EOG Resources Inc (EOG) 2003 Q2 法說會逐字稿

Good day, everyone. Welcome to the EOG Resources Second 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 second 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 our investor relations page of our website.

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

Our second quarter actual results were very much in line with the 8K guidance we provided in May, and yesterday we filed an 8K with guidance for the third quarter and full year. Full year production estimates remain in line with the May guidance we provided.

As we stated earlier, our 2003 North American production growth is second-half loaded, and I will walk you through some of the projects that will come online prior to year end.

Relating to net income, as outlined in our press release, during the second quarter EOG reported net income available to common of $106m, or 91 cents per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net income, EOG’s second quarter adjusted net income was $109m, or 94 cents per share. The reconciliation of GAAP to non-GAAP adjusted net income available to common is found in our earnings press release which is posted on our web site.

Relating to cash flow, 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 second quarter was $304.4m, or $2.62 per share. The reconciliation of non-GAAP DCF to net operating cash flows is found in our earnings press release which is posted on our web site.

Now let me move into the operations discussion, but before I move into this discussion I want to talk more broadly about EOG strategy and the current North American operating environment. Our strategy has three components. The first is to continue to achieve a strong rate of return on all capital investments, thereby generating high ROEs and ROCEs, where we have historically been the industry leader.

Our second strategy is to stay heavily focused on North American gas, because we feel this would be the sweet spot of the worldwide energy picture for at least the next five years.

A third strategy is to expand our Trinidad operations and to conservatively make some North Sea drilling investments. I will provide some color on this in a minute. Regarding North American gas, we have a three-pronged approach. Number one, we will continue to heavily concentrate on our singles and doubles strategy, i.e. drill a lot of moderate rate and reserve wells.

Number two, we will make several bigger target drilling deals into the inventory each year, and I will provide some specifics on this later.

Number three, we are continuing to look for property acquisitions that contain upside drilling potential.

We are seeing some interesting developments in the North American gas operating environment. Surprisingly, our opportunity set is increasing and competition for new acreage and drilling deals in many areas is not commensurate with $4.70 gas.

We are also securing multi-well drilling farms in from majors which simply weren’t available in previous years. Additionally, service costs are relatively flat and we expect full year completed well costs to be ranging from flat to up no more than 5 percent relative to last year.

Against this backdrop, our second quarter volumes were inline with our 8K guidance and we expect full year volumes to be in line with the guidance we provided earlier. 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 year ago levels for the past three quarters.

We expect our third quarter North American volumes to ramp up from the second quarter and significantly ramp up in the fourth quarter. We average 32 North American drilling rigs in the first half of the year, and expect to average 50 rigs in the second half.

I will now walk through some of our operational highlights from our divisions. In South Texas, we are very excited about our charcoal field Roletta results. The [RO-Gutier]’s no. 1 well is currently producing 10m a day. A second well in encountered similar pay and is currently completing. We have 12 additional wells to drill, six of which will be drilled by year end.

We have 100 percent working interest in this play. The typical well cost is $1.7m and net reserves are 2bcf per well. Our South Texas Wilcox program is also generating good results. Our [Din Ranch] Lopez Mineral Trust no. 3 well was recently completed for 10m a day. We have a 50 percent interest in this well.

In West Texas, we currently have five rigs drilling horizontal Devonian wells. Two recent wells are the Blue Topaz 102 No. 1H and the Windham 108 no. 2H. These wells are floating 4m and 6m cubic feet a day and 350 and 600 barrels of commentate respectively. We have 100 percent and 96 percent working interest respectively in these wells.

Typical well costs are $2.2m for 2.4bcfe net reserves. We plan to keep five rigs running in this horizontal Devonian play through year end.

In the mid-continent division, we are using 10 rigs to drill our bread and butter, 7,000 foot deep cubic scenario. Additionally, we made a very successful 75 percent working interest, 12,000 foot [motor] well. The Alexander 467 No. 2R, which is currently producing 20m cfd gross.

In the Gulf of Mexico, we expect first production from our South Tibilier 156 discovery to commence at a 9m a day net rate during October. This was the fourth quarter of 2002 discovery where we operate and have a 50 percent working interest.

Additionally, we expect that our Madagor 2685 discovery announced last quarter will commence sales in the first quarter of 2004.

In the Rockies, our Utah [Masavero] program is generating the expected results, but we’ve been limited to a one-rig development program because of permitting issues on Indian lands. Our standard Big Piney Wyoming program is progressing as expected. Additionally, we recently closed the 70,000 acre Wyoming farm in from a major, whereby we can drill down space frontier gas wells. We will start out with a 30 well program which, if technically successful, will expand to 150 wells. This provides us a new Rocky Mountain production growth platform.

In Canada, our shallow gas drilling program is in full operation and we are running six rigs. We expect to drill roughly 1,000 wells this year with almost all competed by September 30. We expect a significant fourth quarter production increase as these wells are brought online.

In Trinidad, the gas market supply and demand dynamics have changed during the past year. We have seen an evolution from a market that has been long on gas supply but short on gas demand, to a market that is now in relative supply from a supply and demand viewpoint, with LNG commitments absorbing previous excess supply.

We mentioned on our May call that we were actively pursuing new gas markets and we said we expect to finalize an incremental sales contract by October 1. We are still on track to meet that deadline.

From a strategy viewpoint, we plan to increase our Trinidad exploration activity based on our confidence of securing markets. We will pick up the rig in September and plan to keep that rig until mid-2004, drilling our inventory of 3D prospects.

During the past year, we have more than doubled our Trinidad acreage position and during the first half of this year we shot new 3D seismic over this acreage. We view Trinidad as a core piece of our portfolio generating a good rate of return.

Our goal in the second half of this year is to have successful drilling results from two exploration wells and to finalize agreements that secure new gas markets.

In terms of other international areas, our plan is to cautiously drill our way into new areas, rather than produce the M&A approach. We continue to be interested in the U.K. North Sea and will likely drill one or two more farm in wells before year end.

I will now address our inventory of what we call our bigger target ideas. We currently have five bigger target opportunities that are on our immediate plate, which if successful could change the profile of EOG. Three of these ideas are onshore domestic exploration prospects. One involves deep water Gulf of Mexico exploration, and one involves Trinidad exploration. All five of these should be decisioned by year end.

The first of these is the deep water Gulf of Mexico Tuscany exploration prospect. This well is expected to spud within a month and should be decisioned by December. This is a 215m barrel gross oil equivalent prospect that we internally generated and purchased at lease sell 181. The water depth is 7,000 feet and we carry 37.5 percent working interest.

I’ll note that this is a one-of prospect and does not signal an EOG strategy change toward the deep water.

Our second big target idea are two Trinidad exploration wells we’ll drill before year end. These are 150 and 250 bcf prospects where we will have 95 percent and 55 percent working interest.

The last three are more EOG mainstream exploitation projects in the onshore U.S. that would involve drilling hundreds of wells. Two of these are tight gas plays in traditional areas where we’ve recently drilled multiple successful wells, kept the results confidential and are currently expanding our acreage position without much competition. We’ll provide more details on these before year end.

The final big target play involves expanding the Barnett Shale play to the south of the City of Fort Worth. We have been accreting acreage in this play for three years, and at 70,000 net acres are currently the second-largest acreage holder in the play. We are currently drilling our first two horizontal wells in Johnson County and we expect to have five horizontal wells drilled and connected to sales by year end.

Competitors have recently drilled successful horizontal and vertical wells, offsetting our acreage, and if this play extension works will obviously have a lot of 2004 plus development drilling. I will note that these big target opportunities do not require a disproportionate amount of capital to prove or disprove the play. This fits with our mantra of identifying cheap big target opportunities that are all internally generated.

For example, the Tuscany prospect will be drilled at no cost to us. In the Barnett Shell our cost to acquire 70,000 acres was $6m, which is quite attractive for the very large reserve potential. I will now turn it over to Ed Segner to review capex and capital structure.

Thanks, Mark. On the capital expenditure side, total exploration and development capital expenditures during the second quarter were $212.6m, including $9m of acquisitions. Year to date, total exploration and development capital expenditures were $374.7m, including $18.2m of acquisitions.

Capitalized interest for the quarter was $2.1m. Year to date it was $4.2m. We’ve increased the midpoint of our 2003 capital expenditure budget by $75m, and now expect total capital expenditures excluding acquisitions to be between $925m and $1b.

The increase in capex is designed to fund our increased level of activity that Mark walked you through just a few minutes ago. On the capital structure side, during the second quarter we used the free cash flow generated beyond capital expenditure and dividend requirements to pay down debt. We’ve paid down $33m of debt during the quarter and $134m year to date. At June 30, we also had $151m of cash on the balance sheet.

In 2003, we have funded our drilling program and further strengthened our balance sheet with cash generated from operations. At June 30, 2003 total debt outstanding was approximately $1.011b. The debt to total cap ratio was 33.8 percent, down from 40.6 percent at year end 2002.

For those that prefer to do the theoretical computation of reducing debt outstanding by cash and cash equivalents, and then divide by total capitalization, the resulting computation would be 30 percent at June 30. Investors should keep in mind that some of the cash is offshore and may not be fully available to pay down debt. And that the company may use some of the cash for future acquisitions or drilling opportunities.

The effective tax rate for the quarter was 34.4 percent and the deferred tax ratio was 51.9 percent. The unusually low severance tax rate as a percent of revenues during the quarter was the result of an aggregate by-link for eligible tax incentives for Texas high cost wells, which offset the increased lease and well costs which was up partially due to the unfavorable movement in the Canadian exchange rate and primarily due to increased activity levels including compression costs to take advantage of the higher commodity price environment.

The second quarter 10Q will be filed later this week. Now I will turn it back to Mark to talk about the macro gas environment.

Thanks, Ed. I will now provide our thoughts on the North American gas macro and then discuss our hedge position. In spite of short-term fluctuations in storage, the long-term supply constraint fundamentals remain in place. We expect second quarter domestic gas year over year comps for all public companies to be down about 2 percent and we think domestic production will decline 1 percent to 3 percent this year, even with a continued drilling recovery.

We expect 2003 Canadian imports to be down about sixth-tenths of a bcf a day, compared to 2002. This may be exacerbated by the recent Alberta Energy Board announcement to shut in $250m a day of gas in September.

These declines are partially offset by a seven-tenths bcf a day increase in LNG imports. Additionally, Mexico has increased their imports from the U.S. and we think August imports will average 1.0 to 1.2 bcf a day, indicating there is not a lot of price sensitivity relating to northern Mexican demand.

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 remain bullish on North American gas.

Regarding hedging, we have an average of $80m btu’s per day hedged with financial swap contracts for July through October at an average price of $4.54. We have 125m btu's a day collared for July through December at ceiling prices sculpted by month but averaging $5.35.

In summary, approximately 21 percent of our July through December 2003 North American gas production is hedged or collared.

Regarding oil, we are about 22 percent hedged for July through December at a $25.11 average price. We have no gas or oil hedges in place for 2004.

In summary, we like what we see in the current North American opportunity environment. Service costs are relatively flat, competition is lower than expected and we’ve begun securing some large drilling farm-ins from majors. The next five months at EOG should be very exciting as we continue our singles and doubles strategy as well as the bigger target ideas.

We are pleased that our earlier 8K production guidance remains intact and we plan to issue 2004, 2005 and 2006 production guidance at our September 23rd Houston Analysts meeting.

Last quarter we raised the dividend 25 percent and will continue to operate in a shareholder friendly rate of return focused manner. Thanks for listening in, and now we will go to Q&A. Steven.

Thank you, sir. (Operator instructions) Our first question today will come from Argen Mertis with Goldman Sachs.

Thank you. I just wanted to follow up on your comments regarding the Wyoming play and some of these acreage farm-in opportunities from the majors. Is it possible at all to give a sense of how scalable these types of opportunities are? You mentioned Wyoming 30 to potentially 150 wells. I know the majors can sometimes be indecisive and not always as fast-moving as you may like, but can we think about adding a few of this opportunities? Are there five or seven? Is there anyway to give an order of magnitude of how many types of these opportunities you think are out there beyond this play?

Yes, Argen. What we can say about the Wyoming one is we are going to initially drill about 30 wells, down-space frontier wells. We believe, based on our technical analysis that ultimately 150 or more of the wells will be likely drilled on this acreage for us.

The arbitrage for us in the majors here is that our completed well costs are lower than what the major believes that he or she can do. So what we’ve got there is a situation that is win-win I think, for both the major and us in that we will get a decent rate of return commensurate very similar to what we would get on normal kind of activities.

For the farm-in, we don’t have any acreage costs nor do we have any seismic costs and basically what happens is we’ll pay 100 percent of the cost and then we will share, after pay out, the revenue between us and the majors. So the majors rate of return is basically infinite.

We have several more of these cooking. I believe that before the year is out we will land several of them that will give us for 2004 in the range of I would say between 100 and 400 incremental wells to drill on acreage that we could never access in the past.

That scales out roughly, we will drill this well, this year, about 2,000 wells so it is a significant amount of potential increase in the North American gas activity that we can see and expect to see in 2004 and 2005.

Mark, that is very helpful. I know you guys have always prided yourselves on sort of, you’ve got the consistent singles and doubles strategy in your core areas and you’ve always thought there is a certain pace to that kind of activity which is why you have not wanted to crank up activity in your existing areas. It sounds like this type of opportunity would be incremental so the types of higher capital programs you are displaying this year, without wanting to preempt your September guidance, it looks like there is a lot of momentum to continue at those higher levels, if you can continue to secure these types of opportunities. Is that fair?

Yes, I think that is a fair statement, Argen. Like you say, we don’t want to preempt the guidance that we will give in September, but we are pretty optimistic about what our likely production growth rates are going to be for the next three years, and more importantly we feel that whatever growth rates we achieve we will achieve without issuing any paper, also.

That is very helpful. Thank you.

Our next question today is from Mr. John Wolffe, representing Wachovia Securities.

I am wondering if you could give us a little more detail on what you are projecting in the Barnett Shale in terms of potential reserves per well costs, productivity. Secondly, could you tell us what basin in Wyoming that we are talking about with the majors?

Yes, John, on the second question there, the basin in Wyoming, I would prefer just to not say other than to say it is a very proven hydrocarbon basis and Wyoming and the reason is that we don’t really want to go bragging or mentioning counter parties in these things. We’ve got ongoing discussions and there is no real benefit that we would see to do that.

On the Barnett Shale question, let me ask Loren Leiker, our EVP of exploration and development, to give you a little bit of color on the Barnett Shale.

John, as you probably know, the 70,000 acres that Mark mentioned earlier is primarily in Johnson County, south of Fort Worth. From what we see today, the thickness of the Barnett Shale is a little bit less than it is in the core area north of the city, but not a lot less. All the rocks other than that look exactly the same as they do north of the city in terms of organic content, maturity and so on.

We also know that a lot of our competitors have been drilling both vertical and horizontal wells around our acreage position successfully. I guess in terms of reserves per well, that really is the wildcard at this point. If you sort of look at the thickness that we have relative to the north you are still talking about over 100 bcf gas in place per section. So it is really a question of, are the fracs, the horizontal wells and fracs going to be effective?

As I said, the other operators have a few wells online but we don’t have a lot of production history yet. We are really thinking something in the 1.5 to 3 bcf per well type range south of the city as opposed to maybe, I don’t know, 2 to 4 bcf, maybe 5 bcf per horizontal well to the north.

As far as costs go, what we are looking at is about 1.4m per horizontal well completed.

And in terms of drainage patterns, theoretical spacing, what does the 70,000 acres imply in terms of number of locations?

That’s a big guess right now. We’re thinking internally it is somewhere between four and six wells per section, horizontal wells per section is the likely spacing.

Also, why do you think the majors don’t want to just sell these properties rather than do farm-ins instead?

What the trend we are seeing is, as we have had discussions with several of the majors, John, is that they are under pressure to maintain their North American gas volumes but they are under capital constraints with ability to fund any growth in those volumes.

I think they look at it, and look at their cost structure, and then look at EOG’s cost structure and basically say that there is sufficient arbitrage here to do that.

I will say that there are always comments that there is going to be a huge amount of properties from the majors in North America that are put on the market. We keep hearing that, but we haven’t seen a lot of concrete examples of that yet. We think this gives the majors an opportunity to retain the production for the properties, grow the properties without having to commit capital to do it.

Thanks a lot.

Your next question will be from Irene Haas with Sanders Morris and Harris.

Hey Mark, a question. I know you guys have been working on these two shelf projects, and I understand that you guys want to be pretty tight about the location. I just wanted to get a feel in terms of if there is a successful piece – are we talking about bcf's, are we talking about multiple tcf's in range?

Irene, you are trying to get all the stealth ideas out of me here. I mean, what we will say about them is each of them are in the onshore U.S. It is not like a one-well discovery or anything. Each of these is basically a play that will sort out with a whole bunch of wells resulting from the success in the play.

Both of the plays are definitely successful. We’ve confirmed that and we’ve been able to – basically what we’ve confirmed is that the plays are bigger than the acreage we originally had, so we have been frantically adding acreage over the last six months, really, to each of these.

Surprisingly in this high price environment, without a lot of real competition. In terms of the reserve size, they are not tcf size. They are multi-hundred bcf net to EOG side. Each of them. We expect that perhaps by the September analysts meeting and depending on what our leasing situation is, but certainly by year end we will be able to talk about these, because by then we will have whatever acreage we can get.

That’s great. Thank you.

Thank you.

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

Good morning. Could you provide us with an update on the [Uinta] Basin?

I’ll give you a little bit of an update on that, Andrew. The situation there is – let me just expand on that. We kind of talk about these big target opportunities and we’ve outlined five of these that we are going to have decision by year end. If you go back a year ago, the two big target opportunities we were talking about for last year were the [Uinta, Masavur] Basin and the horizontal Devonian play.

As you’ve heard from the call, and the fact that we’ve got five rigs running in a horizontal Devonian with a lot of success, that play worked out. It didn’t work out to the maximum size we thought it would, but it has turned out to be a very strong play.

The [Uinta] play has also worked out, and that has worked out to the original size we estimated which we think ultimately will be about 200 net bcf. The issue we have there is we would like to be running about four or five drilling rigs in that play right now, but that is on Indian land, Indian surface land and the ability to permit those has been very slow and difficult. So we’ve been restricted, basically, to running only one rig.

So this play is going to develop a lot more slowly, but in terms of the results we are seeing there, bottom line we are seeing about 1.3 bcf for about $1m and that one has played out pretty much exactly as we laid it out to you about a year ago.

Thanks.

We will move on now to John Hurlin with Merrill Lynch.

Hi, I’ve got a couple quick ones. With the farm out, Mark, is there any expiration or time limitation with the major?

Yes, there is a time limitation. It is a pretty long time limitation. I believe it is seven years, John.

Okay, that’s fine. Next, with your stealth projects, would you characterize them as being more stratographic in nature? Can you say anything like that?

Yes. The stealth projects are both clearly more stratographic in nature and they involve basically, I would say, some technological edges. In one case I believe it is a seismic technology edge; in the other case it is a drilling and completion technology edge that I believe we are actually ahead of competitors.

So they are really based on technology, but they are stratographic type plays.

Okay, next one. Ed said that there was some cash offshore. Of your cash balance, how much is offshore, how much is on?

Approximately one-third of it is onshore and approximately two-thirds would be in Canada and Trinidad with a great majority of that in Canada.

Okay, last one from me. You are valued at $1.12, $1.15 in Mcfe. Why not buy some shares in with the cash?

Let me address that John. We’ve got a history of the last four, five years we are the only large cap company that has reduced its outstanding share count each of those years.

The reason that we are basically paying down debt and building cash as opposed to buying in shares today is that we want to see – we think the opportunity suite is expanding rather than contracting, and particularly with these five big target things.

If they are successful, and two of them are successful, it is just the scope – we are going to need a lot of incremental investment in 2004 and 2005 to really develop those. If the Barnett Shale works we are going to be off and running and literally drilling hundreds of wells just in that play alone next year.

So what we are doing is taking a conservative approach and basically just keeping our balance sheet strong to see how these things play out, and that will give us some direction as we get into 2004 as to what our strategy will be.

Regarding the Barnett, if you are going to be drilling hundreds of wells, are you going to try to lock in equipment?

Oh yes, we certainly would. Frankly in the Barnett we’ve done all the technical work we can and now it is just a matter of what we find through that drill bit and completion. It is a situation right now where I would say we are really the most positive thing we can say is what Loren mentioned, which is there appears to be very successful competitor wells offsetting our acreage, both horizontal and vertical. But until we get a couple of our own wells under the belt and get them connected to sales and get a couple months production history, we are going to just be uncertain as to what is the ultimate value of this acreage?

Thanks.

Okay, John.

(Operator instructions) Our next question comes from Mark Meyer with Simon and Company.

A question for Loren on the Barnet. You said competitor drilling has been a mix of horizontal and verticals. Sounds like you guys are going predominantly horizontal. Is that correct?

That is correct. Some of the vertical wells that have been drilled around us have had really pretty nice IPs, but not a lot of production history yet. The horizontals have also had nicer IPs, and also less production history than you’d like to be fully comfortable, but we just think that based on the thickness of the Barnett and in some parts of our acreage, the lack of that bottom [sig Viola] we just believe that horizontal is the way to go.

Thanks. Mark, a question for you. Kind of a now versus then as it relates to North American drilling activity. You are talking about, I think, second half drilling levels close to where you were at the peak in 2001 and I think you’ve said on multiple occasions that there were some dollars that you spent late in 2001 that in post-mortem didn’t really measure up to your internal rate of return criteria.

Outside of price looking forward, what are you most sensitive to? Is it prospect quality, is it service cost inflation? Where are the risks to kind of these peak levels of activity again as it relates to your return criteria?

You are right, Mark. We are returning to the drilling level activities that we peaked at in 2001. The difference is we haven’t seen a deterioration in service quality. In other words, we haven’t seen a lot of drilling mishaps, if you will, completion mishaps due to just having green service hands out there.

So I believe the service industry is more stable, plus the total rig count is not as high as it was back two years ago. So the cost side seems pretty reasonable. Also, relative to two years ago, we have beefed up our staff on the operating side and also on the G&A side where for internal personnel, we are a lot more able to handle 50 rigs than we were just a few years ago.

The risks to it there are, if we see the rig count continue to go up will we see service costs deteriorate or quality deteriorate, we will have to reconsider. Right now, my best guess is for the last half of this year we will be running roughly 50 rigs and we will basically say that we’ve got a pretty efficient operation while running those rigs.

Mark, with your beefing up, would you say between now and then your physical prospect quality has improved materially as well for your average prospect?

I would say so. I am very, very comfortable with our second half planned drilling activity level. You hate to use hyperbole here or so, but again we have not really stressed the Gulf of Mexico. We’ve made a couple discoveries in the last couple quarters, but most all of this activity will be indeed in the onshore U.S. and Canada in areas that we are very, very comfortable with.

Last question on LNG. You said the world is changing pretty quickly as it relates to Trinidad and your strategy there. You have 1.4t’s on the books. Between now and 2006 could we see that number double? What are you thinking in terms of increasing your position there?

Let me expand on that question a little, Mark. It’s a good question. Thank you for leading on that one, I will try and hit it out of the park. I think the perception out there in the investment community is that Trinidad is a nice place to do business, but it happens to be very long on gas and short on markets. Therefore if you found incremental gas, what is it really worth?

Up to a year ago I would say that that was probably a pretty good characterization. What we’ve seen in the last year is that the drilling activity for new reserves by competitors has not been all that successful, while we have been successful and we’ve seen that some of the big companies down there are basically seeing the North American market and basically earmarking a lot of their reserves for LNG trains 4, 5, 6, et cetera that will be built there.

So I would characterize the current situation there in Trinidad as one that is relatively balanced between supply and demand. Now, how are we responding to that? In the past five years our track record has been, we pick up a drilling rig, we drill one to two exploration prospects and then we lay down the drilling rig and then we try and find a market for what we’ve found.

We have been extremely successful in our exploration drilling down there, given the limited amount of drilling we’ve done. We added a bunch of acreage last year, about 90,000 acres. We’ve just completed shooting a 3D seismic survey over the whole area, and what we are going to do this time around with our drilling campaign is we are going to basically drill all the prospects that we can identify on our acreage.

The goal is, within the next year, to say, okay, we have “x” incremental bcf or tcf of gas down there. I would say it is not impossible at all that we could be talking about at least doubling our reserves from the 1.4t’s over the next two years in Trinidad.

But the reason we are doing that is, we believe that whatever we can find we will be able to market. We are still trying to look to get away into the LNG game, but the market that we hope to capture by October 1st is going to be more likely for an indigenous, either a methanol or ammonia plant on the island of Trinidad.

But as far as future LNG trains, 5 and 6, we do know that the government would favorably look upon us making some liquid faction investments and going that route. So we will just see how that plays out.

Thanks a lot.

Representing CIBC World Markets, our next question will come from Van Levy.

Good morning, folks, how are you?

Good morning, Van.

A couple questions. In Canada you were looking at I think quick silver scope and methane play close to your – what is your update on your acreage?

We have currently around 60,000 net acres in the vicinity of the Quick Silver in Canada pilot programs that they had drilled earlier. In fact, they continue to develop that area. What we understand from public data right now is that a development fairly close to our acreage of 35 wells is currently producing about 5.7m a day.

At those kind of per well rates, we think that is quite economic. Now we don’t know, I’m not sure anyone really knows, what kind of a reserve per well that is going to turn out to be, but it certainly looks economic to us. We currently plan to drill and recomplete about 10 wells in our 20 acreage block by the end of the year.

We are also leasing on other methane plays in Canada.

Second question, the Barnett Shale, you mentioned 70,000 acres – quite a lot for $6m. Obviously you are hitting the play late. It seems sort of illogical that people that have been there for a while would have missed this portion of the play. Can you give some thought on that?

We are certainly late to the play if you are talking about the core area north of Fort Worth, we were actually one of the first ones into the play south of Forth Worth.

Really the reason people felt that that would not be perspective for the first half of decade that the Barnett was working north of the city was, it lacked a hard limestone bottom seal that they had in the north that people felt was necessary to focus the fracs. So if you couldn’t go in there and frac that 300 to 400 foot of shale and have that frac extend out a long distance laterally focused by that bottom seal type carbonite, there was fear that you would frac into water below that and what is called the [Umberger] formation. In fact, that happened to several operators.

I think what has changed is that people now understand how to frac those wells when you don’t have the bottom sealant, both the vertical case and certainly the horizontal case, that has turned out to be not near the problem that it was once thought to be. That’s been proven by the test rates on at least four horizontal wells that I can think of and probably eight or ten vertical wells now drilled in this area where the vital is absent.

On our 60,000 acres, probably around 50 percent of it does have vital-absent, but we are not concerned with that anymore.

Now our price per acre is much cheaper than the average in the trend, because we were there starting three years ago.

Van, just to give you a little color on that, our price per acre is roughly about $90 an acre. That acreage – and we started leasing out there three years ago at $50 an acre, and current acreage is going at about $300 an acre.

So the key will be productivity, whether these wells really produce given the tight permeability.

I don’t think there is any question they will produce. The IPs in the initial rates that we are seeing in the pipeline down there is quite good. The question is, what will the ultimate recovery per well be and the cost of drilling these wells be? Again, we are optimistic but there is not enough history to answer that question yet.

Okay. Mexico looks like it is beginning to move towards opening up. Clearly that would be an extension of what you are doing in South Texas. What are you doing to position yourself for that?

Van, we’ve looked at Mexico pretty heavily. I guess our position at this point is that we don’t like the structure of the contract. It doesn’t really allow us to grow volumes. It doesn’t incentive us to grow volumes and profit by that expertise. So at this point I would say that our interest in Mexico under the current contract structure is not high.

We continue to look at it from a technical viewpoint and we will just monitor it and see how those contracts evolve.

Last question. North Sea, Mark you mentioned that. Could you articulate your plans there?

Van, in terms of the North Sea what we see there is a lot of majors that have a lot of acreage. There is pressure from the U.K. government on some of these fallow acreage initiatives to force the majors to either drill on acreage they’ve held for 20 years or relinquish it.

We’ve seen that basically the majors would consider anything under about a 200 bcf prospect as too small for them to mess with. So we see a pretty open field for farming in from majors on prospects that are in that range of 100 bcf to 200 bcf in the southern basin of the U.K. North Sea.

That is the plus. We think we understand the geology there. The minus is the infrastructure issues there. We’ve decided just to piggyback on the majors and basically say, we will farm in from you but if we are successful we have to piggyback on your transportation availability there.

So we are basically committing what I would call a relatively small amount of capital there. To date so far we’ve drilled, or we’ve farmed in two wells. One successful, one not. We expect the successful well to come online at 100m a day gross rate, 25m a day net rate in the fourth quarter of 2004. We will drill likely one or two additional farm in wells over the last six months in the North Sea.

So it is basically, I’d say it is sticking our little toe in the water and making sure we understand it before we commit to big investments there.

Good, thank you very much.

And we will take our next question from Shawn Reynolds representing Petrie Parkman.

Good morning. Just doing the math on the guidance, it looks like we are going to have a very strong ramp up in production in the fourth quarter. I just wonder if you can give a little more color on what areas are going to provide that?

Yes, Shawn, and just to give you a little more confidence on that, if you look back at last year we had a very strong ramp up in fourth quarter North American gas versus third quarter. We may be a company that by the nature of our assets that will become kind of an annual event, and particularly in the Rockies and in Canada.

What happens in the Rockies in the Big Pinty area, due to environmental restrictions, we are not allowed to start drilling until the summer. So basically most of the wells we drill this summer will get connected to sales in the fourth quarter.

It is a bigger event in Canada with this shallow gas drilling that we are doing in southern Alberta and southwest Saskatchewan. There we basically batch the wells. We will drill 1,000 of these shallow wells and then we will connect them all at the same time, essentially complete them and connect them all. That is an annual event, quite frankly. It happens in October.

So in terms of components of fourth quarter versus third quarter production growth in North America, the biggest component will clearly be coming from Canada. Probably the second-biggest, we think, will be coming from our midland division, running these five rigs in a horizontal Devonian will get some contribution from the Rockies and then we’ve got a $9m a day net well with the south Timberlier 156 that will come on in the fourth quarter.

So you kind of add that up and then you look at what we did a year ago, fourth versus third, and we expect an even stronger growth this year than last year. It is probably going to be kind of an annual event with EOG with the assets that fourth quarter will likely be every year stronger than the second and third quarters.

That’s good. The other thing is, we’ve seen pretty much across the board with all your peers reporting a ramp up in unit costs and I think with the new guidance we see that in yours as well. Any comments on what is driving that, in the context of what you said with regard to completed well costs would be kind of flat to up 5 percent?

Let me give you a little color on that, because clearly our unit costs are increasing as is everybody in the group. Ours is not watered down, if you will, by a lot of international activities, so our North American gas focus makes it stand out perhaps a little more than some companies who have a lot more – are you still there, Shawn?

Yes, I am here.

Okay, I heard a click on the line there. Our best read is that go forward finding costs in North America will be in the range of about $1.50. If you are heavily in the Gulf of Mexico it is going to be higher than that. So to the degree that our DDNA rate that we are bleeding in costs in the range of $1.40 to $1.50 every year, frankly I think you can expect to see the DDNA rate of us and anybody who is operating in North America continue to move up with time.

The operating cost side is one that we’ve seen some ramp up in EOG’s operating cost and we’ve got the usual stories for the quarter as to some exchange rate issues with Canada, we did a bunch of recompletions and work overs. I would say for the whole industry, for the North American industry, what you’ve seen over the last five years is everybody has added compression to their existing wells over five years ago. We are at the point now where not only every single gas well in the U.S. producing at max rates every day, but they are producing at lower well head pressures with more compression than they were five years ago. That is across the industry.

My sense is that you’ve seen an LOE move up for the industry for the last five years because of the intense amount of compression. In the next five years, there is only so much compression you can put on the average well, and I think that has pretty much been done. So in the next five years, I don’t expect to see either EOG or the industry move up dramatically in LOE as the industry has in the last five years.

That will be kind of embedded in the F&D costs, for any incremental new well that has compression on it.

It will be embedded in the operating costs, not so much in the F&D cost.

Great, thanks.

Thanks, Shawn.

At this time we do indicate that we are out of time for questions, and our apologies to any who are waiting in the queue and did not have time to have their question answered.

At this time I would like to return the conference to our presenters for their additional or closing remarks.

I would just like to remind everybody that we do have an analyst conference coming up. Our annual conference will be here in Houston as usual, the date is Tuesday, September 23. It will last through about lunch time. We will have an evening event the night before. I am looking forward to everybody coming who can make it.

Just to summarize, I want to thank everyone for listening in on the call. We look forward to talking to you again three months from now.

This does conclude today’s EOG Resources second quarter 2003 earnings conference call. We thank you for your participation today. You are now welcome to disconnect from the call.