EOG Resources Inc (EOG) 2004 Q2 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources second-quarter 2004 earnings conference call. Today's 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 the press release announcing second-quarter 2004 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 of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottoms of the investor relations page of our website. Investors are reminded to review our website for the latest investor relations presentation.

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

We filed an 8-K with third-quarter and full-year 2004 guidance yesterday afternoon, which I hope that you have seen. Our 8 percent production growth target for 2004 was reaffirmed, and we increased our 2004 expected CapEx excluding acquisitions from the originally stated 1.1 billion to a current estimate of 1.3 billion. The increased CapEx is based on increased leasing activity in the Barnett and elsewhere, modestly increased development drilling, and increased pipe and service cost. However, the overall budget increase including acquisitions will likely be less than $200 million, because to date we have spent only $2.7 million on producing property acquisitions; and we'd anticipate spending 100 to $200 million this year on property acquisitions, but they are just too expensive.

I will now review our second-quarter net income available to common and discretionary cash flow available to common; and then I will discuss operational highlights. As outlined in our press release, during the second quarter EOG reported net income available to common of $142.2 million or $1.20 per share.

For investors who follow the practice of those industry analysts who focus on non-GAAP net income available to common, to eliminate mark-to-market impacts and to exclude the impact of the tax benefit related to the reduction of the corporate tax rate in Alberta. Canada, EOG's second-quarter adjusted net income available to common was $123.1 million or $1.04 per share. The reconciliation of GAAP to non-GAAP adjusted net income available to common is found in our earnings press release, which is posted on our website.

For investors who follow the practice of those industry analysts who focus on non-GAAP discretionary cash flow available to common, EOG's DCF available to common for the second quarter was $359.9 million or $3.03 per share. The reconciliation of non-GAAP discretionary cash flow available to common, to net cash flow by operating activities, is found in our earnings press release.

I will now discuss our operational highlights. We continue to feel very pleased with all of our ongoing activities, and we remain enthusiastic about our emerging Barnett Shale extension play. Yesterday, we furnished an 8-K with third-quarter and full-year 2004 guidance reaffirming both our 8 percent full-year production growth and our unit cost guidance provided last quarter. We have adjusted our full-year production forecast to account for higher U.S. NGLs and lower U.S. gas caused by increased processing of our rich-stock (ph) Texas gas. But our full-year forecast on an MMcfe basis is unchanged.

I will first discuss each of our major operational areas, including trends added in the North Sea, and I will then conclude the operations segment with the Barnett Shale review. In South Texas, we have continued our hot streak of results from all 4 of our geological plays, the Roleta, Lobo, Frio, and Wilcox. But the upside news is that our Roleta and Frio results have been better than expected.

Our single biggest South Texas play is the Roleta, and we keep getting upside surprises there. Our likely Roleta reserves under captured acreage is bigger than we had previously thought, because the number of commercial sand packages identified on our 3-D seismic has increased. Simply put, this increases our inventory of likely Roleta drilling locations by about 30 percent. A typical recent well is the 100 percent working interest Slator Ranch H-3 that is producing 10 million a day with 4,000 PSI flowing tubing pressure.

So far this year, our Frio program has yielded outstanding results. Two recent wells are the 100 percent working interest Ponderosa Ranch #1 in Matagorda County, which had 75 feet of pay; and we expect it to be a 10 million a day well after completion in September. Another is the 59 percent working interest Brooks #3, which tested at a 10 million a day and 840 barrel of condensate per day rate, with 5,000 pounds flowing tubing pressure.

Regarding our Wilcox program in South Texas, we are continuing to drill successful wells in the previously reported Henley area in Lovaca (ph) County. Our most recent well, the Henley #4, encountered 150 feet of pay, and after completion we expect a 15 million a day well. Our working interest here is 50, five-zer0, percent.

In the midcontinent, our standard fixed-rig Hugoton Deep and fixed-rate horizontal Cleveland plays are working as expected. The new news from the midcontinent is that we captured an additional 30,000 acres of horizontal Cleveland and Morrow acreage via a farm-in from a private operator. This expands our already multi-year inventory of horizontal Cleveland drilling locations.

In West Texas, we are currently operating 4 rigs in our horizontal Devonian program, increasing to 6 in the next month. The play is proceeding with similar results for those reported last quarter. But the new buzz here is that we are applying some of the horizontal completion improvements learned from our Barnett Shale activities and obtaining better results. Our first attempt to use the Barnett completion technology was in the Perdot 101 (ph) #2-H well; and early results indicate we are getting the same productivity from this single lateral Devonian well as we have previously gotten from dual lateral wells. We plan to use this type of completion on a single lateral well that just finished drilling and a dual lateral well that is still drilling. This has obvious positive implications for our West Texas horizontal programs.

In the Rockies, during the third quarter we plan to drill our first 40-acre down-spaced wells in our Utah, Uintah Basin, Mesaverde play. We feel that the Mesaverde can be down-spaced to 40 and likely 20-acre spacing without affecting offset well performance. Our current reserve bookings here are based on 80-acre spacing. We feel the value of EOG's Utah position was recently ratified by the price of the recent Westport/Kerr-McGee transaction.

Our Eastern Montana Bakken siltstone 2-rig horizontal oil development also continues to be successful. Two recent examples are the Stettler 1421 and the Joe 1-H (ph) wells, flowing 650 and 480 barrels of oil per day each. We have 100 percent working interest in each of these wells. Last year, we farmed into 70,000 acres of Wyoming, Moxa Arch, Dakota development from a major, and our initial estimate was that we could economically drill up to 150 wells on this farm-in. Now that we're 6 months into the drilling program, it appears that we have over 200 viable drilling locations; and we therefore plan to increase the rig activity here from 1 rig to 3 rigs in 2005.

Regarding EOG's Rocky Mountain Big Target plays, our flow testing of our Merna exploration well indicated noncommercial flowrates, and this well was written off in the second quarter. Our completion on the Webb Ranch prospect was complicated by drilling problems that caused us to attempt a mechanically crippled completion through the drill pipe; but the results are sufficiently encouraging such that we will drill a second well during the first half of 2005.

In Canada, our 1,300 shallow well program is underway, including 100 Horseshoe Canyon coalbed methane wells at Twining. As usual, our Canadian production growth will occur during the second half of the year as these shallow wells are tied in. Additionally, we are excited about our Alberta Drumheller field deep -- deep being about 4,500 feet -- test under the 2,500 foot shallow field pay sands. To date, we found additional pays in 21 of the 22 deep tests that we have done on this acreage; and this bodes well for deeper potential across our 150,000 acre field.

In Trinidad, we're happy to report that the Nitro 2000 Ammonia Plant has started up ahead of schedule, and our second-half sales volumes to this plant have already ramped up. On the drilling side, we just finished completing several wells to provide several 100 million a day of deliverability to meet our expanded 2004 and 2005 contracts. For the rest of this year, we plan to drill 3 exploration wells -- one 55 percent working interest well on the U(b) block, and two 100 percent working interest wells on the lower reverse L block.

Additionally, we have concluded a preliminary agreement with BP to jointly drill a 21,000 foot test on EOG's SECC acreage to test formations deeper than ever previously drilled in Trinidad. This prospect has multi-Tcf potential and will likely commence drilling in the first half of 2005. Also, we're making good progress on our 30 million a day contract for Atlantic LNG Train 4 and expect to have it signed by year end. This will be our first Trinidad contract where the wellhead price is directly linked to Henry Hub.

Switching to the UK North Sea, we just finished flow testing our Valkyrie discovery well at a gross 120 million a day flowrate. That is 30 million a day net to EOG, and we expect to commence sales in late August. This will be EOG's first North Sea production. Additionally, we expect to commence sales from our Orso (ph) discovery by December 1, achieving a 40 to 50 million a day total year-end net exit rate combined from both wells.

We have been surprised at recent strong UK gas prices, where the UK futures strip indicates 38.5 pence per therm for the first-quarter 2005. This equates to around $7 per Mcf at current exchange rates. Additionally, we expect to drill 1 EOG operated Southern Basin 100 to 200 Bcf exploration well before year-end.

To summarize, all of our ongoing activities throughout the Company are yielding results that are equal to or better than expected. I am particularly pleased that the timing for our Trinidad and UK production ramp ups are on schedule, which isn't always the case for international projects. The point I want to make here is that the pre Barnett Shale EOG is hitting on all cylinders, both domestically and internationally.

The disciplined strategy we have employed is paying dividends in all areas. Because of this strong performance, we have not reallocated any capital away from these areas toward the Barnett. We want you to view the Barnett as additive to the EOG that existed pre Barnett in terms of production growth, capital requirements, and reserve growth.

Now let's turn to the Barnett Shale. I will start by saying that based on production, geologic, and acreage acquisition results, we continue to be very excited about the potential of this play. I will also reiterate that we are very early in the learning curve regarding this play, and the Barnett will have only a small impact on 2004 production and reserve add results. The results will manifest themselves in 2005 and later years.

To date, our main Barnett focus has been twofold. First, we focused on capturing a dominant acreage position in the non-core area regarding this emerging play, and we think we are there. So far, we have captured 258,000 net acres, all of which we think are in the prospective fairway outside the core area. We spent about $45 million or $175 per acre for this position.

Second, we focused on proving that horizontal drilling can economically extract this very large resource, and we feel that this has now been proven by EOG, Hallwood, and other operators. To date, EOG has drilled and completed 15 horizontal wells and has another 5 wells drilled and waiting on completion. Production is currently limited by pipeline bottlenecks, which are expected to be removed by year end.

Now that we have achieved the desired results on our initial goals of capturing a big acreage position and proving the horizontal concept, I will articulate what we know today about this play and also what we don't know along with the time line regarding some of these unknowns. I will start with the punchline that we are reiterating our previously disclosed reserve potential net to EOG of 0.5 to 2 Tcf. I will also stress that most amazing things to me about this play are the economic characteristics, i.e. high reserves of 1.22 to 2.5 net Bcf per well, and relatively low all-in well costs of $1.4 million per well, yielding close to triple-digit reinvestment rates return based on the current futures strip.

Items that we currently feel reasonably firm about today are as follows. First, we believe as the USGS does, that this play covers an extent larger than just Johnson County, where we have drilled all of our wells to date. In fact, almost all of the incremental 83,000 acres we have leased since last quarter's 175,000 acre report are located outside Johnson County, whereas about half of the original acres we reported were in Johnson County.

Second, we believe that 3-D seismic is essential to achieving a 90 plus percent drilling success rate with horizontals. This is different than the core area, which was developed with vertical wells and minimal seismic.

Third, we think we have got the horizontal direct drilling activities nearly optimized, and we can now routinely drill these wells in 9 days instead of the 30 days when we started this program.

Fourth, we have determined that the reserves per well achieved are very sensitive to the well placement and well completion methodology, and we are not nearly optimized on these parameters yet.

Now, some things we don't know and timelines are as follows. First, well spacing. Currently, we're spacing wells every 100 acres, which would result in 7 percent recovery of the gas in place. It's possible that 50-acre spacing may be more applicable, which would likely double the number of viable drilling locations for us. We will drill our first 50-acre 3 well pilot program during the third quarter, which means we will be able to make a judgment regarding spacing sometime in the second quarter of '05, after getting some production history from these pilot wells.

What we're going to be looking at regarding production history are what sort of initial rates do we get from these wells; do these wells decline faster on 50-acre spacing than wells on 100-acre spacing; are we see any bottom hole pressure aberrations relative to the 100 acre spacing wells. So that is what we're going to be looking at once we get these wells on line. It will take us probably 90 to 120 days just to watch these wells after we get them completed.

Secondly, what is the optimum achievable reserves per well? We've noticed improvements in reserves per well based on advances that we and offset operator Hallwood have made in completions; and we expect that by year-end we will have some good answers here as to what is the optimum way to complete these wells.

Third, what about areas outside Johnson County? We expect to get 3-D shot in several of these acreage blocks outside of Johnson County before year-end and should have drilling results in the first quarter relating to several of these blocks.

To summarize, most of our drilling over the next 6 months will be in Johnson County. We have made great progress capturing a big position in this emerging play. But until we understand the play thoroughly and get the completion methodology optimized, we are not going to rush into a drilling frenzy here. We intend to develop this play in a deliberate well thought out manner. I will now turn it over to Ed Segner to review CapEx, capital structure, and our hedge collar position.

With respect to capital expenditures for the second-quarter 2004, exploration and development capital expenditures were $342.7 million, including $1.5 million of acquisitions. Year to date, exploration and development capital expenditures were $609.2 million, including $2.7 million of acquisitions.

Capitalized interest for the quarter was 2.1 million; year-to-date it is 4.2 million. We have increased our estimated 2004 CapEx program excluding acquisitions from approximately $1.1 million to approximately $1.3 billion, as indicated in the 8-K, as a result of increased leasing activity in the Barnett and South Texas, by about $50 million over original plans, modestly higher development drilling expenditures, and higher tubular and service cost.

With respect to capital structure, at June 30, 2004, total debt outstanding was approximately 108.6 million; and the debt to total capitalization ratio was 30.5 percent, down from 33.3 percent at year end 2003. At quarter end, we had $68 million of cash on the balance sheet. Given current commodity prices, expected production ranges, and taking into account our increased capital expenditure estimate, we would expect to further reduce our debt to total capitalization ratio to around 28 percent at year end.

The effective tax rate for the quarter was 32 percent and the deferred tax ratio was 77 percent. The second quarter 10-Q will be filed later today. Regarding hedging, our hedge and collar position has not changed since we furnished an 8-K to the SEC on July 6. Now I will turn it back to Mark for concluding remarks.

Thanks Ed. Let me give everyone a little perspective on what our logic is relating to our hedge and collar position on a go-forward basis. Our view of the 2004 North American supply situation is that domestic gas will fall 2 to 3 percent this year, and Canadian production will be flat or slightly up relative to last year. After adjusting for higher year-over-year LNG imports and Mexico exports, we expect overall U.S. supply to decline the 1.7 Bcf a day this year. In 2005, we expect a further 0.7 Bcf per day supply constriction.

Accordingly, we are essentially unhedged starting November 1 and for 2005 and forward for natural gas. Regarding oil, we are essentially unhedged beginning this month. Given the tight supply situation, we are reticent about adding any hedges or collars at this time for late 2004 or for 2005.

Now let me summarize by reiterating our strategy. We continue to believe the highest reinvestment rates of return are generated by organic growth through the drill bit, and we have geared the Company to that end. We will continue to run the Company maintaining a low debt level. We're currently long on attractive reinvestment opportunities; and during the second quarter, we opened 2 new division offices, one in Fort Worth to focus on the Barnett and one in the London suburbs to focus on the North Sea.

Our North American programs excluding the Barnett are doing great, and the Barnett itself continues to look very exciting. We will develop this Barnett asset with patience and deliberateness. However, the most powerful thing to me about the Barnett is the awesome reinvestment rate of return opportunity. We believe the asset we have captured will allow us to reinvest at least $1 billion over a number of years at after-tax returns approaching triple digits. Simply put, that is a large-scale reinvestment opportunity at huge returns that most of our peer companies don't have in their portfolio. During the past 5 years, EOG has led the peer group in ROE and ROCE, and we believe with the Barnett in our arsenal we have a leg up on leading the group again for the next 5 years.

Regarding our activities outside North America, we are pleased with our profitable growth positioning in Trinidad and the UK. As of now, our 3-year production growth forecast is 8, 10, and 7 percent. I will remind everyone about our September 30 annual analyst conference in Houston, where we will discuss updates regarding our '05 and '06 production growth forecast, as well as a lot more details regarding our reinvestment opportunities. Thanks for your attention, and now we will go to Q&A.

(OPERATOR INSTRUCTIONS) David Khani with Friedman, Billings, Ramsey.

Quick question on the Barnett, which I'm sure people are going to focus on today more. What is your NOI on now your bigger acreage position?

I don't want to get too specific just due to competitive leasing there, but for a very rough term, about an 80 percent NRI (ph) is one way to look at it there, David.

Great. On that $1 billion of CapEx that you guys think you're going to spend over the next several years, how many wells are you using to get to that number? Is it the $1.4 million roughly per well?

In rough terms, what we're saying is roughly 700 wells at $1.4 million kind of get you there.

Okay. Great. On the horizontal Devonian, where you are talking about the Barnett completion, is that the light sand frac that you're talking -- is that what you mean by that? On the completion?

No, it is not really the light sand frac. It is really how to distribute the frac more evenly across the lateral; and that is really what we are working at with the Barnett and some of these others. One thing we have talked about for 3 or 4 years as that we have become a Company that focuses on, I guess, horizontal drilling development of tight reservoirs, whether it is shale gas or whether it is just tight sandstone. The horizontal Cleveland, the horizontal Devonian, and so on and so forth.

What we have found are all of these reservoirs are extremely sensitive to the kinds of completions. Another good example is this Bakken siltstone in Eastern Montana where we're running 2 rigs right now. What we have learned is that some of the things we are doing -- trying right now in the Barnett to basically get the frac more evenly distributed over that roughly 4,000 foot of 6-inch diameter tunnel of the horizontal, that we're now applying some of those, going back to look at some of our earlier horizontal programs.

And right now, we're kind of one for one with our first experiment in this horizontal Devonian in West Texas. So it's not much so much the profit (ph) or anything. It is kind of how you get the frac placed along this lateral.

Great. That is what I had for you. Thank you.

David Heikkinen, Hibernia Southcoast.

I wanted to go through per well year, each rig. Is it 35 to 40 wells per rig per year? Is that about what you are running?

For the Barnett?

Exactly; I'm sorry.

The way to look at the Barnett is it's basically about 25 wells per year. When we say we drill them in 9 days, when you put -- that is really from when you start drilling to when you finish and you TD the well. But then you have to run the casing in well. And then you have to move the rig to the next location. What it really turns out to be is it's really 15 days per well from (multiple speakers) finish. So that is really -- it takes -- you get 2 wells a month in.

Okay. So for a completed well it is 15 days? But drilling time is 9 days.

Yes.

So then it is like a 5 to 7 rig type program over the next several years, is what you're -- or 5 to 10? What is the (multiple speakers) ?

We are still -- at this stage it looks like more like a 3 to 5 rig program for next year, not 7 to 10 rigs or so. What we are finding on this thing is what we have found so far it is that you can outdrill yourself on this thing. In other words, where we are right now is we've got an issue that the pipeline bottleneck is obviously constricting us right now.

But even more so than that, it is real easy to drill them, but as with every well we're trying something different on the completions, -- but if you run too many rigs, you just get so many backlogged wells waiting on completions that you just get yourself backlogged. So it is not like a machine where you can just say, okay, we're going to run 10 rigs or 15 rigs.

The other issue here that makes it a bit different from the core area is the 3-D seismic limitations. In other words, in the core area, you could choose to run 10 or 20 rigs because you were not dependent on seismic. Here, what we're going to have to do on this whole program is -- and the way we have leased this acreage, David, is most of this acreage was leased is in blocks, contiguous blocks of between 20 and generally 50,000 acres in size.

So what we do is, we have got a chunk of acreage that is one of those blocks; and then we go out and we shoot a 3-D seismic over that contiguous acreage block; and get it interpreted. So but from the time you permit that seismic until you actually get it interpreted is usually about a 6-month time lag. Then you can start drilling on it.

So for example, we have leased some of these acreage blocks outside Johnson County and right now we're permitting the seismic, and in a month or 2 we will be shooting it. But that really means we will be drilling on it probably in January. So, it won't move as fast as some people think in terms of developing this. You just can't magically turn on and say I'm going to start with 10 rigs or something.

Are you seeing a lot of unitization on nonoperated wells being proposed coming across your leases? How much of that is going on? Whenever you think about -- you will have 3 to 5 rigs running, but would you expect nonoperated rigs to be active as well?

There will be some of that. But what we have tried to do -- there appears to be in most of the areas -- for example where we are drilling in Johnson County now, we have got between 100 and maybe as little as 80 percent working interest in the stuff. And where we have seen it, the operators have gotten together and said we will go together on drilling it. There's some of that, but I don't think that is going to be a major issue. But most of our stuff we have attempted to lease at a 100 percent, and for a fair amount of it we've got that pretty well done.

Okay. Some of your other bigger target plays, the Webb Ranch play that you had, you were cautiously optimistic the last conference call. Still looking positive there?

Yes, as a former engineer in my previous life, I'm still optimistic about that play. What happened in that is it was a well where we had some mechanical problem in drilling it, and the well kicked on us when we got to total depth. And rather than run the risk of having a well control issue, we just elected to cement the drill pipe in the hole; and we never really got a log on the well, except a caseful (ph) log.

So we ended up with what I call just a mechanically crippled completion. And the well is making -- the last time I checked it was making 600, 700 Mcf a day and some water from a very limited fracture treatment. So, my sense is that if it's doing that well from a command mechanically crippled completion, that when we drill a second well and get it done right, that we will end up with something pretty good there.

So, I am -- I would say cautiously optimistic would be the tone I would put on that. Again, the reason it will be early next year when we drill the well is just that it's in Wyoming; and just to get a federal permit -- it is on federal lands -- (multiple speakers) it just takes a long time.

Then you had an ultradeep well in Texas you were going to be drilling. What is the status of that?

Actually we have got several (multiple speakers) deep wells. We had the 4 in the Rockies that we have talked about previously, including Webb Ranch, and the Merna and Sage, which we talked about before that did not work, or were lower perm type completions.

Then we had another success in Uintah Basin. In the Gulf Coast we have got 3 deep tests that we will be drilling during the year here, too, which we have already drilled and they look like discoveries for us. That (inaudible) is drilling right now. Then we have a couple in Canada too that we would consider big target type wildcats.

I have one in my notes that had potential for a Tcf potential. Is that the one that that is drilling now or am I off base with what I had in my notes?

The one we showed that had a Tcf potential is a clone to the Barnett Shale. It's basically one -- what we are looking for -- somewhere in the state of Texas, we're keeping its secret, is we are leasing acreage right now on what we hope to be another Barnett Shale. What we said is sometime in the next 12 months, we will have a well drilled on it, and we will have an answer as to whether it works or not.

Okay.

That one, where we are is we are leasing acreage right now.

I guess with the increase in capital spending and $600 million year-to-date, the increase was leasing; but you also had some additional just kind of general activity. How much of it was for services cost related, on a percentage basis, out of the 200 million?

Over half of it. Probably I would guess about 125 of the 200 was. Probably 50 of it was incremental lease cost; maybe 25 was incremental development drilling; and unfortunately about 125 million was just higher service costs. And of that 125, the biggest single thing was steel pipe cost.

Okay. I appreciate it. Thanks, guys.

Joe Allman, RBC Capital Markets.

Could you tell us what your goal is in terms of acreage in the Barnett Shale that you would like to have ultimately? Are you still aggressively acquiring acreage?

The answer is yes on the acreage side, and there is a pretty fair chance that before year-end we will have 300,000 acres. Again, that incremental 42,000 acres to get us to 300,000 will be outside of Johnson County. Acreage in Johnson County is pretty much untouchable now. You just can't get any.

So, it is fair to say that as Wall Street evaluates what this acreage is worth, I would say that stuff in Johnson County in my opinion is pretty well proven. This stuff outside of Johnson County is just not yet proven. There is nobody who has drilled a horizontal well, Barnett well, to our knowledge in these areas outside Johnson County.

But, we will probably get to 300,000 acres. Then at that point we're probably going to slow down and just decelerate our acreage leasing until we get some drilling results outside those counties, in some of these counties and see. Then we will just be guided by generally what our first-quarter drilling results in some of these outlying counties look like.

Can you talk us what characteristics you're looking for in the acreage that you have been acquiring recently? Could you also tell us what counties you are now in besides Johnson?

I would just directionally tell you that generally the counties we are looking at are to the West and Northwest of Johnson County primarily. The characteristics we are looking for are if anybody in the last 20 years has drilled and completed a horizontal Barnett well in these counties; and if the well has a production life that shows relatively flat production, even if it is say relatively low rates.

In other words, if you looked at Johnson County just 2 years ago, and you looked at some of the Barnett wells that were there, they looked pretty sorry. But you could look at the production history from them and you could discern some characteristics from them. We are looking for those same characteristics in some of these other counties.

Okay. With the most recent well as you have drilled, do you think that on a reserves per well basis, you're closer to the 2, 2.5 Bcf per well versus 0.5 Bcf per well?

Closer to the 1.2, not the 0.5. The range we gave was 1.2 to 2.5 in there.

Sorry. Yes, in other words are you closer to the higher end than the lower end, do you think?

There is data that would lead us to believe that, but I don't want to lead you one direction or another yet. I would say we will tell you some more September 30, but for now we're just going to stick with the range that we gave you right now, at the 1.2 to 2.5 and the 0.5 T to 2 Tcf.

In terms of the acreage that you have, based on the data you have now, what percentage of the acreage do you think you will be successful on? I know there are some issues with carcing (ph) faulting (ph) in the basin, but my understanding is that is about 20 percent of the acreage. So what percentage of the acreage do you think you'll be successful on?

The numbers that we have been kicking around internally based on the 3-D that we have shot, which is about 72 square miles -- and probably by around the end of the first quarter next year we will have an additional 250 square miles shot in various acreage blocks that Mark described for you. The number we're kicking around internally is more like 50 percent, 60 percent, something like that will be drillable. And with improved technology possibly could go up from there.

That's great. If I understand you correctly in terms of the number of rigs, the per year run rate for wells per year total would be something like 100 or so?

Yes, at this juncture that is probably a decent estimate. If I sound tentative on that, it is that this target is moving. We are still in the early stages, but that is a decent range to use as an estimate right now.

Just a quick question on your natural gas supply outlook. Do you think in 2004 that the production declines are less than they had been in previous years just because of the number of rigs we have got drilling, compared to previous years?

Yes, we believe that last year the U.S. gas production declined by 5 percent year-over-year. This year, we believe it's going to decline about 2 to 3 percent year-over-year, although the second-quarter numbers that came out looked pretty ugly. But we think it will get a little better in the third and fourth quarter. Then we think next year that the production declines in the U.S. will be about 1 to 2 percent.

So yes, the declines are ameliorating with the higher rig utilization. But we don't think that they are just -- we don't we are even going to get to a flat year-over-year decline, even in '05. So the way I look at the whole supply picture, even when you crank in a very high utilization of the existing LNG terminals for next year, that if we thought spot this year was tight on supply, next year we're going to be further constrictor by an additional 7/10 of Bcf a day out of roughly a 55 Bcf a day market.

So we're probably going to be a bit tighter next year than we were this year, and that is what leads us to believe that the prices next year are going to be -- I can't make a point prediction, but it leads us to say that we're not anxious to jump into any hedges or collars at this time for '05.

Got you. Thank you very much.

(OPERATOR INSTRUCTIONS) David Snow of Energy Equities.

Most of my questions have been answered, but I am wondering how far West do you think or geographically how far do you think the Barnett play could extend?

That is a big question for all the operators and all the people trying to catch their leases in the play right now. So we really prefer not to be very specific on that. But I think everyone is looking at maturity levels. Where is the gas? Where could it have more liquid plugging of the permeability? Looking at depth versus cost. And looking at thickness. And all those parameters come into that question. But I'm afraid we can't comment more on it right now.

Depth also?

Yes, depth to the extent that it affects reservoir pressure.

Okay. That's all I had for the moment. Thank you.

Bob Morris, Banc of America Securities.

Loren, you said that by the end of next year you will have about 250 square miles of 3-D shot. Was that correct?

Actually by the end of first quarter of next year I believe we will have at least 250, probably closer to 275. That includes the 72 that we already have and shoots in progress.

It probably won't be much different than that by year end then.

No, in fact by year end I would say we will probably have another 175 of that probably.

Okay. How close are you to optimizing the completion techniques? I know that part of the progress you have made was being able to get 40 percent of the well bore actually exposed to the fracture stimulation. How close are you to getting as much as you think you can get?

I guess one of the things that is out there, Bob, is there has been some noise about a recent well drilled by Hallwood that is alleged to be a 5 Bcf well. We have been sharing data with Hallwood, and it looks to us from the production data we have seen that it indeed is a very, very good well and appears to be a 5 Bcf well.

We have just recently done a well stimulation that -- as near as we can tell -- it is 100 percent clone of what Hallwood did, and our well is now flowing back from frac. And flowing back from frac, since you pump so much fluid in these things, takes about 2 weeks. So in 2 weeks, we will have an answer of a well that was stimulated identical to this Hallwood well. How does our well look compared to that?

So, it is literally just a trial and error thing. Then we've got another nuance on top of that, regardless of whether our well looks better or worse than the Hallwood well. We've got another nuance that we are going to be trying right after that.

My sense is by year end, we will have tried enough nuances -- and I have got to say that it literally is a trial and error thing. I would like to say that we could do reservoir modeling and do that; and we are trying to put as much science in there, but we are really reduced now to just saying, well, let's try this idea and do it on a well and see how it turns out. And then we will try that idea on the next well. But I would expect by year end we're going to have this well completion methodology pretty well nailed.

Okay. Do you think that, given that things are progressing, that at some point you will come back and consider re-fracs on existing wells to get more of the well bore exposed to add additional reserves?

We may possibly do that, but as Mark is saying we're trying quite a number of techniques and it is all in the placement technique here. The tools as well as the procedures. We will just have to see how some of these work out.

One last question is with the debottlenecking in the pipeline that you plan by year-end, what sort of exit rate '05 do you expect to have out of the Barnett Shale, net? I mean '04 exit rate.

We still believe that the exit rate '04 is going to be somewhere in the range of between 30 and 40 million a day. That is a net number, net revenue in interest number. Getting more specific on the pipeline, the bottlenecks -- 3 months ago we had hoped that by now we would have had some of debottlenecking removed. Frankly that has not occurred.

Our expectation is that by about mid-October now, that these bottlenecks are going to be starting to go away significantly, but we're basically telling Wall Street that for modeling purposes, just assume it's January 1. But we're hoping that we really get those things removed by mid-October.

Okay. Great. Thank you.

Jeff Mobley, Raymond James.

I just wanted to follow up with a couple bigger picture questions. Obviously you guys are generating very strong cash flows in this environment. If commodity prices hold your debt-to-cap will certainly approach the lower 20 percent range some time next year. Just curious what your thoughts are on deploying that cash flow. Are you giving any more serious thought to share buybacks or increasing dividends?

Secondarily, you mentioned that the acquisition market is getting fairly expensive. To turn that around, have you considered monetizing some of your non-core properties to take advantage of that price environment?

Yes, let me try and touch that on several fronts there. On the dividend front, we have a pretty predictable track record. In 4 of the last 5 years we have increased the dividend. So I would say that unless we have some massive collapse in commodity prices or so, that sometime in the first half of next year, there is a reasonable chance that you could see that we would do something positive with the dividend again.

In terms of looking at selling producing assets, we look at that differently than other companies. What we have found is that in the past -- and there was a time, you go back 7, 8, 9 years ago in our history, when we did sell some assets. In many cases, some of the assets we have sold we have had to go back and repurchase, because you sell an asset, you say there is no geologic idea left on that asset, and then you go back and you come up with some new geologic idea or some new seismic technique and you found, my gosh, there's a new geologic play underneath that asset.

So we're not a company that is heavily into selling assets and it's not so much for optimizing or anything. It is mainly because we have seen so many examples of what appear to be a tired asset, and then we shoot a new 3-D over it or we have some new geologic concept or we have some new horizontal idea that regenerates that asset. So, don't look for us to go into massive asset sales.

In terms of the concept of share buybacks versus other things, we are really gearing the Company to be able to reinvest a large amount of cash flow as we go forward, so I would say we would like to keep a debt-to-cap ratio of somewhere between 25 and 30 percent. And we want to maintain that, but we would like to be able to intelligently reinvest the money, as opposed to getting a lower debt ratio.

We are seeing a lot of opportunities in the North Sea. Trinidad, the investment opportunities there, I believe, are burgeoning. And if this Barnett plays out as we hope it will, we think that is going to be a lot of opportunities as others (ph). So that is kind of what is guiding us on our strategy in terms of the capital structure, really.

Great. Thank you very much. Nice quarter.

Ellen Hannan with Bear Stearns.

I just have a couple of follow-ups. A couple things you didn't touch on, Mark. I wonder if you could give any updates on your Canadian coalbed methane pilot program.

We now have about 120,000 net acres in Canada in what we call the Twining area, which is primarily that Horseshoe Canyon Cove that other operators have been quite successful with around us. We have drilled a total, I think, of about 17 wells in the cove; we plan to drill about 100 total this year. And I would say so far, the 17 we have drilled, that our results are very similar to the results that have been released from offset operators. We think it's quite economic.

As those 100 wells will drill this year, probably all but about 10 of those are in three specific areas -- sort of pilot programs or development pods. Those other 10 are in step-out areas where we are trying to prove up additional acreage. As far as we can tell right now all 120,000 acres should be good.

We think it is 100 in 60-acre spacing; and for our internal estimates we're assuming half that acreage is good and we still have 375 locations on it. So I would say so far everything looks like we had intended and like we had hoped. We are continuing to drill and complete wells on it. We could conceivably ramp that up considerably in '05.

All right. Question, just switching to the North Sea for a second, what kind of price assumption should we be using? You have talked about 38.5 pence per therm at an exchange rate. But in terms of net of royalties, what do you think your realizations are going to look like in the fourth quarter of this year?

Ellen, as you know, the North Sea, the gas price there is more a function of oil prices than it is even in the U.S. What I can give you quotes on -- what I can tell you on a macro picture is number 1, that EOG doesn't understand the supply-demand mechanics there nearly as well as we purport to understand it in the U.S.. So our knowledge level is pretty low. But we do know that the UK for the first time in about 30 years is going to be a net importer of gas in '05.

The futures strip, the 1-year strip as of Monday, if we wanted to hedge our gas we could hedge it for 1 year at a 545 U.S. gas price for the 1 year. The gas price on a spot rate basis as of Monday was $3.70. When we went into the project there, we used a 2.75 flat gas price, so our going-in economics are enhanced quite a bit.

So, I don't know want to tell you to use as a go-forward forecast. It would depend on what you use for crude in prices.

The net revenue interests there are equal to the working interest. There are no royalties.

All right. One last question, Mark. You did a great job in terms of outlining the running room that you are looking for on the Barnett Shale with your original acreage as well as what you have accumulated. Is it possible you can sort of put it in the same kind of context for us in terms of the South Texas, West Texas, and the midcontinent? It seems like you have got awfully good economics in these three areas as well.

Yes, let me ask Loren to maybe articulate that. That is a tough question, Ellen; I will bounce it to Loren.

What you're really asking are how do the rate of returns compare across the divisions?

I think we can calculate that so much. But I mean Mark talks about that you got an opportunity for sort of a reinvestment of $1 billion in 700 (ph) wells in the Barnett Shale. But it looks like you have similar results, similar economics in some of these plays, particularly the Roleta in South Texas and your horizontal Devonian in West Texas, as well as you're accumulating additional acreage in the Cleveland Horizontal. How much running room do you have left in these 3 things?

To that list I would add things like the coalbed methane in Canada; and I would certainly add the Uintah Basin in the Rockies where we also have a lot of locations and as Mark said potentially a lot of down spacing locations.

I guess what has been surprising to me, Ellen, over the last couple of years is that the more we understand about unconventional plays and the more we understand about horizontal drilling, and more specifically horizontal completions, which I think Gary can elaborate on perhaps, the more potential we see in a lot of these supposedly old, tired basins and old, tired plays.

I think the success we have in 1 division, for example in the Cleveland division, in taking an asset that had over several thousand wells drilled in it and finding another 2 to 400 Bcf, tells us that other types of plays like that exist in other divisions and similar type sandstones and similar type gas sands.

So I think what we are seeing is figuring out the key to a play like the Cleveland in 1 division is opening up other plays in other divisions. So I'm quite optimistic that we have got potential to last this company 5, 10 years out on these on these unconventional type plays. Specifically on tight gas sands with horizontal completions and fractured shales and to some extent coalbed methane.

Fair enough. Mark, 1 last question given what Loren has just said. What does that do to your supply-demand analysis for the lower 48?

My sense still is -- I still continue to be a little surprised by these majors. It seems to me like, just looking at preliminary in the second quarter, that they keep -- the aggregate of the majors seems to be falling at 10 to 15 percent annually pretty much every quarter. You kind of joke that a little company like EOG, if the majors keep falling 10 to 15 percent every year, at some point EOG will be producing more than the majors.

So, my sense still is that you got the independents that are pedaling really really hard and in many cases growing production; and you've got the majors that have decided they just don't want to compete in that environment.

I guess the one thing that I see that conceivably might change the whole horizon on the gas supply-demand is if we had a massive economic slowdown in the U.S. I think that absent that, I think you have got a pretty strong story going forward on the gas supply-demand. I still believe that National Petroleum Council study that came out last September is the closest thing we have to a very very accurate forecast of what is going to happen.

I think on the federal government side you really haven't seen much of anything that has improved in terms of federal land access to ameliorate the situation. So I really think that North American gas is going to continue to be a real sweet spot, Ellen, and don't see any holes in the story absent a big economic collapse.

Very good. Thank you very much.

Van Levy, CIBC World Markets.

Question, Mark, you guys have obviously become more bullish on prices, both oil and gas on one hand. On the other hand, you mentioned that acquisitions were too expensive. Can you kind of give us a sense of where you think the market is trading in terms of what prices of people are using to buy things in the marketplace?

At some point, purchasers' expectations or perceptions will have to go up on pricing or the prices actually will drop. Could you give us a sense of where the market is, and kind of where you are looking at to buy things?

Yes, I will give it to you in a sense of reinvestment rate of returns. As we look at our suite of opportunities we have in front of us on reinvestment rate of return, and I will just leave the Barnett out of here for a minute, because I think that is kind of an aberration as to the abnormally high returns we hope we can get from that.

On the drilling side, just simply buying leases in South Texas or midcontinental Rockies and shooting seismic and drilling on it, we believe with today's price environment we can get at least a 20 percent after-tax unleveraged reinvestment rate of return on our overall investment program. And that is weighting in the dry holes and all the unsuccessful stuff as well as successful.

So, the way I look at it, we have got a choice. We can put the money to work at a 20 percent IRR. If you put the money to work buying properties, basically you've got to bid at a level that if you hedged it out on a Merc, you will bid it at a level where if you're lucky you would get maybe an 8 or a 9 percent IRR on it. So, in other words, you have got to bid it on the futures strip where you get an 8 or 9 percent rate of return. Because that is the price you have to pay to win the bid.

So what you are saying is the clearing -- the Merc is somewhere around $6, $5.89, $6 -- you're saying the clearing price is somewhere running your price specs at around that level?

Yes.

And 8 to 10 is anemic. Clearly you're banking on the upside.

Yes. You've got to have some secret that you know about the property that the rest of the industry doesn't, or you just have to be willing to accept an 8 percent or 9 percent reinvestment rate of return. We believe we have an alternative to that, really, which is a 20 percent rate of return. So that is the difference, and that is why so far for us we just haven't gone that route this year.

Okay. The second question I have, Barnett Shale booking policy. What will be the booking policy in the sense of undeveloped locations? How many for each well? How many undeveloped locations will you book?

It will be booked per the SEC guidelines, and probably -- right now we have zero on our books as of year end last year. Not much is going to be booked at December 31 of this year. The big bookings will be booked really likely in year-end '05, year-end '06, year-end '07. So we expect we will probably have maybe 35 wells drilled by year end this year, and --.

So would you book 3 to 4 offsets per well? Some of the other resource based plays particularly in the midcontinent are booking 3 and 4 offsets per well.

To be honest with you, I haven't looked that hard to know. But whatever we do, we will book it strictly per the guidelines.

Okay. In terms, you have more acreage clearly in the shale now. But yet you are still talking about the same 500 Bs, 2 Ts, I guess. Wouldn't that number go up with just more acreage?

Yes, in a strict sense if it was linear, yes. But that is why we pointed out -- we said, look, all the incremental acreage we leased is outside of Johnson County. And to our knowledge, nobody has ever drilled a horizontal well outside of Johnson County, outside the core area. So until we drill a horizontal well there or so -- we're not going to --.

You are being conservative and prudent.

We are just conservative really. It's not going to be that long; I would say it will be the first quarter likely when we drill our first horizontal wells in some of these counties. So it is not like it's going to be a year before we have some answers on this.

Last question on the shale. You came up last conference call with $1.25 sort of net present value. I am looking at kind of the finding cost, if I have done this right; it is somewhere between 60 cents and $1.20, depending on the reserve per well. Short life reserves, the lease up probably is (inaudible) -- it seems that that is a low number given a $5.50 $6 scrip. Am I doing the math wrong? Or are you just being likewise conservative there?

These are really long-life reserves. The typical well profile here is a well will come on; a decent well will come on at a 3 or 4 million a day rate initially. And then it will follow off at about a 50 percent decline the first year, 30 percent decline the second year, 20 percent decline the third year, and then it will go on about a 6 percent decline for the next 15 years or so.

The DD&A rate on these things, or the finding cost, is -- if you use the 1.2 Bcf net, yes, you will get about $1 finding cost. If you use 2.5 you'll get maybe about a 50-cent finding cost or so. So it is somewhere in that range. But my sense is we have not run the NPV lately or so. I think that NPV I ran was not using the $6 gas price either. So I haven't checked that NPV lately.

It just seems like you take 60 cents a buck; throw in $1 lifting costs including severance tax; and you would have to discount. You would have -- on a $6 price tag you would have a $4 margin.

(multiple speakers) will be a lot lower than a dollar. Another thing that we really didn't mention here is -- well, if you include taxes maybe it will be a dollar. Yes, okay.

Still, it is a big -- I was just wondering if you were using a lower price tag from that.

Maire can get back to you on the details on that.

Thanks a lot.

Ryan Zorn, Simmons & Co.

Quickly I wondered if you tell us a little bit more about the location of the 50-acre pilot. Is that going to be adjacent to a good well already? Or is that going to target some virgin acreage?

No. It's going to be in an area in Johnson County where we already have a good well. All we are going to do there is just densify (ph) an area. So it is an area that we know is one of our primo areas.

Good. On the Roleta, you mentioned a 30 percent increase in your inventory there. What are you looking at in terms of reserve potential at this point?

What we have found there is basically -- all the stuff we do in Roleta is based on 3-D seismic, and what we have done is we pulled some more attributes out of the 3-D seismic; and it's allowed us to pinpoint some -- let me say slightly shallower Roleta sand packages that were ill-defined on some of the earlier processing of the seismic. So we drilled some of those seismic indicators and we found sand packages there.

So, what it does is it just opens up a lot of other areas for drilling that we thought previously were devoid of productive sand. And now we conclude, gee whiz, there is actually productive sands in those particular areas. So that is just a good example of additional seismic technology pulling more stuff out of existing data.

On your staffing, you have been above or right at or slightly above your prior peak rig counts leased in the lower 48 for about 12 months now. I guess you must feel pretty good about your ability, your staffing, your staff's ability to operate on that sort of activity level. Is that -- do you feel like you can stretch them a bit further as you move into '05, or do you have to go out and hire folks?

As you say, we've been running somewhere around 45 to 50 rigs now for the last year. We have continued to add operational experts here over that period of time. Just within the last week we have added another 2 or 3 drilling superintendents. We are just maintaining the people, knowing that as the rig count continues to increase we will have deterioration of service. So we are manning up for that ourselves. So we should not have any problem through 2005.

Thanks for all the good info.

Let me just give you a little color on that too from 30,000 feet. I think we all talked -- the drilling peak, the gas rig count last peak I believe it was 2001, 2000, 2001. Whatever it was. And we saw just a huge drop in what we thought was service company performance, drilling rig crews, frac crews, so on and so forth.

What we as EOG decided to do, we said, my gosh, we believe with these gas prices we will stretch the right fleet again at some point in the future. We said one of the things we are going to have to do is just provide better EOG supervision for that in terms of a better cadre of EOG drilling supervisors; better or larger staff of EOG drilling engineers; some of that. So we embarked over the last 2 or 3 years in just basically beefing up our in-house cadre of people, particularly on the drilling and completion side. I feel pretty good about where we are there.

Now on service company side, we have clearly seen some deterioration over the last year and the quality from the service companies. But at least from my view it's not been anywhere near like the degree of deterioration we would have seen 3 or 4 years ago. In other words, the service companies have proven to be able to better handle the quantity of work than they were in 2001 is the perception I've got.

Oak. Interesting. Thank you.

Gary Thomas is shaking his head generally yes, so he must agree with me. He's closer to it.

Thank you.

Irene Haas with Sanders, Morris, Harris.

Quick question. Mark, it really good to see your weird (ph) gas strategy playing out, after all these few years. One more follow-up question on Canada. The deeper targets, can you give a little more color on the 4,000-feete target that you are drilling? Is it higher rate, reserve for well (inaudible) things of that nature? And formation names?

We have drilled 22 of those so far; and of those 22 that are deeper than that 2,500 foot level that Mark mentioned as the overall field pay, we have averaged about 4 targets per well. Some of those are going to be larger than the shallower normal field pays. By larger I mean maybe in the half to a Bcf; or maybe even larger than that type range per well or per zone.

Likewise, they are higher permeability then these normal field pay shallow ones. So we are tracking a bunch of those wells now and bringing them on. We are going to be drilling a total I think of about 87 of these deeper type wells just in that Drumheller well this year. And a total of about 170 of the shallow wells just in that 150,000-acre position.

Great. Thanks.

Gil Yang, Smith Barney.

Most of my questions have been answered. Could you just talk about for Barnett, what your operatorship is? Is it essentially 100 percent?

Yes, Gil. In terms of the acreage, in Johnson County, pretty close to everything we have is 100 percent. We have got a small amount of the stuff; Quicksilver has maybe an 8 percent interest in some of the stuff; but pretty much everything there in Johnson County we have 100 percent.

As we went out to some of the other counties, in some cases we ended up with maybe 60 percent interest in some big blocks there. We elected to go that route. But I would say overall, we have the vast majority very high operating interest everywhere in there. But there are instances in some of the outlying counties where we do have some other partners. But the partners typically are private companies. In all cases, though, we are the operator.

Fine. Thank you.

John Bailey with Deutsche Bank.

I am going to pass, guys, and let you go.

John Herlin (ph) with Merrill Lynch.

A couple of quick ones. You said you had no perm at Merna; any kind of post-mortem?

I would say we have plenty of rock. We have plenty of gas saturation in -- I think we were counting pay of 2 to 300 feet. But after frac it just became obviously that the innate permeabilities, even with the fracturing, were maybe an order of magnitude less than what others have seen on anticlines with more curvature.

Next up, services inflation. You're making my oil field services analysts very happy today. But what are you doing to try to lock in your steel costs or other things, since you are exploitation driven?

We are pretty well locked in here through '04. We're working on contracts through '05. But we're, yes, prices go up 5 percent, sometimes just slightly more than that for '05.

As far as tubulars, most of our agreements kind of owe (ph) or kind of force-majeured out of effect. We did go in and inventory somewhere around 10 to $12 million earlier this year, seeing what was going on in the oil country tubular goods area. But we're just going to be forced to go along with the current oil tubular prices here for the foreseeable future.

Last 2 quick ones. Mark Papa, you said you didn't want to create a backlog of inventory of wells in the Barnett to complete. With these horizontal wells, you have stressed kind of the sensitivity to completion. Is there anything wrong with having a well sit idle that has not been totally completed, that would affect ultimate recoverability?

We don't think that there is anything in the formation that does anything there. The sensitivity on drilling them and completing is -- one mechanism that we are experimenting with on completions involves running some equipment on the production casing that we run through the horizontals. In other words, the current technology we're using -- and I am going to be a little bit fuzzy here, because we think we may be a little ahead of the curve; we don't want to give away secrets to anybody.

You're no fun, Mark.

But the current technology we're using on most of the wells is we're just running casing in there with no fancy gadgets on it. And then perforating that casing. But one recent enhancement is we are running some kind of special gadgets on that casing. So it kind of says that if these special gadgets work that -- while essentially as soon as you're finished drilling the well you have to know if you want to run those. So it kind of says that while you are drilling a well, you have to know how you're going to complete it. So that is what is making us say we don't want to get a backlog of these things.

That is fair. Last question for me. If you're talking about having such large net reserve exposure, but you don't want to run too hard to destroy returns, why aren't you building infrastructure, since that is an apparent bottleneck?

We are.

But I mean of size.

I guess one way to put it is we're going to have 100 million a day takeaway capacity by early in the first quarter out of Johnson County. That is just net to us on there. We are already working on takeaway capacity from some of the other counties that are also going to be challenged in this area here.

So we have got a separate team of people working real hard now on this issue. There is a pipeline that is being constructed right now by -- was it -- the Energy Transfer Company. It is a 24-inch pipeline that is being built as we speak right now, going to link up from an El Paso line into our system. So there is infrastructure work that is (inaudible) right now. I just didn't really articulate a lot of it right now.

Last one for me. Partnering, if the integrateds as you implied are kind of stepping away from North America, given some of your exploitation expertise they seem like they would be captive beneficiaries. Have you been talking to any?

Yes, we are continuing to make headway with a couple of the majors on farm-ins of consequence. Like I say, we have done some pretty big deals with BP already, big in the Cleveland program in the midcontinent and big in the Moxa Arch. We have done some other deals with one other major that I don't want to mention.

What we have found so far are that the major's responses are kind of bifurcated in that some of the majors are very, very willing to talk about the farm-ins, that they're capital constrained. So we are making pretty good headway with a couple of them. And then a couple others in the majors, they just don't seem to be amenable to that, and we are making very, very limited headway in it.

So I would say we are making progress, but we're not making progress with 100 percent of the majors on these kind of activities.

Okay. Thank you.

Frank Bracken, Jefferies & Co.

Two questions. First it looks as thought those Bakken wells are maybe the principal driver for your better oil productions. Could you outline for us the extent to which you intend to drill that play for the remainder of this year and next?

We have got 2 rigs running there in the Bakken; and we have got 2 other prospect areas working. So we plan just to maintain this rate here. It is an area that is just kind of added on. As far as growth in the Rockies, we would probably send you back towards Uintah over there with the Mesaverde and the Wasatch. That is where we are drilling quite a number of wells. We've got 4 rigs operating there in Uintah right now.

I was speaking specifically to the oil side of the equation. Secondly, could you discuss for us the extent to which you all are active applying your horizontal technology in the Abo (ph)?

We're not.

We are looking at horizontal opportunities in West Texas and southeastern New Mexico and other formations, primarily the Wolf Camp. We think there is a lot of potential for new horizontal plays in that arena, but it is nothing we can talk about yet.

Okay.

Anything further Mr. Bracken?

No, that is it. Thank you.

Tom Covington, A.G. Edwards.

Question on the Uintah Basin, the Blackhawk and Price River drilling. Could you give me a sense of how that drilling is going in terms of the productivity of the wells; and how many wells you plan to drill this year; and what your exit rates are expected to be by year end? Thank you.

The drilling is going fine. We have now got a population of wells that basically says that we're generating about -- for the deeper stuff, this is a Mesaverde, which is indeed the Blackrock and Price River drilling, that for about roughly $1 million we are getting about 1.2 Bcf per well, which generates about a 30 to a 40 percent after-tax reinvestment rate of return.

The reserve booking that we've done on this so far is on 80-acre spacing. And the drilling we have done so far is on 80-acre spacing up here. We have done a lot of reservoir depositional work here and reservoir drainage work. And the work we have done tells us that I would say it's extremely likely that this can be spaced on 20-acre spacing, which gives us a lot more locations. I guess some could argue you that you could even argue that 10-acre spacing might be applicable here.

So if you look at it on a reserve basis, on our reserve books as of year end last year we had 63 Bcf of PUDs. In terms of the potential here, 20-acre spacing I think ultimately you could get up to 300 Bcf or so net reserves to us. Maybe 3 to 400. And I guess on 10-acre spacing it would be a bigger number.

So we've got a pretty good resource captured here. The issue we have here is this is on federal land and Native American land, and the pace you can proceed up here in terms of getting drilling permits is pretty slow. The current net rate we've got coming out of here is -- what is it, Gary?

(inaudible) about 38.

About 38 million a day. I think were hoping that by year end maybe we would get up to the 44 or something million a day net rate coming out of here. I would look on this as this will be a program where we will probably drill roughly 40 wells a year every year for the next 5 or 6 or 7 years.

It is one that, unless we have some big change in the permitting process, that I doubt if we are going to be able to accelerate the drilling level, mainly just due to the location of it.

What is the timing of the EIS that is under way?

We're working on that right now. It is more than likely going to be late '05, maybe even '06. But we have got right now probably somewhere around 150 locations permitted to EOG.

Thank you very much.

Ben Shineman, (ph) with John Levin (ph) Asset Management.

I have a question about the deep Paleozoic reserves. Do you guys still own the acreage that those reserves sit on?

Yes, Ben, we own the acreage.

Being that your cash position is stronger than ever, the pipeline capacity out of Wyoming is better than ever, gas prices are higher than we ever thought they would be, and I would think there is better completion technologies, at what point do you revisit perhaps drilling a well and making a decision whether or not those are economic in going forward with drilling a well?

Our drilling schedules now for 2004 of course are filled. And then most of our divisions are working on their 2005, even talking to 2006. But, as far as our drilling schedule for '05, it's pretty well filled. We've got excellent rate of return projects within our programs.

I know, but that doesn't really answer my question.

Paleozoic, we have not looked at it in the last year, Ben. The last time we looked at it, the issue is -- ExxonMobil has a big plant there. The two issues that the last time we looked at it were -- it looked like as you get off structure, and our acreage is a bit off structure from ExxonMobil's -- and as you get off structure, you have more carbon dioxide and less hydrocarbons in the gas.

One is the emission issue in that any plant today we don't think you could get the emission waivers to vent the carbon dioxide that the past plant got. Then the second thing is, the amount of energy it takes to basically do all the processes, to strip the C)2 and all of the other stuff out of the gas, is almost as much as the BTUs of the hydrocarbons that you're capturing.

We will revisit that again in the next 6 months, but it's almost the case where you expand most of the energy of the gas that you have just to get the few molecules that are left out. So, at this stage, what my recommendation would be is, you don't put any value on our stock onto the Paleozoic.

No, there is definitely none for that. I was just sitting here thinking about it; but it was worth a shot asking. All right. Thanks a lot, guys.

That concludes the question-and-answer session. Mr. Papa, I will turn the call back over to you for closing remarks.

We want to thank everyone for sticking with us here on this long Q&A. Hope everyone can make it to the September 30 analyst conference here in Houston. Bye-bye.

That concludes today's teleconference. Thank you for joining us.