EOG Resources Inc (EOG) 2003 Q4 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources' Fourth Quarter and Full Year 2003 Earnings Conference Call. This call is being recorded.

At this time, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead.

Good morning, and thanks for joining us on the EOG call.

We hope everyone has seen the press release announcing fourth quarter and full-year 2003 earnings, cash flow, and reserve results.

This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings, and we incorporate those by reference for this call.

The SEC permits producers to disclose only proof reserves in their securities filings. Some of the reserve estimates in this conference call and webcast may include other categories of reserves. We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of the Investor Relations page of our website.

With me this morning are Ed Segner, President and Chief of Staff; Loren Leiker, EVP of Exploration and Development; Gary Thomas, EVP of Operations; Bill Albrecht, our Vice President of Acquisitions and Engineering; and Marie Baldwin, our Vice President, Investor Relations.

Two thousand three was a record year for EOG in terms of operating earnings and cash flow. It was also a pivotal year for us from an operations viewpoint.

In North America, we had great results from our singles and doubles drilling program and made significant progress regarding our bigger target programs.

Outside North America, we articulated a longer-term production growth plan in Trinidad and had success in a new international area, the North Sea.

As outlined in our press release, during the fourth quarter, EOG reported net income available to common of $71.8m, or 61 cents per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net income, EOG's fourth quarter adjusted net income available to common was $86.1m, or 73 cents per share, as compared to $39m, or 33 cents per share a year ago.

The reconciliation of GAAP to non-GAAP adjusted net income available to common is found in our earnings press release, which is posted on our website.

For the full year, EOG reported net income available to common of $419.1m, or $3.60 per share. Results include the impact of mark to market of outstanding futures transactions. One could adjust full-year results to reflect actual cash paid out and to eliminate the mark-to-market loss on outstanding transactions and other items.

EOG's full-year adjusted net income available to common was $433.1m, or 3.72 per share, as compared to $92.6m, or 79 cents per share a year ago on a similarly adjusted basis.

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, EOG's DCF available to common for the fourth quarter was $321.3m, or 2.74 per share, versus $255.6m, or $2.19 per share a year ago.

For the full year of 2003, discretionary cash flow available to common was $1.264.7m, or $10.85 per share, versus $777.8m, or $6.63 per share in 2002.

The reconciliation of non-GAAP discretionary cash flow available to common to net operating cash flows is found in our earnings press release.

Now, let me turn to an operations discussion.

Our fourth quarter North American volumes were exactly at the midpoint of our previous 8-K guidance, although the mix was slightly different since we extracted more NGLs from our domestic gas because of tighter pipeline quality specs.

For the full year, we grew total company production 3 percent. We expect our total company production growth to accelerate to 6.5 percent this year, followed by 10 percent and 7 percent in 2005 and 2006.

During 2003, we replaced 249 percent of our production at an all-in $1.28 per Mcf finding cost. Our North American numbers were 259-percent reserve replacement at $1.36 per Mcf finding cost, well below our targeted one dollar to a dollar -- excuse me, $1.50 to $1.60.

We replaced 189 percent of production outside North America at 63 cents per Mcfe from our Trinidad and U.K. activities. It's important to note that these numbers include the effect of a 101 Bcfe downward Trinidad revision caused by a production-sharing contract adjustment related to higher wellhead prices. Our overall finding costs would have been $1.17 per Mcfe, excluding this PSE revision. I'll also note that these finding costs include capitalized interest, gathering, transportation, and processing capex.

Across the board, both our drilling and acquisition finding costs look solid. As always, DeGolyer and MacNaughton has prepared independent estimates of over 70 percent of our reserves, and for the 16th consecutive year has reported no material difference between D&M and EOG. Given some recent industry announcements, it should be comforting to know that we have a 16-year-track record with one of the most respected outside reserve engineering firms.

I'll now walk through some of our operating highlights.

In South Texas, we're achieving positive results from all three of our main geologic plays -- the Roleta, Frio, and Wilcox.

In the Roleta, we recently completed the [Marshall State][ph] No. 1 well for seven million cubic feet a day rate, and we have a considerable inventory of 2004 drilling locations.

In the Frio, we recently completed the [Valley][ph] No. 1 well for 15 million cubic feet a day and 1,200 barrels of common feet per day. And we're currently completing the [Valley][ph] No. 2 well and expect similar rates. We have 100-percent working interest in these wells until payout and then 72-percent working interest after payout with significant offset drilling potential.

In the Wilcox, we reported last quarter about our 25-million-a-day [Henley][ph] No. 1 well. We're currently drilling the [Henley][ph] No. 2 well, and we expect this will also be a 20-plus-million-a-day cubic-feet-per-day producer with several offsets yet to drill. We have 50-percent working interest in these wells.

In the Mid-Continent, we've got a two-prong drilling focus working, which is a higher activity level than in past years. We're currently running five rigs in our standard [Hugetts][ph] and [Deep Play][ph] at depths of 3,000 to 7,000 feet, and we're seeing good results. We plan to run six rigs in the horizontal Cleveland program, where we continue to achieve 1.3 Bcf per well for a $1m well cost.

In West Texas, we're now in our third year of our horizontal Devonian program, which continues to generate excellent results. We recently completed the [Purdow][ph] 101 No. 1 for 3.7m cubic feet a day and 800 barrels of oil a day. We have a 92-percent working interest in this well and enough identified horizontal Devonian locations for a full-year, full-rig drilling program.

In the Barnett Shale, we've begun drilling horizontal wells, and although it's early times, we are cautiously optimistic with results so far. We've got a 100,000-acre position, and to date, we've done a good job reducing our completed well costs, and our early-time production results indicate we're in the range of 1.0 to 1.5 Bcf per well, which generates very attractive economics.

We're still iterating regarding the optimum completion technique, and we plan to ramp up from the current one drilling rig to two drilling rigs in April, and in mid-year, we'll make a decision regarding how to proceed with this program. I'll also note that our year-end 2003 reserves we just reported contain essentially no reserves booked to the Barnett.

In the Rockies, we've got three interesting plays working. In Eastern Montana, we're continuing to get good horizontal oil wells from the [Bokenfieldstone][ph]. We have two rigs running in this play, and a typical well is the [Candy 1-5H][ph], which is producing 350 barrels of oil per day.

In Utah, our [Mesa Verde][ph] gas development program continues to generate good results, and we expect to drill 80 wells this year and operate about a four-rig program year-round.

Also, our Rocky Mountain big target program is underway, and we are currently drilling two [Myrna][ph] wells and one [Jonah 2][ph] well and should have results next quarter. These are our attempts to replicate the [Pinedale Anacon][ph] results.

In Canada, we're busy digesting the acquisition of the [Marathon][ph] properties we made last year and another smaller acquisition. We're gearing up to drill a total of 1,300 shallow wells in Southern Alberta this year, 100 of which will be targeting coal-bed methane.

Our shallow gas-drilling program should increase by about 20 percent, as compared to last year. We're very pleased with the acquisition we made last year and currently see greater development potential than our going-in estimate.

In Trinidad, we've made good progress in setting up 2004 through 2008 production growth. We've recently signed a methanol plant contract to supply 125m cubic feet-a-day gross to a new plant currently being constructed with a mid-2005 scheduled start-up. This is a 15-year contract. We will deliver 95m cubic feet-a-day gross, or 67m cubic feet-a-day net, during the first four years and approximately 125m cubic feet-a-day gross, or 87m cubic feet-a-day net, in 2008 for the remaining 11 years. The gas price will be linked to Caribbean methanol prices, and at current methanol prices would provide a $1.70 wellhead price. The plant will be supplied from a liquid-rich [Osprey][ph] field with initial net condensate production expected to be 1,000 barrels a day in 2005, increasing to about 1,300 barrels a day in 2008.

Additionally, we recently signed a [heads][ph] of agreement for a 30m cubic feet-a-day gross L&G contract for partial supply to [Atlantic L&G Train 4][ph], which starts up in mid-2006. In this case, the Trinidad wellhead price will be a function of the Henry Hubb price. We expect to finalize this L&G contract in the second half of the year. EOG will not provide any equity to either the methanol or L&G plants.

These two contracts set us up for 2005 through 2008 growth, but the driver of this year's growth will be our net 47m cubic feet-a-day supply contract for the Nitro2000 ammonia plant, which is currently under construction and expected to start up mid-year. The wellhead price here is indexed to Caribbean ammonia prices. At current levels, this would translate to a $1.85 wellhead price.

On the Trinidad drilling front, our first exploration well on the Lower Reverse "L" Block was unsuccessful, and the dry hole cost is included in our fourth quarter numbers. We plan to drill development wells on our SECC Block for the next six months and then will resume our exploration program about mid-year.

Switching to our U.K. North Sea activities, we expect to commence first production from our two discoveries by October and should have a year-end exit rate of approximately 40m cubic feet-a-day net. We expect to continue to drill more North Sea [farm-ins][ph] during 2004 since our game plan here is working.

I'll now turn it over to Ed Segner to review capex and capital structure.

Thank you, Mark.

In terms of capital expenditures, our total exploration development capital expenditures during 2003 were $1.322b, so 1,322, including 405m of acquisitions.

Of the drilling program expenditures, approximately 29 percent were exploration spending and 71 percent development.

Total discretionary cash flow available to common for the year was $1.3b. For the fourth quarter, total exploration development capital expenditures were 681m, including 384m of acquisitions, [indiscernible] primarily the [Husky][ph] acquisition.

Capitalized interest for the quarter was 2.2m, and 8.5m for the full year.

As to capital structure, at December 31, 2003, total debt outstanding was approximately 1,109m, or 1.1b, and a debt-to-total cap ratio was 33.3 percent, down from 40.6 percent at year-end 2002.

During 2003, we executed our drilling program and made the largest acquisition ever in EOG's history, primarily funded with cash generated from operations.

The effective tax rate for the quarter was 23.6 percent, primarily influenced by the November 2003 reduction of the income tax rate in Canada and partially offset by the phasing-out of the Canadian resource allowance. The deferred tax ratio for the fourth quarter was 81.8 percent. For the full year 2003, the effective tax rate was 33.1 percent.

For 2003, the return on equity was 23.3 percent, and the return on capital employed was 15.3 percent, consistent with our historical averages. A schedule with the calculation of these metrics has been posted to our website.

For the fourth quarter, the "other income" line item includes a foreign currency gain of 9.3m. And as you probably noted, we did increase the dividend on our common stock by 20 percent, taking the indicated annual rate from 20 cents to 24 cents. This is the fourth increase in the last five years.

Guidance for the detailed modeling of 2004 was provided yesterday in a Form 8-K filing, and we plan to file full financials and footnotes for 2003 in late February.

Now, I'll turn it back to Mark to talk about the macro.

Thanks, Ed.

Our thoughts on the North American gas supply picture haven't changed since the last quarter's. Recent fourth quarter public company North American production volumes have continued to trend to declining production even with higher drilling reutilization.

For 2004, we expect both U.S. and Canadian production to decline 2 to 3 percent below '03, and total 2004 North American supply, including L&G, will be 1.5 Bcfs-a-day lower than 2003.

Although everyone is currently focused on winter weekly withdrawals, I think the summer refill rate will be more telling. I expect refills will be at a much lower rate than last summer because of increased electricity demand, which is well correlated with GDP growth.

EOG's [collar and swamp][ph] positions were outlined in previous 8-K filings. For January and February, actual prices were essentially within the collars, so we're effectively about 30-percent hedged or collared for the full year. We have no positions in place after October of this year.

Regarding oil, we're about 16-percent hedged January through August at a $29.14 average price and unhedged after August.

In summary, we expect to ramp up our volumes each quarter throughout the year and generate both 6.5-percent total company and North American gas production growth, followed by 10 percent and 7 percent total company growth in 2005 and 2006.

Unlike the industry as a whole, EOG possesses a prolific North American prospect-generating franchise. Consequently, we're long on good North American investment opportunities, and our reasonable 2003 finding costs show we were able to intelligently spend $1.3b last year. This year, we expect to spend around 1.1b, excluding acquisitions, and we again expect to spend it wisely. We plan to achieve this production growth without stressing our already strong balance sheet, and with today's dividend increase, we've raised the dividend for the last five years.

Thanks for listening in, and now we'll go to Q&A.

Thank you. [Caller instructions.]

We'll go first to Mark Meyer, Simmons & Company.

Good morning, Mark.

A question on reserve balance. What was the year-end [PUD][ph] proportion? Do you have that?

Yeah, let me ask Bill Albrecht to field that one.

Exchange of our total reserve base, Mark, was 33 percent year-end '03.

And how did that look in Trinidad?

In Trinidad, if you just take international discretely, 68 percent of our international reserve base is in the [Fruton][ph]-developed category.

Question, Mark, on Canadian foreign exchange and plans for 2004. Any thoughts on whether you might try to be a little nimble here with continued weaker dollar and perhaps shifting some spending in North America around? Or are you pretty confident that you can absorb that fact and get under your target of F&D for the year without having to make those kinds of shifts?

Yeah, Mark, let me just add a comment on the [PUD][ph] situation in Trinidad. They're on reserves. Basically, what we've got is our [PUD]s[ph] in Trinidad are discoveries we've made that we have not yet developed, and those [PUDs][ph] will be converted to prove they're develop-producing over the next 12 months, and the reason is because we're going to use those reserves to feed the gas contracts for the methanol and L&G plants we issued. So --

Right.

-- in our mind, that's just an issue of really just spending the money now to develop those reserves that we've discovered and we already have a market for.

As to your question regarding the Canadian foreign exchange, is that going to shift our -- or potentially shift our allocation away from Canada toward elsewhere, yeah, we'll keep an eye on that, but right now, I would say that we're going to continue to execute our Canadian program without making a massive shift from one country to another in terms of where we're looking at the money.

Great. Thank you.

Okay.

We'll go now to [Jeff Mobley][ph], Raymond James and Associates.

Good morning. You know, at the current strip for 2004, you guys will generate substantial cash flow above and beyond the capex budget that you've set. In terms of priority, what would you do with that excess if it actually does come to fruition? Would you buy back stock, increase your drilling, or up your acquisitions, because, clearly, your balance sheet's extremely strong.

Yeah, if we have cash flow of over and above the 1.1b -- let me kind of give you thoughts on priorities.

Number one, the production growth that we've articulated for the next three years, 6.5 and 7, in that production-growth profile, we are not loading in any volumes for future acquisitions of any kind of substantive quality. In other words, the work that we did last year, in my opinion, set us up for the next three years of production growth just by executing our drilling program, so while we're always, you know, be alert to acquisitions, I have to say that any major acquisitions don't look likely for us in 2004. We may do some tactical ones, but it's not likely we're going to have a big year spending on acquisitions unless some big prize just drops in our lap. So that would leave simply debt pay-down, share repurchase, and at this juncture, I would say, you know, our track record is we've been pretty active on share repurchases over the last four or five years, and our debt is already at a level that's fairly low, so we're not a company that's looking to drive our debt down long term to, you know, 25-percent debt-to-capital or anything. We think we're at about the right level right now, so, you know, not going to commit to share buybacks or anything, but I would say that it's not a case where we're looking to, you know, pay down debt to extremely low levels if we have free cash flow.

Okay, great. Just a separate operational question. I know you're still in progress with your [Myrna][ph] play. Any results you can share with us from some of the other industry participants, vis-à-vis the ability to actually have a successful [frac][ph] on the rocks there to actually get commercial production? Anything you can share there?

Jeff, I'd say no, we really don't have any [frac][ph] results yet on our drilling. We have drilled two new wells on that [Myrna anticline][ph] on two separate bumps or culminations or anomalies in the top of overpressure, as we've defined with our 3-D processing. And what I can say is that the top of the over-pressure [cell][ph] has come up -- come in at an anomalously high position on both those wells, and we have been able to log, you know, nice gas shows and nice log pays, but as you know, the proof is in the [frac][ph], and we haven't gotten to that point yet.

Okay, great. And anyone else in industry had any luck yet?

Not on the [Myrna][ph] structure, specifically, no. Our two wells are the only wells drilling on that structure.

Great. Okay, thank you very much.

We'll go next to Van Levy with CIBC World Markets.

Good morning, folks. How are you?

Fine, Van.

Good. A question of the relationship between your capex, I guess, both in the U.S. and Canada, and the relationship between production growth. It looks like essentially what you spent in the U.S. last year, which was about 690m, is what's required to keep production relatively flat. Is there something unusual about the numbers this year, or would that be a correct assessment?

Oh, I think our assessment, you know -- I don't have them in front of me, but basically the 6.5 North American gas production growth this year is what we expect to see a smaller percent than that of production growth coming out of the U.S. and a higher percentage of that coming out of Canada. So, you know, I’m not sure you can say that that 650m, or whatever it is, is -- kind of, you know, gets us to ground zero in the U.S., but it's clear that our production growth will be skewed this year in North America, more heavily in Canada than in the U.S.

Mark, did you guys give a breakout of your capex by country for 2004?

No, we have not yet, and we really [inaudible] finalize our plan with our board of directors before we give that degree of specificity, Van.

Okay. And I’m looking at your --

I'll give you one directional comment on that. We're likely to spend a bit more -- well, we are going to spend more in Trinidad this year than we spent last year, primarily because we're going to be developing our [Paruda][ph] discovery in drilling some -- this was a discovery made a couple years ago -- and drilling some development wells there.

And then also in the second half of the year in Trinidad, we've got two sets of exploration drilling that we're going to do.

And let me just ask Loren Leiker to talk for just a minute on the exploration drilling in Trinidad we're likely to do in the second half of the year.

Yeah, Van, we are within about 2-3 weeks of getting the final processing on our [mega-3D][ph] survey that we shot in 2003 down there. We have preliminary processing on portions of it already. And we do have sort of two programs in mind. One would be the standard, say, 100 to 300 Bcf-type prospects that we normally expect to find, and then in SECC, Lower Reverse "L" in our other blocks there. But we also have a deep prospect, I believe at the Analysts' Conference, that we called B52, that internally is also called [IVISDEEP][ph], that we hope to get [indiscernible] in this year, not really so much contingent on this new 3D as just getting our drilling plan put together. It's deep --it's 20,000 feet -- and it's a very large closure. We think it has excellent up-side potential for the country and for us.

Okay. And so last year, Trinidad was about 44m, so it really wasn't that large. Are you expecting that to be 80 to 100 this year, or what's the rough range of that?

Yeah, that's the rough range, Van.

Okay. And I guess the last question, it's a little unusual, your [drilling][ph] and revision finding costs, the way I calculate them, in the U.S. are somewhere around a buck 58; in Canada, they're a buck 68. Generally, you see the reverse trend, Canada being cheaper than the U.S. You know, I think a buck 58 in this gas price environment's a great number, yet, I guess you're drilling in revision reserve replacement rates about 150 percent in the U.S. If you pushed on that, spent more money in the U.S., would you materially spike that number? Is that why maybe you're not pushing the U.S. a little harder?

In terms of the costs, I mean we come out -- I'm not sure I can replicate your costs exactly in there. Let me ask Bill Albrecht to just feed you what we think those same costs are.

Yeah, our total drilling, Van, in the U.S. before revisions is $1.52, and in Canada, it's $1.44.

Then if you take those numbers, you know, what we're finding is that in the U.S., the finding costs [count][ph] vary by area. For example, in our South Texas area, we're getting excellent rates of return at finding costs and total finding costs in the range of a buck 70, a buck 75. And the reason we get great returns is you get to production pretty rapidly, whereas, obviously in the Rockies, you know, the finding cost is lower up there.

So, you know, our mix is -- right now, I'd say that we'll spend a bit more proportionately in Canada just because we bought the properties last year that have very, very significant undeveloped potential on them, so we're going to be feeding and really capitalizing those properties.

The U.S. program will be approximately similar to what it was this year. The only thing that might change in the U.S. is the Barnett Shale in the second half of the year.

And as we've mentioned to you, we're going very conservatively on the Barnett Shale with, frankly, just one drilling rig right now. That's for two reasons. Number one, the area is pipeline infrastructure challenged, so it's not a case where you just get an immediate hook-up and start producing the well. And the second reason is is that every well we're drilling in the Barnett right now, we're trying something different than the previous well in terms of our completion technique, and until we really get to a point that we feel, you know, quite good about where exactly we're going, you know, we don't want to replicating it and running three or four drilling rigs and possibly making non-optimum completions. So it's possible that in the second half of the year in the Barnett, we're going to pick up, you know, activity, but that's [indiscernible] just the function of, you know, how things turn out there.

Okay, my last question -- and, by the way, the numbers I quoted include downward revisions -- it looks like in the U.S. you had a downward revision of 25 B's, in Canada, 19. What were these associated with, and what could we see in this sort of extension of this going into 2004 and '5?

You know, those downward revisions were just normal revisions not associated with anything significantly, and, you know, I think --

So no major property, just on the fringes?

Just bits and pieces here and there and --

I went out over four years; it looks like in the U.S. you've actually -- you've had positive revisions, and I guess Canada, you have net [negat][ph] up there.

Yeah, that's my comment to really look over the next -- last three or four or seven or eight years. You know, our net revisions have been very, very diminimus, either positive or negative, which I think speaks to, you know, our relative accuracy of our reserves.

That's right. No, I think you're right there. Great. Thanks. Good year, good quarter.

Thank you.

We'll next to [Irene Hoff] [ph] with [Sanders Morris Harris.] [ph]

Hello, everybody. I think most of my questions have been asked, but maybe just a little more color in the North Sea. I mean how do you guys feel about North Sea now versus say, you know, three or six months ago? And what do you think could unfold for ’04, ’05?

Yeah, we feel clearly better about it than we did three or six months ago. You know, we took the route of the North Sea of basically saying we think that there are a fair amount of 100 to 300 BCF prospects in their infrastructure that are frankly just too small for the majors to drill. And we continue to see a fair amount of those prospects that the majors are willing to farm-out. And our success rate so far has been frankly better than we expected on this exploration drilling.

In terms of this year we have the two discoveries that we expect to have online by October, and it is interesting to note that on the latter of those two discoveries, that’s where Exxon Mobile is the operator and our partner. They press released that well, I guess, three or four months ago, and it looks pretty likely that they’re going to recommend a second well on the structure. They believe that it’s a larger accumulation than initial estimates. And so it’s pretty certain that we’ll drill a second well in that structure and have both of those wells online by October. And the other one is by a different major, and that well is expected to be online also by October.

So our sense is that the initial going in plan we had is working, and we’re going to continue to spend, I’d say a moderate amount in the North Sea. We’re not looking at any massive changes, and at this juncture we’re not looking to make any producing properties acquisitions there. The ones that we have looked at just, you know, haven’t passed our screen. So it’s likely we’re going to continue our game plan on drilling to grow as opposed to buying.

Great, thanks a lot.

We’ll go next to [Sean Reynolds] [ph], [Petrie Parkman.] [ph]

Morning. Can I just pick-up on that, and can you give us an idea of how many new expiration prospects should drill in the U.K. North Sea and if you have any names or reserve estimates?

Sean, I think right now we have two that we’re pretty sure that we will be drilling this year. And I would expect by, you know, by the end of the first half we’d have another two, three lined up for the rest of the year. And so our estimate going in is three to five.

And is it fair to think of them all in that kind of 100 to 200 B type of range?

Yeah, I think 100 to 300 BCF is about the range that we’re seeing there. There are some that they’re slightly smaller than that, but if they’re very close to infrastructure they could still be quiet economic.

Right, and are you looking for, you know, roughly 30 to 40 percent working interest? Is that?

In some cases up to 50 percent, and we’d like to even get higher than that.

Right. Okay. And I’d – it looks like you’ve ramped up the activity in the Cleveland, and I think you mentioned kind of reserves you were getting on a per well basis. And I know at one point you were talking about trying to play that down a little bit because you’re still in acquiring acreage. Is that something that you think you’ve completed now, and you’re really going to ramp-up?

Yeah, that’s correct, Sean. We spent most of last year in a fairly stealthy mode relating to that area, acquiring acreage, and the bottom line is we’ve got enough acreage required to feed a six rig drilling program. And I’d say there, we’re definitely far enough down the road with production history to be darn sure that our average reserves are averaging about 1.3 BCF a well, and the completed well cost is about $1.0m. And when you just run that through an IRR you’re looking in the range of about 40 percent after-tax unlevered return on that.

So the important thing in Mid-continent is over the last four or five years what’s been driving our production there has been what we call this [cubits and deep] [ph] program, the 3,000, 7,000 foot wells. And we’re going to be running five or six rigs in that all year. But what we’re doing is we’re basically going to be doubling the impact of production growth by layering on top of that this year a five or six rig program in the horizontal Cleveland. So you’re going to see that ramping up considerably.

I’ll just give you a tone on another play, another one of the big target plays that we talked about a year ago was the Mesa Verde play in Utah. And we told you that we felt we had captured there in the range of 200 to 300 net BCF in that play, and during most of 2003 we tested the limits of that play just geographically and geologically, and we were also a bit challenged by pipeline for structure there, but that's all behind us now. And we’ve now got enough drilling permits to gear-up, and we’re probably looking at about a four rig, full year program in that play.

And I’d say there we feel very comfortable that for about $1m well cost we’re achieving about 1.3 BCF per well. And while some of the wells last year were on the fringes and, you know, didn’t turn out as well because we’re testing the fringes, this year we’re going to be basically going through the heart of it.

And so both of those programs are ones that I don’t know, you might say there’s an analogy possibly to the Barnett Shale in that this year in the Barnett Shale we’re going to be in the kind of probing and testing, and optimizing mode. And, you know, hopefully if the Barnett works out like we would hope it will then some time late in the year we’ll shift gears and go into a more significant mode there.

But I will stress that the Barnett Shale results we have, you know, at this point our I’d say ‘preliminary’ in that we only have a few months production history from these horizontal wells. And while we’re encouraged that’s just not enough time to watch them, for us to feel, you know, like we can declare victory.

Right. But I’ve noticed you have added some acreage over there so you must be on the margins pretty positive to continue to add acreage, right?

Yeah, I think you can take as a sign that the fact that we’ve accreted further acreage, and we’re talking about going from one to two rigs as a sign that obviously what we, we like what we’re seeing so far.

Great. Thanks a lot.

Yeah.

We’ll go next to Ellen Hannan with Bear Stearns.

Thank you. Mark, do you have any update on your coal bed methane activities in Canada?

Yeah, let me ask Loren Leiker to give you some color on that.

Yeah, we have to date drilled or re-completed about 10 wells. And I’d say so far what we’re seeing is that the flow rates that we’re seeing are quite commensurate with what our competitors are seeing across our leased line to the south, and are now seeing to the north, and west, as well.

And so we have about 110,000 net acres in this [twining] [ph] property, and we anticipate drilling about 100 of those coal bed methane wells this year. And at a normal spacing that may be about one-third of the potential on that block assuming that only 50 percent of our acreage is good. And so we see good potential there for, you know, 100, 200 maybe more BCF on that particular play. And we’ve also been accreting acreage on a couple of other coal bed methane plays in Canada.

Can you shed any light on where those are, or?

I’d prefer not to at this point. They are in, not in the Horseshoe Canyon coals that the twining is involved with. We do have exploration wells that we have drilled in 2003, and we are analyzing those now.

And can you outline how much, what your Canadian spend will be in ’04? Capital spending?

Again, Ellen, I’d probably say we probably don’t want to do anything yet until we get Board approval of our full year plan.

Okay.

In terms of breaking it out. But it will be higher than last, well, it will be higher than our last year Canadian expenditures excluding the acquisitions.

Okay, and one last small question. Cap loads interest in the fourth quarter?

It’s 2.2, I believe.

And that’s a good run rate going forward?

I feel comfortable, in that general range.

Good. Thanks very much.

We’ll go next to [David Connie] [ph], Friedman Billings Ramsey.

Yeah, hi, guys. On your ’03 capex how much capital did you use towards [puds] [ph]?

Oh, I don’t have that broken out, David. We’ll have to come back and get you that number.

Okay, and then directionally I know you don’t want to really commit too much to the ’04, but would you see directionally would the pud number, do you think, possibly go down or up on the capex?

Probably be about, the first guess would be flat or perhaps slightly up because in Canada we’re going to be converting a lot of those puds from the acquisition that we bought.

Okay, and I guess also, Mark, if you’d give us a sense of what you’re seeing out on the acquisition front for properties. I know you don’t look at companies.

Yeah, we’re still seeing a fairly expensive acquisition market that I’d say is very, very competitive. They’re, the majors, you know, I believe that it’s possible that Chevron Texaco may be divesting some properties, but we don’t really see the Exxon Mobiles, the BPs, the Shells likely to divest a lot of their properties over the next year. So at this juncture, you know, I’d say it’ll be a market where any acquisitions that are made are probably going to be pretty, pretty pricey.

All right. And then if you had an opportunity to get into another area in the international arena where would that be? If you had your good opportunity?

We are looking at several other opportunities internationally. We are focusing a little bit, at least, on North Africa and extensions of what we’re already doing in the U.K., North Sea. There are other sub-basins within that area that we would like to get to.

Great, thank you.

We’ll go next to [Mary Saffrie] [ph] with [Carl Forzeimer and Company.] [ph]

Oh, good morning. I’m wondering how you’re looking at your service costs, particularly in North America. In the past you’ve mentioned that you’ve locked in contracts, or what do you expect, and how much have you locked in?

Yes, as you probably know, in the past we’ve locked in most all of our services with the exception of our drilling rigs. And we have oh, vendors locked in with agreements through ’04 and as far out as ’07. And on the rig side we’d expect rig rates probably to go up anywhere from five, maybe as much as 10 percent.

And the contracts that you’ve locked in, have they escalated or have they stayed fairly flat with ’03 or what?

They stay flat with ’03. We’ve had some that have gone up slightly, and some that have gone down. So pretty well flat.

Okay, your expectation for the drilling rig from, so it’s five to 10 percent, that’s for this year, or are you researching that?

Above 2003.

Okay, great. Thank you.

Just to scale it out there, the drilling rig itself usually runs about 15 percent of our total well cost. So, you know.

It’s not huge.

And as Mark had mentioned, you know, several cases, you know, our well costs might have been 1.2m last year, this year 1m. When we get into these continuous programs we’re able to continue to optimize and further reduce costs over and above what service cost increases are.

Okay, great. Thank you very much.

And we’ll go next to David Heikkinen with Hibernia.

Hello. Just one quick question on your Barnett Shale and then coal bed methane plays. As you’ve ramped up activity in coal bed methane and Barnett Shale mid-year do you think you’ll have a feel in both of those areas for the scalability? And we’ll talk more about it at the analysts meeting as far as what your intentions could be? Is that a fair representation of timing? I mean I know you mentioned it for Barnett.

Yeah, David. I would say, you know, mid-year and certainly by our September analysts meeting we’ll be able to, you know, give a pretty clear, definitive picture of what’s going to happen with the Barnett Shale. And, again, I think that, you know, if we, if it works, you know, where we’re going to see the production growth numbers are really going to be in ’05 and ’06, not so much in ’04.

And would you actually, you mentioned that it’s pipeline constrained, is that an area that you would commit capital and actually expand pipeline capacity? Is that something that you’re working on, or?

Yeah, we’re actively working on it, and our expectation is is that probably no later than October, maybe a bit earlier than that that the problem will be pretty well [released] [ph]..

You’ll have some capacity?

Though, you know, it’s not going to be one that’s going to be lingering for years and years.

Okay.

But today, as of today, it is an issue.

And just on the Canadian coal bed methane side you had last talked about 10 pilots going, were all of those in the main Horseshoe Canyon or is that including some of the other coals, as well. Do you have a breakdown of how many were in the main area and how many were in others?

All of those we mentioned, David, are in the main area.

Okay.

That we call ‘twining.’ We do have other pilots going outside of that area that we prefer not to comment on yet.

Okay, fair enough. That’s all I needed, thanks.

Yeah, David, you’ll recall that when we made that acquisition last year in Canada we said as one of the possible up sides that we had booked no reserves to, was that we would be approximately doubling our interest or our acreage in that twining area, coal bed methane. And then the bottom line is subsequent to the acquisition we’ve drilled some pilot wells and are sufficiently encouraged, and so one [lang app] [ph] we got from that acquisition is basically we’ve got about twice as many acres in this area as we had a year ago.

Oh, just one quick thing. You mentioned on the Trinidad LNG, I just wanted to check the number. Was it 30m a day?

Yes. 30m a day, nets. And what we’ve done is we’ve signed a hedged agreement on that, and which basically we got all the commercial terms agreed to, and all we have to do now is really hammer out a contract, and we expect to have that done the second half of the year.

And in that instance the price will be directly a function of Henry Hub, and that’ll be a 20-year contract. And I don’t want to go into exactly what the function is as a percentage of Henry Hub but it’s going to be a very attractive deal. And our job will be just to supply gas to the inlet of that plant. We’ll have no interest in either the plant, or the shipping, or the re-gas of it.

The timing of when that plant comes online?

That is expected to be mid ’06.

Okay, that’s all I needed. Thanks a lot, Mark.

Okay, David.

We’ll go next to Andrew Lees, RBC.

Hey, guys. Could you just quickly go over your costs on your Barnett Shale wells to date, to refresh our memories?

Yeah, Andrew, I’m going to give you kind of a circuitous answer on that. What we have in the Barnett Shale extension area is I’d say an extremely competitive situation. The area has heated up considerably in the last six months, and as we mentioned, we bought most of our 100,000 acres at very reasonable acreage costs. And right now, acreage costs have tripled, sometimes quadrupled what we’re in there for. And we’re still looking at doing some other things in accreting acreage there, and bottom line is we’re really don’t want to disclose too much on what our per well costs are at this point because we think that would put us at a competitive disadvantage relative to some others there.

Okay. Now, of your controllable costs overall company you guys have done a really good job with SG&A but your LOE and your G&A are both being guided up again for ’04, and they rose again in ’03. Do you guys have a plan in place to help squeeze down that component of your controllable costs?

Well, I would say on the DD&A side, and I think I can quote these numbers, but we had about $1.08 total company DD&A this year, and I think, you know, we’re expecting perhaps a two or three cent up in that which is a pretty small percentage really.

Right, but that’s not in cash, how about the cash costs?

Yeah, the cash costs, yeah, we’re guiding them up a little bit. I’m, you know, I’m not sure whether, you know, we’re erring on the side of costs, you know, in what we’re guiding you on that, I’d say at this point.

Thanks.

We’ll go next to [Mark Freesen] [ph] with First Energy Capital.

Hi, good morning. I just have a couple of quick questions. First of all, in Trinidad, if you could comment on the exploration well that was unsuccessful there, perhaps, what happened and if that’s perhaps been an influence on the timing or maybe the strategy of the exploration wells to come there?

And also, Mark, you commented on sort of making a loose analogy between the Barnett and the Cleveland, could you comment on perhaps how full the pipeline is of that type of play that needs to develop which will subsequently provide the growth, you know, even beyond the time horizons that we’re talking about?

Yeah, regarding the Trinidad dry hole, that was in our lower [reverse L] [ph] block, a new block that we had just signed up a little over a year ago. And as a result of that contract we were obligated to drill a well fairly early on. In fact, we drilled that well prior to receiving our large [3D] [ph] survey, which as I mentioned earlier I think would be in in two or three weeks here.

Yes.

Having said that, we had older 3D surveys on that that we have reprocessed and felt quite comfortable it was a viable prospect, but it was a difficult prospect technically. And so in hindsight I’d say that it really does not impact significantly our program going forward. It’s a prospect that we tested unsuccessfully, obviously, but we have many other prospects to come, I believe, with the new 3D that will be better defined.

Okay.

And on your second question there, Mark, on kind of the inventory of, you know, how many things that, kind of like the Cleveland or this Utah Mesa Verde play that we’ve got that are in our inventory, and you’re exactly right that some of the bigger target things we’re looking at are the Barnett and this [Merna] [ph] area. And in both those cases what we’re trying to do is just get a situation put in place where we can drill literally hundreds of wells in a manufacturing process on the play. It’s not like you drill one well, and yell ‘Eureka, you made a discovery.’

In the Barnett, just to give you a sense of quantity there, we have 100,000 acres and we think a conservative well spacing on horizontal wells would be one well every 100 acres, and so if you, you know, if you dreamed and you said ‘X percent of the 100,000 acres is actually productive,’ and just for argument let’s just say half of it, then you’re talking about potentially 500 horizontal wells there which will be clearly a multi-well program.

The Merna area where we’ve got three wells drilling, all of those are in basically different geographic areas. And if any one of those three wells works you probably have 100 to 300 wells that you’ll be drilling, keying off that one well. And so, again, it’s a manufacturing process. In that area you’ll be a little different, and you’re talking about 3, 3.5 BCF per well for about 2.5m completed well cost. And so it’s, you know, a slightly different program on reserves and costs.

The other area that we’re looking hard at is in Utah. We’ve had such good success in our program and our Mesa Verde program that we’re doing some drilling in exploration areas in Utah. And again, the target would be there, that we find something substantial and we have enough acreage to drill hundreds and hundreds of wells. And I would say, you know, so far that’s our game plan.

And, you know, the results so far are encouraging on at least some of those plays. And it’s just too soon to tell on all of them. And I will, again, say I don’t expect 100 percent of those plays to work. You know, we’d have to be extremely lucky for that to happen.

But you have a sense that there’s a pipeline of these types of plays to sort of become visible over the next few years?

Yeah, exactly. And another good example of this same kind of play is this horizontal Devonian play in West Texas. When we started out with that play we, you know, we thought we’d have maybe one year’s worth of drilling on that, and as we mentioned earlier, that we’ve got a four-rig program for this year. This is now the third year of this program, and what we’re finding is that what we’re learning applies to a lot of other reservoirs in West Texas and it’s enabled us to get some farm-ins from majors and to do some other things there, so it’s – once you get an idea like this in place and can get it to a manufacturing process we’ve found out we can expand it pretty readily.

Great, thanks very much.

Okay.

We’ll go back to Sean Reynolds, Petrie Parkman.

Yeah, Mark. I just want to follow-up on the M&A environment. And one of the things that you talked about in the analysts meeting was your ability to farm-in to some of these larger resource plays via the majors. Do you see any more of that evolving?

And then, also, taking the other end of the spectrum are you seeing more kind of I don’t want to call it ‘one-offs,’ but maybe, you know, package deals coming from the smaller, you know, private independents being thrown up that might be interesting?

Yeah, on your first question on the farm-in environment, I’ll say that, you know, at the analysts meeting I think we talked a little bit about the farm-in we had done with a major up in [Amoxi Arch] [ph] in Wyoming. And just kind of a report on that is it’s really too soon to tell. We’ve got about three or four wells drilled there, and we’re seeing drainage in some Sans and pretty much original pressure in other Sans. But, again, these areas, just getting the pipeline connects to it and we don’t have enough production history. But it looks, I’d say, you know, cautiously optimistic at this early date.

We’re seeing I’d say not a floodgate of farm-in opportunities, but we’re seeing more than we’ve seen in the 2002 and prior period. So I sense that the majors, particularly if you can bring a technical edge to them. What we’ve found is if you go to a major and say, ‘you know, we’re drilling a lot of horizontal Devonian plays, say in West Texas, and you’ve got some acreage that we think is prospective and you probably don’t give it any value, and you can copycat our technology if it works,’ we’re seeing that that’s a good entrée for us. And so we’ve had no breakthrough giant farm-ins in the last couple of months but we’ve, you know, we’ve chipped away and got some that, you know, 20 wells here, 20 wells there or so.

So you’re actively working it?

Yeah, we think that’s a good opportunity, and we’re seeing, I’d say the majors are clearly more amenable to that then they were in two, three years ago. I mean what we think the majors kind of guiding light is they like the North American gas story but because they’ve reduced their staffs so much over time they’re really not geared up to nor do they have kind of the cost structure to talk about drilling hundreds of 1, 1.5, 2 BCF wells. So, and they’re not willing to sell it generally because they realize that they believe in the long-term North American gas story so if it can be augmented by having someone else provide the capital on their properties they’re not shutting the door on us on those kind of things.

Right. And what about, are you looking at packages coming from some of the smaller independents?

Well, we’re looking to pick-off packages, for example, in the fourth quarter, really at the end of the year we’ve picked off a package in Canada to a company called [Pro Max] [ph] it was in financial distress. And we acquired that. And basically what that was was another undercapitalized property in Southern Alberta where we saw just a whole lot of development drilling potential in these shallow well program. So, you know, those are the kind of things that we’re more likely to do on the acquisition front this year as opposed to any big deals.

Are you seeing more of that, do you think?

Oh, not more, but we’re seeing, you know, it’s still pretty tough to identify acquisitions that you really want to grab a hold of, in our opinion.

Yeah.

That’s why, you know, basically, you know, if you choose to be a shareholder of EOG what you’re buying is a North American prospect generating franchise. You’re not buying an M&A machine, and that’s why I feel so comfortable with the company right now. I mean for the next three years we don’t have to make any acquisitions and we can still hit the production growth numbers, and basically 100 percent organic growth there. So we’re, you know, we’re concentrating more on that than on the, you know, trying to buy packages.

All right, great. Thanks a lot.

Okay.

We’ll go next to John Gerdes with Southwest Securities.

Hey, Mark, the gas number was 236 withdrawal, just by the way. On Green River Basin just the Amoxi Arch farm-out, what’s going on there? Is that Mesa Verde formation, as well?

No, John. Actually, that’s mainly frontier, although we do have some other zones below that that could be prospective, as well.

Okay. And rig activity, what are you doing with rig activity there? And just kind of reserves and cost per rig, if you would more?

We’ve got one rig running in there right now, and the cost is running roughly $700,000 in completed well cost, and the reserves we’re still working these first three wells just trying to, you know, we just don’t have an average at this point.

You’re just at the early stage with that?

Yes, sir.

One last question. On – Loren Leiker, are you still comfortable with kind of [buck] [ph] finding costs type numbers for this Canadian coal bed effort. I know you’re really early stage on that, but that’s still what you’re kind of thinking?

You know, the ranges that we’ve heard from our competitors out there are anywhere from .3 BCF per well to as much as .5 BCF per well. And we just can’t say at this point which of those is going to be right. But yeah, that’s a decent estimate for today, yeah.

Great, thank you.

And ladies and gentlemen, that does conclude today’s question and answer session. I’d like to turn the conference back over to the speakers for any additional or closing comments.

I have no further closing comments for them.

Thanks for being on the call!

Once again, ladies and gentlemen, that concludes today’s call. Thank you for your participation. You may disconnect.