think we have a perpetually tight supply-demand scenario unless we have a global economic slowdown. That is my call.

Benjamin Dell - Sanford C. Bernstein & Co

Great. And maybe I could just get back to one last question on your businesses. Canada and the UK last year when you looked at year-end data [ph] they seemed to under-perform your U.S. business. You seem to have much more focus on obviously the Barnett and the Bakken this year. Do those businesses still fit with your core areas of... are they positions that you believe over the long-term you will be reducing as a percentages of portfolio, or even getting out of?

Mark G. Papa - Chairman and Chief Executive Officer

Likely not, certainly not Canada. We think there is a lot of opportunities out there and certainly one of them would be, shale gas opportunities with horizontal drilling. And so, and we've already made comments in the past that one of our potential growth opportunities there that we are pursuing is indeed shale gas in Canada although we have been rather vague about where. And in the UK, we are just trying to figure out what the real gas price is over there. Currently it's back up to $10. So we think there are growth opportunities, although we basically, we are... as you see we haven't really mentioned it on the earnings call. We really just have muted growth expectations for the next several years there. But certainly for the next year or two we do not have any intention of selling our position in UK.

Benjamin Dell - Sanford C. Bernstein & Co

Okay. Great, thank you.

Operator

And for our next question we will go to David Heikkinen with Tudor Pickering.

David Heikkinen - Tudor Pickering

Good morning and good guidance for next year, it's pretty positively received. But comments and questions not giving details on CapEx but talking about activity levels with an assumption of 13% growth gives you a flat capital budget be reasonable year-over-year?

Mark G. Papa - Chairman and Chief Executive Officer

Yes David, the reason we haven't given any details on the CapEx is we haven't finalized the number down to the nearest $100 million, and we really don't want to give guidance and then where we to change in three months by $100 million to have some sell-side analysts criticize us by... that we already changed it by $100 million plus or minus before the year started. It doesn't take a lot of mathematical skills from the guidance that we have given you here to work back and figure out what CapEx would be under either scenario there to come out with a flat net debt.

David Heikkinen - Tudor Pickering

And I guess on up CapEx would be because net of the Appalachian sales for our methods $500 million to $750 million of incremental CapEx to get the high end growth numbers is kind of the way you are leading us to keep net debt flat by the end of the year, does that... make sure I am capturing that accurately?

Mark G. Papa - Chairman and Chief Executive Officer

Yes and I am not going to give any...

David Heikkinen - Tudor Pickering

Okay.

Mark G. Papa - Chairman and Chief Executive Officer

Guidance but it's basically... it's not that hard to come up with those.

David Heikkinen - Tudor Pickering

If wecan do it I guess any body can. So the part of rig count and activity levels you kind of detailed $7 gap $8 gap Barnett number of wells you've given Bakken number of wells. Can you talk about the number of wells in other regions, Uinta in Canada and Mid-Continent that's the $7 and $8 gas price case?

Mark G. Papa - Chairman and Chief Executive Officer

Yes probably not specifically at this stage. We will be able to hear by the end of the year or at our analyst conference on five divisions on air. But I would say directionally it would be relatively flat with this year is a 13% case and probably up a bit at 7%.

David Heikkinen - Tudor Pickering

Okay.

Mark G. Papa - Chairman and Chief Executive Officer

Which is all I can give you this time but not a specific well count number there David.

David Heikkinen - Tudor Pickering

Okay. And then comes the final question on Appalachia could you give the production associated there as well?

Gary L. Thomas - Senior Executive Vice President, Operations

17 million a day.

David Heikkinen - Tudor Pickering

Okay, and that I guess on the 200 and 250 Bs PUD percentages?

Gary L. Thomas - Senior Executive Vice President, Operations

I don't have those numbers I don't think and majority of this is going to be proved producing and I would guess it's probably going to be somewhere around 25% to 30%.

David Heikkinen - Tudor Pickering

Okay. And then just one final question Mark whenever you said the range on your acreage I had my notes that the Bakken is 20 miles long and did you say several miles wide or 7, I just wasn't sure if it was 7 or several?

Mark G. Papa - Chairman and Chief Executive Officer

Yes I said several miles wide.

David Heikkinen - Tudor Pickering

Several, okay. Just couldn't hear it quite right. Thanks guys.

Mark G. Papa - Chairman and Chief Executive Officer

Yes.

Operator

For our next question we'll go to Robert Morris with Banc of America.

Robert Morris - Banc of America

Good morning Mark.

Mark G. Papa - Chairman and Chief Executive Officer

Hey Bob.

Robert Morris - Banc of America

On the capital spending guidance for next year you'll give that out when?

Mark G. Papa - Chairman and Chief Executive Officer

Yes it's probably either at the next earnings call or I would guess is when we give that out.

Robert Morris - Banc of America

Okay. In the $7 gas scenario I would assume that your deferred tax continues to run at about 80% that I know that moves down as the gas price moves up. So in modeling all that what would you assume is the deferred tax rate in the $8 case?

Timothy K. Driggers - Vice President and Chief Financial Officer

This is Tim. It's going to be in that same range because of the high IDC we have going into that program. In the $7 case we're likely to get into an odd man position which we won't have in the $8 case. So that would be swing variance there.

Robert Morris - Banc of America

So in that swing variance on the 13% case still 80% deferred tax higher?

Timothy K. Driggers - Vice President and Chief Financial Officer

In that range the 80 to 100 range.

Robert Morris - Banc of America

Okay. Quickly on the incremental looks like 45,000 acre plus of acreage you bought in Bakken, what is the pricing going for on that acreage Mark?

Mark G. Papa - Chairman and Chief Executive Officer

I'd say roughly about 200 to 300 bucks an acre is what we pay for that incremental acreage. I'll just note, I mean we are saying greater than 175,000 acres. We try to be sly on that stuff, I mean we've got... we're trying to camouflage our acreage position, we've got more than that.

Robert Morris - Banc of America

Okay. How much did you pay for your sand mine? Is there and also is there an operating cost that will show up in LOE or line item for that going forward?

Mark G. Papa - Chairman and Chief Executive Officer

No it will... now I and Garry discussed the sand mine and the fracs because it's probably worth discussing but it will all show up as it will come through the DD&A line, it's not an operating cost side. I mean it will be part of the well completion cost or that well cost.

Robert Morris - Banc of America

And how much did you pay for the mine?

Gary L. Thomas - Senior Executive Vice President, Operations

We've got a 1000 acres here in Hood County and it's adjacent to the Unema [ph] mine and we paid $500,000 for the lease and essentially the same with the oil and gas lease. We have control of that as long as we are mining, and we spent... we are going to be spending somewhere around $15 million to have everything functionable and we'll start using sand there in December.

Robert Morris - Banc of America

Okay. Right.

Mark G. Papa - Chairman and Chief Executive Officer

Go ahead Gary.

Gary L. Thomas - Senior Executive Vice President, Operations

And the thing that we have looked at here is about the half the completed well cost is on the drilling side and about half on the completion and that half of the completion is a stimulation portion, and about half of our stimulation is the sand. With those owning the sand then there is a tremendous reduction here in the cost of that. Probably somewhere $0.02 per pound versus cost of service companies somewhere around $0.08 per pound. So, that's where a large part of the savings comes in. And of course that's a fraction of how much sand we use and we will continue to use more sand for the work. Per well is per completion. That's how we get the $350,000 savings per well.

Robert Morris - Banc of America

Okay. Yes that's helpful.

Gary L. Thomas - Senior Executive Vice President, Operations

Okay.

Robert Morris - Banc of America

Thanks. That's all I had. Thanks.

Operator

And for our next question we will go to Gil Yang with Citigroup.

Gil Yang - Citigroup

Just follow-up on sand a bit, why are you limited to only about 30 wells with just how close they are to the mine?

Gary L. Thomas - Senior Executive Vice President, Operations

Gil the reason for that right now is, we are going to have 3 frac spreads that we have contracted and we'll just be able to get about a third of our wells completed with those three frac spreads. Now once we get the sand, the sand mine operating and see that we can produce more sand than those three frac spreads can utilize. We have got other service companies that are interested in using EOG's sand which will be also a cost savings to EOG.

Gil Yang - Citigroup

So would that appear in offset to DD&A?

Gary L. Thomas - Senior Executive Vice President, Operations

Yes potentially.

Gil Yang - Citigroup

Okay.

Gary L. Thomas - Senior Executive Vice President, Operations

That will reduce well cost and that of course what we work at, in all cases going back to... yes half our cost is on the drilling side. Large portion of that is a rig so that is why we went to the automated rigs and then we look at the other part of that equation that being the completion and what we can do to improve our efficiency and lower our costs on that side as well.

Gil Yang - Citigroup

All right. Mark a couple of questions for you regarding the acceleration and deceleration activity. How much... maintenance and activity in the Barnett is from lease expiration issues versus just the strong economics, and conversely for Uinta, it sounds like you don't have the lease expression issues but is there economic issues? Economically it's not as strong as the Barnett so that's why you would chose that area to tune that activity a bit?

Mark G. Papa - Chairman and Chief Executive Officer

In the Barnett... most of those leases we have are generally, three year leases with two year extensions. But for example, if you want to extend those leases for two additional years, you basically have to pay the same price that you pay to get the lease to start with. So the economic decision you make is to do I drill on those leases or do I pay, the same amount of cost, maybe get the lease in first place. So, it kind of drives you say let's... since I get a good rate of return anyway, why don't I just keep the activity to level up in the Barnett. So you are driven there, pretty strongly to keep up fairly activity level. In the Uinta Basin, you have quite high rates of return, basically even at $7, you get about a 30% to 50% reinvestment rate of returns. So if you were... if it was purely on economics alone, we would drive a very high activity level in the Uinta Basin in 2008 and go for probably higher than a 13% growth rate. The dilemma that you have is the lease that I see is, why should we be pouring more gas on a market that apparently would be supply long if we were in a $7environment, and stressing our organization's limited personnel even farther. So it's not a case where we, you're going into an economic distress situation at $7 in Uinta you still have very nice economics, but it's a more a case that I am not sure we want to... just fled the market with more gas, it's a market that needs any more gas.

Gil Yang - Citigroup

Okay, fair enough. For the Barnett, if you are drilling out more... and if you let your activities being driven by lease... drilling up leases, will we see any change in the quality of the well that you are drilling to more peripheral areas and will there be a mix shift there?

Mark G. Papa - Chairman and Chief Executive Officer

No, not that we see really. I mean it's still going to be very, very good. I mean we are blending what we will be seeing over time as you see more of the West and more of the Southern extension stuffs about getting gradually blended in Johnson County and that's where they frac stuff that Gary detailed for is important because if you save significant amount for oil out there in the West, it really helps your economics out there because there it's more of a cost driven play. But no you really won't be seeing major shift in mix.

Gil Yang - Citigroup

All right. And last question I have got is, with your capital spending variability depending on the gas price, will there be any change to your sort of exploration activity to search for new shales or whatever else?

Mark G. Papa - Chairman and Chief Executive Officer

No, absolutely not. We still have our ongoing focus in activity for new unconventional plays and the key focus on that is horizontal drilling. All the unconventional plays, unconventional fields we are looking at are the key thing areas, all of them that we are looking involves horizontal drilling. And so that is still a very heavy focus of the company and we keep very, very quiet about those plays. I mean the most recent example we have is obviously the Bakken of a successful one. And when we get one ready and set up and have all the acreage captured then we will talk about it such as the Bakken. But until then you will hear as close to zero news about it as we will, as we can possibly give you. But the emphasis within the company is still very, very heavy on that.

Gil Yang - Citigroup

All right. Thank you.

Mark G. Papa - Chairman and Chief Executive Officer

Okay.

Operator

And for our next question we will go to Leo Marianiwith RBC.

Leo Mariani - RBC Capital Markets

Yes just a quick follow-up question for you folks on the Bakken. Trying to get some sense of sustainability of the production here. I guess one of the wells you had come on around 1900 barrels a day at the end of September trying to get a sense what that well is doing today?

Mark G. Papa - Chairman and Chief Executive Officer

Yes the wells have come on and they have a decline rate it's... I mean just to tie it into it. It's somewhat similar to the Barnett Shale in that the wells come on at high rates then they have a fairly high decline and then they will settle out and they will last for 15 years or so. I would say approximately 15 years. And a typical well will come in at say 1800, 2000 barrels a day and then after a few months it will settle down at probably about 500 or 600 barrels a day. So we don't want to mislead you and think that like this Austin wells as highlighted in the press release came on at 2000 barrels a day. It doesn't stay at 2000 barrels a day for a long time. It will decline fairly rapidly. But it is very similar to the kind of like the monster wells at Johnson County. What happens is you capture a significant amount of high rate production in the first year and it generates a reinvestment of rate of returns of 100% very easily and then what you end up with is kind of a long life well that produces between a 100 and 200 barrels of oil a day for many, many, years. But as you are aware of the finding cost as we quoted with is about $7.50 and obviously if you are selling this stuff for 80 to 90 bucks a barrel we'll, pretty obvious what the profit margin is.

Leo Mariani - RBC Capital Markets

Okay. Could you give us a little more color on your assumption in 80 million barrels recoverable math? I guess about this, just kind of do some quick math and use 640 I think that applies, if you want to use kind of the 700,000 barrel per well, it kind of applies around 40% of your acreage is going to be good. Can you give us any color around what you are thinking?

Mark G. Papa - Chairman and Chief Executive Officer

Yes as we continue to drill we are trying to define the size of the sweet spot. We know there is a large oil accumulation in this eastern part of the Williston Basin in the Bakken. The question is how much of it is going to be a 700,000 barrels per well, how much of it is going to be a little bit less than that is still economic. You probably recall at our annual conference last year we first announced this thing at 50 million barrel as our mid point that's after drilling 4 wells. At the end of about mid summer we drilled I think 13 wells, we have that 60 and today we are showing 80 as our midpoint after drilling 22 wells. And that also means that we have added leasehold during the timeframe of course that we have extended sweet spot nine miles north. Parshall area itself is probably about six or seven miles long and three, four miles wide. So we know now that the sweet spot where we can get this 700,000 barrels net per well is of the substantial size.

Now how we actually get to the 80 million barrel number we are assuming 640 spacing and we are assuming that 700,000 barrels per well, but only in this what I would call the sweetest of the sweet spot the core sweet spot. But then outside of that which includes a percentage or a proportion of our 175,000 acres we are anticipating halos of lesser reserves per well. And what we doing is just kind of modeling 80 million barrels what we would consider a very safe number to date. And if you just use your math 175,000 net acres at 273 net locations you would only need, less than 300,000 barrels per well net to get that 80 million barrel number. So how you mix that up... having mix up your calculation determining how much of that is ultra sweet and how much of it is just relatively sweet, that's the part we're really not willing to say more about today. But we think we have a handle on that and we are gathering it more specific in definitive handle on that as we drill our step-out well.

Leo Mariani - RBC Capital Markets

Okay. So you folks are obviously gradating your acreage here into sort of the bucket for lack of a better word. I guess are you guys also applying some risk assessments to that to get to the 8 million barrels, is that more sort of a risk number in your estimate?

Mark G. Papa - Chairman and Chief Executive Officer

Yes we are raking our acreage to get to that 80 million barrels, yes.

Leo Mariani - RBC Capital Markets

Okay. Just one final question for you gentlemen on sort of Trinidad in UK, you talked about flat to slightly down production 2008. I guess if I just kind of sort of eyeball the trend that we've seen in the past couple of quarters looks like we have seen some declines a little bit in those areas. And I was just trying get a handle on it if you thought you had some incremental volumes in '08 in the UK or you thought there was a change that you're going to producing above contract level in '08, there and Trinidad?

Mark G. Papa - Chairman and Chief Executive Officer

Yes what... we just put up on our website this morning I believe the numbers are that we expect the UK, Trinidad to add this year to produce 300 MMcfe next year those two to produce 290 MMcfe. The assumptions there... the assumptions are that we just have a natural decline in the UK which is by far the much smaller component of that. And I believe that's very, very likely to what will happen because we don't have any new production that's likely to come on there. And then the assumption in Trinidad is that we will be limited to our contract takes. There is a possibility in Trinidad that that we will again have contract overtakes but we would guide you to just the contract takes them out. So the 13% of the 17% production growth, having handle in there that we just are limited to contract takes in Trinidad trended and that we basically go from 300 to 290 in both cases the 13% and 17% in volume from those two entities next year.

Leo Mariani - RBC Capital Markets

Okay. And how many rigs do you guys run in the Barnett right now?

Gary L. Thomas - Senior Executive Vice President, Operations

There are 23.

Leo Mariani - RBC Capital Markets

Okay. Thank you very much for your time.

Operator

And for our next question we will go to David Snow with Energy Equities Incorporated.

David Snow - Energy Equities

Yes hi I wondered if there is anything new or any way to give us a color on what's happening in the Wolfcamp, New Mexico.

Mark G. Papa - Chairman and Chief Executive Officer

There is really not a whole lot new in the Wolfcamp, New Mexico I mean we are running a couple of rigs out there and have decent results. And, it's just supportive play, for our West Texas division and that's all we have ever painted it as being, and that's exactly what it is, it's just a supportive play and things are going fine there.

David Snow - Energy Equities

Okay. Thank you very much.

Operator

And for our next question we will go to John Herrlinwith Merrill Lynch.

John Herrlin - Merrill Lynch

Yes hi, a bunch of them. With the sand are we talking kind of uniform face sizes or are you going to actually sort the sand in all that for your fracs in the Barnett?

Gary L. Thomas - Senior Executive Vice President, Operations

Oh, yes, we sort and we are using the same mesh sizes. The mine has the same mesh size as what we have been using for the last year.

John Herrlin - Merrill Lynch

Okay. Great, given the new sands that fit for purpose rigs or fracs etcetera what's your average completed well cost?

Gary L. Thomas - Senior Executive Vice President, Operations

Well, the average, it ranges anywhere from $1.4 million to probably $3.6 million depending where we are John. So yes the average might be 2.5.

John Herrlin - Merrill Lynch

Okay. A switch into the Bakken if you started one of this horizontal wells January 1st, what would you average about 220-250 barrels a day per year?

Gary L. Thomas - Senior Executive Vice President, Operations

It will be higher than that John, because these wells after several months still 600 barrels a day. Most often that we have I would say it's going to be ramped 350 barrels a day.

John Herrlin - Merrill Lynch

Good, that's what I wanted to say. That's fine. Completed well cost how much are they running in Bakken?

Mark G. Papa - Chairman and Chief Executive Officer

We are listing them in the IR presentation at about $5.2 million right now, but we are likely within six months we will probably be showing lower numbers than that. We are driving it to down pretty well but use 5.25 million right now.

John Herrlin - Merrill Lynch

Okay. Regarding the sweet spot that was discussed by Loren, are we talking geologic or fracturing related type stuffs and so that seems to be very narrow band, can you give more information Loren?

Loren M. Leiker - Senior Executive Vice President, Exploration

Relatively John I can give you slightly more information. I think what we said before is that these sweet spots are both controlled by tectonics or fracturing and by stratigraphy. And so I mean obviously we now believe we have extended the sweet spot all the way from Parshall into the Austin area in nine miles north, that's not a very linear sounding box. So which of the two are the most dominant fracturing or stratigraphy? That so we are not really going to comment anymore today but I would just say that both are involved.

Mark G. Papa - Chairman and Chief Executive Officer

Yes that's about a 20 mile long sweet spot, John. That's not very small.

Loren M. Leiker - Senior Executive Vice President, Exploration

And Parshall is about 6 or 7 miles wide. So talking 20 by 6 or 7 there.

John Herrlin - Merrill Lynch

Yes I just heard that there was a decent structural component. Okay.

Gary L. Thomas - Senior Executive Vice President, Operations

John let me mention one thing here. Looking at some of the early wells that came on a year ago and the rate is one of them came out 1800 barrels a day, current production 415, and that's what I was addressing. By the end of the year we'll be making about 350 barrels oil per day.

Mark G. Papa - Chairman and Chief Executive Officer

And so yearly average you are probably talking about, I would say maybe 600 or so.

John Herrlin - Merrill Lynch

Yes.

Mark G. Papa - Chairman and Chief Executive Officer

Yes.

John Herrlin - Merrill Lynch

Okay. Good still I one I wanted to get to. Last one from me, I guess is the new royalty framework in Canada obviously you've heard about it. Does this mean perhaps in 2009 that you will consider backing off more in terms of long-term activity in Canada or switch to other plays like you mentioned with shale plays over towards BC?

Mark G. Papa - Chairman and Chief Executive Officer

Yes we've calculated the impact of that new royalty on our existing production, it's pretty de minimis. But as you know in Alberta a lot of the stuff we do is that real shallow gas drilling that biogenic gas and really has essentially no impact on go forward shallow gas drilling. What it does have an impact is if you are drilling wells 7,000 - 10,000 feet deep. It's a pretty confiscatory royalty change. So I'd say for those kind of areas which is up in the deep basin area of Alberta the Wapiti area where we drill some wells. On the margin it's probably going to cause us to drill less wells and shift some capital in those areas, shift some capital to other areas.

John Herrlin - Merrill Lynch

Yes, so basically... because your biogenic wells tend to be low volume, you don't get clipped on the royalties, right?

Mark G. Papa - Chairman and Chief Executive Officer

Yes, those will... we will continue that program on a go forward basis but probably I would say 25% of our CapEx the last 3 years is going to kind of the deep base of Alberta areas like the Wapiti area you might have heard us talk about where we are drilling at 7500 feet up there, if you get a well all that maybe it will come in at the million a day or so. Royalty jumps from roughly 26% to something like 40%. Starting in 2009, so clearly at the margin, we and I guess every other producer will be less in time to drill those kind of wells.

John Herrlin - Merrill Lynch

Okay. Great, thank you very much.

Mark G. Papa - Chairman and Chief Executive Officer

Yes.

Operator

And for the next question we will go to Ray Deacon with BMO Capital Markets.

Ray Deacon - BMO Capital Markets

Hi Loren I was wondering in the Rockies, is there anything in the winter that would make you more positive in some of the deeper shale plays about the economics there, in a $7 gas world?

Loren M. Leiker - Senior Executive Vice President, Exploration

Ray we've participated in I think two wells now, into the deeper shales below what we call the Mesaverde and really the results are not very definitive at this point. I mean there is obviously it's a big basin in our gas sales and there is plenty of gas intersection and it's a fixed section. We are talking to 2000 feet of the rock there but of the economics we are not sure justified that they are drilling at this point. And again it comes down to same kind of question we had in that some of these other basins in some of these other basin-centered sales what's controlling sweet spot. At this point there really has not been enough drilling into that section to know whether it's a pervasive wide spread sweet area or there is going to be much more localized by say tectonic fracturing.

Ray Deacon - BMO Capital Markets

Okay. Got it. And I guess just two more quick ones between now and the analyst meeting I guess in the Barnett other than the core and tier 1 where are you going to devote the bulk of your effort? Is it more in the Southern where the Western Counties, where is the effort going and also just a question on basis hedging is that... are going to... are you looking at that at all at this point?

Mark G. Papa - Chairman and Chief Executive Officer

Yes we are not looking to actively hedge any basis. We have, we think the Rocky Mountain situation will clear itself up here once REX comes into service. As far as the Barnett over the next several years it's going to be a mix. But Johnson County is still going to carry the lion share of the load but what you will see is you will Hill County and you will see the Western Counties take on bigger proportions of the load as you get into '08 and '09. But still the bulk of the load clearly is still going to be borne by Johnson County.

Ray Deacon - BMO Capital Markets

Okay. Got it. Thanks.

Operator

And for our next question we will go to Joe Allman with JP Morgan.

Joe Allman - JP Morgan

Hello everybody. In terms of the North Dakota Bakken this Austin well. Do you think that this is part of the Parshall field or do you think it's actually outside of the Parshall field that's still in a relatively sweet spot?

Loren M. Leiker - Senior Executive Vice President, Exploration

Joe we think it's all part of the same accumulation. So in that way you could say it's part of the Parshall field as to whether it's a... we are going to see 700,000 barrels per well at every location between them and Parshall that remains to be seen but we believe that the whole area is going to be a sweet spot.

Joe Allman - JP Morgan

Okay that's helpful. And just to clarify 700,000 that gross is net to you but the gross would be roughly 900,000 barrels?

Loren M. Leiker - Senior Executive Vice President, Exploration

That's correct.

Joe Allman - JP Morgan

Okay. And then you got six rigs running at this point where you are focusing at drilling? Are you pretty much all in this area, or are you stepping outside? I mean you said you got one completing six miles South but any other drilling going on elsewhere?

Loren M. Leiker - Senior Executive Vice President, Exploration

We did have rig drilling our third well at Austin area to the North. We mentioned the two and that we also have a well drilling in that same area. The other rigs are all down in the Parshall area.

Joe Allman - JP Morgan

And this additional 45,000 or so net acres that accumulated, is it all kind of roughly in this area or are you stepping out on to new area as well?

Loren M. Leiker - Senior Executive Vice President, Exploration

We are continuing to lease in the Parshall area picking up interest as we can and in Austin area and in the box to 20/6 mile box that we talked about. And in general this leasing on the whole trend, we believe the trend is not fully defined at this point.

Joe Allman - JP Morgan

Got you. And then on your pricing flexibility for next year's CapEx, are you focused on the spot prices or the 12 month futures? Or are you focused on really what the differentials are? It's Rockies is really sort of a flex area, is really the issue that's going to trigger decision the differential?

Mark G. Papa - Chairman and Chief Executive Officer

All but yes the differentials will play a part of it but we just... we are assuming correctly I hope that when Rockies Express starts up there's not a huge basis flow out between the Rockies and the rest of the country. So we are basically saying that if Henry Hub is $8 or $7 depending on the case that we are assuming some differentials between there and Rockies and Canada and so on and so forth but everything is predicated really on how the Henry Hub numbers.

Joe Allman - JP Morgan

And presumably if we get a spike in prices you will hedge some more and then you might be kind of in a midpoint of the 13% or 17% increase something like that.

Mark G. Papa - Chairman and Chief Executive Officer

Yes I mean you could almost interpolate if gas prices are $7.50 we would probably do 15% production growth. The gas prices are $9 I think you can probably assume what we are still going to do the 17% you can't... don't interpolate north of 17%.

Joe Allman - JP Morgan

Got you. I wanted that and then just comment just on other shale plays now you said your Northwest territories... what were you pursuing up there?

Loren M. Leiker - Senior Executive Vice President, Exploration

Northwest territories was really not a shale play at all. It's more of a conventional structural play involving Paleozoic carbonate reservoirs, and Paleozoic shale source rocks in conventional trusted traps. We drilled I think a total of about four wells out there, found two traps one gas, one oil plus common well... I should say one gas plus common trap [ph]. And appraised one of those and just feel like the results were not sufficient to make us go forward.

Joe Allman - JP Morgan

Okay. Can you comment on anything else that's going to... any other kind of play that especially shale play that you've got going on in Canada and how about West Texas any update on West Texas? Are there other any plays, I know you don't want to comment too much but can you give us an update?

Mark G. Papa - Chairman and Chief Executive Officer

The answer to Canada is no. The one play or plays were involved in or heavily competitive vis-à-vis acreage. And so we are not going to comment and the only comment we'll make on West Texas is we did announce on last quarter earnings call, that we had exited from the Culberson county play which was a much hype play. So we have no position in Culberson county. So you are not going to get any information out of us. We're not doing that to be catty, we're just doing it because these plays are very, very competitive and acreage is competitive and there is a lot of people who follow on EOG in trying to replicate us. So we've adopted a very, very confidential posture on these plays.

Joe Allman - JP Morgan

That's smart and I appreciate that. Just a clarification on you talked about Appalachia, that divestiture. Is it 200 to 250 Bcf of proved reserves? And then you gave a number for the PUDs, I just want to clarify that.

Gary L. Thomas - Senior Executive Vice President, Operations

Yes, that was PDP proved.

Joe Allman - JP Morgan

200 to 250PDP and then so the... okay, the PUDs would be whatever percentage you gave 30% of the total which presumably the total is higher than that number.

Gary L. Thomas - Senior Executive Vice President, Operations

Yes if you use SEC, there is quite additional number of locations that can be drilled.

Joe Allman - JP Morgan

Okay. Got you, and then lastly any basis hedges at this point for 2008?

Mark G. Papa - Chairman and Chief Executive Officer

No we've no basis hedge taking place.

Joe Allman - JP Morgan

Got all right. Thank you very much.

Operator

And for our next question we will go to Joe Magner with Tristone.

Joseph Magner - Tristone Capital

Good morning. Just one more follow up on the Bakken if I may. My understanding is that there is a need for a gas gathering system up there. You are planning gas but limited by state restriction. Is that the case, how much is that curtailing current production? Is there a gathering system plan and if so when will that be complete?

Mark G. Papa - Chairman and Chief Executive Officer

Yes your information is correct. There is not a gas gathering system in place. We are building our own gas gathering system and it should be in place by the end of this year. And so it's not curtailing any current production right now and the gas should be going for sales by the end of the year.

Joseph Magner - Tristone Capital

Full production growth estimates factor that completion in for next year?

Mark G. Papa - Chairman and Chief Executive Officer

Yes not that much. It's called casing gas. It is just a gas I think it's currently like 2 million to 3 million cubic feet a day. But it will contribute but that is factored into our '08 production growth estimate, it will contribute some natural gas liquids and a bit of natural gas that is in our estimate yes.

Joseph Magner - Tristone Capital

Okay thanks. And just go quickly on the Barnett there were a couple of pipelines that were expected in the southern and western extension areas, are those complete or what's the timing and what sort of impact will those have on the Barnett activity next year?

Gary L. Thomas - Senior Executive Vice President, Operations

Yes they are going to be in place for us next year. We got waste pipeline procuring gas through it. We are expanding it and the Hill county or South extension will be completed there next year.

Joseph Magner - Tristone Capital

Okay. Thanks, that's it for me. Thanks.

Operator

And for our next question we will go to Richard Tullis Capital One Southcoast.

Richard Tullis - Capital One Southcoast

Good morning. Just some quick questions. I think most of them have been answered already. Going back to the shut-ins could you review that with us quickly? I didn't catch all of it.

Mark G. Papa - Chairman and Chief Executive Officer

The shut-ins what we have said is for the months of September, October and looks like for the first half of November we have had or we will have anywhere between on a daily basis between 50 million and 140 million net cubic per day curtailed in the Rockies because of this whole gas price. So the effect of that if you look at our actual production for the third quarter in U.S. gas, and the guidance that we have given for the fourth quarter in U.S. gas, the numbers are lower than what particularly in a guidance for the fourth quarter that is lower than the guidance we had previously issued. And we are currently, if you look at 2007 guidance for the full year, we are currently estimating 10.5% production growth, whereas we have previously indicated 11.5% production growth, and 100% of that 1% lower production growth is just due to the production curtailment we have voluntary done in the Rockies due to low gas prices.

Richard Tullis - Capital One Southcoast

Okay. I understand. Just going to the Bakken real quickly. I know you are planning to run 8 rigs starting early '08 any plans to expand, that higher particularly as the expansion play continues and given the higher crude prices?

Mark G. Papa - Chairman and Chief Executive Officer

It's possible in the second half of '08 that we could step it out another rig or two. It will depend on the stepout drilling that we do. Most of those 8 rigs we'll be drilling in that box that we described which is that 20 mile long, but roughly 7 mile wide, sweet spot that we have now pretty well defined. But we will be drilling some stepout wells, particularly in the fourth quarter and first quarter next year to kind of trying to expand that box to make it bigger. And if we successfully make that box bigger, it's certainly possible in the second half '08 we'll ramp up drilling a bit more. But won't be going like from 8 to 16 rigs or something like, it may go from 8 to 10 or something but it will depend on whether we... also possibly on downspacing feasibility here if we are successful and through 28 for spacing and we think we're going to recover more reserves. But it will be a second half '08 event likely.

Richard Tullis - Capital One Southcoast

Okay.That's it from me. Thanks too much.

Mark G. Papa - Chairman and Chief Executive Officer

|Okay Richard.

Operator

And for our final question we will go to Jeff Hayden with Pritchard Capital.

Jeff Hayden - Pritchard Capital

All my questions have been answered. Thanks a lot.

Mark G. Papa - Chairman and Chief Executive Officer

Okay. Jeff, thank you.

Operator

And with no more questions in the queue at this time, I would like to turn it back over to Mr. Papa for any closing or additional comments.

Mark G. Papa - Chairman and Chief Executive Officer

I don't have any additional comments. Thanks everyone. If you stayed on that long for all that extensive Q&A and we will talk to you next quarter.

Operator

That does conclude today's teleconference. You may now disconnect your lines. Thank you for your participation.

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Source: EOG Resources Inc. Q3 2007 Earnings Call Transcript
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