EOG Resources Inc (EOG) 2004 Q1 法說會逐字稿

Good day, everyone. Welcome to the EOG Resources First Quarter 2004 Earnings Conference Call. This call is being recorded. At this time I would like to turn this conference over to the chairman and CEO of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, and thanks for joining. We hope everyone has seen the press release announcing our first quarter 2004 earnings and cash flow 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 Shelf play, 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.

With me this morning are Ed Segner, our president and COS; Loren Leiker, our EVP of exploration and development; Gary Thomas, our EVP of operations; and, Maire Baldwin, our VP of investor relations.

This call will be slightly longer than our normal earnings call, because we have so many good items to talk about. We filed an 8K with second quarter and full year 2004 guidance on Friday, whereby we increased our full year production growth forecast from 6.5 to 18 percent. As I stated in February, we expect our production to increase each quarter throughout the year, particularly in our second half when our Canada and Trinidad volumes will grow significantly.

However, and in my mind more important than the production growth increase, we have significantly reduced our full year unit cost guidance by 12 cents per Mcfe, due largely to expected lower DD&A and lower impairments. We now have three months of actuals, and we have a lot of early drilling success, so we now feel comfortable in lowering theses unit cost estimates.

As you know, in 2003 as in most years for the past decade, EOG has been a low cost producer, and we see no reason why this should change in the future. Our 8K also notes that we are maintaining our 2004 capex level at the originally stated $1.1b, excluding acquisitions.

During the first quarter, I also note that we generated $114m of free cash flow, which enabled us to pay down $23m of debt and increase our cash position by $91m. During the quarter, we also raised the dividend by 20 percent, our fourth increase in the past five years.

Reconciliation of net operating cash flows to free cash flow is found in our earnings press release which is posted on our web site. Now I will review our first quarter net income available to common, and discretionary cash flow available to common, and then I will discuss operational highlights.

As outlined in our press release, during the first quarter EOG reported net income available to common of $98.1m, or 83 cents per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net income available to common to eliminate the market-to-market impacts, EOG’s first quarter adjusted net income available to common was $125.2m, or $1.06 per share. The reconciliation of GAAP to non-GAAP adjusted net income available to common is found in our earnings press release.

For investors who follow the practice of those industry analysts who focus on non-GAAP discretionary cash flow available to common, EOG’s Bcf available to common for the first quarter was 348m, or $2.96 per share. The reconciliation of non-GAAP discretionary cash flow available to common, to net operating cash flows is found in our earnings press release.

I will now address our operational highlights. I will first provide our key points regarding our standard [inaudible] and doubles operations, and then I will discuss our big target success and the likely consequences that will emanate from this success.

In South Texas we are continuing to achieve excellent results from all four of our main geological plays. The Roletta, [Lobo], [Frio] and Wilcox. In the Roletta, we are having great success in our standard vertical well program, and have an early success with a horizontal well. Two key vertical wells drilled during the quarter were the Marshall State 5 and 6. These wells are currently being completed, and are anticipated to come online at 10 to 15 Mcf/d each. We have 50 percent working interest in each of these.

These wells have proved up 15 or more offset locations. We continue to have success in our traditional reinvigorated [Lobo] program, and have increased acreage in potential locations in the past six months. Our inventory of [Lobo] and Roletta locations continues to increase, and we plan to maintain three rigs operating through year end.

Additionally, we drilled the first South Texas horizontal Roletta well in a particularly low permeability faces that was previously uneconomic with vertical completions. This well is currently flowing 5 Mcf/d and has an estimated 3.7 Bcf of reserves for a $4.2m well cost. We plan to observe this well’s production for a few more months and if it holds up, this opens a new area of Roletta reserves to access. Overall, our Roletta and [Lobo] inventory is considerably stronger and deeper than in past years.

In the Frio formation, we’ve recently completed our Valley 2 well for 7 Mcf/d and 1350 barrels of condensate per day. We have a 72 percent working interest in this well with multiple offsets.

In the Wilcox, we drilled a confirmation well to our recent Henley No. 1 high rig discovery. The Henley No. 2 is currently flowing 30 Mcf/d. We expect to drill multiple offsets this year, and to be producing about 100 Mcf/d gross from this field before year end. We have a 50 percent working interest here.

In our Mid-Continent area, our two-prong drilling effort is working fine, with six rigs running in our standard [inaudible] play, and six rigs in the horizontal Cleveland program, where we continue to achieve 1.3 Bcf per well for a $1m well cost. Two recent completions, the Blackhorn 367 No. 4 and Brohard 819 No. 2 are flowing 3.5 Mcf/d and 2.5 Mcf/d respectively. We are currently testing the productive limits of this Cleveland play, and have had success extending the limits, further expanding our inventory. Our current acreage position here is 87,000 acres.

In West Texas, several years ago we identified the horizontal Devonian as a possible big target play. Currently we are in the third year of this program and are drilling with five rigs. A recent Antitypical well is a 92 percent working interest. Purdue 101 No.1 which was recently completed and is flowing 4.6 Mcf/d and 1,000 barrels of condensate per day.

In the Rockies, we’ve got four bread and butter plays working. The most exciting from a reserve viewpoint is another of our past big target plays, the Utah [Unintibation Mesaburg] in Natural Butte and Chipetta Wells. We are running two rigs in this play and will add a third rig in June with plans to drill 60 [Mesaburg] wells this year. The results have been better than expected, about 1.5 Bcf per well for a $1.1m well cost.

We initially indicated we had 100 to 200 net Bcf to develop in this play, but we now feel that the net reserves we have to develop on our acreage are more like 200 to 400 Bcf, of which 62 Bcf of puds were booked at year end. However, I will caution that this acreage is on Native American and BLN land, and because of permitting limitations, development will take place over several years. Overall, we expect to drill 90 to 100 wells in Utah this year in both the [Mesaburg] and [Wassess] formations.

During the quarter, we successfully kicked off our [MoxaMarsh] Dakota development program and a 70,000 acre farm-in from a major. We’ve now drilled seven wells and participated in six outside operating wells, and early results indicate we are obtaining greater than a 20 percent IRR in this project. In eastern Montana we are continuing our successful two rig Valcon Oil siltstone horizontal project. We recently completed the [Edden Call] No. 1 due lateral, which IP’d for 700 bpd of oil, and we have 100 percent working interest. We expect to be producing 3,000 net barrels of oil per day by year end, compared to 200 barrels of oil a day on January 1st.

Additionally, we’ve completed our standard Big Piney frontier program where we expect to drill 20 to 24 wells this year.

In Canada, we are gearing up to drill 1,300 shallow wells in southern Alberta, 100 of which will be Horseshoe Canyon coal bed methane wells at [inaudible]. As usual, Canadian volume growth will primarily occur in the second half of the year as these new shallow wells are tied in.

In Trinidad, we’ve been busy drilling development wells at our Porilla Discovery to provide sufficient deliverability to feed our existing contracts, and the new ammonia and methanol contracts, and our well productivity results are better than expected. Our recently completed Porilla No. 1 well has a 150m a day flow capacity, and we expect about 300m a day total new capacity from our three-well program. Natural gas production from these wells and other sources will easily feed our $150m a day gross of new gas contracts that we will achieve within the next 15 months. We expect to finish up our Porilla Offsprey development well program by July, and then we will begin drilling what I call standard depth exploration wells for the remainder of the year.

We also have a hot potential deeper exploration well teed up which I will make a reference to later under our big target plays. We expect to ramp up our Trinidad volumes by 50 Mcf/d commencing in August, when the Nitro 2000 ammonia plant is commissioned. Plant construction is currently on schedule.

On the gas contract front, we still expect to finalize a 30m a day Atlantic LNG train 4 contract before year end. Frankly, things are going very well in Trinidad.

Switching to the U.K. North Sea, we expect to commence production from our two gas discoveries of October and to achieve a year-end exit rate of 40 Mcf/d net. As part of our strategy, we are transitioning from a non-operator to an operating mode this year, and we expect to spud our first EOG operated well on the Viper project in the southern gas basin in October.

In summary, our normal singles and doubles activity outside the U.S. and Canada are on track. As you know, each year we devote approximately 5 percent of our capex to big target plays, i.e. plays that will make a meaningful difference to EOG if they work. We promised we’d provide results on three of these plays today, and the scorecard is as follows. We have one very large success, which is the Barnett Shale. One where we are cautiously optimistic, which is the Wyoming Wind River Basin Ranch Well, and one, the Wyoming [Mernia] Anticline where we need more testing to determine the economic viability.

The Wyoming Web Ranch well accounted over 200 feet of gas charted [land] pay and we are currently testing. This is a 100 to 200 net Bcf target. On the [Mernia] Anticline, we simultaneously drilled a well with the north and south edges of the prospect. The north well was dry holed and was expensed in the first quarter, while the south well is currently being flow tested. However, regardless of whether Web Ranch and [Mernia] work, the big picture results are overshadowed by the Barnett Shale, which is likely very large and very significant to EOG.

You may recall that the original delineation of a four plus Bcf Barnett Shale productive area was limited to north of the city of Fort Worth, where the Barnett Shale was under laid by the impermeable Viola formation which formed a barrier between the Barnett and the [Went Ellenberger] formation below it. Three years ago, EOG began leasing in Johnson County, immediately south of Fort Worth. Today, we’ve acquired approximately 175,000 acres at essentially 100 percent working interest, a significant portion of which is in Johnson County. We began experimenting with horizontal wells to solve the problem of Ellenberger water, and our results to date indicate that the horizontal has solved the water entry problem.

We’ve also done a lot of experimentation with optimizing the well completions, and using our currently optimized drilling technology, the results have been better than expected. So far, we’ve drilled and completed nine horizontal wells, and we’ve shared data with a private company offsetting us, bringing our database to 13 wells over a widespread area.

The first few wells drilled were marginal, but after adjusting both how we locate the wells using 3D seismic, and also how we complete the wells. The most recent nine of the data set have been excellent producers.

On the operating side, we’ve reduced the time to drill a horizontal well from 30 to 10 days. Preliminary indications from data show we can achieve 1.2 to 2.5 net Bcf per well in Johnson County for $1.3m dollars completed well cost. We currently estimate we have 400 to 800 plus net drilling locations on a total acreage position, which correlates to a reserve range of 500 Bcf to 2 Tcf net on our acreage. When you consider that our total 2003 year end reserves in the U.S. and Canada are 3.8 Tcfe, you can see the magnitude of the Barnett Shale impact to EOG.

Most importantly, we expect this project to generate very high IRR, combined with a very low DD&A rate. Johnson County currently has very limited pipeline infrastructure which is expected to be fully remedied during the second half of the year, so most of the production growth and DD&A moderation impact will primarily be felt from 2005 forward.

All of our acreage is on private and not federal land, so we don’t expect to be held up by lease permitting processes, and development will be able to proceed at a reasonably rapid pace. Simply put, we believe this is a large legacy asset, and EOG has the first move. We have approximately 175,000 net acres at essentially 100 percent working interest, much of which we capture before acreage costs in the Johnson County area skyrocketed. We intend to go into a development mode on this project immediately, and will ramp up from one to three rigs by year end.

I will now turn it over to Ed Segner to review capex, capital structure and our hedge collar position.

Thanks, Mark. On the capital expenditure side, for the first quarter of 2004 total exploration development capital expenditures were $268.5m, including $1.2m for acquisitions. Capitalized interest for the quarter was $2.1m.

For 2004, our unchanged estimate for capital expenditures, excluding acquisitions, is approximately $1.1b as stated back in February and as Mark indicated earlier on the call. As we move to capital structure items, during the quarter we generated $114m of free cash flow. We paid down $23m of debt, and increased our cash position by $91m. At March 31st, 2004, total debt outstanding was approximately $1.086b, and the debt to total capitalization ratio was 32 percent, down slightly from 33 percent at year end 2003.

Had we decided to use the $96m cash at quarter end to reduce debt, the net debt to total capital ratio would have been around 30 percent. A reconciliation schedule has been posted to our website. Given current commodity prices, expected production ranges and current capital expenditure estimates, we expect to generate significant free cash flow this year. Our estimated year end debt to total capitalization ratio could be around 26 percent.

The effective tax rate for the quarter was 34 percent, and the deferred tax ratio was 63 percent. Severance taxes for the quarter increased due largely to a litigation settlement in that category of $5m. The first quarter 10-Q is expected to be filed tomorrow. Regarding hedging, our hedge and collar position was outlined in Friday’s 8K and is unchanged from the previous quarter. Now I will turn it back to Mark.

Thanks, Ed. I will summarize by reiterating that EOG’s game plan has been very consistent – organic growth through the drill bit. We kept this strategy because we believe it yields consistently higher investment rates of return than either of the M&A or serial acquisition strategy, and our five year best of class ROEs and ROCEs bear this out. We’ve coupled this with being a low cost producer and keeping low debt levels.

The conclusions I’d like to leave with you are that our normal singles and doubles operations in the U.S., Canada, Trinidad and the U.K. are performing very well, and now we’ve layered on a successful new big target play. I will also note that at year end last year, 12/31/03 we had essentially zero reserves on our books for the Barnett. Most importantly, we anticipate that this play will yield very strong IRRs. I will also note that we have an ongoing inventory of five new big target plays we will be delineating over the next year. Two in the Rockies, one in Canada, one in Texas and a multi-TCF deeper pool test in Trinidad.

Last September we provided profitable production growth targets of 6.5 percent and 10 percent and 7 percent for ’04 through ’06, and noted that one big EOG differentiation is that half of this production growth will come from North America natural gas. Today we raised the total 2004 company production target from 6.5 to 8 percent, and at this September’s analysts meeting we will provide new targets for ’05 and ’06, but I can tell you now that there is probably an upward bias to the 10 percent and 7 percent numbers, depending on the Barnett Development. Using the 8 percent, 10 percent and 7 percent targets, the result is a 27 percent total production increase for 2004 through 2006 which we believe is very attractive.

We also have a number of calendar items and upcoming analyst meetings. We have analyst luncheons planned as follows: Today in Houston, Wednesday May 5th in New York; Thursday May 6th in both Boston and Chicago, and Wednesday May 12th in San Francisco. Our 2004 analyst conference will be held in Houston on Thursday, September 30th. Thanks for your attention, and now we will go to Q&A. Rob, if you can queue up the Q&A.

Absolutely. (Operator instructions) Our first question will come from Mark Meyer; Simmons and Co.

Good morning, Mark.

Good morning.

You cited some pretty big breakthroughs on efficiencies in the Barnett Shale, and with your lowering of overall cost guidance, what are you seeing in terms of efficiency gains, particularly in the U.S.? We note that the highest you’ve been, at least as far as tracking U.S. rig activity and in terms of how you are offsetting cost pressures.

Mark, the Barnett Shale case was one where we really started out very, very low on the learning curve and just with some relatively simple things we knocked the drilling days down from 30 to 10. One of the simple things we did in this case was eliminate the intermediate casings that we had been running in some of the early wells, so now we just had surface casing until we’re at TD.

So I wouldn’t say that we’re having those kinds of efficiencies across all of our other activities at all. In the Barnett it was just a case where we started very low on the learning curve side.

I would say on a total cost presence we are seeing some slight upward pressure as far as the rig rates. We’ve got our pumping services, which is our biggest single well cost, pretty well locked in throughout the year at flat cases, so I would project we will be seeing a mild potential of cost increase on some of our items, tubulars will certainly be one of them as we go into the second half of the year.

Right. I think one of your biggest criticisms of your own, kind of late year ’01 performance was the fact that you had some inefficiencies from the rest of the industry creep in. What’s different this time? Have you staffed enough that you can handle the higher activity level more efficiently?

That’s exactly right. I mean, clearly as we started at ’01 where there was a frenetic amount of activity, we found that we really weren’t able to properly staff the amount of activity with our in-house people, so between ’01 and today we’ve effectively staffed up our geology, geophysical effort and clearly our operations support effort, and so right now we are running in the range with our 48 rigs in the U.S. and Canada, and we are clearly able to supervise that amount.

Okay, a couple of questions on the Barnett, pretty quick. The two rates that you cited in the press release, what time period of test do those reflect?

The River Hills well has been on now for about two months, and the other well there has been on about one month. Just to give you a reserve assessment on those two wells, the gross base, our estimated base on River Hills well about 4 Bcf and it looks like in the range of about 3 to 3.5 Bcf for the other two wells, so these are absolutely excellent wells, and if all of our wells turned out to be similar to these wells we’d be north of the 2 Tcf of reserves I quoted on our cash and acreage.

And the last question, the 175,000 acres compares with what you had at the end of fourth quarter, I believe the number was 110,000. Is that correct?

About 100,000.

Okay, what was the incremental cost on 75,000?

The overall acreage cost is going up there. The first bunch of acreage, we got in the first 100,000, was in the range of about $100 an acre. This second range of 75,000 is maybe double that in terms of incremental costs.

Thank you.

You bet, Mark.

David Tineh; Friedman, Billing, Ramsay.

Hi guys. Some follow-up questions on the Barnett. How many wells do you think you can drill if you use three rigs? Is it simple to think about 100 wells if you just do the quick math?

In real rough terms, David, we can probably get somewhere between 100 and 125 wells per year, per rig in there and so what we are trying to – excuse me, that’s for three rigs. About 24, let me back up again, about 24 wells per year is what we think we can effectively get with one rig. I was thinking by the time we run multiple rigs here. So if you talk about running four or five rigs you are talking about 100 to 125 wells per year.

I will let you know that we’ve been iterating on the different completions that we have and the different ways to drill it, and that’s why we’ve only been running one rig so far. Although we’ve reached a level where we are able to achieve it looks like 3 to 4 Bcf per well for a $1.3m well cost on an 8-8 spaces gross, we are not through optimizing yet. We are going to continue to go, I would say reasonably slowing on this play, for the next several months until we get a recipe that really gives us the optimum reserve per well cost on there.

Also, the pipeline infrastructure in Johnson County is such where up to this point we’ve literally had to shut in an older well to bring on a newer well because of pipeline capacity, we are just so very limited. That is going to get pretty much improved as we go through the second half of this year and by year end it ought to be completely cleared up, so we haven’t been in any big race so far to generate a lot of deliverability only to be backed up by pipeline takeaway limitations. So we are going to time our activity, particularly over the second half of this year with a strategy that as we see it now we will probably go from one rig to two rigs starting in May and then by year end we’ll probably be at three rigs and then for 2005 we are looking at running three to five rigs for the full year.

Could you maybe talk a little bit more about the pipeline infrastructure? Who is spending money and what is the expansion in capacity?

I guess the reason why there was essentially no pipeline infrastructure in Johnson County is that historically there has been very, very little gas production in Johnson County. So we started off with essentially nothing there but just the patchwork of gathering lines. What’s happening right now is that everybody who is in the pipeline gathering and laying business is kind of salivating to get a position in Johnson County. Most of the pipeline companies clearly see that this is going to be a big growth area, and we’ve committed to one company to get an expansion in there. I am not going to get into specifics on the companies, but I would say there are four or five companies that are really competing to get a foot in the door to gather this gas and get the takeaway out of there.

So you don’t have to spend any money?

The bottom line is, we are making a volume metric commitment to one entity that will put X amount of gas through for X amount of years, but we are not spending any capital other than just some gathering system type things. I will also note here from what we have seen in the gas quality in Johnson County, the gas is not as rich as the traditional Fort Worth, or the play north of Forth Worth. In other words, there are just not as many NGLs or liquids in there, so what it means to us is that most of the development in the north had to also have a large liquid stripping plant associated with it. As we see it in Johnson County, that will not be necessary.

That’s great. One last question. What’s your average NRI on your 175,000 acres?

I would just say it is very good, north of 80 percent. Again, this is a competitive area so we don’t want to give a whole bunch of specifics on some of this.

We’re all going to try to build models here and try to figure out what the value is, we just wanted some help there.

Well I’ll give you a value, I’ll give you the Mark Papa evaluation. Since you asked the question, David, if you take our range of 500 net to 2 Tcf net reserves, and if you assume in Central Offshore Texas these types of reserves, which basically I would call D&D reserves, the market price is conservatively about $1.25 Mcf in the ground. That will, you just multiple $1.25 times those numbers, it comes out to a range of between $5.25 to $21 a share increase in EOG’s NEV.

God bless you.

Okay, David.

We’ve all been waiting for you guys to have a good break through the I think this is great. Thanks.

Thank you, we feel the same.

Up next is Jeff Mobley with Raymond James.

Good morning, Jeff.

Good morning. Two quick questions. First off on your deeper test in Trinidad, could you provide a little more color as to your view on the prospect now? More specifically, has the ownership changed or what working interest do you plan to hold once you spud the well? I guess from a fourth quarter spud –

The spud is actually more likely to be towards the end of the first quarter of ’05. I think it is a very complex well, 22,000 feet or so. It’s a large structure, several thousand acres in size. In terms of the reserves on it, we are not putting out any numbers other than what you’ve already seen, something like a half Tcf to 1.5, but obviously there’s some great upside on that.

Our working interest, we do have a hedge agreement with a major company to help us in drilling this well, and we are actually not going to have – we are going to be fully carried in the drilling of that well, and our working interest after that is going to be in excess of 50 percent.

Okay, great. Just a bigger picture question, obviously your balance sheet is getting to a pretty low lever basis. You know, almost to the point where it is half what some of the large cap companies are being measured at. What are your plans with your excess cash? Obviously you need capital to ramp up drilling in Barnett, same with other plays. I’m just curious, you’ve got this strong cash flow, what do you plan to do going forward?

Jeff, interestingly enough, if you just take round numbers for what the incremental capex would be next year for the Barnett development and just in simple terms, if we say we drill 100 wells next year, you are really only talking about $130m to $140m for that, so as we see it right now, there will be a slight bump in the capital requirements for the Barnett, but it is not an extraordinarily high bump, so it is still going to put us in pretty strong shape.

I would say if these hydrocarbon prices stay where they are, there is a fair chance we would be looking at possibly by the end of the year getting back into the share buyback strategy, because our debt to cap, as Ed mentioned, if these hydrocarbon prices stay where they are, could be around 26 percent by year end. We don’t have any tremendous intention to drive our debt to cap down to 15 percent or something like that, so we realize it is quite low.

Great. Nice job on the quarter. Thanks.

Thanks, Jeff.

(Operator instructions) From Hibernia South Coast, David Heikkinen.

Good morning. I just wanted to get a little additional details on the Web Ranch well. Still in the 100 to 200 Bcf size, 200 feet of land section. What would that be on a per well basis, or is it too early to call that mark?

Dave, it’s really too early to call that, we’re still testing on that well, but on a going in kind of number we were thinking 2 Bcf to 3 Bcf well gross.

David, just to give you a little more color on the Web Ranch well, we drilled the well and encountered basically all the pay we expected to get, which was great. We then encountered some mechanical difficulties in terms of a shale sloughing up the hole, so what we ended up doing on this first well is we had a very compromised completion. We met the drill pipe and the hole, so we are getting I would say reasonable gas rates right now, but it looks like to me what we are going to have to do is drill a second well here and get regular open hole [inaudible] instead of case hole open hole [inaudible] and do a completion that is more efficient.

But I would say my sense at this point is that Web Ranch is likely to work. The Mernia area is one I am not quite succinct with you now, we commenced the north end and the south end we’re still testing, but it looks like what we’ve encountered is even on the south end is we’re kind of on the borderline of something that would have enough pay to be commercial or not, so we just have to see how the testing goes on it. But clearly that one looks the least interesting of the three.

As I mentioned, what is interesting to me is if you look over our big target success history over time, well over 50 percent of the items we’ve touted as big target plays have worked. I mean, ones that are working now that we’re in the development mode in, the Horizontal Devonian in Midland, the Utah [Mesaburg] play, the horizontal Cleveland play in the mid-continent area. So again, the kind of big target plays that we usually focus on are ones where we wouldn’t count them unless we really thought we had a fair chance of making them work. That’s why when I mentioned that we’ve got another five of these that we’ll be testing over the next year, I’d say based on our track record it could well be that over half of those will work.

I guess on the Barnett Shale with 13 wells in your data set, when do you feel more comfortable going to the higher end of the reserve potential? Kind of think 40 to 80 percent of the acreage could be developed, kind of back of the envelope. What thresholds to you get to to have greater confidence on the high end of that reserve potential?

David, I would say right now I am very confident that at least somewhere in the mid-range that is likely to happen. Probably by year end we are going to be able to talk about whether we’re talking about 2 plus Tcf or not.

And still I would assume you have land men working trying to acquire additional acreage. Any other counties that you are branching out into other than Johnson County in your acreage, or what are your targets there?

All of our wells so far, these 13 wells that we are citing are all in Johnson County, and our best assessment now is that county and perhaps a couple of adjoining counties are ones that look quite good to us. That’s kind of what we’re talking about.

Okay, so mainly to the south and west of Fort Worth looks like you have some potential?

More to the south than even the west.

Okay, thanks a lot Mark.

Up next is Irene Haas with Sanders, Morris, Harris.

Hi Mark, congratulations.

Irene.

I have a question for you. You said you have a contract and the infrastructure situation will be better in the south of Fort Worth area, that the gas is dry. Can you give me a number on the X amount for X number of years? That’s the first question.

The second one is, what does the seismic do for you? Does it help you kind of avoid areas with water? If yes, how many of your 175,000 acres, how much is covered by seismic.

Let me address the seismic question first. The 3D seismic is relatively new to the Barnett Shale play, and the 4 plus Tcf originally discovered by Mitchell Energy to the north of Fort Worth, to my knowledge there wasn’t any 3D seismic on there and they still found 4 Tcf.

What we found though is the 3D seismic is an excellent differentiator, at least in the southern area, and it is exactly what you say. You can see very clearly on the seismic sink holes or caverns, and then you can locate your wells in a more efficient mechanism there to drill them. I’m not going to give you any secrets as to how you locate them, because we’ve probably got a little bit of edge on the industry there.

In terms of how much of our 175,000 we have under 3D right now, it’s in the range of about 50,000 acres and we are currently permitting additional 3Ds as we go forward.

Just to scale out, we mentioned the well cost is about $1.3m. That’s the cost to complete and tie in a well. If you allocate an acreage and a 3D seismic cost to it, that comes out to be about $100,000 more a well. So if you are really doing the economics on this, what you need to do is take those net reserves we quoted and use $1.4m as including the land, seismic and well cost.

And the amount, X Mcf for X years?

Let me just be vague on that, because we are in the middle of a lot of pipeline negotiations still and there is a lot of competition there, and we would probably be giving away something I don’t want to give away right now, Irene.

Thank you.

I will say as we make these luncheon presentations around the country, including the one starting today in Houston, we do have a volume chart in there to give you some indication of what we think we will be doing by year end out of the Barnett and I just quote you some numbers on that, and right now our volumes are not all that big, but we expect we’ll be in the range of $30 to $40m a day on a NRI basis, net revenue basis, as an exit range at year end. That’s essentially just the one rig just slowly creeping up as we get into the second half of the year.

And these charts that are being used at these luncheon presentations will be available on our web site within the next several hours.

Thank you.

And we’ll hear now from Ellen Himmens; Bear Stearns.

Thank you, just a couple follow-up questions. Mark, what is your anticipated decline curve on your most recent Barnett Shale wells?

From what we’ve seen on these wells, Ellen, the first year or so is a fairly hard decline. In other words, the well will initially come in at about 4m a day or so, and then it will begin to level out. But once you get past the first year they are relatively low declines, so to the degree that we get to blending this stuff into our North America gas mix, what it will do is over time actually lower the decline rate of our total North America gas production.

The other thing it will do is if you just do the math, again with this $1.4m of total well costs there, depending what you get for reserve range, but if you get 2.5 Bcf reserve range, you are talking about a 44 cent DDA. If you get about 1.2 net – these are net Bcf here – reserve range, you are talking about an 88 cent DDA rate. So no matter which of those you use, you are looking at something that is likely to suppress our go-forward North America natural gas DDA rate.

But would you say it’s like a first year’s decline would be on the order of 20 to 25 percent, or something greater than that?

It would probably be in the range of 30 to 35 percent, Ellen. Then they kind of flatten out in the range of 10 percent or so after that.

Just one other question on the balance sheet, in the deferred tax account is there any kind of step up of assets required? Anything going on there? For tax balance on the balance sheet it is quite a bit higher than what your expense is for the quarter.

Let’s check on that and we’ll go to the next question.

Thanks very much. Nice quarter.

Okay, Ellen.

Next is Frank Bracken with Jeffries and Company.

All of my questions have been answered, thank you.

And with Energy Equity, David Snow.

I wondered if you could give us another snapshot on the macro view?

Yes, David, our snapshot on the macro view, on the gas side it really hasn’t changed much in the last six months. We still project that domestic gas production is going to fall in the range of 2 to 3 percent this year. If you just look at some of the majors that just reported in the last week or two in terms of what their unit gas has fallen, we are continuing to see a trend where the majors are experiencing very, very sharp domestic natural gas production decline and the independents are trying to hold it up a little bit, but the overall decline is let’s say inevitable this year, 2 to 3 percent even with this very very high rate count that we have.

In Canada we’ve become slightly more sanguine in the last six months on the ability to hold production flat this year, so our projection right now is the U.S. is down 2 percent to 3 percent and Canada relatively flat. When you put in the incremental LNG cargos that will be coming in, and also two-tenths of a Bcf per day higher average exports into Mexico this year over last year, it comes out that we are about 1.4 Bcf a day less supply in North America this year than last year. The bottom line is we are going to have to make due with about 1.4 Bcf a day less supply, which I think will hold the market pretty tight.

I will say the gas market, the things I find interesting are that a year ago if you would have asked the average economist if you are going to have $5.50 gas prices for 24 months, and you are going to have north of $30 oil for 24 months, what do you think that would do to the economic recovery? The answer would be gee whiz, that would wreck the economic recovery in the U.S.

I think what I am seeing is that the economy is recovering well and is able to tolerate these very high gas prices and crude prices.

I wondered if you could also tell me, do you see any Barnett Shale potential going to the southeast of Fort Worth?

No, I really don’t – Let me ask Loren Leiker, our VP on exploration to answer that.

We think pretty much going south is the best you can do. If you go southeast you get into the big over thrust where there really is no Barnett equivalent. And going back to Ellen Himmens question on deferred taxes, it’s a good question. Actually it does pretty much balance out within just a few million dollars. You do have, on your long-term side, you do have about $110m increase, however that is offset in the current liability side by a decrease of $59m. There is also a $15m increase in the deferred income tax account on the current asset side. So if you get through netting all of those back it is roughly in the same range as the $32m reported for the quarter.

Further questions?

From Shawn Reynolds with Petrie Parkman.

Good morning. Just a little more color on some of the stratography, you talk about the [Mesaburg] program. Is there a target in the upper [Mesaburg], the lower [Mesaburg] the Blackhawk, could you give a little bit more specifics on where you are really drilling and where you are getting the reserve out of?

Shawn, we’re actually drilling several intervals of the [Mesaburg], mainly in the sort of middle, including intervals that we would call Thrash River and Blackhawk, but there are other intervals as well that we are testing in other parts of the basin.

Right, so that 1.5 Bcf per well is the whole [Mesaburg] package?

It is, and we are talking about maybe more in the upper and a little bit less in the lower.

Did you think there was upside to that reserve range?

I think the reserve range is pretty accurate. What’s happened there is looking at some of the stratography, the numbers that we quoted a year ago of 100 to 200 net Bcf there were based on pretty wide well spacing, in some cases 40 to 80 acres. What we’ve seen now is the stratography is so discontinuous there on a well communication is pretty limited, and we think ultimately we will be able to downspace this to 40’s and possibly even 20 acres, and so that’s why we’re really saying now we’ve captured somewhere in the range of 200 to 400 net Bcf reserves.

I might also add that the stratography is not continuous, it is also fair to say that the stratography is not the only controlling factor here, and you can’t just drill this thing as a blanket everywhere on everyone’s acreage. You really have to understand the geologic setting, the pressure setting to know where it is good and where it isn’t.

What kind of timeframe do you think you will be developing this?

Shawn, this is one that is not going to be developed that rapidly. You’ve got two issues here, one is it is on Native American land and there are only so many permits we can procure in a year. The second issue there is you’ve got some pipeline takeaway issues. I would say this is going to be a five or six year development program is what we’ve got identified.

So that’s why the Barnett Shale is such an interesting differentiator. If you find reserves in the Rockies you are often limited by how fast can you really get drilling permits to go, whereas the Barnett Shale we think since that is always on private line that we are going to be able to move a lot faster there.

That’s it, thanks.

(Operator instructions) Now from Johnson Rice, Ken Beer.

Hey guys, I know that most of the folks asked on the Barnett Shale, but I will just ask a quick question on the U.K. where you are at 40m a day by year end. You said you are going to spud the Viper in October as operator, and as we look out to ’05 and ’06, would we expect to pretty much have you only be an operator going forward, are you going to play that by ear? What kind of, again if you look out to ’05, ’06, is a scenario that would see an increase in activity going forward or do you pretty much like the fairly understated position that you find yourself in?

Ken, it is our view in all of those we’d like to always be an operator, but right now most of the deals we are getting are farm in deals from majors, so that’s going to limit our ability to take over operatorship in most cases.

What we are continuing to see is a pretty ripe environment for opportunities of the 100 to 300 gross Bcf target size in the southern basin of the U.K. North Sea, it’s just below those kind of targets and below the threshold that the majors want to commit capital to.

So I think we will have a pretty consistent program in ’05 and ’06, drilling somewhere between two to five wells per year, we would like to gear that program up some more, and in fact we’ve opened a small office outside of London which is our first actual local representation there.

I would say we are probably going to take a gradual approach. Obviously if an asset package came up in this area in the North Sea that we like, we’d probably attempt to purchase it, but if you really look at the total company strategy right now, it is not – there is not a yearning, need for us to make any kind of a big acquisition anywhere. We are fortunate enough that if you basically say where are the four areas that we operate – U.S., Canada, Trinidad and the U.K. – every single one of those areas are currently growth areas for us and so I would say even though we’ve got a pretty strong balance sheet, it will be out of the ordinary to expect to see us make a big acquisition.

What about just with Viper itself, was that a farm in? When I think of farm in I think you are farming in and you would be the operator. What’s the thought there?

In many cases the farm ins we’ve been doing in the southern gas basins is the majors, and they are holding operations. In the case of Viper, it is also from a major but it happens to be from a separate prospect, it could be a standalone, open water location and we would be operating that well.

All right, guys. Thank you so much.

Okay, Ken.

Now from Southwest Securities, John Gerter.

Hi Mark. On this Barnett, just math wise, you mentioned 500 to 2.5 Tcf net gas, 175,000 acres. The runaway would be 40 percent of that acreage drilled to high end, 80 percent, translates to about 175 acres a well. Based on the recoveries you mentioned even 1.25 Bcf to 3.125 Bcf a well – does all of that, bottom line, are you looking at this as a 175 acre per well development scheme?

The bottom line is no, John. Our bet is with these horizontal wells, spacing at about 100 acres. So frankly what we have quoted to you on the 2 Tcf assumes that only a portion of our acreage is really productive, and that’s why I really say 2 plus Tcf. It is conceivable that by the time year end rolls around, we might be talking another number.

You could essentially gross up that 175, back of the envelope, versus 100 so you could be well north of 2 Tcf on the high end side.

That’s true.

Now what about the spread here? You mentioned 1, 1.4 Bcf. Some of this math would suggest over 3 Bcf and you talked a little bit about recovery factors. What is the assumptions underpinning this? That’s a wide range, obviously, of recoveries, in terms of these wells. Is it stimulation related? Are you still going through the process of completion, evolving completion techniques? What is causing this spread in your mind between the potential outcomes?

What I will say is John, the gas play, 140 acres in Johnson County is about 150 Bcf. So you’ve got a lot of gas to work with. The 1.2 Bcf net is kind of the range that we had on some of our, I would say 3-6 wells out of this database. On some of the subsequent wells were up to the 2.5 Bcf net. The differentiation is the well completions, the methodology for well completions there.

What we’ve learned so far is that if you do a tweak in well completions you get a disproportionately high or low tweak in the reserves you are going to get on those wells. So these wells appear to be quite sensitive to the completion methodology, and frankly right now I am not sure – there may be some more upside on this completion methodology.

What kind of recoveries on the high end are you looking at? You mentioned maybe 5 to 15 percent gas in place recovery. On a high end, what are you looking at as far as a percentage?

Well the numbers that we gave would be somewhere in the range of 6 percent gas recovery per section, and our view on this is we’ve got a captured asset here that’s got [inaudible] in place, and through further optimization over time, we are going to get this gas recovery up higher than 6.5 percent per section.

Where do you think it goes, Mark? As you know, you’ve got a big resource base here so that --

Yes, what’s the bottom line. I would say a goal would be 10 percent of the gas in place. That’s a very pragmatic, achievable goal.

That’s helpful. Can you talk conceptually, and it is probably proprietary at this stage, about what you are doing in broad strokes on these completion techniques? Be more selective about isolating zones to stimulate, or do want to walk down that road right now?

The answer is no.

Let me shift gears real quickly and ask one other question on Canadian coal bed methane. Loren, if you would, just give us a sense on what the action plan is there, and what are you looking at all in with results and what have you at this stage?

John, we’re really involved in a couple of different plays there. The one we’ve talked most about is this Horseshoe Canyon coal in the [Twain] area where we found 111,000 net acres, and we will drill about 80 of those wells, possibly as many as 100 this year. We still don’t know what the range is going to be and reserve size per well, but we’re thinking somewhere between 0.3 and 0.5 Bcf per well.

On that basis, we think our reserves are somewhere in the 150 to 200 Bcf range net after royalty, but that is assuming that not all of our acreage actually works, around half.

Got you.

It’s just a conservative assumption at this point.

Thank you, guys.

Okay, John.

With JP Morgan, Shannon Gnome.

Thanks. Sorry to call in late here. Curious back on the Barnett, it’s kind of following on John’s question on the range recoveries here. How much production history do you have on some of the more recently completed wells that were completed with the new methods?

What I am getting at is, is there a risk here that the decline profile varies from your original expectations or what you’ve seen on some of the older wells. I mean, are you just going to be getting – is there any chance that you are getting more up front but the same ultimate recoveries in the end?

The bottom line is no, I’m not that concerned about that Shannon. We’ve done a lot of modeling of the Barnett Shale wells to the north of Fort Worth and for modeling on some of the horizontal wells there, and these well declines are pretty predictable and pretty easily modeled. We don’t know plus or minus 10 percent what the ultimate reserves are going to be, but we don’t think there is much chance that, for example, the two wells that we quoted there, the [Emins] and the River Hills, that those things are going to fall off and decline precipitously. That would be very, very anomalous relative to the multiplicity of wells that are already at this play.

Okay thanks. Helpful.

We will go now to Monroe Hum with [Simmeron].

Thanks, my question was answered in your response to John Gerter’s question, but great results.

Thanks, Monroe.

And finally we have a follow up from Frank Bracken with Jeffries and Company.

Just a question pursuant to the slides that you are going to release, that 30m to 40m a day net exit rate, how many wells is that going to come from?

I am not sure we even know. I have to get back to you on that one, Frank, on well count. I haven’t really looked at it that way, but I would say a reasonable, stabilized per well rate, we are hoping for in the range of 1.5 to 2m a day. When I say stabilized, that’s say after three to six months of online.

Great, thanks very much.

There are no further questions. At this time I would like to turn the call back to Mr. Papa for any additional or closing remarks.

Let me just make a couple closing remarks here. Although we didn’t address it much on the Q&A, I’d like to say our normal singles and doubles activities across the company are going very, very well. To that, we’ve now added what I think is a very substantial resource play in the heart of North America that is going to improve frankly our reinvestment rates of return and it could be an extremely substantial play, but I don’t want anyone to look at it like it is going to replace, for example, problems we might be having in other areas, because we are not having problems in any other areas. So this play should be additive, we still intend to keep a very low debt rate as we go forward, and we are all watching our unit cost, there’s a 12 cent reduction in unit cost guidance in our 8K so all in all we are very, very comfortable with where we are and extremely excited. Thank you.

That does conclude today’s teleconference. We do thank you for your participation and ask that you enjoy the rest of your day. You may disconnect your lines.