EOG Resources Inc (EOG) 2005 Q2 法說會逐字稿

Welcome to the EOG Resources second-quarter 2005 earnings release conference call. As a reminder, this conference is being recorded. At this time I would like to turn to conference over to the Chairman and Chief Executive Officer for EOG Resources, Mr. Mark Papa.

Good morning and thanks for joining us. We hope everyone has seen a press release announcing second-quarter earnings and operation 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 security filings. Some of the reserve estimates in this conference call and webcast, including those for the Barnett shale play, may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our Investor Relations page of our website. We plan to post and updated Investor Relations presentation to our website early next week.

With me this morning are Ed Segner, President and Chief of Staff; Gary Thomas, EVP operations; and Maire Baldwin, Vice President of Investor Relations. We filed in an 8-K with the third quarter and full year 2005 guidance yesterday afternoon which I hope you've seen. As we discuss our operational results in a few minutes, you'll also note our game plan remains consistent focusing on high returns, organic growth and low debt. I'll now review our second-quarter net income available to common and discretionary cash flow and then I'll discuss operational highlights.

As outlined in our press release, during the second quarter EOG reported net income available to common of $247.6 million or $1.02 per share. For those investors who follow the practice of industry analysts who focus on non-GAAP net income available to common, to eliminate the impact of an adjustment to revenue related to an amended gas sales agreement, EOG's second-quarter adjusted net income available to common was $238.9 million or $0.98 per share. The reconciliation of adjusted non-GAAP to GAAP 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, EOG's DSF for the second quarter was $556.4 million or $2.29 per share versus $358.4 million or $1.51 per share adjusted for 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.

I'll now address some of our operational highlights. You'll note that we grew our second-quarter production 20% year-over-year, all organic, and we've increased our full-year production growth forecast from 13.5% to 15.5%. We've also reaffirmed our 8% 2006 growth expectation even though we're now compounding off a higher number. Regarding 2005 and 2006, we expect to accomplish substantial 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 in 2005 in 2006 and beyond will come from two sources -- the Barnett, which captures all the headlines and, as usual, will likely garner most of the focus during Q&A; and North America ex-Barnett, which by itself is a powerful growth engine. Last year our North America ex-Barnett total production grew 6.3% and this year we expect it to grow over 8%. Let me repeat that because I believe it's very significant and a key EOG discriminator since I don't think any other company our size is generating this degree of organic North American growth.

Even if we totally disregard the Barnett, our North American growth engine generated 6.3% growth last year and we expect over 8% this year. This growth is broad based and comes from all of our major operating areas. I want to stress that EOG is not just a Barnett company so I'm going to provide some overviews of our South Texas, East Texas, West Texas, Oklahoma City, Rocky Mountain and Calgary operating areas to apprise you of the multiyear depth and impact of our inventory. I'll also quantify for you each of these major areas' first-half production growth relative to last year.

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

In South Texas production grew 10% year-over-year during the first half. You'll note that EOG's second-quarter U.S. gas volumes were at the lower range -- lower end of our forecast while our U.S. NGL's greatly exceeded the forecast range. This was primarily the results of adding a lot of rich gas in South Texas which was processed in NGL extraction plants. The South Texas production growth was driven by five different plays, all of which were simultaneously working. The Wilcox, Frio, Roleta, our Stealth play and our resurgent Lobo trend. Instead of providing a lot of individual well results I'll provide some follow-up on some items I mentioned in last quarter's call.

We're continuing to have good results in our South Texas Stealth play where we believe we've got a 100 to 300 BCF conventional gas accumulation. We've completed several 3 to 6 million cubic feet a day wells during the quarter which are generating excellent economics. On the first-quarter call we also mentioned success with the horizontal Roleta play and we replicated that success with a similar second-quarter well. This is significant because we haven't yet applied horizontal drilling to South Texas and, if we can make it work, it will open up a lot of opportunities for us. Additionally, we have one rig drilling quality Lobo wells for us, something we haven't had for a few years.

In East Texas, Mississippi and North Louisiana our first-half production grew 22% year-over-year driven by production growth from the Sligo, Branton and Driscoll Mountain fields. Development in these areas will continue through 2005, '06 and '07 and we also have a new Mississippi gas field development ongoing. So we're very pleased with progress from these areas.

In Midland our first-half production declined 6% year-over-year which was consistent with our expectations. We think we can turn Midland into a 2006 growth area based on recent successful drilling results from our 30,000 net acre Wolf Camp horizontal play we reported on last quarter. We recently drilled two good-looking offsets to our successful Nile 22 state com (ph) #1H well. And if this play continues to develop we expect to drill 100 horizontal wells over the next several years.

In Oklahoma City first-half production grew 17% year-over-year driven by our horizontal Cleveland, shallow Hugoton and Morrow drilling programs. We're well stocked with multiyear acreage for all three programs and expect to add the Wash play to our ongoing programs in the second half. Our Rocky Mountain eight rig drilling program is performing exactly as expected. First half production was up 14% year-over-year. The same can be said about our Canadian activities where production is up 16% year-over-year primarily from our 1,000 well shallow gas drilling program.

In the last quarterly call we mentioned test results from our 26% working interest Northwest Territories B44 well drilled last winter. We tested two separate zones; each zone tested approximately 10 million cubic feet of gas and 3,000 barrels per day of light oil. Now that we've had time to digest the test data, it appears we tested a high gas/oil ratio volatile oil reservoir. This coming winter we plan to test two additional wells to further delineate the multiple geologic structures we have in our leasehold.

This provides a flavor of now broad based our North America ex-Barnett growth is. I'll also note that we believe we can continue a strong pace of North America ex-Barnett growth into 2006 and through the end of the decade. Now let's talk about the Barnett.

The 60 second summary regarding the Barnett is as follows. First, our Johnson County drilling and completion activity is generating the expected results, although due to logistical reasons we didn't get as much accomplished in the first five months of 2005 as we had originally planned. As reported last quarter, we still expect the average well for this program to generate 2 net BCF for a current $1.6 million completed well cost which yields greater than a 100% after-tax rate of return.

Second, we drilled and completed three additional wells in our Jack and Hood County Western acreage in addition to the two wells in Erath and Jack County we reported last quarter. These results verify that we're definitely in the gas and not the oil window and that we expect per well reserves are likely to be between 8/10 and 1.2 net BCF for about a $1.1 million well cost which is clearly economic but not the 100% rate of return we're seeing in Johnson County. Using the $1.1 million well cost and the lower end of the reserve range, 8/10 of a BCF, the after-tax rate of return is 50%.

Note that per well reserves and well costs are lower than in Johnson County because the Barnett out west is shallower and tender (ph). However, there's still plenty of gas in place to work with. A core from our first Hood County well indicates the Barnett contains 90 BCF of gas in place per square mile compared to 130 BCF of gas in place per square mile in Johnson County. In layman's terms, that's a lot of gas in place. It's still early days regarding the Western acreage and I'll caution that we need to drill a population of 20 to 25 wells before we can make a good assessment of per well reserves and that will likely be by midyear 2006.

And then the third key point is regarding 50 acre down spacing, our first Johnson County pilot has been producing for seven months. We're currently drilling three wells for the second pilot and will have a third pilot up and running by October. We expect to make an internal technical decision regarding 50 acre spacing during the second quarter of 2006 because if we elect to implement down spacing we think it's optimum to do so early in the program while the reservoir pressures are reasonably uniform.

We've accumulated 490,000 acres, all of which we believe are in the gas window and expect to level off at about 500,000 acres which is the amount we can intelligently manage. Because of logistical slowdowns we encountered from January through May, we've scaled back our 2005 full-year average production estimate from 60 to 50 million a day, but we still expect to exit the year at about 80 million a day. Because of multiple scheduling issues we only put 18 new wells to sales through May which was considerably less than our original plan.

Simply put, we were too optimistic regarding what we could get accomplished logistically right out of the starting blocks. We've now got the necessary in-house and service support infrastructure in place and have a more pragmatic logistical assessment integrated into our go-forward plan and have increased our rig activity from four to nine with eight rigs currently running in Johnson County and one drilling in Hood County. Our current Barnett production rate is 54 million cubic feet a day.

Note that our assessment of Johnson County per well reserves and cost is the same as we provided six months ago. I'll note that in our 65,000 acre Western Johnson County position we've made great progress regarding well completion optimization and we're essentially now in a well bore manufacturing mode. In the additional 25,000 acres we have in northeast Johnson County where the Viola frac barrier is present, we obtained a pipeline hook up yesterday and can now start drilling extensively in this area where we expect to have per well results that may be even better than Western Johnson County.

To summarize, Johnson County results continue to be highly economic. We feel all of our 490,000 acres are in the gas window and during the first and second quarters of 2006 we'll have more clarification on 50 acre spacing and per well reserves on our Western acreage. I'll also mention that we have 125,000 acres leased on a Barnett look alike play elsewhere in Texas that we'll have some test results from by year-end. During the second quarter we drilled a well on this acreage and took a core sample. We'll complete this well in a few months after the core analysis is complete.

Now I'll shift to Trinidad and then the North Sea. In Trinidad we expect to commence full production during August to the M5000 methanol plant. After commissioning we expect our net sales to the M5000 plant to be 60 million a day at a wellhead net back linked to the Caribbean methanol prices which would currently be about $1.70 to $1.80 per MCF. We expect our Trinidad production will ramp up another 20 million a day net in the first quarter of '06 as we initiate sales to ALNG Train 4 which would be our first Trinidad contract directly linked to Henry Hub prices.

In early July we were awarded Block 4A at a 90% working interest. This block has a low-risk drilling prospect of 250 to 500 BCF size and we have contracted a rig and hope to get this prospect drilled late in the fourth quarter. In 2006 we expect a decision on our higher potential Deep Ibis and Deep Kiskadee prospects on our SECC Block. In the North Sea, our Arthur 2 well where we have a 30% working interest commenced sales in late July at an 18 million a day net rate, giving us a total combined rate from the discovery of 39 million a day net. So we expect our second-half North Sea production to increase over first-half levels.

We also plan to commence drilling an Arthur 3 well in December. We will likely participate in one or two exploration wells before year-end. Additionally, we participated in the 23rd bid round with applications on several blocks, and we expect notification from the UK government by year-end. So far, our major organic entry into the North Sea is on track, and we're pleased with the results.

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

For the second quarter of 2005, exploration development capital expenditures were $426 million with only $10 million of acquisitions, excluding unproved lease acquisitions. Year-to-date, exploration development capital expenditures have been $825 million, including $12 million of acquisitions, also excluding unproved lease acquisitions. Total discretionary cash flow for the quarter was $556 million. Year-to-date, discretionary cash flow is 1,036,000,000. The reconciliation of nondebt discretionary cash flow to net cash provided by operating activities is found in our earnings press release.

Capitalized interest for the quarter was $3.7 million. For 2005, our estimated capital expenditure budget is approximately 1.7 billion, excluding acquisitions, which obviously reflects higher service cost and higher activity levels as reflected in our rig count. Capital structure- wise, at June 30th total debt outstanding was $1,117,000,000, and the debt to total capitalization ratio was 25%, down slightly from 27% at year-end 2004. However, at June 30th we had $283 million of cash on the balance sheet, predominantly international.

At year-end 2004 we had $21 million of cash on the balance sheet. The effective tax rate for the quarter was 36% and the deferred tax ratio was 47%. The 8-K tax guidance range for the whole year of 33% to 37% reflects at the higher end the potential of EOG choosing to repatriate foreign earnings under the American Jobs Creation Act. We do not anticipate a decision by the EOG Board on this matter until late October. We plan to file the Form 10-Q for the second quarter by this Friday.

Now I'll turn it back to Mark to talk about hedging positions and concluding remarks.

Thanks, Ed. Regarding hedging, it appears to us that we'll likely enter the winter heating season on November 1st with between 3.2 and 3.3 TCF in storage which may make us dependent on a third consecutive warmer than average winter to exit the heating season in decent shape. Accordingly, we have no financial hedges for either oil or gas in place for the remainder of 2005 or forward.

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. We're proud of our six-year strong ROE and ROCE track record and, based on a future strip, we expect to exceed last year's 25% ROE and 18% ROCE. Reconciliation schedules for these calculations have been posted to our website. As you know, we believe that organic growth generates higher reinvestment rates return than either producing property acquisitions or M&A's. That's why we're focused on being an organic growth machine.

Second, during the first half of the year we reduced our net debt from $1,057,000,000 to $834 million and our net debt to total cap ratio from 26% to 20%. Based on the current future strip we expect to reduce our net debt to approximately $500 to $555 million by year-end or approximately 10% net debt to total cap. A reconciliation schedule of net debt to total cap is posted on our website. Third, in a rising unit cost environment we think we're doing a better job than many companies in exhibiting reasonably moderate unit cost increases.

Fourth, our North America ex-Barnett growth engine is running extremely well and this growth burst is likely to have multi-year legs into the future. Fifth, the Johnson County Barnett is developing as we had hoped and, regarding the acreage outside of Johnson County, we're now very sure that essentially all of our acreage is in the gas window. The two key unknown items that will be sorted out in the first half of 2006 are 50-acre spacing and pro well reserves in the western acreage.

And finally, no matter how you slice and dice the Company -- Barnett only, North America ex-Barnett, or Trinidad and North Sea only -- every part of EOG is an organic growth engine in a tight hydrocarbon market. More importantly, we believe we can achieve significant organic multi-year growth year after year with the assets we already have in hand while maintaining very low debt and generating free cash flow. Thanks for listening and now we'll go to Q&A.

(OPERATOR INSTRUCTIONS). John Herrlin, Merrill Lynch.

You normally address what you think U.S. production is doing. You didn't this time, so would you -- on gas for the country?

Yes, our expectation that U.S. gas production will fall for the entire year -- we believe it's going to fall by I believe the number is about 1.3% this year, John. The percent of fall will likely decline each quarter throughout the year, but we still see it in decline for the full year.

That's fine. With your increased CapEx, how much is inflation related?

Our CapEx -- the previous was 1.6, now it's 1.7 so we're up $100 million and I would guess 50 million is inflation, 50 million is just a little bit higher activity level. We're up one more rig in the Barnett than we had predicted at this time of the year.

Okay, last one for me. On Trinidad there's been a lot of articles in the press about renegotiating terms, etc. Can you talk about that?

Yes, not much of that is likely to affect us at all. I think most of the focus on renegotiating the terms or on the terms for the existing LNG contracts that are in place really. And I think the direction of that is that perhaps the government wants to call back some of the revenue from those LNG contracts and we never were a party to those contracts. So we don't see it affecting our business at all.

Great, thank you.

Shannon Nome, JP Morgan.

The logistical issues you mentioned in the Barnett, I'm guessing those are just related to the level of activity in the basin or competition from other operators?

Yes, mostly it's just we were too optimistic of really what we could get done from kind of a cold start. I guess the fundamental one is if you just take from when you start a well or spud a well to when you get it actually hooked up and going down a pipeline -- we had estimated originally that we would get that done in about 30 days per well and what it's really taken is about 50 days per well. And then when we moved the few rigs we had early in the year of those 50 mile rig moves to drill those western wells in Jack and Erath county, that took a lot longer than we thought. And then we didn't get the pipeline connects done as fast as we thought. For example, up in Northeast Johnson County there where we drilled a couple wells had some real good results we thought we'd get those wells connected about 90 to 100 days earlier than we did.

So it's mainly just I'd almost say nuisance issues. It's not issues related to what kind of production are we getting out of the wells. It's just logistical issues. And so what we did is we basically said, okay, given that we probably were just too optimistic in how many days is it really going to take from what you start drilling a well to when you get it hooked up and start selling gas from that well, let's reintegrate in our production plan a little longer period in there and let's also take into account that really for the first five months of the year we didn't nearly get as much accomplished as we wanted.

And so when you ran that through the plan it basically said that our original target was 100 million a day -- or I'm sorry, was 60 million for the full year and then we just scaled it back and said we're not going to hit that because we were short in the first half of the year. So we knocked it down to 50. But one way to look at that is basically we were short of our internal plan in the first half of the year for the Barnett and we still achieved pretty close to 20% first-half production growth.

You made it up in other areas (multiple speakers). Another question -- just kind of a technical or methodology question. When you started down space pilot, I gather you have to drill and track all these wells at once. Does that mean you have to curtail production at nearby wells? Or is there any impact at all on your existing production when you do these pilots?

Yes, what we normally do -- in the pilots that we typically do you basically drill three wells at 50 acres apart if you will, three horizontal wells. That's the first pilot we had and that will be the second pilot. And then you attempt to frac them all kind of back-to-back pretty well similarly. And what we have done is we keep all three of them shut in and then you put them all on production at the same time.

What you do see in this Barnett is you do see interference in offset wells with fracs and that's just the normal course of business. In other words, if you frac a well you'll typically see some of the frac fluid go to the offset wells in any case. So it's kind of a typical thing is what we do is when we're fracing wells we will curtail production, basically shut in production for several days from the offset wells because you don't want to have a pressure sink there to attract the frat there.

Just one more and then I'll get off. My understanding, there was a TRC order back in early June that -- hard to totally read it given it's kind of legalese phrasing -- but it read to me like there is no minimum per well spacing requirement now in the Barnett shale field which suggests if an operator decided that 25 acre spacing would work then there's no regulatory hurdle standing in the way of that. Am I interpreting that right or have you seen that?

Yes, you're interpreting it right. Basically it's our understanding that in Encana and Devon petitioned the railroad commission for that spacing order and the spacing order in layman's terms says there's no -- you can drill with no minimum distance between horizontal wells. So in theory the commission has given approval that you could drill the horizontal wells as close as you wanted to subject only to leaseline restrictions and things like that. But in theory, the way we interpret it is if you wanted to drill wells on ten-acre horizontal spacing you've got the commission approval to do it. So it kind of gives carte blanche to the industry to do what they think is optimal economically.

Very nice. Thank you, Mark.

David Snow, Energy Equities.

Could you give us the comparable economics for the Wolf camp? You said 100 horizontal wells, is that like 300 acre spacing and what kind of BCF per well in returns would you expect there?

It's on 100 acre spacing -- or I'm sorry, 160 acre spacing. So that's on very broad spacing. And the economics on that are what we believe is about 1.8 BCF or about $2 million on there. So in nominal terms a little bit over $1 finding cost on that. Ultimately you could end up with maybe more than 100 wells, you may go down to 80 acre spacing on that long-term. It's still in early stages on that, David, but it does look like to us it's got the potential to be a pretty big program.

Isn't that a little under $1 at $1.2 million for 1.8 BCF?

No, it's $2 million.

Oh, $2 million?

Yes.

And is it blanket play basically?

Yes, that's what we believe it is. It covers a large area. We believe it covers 30,000 acres that we have in a blanket area.

And are you still planning two vertical wells as a pilot in the Barnett?

Yes, the Barnett look alike play -- what our plans are right now, we've drilled the one well and cored it and have not completed it and then that core is being analyzed now. And what we are likely to do is go and drill another vertical well kind of offsetting that first vertical well and we will likely just do a vertical -- attempt a vertical completion on that well and frac it and see what kind of gas rate we get. We're not necessarily expecting that we're going to get a commercial gas rate, but we would like to see a gas rate that is 100, 200, 300 MCF a day or so as opposed to 2 MCF a day, for example.

And then based on that data we'll probably then go in and then kick that well horizontally and do a horizontal test on it. On that play -- I mean number one, we again a lot of speculation about where it is geographically in taxes, and we're not trying to be coy about -- have some aura of mystery about it. We have 125,000 acres, there is a possibility we may be able to pick up another 15,000 or 20,000 acres there and that's why we're being quiet about it. We don't want to alert any more competition than is already there.

And the real key to the play on a technical side is we know the Barnett is there. We know it contains gas. We know that there's no water above or below it, so we don't have the Ellenberger water problem like the issue -- like we have in the noncore Barnett. But the real issue is does the Barnett have what's called in situ fractures? Does the Barnett rock itself have some kind of micro fractures already in the rock? And the bottom line is if it does we're in business, if it doesn't we're probably out of business. And the core will give us a little hint of that, but really it's going to take testing a well and fracing it to really answer it.

I was trying to ask -- and I'm glad you answered that question, but I was trying to ask about the twin laterals coming out of the Barnett. Are you going to still do that pilot in the third quarter?

Okay, the stack laterals?

Yes.

We're probably going to put that off a bit yet. It'll be a 2006 event likely on that. We're going to do it but that's probably going to be moved back in the schedule here a bit.

Thank you very much.

Jeff Hayden, Pickering.

Mark, any chance we can get some well results from you on the recent Jack and Hood wells?

We're not going to give any specific results either than to say that in the last quarter we said that the Jack wells produced a little trace of oil and we've now produced them a little bit more and I'd say the trace of oil has gone to negligible oil. The Hood well, no oil. The Erath well we haven't tested any more, there's no pipeline out there, so there's no news on that. So our reading is that the oil issue is negligible -- negligible to zero basically.

And the most telling issue I'd say that we've learned really is the core that we took in the Hood County well -- our first Hood County well. And what that basically tells us is that there's plenty of gas in place to work with which was pretty critical for us. So we're quite heartened with that, but we also recognize the zone center -- and basically what we're saying is our expectation is that the pro well reserves are going to be about half what they are in Johnson County in rough terms. But we just need to drill a population of wells before we can really get that pretty well nailed down.

Okay. And on the Jack well, have you -- I know it's still pretty early -- the original one you guys drilled. The decline curve -- is it looking similar to the Barnett wells -- I mean to the Johnson wells, excuse me?

Yes, it's looking similar or maybe a little bit flatter. So we're pretty well heartened by what we're seeing there particularly if you scale it back to the very early wells we drilled in Johnson County. But as you can tell from our ratio of rigs, we've got eight rigs in Johnson County and one rig in Hood County right now. What we're really about is just building production volumes. We basically feel like we've captured all the acreage that we can manage and we're going to have one rig doing the experimenting or optimization there in Hood County and eight rigs piling up the production points on the scoreboard is what we're aiming for for the next six months really.

Okay. And the last question. The roughly 30,000 acres you guys added since the first-quarter results, where was that?

That's all in the western acreage, a lot of it in Palo Pinto County.

Okay. Thanks a lot, guys.

Joe Magner, Petrie Parkman.

I'm just curious, on the number of days to drill and complete around 50, how does that break down between the drilling operations and the completion operations?

That's not the number of days to drill and complete. Number of days to drill a well is about ten. And what that 50 days is is from the day you move a drilling rig on a well to the day that you actually start to sell gas from that well. So what happens is you move a drilling rig on and you get the well drilled in ten to 11 days, then you move that off and you have a waiting period till you start to complete the well and then you have a waiting period till you get a frac truck out there; then you frac the well and then you flow it back for a couple of weeks and get the water out of it and then at some point you then turn it into sales. It's all that time frame in there. Does that give you a little better explanation of what the 50 days is?

Yes, that's great. And there was a mention in the release about a steady drilling program for the next six years. It seems like you've got quite a few more locations that would support a program longer than that. Do you expect to add more rigs to the play or do you expect to just improve efficiencies over time to keep that program, that six year expectation in place or is that just sort of conservative based on what you know and what you've experienced to date?

Yes, I think that press release said at least the next six years. It's just that that's as far out as we're forecasting right now. But yes, if you really lay it out, we have a drilling program that's probably going to last a decade at least.

Easily.

Yes.

Okay, great. Thank you.

Mark Friesen, FirstEnergy Capital.

I just have a few questions for you. The first one, there wasn't any mention with respect to the weather issues that we've been having in Southern Alberta, Southern Saskatchewan -- lots of rain this year. Pleasantly surprised not to see that impact volumes for Canada in the second quarter. Do you expect it to impact volumes later this year?

No, not really, Mark. It knocked us out a little bit on volume, but we're still in the range and the guidance that was given in the 8-K for the third quarter has that in there. But it wasn't a severe impact to us.

Very good. Next question. You mentioned a couple times, Mark, with respect to the Johnson County that you consider all of your acreage in the gas perspective area now. Does that mean that you're not risking that acreage at 50% any more in terms of selecting the number of locations on it?

No, Mark. What we still would offer to you is that we believe that all the acreage is gas bearing and not oil bearing, but a very rough rule of thumb would be to derate the 490,000 acres by half and say that half of it is heavily carsted (ph) and faulted. I will say that that's probably going to prove to be conservative in that the 3D's that we're getting in in Hood County and Jack County, it looks like less than half of it is really heavily carsted and faulted. But for the sake of conservatism, the simplicity just whack (ph) it in half. That's a good number.

And just lastly, any guesses on S&P (ph) this year.

Aw c'mon, Mark.

Well, you know, the year's half up. I thought I'd ask.

I think we're going to do fine on overall reserve replacement numbers. My guess is in rough, rough terms North America numbers, probably $1.80 or something like that, Trinidad numbers lower than that particularly if we get this Block 4a well drilled in the fourth quarter which is a pretty low risk well there. And to the degree whatever we book on the Barnett should come in at less than $1.80. But I think what we're seeing is in North America ex-Barnett $1.80 to $2 is what's a reasonable finding cost; given today's service cost the Barnett will be lower than that. And then Trinidad will be lower than that obviously in there. But those are just kind of general terms and I believe those numbers will come out to be lower than what people are buying reserves for today.

Great, thank you for your thoughts.

I like your price forecasts; I hope they come out to be correct.

Thanks, Mark.

Ellen Hannan, Bear Stearns.

Just a quick question for you, Mark. On your liquids, you mentioned that your liquids production was considerably higher in the U.S. this quarter. Can you give us an outlook going forward what you expect that trend to look like and also give a feel for the price realizations?

Yes, on the -- I'm not sure I can give you off the top of my head a feel for the go forward price realizations, Ellen, but a significant amount of the NGLs are coming at the expense of South Texas gas volumes, so I'd almost suggest that the way you look at our U.S. gas prospectively is almost just convert the NGLs at six to one and look at the U.S. gas plus NGLs together. And you'll find that the numbers kind of compute. What we're seeing is that particularly in the South Texas Wilcox and Frio we're bringing on gas that's very, very rich that just to meet pipeline specs has to go through extraction plants. And when it goes through those plants less of it comes out as gas, more of it comes out as liquids.

So accordingly, if you look close at the 8-K we've bumped up the NGL estimates for the third and fourth quarters relative to the previous 8-K and taken a little -- actually it's at the expense of what we would've otherwise shown as higher U.S. gas volumes. And I wouldn't be surprised, frankly, if the NGL numbers -- if we actually beat the third- and fourth-quarter 8-K guidance on the NGL numbers. So we've kind of consistently underestimated the NGLs and that trend may continue in the third and fourth quarters.

I can't really give you off the top of my head a guidance as to what the third- and fourth-quarter NGL realizations are going to be relative to say natural gas prices. Maybe we can get Maire to call you back once she talks to our marketing guys on that.

That's fine, thanks. Going forward into '06 when your Barnett Shale production continues to grow, would you expect to see the same kind of an impact in i.e. higher liquids (inaudible)?

No, really the Barnett -- the Barnett for the next several years is going to be heavily, heavily influenced in Johnson County and we're hardly running any of that through plants in Johnson County. We've got gas pipeline agreements there that allow us to run that just directly without running it through plants. I do not expect to see for the next several years that the Barnett is going to change the overall NGL mix. Perhaps as you get out in 2008 and 2009 as we start attacking the Western counties more heavily it may be a little bit richer there, you might see it then, but not for the next couple years.

Very good, thank you.

Gil Yang, Citigroup.

A couple questions. Mark, you mentioned the 50 acre space, it sounds like that that test is going slower than you had thought -- because I thought that you were going to give us an update in the second half of this year. And can you just give us an update that you've got at this point?

Yes, Gil, I believe what we had said previously is that by year end we thought we could give an update. And so we slipped it a little bit there and said it will be likely first or second quarter. I don't believe we promised an update before year-end. So it's -- I guess one way to read it is that we're now -- and previously we talked about two pilots, now we're talking about running a third pilot in Johnson County. I would say that what we're seeing is that the 50 acre down spacing, the components of the economics of that are, one, going to be increase in net present value based on acceleration.

It's kind of like if you're on 100 acre spacing you can get the reserves out over 25 years, if you're on 50 acre spacing there's going to be a component of those reserves that you're going to move up from years 10 to 25 that you'll recover in year zero through ten in a 50 acre well. And then the second component will be incremental reserves that you get. And we just want to get a good technical handle on it and we're just going to try and do a pretty thorough job of that. So I'm not going to give you anything to read one way or another into it. I'll just tell you we're just continuing to gather data.

Okay. And a second question. On Trinidad, could you just outline why Trinidad was so strong in the quarter? And then secondly, how your costs were fairly flat if you exclude the growth in Trinidad? How your costs were excluding the growth in Trinidad because that's a low-cost region.

The Trinidad side, that's where we had the gas contract issue. Basically what we did is we had renegotiated a gas contract down there and it was renegotiated effective back a year previously. And so we collected some revenue from the previous year on that and that was that $0.04 difference that showed up as higher revenue this quarter.

I just meant more on the production side, you beat the high end of your guidance. What was the source of that higher production?

There was some downtime by one of the other producers down there and we were requested by the gas company in Trinidad to make up for the downtime by the other producer. So they had some higher takes from us. Actually, the methanol plant startup has been delayed a month from our schedule, so the fact that we've upped our production forecast to 15.5% should be viewed in light of our original schedule was that that methanol plant should have been up and running during July.

So we're actually upping the production forecast even though we have a month delay in the methanol plant. The cost side of the equation -- I'd say -- I think what we're seeing is that we appear to be doing perhaps a better job than many other companies in kind of leveling off the cost. We've had a pretty heavy focus this year, particularly Gary Thomas, on the cost side. Gary, you might want to speak to that.

I'd just say our overall well costs, we've been saying we'll probably increase in the 10% to 15% range and that's what we're still seeing. Maybe just 10%, but we're saying 10% to 15% just expecting that we're going to see possibly a little pressure on service cost in this second half. But really it's because of us having so many large multiple well programs and having had 50, 60 rigs running here for two years and keeping the same contractors and just continuing to improve our efficiencies.

Gary, what are you seeing on the LOE side in that respect?

We've kind of relaxed a little bit there because we're really pushing on the compression and we've had a little bit of increase in compression costs and we're now buying a few more compressors ourselves. We're also seeing a little bit more on SWD, salt water disposal -- we've got quite a bit out of the Barnett. And also out of Uinta where we've got a large drilling program. And then we're doing quite a number of workovers. The large part of the increase that you're seeing on the LOE includes transportation as well with our increased volumes we're seeing additional costs there, too.

Just to quantify a little bit, on a sequential basis how much of a pickup in LOE has there been excluding the Trinidad area?

I'll have to look it up. I'm not sure there's been more than a penny pickup or so -- has there been? -- sequentially.

We just picked up $0.03 is all.

Thank you.

Richard Wolf (ph), Sachs (ph) Investment Research.

Mr. Papa, I don't know -- first of all, very good news from you on the production side, especially the ex-Barnett. I really like to see that. Can you possibly deal at all with questions on the stock, EOG shares, specifically on insider activity?

Well, yes, --

I'll tell you what the question is, it's pretty simple. It's just that I've observed using one of those leading shareholder data services that about 35% of insider holdings, which I can see they're only like 1% of the outstandings, have been pulled off fairly recently, say June/July.

Yes. Well, I can give you a little bit of color on that. Our compensation programs are heavily skewed towards stock equity based compensation. We don't have a lot of bonus programs in place such that if the stock stays flat or goes down that the executives walk away with big fat bonuses every year. It's heavily based towards driving the stock and when the stock goes up, as it certainly has this year, you're going to see a higher level of stock option exercises.

I will say though that I have an extremely significant amount of my own personal net worth tied up in just ownership of EOG stock, not through stock options but just ownership of the stock. I think I own myself about three-quarter of a million shares of stock and I haven't sold a share of the stock itself although I've exercised some options. So I would just say to you, Richard, that with stock performance as dramatic as we've had at EOG over the last two years that it shouldn't be too surprising that some people are going to get some compensation through exercising stock options.

Okay, that's great. I just wanted to -- I mean that's what I thought was going on. And yet where I am I get questions about that and just wanted to run it by you.

Sure, understood.

Thanks a lot.

Brad Beago (ph), Clayton. One moment. Brad, if you're still on line can you please press star one again? (OPERATOR INSTRUCTIONS)

I'm done with my questions, thank you.

And there appear to be no further questions.

I want to thank everyone for listening in on the call and remind everyone that on September 13th in Houston we have our annual analyst conference where we'll go through certainly in more detail our plans for 2006. And also we'll discuss a little bit about our business strategy post 2006. So I think it will be a particularly enlightening day if you can take the time and spend it. Thank you very much for listening in.

That does conclude today's conference. We thank you for your participation and have a great day.