EOG Resources Inc (EOG) 2005 Q3 法說會逐字稿

Welcome to the EOG Resources third-quarter 2005 earnings release conference call. As a reminder this call is being recorded and at this time I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing third-quarter 2005 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call.

The SEC permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates in this conference call and webcast including those for the Barnett Shale Play may include other categories or reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of the investor relation page of our website. We plan to post an updated investor relations presentation to our website later today.

With me this morning are Ed Segner, President and Chief of Staff; Loren Leiker, EVP, Exploration and Development; Gary Thomas, EVP of Operations; and Maire Baldwin, Vice President of Investor Relations.

We filed an 8-K with fourth quarter and full year 2005 guidance yesterday afternoon reconfirming our 15.5% production growth expectation. As previously stated we expect to achieve 9.5% overall organic production growth and 13% North American gas production growth in 2006. As we discuss our operational results in a few minutes, you will note our game plan remains consistent with the same hallmarks of high returns, strong organic growth and low debt.

I'll now review our third-quarter net income available to common and discretionary cash flow and then I will discuss operational results. As outlined in our press release for the third quarter EOG reported net income available to common of $341.9 million or $1.40 per share. For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the third quarter was $658.7 million or $2.69 per share versus 388 million or $1.62 per share adjusted for the stock split a year ago. The reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities is found in our earnings press release which is posted on our website.

I'll now address some of our operational highlights. You'll note that our third-quarter daily production increased 13.7% year-over-year all organic and our year-over-year organic growth to the first nine months of 2005 is 17.6%. We expect to achieve our 15.5% production growth target for the full year in spite of still having 15 million a day equivalents off line in our Gulf of Mexico operating area because of the hurricanes and also having a six-week delay in gas sales relating to the M-5000 methanol plant in Trinidad.

Regarding 2005 and 2006 we expect to accomplish production growth in each of our three operating areas, North America, Trinidad and the North Sea. This quarter we have positive news from all of our operating areas and I'll discuss these in sequence.

In North America, our production growth is being generated by the Barnett and by our North America ex-Barnett portfolio. During last quarter's call I focused very heavily on the ex-Barnett portion of our portfolio to remind shareholders how well this part of our asset base is performing. This quarter I'll start off discussing the Barnett because frankly I'm very pleased with our Barnett results. We currently have 503,000 acres leased and are running 11 drilling rigs; nine in Johnson County, one in Parker and one in Erath County.

You'll recall that early this year we predicted we'd exit the year at 100 million cubic feet a day, and then during the second-quarter earnings call we lowered the year-end estimate to 80 million cubic feet a day because of multiple logistical issues we encountered January through May. Consequently there may have been a perception that there were some problems with our Barnett program and our stock took a mild hit at that time. While our current Barnett sales are 82 million cubic feet a day and it now appears that we will end the year well above 80 million cubic feet a day and likely close to our original 100 million cubic feet a day goal because we have recently been completing a string of monster wells.

The last 20 wells we've completed in Johnson County have averaged 2.4 net Bcf, which is 20% better than the 2.0 net Bcf we'd been modeling which already yields greater than 100% after tax rate of return. One of these, the Campbell #1 H, appears to us to be the best Barnett well ever drilled in Johnson County by any operator and it commenced production at 7.7 million cubic feet a day. We have 100% working interest in this well.

But rather than focus on individual wells, the key items that have me excited about Johnson County are; number one, using our proprietary completion techniques, we feel we've resolved the issue of extraneous Ellenberger water. Number two, we are seeing more consistent well results. Every one of the last 20 Johnson County wells have generated a 100% after-tax rate of return. This consistency is very important when you're planning on drilling over 1000 Wells.

Number three, we're implementing 500 foot, which is essentially 35 acre down spacing. We recently drilled four wells side by side on this spacing and each had initial production rates of between 2.7 and 3.3 million cubic feet a day. And number four, as we noted during our recent analyst conference by drilling shorter laterals we believe we now have 750 locations, that's up from 450, on 1000 foot spacing but with the same per well reserves. Additionally, we have between 500 and 750 down space locations on our 90,000 acre Johnson County position alone for a total of crude 1250 to 1500 locations in Johnson County. We will be drilling heavily on this acreage through 2008.

Regarding our remaining 413,000 acres in the western counties, we're continuing to shoot 3-Ds and drilling complete wells at a much slower pace until we get the well completions optimized for the shallower depth and 200 foot pay versus 300 foot pay in Johnson County. We expect to continue well optimization during the fourth quarter and we anticipate drilling activity on this western acreage will increase during the first half of 2006. As we've previously noted, we expect these wells to be less prolific than in Johnson County but at current commodity prices, we'll still generate greater than a 70% after-tax rate of return.

You'll note that our third-quarter total exploration expenses were a bit higher than our 8-K guidance. This was partially due to acceleration of our 3-D seismic efforts in the Barnett. To summarize, we're generating consistent repeatable better than expected results in Johnson County where we have a multiyear inventory and are making good progress regarding completion optimization in the western counties.

I'll also mention that we have 125,000 acres leased on a Barnett look-alike play elsewhere in Texas where we are currently float testing our first well. Consistent with our previous statements, we expect to have results from our initial two wells during our year-end earnings call which will be in early February. We also have several other domestic shale gas plays where we're acquiring acreage based on our Barnett knowledge. We'll disclose these later in 2006 after we firm up our acreage positions.

Now I'll switch to the North America ex-Barnett portion of our portfolio where we expect to generate about 8% production growth this year even though we have 15 million a day curtailed likely through year end from the Gulf of Mexico due to hurricane-related downstream bottlenecks. As I've said before, I don't think many companies our size are generating this level of North American organic growth and that's without the Barnett. This growth is broad-based and comes from all of our major operating areas. As I did last quarter, I'll provide you the expected full-year organic production growth for each of our major operating areas.

Note that you won't be able to do a simple arithmetic average of these individual growth numbers to reach a total because each area is a different size. Also I won't highlight our smaller offshore and Appalachian areas for year-to-date production is essentially flat.

In South Texas we expect full-year production to grow 10% over last year driven by five plays, the Reklaw, Roleta, Lobo, Wilcox and Frio. This is the first year in our long South Texas history in which we've had five high impact geologic plays simultaneously working and I believe we can achieve similar production growth again in 2006.

In our East Texas and North Louisiana area, we expect to grow our production 18% year-over-year driven by production growth from the Vernon, Driscoll Mountain, Branton and Sligo fields. We recently completed the 100% working interest in Osborne 19#1 well in the Vernon field for 16 million cubic feet a day and a 38% working interest in Martin Timber 20 #1 well in the Driscoll Mountain Field which tested a gross rate of 4 and 9 million cubic feet a day from two separate zones. Both Wells are North Louisiana expanded Cotton Valley producers.

We're also very excited about our 150 net Bcf Eros prospect which we expect to test in the first quarter. This prospect is located very close to both the Vernon and Driscoll Mountain fields and is an expanded Cotton Valley target. In the East Texas Branton field, we recently completed the 75% working interest AB Johnson #6 well which tested at a 5 million a day gross production rate. We expect to commence sales from this well in December. Similar to South Texas, we expect to duplicate this area's double-digit production growth in 2006.

In Midland, we expect our 2005 year-over-year production to decline by about 3% but we expect 2006 production to grow slightly based on results from our 30,000 acre New Mexico Wolf Camp horizontal play where we're currently running two rigs and also our Bone Springs horizontal well play.

In Oklahoma City, our production will grow 14% this year driven by our Wash Morrow, Horizontal Cleveland and a Shallow Hugoton programs. We expect to grow production another 10% next year. Our Rocky Mountain division nine rig program is performing as expected and will generate 12% year-over-year growth in 2005 and we expect to duplicate that in 2006. We have a very deep inventory in both Wyoming and Utah; enough to carry us through 2010.

In Canada, we expect full production -- full-year production to be up 7% primarily based on our 1000 well shallow program and we expect similar 2006 production growth. Regarding our Northwest Territories 2005 through 2006 winter exploration campaign, we plan to employ two drilling rigs. One would drill the stepout well to test the reservoir limits of the B 44 discovery and one will drill a brand new structure. This summary should reaffirm for you that our North America ex-Barnett portfolio will deliver profitable production growth in 2006 and beyond.

Now I'll shift to Trinidad and then the North Sea. In Trinidad, natural gas production that is feed stock to the new methanol plant commenced in late September. We're currently selling about 70 million a day net to the plant at an expected $1.70 well head price. This is above the average contractual level for the first four years of 60 million a day net. We expect sales to the plant to fluctuate considerably during the fourth quarter depending on plant run times.

In addition early in the first quarter of '06, we expect to commence 20 million a day net natural gas sales for delivery to Atlantic LNG train 4. This will be our first sales where the Trinidad well head price is linked directly to Henry Hub.

Early 2006 should also provide some exploration results in Trinidad. We expect to drill our 350 to 500 net Bcf Block 4A prospect in early 2006 which is also when we expect British Petroleum to commence drilling the high potential Deep Ibis well. With the January spud for Deep Ibis it should reach target depth by May.

In the North Sea, we were recently awarded five blocks in the 23rd bid round. Our current production is over 40 million cubic feet a day and we expect to average about 40 million cubic feet a day in 2006. Our next well will be the Arisis (ph) 3 development well scheduled to spud in March. As we've previously stated we expect to generate a modest level of UK production growth over the next several years.

I will now turn it over to Ed Segner to review CapEx and capital structure.

Thank you, Mark. With respect to CapEx, exploration and development capital expenditures during the third quarter were 493 million with 18 million of that being acquisitions. Year to date exploration development capital expenditures have been 1319 million or 1.3 billion with only 30 million of acquisitions.

For 2005 as indicated in yesterdays 8-K, our estimated capital expenditure budget is approximately $1.8 billion excluding acquisitions. For 2006 we have given a very preliminary capital expenditure budget of 2 billion excluding acquisitions. I'll note that we have not completed our formal planning cycle for 2006.

In terms of cash flow, total discretionary cash flow for the quarter was $659 million; year to date discretionary cash flow is 1.695 billion. The reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activity is found in our earnings press release.

Capitalized interest for the quarter was $3.7 million. As to capital structure, at September 30, total debt outstanding was 1,043,000,000 -- 1043. And the debt to total capitalization ratio was 21%, down from 27% at year end 2004. We expect to end the year at less than 20% debt to total capitalization. At September 30, we had $341 million of cash on the balance sheet mainly internationally.

The effective tax rate for the quarter was 34% and the deferred tax ratio was 36%. The guidance in yesterdays 8-K for the effective tax rate for the full year is 35 to 37%; the guidance for the deferred tax ratio is 30 to 45%. These ranges reflect a $24 million charge for choosing to repatriate $450 million in foreign earnings under the American Jobs Creation Act of 2004. And that will take place later in this quarter.

The Form 10-Q for the third quarter was filed yesterday. I'll also point out in yesterdays 8-K we included a reminder paragraph on the differentials to benchmark commodity pricing as it relates to the way EOG sells natural gas and crude oil. For natural gas, U.S. and Canada differentials as given in the 8-K are based on the natural gas prices at Henry Hub using the average of NYMEX settlement prices for the last three trading days for the subject month.

For crude oil and condensate, the U.S., Canada and Trinidad price differentials are based upon West Texas intermediate at Cushing using the simple average of the NYMEX settlement prices for the prompt's (ph) month for each trading day within that subject month.

Now I'll turn back to Mark.

Thanks, Ed. We talked a little bit here about the North American gas market and our feelings relating to hedges or collars. Regarding the North American gas market we're entering the heating season with about 3.15 Tcf in storage and the industry has a wounded Gulf of Mexico deliverability that will likely stay wounded most of the winter. I believe that a lot of the "demand destruction" implied from the high injections the past few weeks is simply Gulf Coast petrochemical plants that haven't yet restarted and LDCs increasing injections before winter.

Accordingly at this time, we have no financial hedges for either natural gas or oil in place for either the fourth quarter or forward. As always we will continue to evaluate the supply/demand factors and it's possible we could put on some hedges sometime in the future.

Now let me summarize. In my opinion there are six important items to take away from this conference call. First, we continue to be primarily focused on returns. Our six-year track record which leads the peer group averages 27.8% ROE and 17.3% ROCE and we expect to post more propitious numbers this year. Our reconciliation schedule with these metrics is posted on our website.

Second, during the first nine months of 2005 we reduced our net debt to total cap from 26% to 15%. We expect to end the year with approximately $400 million net debt and a net debt to total cap ratio less than 10%. Note that we will achieve this debt reduction while generating 15.5% production growth. A reconciliation schedule of net debt to total debt is posted on our website.

Third, in a rising cost environment, we think we're doing a better job than many companies in controlling year-over-year unit cost increases.

Fourth, our North America ex-Barnett growth engine continues to run very well and is multi-year legs.

Fifth, the Johnson County Barnett Shale is developing better than we'd expected and we've begun to implement 500 foot down spacing. We're continuing to experiment and optimize our completions in the western counties and expect to increase our drilling activity there in the first half of 2006. Additionally, we expect you have results from other domestic shale plays throughout 2006.

And finally, we believe we can generate an average 9% 2006 through 2010 organic production growth while maintaining very low debt, generating high ROEs and ROCEs and likely having significant free cash flow in 2006 and possibly also in later years depending on hydrocarbon prices.

Thanks for listing and now we will go to Q&A.

(OPERATOR INSTRUCTIONS) Joe Allman at RBC Capital Markets.

Good morning everybody. Mark, will we see differences between say Western Johnson County and Eastern Johnson County? Are those differences in initial production due to rock qualities or techniques or what?

There is a difference. The biggest difference between Western and Eastern Johnson County is that the -- our acreage position in Eastern Johnson County does have the Viola barrier which is kind of an impermeable barrier between us and the Ellenberger. So it gives us a lot more options as to how we stimulate those and really there's a lower risk of us cracking into the Ellenberger. But I guess the point I'd make is that we're getting good wells; good wells I'd define as well that have initial production rates of north of 5 million a day with a pretty good frequency in both Eastern and Western Johnson County.

But I would expect that overall the 35,000 or so acreage we have in Eastern Johnson County is going to turn out to be perhaps the single best piece of acreage we have out of all the 500,000 acres we have.

And then regarding the western part of the Barnett Shale in the Fort Worth Basin area, I know in your release you said you are encouraged. Has there been anything discouraging about that? And then just kind of another issue, in the West Texas Barnett Shale, the Delaware Basin, could you give us some more color on that first well and any other color you can give us on that play?

Yes, let me address first the stuff we're talking about in the Fort Worth area there in the western counties there, Joe. In the western counties to date we drilled about eight wells so we are heavily concentrating in Johnson County right now. As we said, we've got the majority of our rigs in Johnson County.

I'll reiterate again that we do see a pretty material difference in the quality of the wells from Johnson County to the rest of the counties. And we have drilled of those eight wells, we drilled wells in Jack County, in Hood County and Erath County. We have not yet drilled any wells in either Palo Pinto or Hill County or Somerville County where we do have acreage.

We expect that the per well reserves are going to be in rough terms, roughly 1 Bcf to maybe 1.3 or 1.4 Bcf in the western areas, the western counties. The costs are also cheaper. And again, that is because the zone is shallower and the zone is thinner than it is in Johnson County. What we've seen is if we apply just a totally identical frac to what we're doing -- what we're doing in Johnson County to the western counties, that is probably not the optimum type of completion. So we are really having to experiment given the parameters of shallower depth and everything. And I would say we're making good progress there and I'd liken it to say the first eight wells we drilled originally in Johnson County.

If you looked at those first eight wells, it wasn't the big Eureka right away. It was kind of a gradual process and we are still improving results in Johnson County. We feel we're clearly going to get there in the range of 70% rate of return but we're doing it with only two rigs because we don't want to replicate ineffective completions and be doing it with seven or eight rigs. We want to just go very slowly before we go ramping up the rigs in the western counties.

Regarding your second question, our Stealth Shell play, I'm not going to really acknowledge what particular basin it's in. What I can tell you about it is that we do have 125,000 acres leased. We're fortunate enough to lease it at pretty low cost relative to what that acreage is going for now. We have drilled two vertical wells in it and in one of those wells we took a core and had it analyzed and the core looks reasonably similar to the Barnet. And we also have another zone in that well.

We have tested the well in a vertical mode which was the plan and now we're going to go ahead and take that vertical well and side track and drill it horizontally and give it a test there and that's really going tell the tale.

So by the time we do our early February fourth-quarter earnings call, we expect to have results from that well in a horizontal mode as well as results from a second well which will be many miles away in a different part of our 125,000 acres. So that is kind of the status of it right now.

Thanks for that, Mark.

Ben Dell at Bernstein.

Hi, Mark. I had a couple questions if I could. The first is on your Trinidad Deep Ibis well. Can you give a rundown on where you see the key risk there is? Is it pressure aggression over the steel (ph) and steel integrity or is the primary risk in your mind the reservoir quality?

And my second question was on West Texas. We've seen a couple of other companies announce wells in the Reece (ph) County rather than Culberson County. Can you give an indication where your 125,000 acres sort of sits between those two counties?

And my last question was really on the long-term outlook or the near-term outlook for U.S. natural gas. You mentioned you didn't see any signs of demand destruction. Can you tell us what in particular you're looking for with regard to next year and where you see the industrial consumer; whether you are seeing any weakness in sort of pulp (ph) pay for packaging and aluminum?

Let me have Loren Leiker address your first question there on Deep Ibis risks and I will come back and address your second and third parts there, Ben.

Your question regarding the Deep Ibis risk -- I think the primary risk, as we've said before, is definitely reservoir risk. These sands that are the objectives for that well have never been penetrated by any well in Trinidad to this date. Now we do have ties to outcrops that are probably in the range of around 20 miles away at (indiscernible) Point, very massive sands. And we do have seismic signatures that lead us to believe that these will be sand rich events; three in fact will be penetrating with this well. But having never been penetrated, we won't know until we see a log if the permeability is preserved at that kind of depth.

Regarding pressure seal, we think we will be overlying by thick shales whether they will be the high-pressured shales or whether they will be pressure aggression, will obviously have some impact on how big that trap could be. But it is a four-way structure, so we anticipate trap as a secondary risk.

Regarding your second question there on our other Texas shale play. I hate to be evasive on the specific location of it there but we still have hopes of perhaps gathering up another 10 or 20,000 acres. And we really don't see any commercial benefit to us to acknowledging the locations of the plays. So we're just not going to be able to respond to which specific basin it's in other than to say its somewhere in Texas.

And on the third question there on demand destruction, natural gas macro, I guess my overall feeling, then, is I have been perplexed by the injections the last couple of weeks but I do believe it's probably more a factor out LDCs just cramming gas in storage to get as much in as they can. I also believe that the $13 gas that we had on the screen for November and December or at least we had it a couple days ago is truly not a long-term market clearing price. That is just too high. That is a price that ultimately would have to come down to clear the market. And if it stayed there, would indeed back out some industrial demand, but I don't have any specific numbers on it.

My read is you're really looking at kind of a weather call right now, as we all are every time we get to this point of the year. If we have an average or a cold winter, I think we're going to have a pretty precarious balance throughout the winter and some pretty elevated prices that I believe will probably ripple into at least through the summer. If we have a very hot winter, we will probably see a decline in prices from what the current 2000 strip would indicate.

Thank you. Well, maybe I could just pull out with one other on that. If you see gas prices drop, where do you feel the marginal cost is? Where do you feel people would start turning off wells and where would your capital budget change in terms of a pricing level?

I believe that you -- for example, a lot of these acquisitions that continue to be done, I think that they're really -- a lot of them are based on the forward strip pricing. So to the degree that the forward -- that prices fall below some of these forward strips, I think you're going to see some of these acquisitions' economics not look that good. And I think some of the drilling that is being done is probably predicated on gas prices of $6 or so. So no one -- you're not going to hear a lot of specificity on that from any individual companies. But I think the explosion in drilling, there were some companies out there, at least we believe, that are doing things at those levels. I'd say that we're not, but we look at some of the offset guys and they sure appear to be. So I believe if you did see gas prices tumble to the $6 level for some reason that you would see a big pullback in drilling activity.

Great, thanks very much.

Bob Morris at Banc of America Securities.

Good morning, Mark. On the Barnett Shale here, you noted the four wells that had very high rates. At the same time, you mentioned the last 20 wells would average about 2.4 Bcf per well. Any sense here on these last four wells, the decline rate, how much of that is flush production, and would those be also at 2.4 Bcf per well? Do you have enough history to determine that yet?

Yes, the typical shape of the decline curves on all of these last 20 wells is still going to be pretty similar to that generic decline curve that we provided to you earlier. In other words, very high decline the first three years.

About 70% the first year still?

Yes, I mean something in that range. The generic one is still impaled there. So those kind of rates don't last long, you know, the 6, 7 million a day rates. But what it does do is it just starts you off on that decline curve at a much higher point on there. And I would say that the four wells we quoted in the press release are all going to be better than 2.4 net Bcf, clearly. They are probably in the range of 3 -- maybe a little higher than 3 net Bcf. And those are clearly some of the best wells. I mean, obviously, we wouldn't have put them in the press release; we're no dummies.

But the point I would really harken too, though, is the 20 out of 20 batting average of the last 20 wells, that the average is 2.4. And the fact that we're beginning to get some confidence that the range that we have on our website for Johnson County on a net Bcf per well is 1.4 to 2.4. And we are clearly getting more confidence that we still are going to show as our model well for the economics that 2.0 Bcf per well, which yields greater than 100% rate of return, but we believe that there is clearly some upward pressure on that 2.0 number and what really is encouraging to us is that just in the last three months with some enhancements to our completion techniques, we can see a cause and effect. In other words we have done some things to improve the completions and we're seeing better wells. So really think there are some further things we can do as we get to the next 20 or next 40 wells and perhaps we can see some further improvements to these wells.

This whole thing is just a giant gas accumulation. It's almost like waiting to be mined, this entire 500,000 acres we have and it's my opinion that it is only going to get better with time as we improve our technology here in the entire area.

You mentioned the 500 foot laterals, how many 500 foot laterals have you drill so far?

We've got three what I'd call pilots which are three groupings of 500 foot laterals; one is the original one that now probably has 11 months production history I would say. Another one probably has three months production history and the third one is one that I quoted in the discussion here where we had just drilled four wells side-by-side on 500 feet and we just commenced production literally just about three weeks ago. And those are the ones that initial production rates are between roughly 2.5 and 3 million cubic feet a day.

As we get the wells permeated and everything it will probably be about the first of the year before we get into the routine process of pretty much drilling all the wells on 500 foot spacing.

Now on those 500 foot space wells, they obviously fall below the 1.4 to 2.4 Bcf range on wells because there is communication on 50 acre spacing. And you didn't attribute any additional reserves at your analyst meeting to those 500 foot laterals for the down space wells. Any better sense at this point with 11 months history as to how much overlap or communication there is between the wells and how much incrementally versus 100 acre spacing you can get in reserve recovery?

Yes, the answer is we really can't give any more clarity on that. And we're going to give ourselves till probably late 2006 before we can provide that clarity. Clearly on present value economics, we calculate it's easily over a 50% return on there. But as to how much is of the production, the molecules that physically comes out of that well are new reserves and how much our reserves that are acceleration coming from the last year 20 through 30 of an offset well, we don't know yet and we're just going to give us another year before we can come up with the number. But clearly a portion of it is easily going to be new reserves. But I would say it's not going to be 2.4 Bcf a well.

Okay. Thanks, Mark.

Shannon Nome with JPMorgan.

Thanks, good morning. My other Barnett Shale question relates to staffed (ph) laterals. Mark, you talked about trying these in the upper northeast quadrant of Johnson County where I guess the Barnett is thicker and the Ellenberger water is not there. Any update on that?

Yes, no real update on that other than some time in 2006 we'll probably give that a shot. Right now we're just technically -- we're focusing on further optimizing the completions in just kind of normal laterals. And we kind of have that on our list to try but it keeps kind of moving back on the list mainly because we see what further technical enhancements are doing to get these wells, IPs of five, six, seven million a day. So I would probably say that will be a second half '06 event, Shannon, really.

And then just one more I guess off the beaten path kind of question. Way back in prehistoric times when gas was only $3.00 or $4.00, I seem to remember you took the reserves at Big Piney off the books. I just wonder, in this environment are there plans to revisit that? What is the potential reserve size there if realistic? And what kind of outlay would that encompass?

You are right. The point is that we have a very large reserve at a depth of about 15,000 feet underlaying our 130,000 acres in Big Piney, Wyoming. It's in a zone -- it's called the Paleozoic formation up there. Exxon Mobile has developed that back in the '80s and the problem with it is only about 22% of that gas reserve is methane. The rest of it is carbon dioxide, nitrogen and a bunch of other stuff.

We have dusted that off again. I mean the reserves net to us would be easily over a Tcf of hydrocarbon gas. The problem is you have to put in a monster plant to remove the CO2 and in earths and everything else there. It would probably be about $1 billion capital investment but we are doing a joint study with someone else up there right now to look at that. There are no reserves on our books. You are correct about that, relating to that. It is possible that that thing might get rejuvenated. But that will probably be a late 2006 event whether we decide to -- whether that's really economically feasible to go forward with that or not.

Any gut as to what the minimum threshold gas price would need to be or is that just the subject of the study?

It's really the subject of study. But I'd say that if based on where we think long-term gas prices are going to end up, which is in the range of $7.00, $8.00, the gut is its probably feasible to do -- the real question is are their environmental issues and could you get a plant permitted that near the Wind Rivers Mountain range in Wyoming. We're looking into those issues. But we believe that the long-term North American gas story probably comports with potential for plant viability, yes.

Thanks, Mark.

David Snow at Energy Equities.

I'm wondering do you get the same reserves per well on a 2500 foot lateral as a 4500 foot lateral? Does that mean the last 2000 feet just didn't give you any incremental benefits or how do you explain that?

Yes, David, what it means is that we're getting more gas per foot of lateral than what we originally thought. In other words we originally thought we might get let's say 2 or 2.4 Bcf out of 4000 foot lateral and now we're finding that we're getting that 2 or 2.4 Bcf out of roughly 2500 feet of laterals. So it basically means in laymen's terms that the Barnett is more prolific than we thought.

Well why wouldn't it still increase proportional to the length as you go those next 2000 feet? You must be getting less effective track as you go over 4500 foot interval I guess is what you are saying?

Yes. Pragmatically 2500 feet is about the average lateral we can drill due to lease line restrictions and boundaries between different people owning different leases and items like that. In a perfect world, we'd drill them all at 4000 foot laterals but since the ownership is not uniform over this 500,000 acres, you can't accomplish that, David.

Okay. But that still doesn't show why you get the same reserves on the shorter lateral. You must just be getting better as you are changing the length. It sounds like there's more than one variable at work here.

Yes, the short answer is we're getting better as we're changing the lengths.

Okay. Thanks.

Gil Yang at Citigroup.

Thanks. Mark, could you comment on the additional 10, 20,000 acres that you would plan on getting in West Texas -- what is the limitation there that you see that would stop you at sort of the 135 to 150-ish level?

You guys are all like district attorneys. You ask these leading questions and say we're not going to acknowledge where it is but given that we have a shale play, there is the possibility -- I mean most of the acreage is already pretty well tied up. But we have a couple deals that are in motion that could land us another 10 or 20,000 acres over and above the 125. But we don't feel there is really any way for example that we could double our acreage position out there. All the acreage, essentially all the acreage that gettable has been gotten by somebody or another.

The second well that you are drilling there or drilled there, was that horizontal or vertical?

We have not yet drilled any horizontal wells there yet. The two wells we've drilled have so far been vertical.

And then last question, the monster well so to speak, maybe this is a question for Loren, could you talk about whether or not you view that those wells are monster as opposed to ordinary wells because of specific geological issues in the rock that those wells tap? Or did you do something different from a technology point of view?

Gil, I'd say it's mainly the latter. We have now made great progress we think in targeting which interval makes sense to drill a lateral in in the Barnett. And particularly in how we frac it and of course we're not going to comment more on the frac technology. That has really evolved over the last quarter here.

I will say that we have areas that are sweeter than others in the Barnett based on rock quality. and obviously we are putting our rigs to work in the places that have the best rock quality right now. But I still think we're going to see upward pressure on that range even in the areas where we have lesser rock quality or more geologic barriers to good production; we're seeing really good wells. Maybe not monster wells, but semi monsters.

Okay, thank you.

Joe Magner from Petrie Parkman.

Good morning. I just had a quick question. You touched on the horizontal Wolf Camp play in New Mexico as a driver for '06 growth in that region. Where does that stand right now? How many rigs are running and how many wells have been drilled to date?

Right now we're running two rigs in that play and as a rough guess, Joe, I'd say we probably have drilled about five wells so far in that play. And those wells generally have been pretty geographically dispersed. We've got about 30,000 net acres in that play. We've kind of drilled it over kind of various areas in that 30,000 acres. And what we've confirmed so far is that the play appears to be pretty darn wide spread across we believe essentially all 30,000 acres there. And what we're gearing up to do is to run likely something like four to five rigs throughout 2006 in this play.

And again this is a play that the zone itself is a pretty sorry zone in terms of (indiscernible) permeability and everything and it was really unlocked by our completion technology. We're not using a Barnett style completion but it's unlocked by a horizontal drilling and how we complete these wells. And we have some hope that actually our results are going to improve as we really get in and complete more and more of these wells.

So I'd say we're very pleased everything that we thought this horizontal Wolf Camp play would turn out to be has turned out that way so far. And it's a little bit kind of like our -- I'd say in some analogy it's kind of like our western acreage in Barnett County. We've gone pretty slowly on it so far this year to make sure of the extent of it and to kind of tweak our completions and everything. And then we will plan to accelerate the activity as we get into '06 on it.

Are you still maintaining 100 to 200 Bcfe range or should we expect towards the upper end of that?

I would say that is still the reasonable net Bcf range for it.

Okay, great. The Red Snapper prospect that's expected to dispose in that late '05 or '06? How long is that well expected to take or scheduled to take?

It's going to be a pretty short well to drill. That is the one that we're mobilizing a rig from West Africa and it will arrive like say sometime probably around Christmas. And the well itself is only going to take a couple weeks. But what we really need to do is drill about three wells and the three wells together will define whether we truly -- we have a reserve range on this net to us of a potential of somewhere between 350 and maybe 500 net Bcf. And one well won't tell us the whole size but the three and three different fault blocks will give us a pretty idea of that.

So I think by the time we do the early February earnings call, if our timing plan is right, we may have one maybe two of those wells down so we will have a reasonable idea but we'll probably still be drilling on perhaps the third well at that time.

You touched on the risks of the Deep Ibis. What are the main risks? I think as I remember, there was a well drilled near or into one of these fault blocks. What is the main primary risks of this prospect?

The Red Snapper, the Bloc 4(a)?

Yes, Red Snapper.

That is the one where there was a well drilled about fifteen years ago by a major company. They were looking for oil and they found dry gas. And at that time gas was noncommercial in Trinidad and they just abandoned it. That is why we deem it low risk. We've got a 3-D seismic over it with lots of amplitudes. There's already been a gas well successfully drilled in it. The real question, the real risk of it is, what is the extent of the gas accumulations in there? Is it 100 Bcf gas accumulation or is it 500 Bcf gas accumulation?

So that is where I would risk the thing. We feel there's a pretty darn high chance we're going to find commercial gas well, just how big is it?

Okay. Guidance for this year, you are still expecting 15.5%. I think the range if you use the fourth-quarter range that is out there is 13.8 to 16.3 roughly. What are the assumptions driving -- what it would take to hit the top of the top end of that range? And what has to happen or what could happen that would cause it to fall toward the lower end of that range?

Probably the biggest variable is what happens with the methanol plant in Trinidad. If you had a lot of down time with the methanol plant in Trinidad just through getting some bugs out of it or something, you'd probably tend to fall lower obviously. If you had a really good run time there you might end up at perhaps 16% number or something like that. But I'd say right now, if you are modeling in the fourth quarter, I'd be pretty good to just model the midpoint. I think we're pretty comfortable with the midpoint right now.

Okay, thanks for the details.

Jeff Hayden from Pickering.

Hey, guys. Most of my questions have been answered, just a few follow-ups. Recount the Barnett, where do you guys kind of see yourself kind of year end '06 and what do you think full development would be in the Barnett?

We've got to 12 rigs running now and we'll be up to 15 to 17 rigs by the end of '06.

Okay. And then on the Western County can you give us any more color on kind of what you are doing to try to unlock that? I mean is it more the length of the lateral, the types of fracs you are using, the amount of water? I mean just a little more color on kind of what the differences are between that and what you are doing out in Johnson?

Jeff, again for proprietary reasons we really don't want to give any color. I mean one thing that we mentioned at the analyst conference and we'll mention it again, I think you can expect as analysts that you are going to get a wide range of reported results both in Johnson County and in these outlying counties from various operators. We make it sound like hey this is a pretty easy deal. You just go out and punch these horizontal wells and you get a 6 million a day well and just go to the bank with 100% rate of return. In fact these are extremely sophisticated wells and if indeed you make a mistake on where you locate the horizontal in the Barnett section or you just tweak the frac one way or another wrong, you end up with an Ellenberger water well.

And so what I would just say is that if you hear from other companies that they're having unsuccessful results in the western counties or in Johnson County, that should not reflect on EOG in any way, shape or form. We would expect a significant amount of the other operators out there to have unsuccessful results at least in the early stages throughout the Barnett Shale, quite frankly. And we're not going to be helping any of them to evolve to successful results. So that is why we can't really be responsive to your question.

Okay. Thanks, Mark.

Monroe Helm at CM Energy Partners.

Most of my questions have been answered but I was kind of curious, since you've had such good luck in Northeast Johnson County where there is -- where you don't have the water problems. Are there opportunities to pick up additional acreage there maybe in Southeastern Currant County where you -- where just maybe the population is pretty dense. I was just wondering if there's some opportunities to pick up some acreage and do some things in there since it would be the most prolific part of what you are doing?

Yes, we don't really think so, Monroe. Our view is that all of the acreage that has gotten there is pretty well tightly held unless you want to pay a monster price for it. So we've pretty much leveled off. We had said that 500,000 acres is where we wanted to level off. We'd love to have some more acreage in Johnson County. But there doesn't seem to be anyone that wants to transfer it to us at any kind of a reasonable price. So I think we're going to be kind of stuck with that 90,000 acres.

Okay. How about up in Denton County? Is there any chance to go into with some of the smaller operators who don't have the horizontal technology that you have since most of those wells were drilled on verticals? Do you do anything up there or is it just not worth fooling with?

I mean we are always open to ideas. But I don't expect to hear any spectacular news about us in Denton County. If there's any news, it will be a surprise to me.

Okay. I just didn't know given your lead on the technology maybe you'd have some people that didn't have that expertise approaching you who already had acreage or production up there. Sounds like they haven't.

Haven't so far.

Okay, thanks a lot. Great quarter.

Frank Bracken at Jefferies.

Hi. Got a little bit of a touchy-feely question but you are doing such a good job in the Barnett one of the things I would hate to do is miss-model this transition between the way you've been doing business in the 500 foot laterals. So could you give me color on a couple things?

Can you tell me with a rig how many of these 500 foot laterals you will drill in a row before you go to where you've got to complete and frac? And what do you think the entire cycle time on that process is? In other words, are you going to start to look more like stair steps than a straight line?

And then secondly kind of as a blending agent, can you talk to us about how many wells you have waiting on completion right now that might help smooth that out as you transition into this new completion methodology?

That is a good question, Frank. We are all looking at each other.

What we've been saying is it's probably going to be a year before we'll be able to assess completely what sort of new reserves adds we're having with the 500 foot spacing. We're going to be continuing to drill quite a number of 500 foot space with several of the rigs but then taking care of our acreage position to hold it.

As far as the number of completions that are waiting -- wells waiting to be completed, we've got a rather short cycle time. So there is few wells waiting for completion. We've got several completion units operating and keeping up with the drilling rigs at this time.

Yes, I guess Frank, I mean a little more color, for example, if you take those four monster wells we highlighted in our press release, we would expect that if we would drill 500 foot down space wells right beside those wells right now that we would get wells pretty much identical in initial production rates. So we'd get wells that started out at 6 million a day. So I think for modeling purposes, it wouldn't be too irrational to kind of assume all the wells are going to be roughly the same at least for the first four or five years of their life or so.

But I mean presumably you're going to drill -- you're going to take a rig, drill several -- I mean are you going to run four rigs beside each other and drill them all of the same time? Are you going to go one, two, three, four, and then frac them all in succession? Just trying to get a handle on how many wells you are going to get drilled per rig per year.

Goodness.

Goodness. What we've been doing is we've been drilling one, two, three, four, and then coming along and fracing one, two, three, four. Just having rigs in particular areas.

Yes, we will have to have Maire get back to you, Frank, maybe with a little more color on that.

Okay, thanks.

Ryan Zorn at Simmons & Company.

Thanks, Mark. I think everything has been asked. The only thing I would want to follow up on has there been any developments that you would highlight in the Uinta Basin since the analyst meeting or any particular milestones we ought to be looking for in the next six months?

Nothing really out of the ordinary. I would say that is just coming along exactly as we expected, Ryan, really. That is why we haven't really highlighted it. It's just percolating along. Yes, I guess the only other point I'd make maybe have Loren address it here is that one nuance and I'm surprised we haven't gotten a question on it here is that over and above the shale play that we've talked about here are our Stealth Texas shale we are accumulating acreage on several other domestic shale plays. It is our belief that there will be additional significant shale plays, commercial shale plays found in the U.S. probably made commercial by horizontal drilling technology of which we think we have perhaps a leg up on that.

And we have identified several of these. We are leasing on them and I think that we will have some news flow clearly on the Texas Stealth Shale play in the first quarter there as we talked about. But I think as we go through 2006 particularly in the probably in the third and fourth quarters, maybe in the second, we will likely have some news flow relating to some other shale plays that obviously we think have a fighting chance to perhaps duplicate the Barnett.

So we've gotten a bit more aggressive on acreage acquisition on some of these based on our confidence factor on how well the Barnett is working and our understanding of what we think makes the Barnett work. That is something that we believe is kind of an upside that we have moved up on our scale of priorities over the last 90 days.

Okay but those areas would not be limited just to the Uinta? Those are rather (multiple speakers)?

Yes, that's really got nothing to do with the Uinta Basin. We don't have any shale play in the Uinta Basin.

Okay, thanks for your time.

Brian Kuzma at RBC.

Hi, guys. One quick question about Appalachia. I was wondering if you guys bid at all on the Columbia natural resources properties? And how you guys in view Appalachia going forward?

The answer, Brian, is no we did not bid. Again our strategy is not to do any large M&As so we were not at all in the bidding game for the Columbia resources properties. We do view Appalachia as having some growth potential particular for unconventional gas. We're taking a more traditional route up there and attacking the unconventional gas. We've got a small presence there. And we believe we can grow it over the next five years but we really don't have anything specific to point to at this point in time relating to that.

Okay. And can you also comment on the extended Cotton Valley wells for example that you guys listed in the press release. Are these development wells in the middle of your field? And what is the exploration potential either from stepouts; these other fields like Eros and Cheniere Creek or other formations in that area?

Yes, Brian, the wells that were reported in the press release I think is the Martin Timber Company and the Osborne well. Our development wells, one of those in is in Vernon Field, a development well in the south end of that field and the other is in the Driscoll Mountain Field, a field that we actually discovered with our partner last year. Or actually earlier this year.

There are additional exploration prospects being generated in that play by ourselves and others and the one we mentioned in the conference call here is called Eros, a brand new structure that has never been penetrated that we mapped up and captured about half of and share in a joint venture with another company. In evaluating via 3-D seismic we shot that 3-D now. It did confirm a beautiful structure that looks very much like Vernon in terms of size and morphology and timing in effect. And other operators has drilled a well some 4 or 500 feet off the plank that was successful. So we feel like it's a very strong prospect.

At Cheniere Creek, we've also captured about half of that and are moving forward to get a 3-D shot there in the first quarter of '06. We will be testing (indiscernible) prospects next year. We have an additional probably five or six prospects on that trend that we are leasing on right now.

Okay and are there any other formations you guys can go after in like the Driscoll Mountain Field or do you guys feel like you have already gone after all of those?

There are secondary objectives in that field that we will be testing in due time. The main event there is the expanded Cotton valley.

Thanks, guys.

Tim Jenkins (ph) at Dolphin Investment Advisors (ph).

Hello, thanks. This is another touchy-feely sort of bigger picture question from a non-geologist type. I'm curious, your success with improved completions in shale are obviously very impressive and there appear to be Barnett rumored to be the best shale around but there appear to be fairly extensive other shale conglomerations or Fayetteville and etc. that I'm sure you are aware of. I'm just curious from a longer-term point of view if you think that this type of unconventional resource along with tight gas sands and whatever are going to fill the gap in the big picture shortage of onshore domestic gas?

Can you comment on that and give us a bigger picture, longer-term view? Where you think the technology is taking us?

Yes, I think on a micros sense if you look at year-over-year gas production in the U.S. prior to Hurricanes Katrina and Rita, production was down about 1.7% and that is with the industry throwing as much capital at it as it could possibly do. My sense is that there will be other shale plays found probably not as big or prolific as the Barnett but there will be some found. And it will help ameliorate the declines. But I just -- I think with particularly with the Gulf of Mexico declines we're likely to see over the next five or ten years that I don't see it that we're going to find enough shale gas to create a gas bubble if you will to create a surplus of gas or anything. I think it's just going to create much-needed gas but not really turn around the macro picture for North American natural gas.

Thanks.

Ray Deacon, Harris Nesbitt.

Just wondering where you're getting your highest rates of return? Is it Barnett, Rockies, Permian? Is there any color on that?

Yes, that is real easy, Ray. It's the Barnett. I mean clearly that is why we're so pleased with the Barnett is if you look at it, we've got potentially 4000 or so plus or minus locations if you believe all our acreage works. We will be pumping literally billions of dollars into that over the next multiple years. And potentially all of it will be at somewhere between a 70 and a 200% rate of return. And if we already feel like we lead the league in ROE and ROCE, what that's likely to do to our ROE and ROCE over time relative to the rest of the peer group.

So that is the issue is that as we look at our internal opportunity suite, the Barnett is just head and shoulders above every, essentially everything else. And certainly in terms of things where we can pump a lot of capital into, it is head and shoulders the number one.

Okay, thanks.

David Snow.

You had said if you drilled 500 feet down spacings on those four monster wells you'd get the same pretty identical flow rates. I'm wondering for the first four or five years, does that mean that if you -- the difference that you reported for those 500 foot spaced wells which was more like 2.5 or 3 million a day -- those same rates would have been obtained on 1000 foots? In other words, you're getting the same -- you expect to get about the same first four or five flow rates for the first four or five years on your down spacing in general?

Yes, the one I quoted there, David, if we would have drilled those wells on 1000 foot spacing, we expect the initial rates would have been between 2.5 and 3.1 million a day. Yes, that is just an area that is probably a little less prolific than some of the other areas.

Okay. And let me just ask one other follow-up to that touchy-feely question about the shale plays in general. When coalbed methane came along in the late '80s, I wasn't able to put a percentage handicap but it looks like in hindsight about half of them have worked. What kind of -- we're early days -- but what percent would you put on shale plays working?

I can't really give you a handicap on that, David. For a long time people thought there was not another Barnett Shale out there but you've got several shales that have already worked. You've got a shale up in Michigan that has worked to a large degree. You've got a shale in Appalachia that has worked. So there has really been three of them that have worked to the scope of over a Tcf. We think there's probably several others. But I can't give you a handicap as to what the odds are.

Okay. Thank you very much.

You bet. Okay, just to summarize, I want to thank everyone for the Q&A and we believe we've got everything on track at the Company. And thanks for taking the time to listen.

Thanks again everyone. That will conclude today's conference call. Have a good day.