EOG Resources Inc (EOG) 2001 Q1 法說會逐字稿

Please stand by. Good day everyone and welcome to the EOG Resources first quarter 2001 earnings conference call. This call is being recorded. At this time I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning and thank you for joining us on the call. This morning we will announce first quarter 2001 earning result and hopefully everyone has seen the press release. I am Mark Papa, Chairman and CEO of EOG Resources and also with me this morning on the call are Ed Segner, our President and Chief of Staff, Gary Komitz, our EVP of operations, Loren Leiker, our EVP of Exploration and Exportation and Maire Baldwin, our VP of investor relations. As you can note from our press release we are off to a strong start, you know and got a lot of things accomplished in the first quarter. In addition to generating record earnings and cash flow we proved to be one of only a few big caps who can continue to grow organically in North America and organically the euphemism for high rate of returns through internal prospect generation. Additionally, we continue to demonstrate alignment with shareholders who are our bosses by increasing the dividends, continuing to buy in shares and paying down debt. During the first quarter we have reported net income available to common of $1.79 per share versus 33 cents per share for the first quarter a year ago. Discretionary cash flow for the quarter was $3.37 per share, an increase in the 137% from the $1.42 per share for the same quarter a year ago. We achieved approximately four percent organic North American volume growth relative to first quarter a year ago. On a per share basis, based on shares outstanding North American production increased almost five percent. Total North American natural gas increased 4.2% made up of a 7.3% increase in U.S. natural gas production and an 11.4% decrease in Canadian natural gas due to processing plant curtailments. We expect natural gas production in Canada to increase during the second quarter. Overall, our first quarter results were in line with the guidance given and we have remained committed to achieving the four percent growth target in North America. On the unit cost side everything was reasonably in line except LOE, which increased because of upward sector pressures and extra compression we added to take full advantage of the very high first quarter gas prices. I will now providing some brief highlights from each of our operating divisions. We have ramped up our drilling activities and are currently operating 40 rigs in North America. Excluding the very shallow Sandhills-type wells, we expect to drill about 630 wells in North America this year compared to the 508 last year. In our South Texas division we continue to have excellent results in the Roleta where we have now been successful in 31 of 32 3-D based wells. Two of the more recent typical completions are the Elgars of 15 flowing 9.5 million a day with a 100% working interest and the BNT D7 well flowing 11 million a day with 50% working interest. We currently have the largest drilling inventory backlog in the division's history and recent data indicates this play will expand farther than previously thought. Also, our first two wells in the Matagorda County Geopressure Trio Play are producing two to four million a day each and we are running a one-rig program in this area where based on past results there is always a potential for some very high rate wells. Additionally we have a multiyear development drilling program underway and a 50% working interest for Rosita field where we're targeting 17,000 foot Wilcox zones that produces at six million a day stabilized rates. In our west Texas division, we have been successful in lot of different geologic play types. We continued to have good success drilling with Wolfcamp Pinnacle reefs imaged on 3-D in our ATM area where we have an 85% success rate. We also recently completely a nice 89% working interest in New Mexico strong well called Oak Lake 25 number 1, which is flowing 800 barrels of oil a day a 2.5 million a day of gas. However, our most exciting west Texas results have been generated by horizontal drilling and I'll discuss these in a minute under our bigger play types. In our Mid Continent division we have had positive oil drilling resolves in the 5,300 feet Cherokee formation in western Oklahoma. We have drilled 15 wells with a 100% success rate to date and most of these can produce 400 barrels of oil a day each but are allowable constrained to 200 barrels of oil a day. We expect to have this project unitized by the fourth quarter when we will then be able produce these wells at a higher capacity. Our average working interest here is 70%. In our Gulf of Mexico division our production increased 23% from a year ago by adding several new Eugene Island 135 and Matagorda 622 wells. Our first foray into deep water was successful. The Atwater Valley 426 # 1 well and counted 215 feet of gas pay which we think correlates to about 200 Bcf gas and we have a 17.5% working interest. We expect this gas will be developed within the next three or four years. I know a lot of companies that placed a very high emphasis on the deep water Gulf of Mexico. I want to stress this is only a very small part of EOG's overall portfolio. We will expose ourselves for few wells each year but only as an augmentation to our existing singles and doubles projects. In our East Texas division we have got a lot of our standard Cotton Valley and Travis Peak drilling activity going on, that will offset normal production decline. The growth driver in the division this year will be Geopressure Frio program near Beaumont. We have recently logged our first well of an eight well 3-D program and got a pay zone that we expect will produce five million a day and 300 barrels compensate per day. We have a 100% working interest in all these wells. As expected, our Rocky Mountain Division has significantly ramped up their activity this year. Most of this activity will be around our legacy Big Piney and Vernal assets where more and more of our tight gas acreage appears economic at a conservative 275 Henry Hubb price scenario. For example, we have recently identified 40 additional Big Piney Frontier undrained locations this year. We also have several bigger target projects, which I will discuss in a minute. In our Calgary division, we have had good success with our first quarter Wapiti Drilling Program and feel better than ever about our ability to continue to grow in that area. Our first quarter Canadian production was curtailed 6 million a day because of a plant bottleneck problem, but we expect that to be resolved by June 1st. Additionally, we will drill 600 of our standard Sandhills and Blackfoot shallow gas wells this year, up from 430 last year. Now let me talk for a few minutes about our North American bigger target program. The previous comments related to our North American singles and doubles drilling program. We have also recently developed an inventory of bigger target opportunities and we want to give it up day on these. A common characteristic of these ideas is that they are all onshore. They don't involve deep water and most have a large exploitation as opposed to an exploration component. A second characteristic is that many of these involve horizontal drilling. The first of these is the North Shafter of California horizontal oil play. We have now been successful in six out of seven wells in the six-mile extension of an existing EOG field and we continue to be optimistic that this could be a 30 million barrel old discovery where we have a 100% working interest. Because this is an unusual rock formation, we have cautiously probed the field limits with a one-rig program but will ramp up to three rigs by May. We still haven't found the productive limits of the field, but I can say that this play has moved from the "would it work" to the "how big is it" category. That same category shift also applies to the West Texas horizontal Montoya gas plant. We are now two for two successful wells in this play. Average reserves are 6 Bcf per well for 4-1/2 million dollars. We have one rig running here and have a 20 well inventory. We have recently added another successful West Texas horizontal gas play in the Devonian formation. Our first 100% working interest well the Noki 1H was successful and is flowing 4-1/2 million a day. Reserves at full Bcf and well cost is 2-1/2 million dollars. We are so excited about this play that we have full rigs running and have eighty thousand acres accumulated. This play is bigger in scope to EOG than the Montoya and I expect you'll be hearing more positive results by next quarter. We could have several hundred drilling locations here, all at 100% working interest. We had also previously mentioned to deep Wyoming exploration ideas. One of these is currently drilling. The other is currently flow testing at 1.3 million a day rate, which is commercial but obviously not a big discovery. This is a dynamic inventory list and we have several other 100+ Bcf projects that we are currently not disclosing for competitive reasons. To summarize our North American activities we're on target to hit our four percent absolute organic production growth this year and it looks like several of our bigger target ideas are developing as we had hoped and could provide volume upside late this year and in 2002. In Trinidad, we expect to produce at the take or pay contract level of a 115 million a day for the remainder of the year. We expect condensate production to average about 2200 barrels a day. We continue to target first sales from our UA block to the CNC ammonia plant in the fourth quarter of 20O2. We are making good headway on the second ammonia plant and hope to be able to make a firm positive announcement regarding this project by the 3rd quarter of this year. With the two ammonia plants, we expect EOG production in Trinidad to double within three years.

Now I'll turn it over to Ed Segner to review cap ex and capital structure.

Capital expenditures for exploration development for the quarter were 205 million dollars and that's more than double from a year ago. Capitalized interest for the quarter with 2 million dollars. Cap ex for the full year 2001 is forecast to still be in the range of 700 to 800 million dollars excluding acquisitions. At current prices we are forecasting over 500 million dollars of free cash flow over and above the likely cap ex level. A three cash flow priorities are first to expand drilling activities to capture high rate of return activities but we are limited in terms of infrastructure to the extent we do have the infrastructure we will, of course, expand the drilling activity; secondly, to complete niche acquisitions in North America and internationally; third, pay down debts to a 25-35% debt to total capitalization range which as I'll come to has largely been achieved. Finally, repurchase shares, which we have been doing. In terms of capital structure, at the end of the first quarter total debt outstanding was 645 million dollars, down from 859 million at yearend. Debt to total capitalization was 29.6% down from 38.3% at yearend 2000. We repurchased 1.2 million shares during the quarter. Of that, 500,000 were for the offset of stock options exercises and the remaining 700,000 were actual reduction in shares. Total shares now outstanding are 116.2 million shares. Mark?

Let me discussed the marketing and hedging situation for a minute. We currently have a 100 million a day of natural gas hedged at $5.16 per MBTU, solely for the month of April and May and other than that we are unhedged. We are still forecasting an industry wide U.S. natural gas production increase of 1-1/2% and do not expect to see any big supply surprises this year or next year. Recent data from Texas and Oklahoma confirms our thinking that production growth is disproportionally low relative to rate count increases. The demand side of the story appears to be bit confused right now, but one thing that is clear from the winter is that more fuel switching to liquids occurred than most of thought possible in a short time frame. It appears to us that gas prices have reestablished to linkage to oil prices. Based the current oil strip it looks like the summer downside gas price may be 425 to 450. The summer upside price still appears to be a wildcard depending on temperatures. On the oil side, we currently have approximately 3,700 barrels a day of crude oil hedged at roughly $26.90 a barrel for the remainder of the year. Now we also file an 8-K on Friday for detailed modeling of the second quarter and full year 2001. We have laid out guidance along the previous format, outlining production ranges, pricing differentials, and cost structures. In summary, we are off to a strong start in 2001 and except subsequent quarters to be strong also. We continued to target four percent organic growth in North America and may have some reserve in production upside surprises by yearend, if several of our bigger potential plays continue to work. With our free cash flow generation, we will continue the strengthen the company financially as well as look for tactical acquisition opportunities both domestically and internationally, and now we will open it up for Q&A. Thank you, Mr. Papa. The question and answer especially will be conducted electronically today. To ask a question, please, press star. 1. We will proceed in the order that you signal us and we will take as many questions as time permits. Once again to ask a question please press star, 1 and our first question will come from Mark Fisher with Bank of America Securities.

Good morning, Mark. I was wondering, you had mentioned at the analyst's conference an interest in hedging a little bit here with this demand question in April, May, June, but you seem so far you haven't hedged very much. Are you still inclined to look for opportunities to hedge out in the spring or has that concern passed?

Yeah, Mark, at the analyst conference we had a few weeks ago we mentioned that we are a little bit nervous on May prices and that was when gas was about $5.50 on the strip we felt there could be some weakness, as you're in a shoulder month and what we done for the month May is basically over the last couple of weeks we pre-sold about 200 million of our gas just as a physical sale, not as a hedge and for that 200 million, we are going to get about 550 Henry Hubb so we have done some things to mitigate the potential that we may see some weakness here in May. As we get to the summer, our current thinking is as long as crude oil hangs in there in a range of 27 bucks a barrel, we think that once you get below say $4.25, you can easily justify switching back from resid and certainly from distillate to crude oil so that appears to us to be a bit of a floor. So that is downside and then the upside is just how much we might postulate will have particularly for electricity demand. So, at this point, we are fairly comfortable but we do think that there has been a linkage reestablished through the crude process.

So for May right now you would be about 300 million hedge to 200 at $5.50 and 100 at $5.16.

That's correct and everything else is open.

Great. Thanks a lot, Mark.

Hey. Our next question comes from Mark Maya with Simmons and Company.

Hey, good morning, Mark. First question. I may have missed it on your opening comments but did you breakdown what that three cents difference between the fourth quarter and your base LOE was attributable to?

Yes, I can basically mention, Mark, that about half of it was probably due to compression and things like hot oilings some of our oil wells primarily to maximize production. The other half was due to just industry wide kind a cost-push on the upside.

Okay, that's what I was looking for. Any FAZ133 impact on your hedges?

No, we marked to market all of our hedges.

Okay.

At this point in time, obviously, you know, we can obviously change policy but we have so few hedges that that is what we decided to do right now.

Okay, last question. I know this is a bit of a moving target but your impairment was significantly higher, I guess, than we had expected, just that particular line item. Any comments there?

Yeah, the biggest part of that impairment were a couple FAZ 121 write downs on some successful efforts pools where we drilled some wells that had not quite worked out So that one, I am not sure is one that you can forecast on a go-for-it basis that its going to be at that level. It may come down as we go forward, Mark.

Right, just wanted to clarify. Thank you.

Thank you, Mark. Moving on to Tom Covington with A.G. Edwards. TOM COVINGTON: Good quarter, gentleman.

Good morning, Tom.

My first question is on North Shafter, what's your sort of gross or net acreage just in that play right now?

Tom,right now, we have around 54,000 net acres and expanding.

Your 30 million barrel estimate for the play, does that cover some of that acreage or just part of that acreage or all of that acreage?

Definitely just part of that acreage.

Can you give us an update of what is going on in the Black River play in the Appalachian area?

We are now standing at about 70,000 acres in New York, net acres that is, and in West Virginia we are currently working to close a couple of trades to establish a significant position there as well. We intend to drill our first well, non-operated relatively small anchors to New York here I believe in May or June and we have about nine other prospects developing there and we're shooting seismic on right now. The West Virginia is a bit more of a moving target, but we hope to be drilling at least several wells there towards the end of the year. 00

Okay, a final question. In the West Texas deep Devonian play, how long does it take to drill those wells?

There about 25-day wells.

Okay, what kind of laterals are on those?

4,000 feet, 4,500.

Thank you very much.

Thank you, Tom. We will now hear from Andrew Lief with Styful and Nicholas.

Good morning guys. Great quarter.

Thanks Andrew.

I was wondering just, you know house keeping, what your cash position was at quarter end, what your current assets, current liabilities were?

Sure. At quarter end, we ended up with increase in cash of right around 12 million dollars so if you kind of break the cash flows out for the quarter we had 401 million dollars of discretionary cash flow. Cap ex ran in total about 209, about 205 of that being expiration development expenditures. We repurchased shares of just under $46 million and that includes both the option to offset piece as well as the outright purchase to reduce the total number of shares outstanding. We paid down debt of 214. We had dividends of four so that gives you a working capital reduction of just over 83 million dollars.

Great, thank you. We will now hear from Craig Elbert with Investment Company.

Hi, I just wanted to ask you to elaborate a bit more if you could on your overall production growth forecast. You mentioned the problems with the processing business and tying things in and also pointed to the Texas data signs that they we're not going to get much production growth this year and I was wondering if you thought that the problems that you had with tying in pipes and processing volumes could be affecting other people as well and that this has just partially explained some of the lag that we have been seeing in production.

Yeah, Craig, the problems in the processing that we mentioned were strictly in Canada and related to a plant up in the Wapiti area that we got some production backed out of, which is, it was a pretty small number, really, six million a day of our Canadian production. We have not seen any problems tying in, connecting or running through processing plants anywhere in the U.S., so in the macro view, I would tell you that in the U.S. situation I don't think that the production lag is at all due to any bottlenecks in plants, pipelines, or anything else. It is a 100% due to just limited wellhead capacity. More specifically, we have analyzed the Texas data. Texas has been kind of mysterious. If you plot up a curve of rig count versus monthly production, you see that the gas rig count keeps climbing every month but monthly production is kind of flattened out at about eight tenths of a percent increase for about the last six months in Texas. So you got a flat line on one side and increasing rig count. If you analyze it by geographic area, we are seeing some production growth in the East Texas and North Texas but it is offset by production decreases in the Gulf Coast and deep south Texas. So, in looking at some of the data we have just seen from one of the majors that is reported of our U.S. gas production for the first quarter, I would continue to say that it is very likely that when you add up all the first quarter production data in the U.S. from all the public companies, you're going to see a disappointing total number relative to the gas rig count increasing. Long answer to a short question there, Craig.

I appreciate it, thank you. Again to ask a question, please press star, 1, and we will now move to John Dedds with Bodrick Capital Management.

Good morning. Thank you. I had two questions, one on Trinidad. I wondered if you were looking into L&G possibilities given the low price they're selling gas there versus what's happening in United States and then switching back here on your capital questions, you're basically where you want to be on your debt target. You really don't seem to have much room to increase your drilling so it seems like it comes down to buying shares or niche acquisitions which, I gather are pretty expensive here so are you basically telling us that you're going to be accelerating your share buy back for the rest of the year? Thank you.

Yeah, John. Your first question related to Trinidad and L&G. We don't have enough gas reserves down there to really play in the L&G game at this time. We would need to have uncommitted, probably 2 Tcf of gas to really get in that game and we don't have those sort of numbers so we have gone indigenous market route through the ammonia outlet and with ammonia prices jumping up pretty well, it is quite possible, we could see head net back somewhere in the range of about $1.40 to $1.50 once these plants come on line because our gas contracts do have a floor but they are also indexed to ammonia prices. The way we look at Trinidad is that we are going to double the production at about a 20% all in after tax rate of return and we think that is very positive. Your second question relating to the capital allocation is, you're right. As a permanent basis, we are about at our debt target. Now we may well elect to go down to a lower debt to total cap ratio as kind of what we say a temporary measure for six months or a year if we don't find the right investment opportunities. But we what we're looking at right now, particularly on some of these bigger potential plays we mentioned such as the West Texas Devonian play and the North Shafter play, it is quite possible that by the 4th quarter of this year, we could dramatically ramp up our drilling activity in both those plays and so we'll be pushing a lot more capital in that case through the highest rate of return channel, in our opinion, which is organic production growth. So we are going to stay flexible but don't look for us to be making huge producing property acquisitions at this time because we do continue to feel that those are relatively lower rate of return compared to our other opportunities.

Okay. Thank you. Mr. Papa it appears there are no further questions. I'll turn the conference back over to you, sir.

Okay. I would like to thank everyone for focusing on EOG and hopefully you've heard a bit of the optimism from the senior management team come through on the call, so we have a higher degree of confidence that we are going to continue to have positive earnings and upside surprises throughout this year. Thank you very much. That concludes today's conference call. Thank you for your participation, and thank you for using the premiere conferencing.