Coterra Energy Inc (CTRA) 2009 Q1 法說會逐字稿

Good morning. My name is Richard, and I'll be your conference operator today. At this time I would like to welcome everyone to the Cabot Oil & Gas first quarter 2009 conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) Thank you.

I would now like to turn the call over to Dan Dinges, Chairman, President and CEO. Sir, you may begin.

Thank you, Richard. And thank all of you for joining us for this first quarter teleconference call. Have I Mike Walen with me, Scott Schroeder, Jeff Hutton, our VP Marketing and Chuck Smythe, our VP Controller. Before we start, let me say the standard boilerplate language and forward-looking statements that we include in our press releases do apply to my comments. Cabot issued two press releases last night regarding the quarterly financial results and operational update. These followed two earlier releases a couple of days ago regarding the Canadian sale and our credit facility. I will touch on all of these topics this morning.

Financially, the company reported a strong first quarter with $42.2 million of net income or $0.41 per share after removing select items, the largest of which was the gain on sale of assets. This gain related to a sale of some of our legacy West Virginia properties that were no longer strategically located. Clearly, our hedge position drove these results with $89 million of increased revenue coming from our counter parties, making it one of our best quarters. In addition to price, however, increased production was also a contributing factor to this success. The quarter reported production was the company's highest ever recorded in absolute terms. The 16% growth came equally interest acquired wells and newly drilled wells, highlighting the growth momentum from our grill bit. The press release shows that regionally the east with its Marcellus initiative and the Gulf Coast region concentrating on the Haynesville and James lime are and will continue to be the catalyst for production growth. We expect this trend to continue more than offsetting any declines we would see in the west from our lack of capital allocated in that region.

Let me touch on the Canadian sale. In the year end conference call, I spoke about the intent to explore alternatives and clearly, we are pleased with market and our near close of this sale. The closing is scheduled for tomorrow, and everything is on track. I would note that the transaction is effective April 1, 2009 and based on our early indications, the company will record a small loss on the sale in the second quarter. However, with that, we were still pleased with the transaction and how it further focuses on our commitment to the Marcellus and Haynesville strategy. In regard to production guidance with our Marcellus production exceeding our earlier forecast, we do not plan to change our guidance to cover the loss production as a result of our Canadian sale. The continued success we see with our drilling program puts us in a great position. While I can't say our forecast production levels are conserve, I can say and I do remain encouraged with the progress we are seeing to create more sales capacity and also to the consistent strength we are seeing in the drilling of our Marcellus wells.

On our capital program, we remain committed to the $475 million program for 2009 though we do continue to tweak where and how we allocate the capital. Using the hedges with the current strip, our cash flow generated still exceeds the investment program. In regard to the Canadian sale, the proceeds from from the sale will be used to repay debt. Some of the changes in the allocation of our capital include adding new wells to the east Texas program including a horizontal Haynesville lime well and our first horizontal Haynesville shale well. We will remove several of our County Line wells to make room for these wells.

Moving to operations. Clearly, our Marcellus activity is the most exciting and the most economic program within Cabot at this time. The effort to the northeast PA continues to surpass our expectations as completion results continue to push our takeaway capacity. It is a -- nice to have such a high class problem. As the release stated, to date we drilled a total of 28 wells, eight are horizontal. Field is currently producing at our takeaway capacity or around 34 million cubic foot a day of pipeline quality gas from 18 wells. We remain very active and will continue to be active throughout the year. Our next horizontal frac will occur in mid-May.

Our plan is to increase our fleet of drilling rigs by one in May, plus we will bring in two fit for purpose rigs. These will be about 1000 horsepower rigs later this year. These new rigs will allow us to drill longer laterals plus handle larger casing, which could result in improved stimulation efficiencies. With the inventory of completions in the queue plus the active drilling program, we have planned to look forward to the impact on our operations and production from this area to continue. We reported earlier on some of our first horizontal completion efforts and those wells continue to outperform. The 30 day, 60 day and 100 day numbers that we gave you obviously remains strong and again, serve as a small indication of just what kind of opportunity we may have up in this northeast PA area. While four horizontals is a small sample pool, we are certainly encouraged with each completion.

Our most recent completion, the Heitzman 1H. Again, with only four stage fracs, we had to shorten the lateral length shorter than we had originally planned. But it flowed to cells at an initial rate of 9 million cubic foot per day. In terms of capacity issue, we are installing additional compression and dehydration is quickly as we possibly can. As press release indicated, we expect to grow capacity to 50 to 55 million cubic foot per day by mid May and expect up to 85 to 90 million per day by the end of June of 2009. We have also successfully negotiated a second compressor site, about four miles away from our initial site for an additional delivery point to the interstate pipeline. This additional capacity will be available in 2010. Between both the delivery points, we will have sufficient capacity for years to come, we think.

In addition to our backhaul takeaway capacity, we are currently negotiating with several parties to also increase our firm takeaway on the interstate pipeline. Also as part of our future expansion, we have secured bids for our first 3-D seismic survey which will cover the entire core area of our drilling. We anticipate the survey will be acquired about this fall with a final process version in-house and impacting -- possibly impacting our drilling program by early spring of 2010. We are confident that this new data will allow us to continue to improve our efficiencies in the field.

Moving to east Texas, that is certainly our other key focus area for 2009, and we have been concentrating on developing the County Line properties, exploiting our Minden area and meeting our drilling obligations and the Trawick area. Even though we have been pleased with our operations in this area and all the areas, we are still adjusting our program to try new ideas and to enhance our efficiencies out there. At this point, we have only four rigs operating in the area with plans to be at one rig by year end, and that will be our last contract rig at that point. At County Line, we have drilled 50 wells with consistent results from this play. Those 50 wells were and are James lime completions. The field average IP is still approximately 10 million per day with an average 30 day rate of 5 million per day. Again, from the James lime, during the first quarter, we have drilled and completed nine wells with an average IP of 8 million per day and average 30 day rate of 4 million per day. These flow rates are a little bit less than what have seen as the average, and that is as a result of a conscious effort on our part to flow back these wells at a slow -- at a lower rate to keep the frac sand in place a little bit longer. We think this process will result in better wells in the long run.

In regard to a horizontal Haynesville shale well, we have agreed to an AMI with one party to drill our first horizontal shale well, and we continue negotiations in another area to drill a second horizontal well. These wells will test the productive section we encountered in our vertical Von Goetz 3 well drilled last year on our County Line acreage. There is some recent Haynesville activity in the County Line area that continues to encourage us about this area for the Haynesville shale. At Minden, we continue to drill a few vertical Cotton Valley wells with consistent results. I think more importantly though, we are in the final planning stages for the drilling of another Haynesville Lime horizontal. This well will be drilled in an area where we have had good vertical success in the Haynesville lime since we had our completion problems on the previous horizontal lime well that we attempted. We are going to be drilling this with some casing using a perf and plug technique to complete the well. This well should spud here in the summer.

Out west in the Rockies and mid-continent area, as per what we discussed previously, we would stop drilling in the Rocky Mountains area. It's driven solely by the low gas prices that we were seeing. Recent index price for our major market is approximately $2. We continue to conduct our technical work on our new prospects out in the area and certainly know that the market will recalibrate in the future, and they will be drilling out there in the future for us. We are following the same path in mid-continent, although we do have one rig currently drilling. After this well is finished, we'll drill one more well in Oklahoma and then we'll shut down the drilling up there for the remainder of the year. The gas market is not as onerous in the mid-continent area, but nevertheless, it's certainly a weaker market than we're seeing in other areas.

On the service side outlook, that is no different than the rest of our peers seeing some significant softening, which was certainly needed by the service sector. In the east, we've seen reductions of anywhere from 20% and 25% in non-cabin owned rigs, anywhere from 40% to 50% reduction in drilling mud cost. A 40% reduction in directional drilling cost and 20% reduction or so in drill bits in the Gulf Coast. We seen similar reductions, drilling rigs have come down from market rigs 40%, 50%. Completion pumping costs are down, 40%, 50% and other services are down anywhere from, say 20% to 60%. In the west, you are also seeing significant rate reductions and service costs. These reductions are certainly needed to calibrate with the current commodity price we see, and we do think further reductions are going to be coming.

Anyway, with that in mind and that said, Richard was fairly a quick overview. But we were fairly focused in the -- in our two key areas, but I will open the phone lines up for any questions.

(Operator Instructions) Your first comes from the line of Joseph Allman.

Thank you. Good morning, everybody.

Good morning.

Dan, I know it's early days in the Marcellus for those horizontals, those four wells, but what would be your best guess at this point in terms of EURs that you are seeing?

We are seeing right now with -- again, as you mentioned, kind of an early time curves, but we are seeing four plus EURs on these wells.

Okay. And then what is your interpretation in terms of the lower than expected declines and would you expect to try to open some of these wells up some more and potentially get some higher initial rates and you are thinking that will lead to some steeper declines closer to the model.

Well. I will let Mike answer that. We think we are prudent in the way we are handling the wells. Again, early time data first wells up in a new area, it was a significantly remote area with our discovery well only being the sixth well ever drilled in that part of the woods. We are handling the wells prudently, and we haven't just absolutely opened the wells up to atmosphere, because we want to keep our frac sand in place. We don't want to damage the wells, close up any our efficiency of our frac. So we think the way we are bringing these wells online, that we are being pretty prudent about it. But as we get deeper into these completions, we are going to be trying a different things.

Yes, Joe. I think Dan is right on there. We have apparently hit some very good rock with some excellent reservoir pressure. The rock is very thick. Probably the thickest part of the Marcellus in the trend. The -- what we were concerned about, as Dan mentioned, is keeping our frac sand in place. We have not had problems to date with that issue, but we want to make sure that doesn't happen, and so we are handling these wells gently. Since it is a new play for u,s we don't really want to open these wells up for -- and get the big flash IPs and to potentially hurt the well bore. So that's our strategy going forward and I think as we get more history, then we can address that issue.

And the pressures are holding up pretty strong it seems?

Yes. This is -- like we've said, these wells are outperforming our wildest expectations. Pressure is looking really good. No hydrocarbon fluids, which we think are very important as far as keeping your relative permeabilities intact. So it looks like a real home run play.

Very helpful, thank you.

Your next question comes from the line of Ellen Hannan.

Good morning. Just a follow-up on the Marcellus, if you could. What are you now looking for in terms of drilling complete costs of wells for these horizontal wells? And is what you are seeing to date -- is there any change in your thinking in terms of your development on 100-acre spacing? And lastly, I believe you mentioned a 3-D shoot that you are planning in this area. What do you expect that to yield for you in terms of additional information?

Ellen, this is Mike. The -- you have a lot of questions there, I trying to think which ones to start with.

The cost per well?

Okay, the cost per well. We started off, obviously on the first horizontals, you kind of learn about that, and we thought that we could get these wells drilled between $3.8 million and $4 million completed, and essentially, our initial wells were right in that range. We are seeing considerable reduction in service costs, as Dan mentioned. But we are also learning an awful lot about how to drill them and our rate of penetration, our days on locations have been reduced markedly. And right now we are -- our latest wells are probably getting down into the $3.4 million to $3.6 million range. And as a matter of fact, we just TD'd a horizontal well yesterday. We're getting ready to set our casing and we drilled that well for about $2.1 million with about -- almost a 4,000 foot lateral. And in that well, by the way, we do plan to complete it with about 10 stage fracs, and that is part of the moving target for our total well cost, because how many fracs that we do put into it. And of course, the more stages, the higher the well cost will be after we drill it. The seismic data is -- as Dan says, the bids are in. We will be selecting a contractor to do that work for us. The reason we were doing it is that there is some faulting in the area, and it isn't a pervasive issue, but there are enough faults to make drilling sometimes give us some surprises. So we think that the seismic will let us more effectively site our well site and also steer the horizontal. Then back to your 100-acre spacing question, that follows right into that. The seismic is going to allow us to place our wells in the most optimum place for a 100-acre unit, which I think we will be keeping going forward until we get new information.

Great. Thank you. Now I have one quick question for you in east Texas. Could you just tell us what your expectations are for a Haynesville lime well versus a Haynesville shale well horizontally, in terms of either your cost or your EUR. What do you think your benchmark is?

Ellen, again, the costs are going to be very comparable, because obviously, the lime is just a little bit deeper , and the drilling characteristics are very similar. Obviously, we think the lime horizontal will be multiple, a the vertical lime intense We are looking at maybe one to two BCF a well for a vertical lime well. We would think that a horizontal lime would be a multiple of that. Maybe three to four to five times multiple of that. Now the shale wells, we are -- we don't have any history yet. We were encouraged with the result of our first vertical test. We are hearing some nice numbers in the area by other operators. And we are thinking right now that the horizontal shale well will be at least on par and hopefully better than the horizontal lime

Thank you very much.

Your next question comes from the line of Brian Singer.

Thank you, good morning.

Hey, Brian.

Following up on the Haynesville, can you talk to any changes you may be making in completion techniques as you go forward with a couple of those that you referenced versus the wells drilled in the fourth quarter early first quarter?

Yes. We tried the Packers Plus in our first Minden horizontal lime well, which was consistent with the flawless completions that we had had in the James lime and County Line. It didn't work for us. We had mechanical issues. Basically a failed completion with our first effort there. And the difference right now is simply, just we are going to cement the casing and complete this well in more traditional sense.

Great. That's helpful. And secondly, on the Marcellus, if we take a step back based on the wells that you've drilled so far, can you talk to -- with your various acreage blocks, what you think is prospective and where you see better opportunities regionally?

Well, one thing about our acreage position, Brian, which we have indicated in the past, that when we initiated our strategy and our play concept up there, we focused in one area initially, and that is in County -- in Susquehanna. And we felt like with the data points that were available out there, that that was going to be the thickest Marcellus that we could find anywhere in the play. So we didn't lease initially in a lot of counties. We only leased in one county, and we blocked up that acreage fairly successfully. And so from a regional sense, and when you look at the Marcellus play and discuss it as a regional play, frankly, we are on a small little postage stamp area with our 160,000 acres in relation to the regional aspects of the play. So far, a deviation of what our expectations are on our acreage blocks since it's all in one area. We are not expecting to see a great deal different in the Marcellus in our area. What we do see regionally though, however, is differences in thicknesses, and we have seen differences certainly in the maturity of the Marcellus wherein in our area, we do have a mature absolute perfectly baked section which gives us pipeline quality gas. In some other areas, there is -- maybe it's not quite as cooked and there's more liquids attached to it. And there is going to have to be some additional facilities to strip out liquids and move the gas into the pipeline. But again, back to -- I think your question is, what is the risk profile of Cabot's acreage position in the Marcellus, and I would say it's very low.

Great. That's helpful. Have you seen anything from others or any plans on the West Virginia side or maintain the more self focus on the Pennsylvania -- northern Pennsylvania?

Well, we're willing to remain with us -- again, hide behind trying to enlarge our program up in northeast PA. Build a core infrastructure up there, get the people on the ground that we want to see. We are going to continue to focus almost exclusively, certainly from a development standpoint in northeast PA. We are adding people on the ground. We had our board meetings yesterday, and they presented a story that said with our drilling equipment and service infrastructure up there, that we have certainly brought our own people up there, but we have also hired probably a third of now our work force up there, our locals from the area that we are hiring. So hopefully, we are giving back in that regard. As far as West Virginia is concerned, I think it's safe to say we continue to look at our -- some of our leasehold positions and some of the acreage we acquired in support of the Marcellus in West Virginia. But the expectation would be, we would probably test the acreage with a couple of wells, but not go into a development phase in 2009 anyway.

Thank you.

Your next question comes from the line of Biju Perincheril.

Good morning. Couple of quick questions. In the Marcellus, Dan, can you address the infrastructure? What will be your capacity with the second compressor and second tap installed?

Well, we are -- our next benchmark is going to be the 50 to 55 million cubic foot per day, and we expect that to be available to us by the end of May. And then the next tranch, which is where we are putting in a fourth compressor at our existing site, and that is going to be a 2300 horse compressor. We expect to be at 85 to 95 to 90 million a day in June at that particular site.

Okay, and then you mentioned the second compressor site in early 2010?

Yes. We have acquired another large site that we are finalizing, and that is going to be the location for another tap into the interstate pipeline system, and it's going to be another site for an expanded compression plant.

And then, what could be the -- eventually the capacity out of that second site? Could that be another 90 million of that? Does -- the interstate has that kind of capacity available?

Well, there's two questions there. One is as far as our site is concerned, we are going to be installing a little bit larger tap into the interstate pipeline. Capacity at that site, depending on the amount of compression we bring in, could be unto 150 million cubic foot a day and in regard to the pipeline we are flowing into, the pipeline we are flowing into is a 700 million cubic foot per day pipeline capacity. And what we are balancing right now is, and what I mentioned in the teleconference is we have firm of up to 90 million cubic foot per day, and that's on our backhaul arrangement. All the gas we've moved to date is on an interruptable basis that we are moving on forward sales. But we are also negotiating with several parties for additional firm capacity.

Okay, thanks. And then in terms of -- any estimate on what your exit rate could be out at the Marcellus this year?

We haven't -- we had a presentation in the board meeting yesterday, and we are going to study that a little bit longer before we give that number out.

Okay, and then one last question. The AMI for the Haynesville shale program, is that just -- does that only cover County Line acreage?

Yes. What we are focused on right now is the acreage that we not only have in County Line area, but we have -- we mentioned several times we have for the last, almost two years now, acquired additional acreage around County Line, which some of the discussions on the AMI covers that acreage also.

Okay, perfect. Thank you.

Your next question comes from the line of Michael Jacobs.

Thank you. Good morning.

Good morning, Michael.

Dan and Mike, as you are looking back and comparing completion techniques between the Eli, the Blacks, the Heitzman wells, what are you doing differently in terms of interval length? Are you seeing better frac placement? And any color on prop and types or the amount of pump fluid that you are using.

These are slick water fracs, Michael. And we are just using regular 20/40 sand, pumping them at about 60 barrels a minute. I think it's -- I think some of these better wells were just hitting some real good rocks. It's kind of jumping all over the page. Some of these six stage fracs wells maybe were only at 6 million a day. A four stage frac well was at 9 million a day. So I think that we were just probably accessing some pretty good looking rock. We haven't done anything special on frac technique or frac fluid recipes, something like that. It's pretty standard stuff.

Okay, and just following up on the infrastructure side, we're up to speed on the near term capacity adds and Dan, you just mentioned you could see up to another 150 million a day. How do you envision total capacity as you look out to 2010, 2011? Any sort of higher level visionary outlook?

Are you talking about from an infrastructure capacity?

Yes, sir.

Well, we are going to be, again, building out this new site. And at that new site, we are designing it as a pretty large -- it will be a pretty large slab to allow us to put in a significant amount of horsepower of compression. And that's kind of my reference to an additional 150 million over and above anything we've talked about . And our existing site is kind of what we are looking at to reach out there in the 2010

And then just one last question. You are obviously doing some more work on the infrastructure side. But it's becoming increasingly apparent your capital intensity in the Marcellus is coming down as a function of better productivity. How are you thinking about the tradeoff of accelerating infrastructure buildout versus potentially dropping rigs and lowering overall capital intensity of the east region in relation to the rest of your --?

That's a good question. And that balancing act is going to be a dynamic process, because we do have a very large acreage position. And the acreage position we have up there, again, in this rank area are all primary term leases. So we want to set a program out that is going to be able to capture HBP, if you will, all the primary term leases. So we will continue, even though we have five year term leases or five year term with five year kickers, we want to continue to be fairly aggressive on the front end to make sure we reach out and we don't fall behind on touching all of our undeveloped acreage. So we are going to remain fairly consistent on the front end of this program but enjoy the efficiencies we are seeing up there, not only on enhanced results, but certainly reduction in cost.

Great. thank you very much.

Thanks, Michael.

(Operator Instructions) Your next question comes from the line of Andrew Coleman.

Good morning, folks.

Good morning, Andrew.

I had a couple of questions. One, just thinking about the 160,000 net acres you guys have in the Marcellus play. With the 30/30 split for horizontal and vertical wells, do you foresee that sort of split continuing in terms of a 50/50 split, or at what point do you think you'll start going with more horizontal completions?

I think it is certainly safe to say that we will be drilling more horizontals as we get deeper into our program. And again, we've only drilled 28 wells in a totally rank area. Brian had asked a question earlier about what consistency that we might have on our acreage position in the initial stages. We didn't think we would see a great deal of difference in the consistency of the rock and the thicknesses and whatnot. In fact, as we have expanded out from our core with these 28 wells, we are not seeing any big differences in the rock in the Marcellus right now. And the vertical wells was allowing us to log and look at the entire section to be able to get the data points that we need. So as we get more and more comfortable and certainly, we are seeing our expectations met in that regard, we are going to be drilling more horizontal wells, less vertical wells as we step out into a deeper development phase.

Okay. So start to think about then from a reserve potential that maybe 80% of the reserves that you are going to book at a 7 to 10 Ts are going to come from the horizontal wells as opposed to the vertical wells?

Definitely more reserves booked attached to our horizontal program. No question about it, Andrew.

Okay. And then you said you had 28 wells drilled to date. If I heard right, at the beginning of the remarks, you said something like 16 are tied in. Are those remaining wells, are they waiting on completion? Or is that part of the region?

Let me make sure -- Mike, correct me if I'm wrong. We had 28 wells drilled, we had four horizontals and 13 vertical wells that are flowing into the pipeline now with 34 million a day. We have three verticals and three horizontals that are waiting on completion and coincidentally, we are drilling three more verticals and three more horizontals as we speak. Are those numbers right?

We have a couple wells that are shut in.

Yes, and we do have a couple wells -- thank you Mike -- that are shut in.

Can you give color as to why -- what is causing the shut in? Is it infrastructure? Is it well performance or clean up or what?

Yes, we have -- we are at our capacity with our 34 million a day and we are shutting those wells in. And frankly, that really tells us something to be able to shut these wells in. We are able to getting some buildup pressures. We are looking at how quick these wells continue to build up. So it's useful information as we go through this process and continue to expand our capacity.

Okay. And then of the wells -- as you are stepping out and drilling your 60 wells this year, how far I guess -- or how much acres are you trying to test up, and I'm thinking about it from a resume booking standpoint. Are you getting far enough apart in these wells to be able to book two offsets, or are they getting -- eventually going to get the tighter spacing here this year?

Well, we have done two things with our 2009 program. With our reduced cash flow based on reduced commodity prices, we revamped our original plan in 2009 to reduce the amount of pipeline we are going to lay out into our leasehold position, and we started with a portion of our wells. We started back filling where we had drilled our 2008 program. And with half our program, we also stepped out, but not quite as far stepped out with our 2009 program. So as far as the -- we will have more wells to drill in 2010, even within our 2008 original drilled area, and we will have, certainly, additional spacing and additional wells to drill in between the areas that we are drilling in our 2009 program for 2010. So, I think that answers your question, but maybe in a different way.

Sure, sure. Last question here, apologize for the laundry list. Looks like brokered gas volumes had gone up by about 30% in the first quarter. Can you explain why or what drives that?

Well, I will defer that to our VP of Marketing, Jeff Hutton.

I believe the increase has to do with pulling gas out of storage. We had some additional volumes that came out of our storage fields that were brokered volumes in 2009.

Okay. And those volumes then, again, they're brokered so that they don't flow into your production level. It is just a cash impact?

That's correct.

Thank you.

Thanks, Andrew.

Your next question comes from the line of Jack Aydin.

Hi Dan, hi Mike, hi Scott.

Hi.

On the County Line in Minden, the Haynesville lime shale -- horizontal Haynesville lime and a horizontal shale, what kind -- did you change anything from the past and in terms of completion, in it terms of the drilling, in terms of fraccing, versus the previous efforts?

Yes. In the -- I will pass this onto Mike to get a little more granular. But our failed Packers Plus effort in County Line, we have not identified conclusively that the failure was a result of it being a little bit deeper and little bit higher pressure and temperature. But we -- dedicative reasoning indicates that that most likely was the problem with using Packers Plus in our Minden/Haynesville lime application. So where we are going with the drilling and completion, Michael describe exactly what we are going to do with that completion effort and that particular well.

Yes Jack, we are not going change much on the horizontal drilling part. It will be tested the same way that we drilled before. We will use higher mud way to course in the shale because of the pressure differential there, but the drilling process will be about the same. And as Dan said on both wells, we will be -- the casing and doing a plug in perf completion, probably up to ten stages in each well, depending on how far out we get. We did do a lot of research and talk to a lot of our peers in this area, and it appears, at least down in this County Line area, that the preferred method to complete is by cementing the casing and not using the Packers Plus. So we are going to use that technique on these first two wells.

Mike, you saw the result of the Southwest Energy well in that area. Are you doing the same thing they doing? They had a good IP yesterday's.

Yes, it will be a very similar completion.

How far are you from that acreage from that well?

Probably less than four or five miles away.

Okay.

And there is other activity out there, Jack, that is pretty encouraging right now.

Okay. Thanks a lot.

Thanks, Jack.

(Operator Instructions) Mr. Dinges, there appears to be no further questions. Do you have any closing remarks?

Thanks, Richard. Appreciate everybody's attention and interest in Cabot. I think we're certainly fairly transparent now, selling Canada's refocused our efforts, not having rigs running in the Rockies and not having rigs running in the mid-continent after the next couple of wells is going to have our entire company focused on the east Texas area and the Marcellus. And we continue to expand both of those operations. Keep your fingers crossed that our tough and low commodity price period through the summer will improve as we come into the winter season, and we look forward to our next report. Appreciate everybody's interest. Thank you.

Ladies and gentlemen, that concludes today's Abot -- excuse me, Cabot Oil & Gas first quarter 2009 conference call. You may now disconnect.