Coterra Energy Inc. (CTRA) Q1 2013 Earnings Report, Transcript and Summary

Good morning, and welcome to the Cabot Oil & Gas Corporation First Quarter 2013 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Dan Dinges. Please go ahead, sir.

Thank you, Maureen. I appreciate the introduction, and good morning. Thank you for joining us for this call. I have a number of our executive management team with me in the room this morning. Before we start, let me say that the standard boilerplate forward-looking statements included in the press release do apply to my comments today. On the call today, we plan to cover several topics: our first quarter 2013 operating and financial results, an update on our expectations for all of 2013, followed by an update on operations in the Marcellus, Eagle Ford, Marmaton and Pearsall. Before I go into the details on these topics, let me first start with the highlights from last night's press release. For the first quarter of 2013, we produced 89.3 Bcfe, an increase of 50% over last year's comparable quarter and 13% over the fourth quarter of '12. During the quarter, we set new quarterly records for production, revenue, operating cash flows and discretionary cash flows even in light of the relative low realized natural gas price. We continued to de-risk our acreage position in the Marcellus, stepping out our drilling to the Eastern portion a little further than we had previously, and these results are very consistent with our initial drilling area. We also see noteworthy results from our Marmaton program. Now for the quarter, moving into the financial and operational results. The company reported clean earnings of $54.2 million, or $0.26 per share, up 90% over last year's comparable quarter. Discretionary cash flow was $234.4 million, up 69% over last year's comparable quarter. The increases were driven by higher relevant -- excuse me, higher equivalent production and, to a lesser extent, higher realized crude oil prices that more than offset the weaker natural gas prices. Total per unit cost, including…

[Operator Instructions] Our first question is Amir Arif from Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Couple of quick questions. One, can you just tell me what was your backlog of completions at the start of '13 and where you think that's going to be at the end of '13?

So our backlog, are you talking about just Marcellus? Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Yes, just Marcellus.

Yes. Our backlog stays relative consistent throughout. If you look at the, say, 5 rigs running, and we have several wells, a couple, either 2 or 3 wells, on each pad at this time, and we're drilling a little bit longer laterals and we are -- reduced our spacing on frac stages for our '13 program, we will continue to have, oh, about 500 to 750 stages in the queue, if you will, just waiting for the rig to move off location and the frac crew to get lined up and scheduled to move on those locations that the rig moved off. So Amir, it's a similar number as we have right now. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So it's not really -- it's not being constrained because of the compression or dehy, it's more just getting the frac crews out. Is that the first step?

Yes, it is just the operational logistics out in the field. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then just a second question, if you can give any color on what your thoughts are on the free cash flow used as you start up in '14?

Well, we have had a number of questions in regard to that, and we're certainly, again, cognizant of the fact of the excellent returns that we get from the Marcellus. So -- in fact, we had a slide in our investor presentation that kind of outlines various different options. But when you look at a primary consideration and the most value creation, it would be to enhance our Marcellus capital contribution and expand that program in a material way. But we also look at either dividend increase, special dividend, share buybacks and -- but the free cash that we anticipate of any material sense will begin in earnest in 2014. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. But it still sounds like you're leaning more towards accelerating activity. So is that a decision still to firm up in the second half?

Well, yes. Yes, it is. It's a decision and a conversation that we continuously have internally. And we also have ongoing work with the North region in looking at what is possible and still be able to maintain our level of [indiscernible]. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And just one final quick question. In the Reilly pad, have you drilled wells out there yet or are you step -- or you're just totally stepping out in that direction?

Yes, we've drilled wells, but we do not yet have the pipeline hooked up to that pad location. We are -- I can't tell you the exact status of that particular pipeline, but the expectation is, early part of third quarter, we ought to have a pipeline out there.

Our next question is from Pearce Hammond, Simmons Company. Pearce W. Hammond - Simmons & Company International, Research Division: Dan, just following up on the prior questioner. Given the jump in gas prices, do you foresee any -- a change in activity for this year or maybe pursuing that very large well pad?

Well, Pearce, we have all been blessed with an uptick in the natural gas price. And when we have in our initial plan, in our operation moving into '13, we thought about not only having one completion crew, but we had explored the opportunity early in the year, actually, towards the end of '12 of having a second completion crew in the field for a short period of time to just take care of some spread-out wells that we had on a waiting-on-completion status. After we saw the -- towards the March period of time, we saw the opportunity for maybe a little bit higher gas prices. We have maintained that completion crew working for us, and that was one of the catalysts that increased the number of stages that we are able to deliver, 70% over the first quarter of '12 and a significant percentage over the last quarter of '12 also. So we're looking at just how we keep that extra completion crew going as an option. And we also have discussions ongoing to determine when we might want to bring a sixth rig into the field to start drilling off a given pad. It does not necessarily move up in the queue the extensive pad drilling or pure pad drilling. What it does do, though, it moves it up in theory because the rig -- the sixth rig we moved back in location will be capturing primary term acreage sooner, which would, as a result, allow us to start pad drilling sooner. Pearce W. Hammond - Simmons & Company International, Research Division: Great. And then have you noticed any changes in service costs or just general service capacity in the Marcellus here recently with the uptick in gas prices?

No, we haven't. But keep in mind, the largest component of our cost out there are rigs and completion crews. And we are in kind of a unique area of the Marcellus out there. And that equipment out there is going to be in that area, and we think we get good pricing. We have a long-term contract on one of the crews, and we're using another as a spot crew. But we have not seen any increases in prices at this stage.

Our next question is from Abhi Sinha, Bank of America.

Yes. Basically, I'm just filling for Doug Leggate here. So -- an overall question, I'm just trying to see, by when would you be done with down-spacing testing in the Marcellus and developed optimizations to shift gears to full development mode?

Well, in the Marcellus, we have remained spaced at a 1,000 foot between the majority of the wells we've drilled. We have drilled several of the Upper Marcellus wells that were staggering in between the Lower Marcellus wells at about 500 feet. Once we get on a full pad development, we are going to experiment with down-spacing the wells to see what might be the most effective and efficient spacing in the field. And I'm sorry, I didn't get the latter part of your question, Abhi.

The same thing as to well optimization queue. Like, when would you be done with down-spacing and well optimization when you're talking about different lateral lengths.

Yes. And, again, the timing of this will be once we circle a rig back around to do the extensive pad drilling, which would be towards the latter part -- beginning the latter part of '13 or the beginning of '14. And keep in mind, once we put a rig on location and say we're going to drill 10, 12, 14 wells, say we drill 10 wells, you're going to be -- you're going to have that rig on location for a good period of time before you can come back in and complete the -- each well. So we're excited to move in that direction. And we have extensive study ongoing to allow us to cut costs in a material way once we get to pad drilling.

Could you give us a sense of, like, on how much of your acreage in the Marcellus will have a little bit prospective for Upper Marcellus?

How much is prospective for the Upper Marcellus?

Yes, sir.

Well, we think we have Upper Marcellus across all of our acreage in the -- in Susquehanna, as you move to the very north end of our acreage. And the entire section thins from 350 plus or minus in the middle part to the northern part to about a gross interval of 250 feet. We would look at those particular wells in a stand-alone case to determine in today's return environment that we're trying to achieve whether or not our capital dollar is going to be spent there today or down the road to compete with the significant returns we're getting in the rest of the area. And, Scott, correct me, I think I -- I think I said northeast. I should have said northwest in our area, where we have about 10% of our acreage up there that we'd be looking at as Lower Marcellus completions but still going to have a science project on the Upper Marcellus completions.

Our next question is from Gil Yang, DISCERN.

The couple of wells that you drilled, that you said was east of [indiscernible] pad, were -- is there -- the 16.3 on 9 stages versus the 22.2 on 17 stages, could you characterize the difference in a per stage volume? Is there a rock quality issue? Or is there a production engineering issue or a constriction sort of issue that would account for those differences in performance?

Well, each stage, I think the average on one is 1.3 million a day and the average on the other is 1.8 million a day. It might be -- Gil, it might be just the immediate connectivity to the fractures in a particular area, maybe several stages, maybe all the stages. But that delta for us does not -- we don't have the ability to discern that level of difference between the wells. But certainly, each of the wells on a per stage basis, actually on average, is a little bit higher than our entire field.

Okay. Great. The issue of pad drilling, drilling a dozen or so wells from 1 pad in the future, can you talk about -- given that your wells, when they come on so strongly, you're already knocking off existing wells off of the -- in terms of production. If you bring on a dozen wells at the same time, so to speak, how will the cost savings of sitting on a pad versus issues surrounding knocking nearby wells off line repeatedly play out? And then does it require upsiding infrastructure that could increase costs?

Yes. And I'll chuck the ball to Jeff to respond to you after my brief comments. But we have a high expectation of significant volumes coming from a fully developed pad site, as you might suspect. We have been discussing exactly your question with Williams for an extended period of time. And through those discussions, as we develop the infrastructure, as we continue to look at all the options that we can create in the field with the locations of compressors, dehys, for example, the Central compressor, we are taking into consideration the expectation of high rates off a pad site and our ability to have the longer-producing wells that have lower pressure to remain producing. And I'll let Jeff fill in the blanks.

Well, a few more blanks, but Dan did a good job because we have been working on this for 18, 24 months with Williams, doing the hydraulic engineering necessary to make sure these pads are able to produce at 100%, plus capture some of the older wells at the same time. And we're basically doing that with more compression and larger diameter pipe and moving the pipelines and additional paths into Tennessee, new stations. And it's the whole ball of wax of activity that we're out there doing today to bring the capacity to the 2 Bcf level by the end of this year. But there's a lot of hidden projects. In fact, we have no less than 60 projects going on to facilitate the pads when we get to that point. They won't be all over the system, so it's a massive undertaking. But we have -- I think we have a very good plan in place to address the pad completions.

And then presumably, the drilling cost savings outweighs the extra cost of the infrastructure you're putting in place?

Well, the infrastructure in place is 100% Williams' cost, and we have a transportation fee that is netted basically from our gross price.

Our next question is Matt Portillo, Tudor, Pickering & Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a few quick questions from me. I was hoping that you could give us a little color on your production constraints to date. You mentioned that some of the wells are being produced at a constrained rate or they're getting knocked off from pressure. So, just curious if you could kind of quantify that for us. And then as you get some of the compression facilities on in June, I was hoping to get a little bit of color on how that could potentially affect your gross volumes in the Marcellus heading into the back half of this year.

Okay. On the first question on the production constraints, and again, it's just -- Matt, physiologically, if you look at the higher rates coming on and, to your question, knocking off the other wells, the line pressure in the field has remained high. We, I think, are still free-flowing even some of our gas directly into the pipelines, not going through compression at this time. But with our relatively high line pressure already and the wells producing into that, when we bring on and have brought on some of these other wells, we might increase our line pressure anywhere from 100 to 150 pounds. And obviously, that delta inhibits the same flow from those existing wells. I can't really put an amount on the amount that we knock off. I mean, it would be a simple math project. I don't have it. Say a well was producing 5 million a day. And you brought on a 20-million-a-day well, instead of netting 25 million out of it, you might be netting 23 million or 21 million. I don't know, something to that effect. But I really, Matt, don't have the number at my fingertips. And your question on the compression facilities was what exactly? Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just as compression comes on stream, could you give us, I guess, a bit of color on how that could potentially allow you to see an uplift in your volume? So I'm just trying to get a better sense of if you're producing about 1 B a day of gross production in the Marcellus, how does that production, that compression coming on stream help change that trajectory in the back half of this year?

Well -- and there's 2 components for that. One is the Central station that is going to allow us to reduce the majority of our field line pressures. And so we may see an enhancement to our production as a result of just going from 800 or 900 pounds to whatever we can lower the line pressure to, reducing that 100, 200 pounds or whatever we might be able to achieve. So we think we might be able to see something from that. And as we put ongoing compression and dehy in strategic spots in the field, in those immediate areas, we're certainly going to allow each of the wells to produce into a lower line pressure than you might if we didn't have those compressors in that area. Jeff, I don't know if you want to add anything else.

One last comment. The other factor that is involved here is that, as we build up the infrastructure to the extremities of the acreage position, the older wells are naturally located closer to some of the compressor stations. And so the extensions of the pipeline going out to the newer wells is naturally bound to happen that the newer wells are going to push back some of the older wells off line until we get the line pressure issue corrected throughout the system. So that's something that all producers face as they start in 1 area and build out throughout their acreage positions. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then just on -- switching gears quickly to the Pearsall. With the wells you have onstream today, could you guys give us, I guess, an idea of how you think about kind of EURs there? And then also, on the updated Marmaton wells, just kind of curious how you guys are thinking about the EURs on those wells as well.

Well, first, I'll start with the Marmaton. The Marmaton is a -- we've seen some really good results in the Marmaton. And it's looking like between our, if you will, shorter laterals versus our extended laterals, it looks like that we can get maybe a 50% increase in our EUR to be up in the 230 or higher range. We don't have a number of those wells producing long enough to where I could -- I can lock in that EUR. But we are very pleased with what we were seeing in the Marmaton. In the Pearsall, still early to tell on the Pearsall because we have tried so many different things, whether it be the landing point -- and this is different from what we are doing in the Marmaton, whether it be the landing point where we're drilling the wells or whether it be drilled in the deposition, much further north in our -- in the deposition, which is more oily, or further south in the deposition, which is more gas liquids attached to the further south, along with the different techniques that we're applying to the completion. So to give a range of EURs in the Pearsall, I'm just reluctant to do right now because of all the variability. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just my last question, just maybe a little bit more color on the rig count for the Marcellus. Could you give us, I guess, some color on timing of when you hope to get your sixth rig in place? And then is it reasonable to think in 2014 that you may be able to accelerate to an 8-rig count? Or is that a little too early to tell just given the constraints you've seen?

Yes. Thank you, Matt. Well, the rig count at the Marcellus, what we've been looking at is, one, I mentioned the efficiencies and making sure we can maintain the efficiencies and consistency of our program. And some of that involves just clearing the locations for a rig on a consistent basis. It looks like it includes the scheduling of the completion. So we won't have stranded dollars out there any longer than we have to. It has -- also has the coordination with Williams on getting the gathering lines to the locations if we move our program up a little bit and looking at all the aspects of that. But what we're looking at is possibly towards the early fall. We might be bringing in a rig, a sixth rig to the Marcellus. And in regard to '14, still early to tell definitively what we might do in '14. We've been very pleased with the uptick in the gas prices through this shoulder period. We have some collars in place that protect us on some volumes on the downside into '14 now. So we are looking at what we might be able to do on our program expansion for our '14 period but a little bit early to say whether or not we'd go to 7 rigs or 8 rigs.

Our next question is Bob Brackett, Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: A question on the Pearsall program. Those 15 gross wells, can you talk about your out-of-pocket costs sort of net of the drilling carries? And where will you be at the end of the year in terms of drilling carries from Osaka?

Well, we will -- we have an expense interest in the wells that we've drilled so far and the wells that we will drill between now and the remainder of the year. We have a 9.75% expense interest in those wells.

Our next question is Louis Baltimore, Macquarie.

Yes. It looks like you're starting to move south into Wyoming County, where some other operators have drilled some very productive Marcellus wells. And I was just wondering if you could comment on what you've been seeing from your wells down there and how big your position is.

Well, we include in Wyoming County the acreage that's directionally towards, say, Citrus acreage, which has the other top 5 of 20 wells in 2012, and Cabot has the other 15. But we like that acreage, and we do not anticipate any difference in that acreage down there than we see we're drilling right now.

Our next question is Gordon Douthat, Wells Fargo.

Question on the eastern side of your acreage in the Marcellus. How do you anticipate the delineation of that? Obviously, you're dependent on infrastructure, but how do you foresee that proceeding over the coming quarters and years?

Well, once we get our infrastructure build-out going in that direction and it be material sized to where we would allocate the rig and completion crews over there to be able to monetize that investment, we do not see any change in how we proceed with the eastern acreage than what we're developing right now. It'd just be a natural extension as we grow from where we started drilling and started our infrastructure as we grow out to -- towards the east.

And it looks as if you've got a number of things coming from the infrastructure standpoint later this year. Is that directed towards the eastern side of the acreage? Or any comments you can make as far as the timing of the infrastructure build-out as you move east?

Yes, I'll let Jeff field that, Gordon.

Okay. I think if I heard you correctly, the -- well, let me just start by saying that on the Zick area in the eastern side, it's probably where we are best positioned with excess capacity. So for example, when we talk about today we have about 1.4 Bcf a day of capacity throughout the system, it's only in the Zick area and maybe a little bit to the north in the Hawley area that we do have excess capacity. So that's a good thing. And one of the -- we mentioned some smaller projects in the press release. It's actually in the Zick area. It's the second phase of a larger project that is giving us some additional compression on the east side around Zick. And so, again, that's a very good thing. So we feel real good about the eastern side in terms of capacities going forward.

And then last question for me. Last night, in the press release, there was a comment about looking for ways to further extract value from your underappreciated assets. So, just wondering if you could provide any color on your thought process to what that -- what's behind that comment.

Well, we have the -- and that comment was kind of directed towards our Marmaton. And what we're seeing there is -- are good results, good returns. And we're not actively marketing our Marmaton at this stage. But if, in fact, it would be a -- if a transaction was to be had, we would certainly look at the Marmaton as an area that we would consider and utilize those dollars to enhance some of the other areas of our operation. And, again, let me emphasize, we're not actively marketing the Marmaton. But being underappreciated is really simply the fact that 90% of oil in those wells, and the well costs 3 million to 4 million, depending on the lateral lengths and number of stages, it's delivering very good rate of returns.

Our next question is Biju Perincheril from Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Can you give us an update on your takeaway capacity out to date of the Marcellus? And...

I'm sorry. Biju, I can't hear you real well. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Can you give us an update on your takeaway capacity out of Marcellus today? And any new projects or incremental capacity coming on until the Constitution?

Yes. Biju, that is a question that's directly up Jeff's alley.

Thanks for the question. Just to be clear, when some people talk about takeaway, they talk about the downstream interstate pipeline capacities that were utilized into marketing our gas. So I'm assuming that is your question and not necessarily the infrastructure? Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Correct. It's -- yes. It's interstate pipelines, right, not the gathering systems.

Okay. So currently, we are producing -- this is raw numbers in the Marcellus, the Bcf. And about approximately 500,000 of that goes down to Transco. And 400,000 and some change stays on Tennessee Gas Pipeline. And the remainder heads up to Millenium Pipeline. So as you know, we've been blessed with 3 very large interstate pipeline markets within 30 miles of our fields in either direction. So it's a great place to start. It's a huge advantage. But as far as firm capacity contracts, we own just shy of 400,000 a day of FT ourselves. And those firm contracts take gas out of Susquehanna County to different market areas, in fact, as far over in East Ohio area and throughout Pennsylvania and into the east. We actually have over 100,000 a day capacity that goes -- it leaves Susquehanna County and goes into the Boston area. We do, however, have a lot of long-term contracts, where we use sales contracts, where we use other people's firm to move our gas. And that's predominantly down on the Transco pipeline. So we feel like we're in a pretty good shape with long-term contracts, using other people's firms and the firm that we own ourselves. That's really been a huge advantage to date. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: So if you're talking about adding -- going to 6 or 7, 8 rigs eventually, I guess that would largely mean using your customers' firm capacity to move gas. Is that...

That will always be part of all producers in the Marcellus package of opportunities. Because if you think about it, the firm contracts, the historic firm contracts are all owned by the marketplace, the LDCs throughout New England and even in the New York area and down to the Baltimore and Washington, D.C. area. And what the producers have done is we've taken out a lot of backhaul contracts and moved gas to the opposite direction that the utility uses. But utilities will always be a huge part of our business with -- because they own the original transportation, whether it's 4, 5, 6 Bcf a day of capacity. Now, some of the nuances has been the expansions. As you know, the [indiscernible] expansion is going to take 600,000 to 700,000 a day down to the Carolinas. We have a role in that. We have a role in Columbia expansion into the D.C. and Baltimore area. And, of course, we have Constitution Pipeline that's going to move 0.5 Bcf a day at Cabot Marcellus gas in 2015 into 3 new interstate markets. So at the end of the day, we will have our gas positioned to deliver into 6 very large diameter state pipeline market areas. And that's been our plan for 2 years now, and we think it's a very solid plan. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: And the Springville system that's moving gas down to Transco, is that at full utilization now? Or is there room to expand that?

If -- okay. So it's a 24-inch high-pressure pipeline, and we're moving in excess of 0.5 Bcf a day down that pipe. We will have to -- there are plans to add a little bit more horsepower so that we can get up to around the 600 level. But basically, that's the extent of that pipe, unless it's looped or some other enhancements may be made to it.

Our next question is Brian Singer, Goldman Sachs.

Three small questions under the context of thinking about capital allocation with a potential sixth rig. First is, you've talked in the past about trying to making sure you get your drilling plan sometimes even 2 years ahead to your key midstream providers. What is the lead time you feel like is needed to ensure reliability? And what's the risk around it all kind of being ready as you talked about earlier for a sixth rig potentially 3 or 4 months away? I guess that's question one. Question two is just making sure whether the sixth rig for a portion of the year is in your CapEx budget, or not, and if you're seeing any efficiencies that would offset that. And then question three would just be how you're thinking about dividends or returning cash to shareholders in the context of a sixth rig and higher gas prices.

Okay. Well, on the -- the risk of planning is low -- excuse me, let me say that differently. We have planned to add our additional rigs, additional activity to our program. And as we have stated, we are actually working on 2015 with Williams as we speak. So the risk of getting things lined up is -- and implementing a plan that would allow us to utilize -- fully utilize a sixth rig is fairly low. What I'd be referring to on getting all the bells and whistles and ducks in a row for a sixth rig is just to confirm that we will be able to have the right people in place and we will utilize our in-house folks, GDS, that handles a great deal of our operations, not only the water hauling aspects but road building and location building aspects of it, just to make sure we can get ahead of it in all just the nuts and bolts of the front-end work to move a rig on, Brian. But in the permitting side of it, we have -- I don't have a high degree of risk on the permitting side. The North region has been great at staying ahead of their permit request over and above the budgeted programs, say, 85 wells that we have budgeted this year. So I feel good about that and would not think that regulatory issues would get in the way. A sixth rig has not been budgeted in our program at this stage. We might have had anticipation of maybe a very short time in December or something bringing in the sixth rig. But for all intents and purposes, a sixth rig has not been budgeted in the programming. What was your last question, Brian?

Dividends.

Oh, dividends. Scott wanted to answer that one.

Brian, in terms of -- clearly, the priority in -- as we approach this higher level of free cash flow is to explore accelerating the reinvestment in the Marcellus. We haven't gone much farther on terms of a special dividend, increasing the dividend yield or a buyback at this point in time. Again, that -- as Dan said earlier, that's more of a '14 decision. We have spent some time with some experts in terms of the impact, accretive, dilutive, best course of action. And quite honestly, on all 3 of them, based on where we're at, they kind of came to the decision that it was -- and, again, not ho-hum, but it didn't have the impact that it can have in some other applications because of the opportunity set related to the reinvestment back in the business, particularly the Marcellus. So haven't made a final decision. And, again, we'll kind of see as we flush out the '14 plan and the anticipation of free cash flow, together with anything else we do, before we come to a final decision on dividends.

Having no further questions, this concludes our question-and-answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.

Thanks, Maureen, and thanks, everybody, for spending their time on this conference call. We're very optimistic. We see a lot in the marketplace that is directing our attention to future demand for natural gas. I think we've said before that we know we have supply out there. We need to enhance the demand. And all the ancillary areas that I spend time looking at, I'm fairly excited about the increased demand that we're going to have in natural gas down the road. Again, I appreciate it and look forward to the visit on the second quarter conference call. Thanks.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.