EOG Resources Inc (EOG) 2004 Q4 法說會逐字稿

Good day everyone and welcome to the EOG Resources fourth quarter 2004 earnings conference call. Today's 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, sir.

Good morning and thanks for joining us.

We hope everyone has seen the press release announcing fourth quarter and full year 2004 earnings, operational, 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 proved reserves in their securities filings. Some of the reserve estimates in this conference call and webcast, including those for the Barnett Shale play, may include other categories of reserves.

We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of the Investor Relations page of our website. Investors are reminded to check our website for the latest Investor Relations presentation.

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

We filed an 8-K with first quarter and full-year, 2005 guidance yesterday afternoon, which I hope you've seen. Additionally, we're pleased to announce a 2-for-1 stock split and a 33 percent dividend increase.

As you know, we have a reputation as a consistent company and this is our fifth dividend increase in the past six years. As we discuss our operational results in a few minutes you'll also note our game plan remains consistent, focusing on high returns, organic growth, and low debt.

I'll now review our fourth quarter net income available to common and discretionary cash flow available to common, and then I'll discuss operational and reserve highlights.

As outlined in our press release, during the fourth quarter EOG reported net income available to common of $204.1 million, or $1.69 per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net income available to common to eliminate mark-to-market impacts, EOG's fourth quarter adjusted net income available to common was $194.2 million, or $1.61 per share. The reconciliation of adjusted non-GAAP to GAAP net income available to common is found in our earnings press release which is posted on our website.

For the year, EOG reported net income available to common of $614 million, or $5.15 per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net income available to common to eliminate mark to market impacts, EOG's full year adjusted net income available to common was $576.6 million, or $4.84 per share as compared to $433.1 million or $3.72 per share a year ago on a similarly adjusted basis. The reconciliation of adjusted non-GAAP to GAAP net income available to common is found in our earnings press release which is posted on our website.

For investors who follow the practice of those industry analysts who focus on non-GAAP discretionary cash flow available to common, EOG's DCF available to common for the fourth quarter was $477.9 million, or $3.96 per share, versus $370.7 million, or $3.16 per share a year ago.

For the full year 2004, discretionary cash flow available to common was $1.575 billion, or $13.20 per share, versus $1.314.1 billion, or $11.28 per share in 2003. The reconciliation of non-GAAP DCF available to common to net cash flow provided by operating activities is found in our earnings press release.

I'll now address our operational headlines. You'll note that we overachieved, with our fourth quarter production volumes hitting the top of the guidance range. We finished 2004 with 10.4 percent year-over-year production growth, which is higher than the full-year guidance we had previously provided. Yesterday we filed an 8-K with first quarter and full year 2005 production guidance, which I hope you've seen.

We expect to grow 2005 production 13.5 percent year-over-year, which will be a slight production increase in most of your models since we're compounding off a higher 2004 base. We expect to achieve year-over-year production growth in each of our three operating areas: North America, Trinidad, and the North Sea. I'll note that all of our production growth is organic.

In North America, our 2005 production growth will come from two sources: The Barnett and North America Ex-Barnett, together generating an overall 11 percent year-over-year North American gas growth.

We expect our Barnett production to increase from a yearly average of 6 million a day in 2004 to 60 -- six-oh -- million a day 2005. And we expect total North American gas Ex-Barnett, which currently comprises the vast majority of our production, to grow 5 percent year-over-year, driven primarily by growth in the Rockies, south and east Texas, and Canada, which are our bigger divisions. In each of these four divisions we expect to grow 2005 gas production by 5 to 10 percent.

I won't go into play-by-play specifics, but I can say our North America Ex-Barnett 2005 program is already defined and is heavily skewed toward development and therefore not contingent on exploration success.

We anticipate averaging roughly 45 rigs in our North America Ex-Barnett program this year. This portion of our portfolio has been overshadowed by all the Barnett headlines, but I'll reiterate that this is a powerful growth engine. There are not many companies our size who can grow North American gas 5 percent per year organically, and this is excluding the Barnett.

At the risk of being repetitious, I can't overemphasize that the key to EOG's results is not only the Barnett. The biggest driver is North America Ex-Barnett, which continues to perform very well.

Now let's talk about the Barnett. As an overview, I'll state that everything is on track and we continue to be very optimistic about the play in our results. We view 2004 as a "capture" and "prove the concept" year, and 2005 as a "drill for production" and "find out the size of what we've got captured" year.

We previously told you we had year-end 2004 goals of achieving 30 to 40 million a day net production and accumulating 400,000 net acres. We hit the production goal and closed the year with approximately 400,000 acres. We expect to drill 90 wells in 2005. Almost all of these wells will be in Johnson County. But we also plan to drill several wells in outlying counties such as Jack, Erath, Hood, and Hill, to test our acreage outside Johnson County.

We expect all of our 2005 production to eminate from Johnson County, but successful drilling in these outlying counties would allow establishment of 2006 production from these areas.

We'll provide a report on our drilling results outside Johnson County in our first quarter earnings call in late April. This will be very important because EOG has approximately 300,000 acres outside Johnson County.

Another issue we expect to resolve this year is well completion efficacy and reserves per well in Johnson County. We're continuing to experiment and at this preliminary juncture it looks to me like 2 net bcf per well, which corresponds to 2.5 gross BCF per well, is a reasonable estimate that we can replicate. By the way, 2 net BCF per well generates a 98 percent after-tax, unlevered rate of return based on our current $1.6 million all-in well, seismic, and land costs. However, I'll note that it will take us another 6 to 8 months of trial and error before we feel totally comfortable giving you a per-well reserve number that we feel can be replicated by hundreds or thousands of wells.

The third item we're addressing are ways to recover more of the gas in place, either by 50-acre spacing or stack laterals. We now have a three-well 50-acre horizontal pilot program producing, and we're going to flow these 3 wells for 6 months and see how these 50-acre wells perform relative to wells spaced on 100 acres. We'll likely report on this in our second quarter earnings call in August.

In summary, we'll achieve our first significant Barnett production contribution in 2005. Additionally, by late 2005, we'll have a good handle on the overall aerial extent of this play outside Johnson County, a pretty firm handle on reserves per well, and at least some preliminary indications regarding methods to recover more gas per hundred acres.

I'll also note that in the past few months there have been three significant transactions where companies have paid a premium to buy Barnett position. We think this independently affirms the play's validity.

Now I'll shift to Trinidad and the North Sea.

In Trinidad our production increased 25 percent in 2004 and we expect 20 percent volume growth in 2005, driven by sales commencement to the M5000 methanol plant. This plant is currently under construction and we expect start-up in July. After commissioning, we expect EOG's net sales to the M5000 plant to be 60 million a day, at a wellhead netback linked to Caribbean methanol prices, which would be about $2 per MCF based on current methanol prices.

On the drilling front, our Lower Reverse L, acronym LRL, exploration well, unfortunately was only a small success. The LRL-2 well encountered 130 feet of pay and flow tested at a 20 million a day rate. However, we then drilled an up-dip offset and the zone was fault separated and wet, so it appears we found only a 50 BCF accumulation, which we'll connect as a satellite to our adjacent SECC block.

Regarding our Deep Ibis prospect, we recently finalized the agreement with BP, subject to government approvals, whereby BP will drill the well to approximately 20,000 feet at BP's sole cost and EOG will have a 51 percent interest in the prospect if a discovery is made. BP will operate the drilling of the exploration well and EOG will handle all subsequent operations. We believe that BP intends to spud this well in the fourth quarter so the well won't be decisioned until the first half of 2006.

Last week we signed a 30 million a day gross or 20 million a day net gas supply contract with NGC for partial supply of their position to Atlantic LNG Train 4 in Trinidad. Plant start-up is scheduled for early 2006. Our wellhead price will be a function of Henry Hub pricing. EOG is not providing any equity to the LNG plant and is not involved in the shipping or terminaling of this LNG.

Last week we also signed a ten-year extension and new pricing terms on our SECC-based gas contract. Our wellhead pricing will be linked partially to Caribbean ammonia and methanol commodity prices and will also include a partial annual escalation fixed price component. With today's commodity prices we expect increased wellhead prices in Trinidad from the revised pricing terms of the SECC contract and on the new LNG and methanol contracts.

Our North Sea operations are proceeding pretty much exactly as advertised. The Arthur #1 well started up in early January, increasing our total North Sea production to about 40 million a day net, which is in line with our 2005 full-year guidance.

I'll now address year-end reserves. Our press release noted that in 2004 we increased reserves by 8 percent to 5.6 TCF equivalent. We achieved 194 percent overall reserve replacement. Our North American reserve replacement number was 209 percent. We achieved this at a competitive finding cost. The percentage of total Company PUD reserves decreased from 33 to 25 percent.

I'll note that we achieved this 209 percent North American reserve replacement while booking only 133 BCF of reserves in the Barnett. We expect to have a considerably larger booking from the Barnett in 2005 and future years.

In addition, for the 17th straight year our reserves were evaluated by D&M with no material difference versus EOG internal estimates. This year we increased the amount of reserves evaluated by D&M. They did a complete independent engineering analysis of 77 percent of our reserves, so we continue to feel good about the efficacy of our reserve bookings.

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

Thank you, Mark. With respect to CapEx, for the full year 2004, exploration development capital expenditures were $1.511 billion, fifteen eleven, including $52 million of acquisitions. Of the drilling program expenditures, approximately 31 percent were exploration expending and 69 percent development.

Total discretionary cash flow available to common for the year was $1.575 billion, fifteen seventy-five.

For the fourth quarter, exploration development capital expenditures were $501 million, including $44.8 million of acquisitions. Capitalized interest for the quarter was $3 million, and for the full year it was $9.6 million.

For 2005, our estimated capital expenditure budget is $1.6 billion, excluding acquisitions.

Assuming a totally unhedged position for 2005, which, as you know, is very close to what we are, the impact of a 10 percent move in natural gas prices would impact net income and cash flow by $21 million. A dollar move in oil prices would impact net income in cash flow by 6.5 million dollars.

With respect to capital structure, at December 31st, 2004, total debt outstanding was 1,078 million dollars, 1.078 billion, and the debt to total capitalization ratio was 27 percent, down from 33 percent at year end 2003. At year end we had $21 million of cash on the balance sheet.

The effective tax rate for the year was 33 percent and the deferred tax ratio for the year was 68 percent.

For 2004, the return on equity was 25 percent, return on capital employed was 18.2 percent, consistent with our historical averages. A schedule with the calculation of these metrics and other non-GAAP measures is included in our press release.

Stock split and dividend increase: EOG's Board of Directors has approved a 2-for-1 stock split in the form of a stock dividend. The Board increased the cash dividend in the common by 33 percent to $0.32 per share or $0.16 per share post-split when it's actually paid. This is the fifth dividend increase in six years.

With respect to our 8-K and guidance, guidance for detailed modeling of the first quarter and full year 2005 was provided yesterday in a Form 8-K filing. I'll point out that the full-year 2005 G&A guidance reflects second half projected expense for stock options of approximately $10 million as it relates to the new accounting rules. We plan to file full financials and footnotes for 2004 in either late February or early March.

Now I'll turn it back over to Mark to discuss our hedge position and concluding remarks.

Thanks, Ed.

In spite of the warm winter to date, we're still forecasting a tight 2005 supply-demand balance, even though we expect April 1st storage levels will be higher than a year ago. Although lots of people will get caught up in the myazma of weekly storage numbers, it's helpful to step back and get some perspective regarding gas supply and demand mechanics.

Last winter was 4 percent warmer than normal. Last summer was among the coolest in the past 20 years. And this winter to date has been 5.4 percent warmer than normal versus the 30-year averages. From a gas producer's viewpoint, we've had three consecutive adverse heating/cooling seasons, yet the COW 2005 futures price is about $6.50, and that speaks volumes about the relative tightness of supply and demand. EOG's very small hedge position was articulated in our 8-K's, and at this point we're essentially hedged for 2005 regarding both gas and totally unhedged regarding oil. Now let me summarize by reiterating our strategy. We'll continue to focus on returns and we're proud that in 2004 we achieved a 25 percent ROE and an 18.2 percent ROCE. We expect to have the best 2005 organic growth in the peer group, 13.5 percent. And it's not a one-year wonder. We expect 35 percent organic volume growth in 2004 through 2006.

Based on the current futures strip, we expect to fund our capital program and further de-lever an already lightly levered balance sheet. In a sector where you're seeing more and more companies having difficulty wisely reinvesting their cash flow, we're long on good reinvestment opportunities.

Additionally, I expect 2005 will be the year when the full-size and prospectivity of our 400,000 acre Barnett is defined. When you add the very high reinvestment rate of return on Barnett to our already powerful reinvestment arsenal, we feel that we have a great opportunity to again lead the peer group in ROE and ROCE over the next five years.

Thanks for your attention, and we'll go to Q and A.

Thank you. Today's question and answer session will be conducted electronically. If you would like to ask a question, please signal us by firmly pressing the star key followed by the digit 1 on your touch tone telephone. In addition, if you are using a speaker phone today, please ensure that your mute function is turned off to allow you signal to reach our equipment.

We'll go ahead and take our first question today from Mark Meyer with Simmons & Company.

Good morning, everyone. Mark, a clarification on the Barnett reserve adds in '04. What was that number?

The number was 133 bcf.

Okay. Still on reserves, can you talk a little more specifically about the 90 bcf negative revision in North American gas?

Yes, I guess, you know, first of all, I'd put that in context. If you look over our North American numbers over the last 5 years, I believe the average reserves change we've had in revisions over the last 5 years, on average, has been about a negative 10 bcf over that period. So this is not a company that has had consistent huge negative revisions year after year after year, which would make you concerned about the efficacy of the reserve base. So, I would view this as a one-year issue.

The revision came from various places. Probably the -- not one geographic area -- probably the single biggest thing we found is that some of our PUD bookings that we made the previous year, we had some acreage that expired during the year that we just didn't get to, to drill, due to drilling schedules. And since we didn't throw any acreage at year-end, we just had to renew those PUDS from the books, which showed up as a revision. So, that's probably the biggest component of -- of that number.

Did that acreage subsequently get leased?

In some cases we re-leased it, in other cases, other companies picked it up and leased it, so --

Okay, so some of it could come back.

Yes. So it was, you know, a piece of it was really a function of the -- our inability to get drilling rigs to certain drilling locations during the year, which was just the tightness of the rig market, really.

Last question on 2005 CapEx progression, if you back out your acquisions from the '04 number suggests something just south of 10 percent in terms of an increase. Can you reconcile that level of increase with the inflation assumptions and, I guess, the rig intensity and the well count intensity, year over year?

Yes, I would say it's about a fairly constant level of activity, relative to last year. In other words, the service -- it's about equivalent to what we expect service costs to go up, Mark, is probably not a bad assumption.

The one thing that we plan to do this year that will be a little different than last year is, last year we had kind of a steadily increasing rig count throughout the year and what we're planning on doing this year is having pretty much a constant rig count throughout the year. So, to avoid, you know, we know that we've got a tightness on rig situation out there and so to avoid this scramble for rigs, basically, we're starting out the year with pretty much the level of rigs that we intend to keep throughout the year.

And you think you've got essentially the same number of wells? I realize there's been a mixed shift.

Yes, it's a shift, but in conceptual terms, you know, you're directionally right that it'll be about the same number of wells.

Okay. Thank you.

We'll now take a question from Jeff Mobley with Raymond James.

Good morning. [inaudible] the revision that was just discussed, your PUD bookings went down to 25 percent from 33 percent last year. And given your success in the Barnett and the reserves that you could have booked, it seems like an even more conservative level than you all normally take. Is there anything else we could glean from that decision?

You know, a big driver for that, Jeff, was in the international arena where we transferred a significant number of reserves from the undeveloped to the developed category, and that was particularly true in Trinidad. And so that was the biggest driver for our true developed reserve percentage to increase, to 75 percent.

Okay. What was the total number of wells that you all completed in the Barnett last year?

It was -- I think it was 31.

Thirty-one? Okay, great. And then, last question for me. The Deep Ibis prospect, has that slid a couple quarter from your original plan?

Yes, it really has, Jeff. And that's been to -- a couple reasons. Probably one of the biggest reasons was the government down there was trying to decide what level of equity participation they wanted to take in drilling that well and that took a while for them to resolve it, and then the tubular deliveries, this is going to take some kind of specialty hype. That also affected things.

So, what we can say about it now, number one is, BP is really controlling the timing , so we're really kind of not in the driver's seat there, but BP does have a rig in-country, in Trinidad, for this drilling program. They do have it slotted on a drilling schedule and the latest estimate they've given us is September of this year is when the well would spud.

Okay. And lastly, what are you all viewing your pre-drill prospect size on that?

Jeff, really no change from when we talked it out at the analysts' conference. I think we gave you a range then of somewhere from 3/4s to a [inaudible] that -- you know, truthfully, we don't know how much sand could be found down there on that 5,000 acre structure. And so, you know, 2 or even 2 and half, 3, is not out of the question on a net basis.

Okay. Great. Nice job on the year. Thanks.

I'll now take a question from Joe Allman with RBC Capital Markets.

Good morning, everybody. Mark, could you tell us how many wells you've drilled outside of the Barnett Shale and outside of Johnson County at this point? And then, where they've been in terms of counties and just characterize the results for us so far, if you have any?

Yes. Nice try, Joe. What -- what I -- I'm not going to directly answer your question and -- mainly for competitive reasons. What I can tell you is that we have drilled and would intend to drill a couple wells outside of Johnson County in counties such as Jack, Erath, Hood Counties, specifically, and specifically what we're looking for there is, number one, are they gas or oil, because there's a lot of definitional issues there as you go west from Johnson County as to at what point is the transition from gas to oil occur, and there's a lot of technical questions on that and so we're trying to sort that out, really. We have our own assumption on that, but we're looking at that and then we're going to make some decisions as to leasing further acreage based on our drilling results there.

We do expect that we'll be able to publicly release results from, oh, probably at least two wells in our end of April first quarter earnings call, and that's about all we want to say about it at this time, Joe.

Mark, have you experienced any disappointments to date, in terms of finding oil where you thought you might find gas?

No comment.

Okay, gotcha. And you're skipping a couple counties there, like Parker and Palo Pinto. I mean, I think you got acreage there. Is that -- any particular reason for that, or just --

Oh, it's just where we -- the counties I mentioned there, which are Hood, Erath, and Jack, that's just the ones where we had -- are likely to drill our earlier wells because we either have 3-D seismic or we have some lease issues or we just want to go out as far west as we have acreage and test the western extremities of the oil/gas line concept. So it's either geologic or geophysical reasons primarily, is what's driving us for those areas.

Gotcha. And then lastly, on your 133 bcf for reserves in the Barnett Shale, that is from how many wells?

Oh, Bill Albright, do you know offhand?

I think it's about 35. We did have some wells that we're in the process of drilling or completing at year-end, that we did not book. That would include, obviously, the few wells that we have, the very de minimus bookings that we had at the end of the year last year.

All right. Well, thanks for your time.

Plus the PUDs? Is that --.

yeah.

I think it's 35 wells plus the PUDs that we would have booked off that, so I'm not sure what the total wells were.

Okay, gotcha.

All the reserves we booked would have been obviously in Johnson County.

Okay. All right. Thank you.

Up next is Bob Morris with Banc of America Securities.

Good morning, Mark.

Hey, Bob.

Looking back at the Barnett Shale, last quarter you had completed 20 wells and it said the most recent three had come in at about 3.3 bcf gross. You said this morning you've now completed 31 wells. How have the subsequent 11 wells come in as far as reserves per well in comparison to everything?

I don't have the -- we're trying to get away from the specific well count as far as numbers of wells and, you know, what the reserves are, and the main reason is the well counts just all over the place, you know, what Bill Albright reported are the wells officially that we ended up booking as of December 31st, and we've got wells up through yesterday, put in the database, but what I will -- I'll give you just a little bit of color on my feeling about this 2 net bcf per well, which is, I think, going to the heart of your question. And you're right. The last quarter we had said that the most recent three or four wells we had at that time were a little bit better than that.

What we're finding is that we're getting some -- several wells that are very, very good wells and are at least as good as some of those very, very good wells that Hallwood kind of episodicly had been reporting. You know, we're getting wells that on a gross basis are probably 4, 4.5 BCF wells, and we now probably have 3 or 4, maybe 5 of those wells in our population now.

And then what we're doing is we're drilling a well immediately offset to it that, in giving it pretty much an identical completion and from what we can tell it should be an identical well and we're finding that that well maybe is only a 1.5 bcf well. And so what we're finding is that the average of the wells that we're completing seems to be hovering around this 2 net bcf well, but there seems to be a pretty good range, you know, ranging from, you know, 1.5 to maybe 4 bcf or so, or maybe even 1.25 for -- and this is still really kind of technically confounding us a little bit.

Those step-outs, they're 100-acre step-outs?

Yes. These are all on 100-acre spacing.

Do you think you're draining, then?

No, this has got nothing to do with drainage at all. These are all undrained locations. So it's got something to do with either rock qualities or something like that, you know, and so that's why we're still saying it's probably going to take us another six to eight months of working with this rock to figure out, you know, what's going on. So I think the conclusion I'd give you is, this has not yet proven to be one of these well bore manufacturing things where every single well turns out to be a 2 net bcf well, plus or minus 10 percent on reserves. Still got a pretty good variance, but, you know, the average reserve is about 2 bcf but with a pretty wide variance around that.

The last three wells that were so good last quarter, you had said for the first ones with the modified A-type completion, have you done the modified A-type on these last 11? And -- what is -- how are you coming out on that? Is that not the key then, after that?

Yes, I mean, we've done modified and then changed it a little bit more, but I'd say that it hasn't consistently given us, you know, the improved wells on there. So, you know, what I would recommend to you right now, you know, is to use this 2 net bcf as, you know, as what I'd call a rational number and just realize that we're not at the stage now where we can just kind of rubber-stamp these wells one after another after another where they're all going to come out that way.

The good news is, even at the low end of the range, you know, on these things, you know, we're still getting wells that -- where the average reserve is 2 bcf and you have a 98 percent return, you know, even the wells I'm saying are disappointing at the low end of range, they're still probably a 20 or 25 percent return in there, so we're still in excellent economic territory.

The other thing that we're still playing around with is where to locate these laterals in the Barnett section. And frankly we thought we had it -- you know, three months ago we thought we had the optimum place in this 300-foot Barnett section located as to where to steer this, and now we're just not so sure, so, you know, I would say it's going to take us another 6 to 8 months, but I would plug in like 2 net bcf if I was doing any modeling on this, in Johnson County.

But you're sure it's the rock quality and no communication between the offsets and the original well?

Oh, yes, we're positive of that. Yes.

Okay. What have you been paying per acre on -- or, what did you pay on the most recent 55,000 acres from last quarter? What are you paying per acre on average now?

I'll give you some overall numbers. For the 400,000 acres that we have, we have about $100 million in acreage costs. So, you know, in rough terms, that's about 250 bucks an acre for everything that we own.

In terms of the most -- the incremental last 50,000 acres or 55,000 acres, I would say that has been probably 300 or 350 bucks an acre, Bob, in approximate terms.

Again, if you're trying to lease acreage in the near-in counties, which would be Hood, Parker, Johnson, Hill County, it's exorbitantly expensive if it's available at all. When I say exorbitantly, you're talking 4 or 500 bucks an acre, generally. As you get to the outer counties -- Palo Pinto, Erath -- it's cheaper, but it's -- in relative terms, it's not very cheap.

So I guess the -- in total acreage throughout the Company last year in that $1.6 billion -- what was it, 150 to 200 million you spent in total Company-wide on acreage last year? What was the number?

142.

142? Okay. Great. Thank you.

All right, Bob.

Our next is Shannon Nome with J.P. Morgan.

Hey, good morning, Mark.

Hey, Shannon.

Just to beat the Barnett Shale bookings topic a little bit more than it already has been. It sounds like you've basically booked it kind of a well plus an offset, if I'm not mistaken. I mean, if that's -- A, is that the case, and then B, can we assume that's kind of going to be your approach going into year-in '05, where you'd book, you know, 90 new wells plus an offset each, which would imply, you know, quite a pickup in your bookings by the end of this year?

Shannon, it's not an absolute. In some cases we have more than one offset booked to a producing well. In some cases we have no offsets booked to a producing well because we factor in geology and the geoscience that we have to date, in and around that location.

Right.

So I don't think you can just say it's an absolute one for one or two for one. It does vary across the field.

But as an average?

As an average it's probably okay.

You're probably directionally correct, Shannon. Yes, the way I see the both production and the reserve bookings on this, you know, where you're going to see the production really begin to move on this is not so much in '05, you know, of course, we'll go from 6 to 60, but I think where we're really looking at the production growth is going to be '06, '07, '08, and I think you're going to see the same reserve movement in '06, '07, '08, so I would not look for a massive booking in calendar '05 from the Barnett.

Okay.

I think that's going to be more '06, '07 kind of time frame.

Okay. And then, so what was then the PUD mix in that 133-B? Was it roughly 50/50?

It was about 65/35.

65 developed?

No, other way around.

Okay. And then just one more. Mark, you briefly mentioned or touched on stacked laterals earlier. Have you started any pilot work there or are you just focused on the down-spacing for now?

Right now we're focused on the down spacing. I'll give you a little bit of color, just on the down-spacing. You know, we drilled -- and this is during the last quarter. We got three wells on 50-acre spacing and we fraced these three -- we had one well already, and what we did is we drilled two wells on a 50-acre spacing and we fraced those two wells, and we used this frac, oh, I guess you'd call it mini seismic technology, called pinnacle technology, to kind of map where the fracs go along the laterals, and to see if, for example, all the fracs on these two 50-acre offsets would channel to the well that was already drilled.

And what we've seen on the frac mapping made us very, very pleased. We saw that basically we got the whole laterals fraced, and that the fracs did not all channel to the original well that was there. In other words, we feel we have an extremely legitimate three-well program here where the fracs really, if we could have drawn them up where we wanted them to go, they went exactly where we would hope they'd go.

So I'd say that on the question of do we have a legitimate pilot, the answer, I would say, on a technical basis, is yes, and now we just have to watch it for six months and just see how are these wells declining, relative to wells on 100-acre spacing. And we also have a vertical well that we drilled that we're not producing it or anything in the Barnett, all we're doing is just constantly monitoring the pressure in that well, and that will allow us to do some computer simulations also.

So probably by August we'll have a pretty good handle on, you know, on what that looks like, and then another concept we have is really drilling two laterals in this 300-foot-thick zone. We may not do that until maybe the fourth quarter. It will probably be something that will be sequential to how the 50-acre spacing does. Our first choice is 50-acre wells at this juncture, but I just would say that we're going to figure a way to get more of the gas in place on 100 acres, I'm pretty confident on that, and it's just a matter of, you know, what method will we end up with there.

Very good. Thanks, Mark.

Yeah.

We'll now hear from David Snow with Energy Equities.

Yes, hi. Just to follow up on that, would you be then drilling horizontal laterals parallel to each other to achieve that 50-acre pattern? Or -- it's getting pretty crowded. How would the -- how would it lay out?

Yes, well, In terms of 50 acres, I mean, you've got to remember, people in the Rocky Mountains right now are drilling, for example, in a field called the Jonah field, or in a field called -- or in areas in Colorado called the Piceance Basin, and they're drilling on 10-acre spacing now.

But those are vertical wells.

Those are vertical wells, yes, but spacing is spacing, whether vertical or horizontal.

I was just wondering how it would lay out. You'd go parallel to each other?

Yes, they'd be parallel to each other, yes. But, you know, vertical or horizontal, it's just how much are draining with well bore. So 50-acre spacing in today's world is not particularly dense.

Okay. And you had mentioned earlier in a conference call, the type-A faulted and type-B faulted. Is this more dense drilling down-spacing applicable to either type?

Well, technically we're pretty much saying that in the faulted areas we're not -- we've decided that probably we want to stay away from the faulted areas. So our rule of thumb that we have right now is, if you have 400,000 acres, that about 50 percent of that acreage we believe would be faulted, and so we really effectively would have 200,000 acres that would be developable. And then if you drill that on a 100-acre spacing, let's just say that would give you 2,000 wells, in very, very rough terms. So the faulted areas, we've now learned, you kind of want to stay away from.

All right. And in terms of the completion, do you have several stages? What would be a typical stage -- number of stages of fracing?

Yes, that's still kind of proprietary. We're still working on that, our completion methodology.

Okay. And the stacked is -- could you -- is it more difficult or expensive to do that, or -- you'd be using the same vertical well bore. That might be cheaper than drilling multiple wells horizontally, wouldn't it?

Yes, the stack lateral would be just -- you'd have just two wells out of one vertical well bore, and in rough terms it might be slightly cheaper than drilling two wells but not, you know, I wouldn't say it would be massively cheaper.

You're thinking in terms of the perspectiveness, the better shot to take first would be the down-spaced horizontals, I guess?

Yes.

Okay. Thank you very much.

Brad Beago with Lyonnais Securities has our next question.

Hey, Brad.

Good morning, Mark and others. To move away from the Barnett for just a second, I know you hate to, but you mentioned the renegotiation of the SECC contract. When will that take -- in effect? I notice that fourth quarter realizations in Trinidad I think was a record for you. What should we expect to see going forward as a result of this and when is -- what's the timing?

Yes. Let me give you a little color on that, Brad. The SEC contract is -- for cal '05 will average maybe about 100, 105 million a day net on the volume, and in -- in terms of the price, if that contract -- it was a renegotiated contract -- had been in place last year in '04, we would have gotten about a $0.40 higher price on that element of our gas sales. And so if one were to assume the same rough level of Caribbean ammonia and methanol prices, that's the kind of uplift we would expect on 100, 105 million a day of our product in '05. And it will be in effect starting January of '05 at least.

Okay. Do you want to talk about maybe what your realizations are for January? Give us a sense?

Well, I don't know if we run them, you know, exactly -- I mean, what the total realizations are when you put the ammonia and the methanol and everything -- or, the ammonia in the mix there, so, you know, I would say, you know, in rough terms, -- I'm not sure I can give you a number relative to the fourth quarter on that, Brad.

Brad this is Maire. You can see from the 8-K guidance that we gave you, in Trinidad for the first quarter, the upper end of that realization is $2, so there is quite an uplift.

Okay. All right. Thank you.

Plug it in.

We'll now take a question from Gil Yang with Smith Barney.

Hi. Good morning. Talking about Barnett -- in view of the reserve revisions you had, where you had some leases that expired, you just didn't get to them -- how confident are you that you're going to be able to get to the 400,000 acres that you currently leased?

Oh, we're very confident on that. The way I'd put it there, Gil, is if you take our total land force that we have in our Fort Worth division office right now, we've got about, oh, I think it's about 40 or 50 people working on our behalf in our land department there, and we're gearing up to make sure that we don't lose any leases there in terms of that. And right now we're in the primary term of our leases, and then we've got extension point, but we're very cognizant of the issues there. So at this point we're going to get to all the leases that we need.

I mean, where we are right now, we're shooting, in Johnson County I think everybody knows where we're at. We're drilling there. But we're shooting 3-Ds in places like Hood County. We've already had a 3-D shot in Jack County, and we're gearing up some 3-Ds in some other areas, and so that's the step that's preliminary to actually drilling wells.

So, you know, once we get those 3-Ds shot, we'll know what acreage we all may want to drill on or what acreage we want to turn loose of, so I'd say we're progressing in a pretty good sequential manner, so that's not -- it's a major issue to watch, which is ultimately the lease expirees, but it's not an issue that's real high on my worry list, Gil.

If that were the sole limiting factor, what would the acreage position that you could build up be?

Expirees?

Yes.

Oh, my.

Could you do a million acres?

Oh, I don't -- I think probably the maximum we're thinking in terms of might be half a million acres that we could capture in any case anyway. So I don't think we have any thoughts of even trying to approach a million acres.

Okay. So from an operational point of view, you could maybe handle half a million acres?

Yes, you know, maybe 600,000, but i -- you know, if we were to try to go north of -- you know, close to a million, I think, yes, we would -- that would be an issue that would be probably maybe bigger than we can deal with.

Okay. With respect to the stacked laterals, does that suggest that with that -- the -- I guess the, what do you call -- the pinnacle technology, does that suggest that you're able to determine that you're not accessing the entire vertical volume of the rock, and what portion are you accessing, do you think you're accessing?

Yeah, that's exactly right, Gil. We -- our reservoir modeling that we've done on the Barnett right now would imply to us that the height we're getting on these fracs is definitely not anywhere near 300 feet. It's considerably less than that, and so if that modeling is correct, that would say that you could accommodate, you know, two laterals in this 300-foot zone and not be draining one from the other. And so that's right now a theory we have that we'll probably have to test by drilling a well with two stack laterals and seeing.

Can you see that on the micro seismic data that you get?

It's not really clear. I think in some cases we've done this on more than the 50-acre pilot that Mark mentioned before. We've probably done four of these so far in the Barnett, and in some cases it looks like we're getting full extension, in some cases not. We're not quite sure yet.

Okay. And finally, your guidance for U.S./Canada gas is up 11 percent gross in '05 and I think at the analyst meeting you said 10 percent. What's the reason for the slight bit of more optimism there?

One moment, everyone. Our speakers have disconnected. They should be rejoining in just one second.

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Hello, Gil? Hello? We just got reconnected to the line here.

Mr. Yang, your line is back open.

Okay. Yes, the last question was just, you're saying 11 percent growth in U.S. and Canada, and in the analyst meeting you said 10 percent growth. What's the source of the material change there?

Yes, just from the analyst conference, you know, at that time, Gil, we were basically -- we didn't think that our fourth quarter was going to be as strong as it was, and basically what we've seen now in the fourth quarter is that our production growth in North America Ex-Barnett has been more robust than we thought, and so what that has allowed us to do is basically say that from North America Ex-Barnett, we basically feel we're going to have more robust growth, and so we've upped the number from 10 to 11 percent for North American gas for the full year.

And again, you know, the full-year estimate is higher because now we're compounding the 13.5% off a higher base than when we had our September analyst conference.

Okay, good. Thank you.

Thank you.

I'll now move on to Greg Pardy with Scotia Capital.

Good morning, Greg.

Hi. Good morning. A couple of questions. Just on the Barnett, just the number of wells you expect to drill on that play in 2005, and then shifting gears, you talked at the analyst day just about the testing that you're planning up in the Northwest Territories. Is there anything you can say on that, or are you still quiet?

Yeah, on the Northwest Territories, let me have Loren address that. Loren Leiker.

Yes, Greg. We are in the process right now with Partners drilling our second well up there and actually reentering and testing our first well over this winter season. And we anticipate having results back that we can talk about probably by the middle of this year, roughly June.

I would say that we did add to our acreage position there over the past summer as well as acquiring additional seismic, I think a total of about 200 kilometers of seismic. So we have about 270,000 net acres in that entire play right now, a million acres gross, and I think you can take it from the fact that we increased our position that we feel pretty good about it so far.

So you -- I mean, you really want light crude here, I guess. You've got availability on the normal wells line?

There is availability on the normal wells -- there is capacity available on the normal wells line, I think around 20, 30,000 barrels a day that -- hopefully that will be the case, but in the gas case, of course, we'd be looking at laying a lateral to the line coming out of the McKenzie Delta in 2009, something like that.

Yes. Okay.

You have to realize, this is very remote territory and it will take us probably a couple of years to really figure out what we have there and drill the other 6 or 8 structures that we have identified so far.

Okay. Great. Thanks.

On your other question, Greg, on a number of wells we plan to drill in Barnett, I mean, we would plan to drill about 90 wells there this year and just as we would look out from our vantage point today for '06 and '07, I would think that, you know, we would drill more than 90 wells in '06 in the Barnett. Can't really give you an estimate now, but, you know, maybe 120, maybe 140, you know, might be a number of the range we're conceptually thinking about now in '06. But that will depend particularly on how these outlying wells in the outlying counties turn out.

Okay. And then, I mean, certainly just in terms of how the math works, you're still thinking well in excess of 100 million a day as an exit rate in '05?

No, I wouldn't say well in excess of 100 million a day. I mean, we're talking about approximately 100 million a day net as an exit rate for '05.

Thanks very much.

Yeah.

Our next is Irene Haas with Sanders Morris Harris.

Yes, Mark. Any status on your other Barnett Shale look-alike in Texas, and is it in west Texas or south Texas, and how many more of those, in your opinion, you possibly can think of that is still around to be found?

Irene, come on. I mean, we haven't disclosed the location other than it's in the state of Texas, and it's hundreds of miles away from the Barnett play in Fort Worth. I'll ask Loren to give whatever color he can give without giving much other information on it.

Not much color. We have established a pretty good acreage position in excess of 100,000 acres on the separate play, and we do intend to drill pilot wells into that program sometime this year, probably towards the middle of the year after we have accumulated additional acreage.

All I can tell you is that it looks to us like it's a very similar type of shale in a very similar geologic setting and depth range to the Barnett and that's probably where we should leave it for now.

And how many more of these do you think, you know, realistically, there are still around?

You know, we are looking for additional plays of this ilk both in Canada and in the U.S., as are a number of other players. Years ago, people looked at that time coal bed methane in the San Juan Basin and said it's the only one of its kind and it turned out that there are a lot of other coal bed methane plays that are not quite as good as the San Juan, but are still coal bed methane plays that are economically viable and I suspect that's how it will turn out for the Barnett. It's thicker than most shales of its lithologic type. You don't usually find shales that are that brittle that are that thick. And its particular history is somewhat unique as well.

Having said that I think that there will be other shale plays found, with slightly different characteristics and will be economically viable. How many? Who knows. Maybe 4 or 5.

Best of luck. Thanks very much.

We'll now hear from Jeff Hayden with Pickering Partners.

All my questions have already been answered. Thanks

Thank you. We'll now move on to David Snow with energy equities.

Nobody asked about the Horseshoe Canyon and I notice that you'd previously said you get .3 bcfs for 250,000, which is about the same finding costs as your Barnett. What's happening and what spacing might you eventually go to up there and what are you planning now?

Yes, David, in that Twining coal bed methane Horseshoe Canyon area, we've drilled a total of about 80 wells so far. 50 of those , or 62 of those, are actually in these 2 pilot areas that we drilled this year, then a few outliers beyond that, just to test the rock. We are still thinking in terms of that 3/10's per well, although some of the other operators in the train are seeing as much as 5/10s -- or -- not 3/10s -- 300 million. per well. Some of the operators are seeing half a bcf per well, or at least reporting that.

Our IPs look very similar to what these other operators are seeing, something in the 100 mcf per well range.

What they are spacing on and what we are spacing on right now is 160 acres. We think it's going to be at least that. It could actually go down to 80s at some point in the future.

We currently have about 130,000 net acres in that area, but in total in that Horseshoe Canyon, we really have about 230,000 acres. Then we have an additional half a million acres that also has coal bed methane potential in Canada for other coals. Notably the Manville coals.

And how many -- how much are you spending in dollars here versus in Barnett this year?

In 2005, I think we're looking at drilling about 100 wells in the Twining area, so, you know, substantially less.

Yes, it's a small fraction of what we're spending in the Barnett, and, you know, although the Horseshoe Canyon is definitely a real play for us, I mean, the relative economics of that play are considerably lower than what we perceive the Barnett play. I would view it -- the Horseshoe Canyon play is a nice kind of bread and butter play for us, but it's not going to be an impact play.

I think as you look at Canada, coal bed methane, the emerging thing that would have a major impact on EOG is if the Manville coals in Canada turn out to be an emerging coal bed methane play and there were some hints of that by some other operators, because that's where we do have this 500,000 acre position already, and I would guess this year will probably be a pretty informative year. We'll do some tests in it and the industry will do quite a few tests in it, and that might be a hidden kind of crown jewel that we have as an asset. But it's just too early to tell, David.

Okay. Thank you very much.

Yes.

Gentlemen, at this time there are no further questions, so I'll turn things back over to you for any additional or closing remarks you may have.

Okay. I just want to thank everybody for staying on the call through the interruption.

Just to summarize things again, again, our very first choice or goal is to maintain a very high ROE and ROCE. You're going to hear us constantly talking about that.

The second point that I'll make is, there's a lot of buzz in the sector right now about free cash flow, and we believe we've got our debt level at a debt-to-cap ratio right now about 27 percent where, you know, we're not in a great anxious mode to pay down our debt to extremely, extremely low levels as we believe the most important discriminator right now among E & P companies is who's got the opportunity set to make a lot of wise reinvestment opportunities, and we think we're very long on wise reinvestment opportunities.

If you run the futures strip through our kind of cash flow model right now, you'll see that we can spend the $1.6 billion, which will allow us to execute our capital program and have somewhere between probably four -- roughly $400 million of free cash flow which would allow us, if we chose, to simply pay down debt with that to exit year-end '05 with a debt-to-capital ratio that would be somewhere in the mid to high teens. So we may be able to basically have our cake and eat it, too, this year, which is have extremely high organic production growth, also to pay down a significant amount of debt and end up with a very, very low debt ratio and also be pretty well set up for cal '06.

So, thank you very much for staying with us. This should be a very interesting year for us.

This does conclude today's conference call. Thank you everyone for joining us, and have a pleasant day.