EOG Resources Inc (EOG) 2003 Q1 法說會逐字稿

Good day, everyone. Welcome to the EOG Resources First Quarter 2003 Earnings Conference Call. This call is being recorded. At this time I would like to turn the call over to the chairman and CEO 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 announcing our first quarter 2003 earnings and cash flow results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings. We incorporate those by reference for this call.

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

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

We are off to a very good start in 2003. At the beginning of the year, we forecast free cash flow beyond our capex needs and stated that our goals for free cash flow utilization would be a dividend increase, debt pay down and share repurchases. During the quarter we accomplished these goals by raising the dividend 25 percent, paying down $101m of debt, and buying in 141,000 net shares. Additionally, we generated 5.3 percent overall absolute production growth over a year ago quarter. On a per share basis, the production growth was 6.3 percent.

As outlined in our press release, during the first quarter EOG reported net income available to common of $126.7 million, or $1.09 per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net income, EOG's first quarter adjusted net income was $144.9m, or $1.25 per share. The reconciliation of GAAP to non-GAAP adjusted net income 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, EOG's DCF available to common for the first quarter was $346.8m, or $2.98 per share. A reconciliation of non-GAAP DCF to net operating cash flows is found in our earnings press release, which is posted on our website.

Now I will address some of our operational highlights. We grew overall production 5.3 percent versus the year ago quarter. I will note that this absolute production growth is a what you see is what you get number. It is not pro forma, nor is it adjusted for sales.

We are pleased to note that of the companies reporting to date, we are one of only a few who have organically grown domestic gas production versus a year ago levels for the past two quarters. Our domestic gas production was sequentially down slightly from the previous quarter because of a previously contracted marketing arrangement whereby we processed more gas as NGLs.

As usual, our operational highlights reflect our decentralized organization. I will walk through some of these highlights. I will cover our North American operations from south to north, then I will discuss Trinidad and the U.K. For the past year we've had a low activity level in the shallow water Gulf of Mexico, but our success rate has been high. In fact, our last two exploration wells have been successful. Last quarter we mentioned our [South Timberleer 156] of 50bcfe discovery which is scheduled to come online this September. This quarter we made a discovery in our 60 percent working interest, MATAGORDA wildcat. This well encountered over 100 feet of data [sypay] and we expect to have this discovery online by the first quarter of 2004. This is a moderate discovery, likely 25bcfe to 40bcfe.

Regarding the deep water, we expect 160m barrel Tuscany prospect in the third quarter. We have a 37.5 percent carried interest in this wildcat. In South Texas, we are continuing our good success in both Roleta and Frio plays. We expect to drill approximately 60 net wells in this division this year. A recent Roleta well is 100 percent working interest, GARZA 24, flowing 9m a day currently.

In the mid-continent division, we recently hit several excellent wells at 6,500ft depth in the Panhandle area. The Jug 23 No. 1 and Rainman 23 No. 4 are currently flowing 8m and 4m a day respectively. We have 100 percent working interest in both wells and plan to drill 80 net wells this year.

Our West Texas horizontal Devonian play continues to yield good results. A typical example is the [Amaker] 99 No. 1H, currently producing 3m a day, and 300 barrels of condensate per day. The well cost was $2.6m and we have 100 percent working interest. We expect to drill 21 dual-horizontal Devonian wells this year.

In the Rockies, our two rig Utah [Masaverd] program is performing as expected and we plan to run at least two rigs through year end. In the Washakie Basin, we recently completed the Cepo Lewis 22 No. 18 for 7m a day from the Louis formation. We have a 70 percent working interest in this well.

Consistent with environmental restrictions, our Big Piney Wyoming drilling program will kick off in a few weeks and we expect to drill approximately 145 Rockies wells by year end.

In Canada, we are gearing up to drill at least 600 shallow gas wells this summer and fall, similar to our program for the past two years. We also have several new deep basin gas wells that have commenced sales at restricted rates due to processing plant limitations which are currently restricting us by about 10m cubic feet per day.

In Trinidad, year over year gas production increased 43 percent due to our mid-year 2002 start up of the CNC ammonia plant where we provide 100 percent of the gas supply. We continue to see a correlation between the North American gas story and our position in Trinidad through ammonia price indexing. We've noticed that Caribbean ammonia prices have risen sharply with North American gas prices. Since our gas supply contract is linked to ammonia prices, we've benefited and in March our well head price for the roughly 50m a day we supply to the plant was $1.58 per mcf.

Construction on the second ammonia plant, Nitro 2000, is on schedule and we expect to comment approximately 50m a day sales to this plant during the fourth quarter of 2004.

During the quarter, we sold down a portion of our equity interest in both ammonia plants and recaptured $6m which we can reinvest in upstream activities. We are also actively working on 80m to 120m cubic feet a day of additional gas contracts for either LNG or methanol and hope to report on those by October 1st.

We are currently shooting a new 3D seismic program over the 186,000 acres we added in 2002 and we plan to drill two wildcat wells on this acreage in the fourth quarter of this year.

Last quarter, we reported on our successful gas well in the U.K. North Sea, where we have a 25 percent working interest. We now expect this well to commence sales at a 25m a day net rate in the fourth quarter of 2004. Our second quarter 8-K production guidance released this morning shows that while we are on target to meet our annual production goals, our second quarter volumes will be down a bit due to three production interruption issues.

In Trinidad, we expect to experience a 12-day shut in during May for the repair of a third party's offshore condensate pipeline that we utilize. In Big Piney, we experience some pipeline curtailments due to scheduled compressor maintenance which is now complete, and in Canada we've had 10m a day of our Northern Alberta production recently crowded out of some processing plants.

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

Thanks, Mark. Total exploration and development capital expenditures in the first quarter of 2003 were $164.3m, which included $9.1m of U.S. acquisitions. Of course as we go along here, this program will step up with weather breaking up in the Rockies, so you should expect increased expenditures as we go forward.

Capitalized interest for the quarter was $2.1m. For 2003 we currently expect total capex excluding acquisitions to be between $825m and $950m. That was $825m to $950m which is up from our previous forecast of $800m to $950m. We have earmarked approximately $70m for acquisitions.

With respect to capital structure, as Mark mentioned at the beginning of the call during the quarter, we used the free cash flow generated beyond capital expenditures and dividend requirements to pay down debt. We reduced debt by $101m during the quarter. At March 31, 2003 total debt outstanding was approximately $1.044b so 10.44, and the debt to total capitalization ratio was 36 percent, down from 41 percent at year end 2002.

During the quarter, we repurchased shares to offset option exercises and reduce the number of shares outstanding. In the quarter we repurchased approximately 141,000 net shares. The quarter average basic shares outstanding were 114.4m, as compared to 115.5m in the first quarter of 2002.

The effective tax rate for the quarter, excluding the accumulative effects of the change in accounting principle was 35.3 percent and the deferred tax ratio was 67.8 percent.

The first quarter 10Q will be filed later today or early tomorrow. I will now turn it over to Mark to talk about the macro.

Thanks, Ed. I will now provide our thoughts on the North American gas macro and then discuss our hedge position. Our macro view hasn't changed much from our previous conference call. We expect first quarter domestic gas, year over year costs, for all public companies to be down over 2 percent and we think domestic production will decline 1 percent to 3 percent this year, assuming a continued drilling recovery increase.

We expect 2003 Canadian imports to be down about 8/10 of a bcf a day compared to 2002, partially offset by a 4/10 bcf a day LNG import increase. Additionally, we think exports to Mexico will be up about 2/10 bcf a day compared to last year. Given the current storage situation, we think an incremental 2 bcf a day will have to be priced out of the market between now and November 1st. Since we haven't seen any appreciable demand loss at the April $5.14 price, we expect prices higher than this will be necessary to get storage to 2.8 tcf by November 1st.

More importantly, we don't see any major supply changes in 2004, 2005 or 2006 that will significantly change this supply-challenged environment, so we are quite bullish on North American gas prices for at least the next several years.

Regarding hedging, we have 100m btu's a day hedged with financial price swap contracts for April to October at an average price of $4.80 and we have 125m btu's a day collared for April/December at ceiling prices sculpted by month but averaging about $5.32. In summary, approximately 23 percent of our April through December 2003 North American gas production is hedged at about $5.10. Note that we are only 15 percent hedged for November and December, since we expect to enter the heating season with a low level of storage gas.

Regarding oil, we are about 20 percent hedged for April through December at a $25.60 average price. We have no gas or oil hedges in place for 2004. There has been a recent effort on behalf of industrial consumers and operators to educate Washington on the importance of natural gas to our economy. The House of Representatives recently passed an energy bill with a number of items to stimulate industry activity. The bill includes the reintroduction of the section 29 type gas and unconventional fuels credit; a provision to support the Alaska Pipeline and provisions that would expedite drilling on federal lands. EOG would stand to benefit from the tight sands credit due to high level of tight sands directed drilling in our portfolio. The Senate is considering a similar bill. The earliest we could have a new energy bill would be this summer. This is something that we continue to monitor.

In summary, we are pleased with our first quarter performance and our base plan indicates that we will continue to reduce debt throughout the year. We are very pleased to have raised our dividend 25 percent with our third dividend increase in the last four years. We believe that with our high North American natural gas exposure, that we are in the sweet spot of a worldwide energy picture supplemented by a very attractive Trinidad position. We feel we've got excellent North American prospectivity for at least the remainder of this year, and expect to be ramping up our drilling program as the year progresses while still maintaining free cash flow.

Most importantly, however, we believe that the supply fundamentals for at least the next several years are bullish for North American gas and we intend to execute our game plan. Thanks for your attention, and now we will go to Q&A.

Thank you, Mr. Papa. (Operator Instructions) We'll take our first question from Shannon Nome with J.P. Morgan.

Thanks, good morning. Mark, you went through quickly a mention on second quarter volume guidance. I hadn't seen an 8K -- can you run through the three factors once more and what you are referring to there?

Yes, Shannon, good morning. We released the 8K this morning so it should be out there somewhere on the wire. The three factors in the second quarter that will impair us a bit on production volumes are, in Trinidad we have a 12 day shut-in of all our production down there for the repair of the condensate line. It is a third-party condensate line that has developed a kink in it, in fact I believe that shut-in is probably commencing today.

Also, in Canada, we've had some backup in throughput through some third-party plants in Northern Alberta that has kind of backed off of about 10m a day of our Canadian production. We hope by the end of the second quarter we'll have that cleaned up.

Also, we've had some production downtime due to compressor maintenance in Big Piney. So the bottom line is the second quarter will be a little bit shy of where our targets were but we are pretty confident we are going to make that up in the third and fourth quarters and close the year pretty strong, so we haven't modified at all our full year production goals.

Okay, and looking just a little further -- recognizing it's early, but in 2004 -- you have obviously had a nice boost from Trinidad this year and it looks like you will get that again in 2005, but without any major projects driving 2004, what projects are giving you some confidence you can sustain some growth out into next year? Which projects should we be focused on?

A couple of them we articulated on the conference call on the international side is, we've moved the schedule up for the Nitro 2000 Trinidad plant. We had been forecasting it would be the first quarter of 2005 that that would come online, we now believe we will be coming online in the fourth quarter of 2004. Also, our North Sea wells should be coming online in the fourth quarter of 2004. You put those two together, that is about 75m a day net.

From the prospect generation that we are seeing in North America, which, believe it or not, we are getting stronger as we go forward in that category. We continue to believe that we can grow our organic North American gas production and I think you will see in the third and fourth quarters, we've been ramping up which is going to give us a real good start as we go into 2004.

Right. Okay, great. Just one final thing. I missed the number for your gas side hedging position, April through December. What percentage did you say?

April through December our gas side is about 23 percent hedged at $5.10.

Thanks very much.

Thanks, Shannon.

We will take our next question from Irene Haas with Sanders Morris Harris.

Hi, Mark. I did actually look at the 8K and believe that I didn't see any guidance at all. Would you be able to at least give us what the gross volume for Q2 might be in bcfe and full year; then secondly, would you be able to tell us a little bit more about your Devonian horizontal program? My two questions are, what is the reserve per well looking like, and how many locations do you have? Thanks.

Irene, happy to do that. On the second quarter we said that, this is for natural gas, we gave a range of 620 to 650; for the full year 640 to 660; for Canada 150 to 170 for the second quarter, for the full year 155 to 175; for Trinidad for the second quarter 130 to 140, full year 140 to 160. So that gave you a total of 900 to 960 for the second quarter and full year 935 to 995.

Total crude, I won't break them out, was 20.4 to 22.2 for second quarter, and 21.7 to 23.8 for the full year. Net NGLs were 2.4 to 3.3 second quarter, and 2.2 to 3.8 for the full year.

On your second question there Irene, on the West Texas Devonian horizontal play, typical well costs out there are about $2.6m. We've reduced those costs over the last year from $4m down to $2.6m. The typical reserves we are generating out there per well are in the range of about 3.5bcfe and these wells produce gas with a fair amount of condensate with them too. That is why I am giving you the bcfe number there. Like I mentioned, I believe we are going to drill about 21 of those dual horizontal wells which is kind of equivalent to 42 wells, really, this year. Then, we have another at least 20 that we will probably be teeing up for next year and we are adding additional acreage, shooting some additional seismic.

I think we've got a program here where we are going to be able to continue this in 2004, 2005 and 2006 pretty well.

Sounds great, thanks.

Next we will hear from Ellen Hannan with Bear Stearns.

Good morning. I guess I am the third person to read the 8K and not find any guidance as well. Is there anything else that you thought was in there other than volumes, and should we look for any changes on the cost side on the second quarter for the full year?

We are checking to see why it's not -- it doesn't seem to be out there, but definitely it got posted. We don't know why it's not disseminated, so we are checking on that.

I can wait, if it is going to come out --

Basic bottom line is that we tweaked upward slightly, expenditures on the LOE and DD&A rate. Most particularly in the second quarter, but also for the full year as well. Quite frankly those simply reflect what we are seeing out there in terms of cost trends. One of the components on the LOE side is simply increased compressor utilization, and that should be driving all of us in the industry.

We also slightly increased our exploration dry hole and impairment ranges for the year and for the quarter. As I recall, those really were the key ones, in addition to the one I had already mentioned on the call. We slightly changed the capex range for the year. What had been 800 to 950 we changed to 825 to 950. Both those exclude acquisitions.

Bottom line, Ellen, is that nothing is substantially different from what we really let out as guidance a quarter ago, really. Just a couple little tweaks here and there.

One last question for you. When you are talking about ramping up activities throughout the year, can you talk about how many rigs you've got -- company operated rigs today versus what you think you'll be by the fourth quarter, and even just a little bit of colour on where your increased activity is likely going to be?

Right now we have about 35 rigs operating, and we plan to ramp up to the 45, maybe a max of 50. We just haven't done much yet in the Rocky Mountains, and also in Canada. We are going to be moving in rigs there in May and then in June in both of those divisions.

Thanks very much.

Our next question comes from David Khani with Friedman, Billings, Ramsey.

Hi guys. On Trinidad, what did you sell down your interest to on the ammonia plant?

Don't quote me on these exactly, but I believe we sold down -- we had in the ammonia plant running CNC, we've had about 15.1 percent equity interest, and I think it is down now to about 12.5 percent. On the second plant, the one that is under construction, the Nitro 2000, we sold down from roughly 30 to about 27 percent. We may, as time goes on -- what's happened with North American gas prices is these ammonia plants have clearly become worth more. So we are looking at our options regarding further sell downs or whether we want to decide to make ammonia a core holding of EOG. I'm being a little facetious there, but…

And did you sell it down to current owners?

No, we sold it to a new owner. Someone who has a lot of experience in the worldwide ammonia business. While we are commenting on Trinidad, I will just say in terms of the new markets there for specifically Atlantic LNG Train 4 which will come online in early 2006, there is also a very big methanol project that has been sanctioned by the government down there called M-5000 which will be online in late 2005. We are working very hard on capturing a portion of both of those markets. Things move somewhat slowly to get all the things tied up here, but I am really hopeful by October that we can report that we get somewhere between 80m and 120m a day of additional market captured for 15 to 20 years down there.

So clearly in terms of our position in Trinidad, I am extremely sanguine about not only where we are today but where we want to be two or three years from now.

Would you want to have any equity ownership in the methanol facility, or do you need to?

At this juncture, we are not looking at having any equity interest in either Atlantic LNG Train 4 or in the M-5000 plant.

And a quick question for Ed. What do you think your return on capital employed was for the first quarter?

Let us calculate it for you and we will get right back to you.

Alright. Thank you, guys.

Next we will hear from Shawn Reynolds with Petrie Partman.

Good morning. I am wondering if you can tell me where you think ammonia prices could drive realizations and trend data, how high you can get your prices?

Yes, Shawn. The contract, the base contract we have in Trinidad is for roughly about a floor price of roughly 90 cents to 95 cents and then it can escalate up with ammonia prices. I believe when we started the year in January we were in the range of about one dollar at the wellhead, and then by March it had ramped up to about $1.58 per mcf at the wellhead. Remember in Trinidad our DDNA rate is 26 cents. So this generates a very attractive after-tax rate of return.

Our best guess is that Caribbean ammonia prices of about $200 per metric tonne, which translates to about $1.60 gas prices, would be consistent with our outlook for North American gas for the next several years of in the range of $4.50 to $5.00, maybe higher than that, gas prices.

There is no limit in how high they could be driven?

No, there is no cap in our contract. I will mention that the contracts we are negotiating, if we can actually get them consummated for either LNG or methanol are again linked to the commodity prices. In the LNG case, the price would be linked to Henry Hub. In the methanol case, would be linked to some barometers of Caribbean methanol prices.

Right. So getting back to this 8K guidance, is there a new guidance for realizations on Trinidad prices?

Just the normal kind of -- I'd be happy to share them with you. We have put in the 1.15 to 1.25 range for both the quarter and the full year.

So you don't expect this March level to stay?

We are not forecasting that to happen. It is certainly a possibility.

That's a bit of conservatism. What we have, Shawn, is roughly 100m a day of the gas sales in Trinidad is under a contract that is basically a base price with a percentage escalator each year, so it is not linked to commodity prices. And then another 50m a day is linked to commodity prices. I would guess we'd be at the upper end or slightly above that range, but just a little inherent conservatism.

Right. And then, is there any other issues in regard to Canadian volumes, other than the facility constraints that you mentioned, the 10m a day? I kind of would have expected your activity levels up there would have driven a little higher.

No, what happens typically there is we don't start the shallow program until early summer up there. So we are just ramping that up now. Basically, I think our volumes are in line with expectations with the exception that we did have, like I said, the 10m a day that we couldn't get through the plant. There is nothing really different in the volume performance in Canada, or in the U.S., really, from what we'd expected.

Okay, great. Thank you.

Our next question comes from Delphi Management's Richard Friary.

Good morning. I was just looking at your release and I saw that production increased 5.3 percent in the first quarter. Is that all from the drill bit, or what percentage of that is from the drill bit?

Essentially all of it is. We've made very few acquisitions over the last year, just a few technical things. So basically it is all drill bit related.

And over time, do you think you can grow from the drill bit at that 5 percent or greater mark? I know in the near term you have a few issues, but over time.

Basically, what we have been telling people is that in North America on the gas side we expect that we can grow production in 2004 and 2005 in the range of 3 percent or 4 percent per year compounded. And then, the growth from Trinidad and the North Sea will be more step function growth. But over the next three or four years I expect that that is going to be at a much higher percent growth than the North American side.

But the key to us is really to maintain the North American gas focus and be one of the very, very few companies of our size that can grow production organically. What we are seeing out there now, particularly with some of our auto-drilling techniques is that the amount of prospects that are open to us in North America right now continue to increase. I think that is where we will distinguish ourselves over the next year or two. The heavy North American gas focus, particularly in times of potentially falling oil prices, and the ability to show some growth, albeit in single digit, in North America during that time without resorting to massive M&A's or massive property acquisitions.

Right. Are you going to continue to both buy back your stock and reduce debt with your free cash flow?

Yes, our base program this year indicates to us that we can buy-in some additional shares and also we can continue to pay down debt. In fact, you know, if you just work the math our debt pay down through the second, third and fourth quarters could continue to be pretty dramatic. It is not inconceivable that in the absence of some other major capital expenditure that we could end the year in the high 20s as far as debt to cap ratios.

Right, and do you have a goal for that debt to cap ratio, or do you just want to continue to reduce it as you can?

You know, we think that a rationale level is about 35 percent debt to cap ratio. It's not that we have any goal to drive it below 30 percent, but our main goal is just intelligent utilization of the capital. We are very cognizant that what we don't want to do is go chasing incremental production volumes and deteriorate our reinvestment rates of return. That is the reason we are not signalling to you that in spite of our bullishness on North American gas prices we are not, at this point, talking about raising our overall capital expenditures for the year.

Thank you very much.

Okay.

Now we will hear from Ken Beer with Johnson Rice & Co.

Hi. Let me just follow up on that, guys. Good morning. Just as you go from let's say up to 35 rigs to the 45 or 50 rigs, do you anticipate that you will have to start to step up the ladder a little bit on the cost side? It seems like enough companies are thinking that they will tweak it a little bit upwards, and as that occurs do you anticipate, and in fact have you added and projected further increases in your drilling and general surface costs as you go to the second half or the back half of the year?

Good morning, Ken. The answer to the question is that the stepped up drilling program through the year is already calculated into our estimated capex for the year. So if we didn't step up the program our capex would be less than what we are projecting. If you look at our first quarter capex levels, I believe it was $164m, obviously that is lower than taking the full year guidance. We are actually starting off the year a bit slowly.

A lot of that is due to just environmental restrictions in the Rockies. In Big Pine Wyoming we are not allowed to drill any wells until late May. Then we have to drill a whole bunch of wells between May and December. We have some similar things in also Utah and other places. So that is kind of what drives our drilling schedule.

As far as the overall costs for wells, what we are seeing right now is that you see the drilling rig count is now up to, I believe, 825 gas rigs and we are seeing some increases, I will call them tepid increases, in drilling rig day rates. But the issue there is drilling rig day rates only count for maybe 17 percent of our total oil costs, and the increase in the drilling rig day rates has actually been offset by decreases in our pumping service cost, primarily hydraulic fracturing.

So at this juncture, our average costs per well is looking to be just a smidgen down from what the average completed well cost was a year ago from an identical well. We do expect that our best guess is that the gas directed rig count will close the year at about 1,000 gas rigs and there will probably be some upward pressure on the drilling rig side as far as rates.

For the big cost components, we've got most of those pretty well locked in for the year, so we are not anticipating any real runaway service costs that are going to affect debts for year end.

One more technical question. You said in the first quarter you had actually pulled out a fair amount of liquids because of a contract. As you look ahead to the second quarter, are we going to see that the liquid volumes go down so you will keep the btu's and the gas stream with the higher gas prices? What is up there? And how much volumes might that be?

The numbers that swung were something like about 800 to 1,000 bpd of NGLs. If you look at our fourth quarter U.S. NGLs versus our first quarter, I think the NGLs were up by about 800 to 1,000. It is not 6m a day that swings. We had a contractual commitment in the first quarter where we had to run those through as NGLs. We have now gotten that contractual commitment out of the way, so we will just make a decision each month to either run it as gas or NGLs and for the month of May, we are going to run that as gas.

Okay. So you'd expect to see more of those btu's in the gas stream.

Yes.

Okay, that's great. Thank you, guys.

Okay, Ken.

We will move on to Andrew Lees with RBC Capital Markets.

Hi guys. A quick question. G&A for the quarter, $20m, was below your $22m to $26m range. Can we expect that to continue?

The reason for the decrease was in professional services versus our previous forecast, which quite frankly was very, very difficult to forecast, as you know. We are really not forecasting any dramatic change in G&A for the year as a whole.

Okay, thanks.

John Gerties with Southwest Securities has our next question.

Good morning. Hi Mark. As far as financial weather, just go back to that for a moment. You guys are 5 percent to 6 percent the peers, large cap peers, both on a book basis and a market basis. Why even bother to buy in any more debt, why not just purely stay to equity?

That is kind of a theoretical question that we get quite a bit. I would say right now that we look at this continually but at this juncture we would like to end up with a low debt level. We mentioned in the past that ultimately over the next year we would like to add one more international branch of activity. So some of that we can drill our way into that as we are doing in the U.K. North Sea, or we can perhaps buy a producing asset there.

So we are looking at the possibility of, should we attempt to make an acquisition, either in North America or to get us in another international position. So we just like to keep our powder dry in terms of the debt level in case that opportunity really would manifest itself.

Okay, that's logical. You sounded 2,800 'B's for November 1st as kind of a bogey for gas in storage. Give us a couple thoughts as to why you see that as the bogey? Obviously a few years ago we experienced a 2,750 figure.

You know, the 2,750 I believe is the lowest figure we've had in a decade.

Correct.

My best guess is that the LBCs will indeed get gas filled to about 2.8tcs, mainly because that is their job.

Right.

Whether it costs the LBCs $3.00 this summer for gas or $13.00 this summer for gas it is my belief that they will indeed get gas storage filled to at least that level.

I also think that on a pragmatic basis that is pretty much the max, max, max level under any circumstances that we could get gas filled to. You know, my best guess is that May prices, as we know, are a little bit above $5.00. We may see June at that Johne level, and then as we get into July, August, September and October I think, particularly if the injections are lagging, I think that we could see gas prices higher than that. A little bit of that would depend on the hot or cold summer.

Then, as we get into winter, obviously last winter we started at about 3.2 in storage and we came pretty close to being highly stressed in March. So if we start at 2.8 in season storage I think that we are going to be on a bit of a razor's edge through the winter unless we experience a much hotter than average winter.

That is my short-term forecast as to what is going to happen to gas prices. I would really lay out to you, in the 2004, 2005, 2006 and 2007 timeframe, when you look on the supply side I just don't see anything different out there. There were no massive discoveries that came online. The NMS is projecting that the deep waters off of Mexico production, in terms of natural gas, is actually going to decline in 2004 and 2005 versus 2003, so that is not going to bail us out.

I think that the shelf will continue to be stressed. My best guess is the futures markets. You are looking right now at a five-year strip in the futures market of $4.71. I believe that is a rational representation of what we may see in the next five years. As we've talked to, gone out on investor relations visits with buy siders, I think there is some cynicism that this year is a repeat of 2001 whereby we had very high gas prices at the beginning of the year and then they dropped to $1.80 by October. I can tell you, I just don't see that out there for three key reasons.

Number 1 is two years ago you had 52bcf a day of deliverability in North America, and by year end this year you are going to have 48.5bcf a day. Number 2 is, for the first time in 19 years Canadian production is going to fall this year versus the previous year. Reason 3 is, Mexico is a significant and I think a very real and consistent importer of gas from the U.S. for the next five years.

With a mild offset obviously being going to LNG, but somewhat mild in that respect.

I think, you know, LNG is currently about 1.5 percent of total U.S. demand and that will double over the next two years. The next step function change will really be in 2007 or later when we get some new green field terminals built.

Those comments are all helpful. Let me shift quickly to operational. You are doing quite a bit more work in the Frio this year. How are those wells shaking out, cost reserve wise?

Gary, you want to answer that?

Yes, in the Frio we're still very active there. We got about a dozen wells drilled in our airport prospect and we've had about 24bcf there. That is $1.25 mining cost. We are going to continue that activity and probably have another 12 wells to drill there this year.

Great. Thank you, guys.

We will now hear from Simon and Co.'s Mark Meyer.

Good morning. A couple of questions. Ed, could you quantify what the sliding scale royalty impact was in Q1 and kind of compare that to what you are thinking for Q2, less the $10m you talked about having backed out.

I don't know if we can give you a quantification on that, Mark. We'll have to follow up with you. It's obviously hurt us a little bit on net after royalty volumes, but I'd say it's not significant enough where we've noted it as a major issue.

Okay, I will follow up. A second question for you, Mark. Just your current thoughts as it relates to the Barnett shale. There has been I think a shift in activity, a little bit more focused on horizontals by some of your competitors, maybe some new entrants ramping up there. Any kind of go-forward thoughts here that you have on the Barnett?

Let me have Loren Leiker address that, Mark.

Mark, we are quite bullish on what we see going on in the Barnett right now. We have drilled a couple of wells there and are in the process of fitting those wells we put together about 50,000 acres south of the city of Fort Worth where, in years past, people thought would be a geological challenge. We are encouraged by what we are seeing. I think the other operators that you mentioned, both vertical and horizontal, are drilling on all sides of us and having some success. So we feel good about our 50,000 and after this testing program we hope to keep drilling wells and keep adding acreage.

Loren, were both of those wells verticals?

Yes they were.

Okay, and when do you think you will have something to say on those?

You know, the testing program will be going on over the next month or two here, and we continue to plan to drill more wells there, probably starting in June.

Probably by next quarter's conference call we will have some specifics and by then we may have one horizontal under our belt, but our best guess is right now is that we are quite hopeful that a significant part, maybe all, of this 50,000 net acres that we have leased is indeed productive in the Barnett, but that is based on early time data from the two wells that we have.

Thanks a lot.

Brad Beago with Credit Lyonnais Securities has the next question.

Good morning. Brad Beago calling. Mark, I'm thinking about the dichotomy between your outlook for gas and relatively modest capex budget in light of your free cash flow and a strong balance sheet. You've touched on a couple of the issues, I guess primarily your desire not to run up costs and hurt your rate of return, although in $5.00 gas the rate of return is astronomical.

But, would it be -- I have two questions, really. Would it be possible for you to push your North American production growth up above 5 percent by spending your free cash flow? Or, operationally do you feel like you are kind of at the limits of what your people can do?

That is a good question, Brad. It is a dichotomy and you are seeing it among a lot of our peer companies too. Another dichotomy is I think you hear most of the companies say, wow, we have a lot of prospects but the industry is short of prospects. I believe that EOG, that is what we are, a on-the-ground, in-house prospecting team. I think that we are one of the few that has a pretty good inventory of prospects.

My best guess is that were we to ramp up and say, let's just spend an incremental $300m, for example, in North America this year on drilling more wells, is that we would probably get a bit ahead of ourselves and end up doing some things that in retrospect probably weren't cost efficient. I would say that we intend to continue a rational program.

What's happened, and this is maybe a little bit understated, is that the difficulty of getting wells drilled kind of increases every year. One from permitting, two is just the amount of complexity in that most of the wells we drill now are related to 3D and a lot of them are in unusual reservoirs whereby you need to drill maybe four or five wells in there and try different simulations before you go launching into a 50 well program.

So you know, the plan of attack we would have is even if gas prices were to go to $7.00 or $8.00 this summer, I don't think you'd see us dramatically ramp up our activity level this year, mainly because we would get, to use a euphemism, we might get a little bit out of control; we'd end up doing some things that either were technically incorrect or just didn't make the best sense for rate of returns. So hopefully that kind of gives you an answer, Brad.

Well I think that gives a lot of things to think about. That kind of links to the next question, which is of course M&A. Either strategically in and around where you are operating, or larger type corporate M&A deals, certainly valuations don't reflect your outlook, and you've got the horsepower to do it.

Yeah, and in the capital estimate there and in the 8K that we're providing, we are kind of allocating about $70m this year for what we call tactical asset acquisitions in North America, and I think in the first quarter we did only about $9m.

You know, I go back to some of the share price performance, and we've analyzed EOG's share price performance over a three, five and ten year time horizon versus our peer companies, and we look quite good in all three of those horizons, clearly. And, when you compare that to some of the share price performance on companies that have gone more the M&A route, I think there is a distinct difference that institutional investors are making and so I would continue to say that our growth will likely be pretty steady but non-spectacular in North America, supplemented by some producing property acquisitions from time to time. I think the growth will be rather spectacular in Trinidad and then hopefully we can add one more international asset. That would get us, at that point, to where I'd say I would feel extremely comfortable about the company, whereby we'd have a decent overall production growth rate and still have pretty good capital discipline.

You know, we're guided a lot by what shareholders have said in terms of share price appreciation over the past three to ten years in terms of strategies, and I think if anybody were to look at that it would become pretty clear which strategy institutional investors seem to like. They are the ones that don't cause you to match the goodwill on the balance sheet, they are the ones that don't cause billion dollar write-offs every two to three years, and that is kind of the strategy we will likely stick to, Brad.

Okay, well thanks. Mark, good job. At the end of the day, you are certainly in the top two or three in terms of valuation in the group, so your formula is working. Good luck and thanks.

Thanks, Brad.

Next we will hear from David Heikkinen with Hibernia Southcoast Capital.

Good morning. A lot of the questions were asked, but I wanted to go through exploration exposure. Really back-half weighted, most of the year carried on head notes of [Merna] and North Sea. Any updates on those? Any changes?

What I'd say on Tuscany is that we are encouraged by the way the permitting process is going and we do expect that to drill this year. Hopefully in the third quarter, possibly the fourth. As you know, we have to carry working interest. It is a very large prospect and we hope for good things from it. On [Merna], we are still -- we acquired a brand new [tribial] with that prospect. It is still in processing, we are doing some pretty high-end processing, partly because they are having a couple of wells drilled on sort of the step-out end of that structure that are not particularly encouraging, so we would like to see this 3D before we really convince ourselves that that is what we hope it is and what we think it is in terms of permeability.

In the North Sea, we have drilled two so far and we are one for two, as Mark mentioned. We are currently screening a number of farm ends and different types of entry potential opportunities in the gas production primarily, and very encouraged by what we are seeing. We will ramp that up later this year and next year.

And for exploration expense, should I weight it some to the third and fourth quarters just because of activity levels? What do you think?

That is probably a fair assumption. We do have a couple of big wildcats coming and it will probably fall in the second half.

Okay.

David, the other couple items that hopefully will be meaningful and we will likely get in before the end of the year, we've got a hot potential well in the Canadian foothills area, probably in the third or fourth quarter we expect to drill. We are going through the environmental permitting process on that. Then, in Trinidad we've got two exploration wells that will likely occur in the fourth quarter. In rough potential, each of those is roughly maybe about 100 to a 300 bcf prospect. We are hopeful that by year end we might have some reserve heads coming from some of these, anyway.

The foothills are the 200 to 300 bcf prospect, or just Trinidad?

Foothills is about 100 to 150 bcf prospect, yeah.

Thanks a lot.

I might jump in there to Dave's question with respect to the return on capital employed in the quarter. It was about 4.9 percent. That would need to be annualized if we were so fortunate to continue the Johne earnings rate, which obviously is something closer to 20 percent. So we obviously had an excellent return in the quarter.

Also with respect to those of you looking for the 8K guidance, to the best of our knowledge it still hasn't come across. It has been accepted by the SEC, we are told that they are implementing some kind of new release system today, and so actually we thought ours had gotten in there prior to that and out, but they are putting in some kind of new system or something, so there is a backlog. I am sure it will pop out shortly. It hasn't come out, I don't believe yet.

We will take our next question from Jeff Mobley with Rades.

Good morning. Brad and David asked most of my questions. One step further on the capex spending increase, you had some level of reluctance in progressing too fast in order to protect economics. But if you have a more favourable gas price environment, wouldn't that offset some of that? Then also, the follow up to David's question, has there been any new information off one of your competitor's wells in [Merna]. Did they give you particular encouragement on the play?

Yes, Jeff. In answer to the second question there in [Merna], we don't have any information relating to that well. I think it is being kept as a tight hold on there, but then hasn't been any offset drilling activities to our knowledge from that well, so I am not sure what that means. Like I said, we are going to wait until we get a 3D seismic survey in and make a call on [Merna], probably in the third or fourth quarter on where and if we drill a well.

In terms of the capex issue and ramping up activity level, from the tone of the questions two or three of you are almost like a district attorney -- you want me to say, "hell, we are going to ramp up." I would just add, to the extent we feel it is necessary to use capital to ramp up the activity in light of our bullish gas price outlook, we will do so but typically what happens is either we have some technical questions to overcome.

Let me just give you a typical example. I will just use the Bonehedge Trail as an example here, although it applies to a lot of different places. Yes, we drill and we have some gas test wells. One way to look at it would be to say, "gee whiz, it looks like gas, go down there and drill 40 or 50 wells between now and the end of the year." But the problem is we don't have any good [inaudible] so another way to do it would be to say, let's not get focused on production, let's watch them for a few months, let's do some tests on them and then just slowly gear up. We would be more likely to use that latter method. That's the kind of decision we are faced with in most of our plays. It is not -- another issue is in the [Messaverd] play in Utah, we've got it pretty well-defined, the issue there is just getting permits. It's Indian land. It's not a case where we can say, "wow, let's go run 8 rigs on this."

So when you put all the operations in there, it tends to say it is not all that likely that when the drilling starts we are going to spend more than what we are currently telling you for the year.

Thank you very much.

That is all the time we have for questions. I will turn the call over to Mr. Papa for closing remarks.

I want to thank everyone for staying with us on the call. I can say this is a wonderful to be a North American gas based company. So thank you very much.