SOUTHWESTERN ENERGY COMPANY
Southwestern Energy Company Announces Fayetteville Shale Play in Arkoma Basin Teleconference
August 18, 2004
| Participants: | Harold Korell; President, Chairman and CEO |
| | Richard Lane; Executive Vice President, Exploration and Production |
| | Greg Kerley; Executive Vice President and CFO |
Harold Korell: Well, good morning, and thank you for joining us today. With me today are Richard Lane, our Executive VP of Exploration and Production, and Greg Kerley, our Chief Financial Officer.
If you have not received a copy of the press release we issued yesterday, you can call Pam at 281-618-4809, and she'll fax a copy to you.
Also, I'd like to point out that many of the comments during this teleconference may be regarded as forward-looking statements and involve known and unknown risks and uncertainties, many of which are beyond our control. Although we believe the expectations expressed in these forward-looking statements are based on reasonable assumptions, our actual results may materially differ from those expressed or implied by such statements. We encourage you to refer to our filings with the Securities and Exchange Commission for a discussion of the risks and uncertainties that may affect our Company's performance.
Yesterday, we announced that we have begun testing a new unconventional gas shale play on the Arkansas side of the Arkoma Basin. We are currently drilling test wells, targeting the Fayetteville Shale, an unconventional gas reservoir, ranging in depths from 1,500 to 6,500 feet. Our Fayetteville Shale play currently includes approximately 455,000 net undeveloped acres, approximately 110,000 of which were acquired in 2004, including a sizable block we acquired last week.
For competitive reasons, we have not discussed the details of this play until today although our New Ventures disclosures in our 10-K for 2003 included over 343,000 acres that are part of the play area. We also control approximately 120,000 net developed acres in the Fairway area of the Basin that are held by conventional production. We've recently begun to test our concept, and our results to date are encouraging. Richard will discuss the details of our drilling program in a moment.
To date, we've invested approximately $18.5 million to acquire leasehold in the play area, including $11 million expended during 2003. During 2004, we plan to invest a total of approximately $20 million in this new shale play, including approximately $8.5 million allocated to drill approximately 20 wells in the area to test our concept.
Although there is a significant amount of data yet to be collected in order to confirm the economic merit of the play, we are encouraged by what we have seen to this point. Through the remainder of this year, we will continue to drill test wells to delineate the aerial extent of the shale and the optimal completion techniques. If our testing yields positive results, we expect that our activity in the play would increase significantly over the next several years.
I'll now turn the teleconference over to Richard Lane, who will provide more details about the play, and then we'll take your questions. Richard?
Richard Lane: Thank you, Harold, and good morning.
I'd like to begin by describing how we've formulated the concept for this play, to cover the technical analysis we've conducted, and finally give an update on our land and operational activity.
In late 2001, we recognized an incongruity in the amount of gas production that was attributed to completions in the Wedington Sandstone. The Wedington Sandstone is located immediately above the Fayetteville Shale sequence. In several incidents within the Fairway area, more gas was being produced than we would have expected based on the Wedington thickness, petrophysical properties, and aerial extent. We believe that the Fayetteville Shale has likely contributed to these unusually high production volumes and that it might, in fact, represent a legitimate, objective reservoir.
We undertook and completed an extensive geologic study to understand the distribution of the Fayetteville Shale throughout the entire basin, including its burial and thermal history. During 2002, we obtained Fayetteville Shale core samples associated with our drilling of development wells in the conventional Fairway drilling program. The samples were analyzed for the critical shale properties necessary for successful shale gas plays. The analysis indicated encouraging data relative to total organic content, which ranged from 4 percent to 9.5 percent, thermal maturity, which ranged from 1.5 to 4.0, and total gas content, which ranged from 60 to 220 standard cubic feet per ton, which we believe compares favorably to other productive shale gas plays, including the Barnett.
The analysis, along with an extensive geologic mapping project, allowed us to high-grade the prospective area and to commence acquiring a land position in early 2003. Land acquisition has gone well, and we now have leased approximately 455,000 net acres at an average cost of approximately $40 per acre. The average primary lease term on this acreage is over 9 years, and our average royalty burden is 12.5 percent.
As Harold said, we also control approximately 120,000 net developed acres in the Fairway area of the basin, as held by our conventional production.
In early 2004, we drilled 2 wells to sample the shale in areas with less well control, and in June, we initiated a pilot well drilling program. We have recently drilled and completed 4 vertical wells in the Fayetteville Shale and are encouraged by our results to date. The test wells are located in Franklin, Conway, and Van Buren counties in Arkansas, and we have found that the Fayetteville Shale extends throughout the tested area and appears to be laterally extensive, ranging in thickness from 50 to 325 feet. The 4 wells have responded to fracture stimulation techniques and have shown preliminary production rates in the range of 150 to 500 MCF per day after 10 to 20 days of testing.
In conclusion, while we are encouraged by the results to date, we recognize that the results are still preliminary and that we have a significant amount of data yet to collect in order to confirm the extent and the economic viability of the Fayetteville Shale play.
Our plans for the remainder of this year include drilling and completing approximately 16 more wells and to continue a program to determine optimal completion techniques, which may include horizontal drilling applications.
That concludes my comments, so now we'll turn it back to the operator, who will explain the procedure for asking questions.
Operator: Thank you, sir. [Caller instructions.] And we'll take our first question from Sam Arnold with Friedman, Billings, Ramsey.
Amir Arif: Good morning, guys. It's actually Amir Arif. Three quick questions for you. First one, on the capital expenditures for the year, $8.5 [million] is going to be spent on wells. Can you tell us what the rest of the money's going to be spent on this year? Is it more acreage?
Harold Korell: Yeah, within our plan, it's for acreage acquisition.
Amir Arif: Okay. And second question, how much thickness do you need generally for these wells to be productive? I mean you mentioned a range from 50 feet on. Is that sort of the minimum cut-off you would need?
Harold Korell: Amir, we -- what we've done to this point is drilled the wells that we've talked about and measured thicknesses that we have discussed. We've had initial test rates, as Richard and as the press release indicated.
As far as the -- I think your question really probably goes more to the economic merit of the play. We're in the early stages of it right now. I can't say that I can tell you a minimum number of feet that's required to make this -- to make this play work.
Amir Arif: Okay. And just one final question here. In terms of -- in terms of the drilling profile going forward, so the 20 wells this year, and then do you have any idea how many you'd be drilling next year? I guess it depends on the results of the 20 wells?
Harold Korell: Yeah, clearly, it does. You know, we've planned 20 total for this year. We've drilled 4 that we've talked about, and we have a rig out there we're currently drilling. We'll be drilling, completing, and, you know, everything in the future depends upon how the results go. We have very preliminary, you know, 10 to 20 days of production history on these wells. We do not have the first well put into sales yet. That should happen fairly soon, though, and so we're at a preliminary stage.
Amir Arif: Okay. And, actually, one final question if you permit me here. Do you have kind of a -- I'm not really sure exactly where this play lies, but it sounds like you do have other conventional wells which are drilled through the targeted horizon, so you've got a good sense of the aerial extent of the play as is?
Harold Korell: Well, when we talk about having the 120,000 or so acres that's held by conventional production, in our presentations in the past, we've referred to that as the Fairway area in most of our discussions, and that's where the Atokan sands produce. We call that the Fairway, so, you know, that -- that area basically has been on production for many, many years, from 40 -- 40-some years. So, you know, within that area, there's a lot of control, and then basically, we've extended our acreage play in the unconventional area to the East.
Amir Arif: Okay. Terrific. Thank you very much.
Operator: We'll take our next question from Van Levy with CIBC World Markets.
Van Levy: Good morning, folks. How are you?
Harold Korell: Good. How are you, Van?
Van Levy: I'm doing real good. Thanks. A couple of questions. You didn't -- in the press release, you didn't talk about implied, you know, reserves per well. What -- do you have any sense of what that is, Harold? It's -- I know it's early -- and what it has to be to make the well costs, which looks like, if I did the math right, about $420,000, or $425,000 per well, to make that work?
Harold Korell: Well, you know, we really aren't talking about that right now. I think it's too early for us to want to put numbers out there like that. I would say that -- I'll leave it to you, right -- you guys right now to, you know, look at -- what we've tried to do -- I'm going to put it this way. What we've tried to do is put out the raw data that we have. We've talked about gas contents, thicknesses, some of that information, and we have just some very early production data. I mean, one, we could set -- we could probably set here and take all the information, calculate it, you know, and could do, and calculate a gas-in-place and presume some amount of recovery factor and speculate at a number. But I don't think it's really appropriate for us to do that right now because the realities of this will depend upon what the production profile and decline, the actual production performance looks like, that we ultimately project reserves off of. And since we have only 10 or 20 days of production history on a well, I don't want to be in a position of putting that out there right now.
Van Levy: Okay. And in your mind, what kind of -- I guess approached from the different side of the coin -- what kind of finding costs do you have to have to make this, you know, to hit your PVI kind of hurdle? Is it $1.00 finding cost or 80 cents or --? Because it's -- that gets into the, I guess, the profile, etcetera. The longer, obviously, the lower the number has to be.
Harold Korell: Well, it's -- you know, again, until we have some more production history and are able to look at the production performance, you know, we're not really going to try to answer that question now.
Van Levy: Okay. Is the $425,000 -- is that -- would you expect it as a number per well, or is that higher because you have maybe some extra testing or something in there?
Harold Korell: Well, we've estimated that. You know, that's our budget sort of number, and the first few wells we've drilled have sort of been in that range. We've been doing a lot of testing that one wouldn't do in wells once you get on a -- you know, on a manufacturing process here because we're taking core samples, special logs, doing a lot of things, also doing some things in the completions on a controlled sort of environment to keep the parameters constant so that we can see the effect on this rock, as the completion technology is one of the big, important parts of getting this right. So, yeah, we're doing a lot of research work while we're doing it current -- in our current program.
Van Levy: Okay. And what are the royalties out there, and what are the rentals, annual rentals?
Harold Korell: Richard, do you want to --
Richard Lane: In my comments, I mentioned that the royalties are 12.5 percent, so --
Van Levy: It's a little low, okay.
Richard Lane: That is an average for the -- for our lease block, so it's pretty attractive.
Van Levy: And annual rentals?
Richard Lane: And the rentals are just -- are very minimal.
Van Levy: Okay. I guess the last question, I was talking to a couple investors, and one of the questions that came up was, you know, why announce this now? Why wasn't this announced on the conference call and then kind of the -- about when, you know, there's some sort of equity deal. I'm looking at your balance sheet. It looks like you have, you know, ample room there. So the timing of the announcement, is there -- what was that driven by?
Harold Korell: Well, as -- as most people know, we have talked about having a New Ventures effort for the past year, and in each one of our presentations, we've talked about having an amount of money allocated, and we, in the course, have not said where that was going for competitive reasons. And that's been the reason we have not talked about this publicly until this point in time.
Last week, we completed the acquisition of another pretty large piece of land, and so that was a key thing and in terms of, you know, getting another area pretty much sewed up, and now we feel like we've reached a point of materiality here where we need to -- you know, we need to be going public with this.
Van Levy: And the debt, as we speak today, roughly is?
Harold Korell: Greg?
Van Levy: I think it was $53 million at the end of the quarter --
Greg Kerley: We --
Van Levy: -- from the bank debt, I'm talking about.
Greg Kerley: We ended the second quarter, Van, at 42% debt, and we have significant level of capacity, close to $275 million in capacity, on our revolving facility right now.
Van Levy: Okay, so the bank, so the bank debt hasn't moved that much from the end of the quarter then?
Greg Kerley: That's correct.
Van Levy: Okay.
Greg Kerley: From a stand -- from a financial standpoint, we are very well set to do what we need to do in this play.
Van Levy: Yeah, it looks like it. Well, great. Congratulations. Wish you well.
Operator: And we'll take our next question from Phil Juskowicz with Buckingham Research.
Phil Juskowicz: Hi. Good morning. Just wanted to -- I didn't get a chance to look at a map. Where is this relative to your Fairway on -- does the Fairway include the Ranger Anticline or is that off to the south?
Harold Korell: Well, the Ranger Anticline is off to the south. The Fairway area would be that northern blob of acreage we've been drilling in since the mid-1940s, and so when we talk about this area, we would be talking -- this play, we'd be talking about generally some of the Fairway area and then acreage to the east of that.
Phil Juskowicz: Are there any synergies that you can get from your service providers? In other words, like whoever's drilling the wells out there for you? Are they helping you out here, too?
Harold Korell: Well, we're getting a lot of help. There's a lot of expertise in the industry on shale plays today with all the big guys in terms of technology, and obviously, we are making use of every bit of that. You know, as we look forward, you know, assuming that this works, and that we move into a much larger operation, we certainly hope to have, you know, some things worked out with drilling providers and so on like that. That will be a good thing for them and us.
Phil Juskowicz: Okay, thanks.
Operator: And we'll take our next question from H.B. Juengling with RBC Capital Markets.
H.B. Juengling: Good morning.
Harold Korell: Morning, H.B.
H.B. Juengling:How are you today?
Harold Korell: Doing pretty good.
H.B. Juengling:I guess so. Hey, spacing on this -- any thoughts there as far as wells are concerned? I know it's really early.
Harold Korell: Well, it is -- I think it is -- it is too early to -- we don't know anything more than looking at analogous-type plays. This is Mississippian shale. It was deposited at the same time the Barnett and Caney were, and so, you know, that -- I think that's about all we know, and until we get further into this, we have just a -- really, a minimal amount of production history from 4 wells. So we can't say much about drainage. We could -- you know, we could do the normal shale-type assumptions, but I think the real answer lies in how these wells perform.
H.B. Juengling: Okay. And then as far as the horizontal well, how many horizontal wells are in that -- the budget for the balance of the $8.5 million?
Harold Korell: One or two.
H.B. Juengling:Okay. And when would they be drilled?
Harold Korell: I'm not really sure of the exact schedule, H.B.
H.B. Juengling:All right. And then what would be -- do you have any idea what the kick might be as far as production would be from those horizontal wells? Or, again, I know it's still....you don't have one down, so it's hard to say, but could you postulate?
Harold Korell: No, I really couldn't. I don't know.
H.B. Juengling:Okay. And then last but not least, can you describe the gas? I mean is it -- are there any problems with it? Is there any -- is it rich or BTUs or anything of that kind of stuff you can give me?
Richard Lane: No, it's -- this is Richard -- it's -- you know, from what we have, from what we've tested so far, it's dry gas. We don't see any problematic components to the gas. And in normal BTU range, we've seen from our other production.
H.B. Juengling:Okay. And then you've mentioned Franklin, Conway, and Van Buren. Are there any other counties that look prospective where you have acreage in?
Harold Korell: Well, we're not completely going to address that today.
H.B. Juengling:Let me guess. There's some acreage out? I appreciate your answers. Thank you very much, gentlemen.
Richard Lane:You bet.
Operator: [Caller instructions.] And we'll go next to Jason Selch with Wanger Asset Management.
Jason Selch: Hello. This is Jason Selch with Wanger Asset Management, and I have Bob Christensen here.
Bob Christensen: Yeah, I'm traveling today, guys, so thanks for the heads up here. The gas content per well you gave, what does that compare to versus the Barnett Shale? Again, I'm out of the office. How much gas content per,....per ton over there?
Richard Lane: That's, you know, that's, there's a lot of published data on the Barnett that you could look at for yourself.
Bob Christensen: Right, I'm out of the office.
Richard Lane: What we're showing is that it ranges from about 100 to 200 standard cubic feet per ton. And then that play is evolving, so that number might change. And then we're in,....we're in a similar range of 60 to 220 feet.
Bob Christensen: Okay.
Richard Lane: Standard cubic feet per ton.
Bob Christensen: Thank you. Second question, if I may. On the better well, the 500 MCF a day, was that completed differently? Or was it thicker coal? Can you just tell us what....shale? Was it - did you do something different on that well, or was it just geologically better rock, or what do you think?
Richard Lane: It's....you know, the way we're approaching it, Bob, is to maintain a consistent completion technique, not change it over some course of the program so that when we see changes in the performance of the wells we can maybe limit that to the changes being associated with the rock that we're seeing. So the answer is no, it wasn't a different completion technique. And I think we'll see variability,....continue to see variability like we show in that range.
Harold Korell: Well, and just to add to that, the things that are variable or were different are - we have completed wells that have different thicknesses. And in addition to that, they're in different areas. And so, you know, going by what we know about the Barnett, you do see variability, you know, across a broad area. Like we've moved a few counties here, you know, between wells.
Bob Christensen: When do you think you might try your first horizontal, Harold?
Harold Korell: Well, you know, that was asked earlier. I don't know the exact schedule. What I'm most interested in right now is keeping some things consistent so that we learn more about the rock and how it responds to fluids. When you get into the horizontals what we know is completion fluids and technology are even more critical because you've got a hole open for a longer period of time, and you've got cleanup issues in those horizontals. So, you know, right now I think it's important for us to do what we're doing in vertical wells and to, you know, work on the fluids and understand how the rocks react to those before we start spending a bunch of money drilling the horizontal wells out here. That's my own personal feeling on it.
Bob Christensen: Sure, so you just stay the same type of well each time, and then the rock tells you something?
Harold Korell: Yeah, and then we can begin to vary the frac fluids here.
Bob Christensen: What are you using now, currently? What's your current modus operandi there?
Harold Korell: We're doing nitrogen fracs which we think should be, should do a limited amount of damage. They're expensive to do and -- but you know, our intention here at the beginning is to start out that way. We may not be doing as large a frac on, you know, currently as we should be doing. We've not done any slick water frac which seems to be common practice in other shales, but we wanted to start off with something that, you know, sort of a controlled environment here.
Bob Christensen: Okay. Are you near pipeline access? Must be, because it's on top of the - it's below the Fairway. You must have existing production. Taking it away must not be a problem, right?
Harold Korell: At this point it certainly is not.
Bob Christensen: Yeah. Well, thank you very much.
Operator: H.B. Juengling with RBC Capital Markets.
H.B. Juengling:Hey, guys. When you talk about the Wedington having a, you know, abnormal amount of gas content, is there any way to quantify how much more gas content you saw there than what you anticipated?
Harold Korell: Well, H.B., when we talk about content, the Wedington is a fairly shallow sand that produces in just a certain aerial extent of the fairway area, and over the years various companies have drilled into it and sometimes had found, you know, quite good production, and other times not very much production. And, you know, that was what really led us here in the first place.
As Richard said, we couldn't understand why some of those wells had produced as much gas as they had. Based upon their aerial extent and the porosity, one would have predicted a lesser total volume than had been produced. And our guys got to looking at that and said, 'Well, you know, possibly some of that gas has been coming from the shale.' And so that's,....so I think that's what's important about it is to understand that probably some gas in some of those old Wedington sand producers have been coming from the shale.
H.B. Juengling:Right, and the shale is a kitchen, right?
Harold Korell: The shale is where probably the source for most of this production in the Arkoma Basin is.
H.B. Juengling:Okay. But I mean as far as the Wedington sand, have you quantified how much additional gas, and what you expected out of the Wedington based on the knowledge of those wells, to the point where you can get an idea as to how much, you know, excess is? I guess it must be significant enough, worth testing the shale, right?
Harold Korell: Well, yeah. And you know, what we've done is way back when we started this work in '01, started to look at this Wedington and actually looked at exact numbers. And you know, the Wedington is not a big producer in many areas itself. In fact, it's only present over a small part of the fairway. But apparently it was acting as, we were producing the gas that was in place in the Wedington. Probably we were also producing some gas from the shale.
H.B. Juengling:Right, right.
Harold Korell: Unknowingly all of those years, possibly.
H.B. Juengling:Right. I follow. Okay. Thanks.
Operator: And we'll take a follow-up question from Van Levy with CIBC World Markets.
Van Levy: A couple of other questions. The timing of the drilling, it's just one rig that you'll be running? Maybe drilling, you know, three, four wells a quarter, or how would this work?
Richard Lane: Yeah, Van, that's what we're doing. We have one rig out there. It'll move back and forth through the areas we want to test, and just stay busy out there and get us to about that number of 20 for the year.
Van Levy: Okay.
Harold Korell: And our plan is, you know, we're going to react to how this goes, as well. So, you know, we're not stuck on one rig running.
Van Levy: Right. And then the, I guess,....not the spacing but the amount of, are these going to be, you know, kind of a mile apart to prove-up an area? Or are you going to focus on kind of one area that you think is productive and just try to get the, you know, production right?
Harold Korell: We'll be doing a little bit of both.
Van Levy: Okay. I don't know if it was answered, the BTU content of this gas? Is it, you know, abnormally low, or?
Richard Lane: No, it's -- what I said is with what we've been able to see so far it's typical of the basin, or you know, not far from 1,000 BTU content type gas, so no problems there.
Van Levy: Okay. And then maybe you answered this already, Harold. But in conventional reservoirs, you know, you essentially do a lot of, you know, pressure buildup work, and you know, try to back into the properties for produceability there. And shale plays, can you do that? Or is it just simply, you know, what you said, watching the production?
Harold Korell: Well, I mean there are predictive ways to look at this, using gas content, you know, per ton, and calculating the aerial extent of it, and the tons, and gas-in-place, and work from there. You also do the absorption curves which give you some information about that.
We have kind of....what we have done, we haven't kind of, we have put out basically the range of data that we have. And it is a range, it's not consistent across the area, but we have put out the ranges that exist, and we just aren't at a point of wanting to give you because we're uncertain enough about what the results are going to be. We're just not at a point here today, and it's not our style to be speculating too much on reserves.
Van Levy: Right.
Richard Lane: The other thing I'd say, Van, is that, you know, when you're in these unconventional reservoirs the typical kind of pressure versus production and rate versus time analysis that you would do is not as straightforward as the conventional reservoir, so.
Van Levy: Horner plots don't tell you very much, right?
Richard Lane: Well, it just, you know, the permeability is orders of magnitude different, so you have to approach it kind of the way that Harold was describing.
Van Levy: Okay. And then finally, Richard, is this gas dry or will it require plants to process?
Richard Lane: It's dry. It's, you know, the Basin is best described as a dry gas basin which is very low liquids of any sort.
Van Levy: Okay. Great. Thanks.
Operator: [Caller instructions.] And we'll go next to Marshall Carver with Hibernia Southcoast Capital.
Marshall Carver: Yes, good morning. A quick question on....so the average well would be about $425,000, you know, for the number of wells that you're drilling this year and the budget? How much more expensive would the horizontal wells be? Would it be two or three times as expensive, just ballpark?
Harold Korell: You know, we haven't drilled one.
Marshall Carver: Right.
Harold Korell: So we don't know, and we don't know how long it would be, and you know, and I don't know what the ratio is in the Barnett, but there's probably a lot of history there that would tell the multiple.
Marshall Carver: Okay. So we can use the....okay. That's helpful. Thank you.
Operator: [Caller instructions.] And we're standing by with no further questions. At this time, I'd like to turn the conference back over to Mr. Korell for any additional or closing remarks.
Harold Korell: Well, thanks to all of you for joining us today. This is a moment that we, internally here at Southwestern Energy, have been thinking about, and waiting for, for some time, to be able to share with you, so that I don't have to say I'm not going to respond to questions about where these New Ventures are.
I do want to remind you that the base program of the Company is working very well. We're continuing to be active in the drilling program at Overton. And then, things are on schedule there. The rest of the program in the Ranger Anticline is continuing to be actively drilling there. And so aside from the New Ventures activity here we're poised for a very successful year we believe.
And we, as you, will look forward to reporting results as they unfold on us here in the old, mature Arkoma Basin. And, again, thanks for joining us.
