EOG Resources Inc (EOG) 2007 Q3 法說會逐字稿

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.

Good morning and thanks for joining us. We hope everyone has seen a press release announcing third-quarter 2007 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 (inaudible) SEC filings. 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 reserves 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, may include other categories of reserves. We incorporate by reference the cautionary note to US investors that appears at the bottom of our press release and investor relations page of our website. An updated investor relations presentation 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. You will 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 curtailments in the Rockies in September, October, and partially into November due to low gas prices. During this period, we have had between 50 and 140 million cubic feet a day of net volumes curtailed on any given day in the Rockies.

The press release also includes EOG's 2008 production growth expectations under both a $7 and an $8 or higher 2008 Henry Hub gas price assumption. I will discuss our 2008 volume forecast and business plan when I review operations.

I will 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 to follow the practice of industry analysts who focus on non-GAAP net income available to common, to eliminate mark-to-market impacts, as outlined in the press release, EOG's third-quarter adjusted net income available for common was $195.7 million or $0.79 per share.

I will note that in this quarter we recognized a writedown 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 had 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 will now address our operational highlights, starting with our 2008 production growth forecast. Our baseline case assuming $8 or higher Henry Hub prices generates 17% total Company production growth. I will note the 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 will 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 and Trinidad and UK North Sea. So essentially, 100% of EOG's total 2008 growth will be organically derived from the US.

Third, because of tax considerations, we expect our Appalachian shallow EOG's 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.

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 is the logic behind our capital allocation? Simply put, EOG can be considered similar to a high-performance engine capable of generating both strong organic oil and gas production growth in 2008 and subsequent years. In 2008, we will 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 will 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 will 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 will 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 have 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 have now drilled 22 horizontal wells in our Mountrail County Bakken discovery. 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're currently receiving WTI price less $6 per barrel at the wellhead. The oil is being piped to the Clearbrook, Minnesota, market area and distributed from there. 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 have continued to perfect our horizontal drilling and completion techniques. We have now begun stepout drilling to determine the size of this accumulation. Our press release highlighted the Austin #1-02 horizontal well, which was 9-mile Northern stepout from our existing production. This well IP'd at 2,000 barrels of oil a day and is one of the best producers we have completed in the field. We have confirmed the Austin results with a 1-mile offset well, the Austin 2-3H, as I said, one mile to the West.

We have also completed a -- we have also drilled a stepout well 6 miles to the south of our existing production. This 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 have increased our estimate of EOG's net revenue interest reserves from the prior midpoint of 60 million barrels of oil to approximately 80 million barrels of oil. 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 hydrocarbons, in place per section; and we only expect about 9% primary recovery with our horizontal wells. We're currently drilling on 640-acre spacing and will soon be drilling a pilot well on 320-acre spacing in an effort to better understand the potential to increase recovery.

We intend to drill 47 net wells in 2008 with an eight-rig drilling program. This program will be the primary generator of our 33% total Company crude and condensate volume increase. 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, let's switch to the Barnett, which will be the big driver of our 2008 natural gas production drilling. 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 will note that all of this is organically derived from undeveloped 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 wells 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 have 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 well drilling inventory in the Barnett. The two largest cost components of this project are the drilling and fracture treating costs. We have previously disclosed how we have 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 have 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 our fracs. 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 apply 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 savings elements will be realized beginning in the first quarter of 2008.

As I mentioned, we will 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. 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 will 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 4(a) field increase by about 60 million cubic feet a day net.

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

Thanks, Mark. For the third quarter, total exploration and development expenditures including asset retirement obligations were $945 million was $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 was 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 a 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 will turn it back to Mark to discuss the gas macro and concluding remarks.

Thanks, Tim. Regarding the North American gas macro, I'm 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 LNG imports will be up only about 3/10 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 1.

The offset to the Independence Hub ramp-up is the current Gulf of Mexico gas rig count, which has dropped precipitously from 85 to 51 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-priced venues.

Regarding pent-up natural gas supply to be unleashed by REX in the Rockies, I think the volume increase, if any, will be very small. Using the supply assumptions I have 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% hedged 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 will also note that we have increased our expected long-term growth estimate from an 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 a 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 midteens net debt to total cap throughout 2008, providing lots of balance sheet conservatism and flexibility.

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.

(OPERATOR INSTRUCTIONS) Brian Singer with Goldman Sachs.

Thank you. Good morning. On the Bakken Play, any initial thoughts on well communication and EURs as you start to pilot the 320-acre downspacing?

No. Not any initial thoughts. Our belief is that it is somewhat analogous to the Barnett in that the initial recoveries we are getting of total oil in place -- in this case, it is oil, of course -- are very low. You know, it is our belief that give us some time and we will find a way to improve recoveries. Certainly one way to improve recoveries is to have more intense spacing of wells.

While we are talking in Johnson County of going to 40-acre spacing, in this case the concept would be 320-acre spacing. So we will be drilling our first pilot well here within a month, the 320-acre spacing, and seeing how that turns out.

It will probably be kind of an iterative process. It will probably take us, I would say about six months to get an understanding of -- are 320s 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, 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.

Then we also think that in terms of how much oil or what percent of oil in place we will ultimately recover, that we will find some way to get that 9% up to a more robust number, too. So there's two ways we think the ultimate recoveries will grow.

Thanks. Then 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 flat or there is a little bit of variability; Bakken is flat -- it is fixed in terms of growth. On your various other plays, could you talk to where you plan to vary? Especially, I guess ostensibly in the Uinta Basin.

Yes, the 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 been the Uinta Basin is we don't have any lease expiry deadlines or anything like that. It is 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 will also -- this other swing area will be Canada, as to how many shallow gas wells drill in $7 versus $8 gas.

But it will also occur in other divisions, not just the South Texas, the Mid-Continent area, East Texas area. But the single biggest play would be likely the Uinta Basin, Brian.

Showed we think that the Uinta Basin needs $7.50 gas to be economic?

No, the thing about it is, it flies at $7 gas. But it is 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 market by pouring more gas onto that market?

So it would be basically a sign where EOG says, we have already got and oversupplied market. Do we, in areas where we have the flexibility to just delay drilling, do we really you want to create more supply, such as in the Uinta Basin? Our answer would probably be, we are probably not going to push it that hard in '08.

Thank you.

Tom Gardner with Simmons & Company.

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

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

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

The trick on -- I always caution people, Tom, on using rig count, particularly in the Barnett. Because what has happened is we are shifting a significant amount of our fleet from these conventional rigs to these automated single rigs. We get more wells drilled with the same rig using these automated single rigs, 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. What I'd 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.

Okay, and those drilling --?

It is dangerous using -- how many rigs do you plan to use?

Yes. The incremental, I guess, benefit not coming from rigs is coming from what? Better stimulation techniques?

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.

We have used Railroad Commission data and other data particularly in Johnson County to get comparisons of that. 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. We just believe we have more efficient completion techniques.

We don't disclose exactly what we're doing, but I think the fact that we are talking about 450 million cubic feet a day next year, and we have made zero acquisitions in the Barnett, speaks for itself. That we are the only one to be generating that kind of production without making multi-$100 million or in many cases, multi-billion-dollar acquisitions in the Barnett. It is because we are getting better wells, I believe.

Got you. 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? What are some of those drivers?

Wow. Yes, that is 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 five 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 converge 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. I don't think it is 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 will just call it directional convergence, because I'm not saying they are 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 a 30-year average winter, that we could see a startling surprise in natural gas prices this winter to the upside.

So 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 upward 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 a 10- and a 30-year winter, and I think $9 gas is pretty well assured, in my opinion.

Thanks, Mark. That's very helpful.

Benjamin Dell with Bernstein.

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 2P reserves are you looking to sell?

Yes, Gary Thomas, do you want to field that?

Our PDP reserves there are somewhere around the 200, 250 Bcf.

Great. Mark, a follow-up question on the hedging. You 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?

You could build a case for that, Ben. You could go crazy trying to figure out what to hedge. I mean I could go crazy trying to figure out what to hedge on there, in terms of things.

But yes, there is some logic to what you say. The way we view the natural gas market is it is pretty much just a weather bet this winter. If we have a warm winter, gas prices could easily be $7. If you have a winter that tends toward the 30-year winter, I think in my mind it is pretty well a lock you're going to have gas prices that will average $9 for the calendar year.

So, it is just kind of what do we believe the winter weather is going to be. So, we just kind of said, since it is a weather bet, we will -- if we can hedge gas around the $8.50 price range and hedge perhaps 30% of it or so, that is probably a comfortable position to be in.

But I do believe that if you've got a reasonable winter that we all will be surprised by the upside strength of how much the gas price moves up.

On the oil side, I just believe that -- my own opinion is that although there might be some emotion in the oil price today certainly, I just believe that you've got worldwide demand at 86 million barrels a day, and you have worldwide capacity today that 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.

I just don't believe that the world, the industry, can grow supply by 10 million barrels a day in five years. So, I just think we have a perpetually tight supply-demand scenario unless we have a global economic slowdown. That is my call.

Great. Maybe I could just go back one last question on your businesses. Canada and the UK last year when you looked at year-end (inaudible) they seemed to underperform your US 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? Or are they positions that you believe over the long term you will be reducing as a percentage of the portfolio, or even getting out of?

Likely not. Certainly not Canada. We think there is a lot of opportunities up there, and certainly one of them would be shale gas opportunities with horizontal drilling. So, and we have 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.

In the UK, we are just trying to figure out what the real gas price is over there. Currently, it is back up to US$10. So we think there are growth opportunities there. Although we basically, as you can see, we haven't really mentioned it on this earnings call, we really just as 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 the UK.

Okay, great. Thank you.

David Heikkinen with Tudor Pickering.

Good morning. Good guidance for next year. Pretty positively received. The comment in question, not giving details on CapEx but talking about activity levels, would an assumption of 13% growth gives you a flat capital budget be reasonable year-over-year?

Yes, David, the reason we have not 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, were we to change it in three months by $100 million, have some sellside analysts criticize us 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 our CapEx would be under either scenario there, to come out with a flat net debt.

I guess an up CapEx would be just net of the Appalachian sales of -- our math says 500 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. Is that -- make sure I am capturing that accurately?

I'm not going to give any (multiple speakers) guidance, but it is basically -- it is not that hard to come up with those.

If we can do it, I guess anybody can. So the thought of rig count and activity levels, you kind of detailed $7 gas, $8 gas, Barnett number of wells. You have given Bakken number of wells. Can you talk about the number of wells in other regions? Uinta and Canada and Mid-Continent at the $7 and $8 gas price case.

Yes, probably not specifically at this stage. We will be able to here by the end of the year, or at our analyst conference, by division on there. But I would say directionally it would be relatively flat with this year at the 13% case; and probably up a bit at 7%. This is all I could give you at this time, but not a specific well count number there, David.

Okay. Then the final question on Appalachia, did you give the production associated there as well?

15 million a day.

Okay. That I guess on the 200, 250 Bs, PUD percentage?

I don't have that number just offhand. The majority of this is going to be proved producing; and I would guess it is probably going to be somewhere around 25%, 30% PUDs.

Okay. 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. Did you say several miles wide or seven? I just wasn't sure if it was seven or several.

I said several miles wide.

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

Robert Morris with Banc of America.

Good morning, Mark. On the capital spending guidance for next year, you will give that out when?

It's probably either at the next earnings call, I would guess is when we would give that out.

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

This is Tim. It is going to be in that same range, because of the high IDC we have going into that program. In the $7 case we are likely to get into an alt-min position, which we won't have in the $8 case, so that would be the swing variance there.

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

In that range, the 80% to 100% range.

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

I think that (inaudible). I would say roughly about $200 to $300 an acre is what we have paid for that incremental acreage. Now I will just note we are saying greater than 175,000 acres. We try to be sly on that stuff. So we have got -- we try and camouflage our acreage position. We have got more than that, but --.

Okay. How much did you pay for your sand mine? Also is there an operating cost that will shop up in allow LOE or a line item for that going forward?

No, it will -- I will have Gary discuss the sand mine and the fracs, because it is probably worth discussing. But it will all show up as -- it will all come through the DD&A line. It is not an operating cost item. It will all be part of the well completion cost or the well cost.

How much did you pay for the mine?

We have got 1,000 acres here in Hood County, and it is adjacent to the [Unima] mine. We paid $500,000 for the lease. It is essentially the same as an oil and gas lease. We have control of that as long as we are mining.

We have spent -- we are going to be spending somewhere around $15 million to have everything functionable. We will start using sand there in December.

Okay.

Go ahead, Gary.

The thing that we look at here is about half the completed well cost is on the drilling side, and about half on the completion. Then half of the completion is the stimulation portion. And about half of our stimulation is the sand.

So with us owning the sand, then there is a tremendous reduction there in the cost of that, probably somewhere around $0.02 per pound versus cost of service companies somewhere around $0.08 per pound. So that is where a large part of the savings comes in. Of course, that is a function of how much sand we use, and we are continuing to use more sand per well or per completion.

Okay.

So that is how we get the $350,000 savings per well.

Okay, that's helpful.

Okay?

All right. That's all I had. Thanks.

Gil Yang with Citigroup.

Just a follow-up on sands just a bit. Why are you limited to only about 30 wells? Is it just how close they are to the mine?

No. The reason for that right now is we are going to have three fracs spreads that we have contracted, and we will just be able to get about a third of our wells completed with those three frac spreads.

Now, once we get 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-saving to EOG.

So that appears in offset to DD&A?

Yes.

Essentially? Okay.

That will reduce our well cost. That is of course what we work at in all cases, going back to -- yes, half our cost is on the drilling side. Well, you know, a large portion of that is the rig. So that is why we went to the automated rigs.

Then we look at the other part of that equation, that being the completion and what can we do to improve our efficiency and lower our cost on that side as well.

All right. Mark, a couple questions for you regarding the acceleration or deceleration of activity. How much (technical difficulty) maintenance activity in the Barnett is from lease expiration issues versus just the strong economics?

Conversely, for Uinta it sounds like you don't have lease expiration issues. But is there any economic issues? Economically it is not as strong as the Barnett, so is that why you would choose that area to tune down activity a bit?

In the Barnett, there, 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 paid to get the lease to start with.

So the economic decision you make is, do I drill on those leases? Or do I pay the same amount it cost me to get the lease in the first place? So it kind of drives you to say let's -- since I get a good rate of return anyway, why don't I just keep the activity level up in the Barnett? So you are driven there pretty strongly to keep a fairly high activity level.

In the Uinta Basin, you have quite high rates of return. Basically, even at $7 you have got about a 30% to a 50% reinvestment rate of return. So 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 -- or at least 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 $7 environment? And stressing our organization's limited personnel even farther.

So it is not a case where you're going into an economic distress situation at $7 in the Uinta. You still have very nice economics. But it is more a case that I am not sure we want to just flood the market with more gas if the market doesn't need any more gas.

Okay, fair enough. For the Barnett, if you are drilling up more, if a lot of your activity is being driven by lease -- drilling up leases, will we see any change in the quality of the wells that you drill into more peripheral areas? And will there be a mix shift there?

No, not that we see, really. It is still going to be very very good. We are blending -- what will be seeing over time is s you will see more of the West and more of the Southern extension stuff getting gradually blended in Johnson County.

That is where this frac stuff that Gary detailed for you is important. Because if you save a significant amount per well out there in the West, it really helps your economics out there, because there it is more of a cost driven play. But no, you really won't be seeing a major shift in mix.

Right. 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 activities to search for new shales or whatever else?

No, absolutely not. We still have our ongoing focus and activity for new, unconventional plays; and the key focus on that is horizontal drilling. All the unconventional plays, unconventional shales we are looking at, the key thing there is all of them that we are looking at involve horizontal drilling.

So that is a very heavy focus in the Company. We keep very, very quiet about those plays. The most recent example we have is obviously the Bakken, of a successful one.

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 can possibly give you. But the emphasis within the Company is still very, very heavy on that.

All right, thank you.

Leo Mariani with RBC.

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 walls you had come on around 1,900 barrels a day at the end of September. Trying to get a sense of what that well is doing today.

Yes, the wells come on, and they have a decline rate that is -- just to tie it into you, it is 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 will say approximately 15 years.

A typical well will come in at say 1,800, 2,000 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 and think that, like this Austin well that is highlighted in the press release came on at 2,000 barrels a day. It doesn't stay at 2,000 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 rate of return of 100% very easily. Then what you end up with is kind of a long-lived well that produces between 100 and 200 barrels of oil a day for many, many, many years.

But as you are aware of, the finding cost as we quoted is about $7.50; and obviously if you are selling this stuff for $80 or $90 a barrel, pretty obvious what the profit margin is.

Okay. Could you maybe give us a little bit more color around your assumption of the 80 million barrel recoverable net? I guess if I just kind of do some quick math and use 640s 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 that way of thinking?

Yes, as we continue to drill we are trying to define the size of the sweet spot. We know there is a larger oil accumulation in this Eastern part of the Williston Basin in the Bakken. The question is, how much of it is going to be at 700,000 barrels per well; how much of it is going to be a little bit less than that but still economic?

You probably recall at our analyst conference last year we first announced this thing at 50 million barrels as our midpoint. That is after drilling four wells. Then about midsummer we drilled, I think, 13 wells; and we upped that to 60 million. Today we are saying 80 million as our midpoint after drilling 22 wells.

And that also means that we have added leasehold during that time frame, of course. But we have extended the sweet spot nine miles north. Parcel 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 a substantial size.

How we actually get to the 80 million barrel number, we are assuming 640 spacing. We are assuming that 700,000 barrels per well, but only in this -- what I would call this 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. What we are doing is -- this kind of modeling 80 million barrels is what we would consider a very safe number today.

If you just use your math, 175,000 net acres, that is 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, how you mix up your calculation, determining how much of that has been ultra-sweet and how much of it is just relatively sweet, that is the part we are really not willing to say more about today.

But we have a think we have a handle on that. We're gathering a more specific and definitive handle on that as we drill our stepout wells.

Okay, so you folks are obviously gradating your acreage here into sort of buckets, for lack of a better word. I guess are you guys also applying some risk assessment to this, to get to the 80 million barrels? Is that more sort of a risk number in your assessment?

Yes, we're risking our acreage to get to that 80 million barrels.

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

Yes, we just put up on our website this morning and I believe the numbers are that we expect the UK and Trinidad this year to produce 300 MMcfe. Next year those two produce 290 MMcfe. The assumption there, the assumptions are that we just have a natural decline in the UK, which is by far the much smaller component of that. I believe that is very, very likely to -- what will happen. Because we don't have any new production that is likely to come on there.

Then the assumption in Trinidad is that we will be limited to our contract takes. There is a possibility in Trinidad that we will again have contract over-takes. But we would guide you to just the contract takes amount. So the 13% and the 17% production growth have inherent in there that we just are limited to contract takes in Trinidad; and we basically go from 300 to 290 in both cases, the 13% and 17% and volumes from those two entities next year.

Okay, how many rigs do you guys run in the Barnett right now, just curiosity.

23.

Okay. Thank you very much for your time.

David Snow with Energy Equities Incorporated.

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

There is really not a whole lot new in the Wolfcamp, New Mexico. We are running a couple rigs out there and having decent results. It is a supportive play for our West Texas division. That is all we have ever painted it as being. That is exactly what it is. It is a supportive play, and things are going fine there.

Okay, thank you very much.

John Herrlin with Merrill Lynch.

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

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.

Okay, great. Given the new sands, the fit for purpose rigs, your fracs, etc., what is your average completed well cost?

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

Okay, switching to the Bakken, if you started one of these horizontal wells January 1, what would you average? About 220, 250 barrels a day per year?

It is going to be higher than that, John. Because these wells, after several months, still 600 barrels a day. Most of them that we have I would say it is going to be around 350 barrels a day.

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

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

Okay. Regarding the sweet spot that was discussed by Loren, are we talking geologic or fracturing related type stuff, since it seems to be a very narrow band? Can you give more information, Loren?

Reluctantly, John. (technical difficulty) slightly more information. I think what we said before is that these sweet spots are both controlled by tectonics or fracturing and by stratigraphy. So, obviously, we now believe we have extended the sweet spot all the way from Parshall into that Austin area nine miles north. That is not a very linear sounding box.

So which of the two are the most -- are dominant structuring or stratigraphy? That is what we are not really going to comment anymore on today. But I would just say that both are involved.

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

And Parshall itself is about six or seven miles wide. So talking 20 by six or seven now.

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

John, let me mention one thing here. Looking at some of the earlier wells that came on a year ago, the rate is -- one of them came on at 1,800 barrels a day; current production 415. That is what I was addressing. By the end of the year, be making about 350 barrels of oil per day.

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

Okay. Good, still what I wanted to get to. Last one for me I guess is the new royalty framework in Canada. Obviously you have heard about it. Does that 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 the shale plays over towards BC?

Yes, we have calculated the impact of that new royalty on our existing production. It is 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. It really has essentially no impact on go-forward shallow gas drilling.

Where it does have an impact is if you are drilling wells 7,000, 10,000 feet deep. It is a pretty confiscatory royalty change. So I would 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 is probably going to cause us to drill less wells and shift some capital in those areas, shift some capital to other areas.

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

Yes. Those will -- we will continue that program on a go-forward basis. But probably I would say 25% of our CapEx the last three years has gone to kind of the Deep Basin of Alberta there, areas like the Wapiti area you might have heard us talk about, where we are drilling at 7,500 feet up there.

You get a well that maybe will come in at 1 million a day or so. Well, the 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 inclined to drill those kind of wells.

Okay, great. Thank you very much.

Ray Deacon with BMO Capital Markets.

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

Ray, we participated in, I think, two wells now into the deeper shales below where we call the Mesaverde. Really the results are not very definitive at this point. There is -- obviously it is a big basin-centered gas field. There is plenty of gas in the section. And it is a thick section; we are talking 2,000 or 3,000 feet of rock there.

But the economics we are not sure justify that drilling at this point. Again it comes down to the same kind of question we had in some of these other basins and some of these other basin-centered sales. What is controlling the sweet spot?

At this point, there really has not been enough drilling into that section to know whether it is a pervasive, widespread sweet area or that it is going to be much more localized by, say, tectonic fracturing.

Okay, got it. I guess, just two more quick ones. Between now and the analysts' 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 or the Western counties? Where is the effort going? Also just a question on basis hedging. Is that -- are you looking at that at all at this point?

Yes, we are not looking to actively hedge any basis. 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 is going to be a mix. But Johnson County is still going to carry the lion's share of the load. But what you will see is you will see Peel 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.

Okay, got it. Thanks.

Joe Allman with JPMorgan.

Hi, 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 is actually outside of the Parshall field, but still in a relatively sweet spot?

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

Okay, that is helpful. Just to clarify, 700,000 of the gross is net to you. But the gross would be roughly 900,000 barrels?

That's correct.

Okay. Then you have got six rigs running at this point. Where are you focusing that drilling? Are you pretty much all in this area? Or are you stepping out some? I know you said you have got one completing six miles South. But any other drilling going on elsewhere?

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

This additional 45,000 or so net acres that you have accumulated is all -- is it all kind of roughly in this area? Or are you stepping out into some new areas as well?

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

Got you. 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?

If the Rockies is really sort of the flex area, is really the issue that is going to trigger a decision the differentials?

Yes, the differentials will play a part of it. But we are assuming -- correctly, I hope -- that when Rockies Express starts up that there is not a huge basis blowout 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, we are assuming some differentials between there and Rockies and Canada and so on and so forth. But everything is predicated really on kind of the Henry Hub numbers.

Okay. Then presumably, if we had a spike in prices, you will hedge some more; and then you might be kind of in the midpoint of the 13% to 17% increase, or something like that.

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

Got you. No, no. Won't do that. Then, just a comment. Just on other shale plays, you said your Northwest Territories, what exactly -- what were you pursuing up there?

Northwest Territories was really not a shale play at all. It is more of a conventional structural play involving Paleozoic carbonate reservoirs and Paleozoic shale source rocks in conventional thrusted traps. We drilled, I think, a total of about four wells up there. Found two traps. One gas, one oil plus [common] -- well, let's just say one gas plus common. (inaudible) Appraised one of those and just feel like the results were not sufficient to make us go forward.

Can you comment on anything else, any other kind of play, especially shale play, that you have got going on in Canada? How about West Texas? Any update on West Texas, or any other plays? I know you don't want to comment too much, but can you give us an update?

The answer in Canada is no. The play or plays we are involved in are heavily competitive vis-a-vis acreage, and so we are not going to comment.

The only comment we will 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-hyped play. So we have no position in Culberson County.

So you're not going to get any information out of us. We are not doing that to be catty. We are just doing it because these plays are very, very competitive and the acreage is competitive and there's a lot of people following EOG and trying to replicate us. So, we have adopted a very, very confidential posture on these plays.

That is smart and I appreciate that. Just a clarification on -- you talked about Appalachia, that divestiture. Is it 200 to 250 Bcf of proved reserves?

Then, you gave a number for the PUDs; I just want to clarify that.

Yes, that was PDP, proved.

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

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

Okay, got you. Then lastly, any basis hedges at this point for 2008?

No, we have no basis hedges in place.

Got you. All right. Thank you very much.

Joe Magner with Tristone.

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 flaring gas, but limited by state restrictions. Is that the case? How much is that curtailing current production? Is there a gathering system planned? If so, when will that be complete?

Yes, your information is correct. There is not a gas gathering system in place. We are building our own gas gathering system. It should be in place by the end of this year. So, it is not curtailing any production right now. That gas should be going to sales by the end of the year.

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

Yes. It is not that much. It is called casing head gas. It is just a gas -- I think it is currently like 2 or 3 million cubic feet a day.

But yes, it will contribute; but that is factored into our '08 production growth estimates. It will contribute some natural gas liquids and a bit of natural gas. It is in our estimates, yes.

Okay, thanks. Then just 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 is the timing? What sort of impact will those have on the Barnett activity next year?

Yes, they are going to be in place for us next year. We have got the West pipeline; we are carrying gas through it; we are expanding it. The Peel County or South extension will be completed there next year.

Okay, thanks. That's it for me. Thanks.

Richard Tullis, Capital One Southcoast.

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

The shut-ins? What we had said is that for the months of September, October, and looks like for the first half of November, we have had or will have anywhere between, on a daily basis, between 50 and 140 million net cubic feet a day curtailed in the Rockies because of just low gas prices.

So the effect of that, if you look at our actual production for the third quarter in US gas, and the guidance that we have given for the fourth quarter in US gas, the numbers are lower than what -- particularly in the guidance for the fourth quarter, they are lower than the guidance we had previously issued.

We are currently, if you look at 2007 guidance for the full year, we are currently estimating 10.5% production growth; whereas we had previously indicated 11.5% production growth. And 100% of that 1% lower production growth is just due to the production curtailments we have voluntarily done in the Rockies due to low gas prices.

Okay, I understand. Just going to the Bakken again real quickly. I know you are planning to run eight rigs starting early '08. Any plans to expand that higher? Particularly if the expansion of the play continues and given the higher crude prices.

It is possible in the second half of '08 that we could step it up another rig or two. It will depend on the stepout drilling that we do.

Most of those eight rigs will be drilling in that box that we described, which is that 20-mile long by roughly seven-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 of next year to try to expand that box, to make it bigger.

If we successfully make that box bigger, it is certainly possible in the second half '08 we will ramp up drilling a bit more.

Okay.

Won't be going like from eight to 16 rigs or something like that. It may go from eight to 10 or something. But it will depend on whether we -- also possibly on the downspacing feasibility here. If we are successful in 320-acre spacing and we think we can recover more reserves. But it would be a second-half '08 event, likely.

Okay. That's it for me. Thanks so much.

Jeff Hayden with Pritchard.

All my questions have been answered. Thanks a lot.

Okay, Jeff, thank you.

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

I don't have any other additional comments. Thanks everyone, if you stayed on this long, for all that extensive Q&A. We will talk to you next quarter.

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