EOG Resources Inc (EOG) 2003 Q3 法說會逐字稿

Good day, everyone. Welcome to the EOG Resources Third Quarter 2003 Earnings Conference Call. This conference is being recorded. At this time for opening remarks and introductions, I would like to turn this conference 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 third 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 note 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 third quarter actual results were very much in line with the 8K guidance we provided in August. Yesterday we filed an 8K with guidance for the fourth quarter and full year, and we are on track to achieve our targeted goal for total company 2003 production growth.

As outlined in our press release, during the third quarter EOG reported net income available to common of $114.7m, or 99 cents per share. For investors who follow the practice of those industry analysts who focus on non-GAAP net income, EOG’s third quarter adjusted net income available to common was $93m, or 80 cents per share, as compared to $29.3m, or 25 cents per share a year ago. 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.

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 third quarter was $292.2m, or $2.51 per share versus $208.5m or $1.78 per share a year ago. The reconciliation of non-GAAP discretionary cash flow available to common to net operating cash flows is found in our earnings press release which is posted on our website.

Before I move into our operations discussion, I want to reiterate EOG’s strategy which has three primary components. The first is to continue to achieve a strong reinvestment rate of return, thereby generating high ROEs and ROCEs where we have historically been the industry leader. Our second strategy is to stay heavily focused on North America gas, because we feel that this will be the sweet spot of the worldwide energy picture for at least the next seven years. A third strategy is to expand our Trinidad operations and to conservatively make some North Sea drilling investments, and I will provide some color on this in a minute.

Regarding North America gas, we have a three-pronged approach. One, we will continue to concentrate heavily on our singles and doubles strategy, i.e. drill a lot of moderate rate and reserve wells. Two, we will mix several bigger target drilling ideas into the inventory each year, and I will give some specifics on this later. And three, we will continue to look for property acquisitions that contain upside drilling potential.

Against this backdrop, our third quarter volumes were slightly about the mid-point of our 8K guidance, and we expect full year volumes on an Mmcfe basis 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 very few who have organically grown domestic gas production versus year ago levels for the past four quarters.

Our fourth quarter North America gas volumes will ramp up significantly versus the third quarter, primarily driven by the acquisition of the Canadian properties from Husky and also from well connects relating to our 1,000 well shallow drilling program in Canada.

I will now walk through some of our operating highlights. In South Texas, we’ve had consistent results from our Roletta program, where we’ve got a full inventory of 2004 drilling locations based on our exploration success this year. However, the Roletta results have been overshadowed recently with some excellent Frio and Wilcox wells. We’ve recently made two excellent discoveries in the Frio South Midway field. We are currently completing both wells and based upon initial flow tests we expect each well to produce in the range of 15 Mmcf/d and 1,500 barrels condensate per day. We have 100 percent working interest in both wells and have several offsets to drill. We expect to have both wells connected to sales by mid-December.

We also have an excellent recent South Texas Wilcox completion. The Henley No. 1 well is currently flowing 30 Mmcf/d and we have a 67 percent working interest with several offsets to drill. In the Gulf of Mexico, we commenced production in late October from the 60 percent working interest South Tibilier 156 b-1 well, at a 10m a day, 3,500 barrel condensate per day rate. It’s important to note that none of the aforementioned four wells went on line in the third quarter. The fourth quarter will reflect partial contributions from these wells, but we won’t have a full quarter’s contribution until the first quarter 2004. We are particularly pleased with the high condensate yields and we can expect to pick up in our North America liquids production resulting from these wells.

In the Mid-continent we are continuing with a three rig horizontal drilling program in the Cleveland formation. To date we have drilled 22 wells and are averaging 1.4 Bcf per well, for a $1m well cost.

In the Rockies, we recently spudded the first well on our 70,000 acre [Mox Arch] farm in, and expect this will expand into a multi-rig, multi-year program. In Montana, we continue to make good horizontal oil wells in the [Bachan Silt Stone]. The Verstep 1-22-H is currently producing 400 bpd from a single lateral. We expect this well will produce 600 bpd when the second half of the dual lateral is co-mingled. We have a 95 percent working interest in this well, and expect to drill 10 to 20 offsets.

We recently spudded the first of three big target Merna and Jonah 2 wells that are our attempts to replicate the Pine Dell Anaconda wells. We expect to have results by March, 2004.

In West Texas, we are continuing to have good success drilling horizontal Devonian wells such as the Garnet 108 no. 1H. EOG has an 84 percent working interest in the well which IP’d for 5.3m a day and 800 bpd of oil.

We’ve also been successful in a new horizontal Devonian farm in from a major. The Arlborough Allan no. 1H is currently producing 225 bpd of oil and we have multiple offsets to drill in this new area. We are continuing our work in the Barnett Shale extension play. We have three horizontal wells drilled, and expect to have pipeline tie-ins by early November. We expect to have preliminary results regarding this play when we report fourth quarter earnings. We have 90,000 acres in this area and are hoping to achieve 1 Bcf to 1.5 Bcf per well for a $1m completed horizontal well cost.

In Canada, we closed the $320m shallow gas property acquisition from Husky on October 1st and are already seeing upside. As part of this acquisition, we increased our coal bed methane acreage position immediately north of Encana’s pilot projects in the Twinning area. Third quarter pilot testing on our acreage looks positive, so we think we will ultimately develop about 100 Bcf net to 150 Bcf net of coal bed methane reserves here, beyond the previously announced proved reserves that we acquired in this acquisition.

Our well connects from our standard 1,000 well Canadian shallow gas drilling project are running about a month behind schedule due to permitting delays, so we won’t see the full volume ramp up from this year’s drilling until mid-December.

In Trinidad, we are still making good progress on finalization of our 125 Mmcf/d mid-2005 methanol plant contract. We currently have the pricing, volumes and timing agreed to, and expect to have a contract signed in the next few months. We expect to commence 95 Mmcf/d sales for this plant in mid-2005 with an additional 30 Mmcf/d to commence four years later.

We are also working on additional Trinidad markets, and we hope to have further positive announcements regarding these on our fourth quarter earnings call. Our first Trinidad exploration well in our 9 month drilling campaign, the [Oilbert] 3X was successful in finding new reserves in one of the two planned objectives, and is a small discovery. The well will be completed after we set an [Oilbert] platform. We will soon commence our lower reverse L exploration well and we expect to have results by year end earnings release on this well.

In the North Sea, we recently mentioned that we expected to drill two farm-in wells during the fourth quarter. The first of these is a success and preliminary results indicate the reserves to be as much as 110 Bcf natural gas discovery. Our working interest is 30 percent. We expect this well will produce at a gross 60m a day rate commencing late 2004. Combined with our first quarter North Sea discovery, we expect to have about 40 Mmcf/d of net production of net production from these two wells by the second half 2004. So it looks like our game plan here is working. We expect to decision one additional farm-in well before year end. I will now turn it over to Ed Segner to review capex and capital structure.

Thanks, Mark. With respect to capital expenditures, total capital expenditures during the third quarter were $266.5m for exploration and development activities, and then that includes $2.7m for acquisitions. Through September 30th, for the nine months, total exploration and development capital expenditures were $641.2m, including $20.9m of acquisitions.

The Canadian acquisition closed on October 1st, increasing acquisitions to date to $340.9m. Capitalized interest for the quarter was $2.1m, year-to-date it is $6.4m. Our 2003 capital expenditure plans as stated in the form 8K filed yesterday are $1.3b to $1.375b, including acquisitions. Our preliminary estimate for 2004 capex is between $1.0b and $1.1b, including acquisitions. We plan to maintain our 2004 capital expenditures approximately within cash flow.

After capital structure, we ended the third quarter with $184m of cash on our balance sheet. On October 1st we closed the Canadian acquisition of the Husky properties. We financed the transaction with $180m of cash, including the $64m cash deposit made earlier, and borrowed the remaining $141m through the commercial paper line.

At September 30th, 2003 total debt outstanding was approximately $1.011b. The debt to total cap ratio was 32.5 percent, down from 40.6 percent at year end 2002. Factoring in the impact of the Husky acquisition on a pro forma basis, the debt to total capitalization would have been 35.4 percent. We expect continued strength at year end, even after the Husky acquisition. Year-to-date we have executed our drilling program and made the largest acquisition ever in EOG’s history, primarily funded with cash generated from operations. The effective tax rate for the quarter was 34.6 percent, and the deferred tax ratio was 69.9 percent.

The unusually low severance tax rate as a percentage of revenues during the quarter and year-to-date was a result of tax credits for high cost gas wells in the State of Texas. The third quarter 10Q will be filed later this week. With that, I will turn it back over to Mark.

Thanks, Ed. I will now provide our thoughts on the North America gas macro. In our opinion, we are currently witnessing a unique situation where both supply and demand have fallen. Recent third quarter public company North America gas production volumes have continued the trend of declining production, even with higher drilling rig utilization. For 2004, we expect both U.S. and Canadian production to decline 2 percent to 3 percent below 2003. In total, 2004 North America supply including LNG will be 1.5 Bcf a day or 2.5 percent lower than 2003.

However, the strong pace of storage refills indicates that demand is also falling. What do we conclude from all of this? We think that the long-term supply constraint fundamentals are clearly in place, but that we may see some price weakness, if you can call $4.00 to $4.50 gas prices weak, if we have a warm winter. Accordingly, EOG has financial collars in place covering about 40 percent of our January through October 2004 North America gas at a $4.77 floor and a $5.40 cap. These collars are detailed in our 8K filing from yesterday.

We also have some 2004 Canadian physical sales locked in, so in total we have about half of our January through October 2004 North America volumes covered with price protection. This is a higher percentage of our production than we normally hedge or collar, but we felt the ability to collar around a $5 2004 strip was too good to pass up. Regarding oil, we are about 8 percent hedged January to July 2004 at a $28.56 average price.

In summary, we are on track to deliver 3 percent absolute and 4 percent per share of production growth this year, which is consistent with the estimate that we provided at the beginning of the year. More importantly, we expect to grow total company production of 6.5 percent, 10 percent, and 7 percent in 2004 through 2006. Note that a significant portion of the production growth will come from high margin North America gas where we expect to generate 6.5 percent and 5 percent growth the next two years.

We expect our 2006 total company production levels to be 33 percent higher than in 2002. We plan to achieve this growth without stressing our balance sheet, where we currently have the best coverage ratios in the peer group. Most importantly, we will achieve this growth while maintaining either the best or one of the best ROEs and ROCEs in the peer group. We’ve raised our dividend three out of the last four years, this year by 25 percent, and will continue to operate in a shareholder friendly rate of return, focused manner. It’s a good time to be in the E&P business. Thanks for listening in, and Phil, now we will go to Q&A.

Thank you, Mr. Papa. (Operator instructions) Our first question will come from Ellen Hannan with Bear Stearns.

Good morning.

Good morning, Ellen.

Just a couple of questions. Mark, will you book reserves this year on the U.K. gas discoveries?

Yes, Ellen, we will. We’ve got marketing arrangements that we are working on for both of the successful farm-in wells.

And that will sort of allow you to book your share of those reserves?

Yes.

And on your Canadian physical sales that you’ve got locked in, what kind of prices are you looking at?

They are about equivalent in terms of collars. Basically they are physical collars, and they are roughly equivalent to what we have for the U.S. which is about a $4.70 to $4.75 floor and maybe about a $5.70 cap on a Henry Hub basis. Now we’ve got foreign exchange in there and location differential also, but basically that’s what makes us feel like we have about 50 percent of our January through October production locked in.

Okay. And last question for me. You mentioned in your press release about a pilot coal bed methane program that you are about to undertake in Canada. Can you add any details to that?

Yes, let me have Loren Leiker discuss that, Ellen.

Yes, we have drilled or completed now, recompleted that is, 10 hot wells in that Twinning area on coal bed methane cross mix. All 10 have come offline gas and it rates similar to what we think the competitors are seeing immediately south of our area. So we believe our 110,000 acres in this area looks pretty good at this point.

Can you comment on what your initial production rates for gas from the wells is?

It’s fairly early in the production life, and some of those are still rising, so I would be hesitant to do that other than to say that it is quite comparable to what others have seen in the area.

Ellen, what we are seeing on that is unlike some of the other coal bed methane, such as the Pilot River, this stuff does not produce any water. So basically what it is is you have four or five kind of thin stacked coals and you give them all a very small individual frac stimulation, you commingle them and flow them back. We’ve seen enough results from our pilot test from our first round of tests that we are pretty likely to do a pilot project beginning next year.

What we see is this is essentially analogous to our shallow gas activities that we already drilled 1,000 wells a year at in Southern Alberta and Southwest Saskatchewan. So the way we look at this coal bed is it is nothing more than ultimately drilling hundreds of shallow gas wells that basically are water free and produce at very moderate rates per individual well.

Last question. Are you producing out of the Brushing Canyon coals, or what are you producing out of? Do you know?

These coals are called the Horseshoe Canyon coals.

Horseshoe Canyon, sorry. Okay.

I should also mention that we have another 35,000 acres or so in a second set of coals, not on this same prospect but also a candidate.

And is there any opportunity in this area for gas from conventional sands, or are you just going after CBM?

Actually it does have stacked objectives, including oil production from Jurassic rocks in that same area.

Ellen, when we made our conference call announcement about this acquisition we basically said there were two upsides to it over and above what we bought in terms of what we’d consider to be proved reserves. One of those upsides was the coal bed methane, and we kind of checked the box on that one, it looks like it was working. The other upside was a secondary recovery from a zone entwining called a Pachinko zone which is a Jurassic zone. That one will take probably a year to play out. We are undertaking a pilot water flood in a small area there right now, but it’s going to take us six months to really see what kind of response we have.

My guess is a year from now we will be able to check the box on both of those significant upsides on the acquisition and say they both worked.

Thank you very much.

Okay.

We will now hear a question from Shawn Reynolds with Petrie Parkman.

Good morning. I was just maybe wanted to take a broader question with regard to how you continue to, as an industry, generate positive returns. Just looking at operating expenses from Q302 to Q303 just about every line item for you and for many of your competitors are on the upswing. Now I know the margin helps with the high gas prices, but I would expect that F&D charges for most of the industry is going to be up this year as well.

I am just wondering if you have any thoughts about managing the returns and what you can expect going forward if returns are going to flatten out, if they are going to continue to stay reasonably strong or if they are going to possibly shrink?

I’ll give you my thoughts on it. There is no doubt that for the industry and EOG North American finding costs as translated in DD&A rate are going to go up, relative to the past. On the operating cost side they are clearly up relative to a year ago, but I would note that I think most analysts total it up and say we are the lowest cash cost guy out there.

The issue is really the fact that if gas prices dipped to $3 or so, the whole industry will have a problem making margins, and I think the response that you’ll see if we see a gas price drop that far is you will see the gas directed recount fall dramatically, which will then cause us six months after that to have another supply crisis, even more severe than what we are projecting.

So you know, clearly we have a very good margin, in fact for this year we expect to be showing in the range of about a 15 percent ROCE for the full year and about a 25 percent ROE, but I think the kind of trap in your logic, Shawn, is that the assumption that the industry will continue to drill at high levels if the margins shrink, and I think that that will absolutely not happen. I know it will not happen with EOG.

Do you feel poised -- maybe not poised, but you would basically shut it down fairly quickly if you saw prices drop into the $3 range?

I think the entire industry will, if you saw prices drop that far, I think you’d see the rig count fall 200 rigs within 90 days as far as a gas directed recount. I won’t comment specifically on what EOG would do, but I think that convinces me that we are really in a higher priced environment, and I will say also Shawn that this year we are going to average, Henry Hub for the whole sector is roughly about $5.50. I believe that is probably higher than the market clearing price should be. I think the pace of storage injections we’ve seen tells us that $5.50 is probably too high of a price in normal conditions, and what we feel is that gas prices will be volatile around about a $4.50 median price, and that is one of the driving factors that kind of directed us to lock in for 2004 some of the gas collaring around a $5.00 strip that was available at the time.

Right. Those are nice looking hedges. Could you add a little bit more color to the Barnett? You said you had three horizontals drilled. I think at the time of the analysts meeting you kind of had one down, one completing. I wonder if you could add a little bit more specificity to what you are seeing in terms of flow rates. Are you pretty happy with it? Has it been mixed?

Shawn, we have now drilled three horizontals. We are drilling our fourth, two of those are online now, but only for a very short time. We are shooting 3D and we have increased our acreage count to close to 100,000 acres now. All I can say is that from the first couple of wells we have online the results are as projected. We believe we are seeing what we want to see there, both in the production rates and in the course that we’ve taken.

I think that’s about all the color, frankly, we can give at this time because it really is just too soon to tell. These wells that we had online, they’ve only been online generally a week or two, so there is gas there, we think that the most important thing that we’ve seen is we believe our ability to drive down costs is going to be greater than we initially anticipated. At the time of the analysts conference just a month or so ago, we were projecting the average well cost here would turn out to be $1.3m roughly. Right now we are saying we can get it to $1m and we are working on some methodology such as eliminating the intermediate pipe string, casing string, that may ultimately get these well costs down to about $800,000 per well. So we are having real good luck on that side, but we just need to get some production history from these wells we’ve drilled to see, what are we really dealing with in terms of reserve size?

I guess suffice it to say, you are encouraged enough that you are continuing to drill in your program. How many do you think you’ll get down by the year end?

I would say at least three more by year end.

Including the one drilling?

Yes.

Great. Thanks a lot.

Moving on we will hear from Irene Haas with Sanders, Morris and Harris.

I am afraid most of my questions have been answered. Thank you.

Hi, Irene.

From Simmons and Company, our next question will come from Mark Meyer.

Good morning. Close to 100,000 acres that Loren cited in the Barnett Shale, does that mean you picked up about 30,000 in the quarter? Am I thinking correctly, that you were at about 70,000 at the end of last quarter?

I think we’ve added about 20,000 in the last quarter there. Just closer to it.

You cited, I think, kind of a $300 an acre current price. Have you seen any change to that in the incremental purchases?

Anywhere from $200 to $300 is what we are seeing now.

Mark, any change based on what the majors have reported and domestic gas production this quarter, any changes to your views on what this year and next year are going to look like, North America gas production drops, year over year?

No changes, but I will say that the third quarter production as we total it from the majors and the independents is down a bit harder than we would have expected, particularly relating to the year over year costs. And if you look at the third quarter a year ago, they were more severely affected by hurricane activity. I would say what I have seen are the majors are showing production declines more steep than we would have predicted, the independents are about in line with what we’ve predicted, so it just gives me a little more confidence that the range of declines next year are going to be about 2 percent to 3 percent in North America and 2 percent to 3 percent in Canada also.

So what we see, really, is we lay things out just for the next four or five years, even if you lay on some increasing L&G every single year, there is that the total supply available to the U.S. is going to be constricted to the tune of about anywhere between one half and 2 Bcf a day per year, each year, for the next several years. We’re projecting it is going to be constricted by 1.5 Bcf a day in 2004 versus 2003, but the main point is, it is not going to stop in 2004. In 2005, 2006, 2007, it’s going to get further constricted, even though it is partially offset by L&G. The bottom line is, L&G imports increases will not totally offset the constriction.

Right. Along those lines, are you more optimistic that you are going to be able to shake loose more amounts?

Yes, I think so. I think the one we mentioned in this conference call is a horizontal Devonian oil farm-out that we have in the Permian Basin area. We reference that Allan well about 225 bpd. That’s on a reasonably significant sized farm-out and this was an important well because it’s going to allow us to kick off a more intensive program.

And we’re working on several others in terms of farm-outs, so I expect we will continue to see a greater population of these opportunities than we’ve seen historically.

And are the ones you are working on more gas prone?

Yes. Pretty much all of them are gas prone, this one, this horizontal Devonian, it’s odd that it’s oil. Unusual.

Thanks.

Andrew Lees with RBC Capital Markets has our next question.

Hi, Mark. You had mentioned that you only hit one of the formations you were targeting at Oil Bird. I think you had 110 to 225 Bcf pre-drill. I thought it was from three targets. Can you kind of clarify, with one target, that makes it small, does that still mean it is at the low end of the range or is it smaller than that.

Andrew, it is a bit smaller than the low end of the range, which is 110 Bcf. I don’t want to go into specifics, but basically it is enough to set pipe on and we will complete it when we set an Oil Bird platform, but the bottom line is we had two amplitudes that we were drilling for, one of them was a little weaker than the other and the weaker one turned out to be a wet zone, so we only caught one of the two zones.

So we are in the process right now of finishing up cementing the liner in that well and then we will be moving to the lower reverse well which is frankly a higher quality exploration prospect than the first one we drilled. The first one just happened to be a sidetrack out of an existing well bore we had.

Great, thanks.

We will now hear from Van Levy with CIBC World Markets.

Good morning, Mark, how are you?

Hi, Van.

You guys obviously have a great balance sheet. Could you give us a sense of what you are seeing in the deal flow market, is pricing getting more reasonable? And are you, or would you consider, corporate deals, like Quick Silver, that’s right in your area in Canada, looks like a pretty cheap stock on a corporate basis.

Yes, I would say in terms of deal flows, I don’t think we’ve seen a dramatic difference either up or down in deal flows for M&A opportunities or for producing property acquisitions. I would say on the M&A side we are still, it is very doubtful that we are going to participate in that market in terms of swallowing up companies smaller than us. We still are not convinced that that is the best way to get high ROEs and high ROCEs.

The other point that I make is that the acquisition that we made in Canada really sets us up pretty well, so those production growth rates that we are talking about for the next three years, 6.5, 10 and seven are really predicated on us not making any substantive acquisitions during that three-year period other than maybe $50m or $100m a year for a usual tactical acquisition.

So in terms of being set up for the next three years, we are probably better set up now than we ever have been and it would be even greater if indeed this Barnett Shale or the Merna kind of wells work. So I guess what I would tell you is, don’t look for us to be extremely active in either of the producing property acquisition or the corporate deal activity.

Okay, second question. Merna Anticline. Can you give us maybe review the geologic concept, reserve potential, well costs, and give us a sense of when that well will be at the decision point, number one. Number two, there was a stealth well around that area that you were going to spud, what is the status of that?

Yes, Van, Merna, we are drilling our first well on that Merna Anticline right now, which really consists of two separate prospects, so Mark mentioned in the notes at the start here that we had three such wells to be drilled by the end of the year, or at least be spudded by the end of the year, and the first of those is drilling. The other two, as I said, will be spud by the end of the year, I am not sure they will both be down.

That would include, in other words, two prospects on Merna and then the Stealth prospect that we mentioned at the conference a month-and-a-half or so ago. All of these wells are searching for what I call chimneys in the top of over pressure, or built up areas where over pressure rises higher in a section, enhances permeability in those crustaceous rocks. Very similar to the traps built at Pinedale and at Jonah.

We are looking for somewhere in the neighborhood of maybe as little as 2 Bcf, maybe as much as 5 Bcf per well. Well costs, the early well is going to be a little more, of course, because we are doing a lot of testing and a lot of logging and we -- not on a program basis, they are probably in $3m to $3.5m range. On a program basis, we will probably have that down to $2m, $2.5m range. We have right now I think about 30,000 acres at Merna and about 4,500 acres on the other prospect, the Stealth prospect, so easily for 250 to 350 at such locations.

Okay, final question. Mark, just conceptually, what are you most excited about over the next 12 months, and what causes you the greatest concerns?

I think in terms of what I’m excited about over the next 12 months, I would say our bigger target opportunities between the Merna, the Barnett Shale and some of the drilling we are going to do in Trinidad. I think we’ve certainly got a chance to have some break out potential. Our bread and butter stuff is pretty steady and working well, so that is what I would probably be most excited about.

In terms of the biggest concern over the next six months, Van, it’s really a warm winter and that is why we’ve gotten into a bit of a defensive position vis-à-vis hedging. I do believe that if we have a warm winter we are going to see further downward pressure on gas prices, which will pretty directly translate into a reduction in drilling activity for the industry, which will probably set us up for the fourth quarter for some dramatic upswing in prices, and that is why we’ve only hedged or collared gas through October. We’ve really left November and December 2004 open. One, we just can’t predict that far out. Two, there could be a dramatic change in the whole supply/demand perspective by that time, if we have this warm winter scenario.

Great. Thanks.

John Herrlin with Merrill Lynch has our next question.

Pretty much everything has been asked, so I will pass.

Okay, John.

Mary Salfway with [Calls, Poorsheimer & Co] has our next question.

Good morning. I am wondering about your service costs. In the past, you’ve kind of locked some of them in, I’m wondering what your situation with that is now.

Service costs, they declined in the first part of the year, maybe about 5 percent and we’ve probably lost that over the next four to six months, so we are pretty well flat with 2002. We had already locked in, probably mid-year, most of our costs for 2004. That does exclude rigs. We just have a couple of floor and ceilings in place with one or two contractors. Most everything else is pretty well set.

And these prices you say are flat with 2002?

Yes.

Okay. Thanks very much.

(Operator instructions) We will now go to Ken Beer with Johnson Rice.

Hi, guys. Just a follow up on the Barnett Shale. It sounds like you’ve got three wells hooked up, three more to be drilled before year end. What are your thoughts if you look out to 2004, what kind of well count or how many drilling locations might you drill up in 2004 and also, I was just going to make sure, 1 Bcf to 1.5 Bcf per well, I am assuming that is a horizontal well, and your million per well is obviously for a horizontal well.

Yes, Ken. In terms of the cost, all of those reserves and costs are horizontal wells. I guess to scale things on the expectations of the Barnett Shale relative to what we talked about a few months ago at our analysts conference, at that time we were talking about average well costs of about $1.3m and reserves of about 1.5 Bcf to maybe 2 Bcf a well. After looking at it more, both the costs and reserve expectations have come down a bit to the $800,000 to $1m per well cost and probably 1 Bcf to 1.5 Bcf per well. That is just basically looking at a closer look at the few vertical wells and horizontal wells that have already had some production history down in that south area.

What we are doing right now is the wells that Loren described are basically going to be scattered over various parts of our 90,000 acres to 100,000 acres. What we are trying to do is find out, do we have uniform distribution of productivity or is one area better than another. So by year end we will probably have some feeling on that. And then I would say, assuming that we are able to hit the threshold of 1 Bcf to 1.5 Bcf per well, probably in the first half of the year we would still do a cautious one to two rig program just to get more data, and then you could look for us potentially, assuming again we had success in the second half of 2004, to probably ramp that up into something that might be a five rig program or something.

What type of spacing do you think you can look at if you have the 90,000 acres to 100,000 acres? What are the potential locations you are looking at on your acreage position?

Our best guess right now is that a very conservative, and certainly not a tight well spacing, would be one horizontal well every 100 acres. So you could say, if all acres were productive, that would be simply 900 wells. Looking at it from a more technical basis, it would surprise me if ultimately the spacing ends up tighter than that, really, on this.

Well fair enough. I appreciate it. Thanks so much, guys.

Okay, Ken.

And we do have a follow up question from John Herrlin.

I do have one for you on hedging, Mark. Obviously you’ve set a more cautious tone. Is 50 as high as you’ll go in terms of capping on hedging?

Yes, that’s a good question John. 50 percent is the current authorization our board has given management and one of the items that we are going to discuss with our board within the next week is just to get authorization to go up to higher levels. I’m not sure how the board will respond to that, but it is possible that between now and year end or between now and early next year that we could go up a bit higher. I would say that the absolute maximum we would do would be 70 percent, but first we’ve got to get our board to give us permission to even consider doing that.

Okay, and last one for me, You bought in a lot of shares after your immense patience. You’ve been more or less keeping equal with options dilution currently. Your stock hasn’t really been a strong performer this year. Any thoughts to being more aggressive with buy backs as well?

Yes, we always look at that John, but in terms of how we see the capex for next year, I would say don’t look for us to be particularly strong in the buy back market. The reason is, a lot of it will depend on how this Barnett Shale and how the Merna thing plays out, and the coal bed methane in Canada, but if indeed we have one or two of these that actually turn out to be successful, I think we are going to need all of capital for the next several years just in reinvestment opportunities to develop this stuff.

Okay, thank you.

Mr. Papa, there appear to be no questions at this time. I will turn the conference back over to you for final and closing remarks.

Okay, I appreciate everyone listening in for this time, and I relate my feelings again that I feel like, as a company, we are set up better for production growth and more importantly economic production growth, we are set up better then at any time, I believe, in the company’s history. I think how we are going to distinguish ourselves versus the peer group over the next several years is our absolute production growth rate while maintaining very good returns, and two, more specifically our ability to grow North America gas year over year, quarter after quarter, relative to I think some of the other companies out there. So thank you very much and we will talk to you after the next quarter’s earning release. Bye, bye.

Thank you. That does conclude today’s teleconference. Thank you for your participation. At this time you may disconnect.