EOG Resources Inc (EOG) 2002 Q1 法說會逐字稿

This is Premiere Conferencing. You are on line for today's EOG Resources first quarter 2002 conference call. At this time we are assembling today's audience and we expect to be underway in a few moments. Your patience is greatly appreciated. Please remain on line.

Please stand by. We are about to begin.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, sir.

Good morning and thanks for joining us on the call.We hope everyone has seen the press release.

This conference call includes forward-looking statements.

With me this morning are Ed Segner, our president and chief of staff. Loren Leiker, our executive vice-president of exploration and exploitation; Gary Thomas, E.V.P. of formations, and Laura Baldwin, our vice-president of investor relations.

The first quarter 2002 was a strong operational quarter for EOG, delineated by several exploration successes.Consequently we feel very good about the resulting return we expect for the $196 million of capital we spent in the first quarter.

This should set EOG up nicely for a strong second half 2002 and full year 2003 performance.

Our start up first quarter operational review with Trinidad where we have three discreet accomplishments to report.The well was drilled to 17,960 feet and this wild cat encountered 372 feet of high quality pay.

We expect the well to have a stabilized flow capacity of at least 40 million a day with 1200 barrels a day. The widely reserve range is 250 to 350 net B.C.F.E. Although because we are conservative we may not book this full amount at year end.

The prospect was identified as the reprocessing our existing 3-D seismic on the SCC block

The second discrete Trinidad accomplishment is the signing of the Nitro 2000 ammonia project and related gas contract.

It will provide 100 percent of the 60 million a day gas supply to the plant which will commence operation in the first quarter 2005.

The third accomplishment is the signing of the new 90,000-acre offshore exploration block called lower vessel which is contiguous with our SCC block.We intend to commence a 3-D seismic block this summer and complete the well next year.We will see a wealthy production increase at that time from Trinidad.

Additionally, our Parula discovery means we now have incremental reserves to search out additional local and export markets. We are pursuing both LNG and even CNG which is compressed natural gas, because these would have prices linked to Henry hub.We completed two wells flowing 15 million a day each and are constrained by surface production facilities. We are currently completing two additional wells, one of which should have a 25 million production capacity and our drilling an additional well we should have a similar capacity.

We expect to install expanded production facilities early in the third quarter and expect to have increasing production from this field throughout the year. Our working interests in this field is approximately 50 percent.A typical recent completion is the he will guard 21 which is currently flowing 2 million cube feet a day.In the Devonian we think the optimum way to access this gas resource is through multi laterals. We successfully completed our first dual lateral. We are in the process of completing our second dual lateral and currently completing our first triple lateral well. Because this is so tight and has minimal natural fractures these wells will not have monster productivities. We expect stabilized rates of two to 4 million a day per well. We plan to run four to six rigs for the remainder of the year in this area.

Our goal is to determine the optimum way to drill and complete these wells so we can go the into a program drilling mode in 2003.We expect to drill approximately a thousand shallow wells this year. This program has repeat ability. This is a very low risk way to grow production. Because of our experience we are one of the cost control leaders, which is critical in this play.

Thanks, Mark.That was excluding acquisitions between 700 and 750 million.

Acquisitions are currently forecast to be approximately $50 million.But which the primary item in the 68 million was a $53 million decrease in accounts payable, which essentially reflected the decrease in the first quarter 02 capital expenditure program versus the first quarter 01 capital expenditure program. That decrease between the two quarters was approximately $75 million. I think you can see it coming through the accounts payable category that way.

As we've mentioned before, we are maintaining an opportunistic share buy back strategy with the goal of maintaining a strong balance sheet.

We are remaining flexible to provide some market liquidity in the event the eleven and a half million shares held by Enron come to market through the bankruptcy process. Thus to date we have not repurchased any option shares this year.

EOG would prefer to see the Enron shares sold in the near term to increase market liquidity. Obviously this is very manageable as we have had share holdings of this size in the past and have been able to handle these in a very orderly fashion.

As a reminer, all of these eleven and a half million shares are fully in our outstanding share account of one ways I can share count of 115.6 million at March 31, 22.The deferred facts ratio was 85 percent.

Turning to the legislative front for a second, with the energy bill going to the house Senate conference -- to the house and Senate conference committee, you may be aware that it includes in both the house version and the Senate version various forms of tight gas stands and Devonian shield tax credits. Obviously EOG would stand to benefit if the bill passes in any form, coming out of both of the houses. If that happens, obviously we will need to open mice our own capital expenditure strategies and drilling strategies to take advantage of those opportunities.

With that I'll turn it back to Mark to close out.

Thanks, Ed. Let me talk a little bit about our perception of the gas market and our head situation. In the last quarterly conference call, we said we expect low gas prices in the first half of the year strengthening in the second half. The gas price recovery came one quarter faster than we predicted partially driven by the 7-dollar per barrel crude price increase. However, until we work off the storage surplus I'm still confident regarding short-term gas prices but will certainly accept the 350 plus prices we are seeing on the screen right now

We also told you because of the 29 percent U.S. industry gas decline rate, we expect the domestic production to fall by three to 4 percent this year. In the recent first quarter public company production numbers certainly support our decline estimate and are in fact indicating sharper declines than even we estimated.

We expect this domestic gas production decline to increase during the second, third, and fourth quarters this year because of the low gas recount. By the fourth quarter we expect year-to-year comps will be off six and a half percent which means we will enter 2003 with crippled deliver ability. With that macro view, I'll now discuss EOG's hedging strategy and results.

For 2002 we took a view that gas prices will be stronger in the latter part of the year and we layered in hedges for the first half. First quarter we were 29 percent hedged. In the second quarter we have an average of approximately 360,000 [M.N. BTUs] a day in price swaps at an average price of $2.77. These are under water and reflected in the market to market loss calculations of $34.3 million at March 31, taken in the first quarter.

We have 2,000 barrels of oil a day hedged at 22150 price through December 2002.

We have totally unhedged on both gas and oil for 2003 and beyond.

Let me talk about our 8-K for a minute. Updated guidance detailed modeling of EOG for 2002 was given in the 8-K filed last night. We have laid out guidance for the second quarter and updated full year 2002 along the previous guidance for production ranges, price differentials and cost structures.

To summarize we had a great first quarter operationally. Our goal this year is to set the company up for the second half of 2002, full year 2003. Based on our first quarter results, we are on track to achieve that goal. EOG's production profile will be counter cyclical.

We discussed financial replicasy on the last conference call but I want to remind anyone EOG has no SPBs. We have zero good will on our balance sheet and has never had a significant write down in our history.

That concludes the prepared part of the conference call. We'll go to Q & A now.

Thank you. Our question and answer session is conducted electronically. If you would like to signal for a question, press the star key followed by the digit one. Again that's star one on the touch tone phone. We will pause for a moment to give everyone a chance to signal.

Our first question will come from Ray Deacon.

Hey, good morning.I want to make sure I understand that.

That's essentially right.So you can, you know, squeeze out roughly 50, 52 there.

All right.

And the single largest item on that is in the accounts payable area where it increased -- excuse me, decreased $53 million.

Great. Got it. In terms of, you mentioned the gas credits and Devonian shales. Is it too early to quantify as it stands now how much this would benefit you going forward?

It us in a lot of ways. Obviously in conference committee it's very, very hard to know where they will come out. But I think one thing we need to remember is, this company was a significant beneficiary in the program that was done in the early '90s. And there is really no reason to believe under either of the programs, and they are very different how they have been structured. But in both cases they would be, we would be significant beneficiaries.

Thank you.

We will now go to Robert Morse of Salomon Smith Barney.

Good morning. I have three questions. First for you, Mark, regarding the domestic gas production, Nye in the first quarter you did not moderate, although at the same time because of the warm weather and lack of extreme demands you didn't produce all out similar to what Exxon Mobil told us in regarding to production numbers being down. We saw, going forward with pressures up during the period.

How much do you think production was held back as opposed to if we had had really extreme weather and everybody had been producing all out? Percentage-wise for the industry?

Yeah, my sense is, Bob, that they are probably, that might affect a 1 percent number here. I'll tell you, our goal in estimate based on the 29 percent decline rate and the three to 4 percent total U.S. production decline, that we articulated last quarter was that the first quarter production year-to-year costs would be off maybe two and a half percent, second quarter three and a half, growing throughout the year to be about six and a half percent.

By the fourth quarter the numbers we're seeing right now are certainly a lot sharper than the two and a half decline we would have guessed on a year-to-year comp for the first quarter.

And I think part of that is due to -- certainly last year everybody was trying to put all the compression on wells and do everything they could to get every MCF a day out. Maybe 1 percent I might attribute to that, I would think would be an industry guess I would make, Bob.

Second question for Loren on the forecast of $50 million in acquisitions this year, previously you indicated perhaps up to 200 to 300 million in acquisitions. Is that lower number now just because prices haven't come down? You are not seeing the deal flow or what is behind the lower number than what the previous indication was?

I think it's partly that for sure. Prices had risen faster than what we expected. Obviously the opportunities are not going to be as great. I think one thing to keep in minds is that, you know, this is a

company that does detailed return analysis on acquisitions as well as our own drilling program. Not everybody does that on the acquisition side. That's justed standard here. And so we are very price conscious in terms of making those decisions.

As I said in the first quarter we made about 10 million of acquisitions. We have additional acquisitions most of which have occurred in the second quarter.

The second aspect is that we just simply have a lot of TV in our drilling program and, you know, we've always been a company that driven our druthers, we would rather drill than acquire.

Last question real quick. You said you prefer to see the shares held by Enron sold in the near term. I think that's a reversal practice what you said before. Before you had a lawsuit to make sure that those shares were distributed for the terms of the original convert. Why the change of view there? Why would you rather see those shares put out near term?

Good question. To kind of clarify our previous position was that we wanted to enforce the transfer restrictions and voting restrictions that are on those shares and make sure that those in fact were abided by in any subsequent sailor resale of those shares. And we have as some of you may have noticed in a 8-K filing several weeks ago with an institution that claims beneficial ownership of those shares, they are one of the partnerships that Enron did. We have gotten those types of share transfer and voting restrictions recognized. So that issue is off the table.

So from this point on, our simple issue with that is an orderly transition of those shares to the market place. And of course, that's really not anything that we have a great say in, to tell you the truth. We are really not a party to that in anyway. That is a matter for the bankruptcy court to determine as there obviously may be several competing parties who claim those shares. Certainly one possibility is to simply sell them and place them in escrow.

We really don't have a feel as to whether we are looking at a 30-day process, 60-day process, or something that might be three to five years. I do think it's fair to say that there will be parties who will try to take a shorter term view. Whether or not they are successful or not, that would be sheer speculation on our part.

Okay.

Our next question comes from Irene Hawes. She's at Sanders Morse Harris.

Hello, everybody. This question is for mark. I would like to have a little update on your Devonian program, the horizontal drilling. It sounds really good. Wanted to have a recap as to what you think could be recoverable, say at a 3-dollar gas price and what is the break even you are looking at now. How many wells you possibly can drill per year once you go to program drilling. And how many years of inventory you might have.

Good morning, Irene. The Devonian play, our goal at the beginning of the year was to go ahead and drill some dual laterals, drill some triple laterals, try different well stimulations on these very tight rocks and have an optimum way to drill and complete a typical well determined by year end this year.

What has happened is the gas price has risen faster than we thought and so we decided to accuse sell rate our program a bit. And we would hope that before the end of the year now we will have the open numb methodology as to how to drill and complete these wells.

Our drilling inventory here could be considerable large. Especially if you are talking about a 350 or a 370 stabilized long-term gas price, which is what I believe.

So we believe that, I think in the last quarterly update we said we had booked about 100 net VCS at year end last year to this Devonian and as a minimum we had another 150 to go. I would say what we are seeing now, we think there's considerably more reserve outside on that that will play out likely in '03 and '04.

We will now go to Andrew Lees.

Good morning. You touched on the tax situation.Yours seems to be coming down. What have you done to facilitate this and how long do you think it can last, aside from the energy bill?.

Good question.So obviously that benefits us from a deferral standpoint.

Obviously we are all hoping that that does change. So it wouldn't last permanently.

So that is -- plus the rate changes. So that effectively is part of the answer.As we are continuing to have a fairly active program here, that gives us some ability to shelter.

Thank you.

Now go to Sean Reynolds. He is he's at [Petri Parkman].

Good morning. I wonder if you can give us an idea of the production volumes that you have acquired. And also just from looking at the income statement it looks like you've actually sold some reserves as well. If you can net that out for us for the quarter.

Yes, Sean. Pretty much all the acquisitions that have been made and really, you know, the 20, $30 million of acquisitions really so far if you roll in the second quarter are characterized by very low current production rates. And ability to grow, to drill literally hundreds of wells on the acreage. It's basically looking at generally undeveloped kind of activities.

So in terms of what we bought, it's pretty de minimus. In the first quarter it might have been a million a day, maybe total by the second quarter might be two to 3 million a day.

The real important thing, what are we going to do with this? We think we can grow those substantially particularly with the drilling program later this year out there.

Okay. Then getting back to the deep Devonian, this is quite a bit of a ramp up from what you indicated earlier in the year. And you did say it seems to be mostly associated with rising gas prices. Would that suggest that if we had some sort of near term correction during the summer that you pull back from it? Are you pretty much going to run four to six rigs solidly for the rest of the year, irregardless of what happens in the short-term with the gas prices?

You're right, Sean. We previously said last quarter we were likely to run two to three rigs in this program this year. And what we found out is a typical, a triple lateral well takes us about 90 days to really drill. And then another 20 or 30 days minimum to complete

So the problem we have was, you know, if we wanted to drill triple laterals and do some experiments on them, we only get about three wells a year drilled using one rig.

So what we have decided to do is ramp it up, mainly because we want to just try different methodologies. I'll say a bit of a science experiment here. So it was the ramp up was driven more by, we wanted to get enough data on alternate drilling and completion methods by year end so that we could have this thing figured out as to how to go forward in '03 and forward.

Okay. Finally, on Dinn Ranch, you mentioned that you are -- you are in the process of completing two wells. Is that correct?

Right.

Seems like you have been in the process of doing that awhile now. Is there anything, any kind of hiccup?

No, the difference, Sean, is that last quarter we said we were completing, both of those were completing 15 million a day each and have a capability of $25 million 25 million a day each. What we have done in the last three months, we completed those two. They were absolutely excellent wells.

We have now completed two more wells and we are completing those wells. In terms of progress, the progress has been very substantial. The program has worked out well.

The biggest draw back that we have now are surface facilities. This gas contained some CO-2 and a little bit of hydrogen sulfide and requires in some, I won't say specialized treating.The capacity there is, westbound able to add that a bit more slowly than we wanted

So that's our real hang up right now. As far as the well operations and the reservoir performance, from what we have seen so far it's gone pretty much like clock work.

Would there be any change in your out look for how the production ramps up for the year?

No, the next big jump probably will be in July or August when we get some surface aiming units installed. I expect later in the year we'll see another jump on there. Basically we started the year with zero production at Dinn Ranch and end the year as arising profile in the range of 50 million a day, I would hope, net production.

That's going to carry on in '03 where we think we might be able to pick it up further then.

If you look at our -- I think one logical question everybody out there would have is, gee, whiz, with all the U.S. gas production showing up for the public companies so far is disappointed. EOG is continuing to point out the 29 percent decline rate that everybody is fighting. How in the world is EOG going to grow their production through the year, particularly when we are really not making any substantial acquisitions or [M & A] activity?The rest of them will be relatively flat.The shallow well program in Calgary will be the driver up there.

What we want to do is give you some color as to why our profile is going to grow quarter to quarter when I think a lot of companies are going to have trouble doing that this year, with acquisitions.

Thanks.

Next question, gentlemen, comes from David Snow at Energy Equities.

Hi. I'm wondering if you could hazard a guess as to what brick count could hold the production level?

That's a tough one.

I meant for the industry.

Oh, for the industry. Whew, I'll tell you what. I'll scale it out for you. Last year we had an average recount of what was it, 900 or so. And production grew half of 1 percent. So I would say you would have to get a recount up at that level to have a chance at keeping production flat. My own assessment is, I'll give you a little more color on the gas side. I think everybody is forecasting a U.S. gas production decline in '02.

But I think when I really kind of becomes serious is as we enter '03.

Okay. And you mentioned CNG. Could you talk about the, whether it should be ammonia, LNG, or CNG or gas liquids? How do those all fit together?

Sure, David. To cap our Trinidad stores, the currents production we have down there, 110 million a day, we are selling a about a buck 20, buck 22 right now.

That all goes into the indigenous gas market down there. It's not really indexed to anything. It's just a contract that has a bit of an escalator on it. The next two trenches of gas will go to the ammonia plant one starting up this year and the Nitro 2000 starting up in early 05. Those will have prices that will have a floor of about 90 cents and then they may move upward depending on Caribbean ammonia prices.

We have more gas reserves than the contracts right now with our Parula discovery. What we are searching for is additional gas markets. And really there's about three choices in Trinidad. One is to go with the indigenous market which really ties you to methanol or ammonia likely.

The second choice there is to see if you can get into an LNG plant and we are pursuing that.

The third choice, which is kinds of the wildest one of the bunch, there are some conceptual thoughts out there and some companies who talked to us about literally CNG, compressed natural gas. You basically run the gas on to a ship and then the ship disembarks and heads for Henry hub and puts the gas there.

This would be a unique concept. But the point we would like to make, we would like to get our portfolio tied in more closely with Henry hub gas. We will be working very heart on the CNG and LNG side for incremental volumes on a going forward basis.

Would the CNG be more competitive than gassed liquids?

Yeah, we've -- in our opinion, yes. The gas to liquid, I think we still view that as a bit of an experiment. And we have not seriously considered any GTL kind of situation for our gas in Trinidad.

Too soon to tell, but the preliminary numbers we have seen indicate that, you know, we could get likely higher well head net back doing that at a 350 Henry hub price than we might in linking this to the ammonia market

That's why we are looking hard at it, David.

But not as high as if you went to LNG, I guess?

Yeah, right now that would probably be the priorities. LNG might be the highest net back. CNG second and tying it into the ammonia methanol market is third.

Is CNG dependent on being relatively closer to market, the longer you are, the farther you want to go with LNG, I suppose?.

Yes.

GTL doesn't enter into it until you see more of a performance?

Something of our scale, yes. There are some experiments going on worldwide right now, but I think the jury is still out whether that's going to be a competitive situation.

We go to John Herwin at Merrill Lynch.

Just a couple of questions. Most everything has been asked. Do you think with the Devonian market the potential is less than you previously thought?

No, John. What we've found in the Devonian play is that where we once thought we had 150,000 acres of relatively uniform tight carbonate, the more data we get, the more cores that we run dates there's a lot of heterogeneity in this reservoir. So the idea just without any 3-D seismic or anything kind of drilling blanket hundreds and hundreds of wells on here and getting kind of identical wells, probably was too simplified. What we find is it's more complex than that.

We are also finding the orientation of the laterals north south versus east west seems to make a difference in the recoverable reserves.

So I would still say that, you know, the overall resource assessment is as we had given previously. The complexity of this, which we probably should have expected, is higher than I would have, you know, been able to tell you three months ago.

Are you implying there's a structural over tone to this rather than primary sedimentary features or secondary features?

Yes, let me have Loren Leiker address that.

I think structural does play a role here, but a very minor recall. Perhaps augments fracturing, although fracturing has more to do with the generation stages than the structuring stage.

I think we still see this as a huge area of trapped gas with non-reservoir heterogeneity. The primary thing we are deal with now is how to get around vertical permeability problems. There are depositional things that add some complexity to the reservoir. But I think the most significant thing we are dealing with is how to complete the wells and hook up the reservoir through these vertical barriers. We plan to drill fairly wide step outs, 10-mile step outs to prove the point that it is a lower strata.

Are you drill under balanced? Or drilling with any sort of fluids acid eyeing?

It is an acidizing situation (inaudible) and crack height is the critical question right now.

We tried the under balanced on a well and that one didn't work. That was one of the experiments we tried.And on a cost per MCSE basis that appears to be the most effective right now.

There's still all kinds of questions, you know, which direction do you drill these? And how big of an acid job do you give? Kind of a lot of operational issues. That's why we've, you know, we basically have said this is going to be kind of a learning year. Next year will be kind of a program drilling year, we think.

Our next question comes from David Huykenan. He's at Hibernia South Coast Capital.

Not to completely beat the Devonian to death, but the first dual lateral recovered about 5 Bs at $3.6 million. Can you give us an idea of recovery in cost per year for your triple laterals?

Yes, David. The triple lateral, we're still drilling it. We are drilling the third lateral in right now.

It is going to be probably at least the next quarter before we have any real data on it. And likewise, we are drilling a second dual lateral right now and completing it.

Your cost expectations on the triple lateral are not done yet?

The cost on the triple lateral is about $4.2 million. Compared to the dual, 3.6.

Right.

The average lateral cost is going to be about $1.4 million.

Okay. And then you were looking forward you had a New Brunswick play, as well as a deep well in North Shafter. Could you talk about that, both of those?

Yeah, the New Brunswick play we are currently drilling and testing the wells. We drilled one well. We are in a completion mode on it. We just finished drilling a second well. We have one more well, a third well we will be drilling. And we are going very slowly on the completion.

At this stage, all we can say is that, you know, we've got the operations in hand, but we don't have any results to report yet.

Okay.

On North Shafter, really we don't have a lot more to report there. That's turned out to be 10 million-barrel accumulation and we are still doing some drilling on it. But we don't have a lot of experiments or ideas that we think are going to make it bigger than that on the going forward basis.

The deep test, are you going to drill that?

The deep test and north shafter will probably take one more set of that well to the deeper ridge. The bigger potential has more to do with down spacing in the 10 million-barrel net.

Okay, very good.

Next question comes from David Kahany. He's at [Freidman Billings Ramsey].

Hi, guys. Just a quick follow up on the CNG opportunity. Do you need an import terminal when you use CNG? Is that kind of the benefit? Operationally?

David, I guess the answer is no, you don't need an import terminal. Basically what you are doing, you're taking normal gas and you have a huge coiled tubing that is on a vessel and you put enough gas in there to pressure it up to 3,000 PSI and you sale the vessel from Trinidad to anywhere on the Gulf coast and basically you open up the valve and put it right into the gas pipeline.

It is fairly simple. What we say, there are a couple very reputable well-known companies marketing this idea to us. And we are looking at it real hard.

But one of the keys is clearly you have to be close to a market. And that's one advantage Trinidad has, it's not a long distance from there to the actual gas market.

Good.

No, no. This is just normal gas that's just pressured up. So there's no lick which if I indication or anything like that with it, David.

What is going on with Appalachia? We haven't heard much.

In Appalachia, we are still pursuing the black river flight.We are excited about the play.Although it's a widespread play it looks to be quite economic. It is not a big individual target. It's more occupying a space in one of our normal every day plays for Appalachia. We are excited about what we are finding in two other areas, one is normal shallow gas drilling. We have been drilling excellent wells in there.

Also, how are rig costs affecting you guys out there?

Rig costs are going down substantially. The average rig size that we use is a thousand ore spur. Mid 2001 the they ranged about $14,000 a day. Now they are down to about $8,000 a day. That's just somewhere around 20 to 30 percent of your overall well cost. So our well costs have come down somewhere in the ten to 20 percent, depending on the area.

Are you noticing anything -- I mean, you're hearing everywhere else that they are starting to tick up here. Are they going to tick up much on shore?

No, they haven't started to pick up much yet on shore.

Okay.

David, I think the key on that that Gary Thomas pointed out, is although the rig costs have swung kind of wildly, if we really assess total costs including fractures and fracture stimulation, pipe, so on, so forth, we are really down only about ten or 15 percent in total well cost from what we were dealing with on an average for a year ago.

So we haven't seen a huge drop in our costs to do business really.

KIRK MOELLER]: Good morning, ladies and gentlemen. Following up on the last question, could you guys talk a little bit about what costs you are seeing in other areas, what you kind of expect going forward?

In terms of drilling costs, Kirk?

KIRK MOELLER]: The costs besides the actual rigs themselves.

Yeah, those costs haven't fallen that much. We've got term deals, for example, on the fracs and for the logging of wells and things like that, most of the term deals we have are linked to gas prices. They are multi year deals.

we feel good about them if gas is 350 or $4, we will pay more for the services but proportionately we will have a net gain on that.

My sense of what is going to happen in the overall market is, we reached an inflection point in the rig count. I don't think it will fall anymore.

It may well end the year somewhere up around 800 or so. I think the one issue that we really have is how many prospects are out there for people to drill. I think one thing is, one theory is that last year most companies pretty well shot their inventory drilling anything that even looked like a prospect on a drilling frenzy. They don't have that much additional inventory.

That's why I think as we go through the rest of the year, EOG is going to look better perhaps than some of the other companies because we do have a good inventory and we will show that through arising production profile as we go through the year.

KIRK MOELLER]: It looks like your costs have fallen dramatically from a year ago or even a quarter, even from the middle of last year. They kind of appear to be this level for the rest of 2002. Is that reasonably accurate?.

What costs are you specifically referring to?

KIRK MOELLER]: Yes, yes.

I'm not sure I would say they have fallen dramatically. Our operating costs have fallen three or 4 cents, I believe, during that time frame. Our DD&A may be down a couple pennies, but I would say, you know, that's a conservative cost control effort.

Actually, this quarter over quarter.

KIRK MOELLER]: Right.

Actually, in our other cost structures we are up a little bit then.

KIRK MOELLER]: Okay, thank you very much.

We will now go to John Gertis. He is with Frost Securities.

Loren, back to the Devonian. You said with you were doing stage fracs on these horizontal Devonians. Are you using a prop or acid frac type process or how are you progressing with with that?

250,000-gallons. Also including some methanol with CO-2 to help to recover frac load rapidly.

Okay. And Mark, as far as, there's a theory out there that with these better gas prices we are going to see a shift in drilling patterns to more rate intensive projects.

John, I think we will certainly see an up tick in the drilling activity.I think we will see a shift back to that.

I almost say it doesn't matter. I think we are pre ordained to have production falling on a year-to-year comp in the second quarter, the third quarter and I believe even in the fourth quarter even if drilling activity were to pick up dramatically tomorrow.

And what I'm kind of questioning right now, if you go back to the last quarter, we predicted U.S. gas was going to fall three to 4 percent this year. We were kind of on the extreme end of most people's forecast. Most people were saying zero to 2 percent production decline. And what I'm beginning to wonder right now, has EOG even underestimated the effect of that 29 percent production decline? Right now the data is telling me the three to 4 percent production estimate decline this year may be conservative. I don't think it's going to change. If we are down, you know, five, 6 percent on the first quarter year-to-year comps, which is what it kind of looks like to me with the public companies reporting so far, it's not going to get any better throughout the rest of this year.

So I'm a bit concerned whether we as an industry have underestimated the impact of the 29 percent production decline that all of us in the industry are fighting. That's my soliloquy on that, John. Sorry it took so long.

No, that's helpful. We would agree. Thanks, Mark.

the final question of the morning comes from John Herwin, Merrill Lynch.

JOHN [HERWIN}: Hi, I didn't get to ask this before. How long or how far do you think if up run your program at Dinn Ranch.

That's a good question, John. Let me give you a little more color on Dinn Ranch. Out of the -- we basically have four wells right now that are drilled. And three of those four wells either are or will be completed in the deeper part of the pay that we found. But we found massive amounts of pay in two that have been drilled and we expect one that is currently drill we will find massive amounts of pay. Massive amounts being pay counts, big pay counts, 500 feet of pay.

And what we've completed in to get the 20, 25 million a day well capabilities is the bottom half of that way.

So first round of drilling here is to take the deeper horizons, but we know there are a lot of shallower horizons, generally between ten and 14,000 feet here. So the next trench of drilling once we get the deeper stuff will be to go back and drill for the shallower stuff.

My sense is we probably have at least an additional twelve months of drilling with probably two rigs in this area. That may stretch out, you know, 18 months or so of drilling.

So that's why I'm fairly confident we will have an ascending production profile throughout this year for this field and on into next year easily.

This is -- I don't want to give any estimate of field size now. But the analogous geological look alike to this is the Bob West field. Now, this one, the Bob West field was characterized by huge amounts of pay, 700 feet of pay or so, and a relatively small surface area where this pay was actually especially countered. That's what we have in ours. Only ours is smaller than Bob West. But I still think it's going to be a substantial field size.

My last question. With regard to potential legislation regarding income tax credits or drilling credits, you had 65 cents before. Where do you think the credits will shake out the at?

Let me kind of address that, John. This energy legislation that worked its way through the Senate recently. All of the noise on there was ANWR. Some noise about the possibility of tax credits for the Alaskan gas pipeline. The thing that didn't have any noise was the tax credits for unconventional gas, which would be coal bed methane, Devonian shale. And tight gas ends. They are in there right now in both the house and Senate versions. The Senate version is for wells that will be drilled in the future. The house version is basically a tax credit for existing wells that would fit those categories.And if EOG looks over our portfolio, we don't have a whole bunch of coal bed methane, but we have scads of tight gas. A lot of drilling we do in the whole company is tight gas. We would be a very significant beneficiary of the credit if indeed it, you know, it ultimately gets passed.

Thanks very much.

Mr. Papa, those conclude our question and answer session. I'll turn it back to you for any closing comments, sir.

Okay. I want to say thanks for everybody for staying with us on the conference call. We've got a consistent steady game plan and I feel very good about our game plan and think that the only thing that is kind of startled me a bit is that all the gas price recovery began three months earlier than we predicted it would happen, but the keys to me are EOG's production performance as we go through the rest of the year. I feel very, very good about that.I feel very good about where Henry hub prices are going to go for the next two, three, four, five years.

Thank you very much.

Thank you. That does conclude our conference call. We do appreciate your participation. At this time you may disconnect. Thank you.