EOG Resources Inc (EOG) 2004 Q3 法說會逐字稿

Good day, everyone. Welcome to the EOG Resources Third Quarter 2004 Earnings Conference Call. As a reminder, this call is being recorded. At this time I would like to turn this 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 third quarter 2004 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings. We incorporate those by reference for this call.

The SEC permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates in this conference call and webcast, including those for the Barnett Shale play, may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of our 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; Loren Leiker, our Executive Vice President of Exploration and Development; Gary Thomas, our Executive Vice President of Operations; and, Maire Baldwin, our Vice President of Investor Relations.

We filed an 8-K with fourth quarter and full year 2004 production guidance yesterday afternoon, which I hope you’ve seen. Although we raised our 2004 production growth forecast to 9 percent at our recent September 30th analyst meeting, it now appears our full year growth will be about 9.5 percent due to stronger than anticipated fourth quarter volumes, and our 8-K numbers reflect this upward revision. The 8-K also indicates that our total 2004 capex estimate will be about $1.45b including acquisitions.

I will now review our third quarter net income available to common and our discretionary cash flow available to common, and then I will discuss operational highlights. As outlined in our press release, during the third quarter, EOG reported net income available to common of $169.6m or $1.42 per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net available to common to eliminate mark-to-market impacts, EOG’s third quarter adjusted net income available to common was $134.1m, or $1.12 per share.

The reconciliation of GAAP to non-GAAP adjusted net income available to common is found in our earnings press release which is posted on our web site. For investors who follow the practice of those industry analysts who focus on non-GAAP discretionary cash flow available to common, EOG’s DCF available to common for the third quarter was $387.9m, or $3.24 per share. The reconciliation of non-GAAP discretionary cash flow available to common to net cash flow provided by operating activities is found in our earnings press release.

I will now address our operational highlights. Yesterday we provided an 8-K with fourth quarter guidance which increased our full year 2004 guidance to 9.5 percent because of stronger than expected results from the U.S., Canada and Trinidad. Although the Barnett Shale has captured the headlines, our recent North American activities have been firing on all cylinders as well.

I will first discuss each of our major operational areas in the U.S., then review Canada, Trinidad and the U.K. North Sea, and then I will conclude the operations segment with the Barnett Shale review.

In South Texas, third quarter production is up almost 8 percent versus year ago levels, and we are continuing to see strong contributions from each of our four geologic plays, the Roletta, [Lobo], [Frio] and Wilcox. But the best news is that we are drilling at the highest activity level in over a decade, and we are still able to add to our net drilling inventory.

In past years, when we’ve run over five rigs continuously, we began to deplete our inventory of new drilling locations. Today, because of our multiple geologic successes, we are running nine drilling rigs, and actually adding to our net drilling inventory.

During the quarter we completed a number of notable wells. At [Din] Ranch, the Buck Hamilton No. 10 well is flowing 24 Mcf/d at 7,800 pounds floating tubing pressure from the Wilcox formation. We have a 65 percent working interest in this well. Additionally, the Slater Ranch L-1 well in the [Lobo] Roletta trend robbed 100 feet of pay and tested 8 Mcf/d of natural gas. EOG has 100 percent working interest in this well.

In San Patricio County, we encountered 290 feet of pay in the Frio formation at the Bell Farms No. 2 well. We are still completing this well and expect it to flow at 8 Mcf/d and 600 barrels condensate per day. We have 77.5 percent working interest in this well.

In our East Texas, North Louisiana division, we expect 2005 production to be up significantly relative to the past few years. During the third quarter, we made a nice North Louisiana expanded Cotton Valley discovery at the Driscol Mountain field, which we feel is analogous to the nearby Vernon field. The initial well is currently flowing approximately 4 Mcf/d to sales, and we expect to drill two offsets before year end. We have a 50 percent working interest in this property, and we expect this to be a 100-200 net Bcf discovery that will be developed throughout 2005 and 2006. Additionally, we currently have two rigs developing the North Louisiana [Slido] field. A typical well here develops about 2-2.5 Bcfe equivalent reserves for about $1.6m cost.

In the Mid-Continent, we are continuing our two-prong [Huvican Deep] and Horizontal Cleveland projects. In the [Huvican Deep] play we are exploiting a recently discovered new morrow channel at 5,500 feet with wells such as the 100 percent working interest Rally No. 5 No. 1, currently flowing 6 Mcf/d. In the Horizontal Cleveland play, we are running three rigs and achieving an average of 1.4 Bcf per well for $1.2m completed well cost. We’ve got an inventory in both of these plays to carry us at least through 2006.

In West Texas, our primary focus continues to be horizontal Devonian drilling, combined with some vertical morrow wells. A couple of recent successful morrow wells are the Lusk 23 No. 2 flowing at 6 Mcf/d and 120 barrels of condensate per day; and the Dane 24 No.2, producing 4.6 Mcf/d. EOG has 100 percent and 45 percent working interest respectively in these wells.

We are currently operating four rigs in the horizontal Devonian play, and we are applying some of the horizontal completion improvements learned from the Barnett Shale activities and obtaining better well results. An example, Reserve Con 100 1H in the ATM field. This well, which is a single lateral, was completed using our new method and is producing at 6.5 Mcf/d similar to our previous, dual-lateral wells. This is a big breakthrough, and would permit us to drill and complete a single lateral and obtain equivalent reserves for about half a million dollars less than a dual lateral, which will increase our West Texas opportunity set.

In the Rockies, our third quarter production was up 15 percent versus year ago levels, and we expect 2005 production to continue to increase. This growth will b e generated primarily from two areas – the Utah [Ulysa] Basin Mesaburg] Development, and downspacing in the Wyoming [Moxar].

In the [Ulysa] Basin, we feel the [Mesaburg] can be downspaced 20 and possibly 10 acre spacing. Our current reserve bookings and drilling density is 80 acres, so we potentially have 250 to 500 net Bcf of unbooked in field reserves here, that we will be drilling in 2005 and later. On the Moxar Arch we expect to drill 55 net wells next year on our 70,000 acre position, compared to 14 net wells this year.

We continue to see good results from the Montana Valcon play. A recent completion is 100 percent working interest Michael 127 well, flowing 600 barrels of oil a day.

In the Gulf of Mexico, we had minimal impact from Hurricane Ivan. We just brought the recently completed [Matagorda] 685 C3 well online at a rate of 6.5 Mcf/d. We have 68 percent working interest in this well.

In Canada, third quarter production was up 37 percent versus year ago levels, and we are beginning to see the volume bump up as our 1,300 well program is batch connected to sales. including activity in the Horseshoe Canyon coal bed methane project. Also, our Alberta Drumheller field program continues to average three or four pay zones per well, which has good implications for our 150,000 acre lease block.

In Trinidad, the fourth quarter will reflect the first full quarter of sales to the Nitro 2000 ammonia plant. Our first exploration well on a 55 percent working interest UB Block encountered non-commercial quantities of hydrocarbons and was written off as a dry hole in the third quarter financials. We are currently drilling on the 100 percent working interest slow reverse L Block. Regarding the 20,000 foot Deep Ibis prospect, we expect that well to spud around mid-2005 and reach target depth around year end.

During the third quarter, we initiated first production from the U.K. North Sea. The [Vaftree] well came online in August and is currently producing 19 Mcf/d net. The Arthur No. 1 well is expected to come online in December at a rate of 20 Mcf/d net. Natural gas prices in the U.K. remain strong. The 2005 [feature strip] is currently indicating $7 U.S. per Mcf.

To summarize, all of our ongoing activities throughout the company are getting results that are equal to or better than expected. I am particularly pleased at the timing for our Trinidad and U.K. production ramp-ups are on schedule, which isn’t always the case for international projects.

The point I want to make here is that the pre-Barnett EOG is hitting on all cylinders, both domestically and internationally. The disciplined strategy we employ is paying dividends throughout the Company. Because of this strong performance, we have not reallocated any capital away from these areas toward the Barnett. We want you to view the Barnett as additive to the EOG that existed pre-Barnett in terms of production growth, capital requirements and reserve growth.

Now, let’s turn to the Barnett Shale. I will start by saying that additional data points that we continue to get adds to our enthusiasm regarding this play, and now we are beginning to move from capture to the exploit mode. In our September 30th analyst meeting, we provided a detailed analysis of this play and those slides are still available on our web site. The following three items are updates on the events the four weeks since this September 30th meeting.

First, the Johnson County pipeline was placed in service, and our current net sales are 17 Mcf/d on track to hit our 30-40 Mcf/d year end target. To that end, we recently stepped up our activity level from one to four rigs.

Second, we’ve completed three additional wells and are continuing to see improved reserves to the well as we enhance our completion technology. The average net reserves per well for the three latest wells is 2.6 net Bcf per well. One of this, the Fritz No. 3H, appears to be one of the better Barnett wells drilled by any operator in Johnson County so far. Note that this three well average of 2.6 Bcf per well is significantly more than the 1.92 Bcf per well we had shown in our analyst conference. To reiterate the awesome economics of this play, a 2.6 Bcf per well yields a 100 plus percent after tax rate of return, and a 1.92 Bcf well yields a 70 percent after tax rate of return.

And the third point subsequent to our September 30th analyst conference is, we’ve added an additional 20,000 acres, most of which are in what we call our lower risk areas. These are counties with previous Barnett drilling and/or production history.

To summarize, most of our 90 well 2005 drilling is done in Johnson County, and we expect to exit 2005 at 100 Mcf/d net rate. Additionally, we will be completing wells in a 50-acre three well downspaced pilot in Johnson County during the fourth quarter, and should have some results by the second quarter of ’05. Reserve ranges we have previously provided were based on 100-acre spacing, so I am sure this 50-acre pilot will be closely watched.

Outside Johnson County, we will be acquiring 3D and drilling a few horizontal wells, and we should also have these results by the second quarter. We’ve made a lot of progress capturing a big position in this emerging play, and we will continue to be positive. We are now comfortable enough with the completion technology to begin development with a [degree] program. But I will reiterate that our overall intention is not to outpace our learning curve in this technology play. We will develop this resource in a deliberate, well thought out manner. I will now turn it over to Ed Segner to review capex and capital structure.

Thanks, Mark. With respect to capital expenditures for the third quarter of ’04, exploration and development capital expenditures were $400m, including $4.7m of acquisitions. Year to date, exploration development capital expenditures were just over $1.b, $1.009b, including $7.5m of acquisitions.

The capitalized interest for the quarter was $2.4m, year to date it is $6.6m. Our revised 2004 capex program, including acquisitions, is approximately $1.45b, as Mark indicated earlier. Excluding acquisitions, our estimated capex program is $1.4b. This is an increase of $100m from previous guidance. Approximately $48m of the increase is from increased leasing activities, primarily in the Barnett Shale. The rest of the increase is largely from increased service costs, including tubulars, and increased exploration activities.

For 2005, as indicated at our September 30th analyst conference, we gave a very preliminary capex number, excluding acquisitions, of $1.4b. We also indicated that at $5 Henry Hub price, we would expect to be roughly balanced on capex and cash flow in 2005. I will note that we still have not gone through our formal ’05 budget and planning process, and as we’ve indicated to you in the past, we are long on drilling opportunities, and at current prices it is likely to see an upward revision in the actual capital budget for ’05.

With respect to capital structure, at September 30th, 2004, total debt outstanding was $1.063b and the debt to total capitalization ratio was 28 percent, down from 33 percent at year end 2003. At quarter end, we had $82m of cash on the balance sheet. The effective tax rate for the quarter was 34 percent and the deferred tax ratio for the year is expected to be about 72 percent. The third quarter 10-Q is expected to be filed later this week. Now I will turn it back over to Mark.

Thanks, Ed. Let me discuss our view of the overall U.S. gas situation and give you a few thoughts on our [hit] situation. We expect 2005 overall U.S. gas supply from all sources, included imported LNG to decline by about three-tenths of a Bcf a day relative to 2004. So the 2005 market is likely to remain tight and the relative degree of tightness will be a function of weather and GDP growth. Our hedge collar position was articulated in yesterday’s 8-K, but I will summarize it as follows. We have no oil hedges in place. Regarding gas, we have price swap contracts in place for November and then we have less than 10 percent of our gas collars from November through March at strong floors and ceilings. After March, we have no hedges or collars in place. Given the tight supply/demand situation we foresee, it is probable we will stay relatively unhedged.

Now let me summarize by reiterating our strategy. We continue to believe the highest reinvestment rates which were generated by organic growth through the drill bit and we have geared the Company to that end. We will continue to run the Company maintaining a low debt level. We are currently long on attractive, organic reinvestment opportunities. Our North American divisions, without taking into account the Barnett Shale, are gaining momentum going into ’05. The bigger divisions, Calgary, the Rockies, South Texas and East Texas North Louisiana all expect production to be up year-over-year in ’05 versus ’04, and we expect flat to slightly up production from our smaller U.S. divisions.

Additionally, the Barnett will be additive to these numbers and we expect the growth curve from the Barnett for years to come. When you layer on our U.K. and Trinidad ramp-ups, we expect 34 percent 2004 through 2006 production growth as articulated in our recent analyst’s conference. More importantly, we led the peer group for the past five years in both ROE and ROCE and with the high rate of returns Barnett has set in our arsenal, we feel like we have a great opportunity to again lead the peer group over the next five years in ROE and ROCE.

Thanks for your attention, and we will now go to questions and answers.

Thank you. (Operator instructions) We will take our first question from Bob Morris; Banc of America Securities.

Good morning, Mark.

Hey, Bob.

How are you?

Good.

Quick question on the Barnett Shale, with the three additional wells you’ve completed now, I think you’ve got 20 wells producing at the rate of 17m a day, that is pretty close to what you were before this latest well of 5.8m a day was tied in. Are you surprised that the volumes aren’t higher, there are still some issues being resolved there on the pipeline and the compression that should bring those volumes up at a quicker rate. I know you’ve got two more wells to tie in, or are waiting for tie in before you were going to drill another eight wells, so that is probably going from 20 to 30 wells by year end to get from 17m to 30-40m a day – are you forecasting some kinks in the compression pipeline, or do you expect these additional wells to be at a lot higher rate?

Given the total number of wells we have so far, it is a bit inaccurate. If you go to that one chart we had at the analyst conference on the Barnett Shale completion techniques, we had type A, type B completions, faulted, unfaulted. Basically what I would say is really what we are looking for is these type A unfaulted completions and where we are right now, we have 11 wells that are really fitting into that category. So I would say that basically, the majority of the contribution we are getting right now are from those 11 wells.

What’s happened is those 11 wells are producing, on a gross basis, in the range right now of about 23m a day. That translates to about 17m a day net. That situation is about what we expected. We mentioned that initial flow rate on the fric, but again I would caution everyone. The initial flow rate is no more than a preliminary indicator, because these wells decline very rapidly. Again, typically these wells will level off between 1m and half a million a day, so it is not so much the initial flow rate, it is really – this play will be a conglomeration of hundreds and literally thousands of wells that make, in a long term basis, about half a million a day. So I would say we are exactly on track where we expected to be at this point in time, Bob, with the wells.

The most significant point that we have seen in the 30 days, however, is that the last three wells we have achieved this higher average on reserves per well, and although it is – three wells don’t make anything we can really extrapolate from, it is encouraging. We are beating this 1.92 Bcf per well and we believe, if we can get another 10 of those wells under our belts where we achieve this 2.5 Bcf, 2.6 net Bcf per well average, then I think we will have enough data to start feeling comfortable that maybe we can replicate that times hundreds of wells.

And the average for the last three wells, what reserves are you putting on this fric well, feed at 5.8m a day?

On a gross basis, somewhere between 4-4.5 Bcf.

Okay. All right. Thank you.

You bet.

We’ll take the next question today from Joe Allman, RBC Capital Markets.

Good morning, everybody. In terms of these last three wells, were you talking about the average reserve recovery of 2.6 Bcf, on an eight ace basis, what would that be? Would that be like 3.2, 3.3?

About 3.3, Joe.

Got you. And I know you expressed your goal of getting up to 400,000 net acres by year end. Beyond year end, do you plan on continuing to buy acreage in the Barnett Shale?

Our intention is, we are going to continue to buy acreage until technical data indicates otherwise, and by year end or by January, we will have some data points on a couple of outline wells in some counties outside of Johnson County. Those wells will be kind of important to us in terms of what we do in acreage outside of Johnson County. We will probably release that data to the public, maybe by the second quarter or so. So we are really going to be looking at some of the technical indications, and the other technical indication we would be looking at, we have some 3D that we are shooting outside of Johnson County, and we will be looking at what portions of those 3Ds are relatively unfaulted. That will give us a real indicator as to what does the geology look like outside of Johnson County?

If the geology looks relatively similar in terms of faulting to Johnson County, and if we get some positive indications from these few wells we are going to be drilling outside of Johnson County, our intention would be to continue leasing as we get into ’05.

All right. Thank you.

Okay.

Ellen Himmens of Bear Stearns has the next question.

Thank you. Mark, a couple questions. One on Canada. Can you give a little color on your production in the Horseshoe Canyon right now, and kind of what your plans are for there for 2005?

I’ll let Loren field that one there.

Yes, I guess it is fair to say that our prediction is, as anticipated, we are getting the same kinds of initial IPs as all of the operators from all four sides of this. I can’t tell you what the average is, but we’ve had ranges in there from around 100 and 200 and in fact, up to 250 Mcf a day, a little over. I guess we’ve drilled now a total of 70 wells this year – Gary, what does that look for next year?

Somewhere around 150 wells.

And the reserves we are currently achieving there, Ellen, about three-tenths of a Bcf per well for about a quarter million dollars, roughly.

Second question I had was, Ed, your comments on the preliminary outlook for capital spending for ’05, where you expect that to trend upward. How much of the upward pressure do you think is just going to be due to increased service costs, or will it be due to a higher level of activity?

Service costs are probably going to be up somewhere around 15 percent. And the balance of that would be just increased activity.

Thank you.

Okay, Ellen.

Greg Pardy of Scotia Capital has the next question.

Hi, good morning. Mark, you’ve touched on this already, but can you just go back to the Barnett in terms of first year declines that you are expecting on the wells? Now you’ve got 17 down now, what is your thinking there?

The first year declines on these wells are pretty steep, in the range of about 60 percent. So you know, like I say, the initial production rate on these things, don’t be guided too much by that. That’s just kind of a very initial data point. What we really look for is, what are the wells produced sales the first two weeks, or first 30 days is more of an indicator. But the way you should really view this play is, you know, almost all of these wells after six months or so are going to level out at 1m a day or less and so it is really just how many wells can we accumulate that make 1m a day or half a million a day over the life of the well, really. As opposed to a whole bunch of wells making 3m, 4m or 5m a day.

Thanks very much.

Okay, Greg.

Up next we have Candace Gimbel, Smith Barney.

Hi, this is Gil Yang. Again with the Barnett, could you give us some color as to what made that one well so good? Is it just that your seismic shifting is allowing you to drill more effectively, or are you completing better? And, you know, in that context I guess, is that 5.8 Mcf well a type A unfaulted or is it sort of a type A unfaulted modified?

It is unfaulted and it is a type A modified completion. It is an enhancement of the type A completion, Gil. It is something that was done differently than our standard type A completions. So it is just another evolution on the completion learning curve.

Okay, and are all three of those wells of a modified type?

No, of these three, that is the only one that is the modified completion. They are all unfaulted wells. The other two would be type A. This one is type A modified if you want to get specific.

Okay, and I know it is taking very small samples, but do you have any confidence that the modified really substantially will be level, or is just that this well happened to be good, type of performance.

We don’t know, but a couple of the other we’re drilling right now are the type A modified. So give us another couple months and we will have data as to whether the type A modified is really replicable or not.

Okay. Thank you.

Okay.

The next question comes from Irene Haas, Sanders, Morris Harris.

A question, the North Sea, can we have some update on the Viper prospect, are you still drilling that? And then West Balkin, have you started yet? And did you continue to see extremely strong gas prices in the U.K. market?

Yes, Irene, the Viper well is currently drilling, we just haven’t reached target depth yet, so sometime within the next 30 days we expect to reach target depth on that. The West Balkin well we expect will probably spud or start some time in December, so it will be a first quarter event when that well is positioned. And on the gas prices in the North Sea, one, we don’t purport to have any expertise as to what the supply/demand mechanics are in natural gas in the North Sea, but there is obviously some linkage with crude prices there. But our expectation is as long as crude prices stay relatively strong that the gas prices will stay pretty robust. Since we ran our economics getting into the North Sea, the $2.75 gas price we are pretty comfortable there.

Actually, our DDA, our year end DDA for the North Sea, we expect is going to be in the range of about 67 cents, and our LOE, which would include the processing fees on third-party platforms is about 85 cents. So this is going to be an extremely high profit margin area for us with these kinds of gas prices.

Great, thank you.

Okay.

Up next we will hear from Mark Meyer, Simmons and Company.

Good morning. Mark, you gave some comparative return statistics on the 1.9 Bcf versus the 2.6 Bcf and I think you used strip prices in some part of your economics. Can you talk about kind of what the order of magnitude level is reflected in those returns?

Yes, actually I was just quoting the numbers that we had provided in the September 30th analyst meeting, and really at that time we had used strip prices that was the three year NYMEX strip which would have been about a September 20th three year NYMEX strip, and $4 flat thereafter. So obviously if you ran at today’s three year NYMEX, you get a much stronger number, but the bottom line is, on the three year NYMEX as of a month or so ago, a 1.2 Bcf well would give you a 28 percent fully loaded after-tax return including the land and the seismic costs. 1.92, 70 percent return and then a 2.4 Bcf well would give you 100 percent rate of return.

You know, the point we make is basically this is, as we see things in North America, this Barnett is one of the highest reinvestment rate of return assets that we have in our portfolio that is of large enough consequence to be meaningful. As we begin to layer in meaningful amounts of this beginning in ’05 and certainly in ’06 and ’07, we think it is going to act as a leavening effect on the United States DDA rate. And that will obviously flow through in ROE and ROCE as we get more and more Barnett contributing to the overall mix.

One more question. On the Davis Brothers well, can you talk a little bit more specifically about how you completed that well, maybe how much of the pay, the kind of oil that you perforated?

Mark, there were numerous pays in that well bore. We did multiple stages and we would frac and set plug, perforate the frac and set plugs as it came up the hole, so there is, I think the number of intervals that we had was somewhere around 10.

I think we ended up about a five-stage frac, Mark. We had over 450 feet of pay in that well. Given the pressures and the amount of pay that we had, we weren’t really designed as a non-operator, what we are saying is we were not really designed to get effective frac over all that 450 feet, so our guess right now is that only a portion of that has been effectively completed.

Are you seeing any water production.

We are not.

No.

Great, thanks.

(Operator instructions) We will take the next question from David Snow, Energy Equities. David Snow, your line is open. Hearing no response, we will move to the next question. John Herlin, Merrill Lynch.

Yes, hi. Could you address the frac technique you are using in the Devonian? You said they were transferring your technology from the Barnett. Can you be more specific?

Yes, in a generic way, John. What we have been doing in the horizontal Devonian in West Texas was doing a fracture technique that had been generating what we thought were good economics, but what we learned in the Barnett was, our early Barnett wells we were not distributing the fracture very evenly along the whole length of the Barnett horizontal well and as we began to experiment with the horizontal Devonian, we found that basically the whole program we drilled out there, we likely had been doing the same thing, i.e. not distributing the fracture very well along the whole horizontal treatment of the horizontal leg.

So we’ve now done two horizontal wells out there in West Texas and the conclusion we’ve drawn from the two experimental horizontal wells is that we can drill a single lateral and get the same productivity in West Texas as a dual lateral using our old completion technology. This has obviously opened up our eyes and increases our opportunity sets quite a bit.

One, it could make you go into even less attractive areas and exploit those. The second thing is, you can do a lot more just because your costs are less. So I guess what it tells us is that about five years ago we got into this horizontal drilling in type zones as, I guess, a core competency of EOG in the U.S. and it looks like there are a lot more areas we can move into in the U.S. as we advance this technology. I know I am answering in a bit of a circular method there, but I do think we have an edge on a fair amount of the industry as to how exactly complete these kind of wells.

Okay, sure, this is all right. Next question, in Trinidad can you give us kind of a post-mortem on what happened there on the wildcat?

On the UB Well, John, we are 55 percent working interest there. That was our first wildcat on that block. It was off our new 3D. I have to say, the data was not as clear as we had hoped, really because the geology is fairly complex down there, a lot of faulty. It was a track failure. We do have other leads working on that block.

Okay. And last one for me, some of your peers are generating a fair amount of free cash flow. Why not more cash flow, less volumes?

Yes, here is the way we look at it. Basically, we are going to continue to reinvest as long as we are getting an attractive reinvestment rate of return. We just happen to be blessed with a lot of projects that are very high reinvestment rate of return projects, so we believe that is the best place to utilize the shareholders’ money. I guess the other option, or the other way to look at it is, the current futures strip is $8, and if indeed you run that through based on our production forecast next year, it would give us a cash flow in the range of $2.1-2.2b, which would give us free cash flow in the range that we can almost pay off all of our debt by year end ’05, in addition to executing our program. So we may be in a position where we are going to have very, very high production growth next year, all organic, and if these prices hold, in theory, in a way, we could be pretty close to debt-free by the end of the year. We may be able to give the shareholders both.

Okay, thank you.

(Operator instructions) We will now hear from Ken Beer, Johnson Rice.

Hi Mark, that actually dovetails perfectly with my question. If indeed you do have cash flow above that $1.4b plus that you’ve indicated, and you’ve got these 100 percent rate of return projects, is your inclination to put it right back into the ground, or is the organization pretty much at a level where you are maxed out organizationally and people-wise, even though you have additional prospects? And then therefore you’d either have to go to paying down debt or buying in stock?

Yes, you know the one area that the question would apply to is in the Barnett, particularly if you have a lot of 100 percent reinvestment opportunities, why wouldn’t we double or triple our activity in the Barnett? It is my sense at this point in time that just due to technical limitations, in other words, how many 3Ds can we get shot and how many drilling locations can we really get set up and everything, I’m not sure we can go a lot faster than drilling 90 wells in any case. So my sense is that although it is possible we could slightly ramp up our overall program, we’ve pretty much got our overall drilling program for next year pretty well set in our minds. The only thing that could affect would be the amount of inflation that we might see through service companies. So it is more likely we will probably just execute that program rather than hyper accelerate it, regardless of gas prices. So then the choice would really come down to buying in shares or paying down debt, as opposed to massively accelerating the drilling program, Ken.

That’s fair.

On the acquisition side, we continue to believe that prices are just very, very, very strong and it still is unlikely that we would jump into the acquisition game in any major way.

Ken Beer; Fair enough. One last question and then I will jump. As you look at, we’ll just use the Barnett as an example but you could use any other of your projects -- but if you look at a project and start seeing service costs moving up 10, 15, 20 or 25 percent, do you have a sensitivity as to what would happen to that 100 percent return project with a 20 percent increase in service costs?

Yes, we watch that closely, and my overall comment would be it is not so much that with a drilling rig costs 20 percent more or a frac job costs 20 percent more – I mean, we’ll watch that. But what we’re watching even more closely is the relatively efficiency of say that drilling rig. In other words, during the last kind of boom which was ’01 or so, what we saw is if it normally took us say 15 days to drill a well, with the new rig crews and everything crunching at that time, maybe it would take us 22 days to drill that same well just because all these inefficiencies crept in the system.

Right.

If we see that begin to happen, then we will begin to cut back our activity. So we are watching very carefully for that. We have not seen that in any significant way so far, but if that begins to occur then we will do some things and you will see us make some adjustments to our activity level. I guess that is possible. All I can tell you right now is we are watching closely for that.

Thank you, guys.

Yes.

The next question comes from Shawn Reynolds, Petrie Parkman.

Good morning, guys. I wonder if you could expand on, you linked a little bit, Mark, you talked about – it might be worth reiterating what the reserve potential is just from the in fill potential there, and then I know at the analyst conference you talked about a couple of “exploration” or extension ideas, and I am just wondering what the status of those are in the [Uinta].

In geologic terms, the [Uinta] is pretty similar to Peons Basin in Colorado, which is already being downspaced to about 10-acre spacing. We feel that our position in the [Uinta] Basin there from the depositional and stratographic work we’ve done is likely to at least ultimately get downspaced to 20 acres and probably a fair chance it will ultimately go to 10 acres. So if you look at where we are booked on reserves today, and where we are currently on our spacing for this [Mesaburg], we are currently booked and spaced on 80 acres, so we’ve got yet to downspace with all of our 40 acres and then into 20 acres and then potentially to 10 acres.

So one way to view it is that we have an unrealized reserve booking of somewhere between a quarter of a Tcf and a half a Tcf net to us that will occur. That is pretty much in the bag. Now the only caveat to this is all of this is on either Native American land or on federal land, and there are permitting issues there. The ultimate downspacing time is likely to take place over many years. So this isn’t something we are going to be able to do over a two-year period or so. Now we’ll begin to do that starting in ’05, but I think it is pretty much in the bag. So that is something that could be put as a true value for EOG.

Now what we also believe is that Utah and this whole [Uinta] basin area is one of the less explored areas in the Rocky Mountains and we’ve captured a pretty significant acreage position to the west of our existing production in looking for a clone in a relatively unexplored portion of the basin. We’ve drilled a couple of step out wells and had wells that I would say are either near misses or they are marginal producers. They are not barn burners, but they are close. And we’ll be drilling more of those as we get into next year and my sense is that over the next year or two we will find another significant tight gas accumulation there. It’s just a matter of really drilling a couple more wells to sort it out.

So it will be an area of pretty intense focus for us over the rest of this decade. Does that give you what you need, Shawn?

One more thing. I guess one of your competitors out in the area of Russet reported a very nice Black Hawk well, and I am wondering if you have anything specifically focused on chasing the Black Hawk?

Yes, Shawn, the numbers in [inaudible] do include Black Hawk. Now we call it all [Mesaburg] but there are several formations within the [Mesaburg] and Black Hawk is one of those that has been good to us so far in our main core asset area, Chipetta West, [Natural Butte].

Right. Thanks a lot.

Up next we will hear a follow-up from David Snow, Energy Equities.

Yes, actually my first question. I was off the line for just a moment, but I’ve heard, I believe and I am wondering if you can tell me. Are you, in the Barnett Shale, using a slotted liner and submitting it and trying to put your frac right into a specific location? Is that part of the method of completing?

David, that’s a good question. We’ll just give you a circular answer on that and say we are not going to answer you directly. We think that we’ve got a bit of a competitive edge over the rest of the industry in how we are completing, and just due to confidentiality reasons, we are not going to give any specifics on it.

Okay, I thought I would try anyway. I am trying to ask another question about the acreage. Are you, prospective on the whole 345,000 so that in theory you could be drilling 3,450 wells or is some of that under schools and places where you are not going to get to?

No, on the whole 345,000 acres we’ve specifically leased in areas that are accessible. So none of it are under city limits or schools or anything like that. We really started leasing immediately south of the Culture of Fort Worth, if you will, in Johnson County. So if the Barnett is productive, then basically we can access all 345,000 acres.

And is that likely to – you are likely to drill the whole thing, or would you high grade and drill the type A portions, or how would you – would that be 3,450 locations, basically?

Well what we’ve got right now, we’ve kind of broken it out into two categories of acreage. As of today we’ve got about 155,000 acres that we call lower risk areas, which is Johnson County and other counties. The remaining 190,000 acres are in what we call exploration areas. What that really connotes is just they are untested areas where no one has ever drilled a horizontal Barnett well and so you know, we basically would say 155,000 acres we are more comfortable that they are indeed – that’s got a high probability of working. The other 190,000 acres, we will likely be the first one to drill a horizontal well in most of those areas, and we just have to see whether it works in those areas or not.

Obviously we think it will, but we just have to prove it first.

And in those others that haven’t had horizontal wells, have they had vertical wells with the recent year’s completion methods?

There is – yes. All of these areas have had vertical wells in them. Some of them have not – they have all penetrated the Barnett. Some of them have not really tested the Barnett, but in all of the areas, we know where the Barnett is because of vertical Barnett wells in it.

Okay.

So there is not really a geologic risk of, does the Barnett exist or not? We know it exists, it’s just a matter of no one has really tried to produce Barnett gas from some of these areas.

And you are looking for unfaulted completions, I guess. So that means you are looking for less fault density in the areas?

We are looking for unfaulted areas in this acreage.

How much, percent-wise, would fit in that category?

Well, what we’ve found so far in Johnson County, it’s about 50 of the acreage is unfaulted, so we are trying to hone in on the unfaulted areas. So if you extrapolate that to the rest of the acreage, in very rough terms out of 345,000 acres, then 172,000 acres would really be acreage that we would actually drill on.

You could probably go back and drill in the rest eventually though, I would imagine. Or would you downspace on the unfaulted?

Well, we just don’t know. It’s a big resource. Our job now is to capture it. We believe we downspaced clearly on the unfaulted and whether we would ultimately drill on the faulted is a technical question we haven’t answered yet.

Thank you very much.

Okay.

Van Levy of CIBC World Markets is up next.

At the conference, Mark, you talked about gas prices. I thought it was $7 or so, and if it hit this level you would consider putting on a heavy hedge for this winter season. You know, price has obviously moved up but yet it seems like your posture has changed. What has changed in your mind in that regard?

They flew by $7 so fast that they can’t do anything. They flew to $8 so quickly. I confess, I am kind of confused by how fast gas prices moved. They appear to have moved just simply with oil and potentially because of some of these weather forecasts. Our sense is right now that because of the relatively tight supply/demand scenario we are probably not going to get ourselves in a heavily collared position at this stage.

Why not just buy, say puts at some price out of the money?

Yes, we keep looking at puts, they are just so darn expensive though. You know, they –

I am talking about maybe 5, 5.50. Something out of the money where it wouldn’t be that expensive but still would give you some level of protection and leave your upside open.

We haven’t priced them that low. We will take a look at it. But at this stage, I guess we are comfortable enough with the supply/demand where we are probably – we’ll not do a whole lot on price protection.

Right. You have a great balance sheet, so there is no real need. Second question, in terms of the Barnett Shale reserve booking, when your engineers look at booking reserves per well, for instance, this new well you are talking about 4-4.5 Bcf, you are not doing any pressure build-up tests and things like that, right? It’s simply looking at the starting production point and extrapolating previous pipe log curves. Is that right?

That’s exactly right. What we found in something that is tight and dominated by fracture flow, really pressure build-up analysis or any kind of pressure analysis is very problematic. So the reserve estimates we use – in fact, the reserve estimates that D&M uses for the Barnett are mainly based on pipe curve and decline curve analysis.

So I guess the genesis of my question is, those new wells that you are talking about, 3.3 gross Bcf, how likely are those to change? How confident are you that those reserve levels would hold up and what could change positively or negatively?

Obviously, we will know more after we get six months or a one year production history off of them. What we are basing them off of are, we’ve got a database of about 3,000 wells up in the core area and that is a pretty solid database to build your pipe curves off of. There is some logic that these horizontal wells may level off and not decline as fast as some of them in the core area, but right now I would say we are fairly comfortable that we’ve got a pretty good handle on these. I’m not too worried about quoting reserve estimates on these wells.

Okay. And then the nine wells that didn’t work out, are those uneconomic or 10 percent rate of return wells? You mentioned the 20-well set that essentially was the 17 Mcf/d. Those were 11 wells, right?

A few of those were just uneconomic, pretty well totally. I’m looking at my list here. There were about six of them that just didn’t make the cut at all, and then there were another three that they might yield a 10-12 percent rate of return. So it really took us about the first nine wells to get off the learning curve before we figured out how to locate these wells in unfaulted areas and then how to complete them.

That was, again, the thrust of my question. So you are determining where the sweet spots are and the not so sweet spots, right?

And then determining how to complete the wells, even getting them located in the sweet spot.

Okay. And then the last question, you know, a huge emphasis on Barnett Shale. A lot of companies, when you get on the conference call, it’s all about Canada. Do you have a lesser view of Canada? Why – it doesn’t seem like you spend as much time, or effort. Is that just something being overshadowed by the Barnett?

It’s really, the one issue we have here is that I think most all of our North America activity is ex-Barnett or getting overshadowed, and that is a little bit of, I guess, an unfair situation because what is really packing the mail now and what’s delivering the production growth is not so much the Barnett this year. You know, we’re going to deliver 9.5 percent production growth this year and maybe 1 percent of that is coming from the Barnett. The other 8.5 percent is coming from all the other parts of the company and a big part of that is indeed Canada.

So the fact is, our Canadian production growth is up 35 percent or so this year, and next year we expect it will be up – I can’t quote you an exact number, but probably at least another 10 percent or 15 percent year-over-year. So it is just a matter that it gets overshadowed because now it seems fairly standard, unfortunately.

Okay. Great. All right. Thank you. Thank you very much.

Okay, Van.

Mr. Papa, at this time there are no further questions. I will turn the conference back over to you for any additional or closing remarks.

Okay, I have no further closing remarks.

That does conclude today’s conference. We would like to thank you all for your participation. Have a great day and you may now disconnect.