EOG Resources Inc (EOG) 2002 Q2 法說會逐字稿

Good day everyone, welcome to the EOG Resources, second quarter 2002 earnings conference call. Today's call is being recorded. At this time, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning, thanks for joining us on the call. Yesterday afternoon we announced second quarter 2002 earnings and cash flow results. We hope everyone has seen the press release. This conference call includes forward-looking statements and oil and gas reserve comments. The risks associated with forward-looking statements and oil-gas reserve comments have been outlined in the earnings release 10 K-and other EOG SCC release filings.

With me this morning are Edmung Segner, President and Chief of Staff, Loren Leiker, Exec. VP, Exploration and Exploitation, Gary Thomas, Exec. VP, North American Operations, and Laura Baldwin, our Vice President of Investor Relations.

During the second quarter, EOG had to circumvent the North American challenges in the Rockies and Canada. We achieved a strong operational quarter marked by further evolutionary success in our key North American natural gas place. Our continued operational success will position the EOG to continue our what you see is what you get strategy, and deliver consistent results.

Regarding financials, yesterday I signed the SCC order 4-460 affidavits regarding our prior filings. As outlined in the press release, during the second quarter EOG reported a net income of $35.4 million or 30 cents per share to. To convert reporter earnings to reflect actual cash paid out and eliminate the ark to market game, the following adjustments can be made to conform to most analyst practices of matching realizations to the settlement month. Subtract the 700,000 gain from the mark to market impact of our outstanding feature transactions, which is 500,000 after-tax or less than 1 cent per share. Subtract the $19.8 million, $12.8 million after-tax, or 11 cents per share of actual cash paid out after in the quarter to settlement commodity contracts. Adjusting for these items net income for the quarter was $22.1 million, or 19 cents per share versus last year of $110.2 million or 93 cents per share on a similarly adjusted basis. For the second quarter of discretionary cash flow available was $169.7 million, or $1.44 per share. I will note during the current year second quarter, we moderate the small amount of Rocky Mountain production because of unacceptable low gas prices and last year's quarter had a high volume adjustment.

Now, I'll discuss some of our operational highlights. Last quarter, we told you we would sculpt our North American production growth to meet the expectation of rising gas prices throughout the year. While our supply expectation was right, we saw a 60 cent fall in third quarter gas prices because of weaker-than-expected demand. Additionally, prices in the rockies and Canada are considerably lower than we expected; therefore, our AK second half production guidance reflects the reality of what we could expected in September and October gas prices and very high basis differentials.

I'll now provide highlights regarding our diverse operational activities. In south Texas, we continue to have excellent results. Two receipt wells at Union Ranch number 2, the Billings B-4 most recently completed and producing 4 and 8 million cubic feet a day respectively. We have 100% working interest in both wells. These are 3 BCF wells and cost $1.8 million each. During the quarter, we've increased our geology and geophysical understanding of this play, and have added significant acreage in this expanding trend and have a lot of room to run. Our ranch, deep Wilcox drilling and completion program continues to be successful, although we won't see a production increase until October 1, when new surface production facilities are installed. We now have three wells that are each capable of 20 million a day, and we have 50% work interest. Our current net production is 18 million a day and expect to ramp up to 45 million a day net by year end. In Mississippi, we recently completed two 100% working interest wells in Grangefield.

The Halberg number one is flowing three million a day, and the Torman number 1 is flowing 3.6 million a day. In our Medcontinent division, we confirmed a new discovery in Texas county, Oklahoma. It was completed in the sand at 4800 feet and has been producing 10 million a day and 50 barrels of condesate a day for about a month. The second well, Hudleston 25 number 2, was completed in the same zone for nine million a day and 40 barrels a day of condesate and confirms what we believe to be a 20 BCF trap in this high quality, very shallow reservoir. We plan to drill three to five offsets by year end to further delineate the reservoir. EOG has 100% working interest in this discovery. In west Texas, we're now running four rigs in the devonian horizontal play. Two in Allison ranch and two in the ATM area. We plan to add a third rig during August in the ATM area. Our drilling efforts have been focused on determining the optimum drilling and completion methodology what we reported to you in the previous quarter conference call, and it appears that bill lateral list provide the best mix of reserves per cost. We recently completed the SHIRK 13 number 1 H in the ATM area. This duel lateral well was producing 3.8 million a day, and 380 barrels of oil a day.

Reserves are estimatedly at 5 BCF and the completed well cost is $3.2 million. We recently completed the nokey 4 and 2H at Allison Ranch. This well was another duel lateral and is producing 3.5 million a day and 100 barrels of oil a day, the reserves are estimated to be 4 1/2 BCF or $3.2 million. We plan to maintain a five rig program in the devonian horizontal play through year end. We're continuing to expand this play by drilling two significant steppout wells during the third quarter, one a six mile offset and another is a 23-mile offset from our core development area. During the quarter in west Texas, we also completed a nice Montoya horizontal well, 98.1 looks to be a 10 BCF well for a 6, 6 1/2 million well cost. We have a 68% working interest in this well. In the Rockies, we have continued our standard success for western Wyoming's area infield and steppout program.

We have had exploration success in eastern Wyoming where we recently completed two 100% working interest wells producing a total of 600 barrels of oil a day. We'll be drilling two other exploration wells in this area during the third quarter. In the vernal Utah area, our Wasatch formation infield drilling program has been slowed by permitting issues, but we have drilled and completed several deeper, bigger target Mesa Verde tests, and I'm very encouraged by the results. Three out of four Mesa Verde tests so far have been successful. Typical reserves are at least 1.2 BCF per well for a million-dollar well cost. I'm optimistic we have a potential for 100 to 200 net BCF of economically developed gas in Mesa Verde, under the Utah existing acreage. In Canada, natural gas production increased significantly compared to the second quarter 2001.

As part of our North American natural gas strategy, we acquired additional gas acreage in southeast Alberta and southwest Saskatchewan over the past 24 months enabling us to continue our shallow-gas drilling program at a high pace. We plan to drill 1,000 shallow wells this year and have enough acreage to repeat this in 2003 this. This continues to be a low-risk way to grow production; additionally, in northern Alberta, we tied in the Elmer 33 well completed in the Charlie lake formation at 7800 feet. The well is producing 14 million a day and we have a 50% working interest.

Let me provide with you a clarifying comment regarding North American cap x and short term volumes. During the first half of this year, we've allocated a higher than usual amount of cap x to three projects where the timeline between expenditure and increased production volume is longer than typical. These three items are, number one, all of our Canadian acquisitions are characterized by low current production rates but lots of PUD infield drilling potential. In south Texas, our Vin Ranch deep Willcocks play, we continued to drill wells, even though we haven't seen a short-term production increase because we're anticipating in the fourth quarter we'll have our expansion and surface production facility. Basically, we're spending money there, um, and it will be the fourth quarter before we see an increase production coming out of that, and then in our west Texas devonian play, we have delayed completion on several wells because we wanted to monitor the results from other receipt wells as part of our completion optimization strategy. In other words, we're not able to go in the program drilling mode because we're trying to learn what the best way is to drill and complete these wells. All of these investments, um, we feel very good about making them because of our confidence in the gas supply-demand story.

Let me talk about Trinidad for a minute. In Trinidad, the CNC ammonia plant came on line ahead of schedule at the end of the second quarter. We're currently running full production in the plant about 50 million a day net. The gas price is tied to Caribbean ammonia prices. We added a third exploration block earlier this year, and a prospect inventory in Trinidad has never been deeper. We plan to drill two to three wildcats per year for the next several years, and I'm confident we'll add substantial reserves above the 2 TCF we currently have in Trinidad. Even with our new ammonia contracts, we're long on gas reserves in Trinidad and can feed additional markets with existing reserves. We're currently in preliminary discussions in train 4 of the Atlantic LNG project. The first production would be in 2006, if we are successful, and the pricing terms are reasonable, but since we're in negotiations, I don't want to discuss any specifics at this time. Without discoveries and potential for new gas market, we expect to increase Trinidad production at an 11% compounded annual growth rate for 2006. I'll now turn over the discussion to Edmung Segner, to review cap x and capital structure.

Thanks. Total exploration and development capital expenditures in the second quarter of 2002 were $208 million, including acquisitions. We made $33 million of acquisitions primarily in Canada, where we have added to our shallow gas position that Mark mentioned. Year to date, total exploration development expenditures were $404 million, including $44 million of acquisitions. All primarily shallow gas acheorage in Canada.

Capitalized interest for the quarter was 2.2 million. Year to date, capital expenditures have exceeded cash flow as part of our first half strategy of prespending at the current point in the cycle with a lower service cost environment to set us up for 2003. We revised our capital expenditure forecast and expect total capital expenditures, excluding acquisitions, which year to date have been 44 to be between 745 and 800 million for the year. This also excludes our Trinidad ammonia plant investment of approximately $20 million. Over time, it's our anticipation to sell these ammonia positions down.

On the capital structure side, at June 30th, total debt outstanding was approximately $1 billion, 36 million, the debt to total capital ratio was 38%. With our strong balance sheet and credit rating, we were able to outspend the cash flows in the current environment of lower service cost. Based on our current cash flow and capital expenditure forecast, we expect the debt to total cap ratio at year end to be slightly over 40% still, one of the strongest in our peer group. We plan to continue sharing purchases to offset employee stock option exercises and maintain a flat share count at year end. Our goal is to repurchase approximately one million shares prior to year end. We have not purchased any shares yet year to date. The effective tax rate for the quarter was 31%, the deferred tax ratio was 78%. I would also note that GNA this quarter does include an approximate 2.4 million nonrecurring litigation items that was included in GNA.

On the legislative side, the energy bill currently under consideration in the conference committee, um, is certainly applicable to EOG, and there is the possibility that it may pass. EOG one a beneficiary if the bill would pass both houses coming out of conference committee, due to the tight gas ends and tax credits in the bill. Now, I'll turn it back to Mark to talk about marketing and hedging.

Thanks, Ed. I'll give you our thoughts now on gas macro and then discuss our hedging strategy. Based on our calculations, second quarter company gas production was down 5.1% year over year, which is very close to our model prediction. We expect the full year 2002 gas production will be down 5 to 6%, which is the largest decline in 16 years.

Further, our model's indicate even with a robust drilling recovery, U.S. production will fall by another 2 to 4% in 2003. To put this in context, U.S. gas supply has been 52 BCF a day, plus or minus 1 BCF a day for the last decade. By early 2003, we expect domestic supply will fall to 47 BCF a day. This magnitude of decline hasn't happened in recent history. Further, we expect total Canadian imports to decline in 2003 versus 2002. This decline will be approximately offset by increased LNG imports; therefore, we'll likely have 4 to 5 BCF a day, less North American supply in 2003 versus the beginning of 2002. Demand in our opinion has been weak so far this year. We're not surprised by the near-month price weakness, but after we work off the storage overhang, we expect robust prices in 2003 and '4 with that macroview, I will now discuss EOGs marketing and hedging strategy. In the second quarter as a result of mild weather and other market factors, well head gas prices in Iraqi fell to 80 cents MCF. EOG has [INAUDIBLE] most of this exposure due to ownership of significant firm transportation capacity to midcommon marks. However, we do have swing volume subject to spot Iraqi's prices, which are currently still 80 cents at the well head.

Regarding third quarter financial hedges, we have an average of 100 million cubic feet a day of price swaps, an average price of 320. Using the August 9th price cap, we would calculate a cash flow in the third quarter of $600,000. We have also presold physical gas in September and October. For the fourth quarter, we have natural gas price swaps for 10% of our North American production and 330 average price.

Regarding oil, we have 2,000 barrels a day of oil, of oil heads at 2150, through December 2002. We're totally unhedged on both gas and oil for 2003 and beyond. Updated guidance for detailed modeling of EOG was given in the AK filed last night. We laid out guidance for the third and fourth quarters along the previous guidance format, the production ranges, pricing differentials and cost structures. As we stated, we factored in the production guidance, the possibility of production moderation if we continue to see weak prices and basic differentials in third and fourth quarters.

In summary, we had a strong second quarter operationally. We made progress on some of our key plays that will continue to set us up for 2003. On the financial side, we continue to focus on the rate of return of our drilling program. We have a lot of exciting things going on at EOG, and plan to capture a lot of them upside with an improving gas market. Thank you, and now we'll turn it over to Q, and A. Hello, Clay, are you still on there?

Yes, I apologize. Today's question and answer section will be conducted electronically. If you would like to ask a question, press star 1 on your touch tone phone. We'll take your questions in the order we receive them and allow as many questions as time permits. Once again, that's star 1 to ask a question, and we'll pause for just a moment. We'll take our first question from David Snow with Energy Equities.

Yes, can you tell us, you were shifting your viewpoint on the macro from total U.S. to company reporting, um, did I pick that up right, it's at, um, a refinement or why did do you that?

No, it's, um, the -- basically we just used all the public companies as a proxy for total U.S. So, um, you know, it's the only guidance that is out there in terms of real -- very hard numbers. If go back to our conference call of the previous quarter at that time, we were forecasting U.S. gas would fall in a range of, um, 3 to 5%. We've -- now that we have updated our models and seen the results, we have upped that to the 5 or 6% range this year, and then the other refinement that we previously had not indicated publicly is that it's our feeling that even with a robust drilling recovery, gas production will fall again in '03, and one of the reasons we feel that way is that, um, the exit rate in the fourth quarter is likely to be in a range of, um, somewhere between 6 and 8% decline on year over year basis, and simply stated when you start the first quarter in that big of a hole, um, there is no way U.S. production can even be flat next year in our estimate.

I guess you're, um, reflecting a lack of total competence in the DOE figures, showing 2.4%, or something in that range declines so far.

Yeah, I, um, I mean I guess -- I would say that the balancing item, the DOE numbers moves around. We don't rely on those numbers ourselves.

Okay, you mentioned in the last conference call there was a compressed gas alternative for moving, um, offshore gas to the U.S., and um, could you give us some ideas to whether this is still a serious possibility and who are the vendors of that kind of technology or equipment.

Yeah, David, what I mentioned was that, um, we were looking at the possibility of compressed gas, um, coming from Trinidad to the U.S., um, and that was one of our potential market outlets. I can tell on you a specific EOG case, that idea has kind of fallen to a lower probability over the last three months, our excess gas has moved up on a probability scale. Um, in terms of whether that's likely to be, um, you know, a major import item into the U.S., I would say it's too early to tell. What I can tell you is the people talking to us about compressed gas on this scale admitted this was kind of first of a kind, um, thing, so in my opinion, over the next several years, I wouldn't look for that to be a huge factor in terms of U.S. gas macro.

Could you share with us who the person was you were talking to about that idea?

Oh, probably not, David. Thank you.

Okay. Thanks a lot.

Okay.

Our next question is from Mark Meyer with Goldman Sachs.

Morning, Mark.

Morning, Mark.

Question about, more broadly on Trinidad, do you see an opportunity in the '03-'04 time frame to accelerate volumes into the North America market. I know you talked in terms of 06 with the -- in terms of LNG

The answer to the question there, Mark, is no. We don't see any volume in that kind of time frame, any possibility of doing it there, um, our situation in Trinidad is that we're -- we're long on gas right now to a tune of maybe a half a tee, um, where we have undedicated gas. And, um, we think the drilling next year will probably end up being longer, so that's why we're pursuing the LNG, but most things in Trinidad work on schedule similar to deep water, you know, it's two, three, four years lead time, and they're a pretty discreate production growth increments as we go for.

This accelerated program, the two to three wells per year is in anticipation of an '06 and beyond LNG opportunity?

Yeah, you know, the '06 LNG opportunity, we have the reserves in hand now, but the drilling program that we do in '03 and '04 would really set us up for additional growth in '07, '08, that kind of time frame, Mark.

Mark, your '03 Ks for, um, I guess, tighter, tighter gas markets are -- around hedge position, is that strictly a supply-site driven view, or, I guess, the better way to ask the question is what is your demand view. I know you said you continue seeing weak demand. What is your general '03 demand?

Our view is that, um, as we decline from 52 to 47 BCF a day, um, we don't need any demand growth to make the gas story a lot stronger, um, so, you know, our view is that, um, as this thing plays out and people begin to see in the third quarter production numbers as well as fourth quarter that, gee, whiz, deliverability isn't falling to 34 BCF a day. The questions of demand will be more on what are the break points where you have significant declines and incremental demand below what you can supply with 47 BCF a day in the U.S. and I would still give thoughts that you know, I would say between $3.50 and $4 stabilized Henry hub gas prices, stabilized as you can get from volatile commodity, or what we're planning on for the period '03, '04.

Thanks, that's helpful. Thanks, Mark.

Thank you.

Our next question is from David Huykenan from Hibernia South Coast

A quick question. Was writing down your capital spending, it was 404 million year to date, 44 million with acquisition, is that right?

yes.

Your increased capital, is that going for additional devonian development with additional riggs being added or where is that being spent?

A big part of that is coming from, um, the Vin Ranch that Mark spoke of.

Okay.

As well as devonian in west Texas there.

Do you have a breakdown, I mean kind of half-and-half in those two, is that a fair way to look at it?

It's probably a little -- probably 60% of it is Vin Ranch.

Okay.

The other is devonian.

Okay.

Remember, we're spending capital throughout the company.

Oh, right.

And all of our divisions, and so, um, --

Just the additional $50 million roughly is the -- of those two areas.

We probably have spent about, um, $25 million additionally there at Vin Ranch that is on wales that are still shut in, waiting on treatment plants to be installed, and then in west Texas, it's probably closer to $10 million of expenditures for wells that are still waiting on completion for us to spend time, um, further optimizing completion and simulation processes.

Okay. Thanks a lot.

As a reminder, if you would like to ask a question, please press star 1. We'll go to Herb Chin with Chin Capital. Mr. Chin, your line is open. Please go ahead and ask your question. Moving on, we'll go to Andrew Lees with RBC Capital Market.

What was the rig rate assumption going with your forecast for next year, Mark, and then a quick update on Appalachia.

Yeah, okay, on the rig rate assumptions for the gas -- oh, had a little noise on the line there. The rig-rate assumption for the gas supply forecast, basically we're assuming that it goes pretty much on a straight line from -- from where we are right now, roughly to 720 gas rigs, um, up to about 1100 gas rigs by, I believe, it's March or April of 2003, and then it basically moves, it kind of goes slower, slow, but increases through the rest of 2003. Um, that's a very, very aggressive drilling forecast in light of what we have seen the last month or two, um, so I wouldn't be surprised if, you know, if we really kind of underperform that amount of increased rig activity. To me, the interesting thing was even with that aggressive forecast, it, you know, we saw continued production decline in '03 versus '02. On your second question there on Appalachia, um, we continue, I guess on the two plays that we're working there, really three plays, we have a shallow devonian play, a standard bread-and-butter play, we'll probably end up drilling, get ourselves set up to drilling 1 to 200 drills a year every year first, you know, X years. Similar to our sandhill program, only not as intense on. Trenton black river play up there, we're concentrating primarily on the western New York State, and um, likely we'll drill another -- we'll drill several wells. We haven't really drilled any so far this year of any consequence, so we'll drill a few as we go forward, and then we're investigating the possibility of cold mine methane in Appalachia, it's looking intriguing to us. It's too early to tell in terms of any results there, Andrew.

Mr. Lees, anything further?

In terms of leasing anything further, we have off-leased a little acreage there, nothing substantive, Andrew. I guess our 4 A into appalachia, I would describe at this time is, you know, it's probably going to take us another year to see whether that was a successful foray or not, but right now, um, both the Trenton Black River play and the Coal methane play look like they'll work, in my opinion. It's just a matter of what's the scope of how well it works. Is this a really big deal or is it something going to be more moderate sized.

Moving on, we'll go to Adrian Day with Global Strategic Management.

Yes, good morning. On the macro situation, most of the discussion was on, um, U.S. production if I understood you, and I wondered if you had any comments on growth potential of Canadian production on a macro sense. The second question is, on the option of what were discussed, you can let us know what the prices are, what they're going to be exercised that?

um -- .

I'm talking about this year, the options.

Yeah. Let's -- some of that -- on the first question there yeah, on the Canadian issue there, Adrian, um, our read is for the first time in quite a few years, um, in '03, we won't see any growth from Canada, also including eastern Canada, part of that is due to likely declines in the lady fern field on the the Alberta BC border, part of it is due that the next scheduled production increase is from eastern Canada is not until 04, so our read is, and the other part is the decline rates in Alberta and the drilling activity in Alberta, um, both point to problems in production growth in Alberta. Our best guess is that, um, imports from Canada '03 versus '02 might be down in the range of half a BCF a day and that will be approximately offset by some increase -- at existing LNG terminals that would say we might be up half a BCF a day from more LNG coming in. In very, very simple terms, um, you know, those two will roughly cancel out, um, Mexico also playing a part in this, and right now, Mexico is importing from the U.S. about half a BCF a day, and some of the receipt pronouncements infer that that willful of -- level of imports may stabilize or grow over the next several years. Not a lot of hope that gas will be coming north from Mexico in this time frame. Regarding the second part of your question, um, let me ask Edmung Segner to answer that.

As a refresher, we have 115 million shares outstanding. At year end, we had approximately 7-million options outstanding, um, so, you know, obviously a relatively small percentage relative to most companies. Options, exercisable at that point in time were about 4 million, um, and of that four million about 2/3 of those had prices somewhere in the range of either 20 or, um, around 15.

Okay, thanks. Thank you.

Our last question today froms from Phil [INAUDIBLE] with Credit Swiss First Boston.

Hi, guys. How are you doing? I wanted to know, there has been a creep in DDNA rates, at least among those that hadn't had big writedowns, um, yours is creeping up a little in the last year, but you're at a good level. I wondered if you would speak to -- it would look to me like it's another typical EOG finance cost year.

Yeah, I think -- I think, Phil, um, the advantage we have on a go-forward base is, um, is really that -- our program activity is going to yield pretty consistent DDNA rates as we go forward, so I would say the finding costs this year, you know, it's too soon to give a quote, but I would say that our overall reserve replacement number total company is going to look excellent. Because we had a substantial discovery in Trinidad, um, and so our aggregate finding costs will likely look pretty darn good. When you break it down in North America, though, I would offer that typically we had reserve replacement in North American range of 120 to 140% year after year, um, and I would look for it to be somewhere in that range in the -- and the finding cost will -- will be reasonable, we're targeting about a buck and a quarter, um, but we don't have a lot more specifics than that. But on a go-forward basis, yeah, we feel like we're penalized because we're the only company that hasn't had substantial writedowns, ever in our history, and so we're carrying that little baggage along that we never got to write anything off on our DDNA. That give you an answer, Phil?

Perfect, exactly what I was looking for. I don't think I would do a writedown to be appreciated. I would keep doing what you're doing. Take it easy, guys.

Thank you.

We'll take the next question from Stephanie Joe with Sanders Morris Harris.

Good morning, at this time -- would you providing any guidance for '03 production, particularly U.S. and Canadian?

Oh, Stephanie, yeah, um, we haven't changed our generic guidance, which is really, um, you know, the 4% growth in North America when you tack on the Trinidad growth which is there from -- from the, um, the plant that has come on line recently, you know, it looks like aggregate company growth would be in the range of 6 to 7% on an absolute basis, um, that, you know, we'll give more detailed guidance other than generic guidance as we get into the fourth quarter, really, but the game plan we have was -- is really that our exit rate at the end of this year, particularly when we had the Vin Ranch coming on, and hopefully when we get more of this devonian play, that it kind of kicks in here. Our exit rate for this year should be pretty strong in North America, and that will be a good lead-in to carry us forward as we go through 2003.

Thank you.

Okay.

We'll now go to John Gendry with Federated Investors.

Yes, thank you, my questions sort of piggyback on the last one here. Can you give us guidance in terms of '03 leverage and capital spending and what your feeling is on your current debt rating.

Yeah, in, you know, I can -- I could give you some general kind of philosophical, um, leverage in terms of -- of what I would like to have next year, um, if you look at a $3.50 and $4 gas price and run that through your models for us, um, it's not hard to get a number that basically says our cash flow next year, um, could be in the range of 900 million to a billion dollars, we think that will drive service costs up, it will -- it will create a bit of a heated environment where things will become more expensive, and um, philosophically, it's -- it's not obvious to us that we want to overexpend our cash flow, um, next year. It might be a time in the, um we might want to underexpend our cash flow, actually, and not get caught up in, you know, some of these low return things. I know that's different from a lot of what we have seen the last year or two, where most ENP companies significantly overexpend last year and run their debt up, but philosophically, that's where we're looking at. As far as our credit rating and kind of where we are on that, Ed, you may want to respond to that.

For those who don't know, we're triple B plus, um, double-A, too. Double-A 1, excuse me. Triple B plus, double-A one. Um, and we're very comfortable with that rating, and um, certainly hope that it's maintained and we're not aware of it, it's under any particular review or anything at this time.

If I could I could just follow up quickly, would I expect your leverage to trend down as you pass the higher capital spending to year going in '03?

Um, yeah. If ween up with a $3.50, $4 Henry hub gas price, um, we will take a much more serious look at either share repurchases or, um, some debt paydown next year, if we have those kind of cash flows, and historically, if you look at last year, we bought in about 2% of our equity and retired it and kept our debt level flat. So I think you could look a bit to what we did last year, um, as to what we might do in -- in the period of '03.

All right. Thank you.

Okay.

Chris Eve with Simmons has our next question.

Good morning. I was wondering if you could give us color on your guidance for Trinidad gas production in the second half of the year. You have the take-or-pay contract at 115 a day, and the ammonia plant at 50. I'm wondering why, particularly in the third quarter, the guidance is 130 shirt to 145.

Yeah, Chris, specifically, we expect the ammonia plant to be running pretty much in the second half the year. The one where we're, um, kind of dependent on the government, the gas company there, natural gas company in Trinidad is on our base volumes and the SCC block.

uh-huh.

And right now, they're running a bit of a deficiency on take-or-pay levels so far this year, and they have indicated to us that it's possible that they may not overtake for the rest of this year, and so we might end up with kind of a deficiency in take or pay. This is something that happened in the past there.

Right.

And so that's why our volumes are lower. The other thing is that we have a pipeline repair, um, that's going to shut us in for 10 or 14 days for the second half of the year. That something, you know, we've known about it for quite awhile, that's one reason the volume's going to drop down there also. It's just a mechanical issue.

Great. One last question. On the deferred tax guidance for the rest of the year, that looks like it's come down from what you're previously guiding towards. Can you give us a feel for what you're feeling there?

Chris, the first mover and the most important mover is we're expecting a lower tax rate, which is driven for mostly, um, by the fact that we have lower taxable income.

Right.

Due to lower pricing. Um, and so that's really what's the primary driver, um, the other aspects of that are that, um, we do have, um, obviously lower tax, or lower prices and lower, um, taxable income. The franchise tax in Texas goes away from being an income tax to being a true franchise tax or capital tax, if you would, and so thus goes on a different line, and in much smaller numbers, so that's a factor. Um, a second factor, um, on the tax rate, um, is that in Trinidad, um, in the past on our UA block, we've had nondeductible losses, um, these are now nontaxable losses. Nontaxable income, if you would. Um, as that project kicks in.

Okay.

And then also our state tax rate is -- we're carrying it a little lower right now.

Okay, great, one last question, if I could. Can you address the shift in CapX. Look like you -- you have taken dollars out for the Trinidad budget, obviously moved more under the U.S. side. I was wondering what if you address what has changed relative to the last update.

We had two discovers, one last year and one this year, and we're continuing to define what kind of production platforms and facilities will be required to bring those on, and what kind of time frame we tonight bring them in on, and we have moved a little bit out of a development capital, facilities this year into early next year.

Great, thank you very much.

That is all the time we have for questions today. Mr. Papa, I'll turn it over to you for any concluding or closing remarks.

I want to thank everyone for listening in on the earnings conference call, and let you know we're still on track at EOG, and we're excited about what we think is going to be the right position for EOG, right in the fairway for the next three, four years in the North American gas markets. Thank you very much.

That concludes today's conference, we thank you for your participation and hope you have a good day.