EOG Resources Inc (EOG) 2005 Q1 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources' first quarter 2005 earnings conference call. Today's call is being recorded. At this time I would like to turn the conference 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 first quarter 2005 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call. The SEC permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates in this conference call and web cast, 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 the Investor Relations page of our website. Investors are reminded to check our website for the latest investor relations presentation.

With me this morning are Ed Segner, President and Chief of Staff; Gary Thomas, EVP of Operations; and Maire Baldwin, Vice President of Investor Relations. We filed an 8-K with second quarter and full year 2005 guidance yesterday afternoon, which I hope you have seen. As we discuss our operational results in a few minutes, you will also note our game plan remains consistent focusing on high returns, organic growth, and low debt.

I will now review our first-quarter net income available to common and discretionary cash flow and then I will discuss operational highlights. As outlined in our press release, during the first quarter EOG reported net income available to common of $200.8 million or $0.83 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, EOG's first quarter adjusted net income available to common was $207.8 million or $0.86 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 DCF for the first quarter was 479.6 million or $1.98 per share, versus $348.7 million or $1.48 adjusted for stock split per share 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 will now address our operational highlights. You will note that we overachieved again with our first quarter production volumes exceeding the top of our guidance range. Total production grew 19.3% year-over-year, and North American gas was up 12.4% year-over-year. We are pleased to note that this growth is 100% organic. For the full year, we have reaffirmed our previously stated 13.5% production growth target, although if we continue to overachieve there will likely be some upward pressure on this goal later in the year. We expect to accomplish substantial 2005 production growth in each of our three operating areas, North America, Trinidad and the North Sea.

This quarter we have good news from all of our operating areas and I will discuss each of them in sequence. In North America, our 2005 production growth will come from two sources, the Barnett, which captures all of the headlines and will likely garner most of the focus during the 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 6.5%, and this year we expect it to grow 7.5%, all 100% organic. Even if the Barnett is excluded from our portfolio, we've got a very impressive North American growth engine.

Let me repeat that because I believe it is very significant. Even if we totally disregard the Barnett, our North American growth engine generated 6.5% growth last year and we expect 7.5% organic growth 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 the Barnett Company, so I'm going to provide some highlights from our Corpus Christi, Tyler, Midland, Oklahoma City, Denver, and Calgary operating areas to apprise you of the depth and impact of our inventory.

In South Texas, we have four impressive items to talk about. The first is our big target stealth play where we have quietly accumulated 35,000 net acres in what is for us a New South Texas county where we have identified multiple 3-D image sand targets. We currently have one rig running in this area and while we expect most wells to average 2 Bcf for $1.5 million completed well cost, so far we have drilled two anomalously high productive wells in addition to six of the more normal wells. The most recent well was currently producing approximately 20 million cubic feet per day and 500 barrels of condensate per day, with 4,100 PSI’s flowing tubing pressure.

We have 100% working interest in our 35,000 acres in this play, and believe we have captured a net 100 to 300 Bcf that will develop in 2005 and 2006. So we moved this play from what was formally on our South Texas big target stealth list into a development category now. Two recent successful wells in a different play, the South Texas Wilcox or the Aviator 2 and Buck Hamilton #11 wells, which commenced production at 12 and 16 million cubic feet per day respectively. We have 100% and 50% working interest, respectively, in these wells. We have multiple offsets to the Aviator well and expect this will develop into at least the net 50 Bcf field.

We also achieved a positive and potentially very significant South Texas horizontal drilling resolve in the Roleta zone this quarter. The Staggs' (ph) 3H well was drilled horizontally in the low permeability portion of the Roleta reservoir that was noncommercial with vertical wells, and it has performed very well. We estimate the Staggs' 3H will be a 4.2 Bcf well, (indiscernible) $3.8 million will costs and we're currently drilling two additional horizontals to see if this success is replicable. If so, this will create a lot of new running room for us.

Moving to East Texas and North Louisiana, we have three positive play results to report. In the East Texas Branton Field, we made a new Cotton Valley shoulder discovery that will likely be a 60 net Bcf discovery to EOG. To date we drilled two wells in this field. One commenced sales at 9.4 million cubic feet per day and the second is waiting on completion. We expect production here to ramp up throughout 2005 and 2006. In our previous announced North Louisiana Driscoll Mountain discovery, which is six miles west of the Vernon Field, we drilled a key field extension well that indicates this discovery is likely 400 Bcf gross or about 150 Bcf net to EOG.

The Davis 21 #1 well extended the down dip limits of this reservoir and we'll be developing this field with a two-rig program for the next several years. We also have two geologic look-alike structures we will be testing during the next twelve months to see if we can replicate this Driscoll Mountain discovery in some nearby areas. In the nearby Vernon Field, EOG recently completed the Mack 19 #1 which tested at 13 million cubic feet a day. We have a 75% working interest in this well. Combined, these results have converted our East Texas North Louisiana division from one that exhibited production declines the past few years, to one that is expected to grow production over 9% this year.

In our Midland division, we're excited about results from our Nile 22 State Com #1H horizontal well from the Wolfcamp formation, which appears to being a 1.8 Bcf well for $2 million completed well cost. We have 30,000 net acres in this area and hope we can turn this into our next horizontal pipe carbonate multiwell success story. With further drilling and completion cost optimization, we expect to lower completed well costs to $1.5 million over the next several wells. We will drill several offsets to hopefully confirm the first wells resolve, and if so we have enough acreage to drill 100 wells over the next several years here.

We have also had some recent West Texas Oil success with the Shannon Hospital Number 42 and 43 wells, each of which IP'd (ph) for 400 barrels of oil a day for $1.2 million completed well costs. We will be drilling additional wells here throughout the year. In the Mid-continent area, we have confirmed our multiyear horizontal Cleveland -- we have continued -- excuse me -- our multiyear horizontal Cleveland and Hugoton-Deep programs, but we have added results from a new program, the Granite Wash. During the quarter we drilled three Wash wells and each appears to be a net (technical difficulty) Bcf well for about $1.4 million well cost, which gives us a more powerful mid-continent program than we have had in the past. We anticipate drilling another seven to eight Wash wells later this year.

Our Rocky Mountain eight rig drilling program is performing exactly as expected. We expect to grow our total Rockies production 10% this year after growing it 11% last year. The same can be said about our Canadian activities. This year we expect to again drill around 1,300 wells, similar to last year, in Southern Alberta and Southwest Saskatchewan, and we can increase full year natural gas production in Canada by 10% after growing it 28% last year.

A few weeks ago, one of our partners' press released results from our Northwest Territories winter drilling and testing efforts. We have a 26% working interest in the B44 well which was completed and tested from two individuals zones. Each of these zones individually takes approximately 10 million cubic feet per day and about 3,000 barrels per day of light volatile oil or condensate. One of the zones also produced about 1,000 barrels per day of water. The reservoir size will need to be confirmed by further testing and/or drilling during next winter's operating season.

A second well, the L71, was drilled on a different geologic structure and tested but did not establish commercial flow rates and we have written the well off in the first-quarter. We have other large structures to test in this area and further winter-only evaluation will be needed to determine the commerciality of the B44 discovery. I hope that gives you a flavor of a broad based North America Ex-Barnett growth engine.

Now let's talk about the Barnett. I will focus my remarks on two areas. The first area is Johnson County, where we have 90,000 acres and where we have done vast majority of our drilling so far. The second area includes Erath and Jack Counties where we have done some outpost drilling and have some results that affect much of our remaining 370,000 acres. In our 65,000 acres in the western half of Johnson County, we have now drilled 31 3-D seismic based locations using our updated completions, and we have averaged 2 net Bcf per well; that is 2.5 gross Bcf per well. And I believe this is a reasonable go-forward number we can replicate on this acreage spread.

This is the same reserve per well number we reported to you last quarter. By the way, 2 net Bcf per well generates 100% after tax rate of return based on our $1.6 million all-in well seismic and land costs. Our remaining 25,000 acres in Johnson County are in the Northeast corner where we have a viola barrier between the Barnett and the wet Ellenberger (ph) zone, making these completions less difficult. We have recently drilled our first 3-D based well in this area called the set back partners number one and it appears to be a 2.5 to 3 net Bcf well.

So we're hopeful we can achieve even better results on these 25,000 Johnson County acres. To summarize Johnson County, we will do the vast majority of our 2005 drilling here and our aggregate results are still very good. However, I want to stress that the Barnett program will never be a low-tech well bore manufacturing process. Each well requires a lot of integrated technical input to minimize and hopefully eliminate the incursion of Ellenburger water, which is the biggest technical hurdle in the play.

Now let me shift to the results of our outpost drilling located 32 and 47 miles, respectively, to the west and northwest of Johnson County in Erath and Jack Counties. I consider the data from these wells very significant because in EOG's technical opinion, these well results confirm that essentially all of EOG's 460,000 acre Barnett position is within the gas window. You may recall that there has been a split in industry opinion regarding whether the Barnett rock contain gas or oil as you move West from Johnson County. The conventional wisdom was that all of Erath, Palo Pinto, Jack and parts of Parker and Hood Counties, contained oil in the pore spaces, and was therefore likely noncommercial.

EOG's technical analysis yielded a different conclusion and this provided us an ability to lease acreage that many in the industry thought was noncommercial. After amassing the acreage, two questions remained. One, did the western acreage contain a higher percentage of karst and faults in the 50% we found in Johnson County; and two, did the Barnett contain gas or oil out west. Regarding the first question, we now have 3-D seismic over part of our Jack and Hood County acreage, and the results indicate that 60% of the acreage is unkarsted, better than the 50% we have experienced in Johnson County.

To answer the question of whether the Barnett contained gas or oil, during the first quarter we drilled one horizontal well in Erath County toward the Western edge of our acreage, and one in Jack County at the Northwest edge. According to our technical analysis, if these wells tested gas we would expect all our acreage to be in the gas window. Fortunately, both tested gas. The Erath County well was a short lateral with a small frac and it produced at a 500 Mcf a day rate with no oil, which is consistent with what a Johnson County well would do with a similar short lateral length and small frac. The Jack County well tested 900 Mcf a day with only a trace of oil. Note that both of these wells were designed as test for hydrocarbon content and we expect better producers with subsequent wells, the same as in Johnson County.

We also have verified Barnett gas production tests in these Western counties by multiple vertical wells drilled by small private companies. Therefore, we believe the Barnett play extends to six additional counties beyond Johnson, where EOG has leases and that EOG's total 460,000 net acres are gas productive. We intend to start development drilling and selling gas from Jack County immediately while development drilling in Erath County won't occur until 2006 when pipeline infrastructure will be added. Additionally, we will be completing our first Hood County well which is between Erath and Johnson Counties, within a few weeks and we expect to have a full-scale development program here in Hood County in late 2005.

I will also note that as we move to the West from Johnson County, particularly in Erath and Palo Pinto Counties, the Barnett is shallower and thinner and we expect reserves to be roughly 0.8 to 1.6 net Bcf per well. But the well costs will also be lower because of the shallower depth. Typical economics here work out to be 80% after tax rate of return.

To summarize the Barnett overall, we feel we have confirmed a very large gas accumulation and we've established a dominant acreage position. We expect by next quarter we will have 500,000 acres under lease which was our goal. Based on our Johnson County results, the economics of this play appear to be head and shoulders above the typical economics for most other North American hydrocarbon plays. At this point, we plan to develop 100 acre spacing, but we have a 50 acre pilot in progress and we are commencing a second 50 acre pilot in Johnson County by midyear. We will give reports on both pilots by year end.

We plan on increasing our rig count from the current four to seven by June 1st and will likely increase the rig count even further in 2006. We expect our average Barnett production to grow from 6 million a day last year to 60 million a day this year. Now I'll shift to Trinidad and Tobago and then the North Sea. In Trinidad we expect to ramp up production during the third quarter with the startup of M5000 methanol plant. After commissioning, we expect EOG's net sales to the M5000 plant to be 60 million a day at a wellhead net back linked to Caribbean methanol prices which would currently be about $2.00 in Mcf. We expect production will ramp up another 20 million a day in the first quarter of '06, as we initiate sales to NGC for their position in Atlantic LNG Train IV which will be our first Trinidad contract directly linked to Henry Hub prices.

On the drilling front, 2005 will be a relatively slow-paced year for us, while 2006 will be a much more critical exploration year. This year we hope to drill a 250 Bcf prospect on Block 4A if the government awards us the block by midyear. Additionally, we expect BP to spud the 20,000 foot deep Ibis prospect on our SECC Block about November 1st which would mean the well would likely be decisioned in mid 2006. EOG will have a 51% working interest in the well in (indiscernible). Also in 2006, we will likely drill the Deep Kiskadee prospect which will be approximately a 500 Bcf prospect. So 2006 is stacking up as a key exploration well year for us in Trinidad.

In the North Sea, we are happy to report successful results from the Arthur 2 Well, EOG working interest 30% in the Southern Gas Basin. This well tested 58 million a day gross from a new fault block, separate from our currently producing Arthur 1 Well. We expect this well will be connected to sales before year-end. We are currently drilling an exploration well in another part of the Southern Gas Basin and will likely participate in two or three additional exploration wells before year-end. So far our measured entry in the North Sea is on track and we're pleased with the results.

If you look at Trinidad and the North Sea combined, we expect production to almost double between mid 2004 and mid 2006 from 170 million cubic feet per day to roughly 340 million cubic feet per day.

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

Thank you Mark. With respect to CapEx, for the first quarter '05, exploration development capital expenditures were $399 million which included $1.5 million of acquisitions, so virtually no acquisitions. Total discretionary cash flow for the quarter was 479.6 million, capitalized interest was 3.4 million. For 2005, our estimated capital expenditure budget remains at 1.6 billion excluding acquisitions. Assuming a totally unhedged position for 2005, the impact of a $0.10 move in natural gas prices would impact net income and cash flow by $21 million. A dollar move in oil prices would impact net income and cash flow by $6.4 million.

Turning to capital structure, at March 31, '05, total debt outstanding was $1,120,000,000 and the debt to total capitalization ratio was 26%, down slightly from 27% at year-end '04. However, I would note at March 31st, we had $173 million of cash on the balance sheet, virtually all international. At year-end '04, by comparison, we only had $21 million of cash on the balance sheet. The effective tax rate for the quarter was 35% and the deferred tax ratio was 41%. We did file our Form 10-Q last evening. Now I will turn it back over to Mark.

Thanks Ed. Let me talk just a little bit about our view of the North American gas macro and our hedged position. Consecutive warm winters and a very cool 2004 summer, the macro North American natural gas supply and demand situation is very tight in our opinion. We expect domestic production will decline 1.3% this year in spite of the rising drilling rig count, primarily because of continued high year-over-year Gulf of Mexico declines which contributes 24% of the nation's gas supply. Accordingly, we have no financial hedges for either gas or oil in place for the remainder of 2005 or forward.

Now let me summarize. In my opinion, the important items to take away from this conference call are as follows. First, our top priority continues to be focus on returns. As you would expect in the year where earnings may be as high as expected, cost structures have increased. However based on current futures prices our return profile remains strong and we are likely to exceed last year's 25% ROE and 18% ROCE. Reconciliation schedules for these calculations have been posted to our website. Second, with current commodity prices, our net debt is likely to be further reduced throughout the year. During the first quarter we reduced net debt by $110 million while delivering 19.3% organic production growth.

Third, our North America Ex-Barnett growth engine is running quite well. Fourth, the gas tests from the Jack and Erath County Barnett wells are very significant and, in our opinion, confirm we have a 460,000 acreage position within the Barnett gas window. Fifth, 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. Thanks for listening, and now we will go to Q&A. Audrey, if you can queue up the Q&A, please.

The question-and-answer session will be conducted electronically today. (OPERATOR INSTRUCTIONS) David Khani with FBR.

Hi, guys. Can you hear me?

Yes, David.

Okay, great. With 173 million of cash, and I know it's international, I thought you could repatriate that cash domestically. Is there a reason why it has to stay international?

You are correct, we can repatriate. Obviously there is, this year, a tax advantage of doing so. Effectively the tax rate would drop from 35% to 5.25%. We have not made the decision yet how we want to handle that, if at all, and really don't anticipate making that decision until approximately September 30th. With respect your international cash position, quite frankly, our operations internationally are continuing to grow. So we do in fact have cash requirements in general for that cash. The bulk of that cash at this point in time, however, is in Trinidad, and so we will continue to evaluate what we should do long-term.

Okay. In the past, you used to buy back stocks. Is that potentially in the cards near term with the amount of cash that you have building?

David, that is a possibility. I think where we stand right now is once we get -- right now our net debt to total cap is in the 23% range. I think once we get it knocked down below 20%, which will probably be at the end of the second quarter, we will start looking at the option of further reduction in net debt versus potential share buybacks. As you know, we always want to be at the low end of the debt to cap ratio, but once we get to 20% and look at below that, I think we really have to question how much lower do we really want to take the net debt.

Right. Okay. Given the drilling success to date, and it is way too early I guess to call funding development costs, but do you think that you're in position in all of your major regions, U.S., Canada, UK and Trinidad to add reserves? Or is that not the goal this year in some of the regions, to replace reserves?

I think we're going to have a very good reserve replacement year in essentially all of our areas, David. I don't see that we are going to have a problem at all, with year-end having a very good reserve replacement percentage number. But I think it is way too early to call what the finding cost number will be.

I just didn't know whether with Trinidad if you were going to have the ability to add reserves this year because your activity level is sort of more back-end loaded.

Yes, what we hope to accomplish in Trinidad there -- and it's Block 4A which is -- we think it is a pretty low-risk drilling prospect there. We bid on that block, and we were the only bidder, a couple of years ago, and we believe we have a pretty high likelihood of the government awarding us that block sometime and hopefully within the next month or two. And then we are going to make every attempt to jump on it and get that well drilled sometime during the second half of the year.

So we think we have a good chance to have a reserve addition there during the second half of the year. But the big year for us in Trinidad in terms of setting us up for 2009 in forward production growth in Trinidad is really going to be 2006. That is when our -- both the Deep Ibis and this Deep Kiskadee well will likely be decisioned. So that is why we put it that way.

Moving over to the Barnett now, how much 3-D seismic do you have covering all that 460,000 acres?

We currently have about 370 square miles, and we have got either permitting, shooting -- we ought to be somewhere around 1,000 square miles by year-end.

Last question I guess, Mark. About a year and a half ago, you gave us sort of a value for the Barnett Shale of 5 to 20 and that was obviously presplit. Do you dare to give us another value today?

Yes, I am not going to do give a value as to what it is other than I think that what is currently embedded in the share price today is low when you put a value on the 460,000 acres based on the data we have today. But I'm not going to do -- I will leave that to you gentlemen.

Well you gave it to us once before. I figured I would give it a shot. Okay, thanks. Good quarter.

Ellen Hannan with Bear Stearns.

Actually, I think that all my questions have been answered. Thanks.

Mark Meyer with Simmons & Co.

Driscoll Mountain, I am wondering if you could share a few more specifics in terms of kind of typical well parameters. Perhaps it may be a bit too early but any additional specifics on Driscoll Mountain would be helpful? Also, recalling I think a 200 Bcf potential number that you talked about last fall, post the discovery. Is that a number I should compare to the 400 Bcf? In other words is that a gross number?

Mark, this is Gary. These wells are 16,000 foot in-depth. They are six or seven Bcf equivalents, and they cost about $6.5 million. And, yes, we are still looking at somewhere around 400 Bcf gross, and a 150, 160 Bcf net to EOG.

In relation to the 200 number we may have given you in the past, I am not sure whether that number that you picked up was a gross or a net number, Mark. I believe what we would have said about a year ago is that we felt it was -- about six months ago what we felt was that we had kind of a sure 200 gross Bcf kind of based on the drilling. And so the significance of this growth quarter is based on the Davis Well, tested a down structure is, we now believe it is bigger in terms of both gross and net than what we thought before.

That is the way I read it; I just wanted to clarify. Thanks. Quick questions on the Barnett. The statement that substantially all or a substantial majority of the acreage is in the gas window on two wells worth of data. Just wondering if there are any specific kind of PBT observations, fluid property observations, that you saw either BTU (ph) or liquids content that gives you that level of confidence this early?

Yes. Let me give you a little color on that. It is not two wells worth of data. It is two EOG wells. We have done a pretty intensive amount of research, particularly in Jack, Palo Pinto and Erath Counties and when you really dig into the data, there is probably an additional, I would say, 10 to 15 vertical wells that have been drilled out there by private companies, very small private companies, who have completed wells in the Barnett Shale, that such wells made somewhere, and have been making in many cases for years, somewhere between 50 and 150 Mcf a day with no oil.

And those are identical tests to what keyed us into Johnson County three and four years ago. So before we really started leasing out there, we had this data that made us feel pretty darned comfortable that the conventional wisdom on where that oil and gas delineation line was, that that conventional wisdom was wrong. In other words, we had bona fide multiyear gas tests out there from teeny tiny companies. We then confirmed that with geochemical analysis, specifically vitronot (ph) reflectives data that told us where the oil window should be versus the conventional wisdom.

And so it told us that the oil window was considerably farther to the west than the conventional wisdom. And so by the time we drilled the Jack and Erath Wells, I would say we would have been very, very surprised had those wells turned out to be oil instead of gas based on the data we had there. So when we speak now about our confidence factor there, trust me, it is not based on our two wells. It is based on considerably more data than our two wells. It is just those are the two EOG wells that we are basing it on.

There have been some indications of some 1,200 BTU gas East of those areas. Have you seen significant variation from your Johnson County production to what you have observed, either from this longer dated production history or your most recent wells, from a BTU standpoint?

The interesting thing on the BTU content is, the BTU in Western Johnson County is about 1,220 and the BTU in our Bishop Well is 1,220. That is an Erath County. And the BTU in our Richards Ranch Well is 1,216. So surprisingly, where you literally go 30 and 40 miles West of our Johnson County stuff, the BTU content is essentially identical, which again that is surprising. We thought the gas would get a little richer, but it is just another datapoint that tells us that this is a big gas accumulation.

And so the data is all converging to tell us that pretty comfortable that all of our acreage is in the gas window. So it really boils it down then, what is the big question you have out there? Well the acreage to the West, the Barnett is clearly thinner. And in both the Richards Ranch Well and the Bishop Well, the thickness of the Barnett is roughly 200 feet versus 300 to 350 feet in Johnson County.

Essentially all of our acreage that we have outside of Johnson County is, at least the Western acreage, is between 200 and 350 feet thick in there. So the question is, as you get a little bit thinner, what does that do for you? And the other question is, it is shallower, and so you're going to have less pressure, so you're going to get less reserves per well. That is why we quoted you the number that -- it degrades the returns, plus percent rate of return down to a mere 80% rate.

The real question, I think in my mind now and the question to be objective on this is, we have a large acreage spread in this area. We have some 3-D seismic over our Hood and Jack Counties. The rest of it is being shot or in-process. The data from the 3-D seismic indicates your tectonic complexity lessens as you go to the West, i.e., there is more acreage you can drill as you go to the West, less karst. But the real risk is we have to establish commerciality in those counties. In other words, we have to drill over a widespread area and find out what kind of reserves per well and what well costs can we establish. And we will be doing that in both Jack and Hood County in the second half of this year.

Great, thanks for all of the detail.

Gil Yang from Smith Barney.

Good morning. Mark, could you comment on -- you used to categorize acreages as low-risk in other more exploration acreage. With the success of those two wells would you now move all of that acreage into low-risk, or is there still more testing to be done and what would that testing be?

Yes, you still have to say that the Johnson County stuff is still the lowest risk stuff because we know more about that, but I would say I would move the classification from exploration acreage to something that would denote a lower risk than exploration. Now I would say, it is just -- I would probably just call it Western acreage and say that it is -- the next hurdle is, can we drill Western acreage in a widespread area and deem it commercial? Can we get the reserve range that we believe, over hundreds of thousands of acres? But I think it lowers the risks on that proportion of our acreage by several notches from where we had it indicated previously.

Can you comment on where the new, the 60,000 acres that you purchased in the quarter, where that was added approximately?

Yes, approximately a big chunk of that was in Palo Pinto County and Erath County primarily, would be the two counties.

Okay, with respect to I guess the Johnson County acreage, it sounds like you have honed in on what you would call the state-of-the-art tracking completing technology? Or are you still groping around for what the best thing to do is?

I don't know if groping around is the right term, but we are not satisfied with where we are yet. I think we have got -- the well completions side, we now know that the biggest risk we have is the Ellenburger water issue. And to kind of capsulize it, about 20% of the wells that we have drilled off the 3-D seismic have produced anomalously high amounts of Ellenburger water. So somehow or other, we have induced Ellenburger water to our frac treatments.

That 20% of the wells that are making anomalously high water, that is integrated into the 2 net Bcf number. So if we could somehow eliminate, knock that 20% down to 10%, we could probably get that 2.0 net Bcf up to say 2.2 or something. So that is kind of what we are trying to focus on right now, but we're also doing some other things with the completions. We are trying to figure a way where we can get that 2.0 up a bit higher. So it is quite possible that that number, that 2.0 -- we are doing things to see if we can get that number higher.

And perhaps by the end of the year we may have a number that is a little bit better than that. But I don't expect on the 65,000 acres, that that number is going to jump to three or something like that. There is a chance on the 25,000 acres, up in the Northeast corner, that we may have a better number like 2.5 or 3 up there though. We just have to, in the second half of the year we will get a pretty good handle on that.

The 20% of wells that are making a lot of water, are those -- are they being plugged or are they still economic, just because they are making less gas and more water?

No, they are making less gas and more water. So those wells may be averaging maybe 1.25 or 1.5 net Bcf per well, but they're still commercial wells. But they're just bringing down the average.

Is that because you're plugging back the lower perforations to block out the water?

No, we are just handling the water, but they're just making water along with that gas.

Okay. Just a final question. The downspace tests or the two that you're now running, are you confident that you know and answer, good or bad, by the end of the year? Will they be definitive or is there not variability that you're not going to be sure?

The downspace tests, what we are doing, we're running the one now, and so far everything looks positive on it. I would say it is absolutely certain that at a minimum we're getting acceleration reserves. In other words, reserves that we would otherwise be producing in year 20, we're producing in your one. So if you look at on present value basis, I think it's pretty clear that you're going to get a positive NPV on it.

But we are still -- we just want to give it a longer run-time really to find out, are you really getting actual increase in ultimate reserves, or are you just getting acceleration reserves? We just need to let it go longer, but the three wells on the pilot are doing very well. That pilot is kind of in Northwest Johnson County, and what we're going to do is we're going to start a pilot here in this second quarter in Southwest Johnson County and that will give us two pilots running. I suspect by the end of the year, we will probably have a pretty good handle on it. I won't say absolutely yes or no, but we're going to have probably an 80% answer.

Okay, thanks very much.

Frank Bracken with Jefferies & Co.

I've got two questions. First, trying to get a little more clarification on this modestly denigrated rate of return that you're talking about in Erath and Jack, etc. You gave a very wide range of reserves, one double the other in terms of 0.8 to 1.6 Bcf, and a single point estimate as a relates to IRR. Could you help us out a little bit on some of the variables, whether it is well costs or whether you're talking about 80% on the midpoint of that range. Or give us a little more color to true those numbers up? And then I will come back and ask my second question.

Yes, Frank. What we use there fore that 80% rate of return is a well cost of about $1.3 million, or basically kind of a well seismic land cost of 1.3 million compared to the 1.6 million for Johnson County. Kind of a mix of net reserves per well of 1.1 Bcf. That is just kind of Johnson, Erath, Palo Pinto, Hill County, a bunch of counties. Okay? And if you do that when it spit out a finding cost of roughly $1.18 and about an 80% after tax rate of return.

Actually one other little question on the Barnett before I move on. I am hearing that gathering and take away capacity are getting tight and that is starting to blow out the basis. Could you comment on that?

We have locked in our capacity for sales here. We've got 150 million a day capacity out of Johnson County. Yes, we do have some transportation costs. It runs as high as $0.40. There in Jack County and Hood County, we are setup with sufficient capacity for some time.

So if it is happening to somebody, it isn't you.

Yes, actually we have been kind of pleased by our ability to get the gas out of there, and other than just the transportation costs to get it to a mainline we haven't seen any real basis blowout or anything so far.

My other question relates to your Wolfcamp Well. Would that be -- you said it was a carbonate, would that be what Yates and Parallel (ph) are calling Diablo (ph)?

No. No, it is a different play than Diablo. This is one that we kind of setup, it is just a different play. It has taken kind of the horizontal technology we developed in the mid-continent, this horizontal Cleveland play really in our well completion technology there, and then applying it to what we're doing in New Mexico. Like I say, so far we are one for one on that and we have accumulated a lot of acreage. Next quarter we will probably have two additional wells worth of data there and that will kind of tell the tale, in my opinion.

You mentioned a well name?

It is called the Nile State, Nile 22 Fed Com 1H, or something like that.

That's interesting, because your partner is saying that is Diablo.

We would not call it Diablo.

Just gas, I guess, is what you should call it, right? Fair enough. Thank you.

David Snow with Energy Equities.

Let me follow up on the well you were just talking about. Is that the well with parallel?

Yes.

Okay. Does that look like repeatable type of -- I guess one-for-one doesn't give you enough, but does that seem from your Cleveland experience to be a pretty repeatable type of completion?

Yes, we think it is or we would not have mentioned it here in the earnings call. We think it's got all of the characteristics. We have done a lot of these horizontal plays across North America now, and this one looks like it's got all of the characteristics, but give us a few more wells before we can really check it off and kind of guarantee it for you, David.

What price deck are you using on your 80% return or 100% Johnson County?

What we are using is as of April 15th, we just took the 3 years of the NYMEX strip, and then we just took $4 flat price thereafter.

Fine. Thank you very much.

Van Levy with Dahlman Rose.

Good morning, Mark. How are you? Pretty impressive growth in the U.S. sequentially. Is most of this coming from the Barnett Shale, or are there other areas that are driving this?

Van, this is coming from most all of our North American divisions. Yes, Barnett is kicking in, but we're seeing good growth out of Corpus, Tyler, Denver division, Midland as well.

So all cylinders are hitting. First quarter, what was the Barnett production and where do you expect to exit the year?

We're not going to give quarter-by-quarter Barnett production, Van. We just don't want -- we don't give out division by division production. We expect to end the year at roughly 100 million a day.

100 million a day. Any sense of 2006, what you expect to average or percentage growth from 100 million a day? Are we talking 20, 30% growth?

I think we will just -- don't want to give a number on that until -- probably we will give that at the September analysts conference.

Okay. You are ramping up the rigs in that area. I would imagine there's some pricing pressure. Any thoughts on building your own rigs or subsidizing someone to come in so you can mount (ph) a much larger program?

We really hadn't had that much difficulty picking up rigs. We've just gone from the four to seven rigs. We've talked about subsidizing, something of that sort, principally to just get new technology and drilling rigs to the area. We will continue to look at that.

Okay.

We're not going to build our own rigs.

At year-end, what did you have booked for the Barnett Shale?

I think it was about 130 Bcf total; part of that PDP and part of it PUDs.

That was my next -- roughly, what was PUD?

The great majority was PUD.

Okay. I guess you mentioned you had what, 30, 35 wells that are underpinning most of this. What kind of variability are you seeing in terms of reserves per well production rates? Is it a wide variability or are you converging on more of a consistent result set?

I guess on a gross basis, they are probably from roughly 1 Bcf to probably 4.5 Bcf.

But if we took like a mode or something like that, where would they convert? Is there so much dispersion that it's just hard to talk in those terms?

What we are seeing is the wells, 20% of the wells that are making Ellenburger water are typically wells that are in the 1 Bcf range or 1.25 Bcf range. And then we've seen what appears to be what we call a sweet spot there where we have got several wells that appear to be somewhere between 3 and 5 gross Bcf kind of wells. Most of the rest of them kind of hover in a pretty good median that turns out to be 2 to 2.5, in that kind of range.

So what we are seeing is that the results appear, now that we're getting a pretty good database, they appear to be fairly explainable and we're not getting as many surprises now that we are beginning to understand some things there. So we're getting a little more confidence in kind of projecting and using that 2 net Bcf and kind of saying for that 65,000 acres, that looks like a number we can probably replicate.

Okay. David asked you the question on pricing. You said the three-year strip, it sounds like it's kind of in the $6.50, $7 range if I'm correct on that. Running those numbers in your 80% return, what is your net present value per well, or alternatively, what I am really trying to drive at, net present value per Mcfe net of development costs? What does it calculate to be?

I don't have those numbers --.

$3 or $2.50?

I would have to just dig them out. We will get more -- dig them out and get them for you.

Last question. The mathematical kind of equation of running through the acres, 460,000 acres, and condemning half of it because of costing or the sweet spot would leave you around 230,000 acres. And you talked about 100-acre spacing per well, so it's about 2300 locations. If you did 2 Bcf, 1.5, you're coming up with over 4 Tcf of reserves. Is this a reasonable number, or is there some error in that calculation?

The 2300 wells is about right. That is kind of -- we have got to slide as we go to -- we've kind of updated our slide and analysts presentation, and the range that we are saying now is in net Bcf potential -- we have upped it a bit from the old range -- is somewhere between 2.1 and 3.8 Tcf net on this thing here. So if you take that upper range, that is approaching the 4 Tcf that you just mentioned, so we think we are in that range.

We anticipate having these slides up on the Internet sometime around lunchtime.

Right. If you come anywhere close, does the Company in itself, any consideration of carving this out? So I would think you would get a higher value. Mark, you mentioned that you didn't think very much value was embedded in your stock. Clearly, that is a separate company. I think investors could focus on that and give you a higher value. Any thought?

No, we are very unlikely to do that. There's just too many skillsets that are transferable to -- as we learn these well completions -- that are transferable to other divisions, just like we talked about with the play in New Mexico a few minutes ago. So very unlikely we would do that. That is un-EOG like.

Last question. As you drill more wells and you get more confident, is there a point where you would jump it from, say, four to seven, maybe seven to 14 to 20 rigs? What is the practical evolution of the drilling pace?

Van, we're just like you say running seven now. We will be increasing that. We are adding people, and it's probably people constrained to really find more of the EOG quality folks. So I would say next year, I think we already had laid out that we will probably be in the eight to ten rig count. That is our current plan.

Okay, great. Thanks.

Jeff Hayden with Pickering Energy Partners.

Most of my questions have been answered. I just wanted to get one thing clarified. You mentioned on the Erath test that that was a short lateral and a small frac. The Jack test, was that the same?

The Jack test was again, it was kind of a medium-sized lateral and a medium-sized frac. Like I say, both of those wells, when we sorted the plan for them, our goal was just to find out what is rock going to produce. The goal wasn't really to make a commercial well. So we designed it that way. And together the data, particularly on the stressed (ph) fields, for example, what azimuth, in other words, what direction do we drill these wells, some things like that. So I would say the objective on the first well was data gathering, and so we are very happy with the results.

To me, the most interesting portion of the results on the Erath well is the Erath well results, half a million a day on kind of an extended flow test, those results lay down practically identically to some of our early Johnson County wells drilled with the same lateral length and the same small fracs. That is kind of surprising to us and gives us some hope that once we drill them like we are really drilling them for production that maybe we have got something -- maybe the reserves out there in Erath County might be a little better than we are currently crediting them with. It tells me that the rock quality in Erath County which is, as we say, 30 some miles away is maybe just as good as it is in Johnson County, and that is very important.

Okay, thanks a lot, Mark. See you guys at the lunch.

Joe Allman with RBC Capital.

Good morning, everybody. Mark, how many wells do you need to declare commerciality out here on the Western edge?

I think we probably are going to need five wells or so in Jack County and say five wells in Hood County before we have a comfort factor to say, okay, we have got commerciality. The same in Erath County, but that probably won't happen until next year in Erath County.

In terms of your -- I know you addressed the acreage, incremental acreage acquisition. Have you bought in any additional counties like, for example, Comanche County?

No, we haven't bought in Comanche County. We may have bought in some other counties that shall remain nameless at this point.

Can you give us a sense of what the rationale has been behind where you've been buying acreage? Like, for example, this last 60,000 has been focused on Erath and Palo Pinto. Is that because of just something you like out there, or is it just kind of getting an even amount in all of these Western counties?

No. Well, it is almost kind of availability. Availability in Parker and Johnson County is -- there isn't any availability, frankly. So you have to go out farther West to find any availability. So we just -- it was more where we felt there was a very high probability we were in a gas window and where the prices were somewhat rational and not insane. So it was more kind of where was our opportunity to fit those categories as opposed to trying to have even amounts in any county or anything like that.

I think you said your target is 500,000. So you plan on sort of stopping at that point?

Yes, we have already got kind of handshake agreements that if all the handshake agreements are consummated, we will be at 500,000 probably in two or three months.

On the Barnett, just to summarize, can you update us -- so how many wells have you drilled to date in the Barnett and how many have been in Johnson, how many in Parker, and how many elsewhere?

I guess probably total wells, we probably drilled something like maybe 43 total wells if you go back to the beginning. And I think we drilled maybe 31 wells that I quoted to you earlier in Johnson County that are ones that we consider the technically correct locations with the technically correct completions. Outside of Johnson County, I believe we have only drilled the two wells. So we haven't drilled any wells in any other counties other than the two wells in Jack and Erath County. So none in any other counties outside of Johnson, other than those two.

But that is going to change between now and year-end, though.

Yes. Like I say, we have got a well in Hood County now that is waiting on completion, so that will be pretty certain. And then probably by the fourth quarter, we will have Hill and Palo Pinto County wells drilled in that area, and possibly Somerville County also.

Lastly, I missed a data point when you were talking about the granite wash play; I think you said the cost was 1.3 million per well, but I missed the reserve. I think you gave a reserve number per well.

I think it was about 1.5 Bcf or $1.4 million.

What is your exposure to the granite wash? How many locations could you drill based on your acreage?

I think we said seven to eight wells this year, and I would say we have a moderate exposure for the next several years. It is not where we have possibilities for a 100-well program over the next several years, but it is enough to kind of give us a third leg to our Hugoton Deep and our Cleveland program.

All right, thanks for your time.

Joe Magner with Petrie Parkman.

Good morning. Thanks for all the info today. Just curious if there was any update in the Uinta Basin on either the testing of 20-acre downspacing this year or the testing of the big target play in the Western Uinta?

No data on the testing of the big target play in the Western Uinta. Most of that stuff is held up with permitting issues just on federal lands. In fact, on the stuff, on the listing of the big target plays we are going to put up on the website here about noon today, we are sliding that until early '06, that Western Uinta, just because of permitting issues, timing. On the 20-acre downspacing in the Uinta, no data on that either. That probably will be something that we will be looking at in early '06, is what we are looking at now for that.

Other than that, everything is going find in Uinta. It is just kind of a standard program this year on there. The biggest problem we really have there is just getting enough permits to drill, just on the federal and the Native American lands. But everything is going fine there, but there is no outstanding wells to report. So we just -- everything is going about as expected.

Okay, great. Thank you.

Bob Morris with Banc of America Securities. Mr. Morris, your line is open. Hearing no response, we will move onto a follow-up question from David Snow.

I wondered if the New Mexico well that you were talking about was basically using the same completion methods as the Barnett Shale?

No, it is more similar to what we're doing in other areas of the Permian Basin.

Not just a slick water frac?

It is. We are using some (indiscernible) and it is a cemented liner, multiple stage.

Okay. Thank you,

There appears to be no further questions at this time. Mr. Papa, I will turn things back to you.

Okay. I want to thank everyone for listening in on the call and obviously we are pretty excited about the situation here at EOG. And we will have more good business to report at the end of the next quarter. Thank you.

That does conclude today's conference call. Thank you for your participation.