SWN - Southwestern Energy Company
Q2 2007 Earnings Conference Call
August 1, 2007
Officers
Harold Korell; Southwestern Energy; CEO, President, Chairman
Richard Lane; Southwestern Energy; President, E&P
Greg Kerley; Southwestern Energy; EVP, CFO
Analysts
Scott Hanold; RBC Capital Markets; Analyst
Tom Gardner; Simmons & Company International; Analyst
Joe Allman; JP Morgan Securities; Analyst
Brian Singer; Goldman Sachs Group; Analyst
Jeff Hayden; Pritchard Capital Partners; Analyst
Michael Scialla; AG Edwards; Analyst
Michael Bodino; Coker & Palmer; Analyst
Robert Christensen; Buckingham Research; Analyst
David Heikkinen; Pickering Energy; Analyst
Travis Anderson; Gilder, Gagnon & Howe; Analyst
Presentation
Operator: Good day, everyone, and welcome to the Southwestern Energy Company Second Quarter Earnings Teleconference. At this time, I would like to turn the conference over to the President, Chairman, and Chief Executive Officer, Mr. Harold Korell. Please go ahead, sir.
Harold Korell: Good morning, and thanks for being with us today. I have Richard Lane, the president of our E&P company here with me, and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release we announced yesterday regarding our second quarter results, please call 281-618-4784 to have a copy faxed to you.
Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.
Well, to begin with here, we've had a very productive first half of the year and we've had--we've made a lot of progress at our Fayetteville Shale play. Our production growth of 57% over the second quarter of last year shows the strong impact of our Fayetteville Shale play in our results. However, we are also having very good results in our base activities in East Texas and the conventional Arkoma Basin, as Richard will discuss more in detail in a moment.
We continue to grow our capabilities to carry out the increased activity levels this year, as we've added now about 175 new employees in the first half of the year. For the remainder of 2007, we plan to focus our Fayetteville drilling activity in areas that have been identified as better performing, and where possible, in areas where we have 3D seismic data. Generally, now we are moving to the slickwater fluid systems for our frac jobs in the Fayetteville, and we've begun drilling longer laterals, which coupled with additional completion stages seem to result in better wells. So we're continuing to make progress in our Fayetteville project and we're seeing good results in our other base project activity areas.
I'd like to now turn the conference over to Richard for a discussion in more detail about our operating results and plans.
Richard Lane: Thanks, Harold. Good morning. Our natural gas and crude oil production totaled 25.8 Bcfe for the second quarter of '07, up from 16.4 for the second quarter of '06. The increase was primarily due to growth from our Fayetteville Shale play, which produced 10.7 Bcf in the second quarter of '07, compared to 8.2 in the first quarter of 2007, and 1.8 in the second quarter of 2006. So our buildup continues there. We continue to estimate that our full year production will range between 107 and 110 Bcfe.
In the first half of 2007, we invested approximately $670 million in our exploration and production activities and participated in drilling 304 wells. Of the 304 wells, 142 were productive, five were dry, and 157 were in progress on June 30 for an overall success rate of 97%. Of the $670 million invested, approximately 568 million, or 85%, was for drilling. We currently have 31 rigs running, 15 deep and four shallow rigs in the Fayetteville Shale play, seven in East Texas, four in the conventional Arkoma Basin, and one in North Louisiana.
In the Fayetteville Shale play, we drilled and completed 62 wells in the second quarter. The wells drilled range in total vertical depth from approximately 2,300 feet to 5,300 feet with horizontal sections that averaged approximately 2,550 feet. During the second quarter, our time to drill to total depth averaged 18 days from re-entry to re-entry, compared to a first quarter average time of 20 days. Average completed well costs during the second quarter were $2.9 million per well, compared to the 2.6 average cost we reported for the first quarter. The increased cost is primarily due to drilling and completing wells with longer horizontal laterals.
Lateral lengths for second quarter wells have averaged 2,550 feet, compared to 2,100 feet in the first quarter. For the remainder of 2007, the majority of our Fayetteville Shale drilling activity, as Harold mentioned, will be in areas that have been identified as better performing to date, and where possible, where we have 3D data. We plan to complete the vast majority of wells going forward using slickwater stimulations. We also plan to use open hole packer systems on as many wells as possible. Our analysis indicates that both the slickwater stimulations and the open hole packer systems yield better performing wells.
We are also seeing better well results from drilling longer horizontal laterals. In the second quarter, we drilled 10 wells with laterals longer than 3,000 feet. These wells had an average initial production rate of 2.1 million cubic feet per day and an average estimated cost of 3.1 million per well. Our Bartlett well, located in the South Rainbow pilot, had a 3,700-foot horizontal lateral. After completing it with an eight-stage slickwater stimulation, that well had an initial production test rate of 4.4 million cubic feet per day and was producing 4 million cubic feet per day after being on production for about 25 days.
Our most recent wells, those put on production from July 1 through July 21, have an average initial production rate of 2.2 million cubic feet per day. And the last 10 wells we completed have an average initial production rate of 2.6 million cubic feet per day. Of these 10 wells, three had initial rates at over 4 million cubic feet per day.
In the southeastern part of the play, our Reaper 1-12 well in our Bull pilot was put on production in mid-July at 4.6 million cubic feet per day, which I think represents our highest rate to date. In our press release, we provided an updated normalized average daily production for horizontal wells completed with slickwater and/or crosslinked gel frac fluids.
As we have noted before, we are continuing to see variability in the play and the well performance across our pilot areas. And as you review this new data--new updated production data, there are a few things worth nothing relative to the prior reporting period. One, the initial production rate is approximately 200 Mcf per day higher, showing the effect of some recently improved well results. Second, we have slightly lower rates in the zero to 180-day period, and this shows the effect of some of the poorer wells, like our East Cutthroat area. And third, and favorably, a flattening of the decline in our oldest producing wells.
Production from the Fayetteville Shale play area is now at approximately 200 million cubic feet per day, including approximately 10 million cubic feet from five conventional wells in four separate pilot areas. This production milestone is particularly notable in that we began drilling wells just three years ago, and at 200 million cubic feet per day we have doubled the rate during 2007 alone.
Going forward, we are confident that we have adequate pipeline takeaway capacity to keep pace with our growing production. Four of our five conventional wells are producing from the Hale reservoir, and the remaining wells are producing from the Orr sand. We are currently completing four additional wells in three more pilot areas east of where we currently have established conventional production, and are planning on drilling several more conventional tests before the end of the year.
We continue to be very encouraged by our conventional exploration program in the Morrowan section, and have begun to recognize some deep potential below the Mississippian section. This should be further enhanced by our ongoing 3D seismic program.
Our second horizontal test of the Moorefield Shale, which underlies the Fayetteville Shale on the eastern portion of our acreage, appears to have treated out of zone and is mostly water. We're currently analyzing the Brooks #3-27 well--its frac data--to try to understand this. We continue to believe that the Moorefield is prospective and are currently completing the Brooks #1-20 well in our Midge pilot and the Russell #1-35 in our Tiger pilot for the Moorefield shale. We also plan to drill a couple more Moorefield tests by the end of the year.
We plan to invest approximately $950 million in the Fayetteville Shale project area during 2007. This capital investment includes participating in approximately 400 horizontal wells in the play. We are integrating many new people into our operation, and we Harold mentioned, we're experimenting a lot with new technology and continue to move forward with assessing our vast acreage position.
Moving to the Arkoma Basin, the conventional assets, we have had a very positive first six months of 2007. We have invested approximately $86 million here, drilling 59 wells, of which 45 were productive and 11 still in progress at the end of the quarter. We are continuing to put good wells on production at our Ranger Anticline and Midway areas. As a result, production from the conventional Arkoma Basin assets was 6 Bcf for the quarter, up 25% from the second quarter of '06. In the second quarter, we placed 12 wells on production at Ranger with average initial production rates of 2.6 million cubic feet per day. Our current gross production at Ranger is approximately 50 million cubic feet per day, and we estimate that we have an inventory of over 140 potential wells remaining to be drilled here.
At our Midway project, we have drilled enough to know we have opened up a new gas field here. Our initial test well here was drilled in late 2005. Since that time, we have drilled 21 wells and will drill an additional 15 to 20 wells in the remainder of '07.
In East Texas, we've continued our active drilling programs with four rigs at Overton and three at our Angelina River Trend. In the first six months of '07, we invested approximately $100 million drilling 26 wells at Overton Field and 13 wells in our Angelina River Trend, one well at our Jebel prospect, and two wells in other areas. All of these wells were either productive or in progress at the end of the quarter. Production from East Texas was 7.5 Bcf in the second quarter, compared to 7.8 Bcf last year. And we've nearly offset this decline attributable to slowing down our drilling program at Overton by ramping up our activity in other East Texas projects.
We are currently testing the first well on our Jebel prospect that we drilled in the second quarter. The Timber Star No. 1 is located on approximately 16,500 gross acres that we farmed in late last year, and is currently testing at a rate of about 3.4 million cubic feet per day from the Travis Peak. Since obtaining the farm-in, we have added approximately 16,000 additional acres in the area, for a total of 32,000 gross acres.
In addition to the Travis Peak, we believe that this acreage may be a candidate for horizontal drilling in the James Lime. And we are currently drilling our second well on that block right now.
In summary, we are pleased with our year-to-date results. Our Fayetteville Shale play is advancing extremely well. It holds a tremendous inventory of wells for us to pursue and to organically increase our production and reserves at very meaningful rates. Our other assets are performing well also, and together our producing property portfolio provides a predictable, long-life producing base with more opportunities left to develop on them.
I will now turn it over to Greg Kerley, who will discuss our financial results.
Greg Kerley: Thank you, Richard, and good morning. Our earnings for the second quarter were $47.6 million, or $0.28 a share, up 29% from the prior year. Our record financial results were driven primarily by the positive effect of our earnings--of our increased production volumes and higher realized natural gas prices.
Net cash provided by operating activities before changes in operating assets and liabilities increased to $146.8 million, up 74% from the prior year. We produced a record 25.8 Bcf in the second quarter and realized an average gas price of $6.90 an Mcf, which was up $0.67 from the prior year period. Our commodity hedging program also increased our average price by about $0.07 in the quarter.
Our current hedge position, which consists of fixed price commodity swaps and collars, provides us with support for a strong level of cash flow. For the remainder of the year, we have approximately 75% of our projected natural gas production hedged. We have 26 Bcf hedged with fixed price swaps at an average price of $7.90 per Mcf, and we have 17 Bcf hedged through price collars with an average full price of 6.85 and an average ceiling price of $10.64.
We also have hedged 85 Bcf in 2008 and 48 Bcf in 2009 at even higher prices than those in 2007. Our detailed hedge position is included in our Form 10-Q, which was filed yesterday afternoon. Our lease operating expenses per unit of production were $0.73 per Mcf equivalent during the second quarter, up from $0.64 from the same period last year. The increase was primarily due to increases in gathering and other costs related to our operations in the Fayetteville Shale. For the full year, we expect our unit lease operating cost to range between $0.82 and $0.87 per Mcf.
Taxes, other than income taxes, were $0.21 per Mcf during the quarter, down from $0.39 in the prior year period, and we expect our rate to range between $0.21 and $0.26 for the full year, assuming a $7 average NYMEX gas price for the balance of the year.
General and administrative expenses per unit of production were $0.48 per Mcf in the second quarter, down from $0.60 in the prior year, a decrease in G&A cost per unit of production, which is primarily due to our increased production volumes. We expect our general and administrative expenses per unit of production to range between $0.41 and $0.46 per Mcf for the calendar year. Our full cost/full amortization rate was $2.41 in the second quarter, and we expect our average rate for the year to range between $2.20 and 2.40 per Mcf.
Operating income for our midstream services segment was $2.3 million in the second quarter, up from $800,000 in the same period a year ago. The increase in operating income was due to increased gas gathering revenues related to our Fayetteville Shale play.
Our natural gas distribution segment realized a seasonal operating loss of $1.7 million in the second quarter, compared to a loss of $2.1 million during the same period last year. The improved results were primarily due to colder weather. In July, the Arkansas Public Service Commission approved a rate increase for our gas utility of $5.8 million annually, which became effective today.
At June 30, 2007, we had total indebtedness of approximately $497 million, which includes $360 million borrowed under our revolving credit facility, resulting in a capital structure of 24% debt and 76% equity. Our $1.3 billion planned capital program is expected to be funded by proceeds from our cash flow borrowings under our revolving credit facility and/or funds raised in the public debt or equity markets. Assuming our capital program is funded entirely through cash flow and borrowings, we expect our long-term debt-to-total-capitalization ratio to be approximately 35% at year-end.
That concludes my comments, so now we'll turn back to the operator who will explain the procedure for asking questions.
Questions and Answers
Operator: Thank you. (Operator Instructions.) We'll go to Scott Hanold of RBC Capital Markets.
Scott Hanold: The recent results that you've been getting actually seem pretty strong. Can you talk about anything that you may have changed? Have you changed the way you are drilling as well as drilling patterns, or have some of those wells been drilling sort of with the benefit of seismic data?
Richard Lane: Yes, Scott. I think there are some of both there. We're trying to--as we mentioned in our comments, trying to take advantage of the 3D seismic wherever we can, which I think generally is--right now, we would categorize that mostly out of the steering and geologic control tool, so we get some benefit from that. And then, the longer laterals--we have more completed lateral foot and we're seeing the results at least in the initial potentials there.
Harold Korell: I think the other aspect of that to mention is we had some poor results in areas like East Cutthroat and New Quitman off in the southeast part of the play. And those have been watering down the performance that we've seen quarter-on-quarter. And without that activity coming into this quarter in most recent drilling wells we're seeing the benefits of having focused some of the drilling activity away from there.
Scott Hanold: Okay. Well, specifically with that 4.6 million a day well, the Reaper well, especially since it had such a relatively short lateral length, I mean, what do you think happened there? Why were the results so good at that well?
Richard Lane: Well, it's not entirely obvious, Scott. We had a good completion go off there and there have been some other good wells in the area. The rock looks good there. And so, it's not clear why that is an emulous as high as it is, although we've seen that variability in the play. We could be seeing some more natural fracturing around that well bore, but we're not sure about that.
Scott Hanold: Okay. And then secondly, you indicated you're going to be focusing on certain areas, including where you have 3-D seismic. Can you talk a little bit about those areas and where you expect to have all the seismic by year-end?
Richard Lane: We have 3-D seismic right now over seven of our pilot areas. We continue to acquire data as we speak and we'll be requiring data throughout the year and processing data, so we're moving as many wells as possible into those areas.
I think going forward in '07, what we have left in front of us, probably we'd be somewhere around 30 to 40% of the wells will be under seismic coverage.
Harold Korell: And just from a reference standpoint, for those of you who have seen the bubble map that's in our Investor Relations book or the map that's in the press release yesterday with the pilots, generally the area that we have been shooting 3-D in is the area that's from Gravel Hill on the west side going easterly towards the Southwest Greer Lake area. So generally the 3-D is in that part of the field.
And the reason for shooting the 3-D there, of course, is we've scattered wells across this whole area. We have much less -- many fewer data points in the eastern part of the play at this point in time. We have more data points, in other words, more wells drilled in that area from Gravel Hill to the Southwest Greer Lake pilot areas. So we focused our 3-D over there and it makes sense to be able to follow the 3-D with drilling behind it.
So we still will continue to be drilling wells over in the easterly area, because there's a lot of acreage still to assess. But, we're going to have a combination of both going on. And as Richard said, about 30% of the wells going forward will be drilled in areas behind the 3-D. So it's still not a high percentage, but generally over in the Gravel Hill to Southwest Greer Lake area we have a lot more data there, well control and now the 3-D beginning to unfold alongside of that.
Scott Hanold: There's another operator out in White County shooting some 3-D as well. Are you going to be able to get your hands on some of that, too?
Richard Lane: We have arrangements with another company to be able to purchase their seismic and conversely they can purchase our seismic.
Tom Gardner: I believe Richard mentioned plans to drill additional wells to the Moorefield in Chattanooga. Could you discuss where you are with respect to commercializing those intervals and if there's any commingling potential with the Fayetteville?
Richard Lane: Sure, Tom. We've delineated on our public data what we think is perspective for the Moorefield. If you look at our most public data you'll see the subset outline of the Fayetteville that kind of describes that. And it's generally on the eastern side of the play. Kind of an update, remember we had our first horizontal well I believe was the Carter in the East Cutthroat area that we put on production. We were encouraged there. It wasn't a barnburner or obviously commercial, but producing gas and for our first try.
The second well is not very good at all and we're kind of scratching our head trying to understand the data. It's not very far from the other one. But, we've produced a lot of water and a lot more than we should have just from the stimulation, so it tells us it's probably extraneous water, so we're not sure where that's coming from. We'll be doing some studies to try to figure that out. So, a couple more wells right on the horizon here soon and then from what we learn on those wells, maybe we spud a couple more later in the year.
But I wouldn't say we've established commerciality. It is what we've called it, which is another potential zone and we'll be working at trying to understand it through the rest of the year. Commingling it is another challenge. If we could do that, then it would help the commerciality of the whole picture. But right now, the technology, the down-hole technology is not really quite there to have both those laterals multistage frac'd and producing up one well bore. That's an example of technology yet to really come to fruition that could affect that and affect the play.
Tom Gardner: I see. One last question then regarding stimulation effectiveness in these longer laterals in the Fayetteville. Are you concerned at all about the effectiveness of the stimulation treatments at the tow of the well?
Richard Lane: Well, we're concerned with making sure we get the most out of our stimulations and every stage that we pump we want it to be effective, obviously. I don't think preferentially at the tow we have much greater concern than any other given stage. But our goal is to get the most out of every stage that we pump and then to monitor those and try to understand how we're doing. And so we have quite a bit of data that lets us know how each stage has done in various wells.
Joe Allman: I know it's early days, but what would be your best guess regarding the EURs with the longer horizontals? And is it reasonable to assume that if the initial production is maybe 30% above your type curve that the EURs could potentially be 30% above the 1.5 or 1.3, whichever type curve you're looking at?
Harold Korell: Well, Joe, that's too broad of a question, I think. And the reason that I think it's too broad is that we have such variable results across the play area. Specifically, longer laterals across the whole play, you know, a longer lateral in some parts of this I don't think is going to be as effective as it is in some others. For example, you know, on this east Cutthroat area, that may not be effective enough to get us to a point where we need to be.
Now, your other part of the question is it, basically if you're seeing IPs that much higher is it going to translate to EURs? The answer to that is, if the decline curve performs parallel to the other one, the answer is, yes. What we need to have is time on the performance of those wells, just as we've said from the beginning of all this, we've been a little bit reluctant to step out very far in terms of saying what ultimate, you know, moving numbers higher.
We're getting more comfortable now, because as Richard mentioned in his comments, our oldest well now is getting pretty flattened out, so we're getting to the point, at least on 1 to 3 wells, you know, maybe 3 wells total in our package, where we can start to see what these terminal decline rates are looking like. We'd like to have far more data than that before we tell you some higher number, if that's what it's going to be.
But higher IPs tend to, in general, if you're going to follow the same type of decline as other wells, then you would have higher EURs. I think that you can see that if you look at the average daily normalized production graph that we put out for the average of all the wells. And then if you look at just the East Cutthroat one, which is our poorest performing area and then the other line that's on that graph is gravel hill, which is our best performing, you know, clearly when you start out higher with those kind of similar declines you're going to produce more. And I don't know if it's 30% more, but we'll learn that a little bit more over time.
Joe Allman: Okay, that's helpful. And in terms of the pilot areas that will be more the focus for the rest of this year, so far I think you've tested 33 pilot areas. How many pilot areas will be the focus between now and year-end?
Richard Lane: I don't have that exact number, Joe. Last time I looked I think we had about -- this is not specific to your pilot answer, but we had about 20% of the wells remaining in '07 that were still out in the less certain areas, if that gives you some feel for the concentration.
Brian Singer: I guess following up on the last question and some of the earlier ones, you mentioned some of the pilot areas you will be focusing on. Any areas aside from East Cutthroat where you purposely have less of a focus, can you kind of talk about that regionally?
Richard Lane: We've updated our bubble map, if you will. I think that data's out there that we've put out commensurate with our earnings. There's a lot of uncertainty there. I mean, we've talked about some areas that we've gotten a higher well count in, like East Cutthroat and enough wells to kind of say, based on those results, it doesn't look too good.
A number of other areas we really just have single well tests and we're still trying to understand those. So the jury is really out on those. And then what we can bring to bear, even on the poorer areas that we've identified so far is there's still more we can do there. But, you know, we were talking about really more like probably 75% of the pilots that we've drilled in we'll be more focused on in the western side.
Brian Singer: Okay. And then in terms of your theory from the impact of some of these higher rates, do you see, assuming that the declines are in line with expectations leading to higher EURs, does that represent an increase of the recovery rate or would that just be an acceleration of recoverable resources?
Richard Lane: Well, it's kind of like it could be both, I guess. Not to avoid the question, but if you just think of pure spacing, if you drill longer laterals then you have coverage of -- if you just take a 640 section, kind of our unit premise, drill longer laterals within there, then you would cover the unit, if you will, with less wells and then you might say that that translates into higher recovery per well in that unit if everything else is static. So it's really kind of hard to pin that down. There's a lot of variables in that question, Brian.
I think, you know, the other thing is, we're still experimenting with the orientation of our laterals and that has a significant bearing on the number of laterals we can put in a unit. So there's a lot of moving parts there. We've been experimenting some with drilling north/south laterals instead of on the diagonal and that affects how many you can put in a unit as well.
Harold Korell: I think the key part of it is, if you're getting higher recoveries per well then you would just generally not be drilling as many wells per section, which is a good thing.
Brian Singer: Any update in terms of the service cost environment with increased competition that you're seeing in the Fayetteville?
Richard Lane: Well, this year we're driving our own ship, if you will, on the drilling side there with the predominance of our own company-owned rigs in the play. On the completion side, we've kind of held our own I think there. A combination of getting some improved pricing within the play, offsetting some of the higher cost things we're doing in the completion. The pure third-party side of it, the vendor side of it, we actually have some slight discounts over last year.
Jeff Hayden: A couple of quick questions. First of all, I'm wondering if you could give us a little color on those most recent 10 slick water fracs, were those all concentrated in kind of one or two pilot areas or were those spread out over a number of the pilot areas you guys are currently working on? And then after that, just wondering if you guys could comment a little bit on spacing, you know, what you guys are seeing? Is 80-acre spacing going to be the right number, you know, could it potentially go tighter than that? And I may have a follow-up to those.
Harold Korell: Let me address the last question first. The spacing question is still up in the air about this play. We are by no means have drilled down to the point where we're talking about the optimum spacing at this point. And that goes back to the discussion on the question Brian asked to some extent. If we drill longer laterals, then you have less wells per section, which would say if you divide it by 640 that would be less tight spacing.
But at the end of the day when you look at this Fayetteville Shale play, and I would suggest -- here's a pitch that some of you that I've had meetings with, I've put you onto, but for the rest of the world that's listening, the North Texas Geological Society book that was published that George Mitchell funded to have written, called the Barnett Shale, which goes into the years of development that went into the Barnett -- I recommend anybody interested in unconventional plays ought to buy it and read it. And when I read it, the conclusion you have to draw about it is there's a whole lot to learn about these plays.
And at the end of the day, my reading of that book and others here internally, whose comments I've received, is my gosh, you know, we're learning each of the steps that was learned in the Barnett. And one of those big ones in the Barnett is spacing. You know, whatever you conclude at one point in time with a limited amount of data is probably wrong and you keep seeing them go to tighter and tighter spacing.
And so on the spacing question, these rocks hold tremendous amounts of gas. And the spacing question isn't just a today question. And particularly, we're not at a spacing point yet. We're still drilling wells scattered across a very large area. And then we're considering moving into, say, one of these areas this year and calling it kind of a full development area. We're not even in development phase here in anywhere. We're still drilling sparsely placed wells. We're thinking about taking an area which we would go into and actually test getting into development mode.
So we'd see what is our well cost on a development program? What is our completion cost on a development program? Can we optimize many aspects of this like building locations and all? That would also possibly involve reorienting some wells. We've drilled, as Richard mentioned, some north/south wells rather than the preferred north westerly direction and we're getting pretty darned good results out of those. Well, if you can do that, it changes the geometry of how you lay out your well bores in a positive way.
And so, there's a lot to be answered about spacing.
And, guys, we can’t answer the spacing question now, because any answer we’d give you would probably change in, you know, in a year. So kind of – hopefully, that can kind of cover that spacing arena.
And, Richard, you might discuss these other wells that have been drilled.
Richard Lane: I think, Jeff, I think the other part of your question was on the last ten wells, it looked pretty good, what was the – you know, where were they or were they concentrated. I think there’s eight different pilots that those were drilled in so they actually represent a pretty broad area which is, you know, is encouraging, it’s not just one hot spot, so eight different pilots making up those wells.
Jeff Hayden: Okay, great. And then one quick follow-on. You know, you talked about basically not even being in development mode yet. You mentioned costs. It seems like a lot of the other – you know, once people have gone into development mode they do find ways to optimize things, push costs down. You know, is that a reasonable expectation for us to make that, you know, it’s still really early on and once you really start going full development mode we should see those kind of per well costs come down?
Harold Korell: Yes, once we’ve settled on the basic design, but as you – be sure that you keep in mind as we’re drilling longer laterals they’re going to cost more, not just because of the drilling but, in addition, because of the additional fracture stimulation. And our real task is to figure out where is the optimum level there.
Gil Yang: Good morning. Just following on the same line of questioning everybody else seemed to be focusing on. The ten best wells are they drilled, and maybe you mentioned this, are they drilled with seismic or without seismic? Or what made that consistency so good, what was different?
Richard Lane: Well, they’re not all under 3-D seismic, Gil. Probably maybe half of those, something like that were under 3-D seismic. I think the improvement is just the, you know, the constant monitoring of what we’re doing and the technologies that we’re applying and, you know, just trying to improve each well as we go forward.
We have, of course, we have longer laterals in those wells and we have less of a mixed bag of the types of fluids. You know, as we reported, we’re concentrated on the slick water fracs. So I think it’s a refinement of where we’re heading and there’ll be more changes still, but –
Harold Korell: And, Richard, if I might add to that, there are going to be multiple factors that come into play in these plays, some of which we don’t know in advance, so I guess I would say one of the obvious reasons that those 11 or 10 wells were better is they weren’t drilled in core areas.
Richard Lane: Yes.
Harold Korell: Now, you might say to me, “Well, how do we define that?” And it’s a good question, but maybe it opens up eyes to be able to really understand it. So, you know, when we have been drilling in areas where we have no control, and if you pull out the map that shows the bubbles again, any bubble that’s blue means there’s not very darn much control there because that means that that’s either the first or second will drilled there, and on those blue bubbles as you look around them they’re 10 to 20 miles from the nearest blue bubble.
And so any time you’re drilling where you don’t have control you’re not going to know very much about what you’re going to find. Now, so you – that may lead to the conclusion, well, some of those areas may be poor, and some areas in this play I think will be poor, poorer, just as they were in the Barnett. Some parts of it’s going to – we’re going to turn out some day I would guess, we’ll be able to say what the core area is and what the noncore area is, much like they’ve described over time in the Barnett. And the likelihood is, you know, the core area is going to be very good economics, the noncore is going to take more work to make it actually economic.
So some of it is that, just simply that, Gil, is when we drill in areas where we have well control and seismic and production information, and then maybe where we’re using the right frac jobs, we’ve done – in the past we did – we were doing a lot of crosslink gel jobs, and there was a lot of controversy which was the better way to do this, and we’ve now are completely concluded in house that where we can do it slick water jobs are the best outcome.
And then we’re also seeing some pretty darn good results out of these open hole packer jobs. They cost a little bit more to do, so the costs may offset the better performance, it may be equal, so there may not be an economic gain, but then if we can make headway on those completions by changing and not having to run the 7-inch casing then we’ll have an economic gain there.
So we have a combination of factors going on here that are affecting the results, but in areas where we have quite a lot of experience now and where we have more control over we are getting better results. And so it will drag the average up, but that’ll be gradually now because averages are averages. We have all of what we have plus whatever new ones are coming in.
Gil Yang: Okay. And the second question I’ve got is have you been able to do some postmortems, so to speak, on – we’re using 3-D shot over wells that have not been particularly good, have you been able to determine what makes those areas – and what has made those wells not good and, thereby, come up with a solution to that problem?
Harold Korell: Well, very clearly, we know when we drill through fault zones we don’t get good wells, and that is – that’s been a factor, certainly, and where we have our oldest data set, in Gravel Hill, wells we drilled through fault systems and much like, read the Barnett book, much like in the Barnett, when you do that you’re either losing the frac energy in that fault zone or there’s some mineralogical changes along that from waters moving through it over the years or something that caused it not to do as well. And then when we orient wells away from that we have good wells. So, yes, clearly we know that. I don’t think it’s much of a coincidence that Gravel Hill is one of our best areas and where we’ve had 3-D the longest.
Gil Yang: Okay. Terrific. Thank you very much.
Michael Scialla: I guess at the risk of beating this to death, I just wanted to ask one more time about those ten recent wells, if they do continue to perform the way you’d expect, can you venture a guess as to the average EUR on those ten?
Richard Lane: I think Harold has kind of really framed that well already, Mike. I think the answer is, no, I don’t want to hazard a guess. The obvious thing is that we’re getting better near-term performance and you would hope that would translate into better overall well performance, but it will depend on how they conform to the declines that we’ve already seen.
Michael Scialla: Sure.
Richard Lane: If they do that, then we ought to get something good from it.
Michael Scialla: Okay. And then on the spinning plans for the Fayetteville this year, you’re saying $950 million. Has that gone up? I saw that one point, or looking at like $840 million or is there some allocation issue there, or am I just misreading that?
Greg Kerley: No, Mike, that is the number that Richard talked – it included the gathering that we have, too, so there’s about $840 million, you’re right, of E&P and then the balance is – or is that – excuse me – that was about $875 million of E&P and there’s – the balance is gathering.
Michael Scialla: Okay.
Richard Lane: The number hasn’t changed. That’s right.
Michael Scialla: Okay. Thank you.
Michael Bodino: A couple of questions here. One is on the conventional sands, you’ve had some very good wells and the rumor is that Hallwood’s well was conventional sands that produced 6 million a day. How big of a play can these conventional sands become as part of this whole program?
Richard Lane: Well, that’s – you know, it’s undetermined. I think the exciting part about is if you’d look at the map that shows where the conventional zones are that we have – conventional wells we have producing, they’re across a pretty darn broad area, so it’s a pretty exciting potential. I mean if you go over to the Fairway, we know what that looks like, and there’s a tremendous resource there that has been harvested through the years.
We have less zones to chase than what exists in the Fairway area, but nonetheless we’ve encountered this – these zones across a really broad area and some of them have been outstanding producers when you would compare them to a typical well that you might drill in the Fairway right now. So I can’t quantify it for you, Mike, but we sure like the – what we’ve seen so far.
Michael Bodino: Is what you all are seeing on the kind of western side of the play in terms of maybe the Hale sands different than what maybe they’re seeing out in White County in terms of the conventional zones or are they all the same conventional zone?
Richard Lane: I think it’s the same general stratographic section that people are looking at and having some success with.
Harold Korell: The interesting thing about it, Michael, to me, is that this really has not been worked. And we are only beginning now to do the work. And, of course, one of the reasons that there hasn’t been a lot of work been done on it, there haven’t been a lot of well penetrations. And now as we’re drilling wells through that section we’re, you know, we’re encountering these gas shales, and then it’s a matter of starting to put maps together with what data you do have.
And as that 3-D sweeps across here that’s going to be a huge improvement on our ability to look for these conventional zones, and then the conventional pays become a very real key and important part of the play because they’re very inexpensive to drill, first of all, and rates, when you’re getting 3 or 4 million a day out of a well that cost you $700,000 to drill and complete, there just – those are kind of homerun economics.
So we’ve got people now specifically mapping in the conventional which we’ve not really had an effort on up until now, we’ve been so focused on answering all the questions that we have and everyone else has about the Fayetteville, but on the way down we’re getting a look and it’s not just limited because we now have gas coming out of wells that are spread across, I don’t know, 50 or 60 miles here, from east to west.
And so, basically, we have an unexplored basin and no one really knows the extent of it, and the section that’s just shallower than the Fayetteville, and then who knows what’s deeper. You know, the majors made a play in here for the Arbuckle in the ‘70s, but there are potentially other parts of that section that we haven’t even begun to put our binoculars on.
Michael Bodino: Will this be part of your program in ’08?
Harold Korell: It’s part of our ’07 program, certainly.
And then in some, you know, we have some of those shallower rigs that are capable of drilling some of these, too, so we can get on them pretty, pretty quickly, and kind of natural completion so they’re not as expensive, so, yes, we’re very focused on it.
Robert Christensen: That’s a breath of fresh air, talking about the conventional. On that same subject, you had the Lawrence Well, in Faulkner, and the Tharp.
Harold Korell: We can’t hear you, Bob.
Robert Christensen: You had the Lawrence Well, in Faulkner, and the Tharp in White County, both were designated Hale completions, and on the day that we got from the Arkansas and Gas Commission we didn’t get an IP. Would you care to venture what those two wells did in their first (inaudible)?
Richard Lane: Let’s see, I’m just looking at your data, Bob. I don’t have that in my head, but I think I have some – the data here. The Tharp tested about 2 million cubic feet per day, and we’re waiting on the hook-up for that. And what was the other one?
Robert Christensen: The Lawrence, 8-12, that was in Falkner?
Richard Lane: Yes, the Lawrence was about 1 million a day.
Robert Christensen: Okay. So, okay, well – and how many more Hale attempts did you say you would – conventional attempts you would have this year?
Richard Lane: I said several, I didn’t say exactly, but we have I think four wells that are not in that producing base we’ve talked about waiting on completion or hook-up to pipeline, and then we’ll be – I don’t know exactly how many but what we’re trying to gear-up to do is to have kind of a small rig program that we can get enough of these locations, offset locations mapped where we can just stay after it with a rig.
Robert Christensen: Are these future wells here, say, second half, to the Hale, are they done on 3-D or are they just geologic sort of mapping at this point in time, or is the 3-D already bearing fruit for the conventional?
Richard Lane: Well, some are within 3-D and some are not, so it’s a combination of working all the data, you know, and I would tell you when we’re offsetting one of these good ones we’ve already had we’re trying to get a geologic handle on the shape of the sand bodies and trying to offset them in the most certain place to start with. Others we have some 3-D and we have got some interesting work going on looking at the 3-D data to see what kind of second order things we might glean from it that relates to the conventional production.
Robert Christensen: Finally, you indicated something below the Fayetteville shale, I mean are you, you’ve seen Arbuckle on the 3-D yet?
Richard Lane: Well, we see, you know, we see very deep into the section with the new data that we’re acquiring, and it’s good data. We can see – seismically we can see very deep in the section which would take you down through that. I think, you know, an interesting section below the Fayetteville but yet above the Arbuckle, some interesting carbonates that exist and are productive in the basin to the west, and have some very interesting structural styles to them that give you some hope that you can have carbonate traps of significance, but that’s, you know, that’s really speculative right now.
Robert Christensen: One final question, if I may, what happens when we put compression on one of your older Fayetteville wells? Say, we go out on that well that was graphed and it’s 640 days old, what happens when you put some compression and draw-down the surface pressure? What kind of response do you think would we see? We’d be adding reserves if we added some field compression?
Harold Korell: Well, we’ve – yes, I mean we have compression in the field now, that’s how we – I mean we eventually pump this gas into the transmission lines that are 1,000 PSI, so we have to have compression to pull the gas from our well bores. So there are opportunities throughout the field to optimize that compression as we get further into the development, we would have some wells that may have a higher wellhead producing pressure that if we drew it down would produce currently at higher rates, and then you would get the increment of gas that would be, that would become, say, if you were producing at 150 or 200 pounds wellhead pressure and you draw it down to 50, the PVT is going to tell you you’re going to get more volume ultimately, so.
Robert Christensen: That would change the EUR?
Harold Korell: Yes, yes, that could pull – you’d pull incrementally more volume out with lower pressure, it’s just simply the physics of it, but right now I don’t think that has much of an impact on the numbers as we’re looking at them today, but ultimately I mean that’s what happens in every gas field if you keep putting more compression on it then ultimately you get a little more gas out over the years.
Robert Christensen: Thanks. Great progression there in the Fayetteville.
David Heikkinen: I just had a question about for a new play like North Louisiana or Appalachia to be core for Southwestern, how big would it need to be?
Richard Lane: Oh, you mean what kind of a resource size?
David Heikkinen: Yes, exactly. Resource size, what would be your scope and desire be to get into a new area?
Richard Lane: Well, I think it depends on the economics, David. And it would depend on how much traction we could get in a new play and how much of it we can control. It's kind of hard to quantify. Obviously, as we grow, we're looking for projects that can have an impact. It just would have to be specific to each area.
Harold Korell: I would say it's baseball season and when we go to bat sometimes singles are okay and sometimes doubles and sometimes triples and sometimes you steal a base and sometimes you try to hit a homerun.
David Heikkinen: Okay.
Harold Korell: So it could be all sizes. It depends on the risk and the situation we're in.
David Heikkinen: The one rig running in North Louisiana, how big of a play is that?
Richard Lane: Well, that's a coal bed methane play.
David Heikkinen: Right.
Richard Lane: I think there is more acreage there. The full extent of the play I don't think we fully understand, but it's in the low hundred Bcf type range and then -- and could grow from there, depending on how much acreage we can pull together.
David Heikkinen: Current acreage is where there?
Richard Lane: Our gross acreage amount?
David Heikkinen: Gross and net.
Richard Lane: I don't have that in front of me, David. We'll get -- we can get that to you though.
David Heikkinen: And then, kind of looking forward where you are now in the Fayetteville with the number of wells awaiting completion and then how that moves forward as you go into a focused development, what do you think the backlog of wells will be in the third quarter and fourth quarter as you move forward?
Richard Lane: It's a challenging part of the project for our operation folks to manage and every time we think we know exactly where it's going to be it will swing pretty dramatically. And if we get some efficiencies in drilling, all of a sudden we're eating into that inventory. But I think 20 to 25 wells is kind of a reasonable inventory of wells waiting on completion to have. We have seen that if we get a lot less than that then maybe there is some waste in the logistics that would be more of a factor than the discounting or waiting on the capital. So I think we're in about 25 right now and -- which doesn't feel too bad.
David Heikkinen: Okay. So no big upswings or downswings as you put a rig in and try to run that going forward.
Richard Lane: Yes. And we have -- the completion units there that we have running, we seem to be keeping pace with that and we have resource that we could add to that if we need to. I think CBM acreage is about 28,000 gross and 20,000 net, David.
David Heikkinen: And then, just your production per area in the second quarter? I have the Fayetteville and East Texas. Could you just pick through that?
Richard Lane: Yes. The Permian was 1.2 Bcfe; Gulf Coast, 0.3 Bcfe; just about a tenth out of the -- our unconventional assets, new stuff, and --
David Heikkinen: And then, conventional Arkoma?
Richard Lane: 6 Bcf.
David Heikkinen: Okay.
Richard Lane: About 25% higher than year-on-year same period.
David Heikkinen: That's perfect.
Travis Anderson: Got a minor question. I notice that you said that you got about 76,000 acres now held for production, which would imply that you've only brought on about 120 wells net; is that correct?
Richard Lane: Well, we have some -- we're holding 640 acres with a producing well, but we have units where we have more than one producing well in a unit. So it's not that simple.
Travis Anderson: Okay. I thought you all were really widely scattered.
Richard Lane: Yes.
Travis Anderson: Okay.
Joe Allman: Regarding the conventional wells in the Fayetteville shale area, it seems that the production is holding up fairly well from the initial rates; is that right? And also please confirm the costs at around $700,000 of drilling complete for the average of those 5 wells. And then, do you expect to have, like, a 1 to 2 rig program going forward in that play?
Richard Lane: Well, I think you -- you're correct on the flatness of the productive rate has got us paying attention to it for sure. So we're seeing wells produce in the 2, 3, and 4 million a day and holding up very well. So your observation is correct there, Joe. I think that's a really nice looking production. And those well costs I think are in line for kind of the average of what we would see there. Because, like I said earlier, they're shallow, or Harold said earlier, they're shallow and we can get to them pretty quick and we don't have a lot of completion costs for those. Fairly simple completions to get those kinds of rates, so we're not having to pump big stimulation.
And then the rig program is -- we're just going to have to flush that out here later in the year. Certainly wouldn't -- don't know how much -- how many rigs we would have on just that program next year, but we're trying to -- kind of a goal for me right now is to try to get where we can have one of those shallow rigs stay busy, at least later in the year here, but it just depends how many locations we can get mapped up and get through the integration process and things.
Joe Allman: Helpful. And in the Moorefield -- in your map there, you mapped out kind of the area that you say is prospective for the Moorefield. What is the data that you have that tells you that that specific area is more prospective for the Moorefield versus a -- stuff to the south, southern part of your -- more central development?
Richard Lane: Well, it would be, I guess the -- how we have delineated that prospective area would be where we see it thickening and it’s not as thick in other areas and where we see decent attributes on the logs that tell us it's a gas-bearing organic-rich shale. So, I mean, that's how -- roughly how we have outlined that prospective area within our acreage. And then going much further south off of our acreage, we haven't looked that hard at that.
Joe Allman: But I mean have you taken your Fayetteville shale wells deeper just so you can have a look at the Moorefield or are you looking at older logs that previously went to the Arbuckle or somewhere?
Richard Lane: Both. Both. We have purposely deepened pilot holes, strap tests to go through the Moorefield to get a look at it and to gather data.
Joe Allman: Got you. And then, that Bartlett well, what was the cost of that Bartlett well, horizontal well?
Richard Lane: Oh, let's see, I think that was about $2.9.
Joe Allman: Even though it was a fairly low lateral, it was cheaper? I know it's kind of an average but cheaper than other --
Richard Lane: Yes, we'll have to confirm that for you, Joe. What we have going on in the well costs that is probably worth noting, we try to give this reporting of comparison of previous quarter, but obviously the other things that go into that are where are the wells being drilled? We have shallower parts of the play and deeper, and so the waiting of where those wells are would affect a period-on-period reporting, and then, -- and obviously, the length of the lateral, so all of that goes into it.
Joe Allman: And then, just lastly, can you make any comments on what's going on in the kind of West Texas Barnett/Woodford/other stuff?
Richard Lane: Our holdings out there?
Joe Allman: Or just any activity. Any insights into that play? Any updates?
Richard Lane: Well, it's still up -- I think there is still a lot of up the air there. We're seeing a little bit more well data, but not a lot of it, and it's pretty scattered. So I think the jury is still way out on that play. It's such an enormous area that has been leased up. It's hard to believe that it's all going to be good and it's also, to me, hard to believe that there isn't going to be some part of that's good. But we're -- as we reported before, we're kind of watching and waiting there a little bit with those higher cost horizontals.
Michael Bodino: Real quick question. I know we talked quite a bit about this earlier in terms of different variability in these wells and I just wanted to ask Richard a question. A couple of years into this, how would you assess, even in some of your core areas the variability, is it depth of the reservoirs, if the reservoir is at completion, length, lateral? I mean -- and I assume that in every area you get a curveball on some variable out there that you have to work on, but is there any good rule of thumb that you would look at and say in certain areas certain variables are more omnipresent?
Richard Lane: Well, I would say this, that we don't have the -- we don't see the criteria that would say certain depths are where it's going to be good and other depths are where it's not going to be. We've seen the variability within areas at different depths, so that's not -- I don't think that's the real driver. I think the main variability, and I'll give you a general answer, but we haven't figured all of that out yet, I think the main variability will be in the rocks and the quality of the reservoir and how those rocks react to being fracture stimulated. But we're seeing that variability in a macro and a micro sense, Mike.
Michael Bodino: Okay.
Harold Korell: I think in -- I mean, I've got to add to that, because how the rocks react when they're stimulated also means structural features that are present in the area where you're drilling. So the structural things like faults are important.
Michael Bodino: Yes, clearly. There seem to be a lot of questions regarding this and I think -- sounds like a lot of the focus is on the frac design more than anything else and I just wanted to clarify that it may be more reservoir driven than anything else.
Harold Korell: Well, it's a good point, Michael. Every one of these elements will be important. And I think that any point in time that you believe you know the answer in these kinds of reservoirs, until you have more of the data unfolded, you don't -- you just don't know for sure. We know for darn sure that if we don't pump a good frac job, if we only get two of the stages done, that's a poor well. So right off some of that answers some of them. Mechanical problems, if you don't have a good cement job, the frac doesn't stay in zone. So within given pilot areas we know we've had those kinds of difficulties. So, simply, the frac stimulation is really important to it. But then the structural things, we know in Griffin Mountain, where we first began drilling, we had pretty poor results in a number of vertical wells. And then we moved away from that fault zone and started getting bet ter wells. So we know that's important. And then the gas in place, the original rocks, the clay contents, all of those things are going to be important. But when you're drilling in -- what's -- the other important thing is there is 100 miles across here where we're producing gas in the east to the west direction. And so you know there is gas in there. The question is -- and, well, and the other thing, Richard didn't say this, but it's obvious, is thickness is also important.
Richard Lane: Yes.
Harold Korell: There are some areas here where, like East Cutthroat is about 100 feet thick. We talked about that at the last conference call. Why is that? So understanding those macro geological things are important. And we're just now all getting the -- starting to get the picture by drilling enough penetrations so that we can understand the big picture geology. If you go back to the -- read the -- read the Barnett book, don't just listen to the news, go read that book, and you'll see what's unfolding here.
Michael Bodino: That helps a lot. And I know statistically we're getting a lot more wells drilled, so we're hearing a lot more good wells and just trying to understand whether it's we're getting in an area that we're -- everybody has gotten more comfortable with and that's what -- the creation of that or whether it's something else.
Harold Korell: I think it's a combination of all of the things because there will be certain areas that you identify that are really working well, so you want to poke some holes in there, continuing to drill on new sections where you can. But we also need to continue to poke holes where we don't know the answers yet, so that we can begin -- that we can evolve to an answer.
Joe Allman: In terms of the slickwater, why do you think the slickwater is working better than the crosslinked gel?
Harold Korell: It was a more complex fracture treatment and connects up with more of the rock for a dollar that we pump in there.
Joe Allman: Okay, that's helpful. And just a quick one, the Jebel for the Travis Peak, that was a vertical well?
Harold Korell: That's a good question. Richard.
Richard Lane: Yes. It's a vertical Travis Peak well.
Joe Allman: Okay. Got it. And then, Richard, you made a couple of points earlier in the presentation and you were saying that, like, one thing, three things observed, you said the IPs are 200 Mcf higher and then you were talking about slower decline. What was the other point that you were making on the recent wells?
Richard Lane: The IPs are a little higher, so you're just -- you're seeing some of those good wells affecting that big data set, and it's a big data set, so they have to pretty good to push it up.
My comment is that in the 0 to 180 day kind of period, if you compare the old data set, the old data set was a little higher in that period, not very much but a little bit, and so you're seeing some of the effect of some of those poor wells washing through.
The third point I made was that in our oldest time production data we see a nice flattening in the conformance, if you will, to kind of how we have typed curves. That's, I think, a real positive thing for us to be seeing. It's just a few wells, as Harold pointed out, but, boy, that is sure what you want to be seeing.
And what I didn't say really, a fourth point would be, is if you go the 180 to two quarters more on top of that, you'll actually see that we're a little higher in that period relative to the prior reporting.
Joe Allman: And you made another point in response to another question about the Moorefield and you were saying that the technology is just not there yet for the Moorefield. What technology were you referring to specifically? I'm sorry.
Richard Lane: I think that was a sub-question that was asked about dually-completed.
Joe Allman: Dual completed, okay, got you.
Richard Lane: Just a mechanical challenge right now to do that. We hear about dual horizontals and things, but when we're trying to isolate and do multi-states fracs and multiple laterals, that's where the real challenge is.
Harold Korell: The Moorefield, yes, I wouldn't want you to get off base on that. I mean, they -- the thing -- where I see the Moorefield is we have an area where we've delineated where it could be prospective and we had one well that looked pretty darned good. We drilled in it. The Carter well. And then the follow-up well Richard just talked about is producing a lot of water. It's producing more water than we put in there. We don't think it's coming from the Moorefield section itself, but we must have frac'd, generally we think we frac'd into something deeper that has water in it. So we've got to go back and deal with how do you keep that from happening. Or maybe there is some fault system near there that we are latched up to and it's bringing water. We won't -- we don't know the answers, but, again, it may be like some portion of the Barnett turned out, where they had some water problems below the Barnett getting into the Ellenberger and we maybe have that happening with the Moorefield and have to figure out how to deal with it. But we are so early in the Moorefield, we just started and we've got a lot going on, so it's hard to say maybe even we should try to focus a whole lot on the Moorefield right now, as far as our activity, in my mind.
Joe Allman: Okay, very helpful. Thank you.
Operator: At this time there are no further questions in the queue. I'll turn the conference back to Mr. Korell for any additional remarks.
Harold Korell: Okay. It's been one of our longer ones. I think we're at about an hour and 15 minutes now. So I appreciate all of the questions. They're good questions. I think it helps everyone get a better understanding of what's going on here. And here we are now, I guess, about 3 years into the drilling activity. Seems like a long ways. It's not much compared to 18 years in the Barnett before things started working. So I think we're -- the benefit of what they've learned there, but we're still early in this. It's a big area. If we were focused in, say, 50,000 or 60,000 acres of leasehold position here, I think we could tell you everything, but it's 900,000 and it takes a lot of drilling and a lot of understanding and a whole lot of work. That's where we are. Appreciate your time. Thanks.
Operator: That concludes today's conference call. We thank you for your participation.
