Good morning, and welcome to the Cabot Oil and Gas Second Quarter 2014 Earnings Conference Call. All participants will be in a listen only mode. Please note this event is being recorded. I would now like to turn the conference over to Dan Denches, Chairman, President and CEO of Cabot Oil and Gas. Please go ahead, sir.
Thank you, Youssef, and good morning to all. I appreciate you joining us for this Q2 call. With me today, as usual, I do have several members of the Cabot executive team. And also before we get started, the standard boilerplate to forward looking statements included in the releases do apply to my comments today. First, I'd like to touch upon a few of the financial and operating highlights from the Q2 that were outlined in this morning's release.
I think all of which indicate some positive numbers. Equivalent net production for the 2nd quarter was 1,402,000 dollars excuse me, 1402,000,000 cubic foot per day, an increase of 34 percent over the prior year's comparable quarter. This also represents a 5% sequential increase over the Q1, driven by 4% increase in daily natural gas volumes and a 39% increase in daily liquid volumes. Of particular note, oil production for the quarter increased 65% compared to the prior year's comparable quarter when adjusting for last year's Mid Continent and West Texas Texas asset sales. Year to date, our equivalent production is up 34% compared to last year, in line with our current guidance.
Discretionary cash flow for the quarter was approximately $332,000,000 an increase of 12% compared to the Q2 of 'thirteen. And for the quarter, Cabot generated approximately $50,000,000 of free cash flow, highlighting the capital efficiency of our program and that's despite the lower natural gas prices. Net income excluding selected items for the Q2 was $115,000,000 an increase of 21% compared to the Q2 of 2013. Our unit cost, another area of improvement, continues to trend down, decreasing 16% year over year to $2.59 per Mcfe with per unit cash cost of only $1.27 per Mcfe. Let's move to the region.
First, the Marcellus. The company continues to experience exceptional well productivity as evidenced by the step out results that were reported in today's press release, The consistency of our acreage to the north and east, while we expected these results, was confirmed by the step out wells. It's still early in the production cycle, some of these wells, but we are pleased with the results to date and expect the EURs per foot on these wells to be in line with our well results we reported at year end. Net production for the field was 1.26 Bcf per day, up 4% over the Q1, but did fall a little bit short of our internal expectations. This shortfall was exclusively a result of the ongoing issues directly related to gathering operations and not related to well performance.
As we pointed out in the Q1, Williams had experienced significant downtime with their operations during the extreme winter conditions. Unfortunately, some difficulties persisted throughout the Q2, which were unrelated to weather. We've been in constant contact with Williams and have recently seen operational improvements. However, throughout our discussions with Williams, we have made it very clear exactly what our expectations are moving forward and we do believe Williams' operating results will continue to improve. Despite this unexpected dynamic, Cabot still achieved the midpoint of its production growth guidance for the 1st 6 months of 'fourteen, and we reaffirm our production guidance for the remaining 6 months of 'fourteen and the full year of 2015.
During the Q3, approximately 60,000 horsepower of additional compression will be added to our gathering system. This new capacity will alleviate high line pressure in certain areas and will also provide for compressor redundancies throughout the system. Having this spare capacity will definitely mitigate a significant amount of the compressor downtime experienced during the first half of the year. We continue to operate 6 rigs in the Marcellus and expect to hold that rig count flat through 2015 based on our current operating plan. We plan to drill and complete approximately 60 additional wells during the second half of twenty fourteen.
It certainly is nice to be able to operate only 6 rigs in a field and deliver top tier production growth of such a large production profile. Now let's move to the Eagle Ford where we had some highlights. Our Eagle Ford team continues to work to maximize drilling and completion efficiencies in our core Buckhorn position in the oil window of the Eagle Ford. As a reminder, we currently have over 53,000 net acres in the Eagle Ford with approximately 43,000 net acres at our Buckhorn prospect, which is located predominantly in Fria and Atascosa Counties. Cabot has 3 rigs drilling in the field and by the end of the Q3, all 3 rigs will be converted to walking rigs capable of effective efficient pad drilling.
Pad development equates to drilling and completion cost savings in excess of $500,000 per well and the facility cost attached to pad development is a cost savings in excess of $200,000 per well on a multi pad site. The team has shown significant performance improvements in 2014, which has been driven by the continued optimization of our drilling and completion operations in the play. Some of the recent refin initiatives, including drilling longer laterals, reducing the spacing between frac stages, and increasing the amount of profit per foot. For the first half of twenty fourteen, our typical well was more than 25% longer than our average well drilled in 2013. We have further reduced our stage spacing in the Eagle Ford and modified the profit size we use in our frac jobs, both of which have resulted in a significant increase in fracture conductivity.
In the Q2, our average stage spacing decreased 15% compared to the average spacing for our 13 program. This equates to more stages per well and more proppant per lateral foot. In 'fourteen, we have also increased our profit per foot by 15% to 20% over our 2013 levels. On the efficiency front, also we continue to see an improvement in drilling days and drilling costs per foot. In fact, recently we achieved a new record for us for drilling days, drilling to TD in only 7 days for a 6,400 foot lateral well.
As we highlighted in the press release, during the quarter, we placed 10 wells on production that have now produced for at least 30 days. These wells achieved an average 30 day production rate of 8.40 BOE per day per well with a 92% oil cut from an average lateral length of 6,700 feet. The approximate well cost of these wells is about $7,000,000 Certainly, these wells are trending above our 500,000 barrels per BO per well EUR. We also recently drilled and completed our first 300 foot down spaced well and have been pleased with the results to date. We will continue to monitor the production profile from this pad and have additional 300 foot space wells planned for the rest of our 2014 program.
300 foot down spacing could increase our location count at Buckhorn by 25% to 30%. While we did not add a material amount of new Eagle Ford acreage during the quarter, we do continue to assess different opportunities throughout the trend and anticipate adding more meaningful to our position throughout the balance of the year. And now the remainder of my comments will be addressed to answer possible questions we might have in regard to pricing. We are certainly all aware of the pricing dynamics surrounding the Marcellus and it continues to put pressure on the differentials throughout the Northeast United States and the overall weakness realized in realized gas prices affecting all of the Marcellus and Utica producers. Cabot certainly is in this same position as we continue to experience differentials that can be attributed to continued growth of supply.
Increased demand and the in service of new long haul pipes designated to take Marcellus gas out of the region will certainly help the differentials. As we explained on our last call, we had certain winter contracts roll off prior to April 1st and we anticipated slightly weaker realized prices for the summer period. As expected for the Q2, our realized prices before the impact of hedges averaged $0.89 below NYMEX, which is in line with the guidance we provided in our investor presentation. We expect our realized price point to be reduced slightly in the 3rd quarter and expect to see improvement as we enter the traditional heating season. Moving to Constitution pipeline update, we continue to make additional progress as we await the issuance of the final environmental impact statement.
The project is moving ahead on all fronts as Constitution continues to acquire additional survey permits, right of ways and permits required to begin construction schedule for early 2015. We continue to see frequent updates from the Constitution team at Williams and despite the delay we saw in FERC's issuance of the final EIS, there has been no change to the expected in service date that Williams provided us back in December of 'thirteen. As a result, we remain optimistic for an in service date of late 2015 to early 2016, though we do recognize several approval milestones do need to be met. In regard to share repurchases, anticipating that question, share repurchases are still part of our capital allocation discussion internally. Year to date, we have not repurchased any shares.
Currently, management is focused on balancing long term development opportunities with share repurchases. Our near term share repurchase activity will be coordinated with the success of additional acreage acquisitions and the corresponding acceleration opportunities on any of that new acreage we will acquire. And certainly, the share price is of consideration also. In summary, even in this challenged pricing environment, we continue to generate growth in earnings and cash flow led by our top tier production growth. Current natural gas price realizations, certainly while not robust, are still manageable and allow us to generate best in class returns.
Add to this the fact that our efforts in the Eagle Ford will continue to deliver strong oil growth with our efficiency improvements and results, plus an expanded rig count in the second half of the year, you will see these strong oil production growth. So what can you expect from Cabot is that we will continue to deliver strong production growth, we'll maintain a very efficient capital program with excellent returns despite the differential effects, will add significantly to our reserve book, will capture margins with our continuing efficiency gains and operations and unit cost, and we will continue our efforts to expand our investment focus. Youssef, with that, myself or the management team will be happy to answer any questions.
Thank you, sir. We will now begin the question and answer session. Our first question comes from Charles Meade with Johnson Rice. Please go ahead.
Good morning, gentlemen. Dan, I want to say, I think, with your last comments there, I think, a lot of us, me included, scratched off a lot of the questions that we had planned. So I think maybe there's been a theme on recent calls. So thanks for addressing that. I want to if I could get you to decompose a bit the results on those 3 pads with the 191 stages.
I know you said that they're in line with the estimates. I guess that means your EUR for year end. But can you discuss at all maybe some of the variability that for when you went north and it got thinner for when you went east, if there's any variance around that 1.25 millimeters millimeters millimeters millimeters millimeters millimeters millimeters millimeters
millimeters millimeters millimeters millimeters
millimeters millimeters millimeterscf per stage?
Well, there's not a lot of variance, and each well can be unique in its own way, Charles, when you and that statement is consistent with the other areas we've drilled also. We have to make sure that we stay within the exact zone that we select. Down south where it's a little bit thicker, we have a little bit more leeway to stay within that zone. But certainly, the thickness does not diminish significantly to the north, just slightly and we stay very vigilant on making sure that we stay within the zone that we're trying to target. But aside from that, we've been very pleased with the results, the frac spacing that we continue to play with between 150 and 200 foot space fracs.
We're toying with and continuing to gather data in that regard. The flowback process that we employ up to the north and the east has been similar. The type of frac we put on the wells was similar with the amount of profit per stage and the pump pressures that we utilize and the type of profit has been consistent. So we are not seeing again any differences in either way, either it's our implementation and how we drill the well except being more vigilant and staying in zone. But our completion techniques and operation side is consistent.
Flowback is the same and as indicated, the results are good.
Well, that's great. I imagine you have to be quite pleased with that consistency. And if I could just take one follow-up on the Eagle Ford, if I remember correctly, I think that on your last call, Dan, you were talking about that your organic kind of lease acquisition efforts were underway and that I think you indicated that was your focus. Is that still is that correct? And if so, is that still your posture or are you maybe looking more at maybe some producing property packages as some people exit the play?
Yes. Well, we have evaluated through our internal team not only the primary term or open acreage acreage out there, but certainly on small bolt on type of opportunities, we evaluate also. Those bolt on opportunities could come in the form of either just acreage or it could come with a little bit of production, but we're evaluating both.
Got it. So you're agnostic on that. You're just looking for value and how it fits with your existing position?
Exactly.
That's it. Thank you very much, gentlemen.
Thanks, Charles.
Our next question comes from Joe Allman with JPMorgan.
Thank you. Good morning, everybody. Hi, Joe. Could you talk about the differential, the gas differential so far in July? And then, Dan, what are your expectations for the differential the gas differential in 2015?
Well, I'll let Jeff feel that, but I will say this just from an overall standpoint that the differential by itself is going to be certainly a moving target, but the differential will also be the final differential would be affected also by the price of NYMEX. So as you see the fluctuations in NYMEX, I think you'll see the fluctuations also in what the exact differential will be. But I'll let Jeff answer the question in regard to the July and 2015.
Okay, Joe. I'm glad that excuse me, I'm glad that Dan led in with that quick summary on the differences that we expect to see between the differentials on a higher NYMEX number rather than a lower NYMEX number. July did come in slightly less than our average for the Q2. That said, we've sort of expected that. We also expect that continue as we reach the winter season.
Again, weather will play a role here. And if we see a normal winter to a good winter like we saw last year, we expect the differentials to strengthen a little bit. As far as 2015 goes. Personally, don't see much difference between that year and this year in terms of differentials, but again, a lot of that has to do with this winter and the weather we will experience then. Okay.
That's helpful. And then
a question on Constitution. So what are the key hurdles that can affect whether that really comes on late 2015, early 2016 or if it's delayed?
Okay. Joe, this is Jeff again. Yes, the primary key hurdle is the excuse me, the final EIF statement. We expect that out in the next 2, 4 weeks or so. The certificate will follow under a normal process with that.
Along the same path, we'll be and have been working with the New York DEC and the PA DEP on getting the permits necessary for construction. But the final EIS is a significant event, and our expectations are we'll see that on schedule. And the in service date at this point, like Dan mentioned in the speech, is still scheduled late 2015, early 2016. Okay. That's helpful.
And then lastly, just with Eagle Ford, I mean, Dan,
it sounds as if you're planning on adding a significant amount of acreage in Eagle Ford. And you previously talked about just some bolt ons or potentially some production added with that. But are you also considering a bigger asset acquisition or might even consider a corporate acquisition?
Well, right now, we're looking at the asset acquisition being in the form of whether it's just additional leases or small bolt on type of opportunities. The reason is very clear. You look at our results that we've been able to post with the type of wells that we're drilling, the efficiency gains that we've had that I've mentioned on the drill side and completion side. We have had in our investor presentation on a typical 500,000 EUR type well, well cost 7 $1,000,000 and our lateral length being in this type well being consistent with the lateral length and the number of stages that we've done on our last 10 wells, at $90 we get over 60% return on that type of well. Two things in regard to these 10 wells, the 10 wells are trending above this type curve for the Eagle Ford Economics that we have presented and certainly our realized price is higher than the $90 that we've represented to get over that 60% return.
So we are looking at the additional opportunities out there with economic improvements that we've seen and the efficiency improvements that we've seen to take advantage of any additional acreage we can find. Rodney
McMullen:] Great. Very helpful. Thank you.
Rodney McMullen:] Thank you.
Our next question comes from Drew Venker with Morgan Stanley.
Good morning, everyone. Wanted to address the takeaway situation. Obviously, there's a huge amount of demand for additional long haul pipe out of Appalachian General. Just curious for your position specifically, have you examined building your own midstream solutions of Northeast PA? And I'm thinking really in addition to Constitution.
Yes. We have certainly Constitution. We've talked about, everybody is aware of it that the commissioning of that particular pipeline will give Cabot an additional 500,000,000 cubic foot net a day of gas going through to a different price point. We've also are participating in the Central Penn Pipeline, which is scheduled for the latter part of 'seventeen. Our participation in that is, if you will, a midstream investment.
But more importantly, we are the foundation shipper on that particular Central Penn Pipeline and that will allow us to move an incremental 850,000,000 cubic foot a day. And again, anticipated commissioning of that in the latter part of 2017. And I might add that certainly we're very in tune. Jeff stays up to date on every moving part out there in the midstream market. And we have ongoing discussions with how we're going to continue to move our gas with the growth expectations that we have.
Partly the question arose because the asset really is so tremendous that if you had adequate pipeline capacity, I think you could grow at basically whatever rate you wanted to grow. So maybe there are other considerations, maybe the macro pictures is a part of it. Are there other things you're taking into account when you evaluate your midstream needs?
Yes. We kind of back to my comment I made about drilling in a field with 6 rigs, having a I don't know who's producing the most gas in the entire Marcellus or Utica area, but we're close to the either 1, 2 or 3 and it's producing a 1,500,000,000 cubic foot per day up there and being able to grow off of that base with only 6 rigs. I don't know who's producing the most, but I know that we have the least rigs running in the area, particularly with that growth profile off of that larger base. So, we know we can continue to grow this tremendous asset, 30 to 40 TCF resource opportunity up there. We know the present value is important to all of us.
So everything we do is to enhance the present value of that asset. Couple of things that will be happening in the future, we're all aware of. I think we all believe that demand is going to be enhanced, whether that demand is in power generation, industrial use, LNG exports, all of that is moving forward. So, we're optimistic, though we are in a little bit of a lull period. We're optimistic that in the foreseeable future demand is going to be enhanced.
And I think that demand enhancement is certainly going to be coupled with the midstream efforts that are ongoing right now to attach the supply area to existing demand areas and incremental new demand areas. So we think we have a bright future.
Okay. Thanks, Dan. And then lastly, can you speak to the potential you have in the dry gas Utica in West Virginia or even if there's some potential you see there?
Well, we are in the Utica play. We have some acreage to the north, over 50,000 acres to the north area of the play, and we have some extensive acreage to the south area of the play, where we are whether it's the dry area or the liquids rich area of the Utica, We are looking at it. We're evaluating. We have a rig active at this point in time. Still an exploratory project for us, but we're optimistic with the geology we see.
And then is there a potential to get an update on well results this year?
Possibly. We can't guarantee anything at this stage, but it's certainly very possible that we could have some initial results this year.
Thanks, Aitan.
Thank you.
Next, we have Pierce Hammond with Simmons and Company.
Good morning, guys.
Hey, Pierce.
Dan, I was curious what your thoughts or plan was for 2015 hedging?
Yes. We have looked at 2015 hedging, Pierce, and we have considered it And looking at not only the NYMEX, certainly, it's just one component of it, but we had before we've kind of changed our accounting process and now go to mark to market, we had tried to tie some of our and looked at trying to tie some of our 15 volumes to a particular pipe, but what we saw was 1, it was not a very liquid market and 2, the differentials that we would have had to lock in advance were punitive. And what we have seen each month is that the forward looking curve gives a significantly higher discount than the actual month realizations. And we were not prepared to lock in those punitive differentials in advance in an illiquid market. But we as we've indicated or as we illustrated with our hedge book, we are interested in hedging and we'll continue to try to find ways to mitigate the volatility.
But it is your expectation that you'll put on some kind of NYMEX Henry Hub hedges for next year?
Yes.
Okay. And then my second question is really strong oil production growth this quarter. Congrats on that. Would you be willing to put out some oil production growth guidance for 2014?
Scott is shaking his head no. But right now with us moving a new rig into the area, us looking at additional acreage out there and how we might move our activity around a little bit. I'm more comfortable just to be putting it out there with what we have, but I am optimistic that what we have out there is certainly reachable.
And then one last one for me and I apologize if you've already mentioned this in your prepared remarks, but what is current net production in the Marcellus or what is the month to date production look like there?
Gross production up there is we're working through these William issues that I've discussed, but we're over we're somewhere in between 1.4, 1.5.
Great. Thanks so much, Dan.
Thank you, Pierce.
Next, we have Matt Partillo with TPH.
Good morning, guys. Hi, Matt. Just two quick questions for me. I was wondering if we could get an update on how your downspacing test is performing in the Marcellus?
Okay. Just real quickly, we have several examples out there. We had a 10 well pad that we've been producing now about 9 months. About 9 months, we had our closest spacing on that pad. That spacing had the Lower Marcellus spaced at 500 feet and we still like the trend line on our curve from those wells.
We do continue to look at and implement additional down space opportunities. So, I guess, to say it differently, we are going to down space further. So everything we've seen is positive so far.
Great. And so is it the plan there to potentially maximize the amount of wells you're able to fit in that section potentially with a little bit of interference or you're not seeing interference at this point?
Well, it's
still early in the curve to be able to make that definitive statement. The answer is no, we haven't, but it's still early in the production cycle when you think about how you're going to be able to ascertain what is incremental reserves and what is acceleration reserves.
Great. And just my second question on the Eagle Ford. As you mentioned, you're starting to see the returns exceed that threshold you guys have talked about in the past. I was wondering if you could provide a little bit of color around the acceleration potential. And then I guess just a quick follow-up.
In regards to the completions you're using in the basin, could you give us a little bit of color on kind of what your current completions are in terms of the size of the fracs you're doing and the number of stages you're completing? Thank you.
Okay. On the acceleration side of the Eagle Ford, we have brought in another rig. We plan on implementing a walking package on a couple of rigs that do not have that capability today, which will help accelerate our efficiencies as we've discussed. We've mentioned that we're looking and continue to look at additional acreage out there. With that opportunity, if we have success, I think you could anticipate additional acceleration, maybe another rig in that as a result of additional acreage.
So that is also a way of doing it. When you look at the completions and you look at the 10 well that we recently did, the average lateral length was 6,700 foot or so. We had an average of 26, 27 stages in those wells. And the items that I mentioned, we're toying with the proppant size. We are looking at the amount of profit per stage.
So all of those things we're gathering additional information on and we continue to improve with the again our type of things that we're exploring out there.
Thank you very much.
Thank you, Matt.
Our next question comes from Subash Chandra with Jefferies.
Yes, hi. Following up on the Eagle Ford questions, 2 for me. 1 is, can you be more specific just on the proppant intensity, pounds per stage or pounds per foot, what you might be trying there in terms of escalation? And then, with the 8,500 foot laterals included in this update? And finally, if you could just refresh me on the net locations you have remaining in your current acres?
Okay. I'll take this first on the location size. If you use 400 foot spacing, we are probably over 600 locations. Now we're looking at the down spacing going down to the 300 foot and as I mentioned that could add 20 5% to 30% or so to the location count. On the profit, I'll let Steve Lindeman have a brief discussion on the profit question on what we're doing on a per foot basis and maybe how we're tweaking some of the proppant size without getting into too much detail.
Yes. Just quickly, if we look at our 2013 program, we had pumped a lot of fortyseventy mesh sand in the, let's say, 300,000 to 400,000 pound range. We've increased our proppant to 30, 50 and we've actually done some 20, 40 jobs now and we're pumping about £400,000 to £500,000 per stage on those treatments. And then as Dan mentioned earlier, we are narrowing our spacing from 275 that we had last year down to something below 250 this year. Okay.
Got it. Okay. And just the final one was if the 8,500 foot wells were included in this update?
Yes. Some of those 8,500 foot wells were in the 10 well average that I indicated to you.
Got it. Okay. Thank you very much.
Thank you.
Our next comes from David Deckelbaum with KeyBanc.
Just to clarify, you talked about perhaps adding another rig in the Eagle Ford, but the 2015 guidance assumes on terms of overall growth that you're using 3 rigs in the Eagle Ford and 6 in the Marcellus?
That's correct. Okay.
And how do you, I guess, balance you did talk about you haven't done any share repurchases to date. I guess, do you look at perhaps putting a rig in the Eagle Ford as a better use of capital than perhaps thinking about share repurchases right now? Or is there are they not necessarily mutually exclusive?
Well, they're not mutually exclusive. However, with the efficiency gains and what we've been able to see with the realized pricing, the Eagle Ford is furnishing excellent returns. And as I mentioned, we have and you mentioned, we have 3 rigs running there now, if in fact we can be successful on additional acreage, we could increase that rig count also, not only for our guidance of 2015, but we might be able to do something earlier than that.
Great. Thanks, Dan.
Thank you, David.
Our next question comes from Brian Singer.
Thank you. Good morning.
Hey, Brian.
This may be repetitive, in which case I apologize, your CapEx for the quarter was down a bit and the lowest in a while. And I just wanted to see if you could talk about the outlook for capital spending for the rest of the year, how Marcellus prices could make that fluctuate one way or the other in terms of
the budget that you have outlined? Brian, this is Scott. We reaffirmed the capital guidance night, which is 1.375 to 1.475. That plan, again, there might be some variability within it, but that's still the plan. It was reaffirmed 2 days ago in our Board meeting.
It's basically a timing difference, just some of the timing and the flow through of the dollars associated with the completion operation and the drilling operation. We still expect to be within that range. So they'll be from where we were thinking maybe earlier in the year, there's going to be more in the second half of the year. And then unless there's some huge dramatic falloff worse than any of us anticipate, that plan is not going to change.
Okay. And that is actual change in activity in terms of the level of spending in the second half? Or that's just kind of accounting noise where you actually probably really did spend more in Q2 than gets reported for GAAP?
Yes. That's accruals. It's accounting noise.
Got it. Got it. So effectively, you think you're generally on pace as opposed to expect some acceleration in your base level spending?
Correct.
Great. And then I think you mentioned share repurchases in your opening comments. Can you add any more color as to what you would need to see to become more aggressive on that front?
Well, as I mentioned, we're trying to just dovetail out with the management of our capital exposure and some of the activity that we are in the middle of, Brian, regarding lease negotiations with that and with success or without. They're not, again, mutually exclusive, but we felt like that we wanted to do that, have some resolution if you will on a couple of ideas that we're thinking about before we jumped out and bought additional shares.
Great. Thank you very much.
Thank you.
Our next question comes from Marshall Carver with Haykin Energy Advisors.
Yes. Most of my questions were already asked. I did have a question on the downspacing tests on the Marcellus. How many additional downspacing tests are you planning for the back half of this year with the 500 foot spacing? And what are your average well spacing for this year?
Yes. Marshall, we're going to on the going all the way down in the Lower Marcellus to 500 feet, we're going to watch the wells that we have done that close together to see how they perform. We wanted a benchmark that was very close and we think five 100 foot is very close for the Marcellus. But away from the 500 foot, for example, we have a large pad that we are going to drill that will all of the wells on that large pad will be down space less than 1,000 foot. So we do and in earnest, we are continuing a down spacing effort, but the 500 foot was a downspaced distance that again is going to give us some very, very good data.
But I would not anticipate that the entire Marcellus would be able to be down spaced to 500 foot, but I do anticipate it would be able to be down spaced less than 1,000.
Okay. Thank you.
Thank you.
I'm showing no further questions. We will now this concludes the question and answer session. I would now like to turn the conference back over to Dan Denches for any closing remarks.
Thanks, Youssef, and I appreciate all the questions. The questions fairly narrowed in a band. But again, the takeaway from my closing comments prior to the Q and A, Cabot is going to be able to deliver some good results with our growth production growth, our capital efficiencies. I think you're getting a flavor on what we're going to be able to do with our Eagle Ford operation. And though it's early stage in what we think we can do with our increase in liquids volumes, but we're optimistic that we're on the right track in that area.
And directionally, I think you can anticipate additional capital to be spent in that particular area. So with that, again, I appreciate the interest in the second quarter call and look forward to visiting with you all on the 3rd quarter call. Thank you.
The conference has now