Coterra Energy Inc (CTRA) 2015 Q1 法說會逐字稿

Good day, and welcome to the Cabot Oil and Gas Corporation first-quarter 2015 earnings conference call and webcast.

(Operator Instructions)

Please note this event is being recorded. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, CEO, and President. Please go ahead, sir.

Thank you, Dan. And good morning all. Thank you for joining us today for the Cabot first-quarter call. With me today, as usual, are several of our Management team. Before we start, the standard boilerplate regarding forward-looking statements do apply to my comments today.

I would first like to touch upon a few financial and operating highlights from the first quarter that were outlined in this morning's press release. First, equivalent net production for the first quarter was slightly above 1.9 Bcfe per day, an increase of 43% over the prior year's comparable quarter, and a sequential increase of 15% over the fourth quarter.

A particular note, our daily liquids production for the quarter increased 132% compared to the prior year's comparable quarter, and 20% sequentially over the 4th quarter, highlighting the success of our team in the Eagle Ford. Net income, excluding select items for the quarter, was $49 million, or $0.12 per share, and discretionary cash flow for the quarter was $240 million. Both of these items decreased relative to the first quarter of 2014 due to a 34% decline in realized natural gas prices and a 55% decline in realized oil prices.

On the cost side, our team continues to work hard and deliver on driving down unit cost, which is evidenced by the 10% decline in cash unit cost to $1.22 per Mcfe. I think this decline is even more impressive when considering that we have increased the percentage of oil-focused activity in our mix, which typically is more costly to operate on a per-unit basis.

Additionally, we reaffirmed guidance even with the planned curtailment, which is I think the right economic decision. In the Marcellus, our operational results for the quarter exceeded expectations. The Company averaged over 2 Bcf per day of gross Marcellus production, which is 1.7 Bcf per day of net production, an increase, as mentioned previously, 43% over last year's comparable quarter.

We completed 19 wells and placed 17 wells on production, which drove the 16% sequential growth for the quarter. These production levels highlight the productivity of our Marcellus assets and demonstrates that the asset quality and well performance are quite unique assets for Cabot. However, we would like to see more favorable natural gas prices, which we anticipate will materialize upon the in-service of several new takeaway projects in our area, scheduled over the next 12 to 18 months, along with a continued increase in natural gas demand growth.

I want to also highlight that during the first quarter, the state of Pennsylvania began reporting monthly production data and did report for both January and February. Cabot was the top producer in Pennsylvania, which is not bad for a company that has never operated more than six rigs in the state.

Marcellus pricing continues to be the primary focus of our conversations with shareholders, and, I imagine, is front of mind for everybody on this call today. Our first quarter natural gas realizations were $2.46 per Mcf, which is $0.52 below the average Nimex price for the quarter, and improvement relative to the $1.04 differential in the fourth quarter.

Excluding the impact of hedges, our realizations were $0.75 below Nimex, as compared to $1.21 in the fourth quarter of 2014. The primary driver of the differential narrowing quarter to quarter was that our marketing team was able to secure a meaningful amount of favorable fixed-price contracts for the winter season, prior to the most recent decline in natural gas pries. Many of these deals do roll off in March.

However, we do have over 20% of our expected volume sold at a fixed price above $2 in the second quarter. Based on our current view of where the regional indices will settle over the quarter, we anticipate that second-quarter price realizations will be between $0.82 and $0.92 below Nimex, and before the impact of hedges.

Additionally, we anticipate another $0.40 to $0.45 uplift in realized prices from our hedges based on the current strip. Since we frequently get asked the question, we have provided a split of our pricing exposure by index on our website, which should provide some clarity on how we are marketing our gas for the quarter. We anticipate that the third quarter will look similar to the second quarter as it relates to the percentage of sales by index.

As we have guided, we have reduced our production volumes for the second quarter relative to the first quarter, in response to our expectation of continued weakness in pricing during the second quarter, some of which is being driven by numerous maintenance and construction projects directly related to our downstream market.

Virtually all of the pipelines our production reaches have planned or scheduled projects during the second quarter. Most notably is the new looping of the Transco Leidy line in conjunction with the Leidy southeast expansion project. Although this expansion of 525 million cubic foot per day of new capacity will ultimately be very beneficial to Cabot at in-service in December of this year, the 43-day construction period is expected to affect through-put on the Leidy line currently, resulting in pricing pressures during this period.

We expect to produce between 1.55 Bcf and 1.6 Bcf per day in gross production in the Marcellus for the second quarter, and we'll continue to monitor the price environment before we make any decisions on selling more gas into the local market. It is clear from our first-quarter production that we have the ability to move volumes in excess of these base-load levels. But we are not going to chase production growth to the detriment of cash margins.

As planned, we recently decreased our level of activity in the Marcellus to three rigs and one frac crew, down from five rigs and two frac crews at the beginning of the year. Our current operating plan and capital program assumes this level of operating activity remains constant for the balance of 2015.

However, in light of our expectations for continued weakness throughout Appalachia, during the summer months we do often reevaluate our program and may consider delaying completions as we await a more favorable price environment in the future. Again, not anticipating affecting our guidance.

In the Eagle Ford, moving on to the Eagle Ford, our team had an outstanding quarter operationally in South Texas as evident by the 19% sequential growth in daily liquid volumes over the last quarter. During the quarter, we placed 20 wells on production, many of which weren't turned in-line until late in the quarter, which resulted in the strong sequential production growth.

As a reminder, much of this activity was driven by near-term, held-by-production commitments, primarily from the acreage we acquired late last year. If we take a step back and we look at where our Eagle Ford program was a year ago, it really highlights the significant improvement we have seen from this asset in a short duration of time. On last year's first-quarter call, we had just made a change in the Management team overseeing the program, and made the decision to increase our rig count from two to three.

The increase in rig count was predicated on an increase in the return profile to over 50%, hoping as a result of well performance enhancements and decreased well cost. Keep in mind that we were running our economics at $90 per barrel at that point. We had approximately 600 gross locations identified based on 400-foot spacing, and frankly, we're pretty excited about the long-term value generation opportunity afforded us by these properties.

If you fast-forward 12 months, and a lot of things have changed. The most obvious being the underlying commodity price. However, as a result of significant improvements in our operating efficiency and well performance, along with a reduction in service costs, our operation now eclipsed the same 50% rate-of-return threshold at a price of $65 per barrel, which is only $5 higher than today's 12-month strip.

Relative to the 600 gross locations we had mapped at this time last year, we have now increased that location count to over 1,300 locations as a result of our bolt-on acquisitions in the fourth quarter of last year and the success of our 300-foot down-spacing program across our acreage position. We have also seen a 30% decline in operating cost in South Texas as our team continues to work on driving down our cost structure.

We are currently running two rigs in the play, with plans to decrease to one rig by the end of May. Our plan is to remain at this level throughout year-end. However, we will consider acceleration of completion activity in the Eagle Ford, if we see a sustained oil price recovery, or further reduction in drilling and completion costs, which have decreased to date 20% to 30%.

Now, let's move to another area that has many questions in regard to our time with investors. On the year-end call, we discussed a few of the significant accomplishments the Constitution had recently achieved, such as the [Burke] Certificate of Public Convenience, approving Constitution Pipeline, and the New York DEC formal notice of complete application for the final New York permits. Also we briefly discussed the regulatory process in New York, requiring a public comment period extension, which closed on February 27, 2015.

Today, we can continue that update with the following. The project remains on its current schedule for in-service during the second half of 2016. The New York DEC is currently finalizing responses to the comments received during the public-comment period. Constitution now has possession of 100% of all the tracks necessary to begin construction.

Constitution is working toward the finalization of New York State permits by the end of the second quarter. And the Burke implementation plan is expected to be filed by Williams during the second quarter. Based on the progress during the last few months, we continue to be optimistic that construction can begin midsummer, assuming all these permits are in hand.

As we also mentioned in our press release, we recently amended our credit facility, increasing the total commitment from $1.4 billion to $1.8 billion, providing us ample flexibility in this challenged environment. Our lenders also approved an increase in our borrowing base from $3.1 billion to $3.4 billion, despite the lower commodity price environment. A total of 20 lenders participated in this upside facility, including six new banks.

So we are appreciative of the support we saw in this transaction, and we believe it demonstrates the quality of our Company, both operationally and financially. Pro forma, for this increase in commitment, we had over $1.5 billion of undrawn commitments as of the end of the first quarter. In this morning's press release, we initiated second-quarter production guidance, which implies slightly over 1.5 Bcfe per day of net equivalent production for the quarter at the mid-point.

Despite this sequential decline in production, relative to the first quarter due to the previously mentioned curtailments in the Marcellus, we have reaffirmed our 2015 production growth guidance range between 10% to 18% based on a stronger than anticipated first quarter and expectations for increase in production above second-quarter levels later in the year. The capital program for the current year remains unchanged at $900 million.

I would, however, highlight that not only is our 2015 capital program weighted heavily to the first half of the year, the first-quarter capital expenditures on the cash flow statement also reflect carry-forward cash outlays associated with our capital incurred in 2014 but not paid until this year. We have also decreased our unit-cost guidance bar LOE, taxes, other than income, and DD&A. These updates can be found on our website.

In summary, our strong first-quarter production highlights that Cabot is able to achieve operationally strong performance. Currently, lower natural gas prices are a reality through Appalachia. However, we are optimistic the environment improves over the next few quarters through a combination of decreased levels of operating activity, increased demand, and new takeaway projects.

Our goal in end-term is to protect margins and ensure we aren't giving away our valuable resources at marginal prices. Despite our planned reduction in volume for the second quarter, we remain confident in our production guidance range for the year, and continue to be excited about our mid-term outlook as we increase our portfolio of firm sales and firm transportation to close to 3 Bcf per day by the end of 2017, of which approximately 70% reaches markets outside of Appalachia.

With that, Dan, I'll be more than happy to answer any questions.

We will now begin the question-and-answer session.

(Operator Instructions)

Subash Chandra, Guggenheim.

I was curious, strategically, if there's any interest at all in securing a southern Marcellus foothold? As I suspect there's a shakeout coming, the American Energy folks of the world, et cetera. And if there's any interest in doing that? And then secondly, if you could maybe get more granular on the impressive operating cost experienced in the first quarter? Thanks.

Okay. First I'll respond to any M&A considerations within our Company. We're proactive in evaluating opportunities out there. Each year, I think as you're probably aware, that we have our strategy session. And certainly in environments as we're in today, we have a time set aside in our executive board session just as we did yesterday to talk about all the macro environment, including M&A opportunities, considerations. We're not in any discussions with a southwest Marcellus or Utica opportunities down there, but we want to be aware of what opportunities are available. And we'll continue to evaluate any possible opportunities.

But specifically, for the southwest part of the state, again, we're not in any transaction discussions or anything at this particular time. In regard to the operating side of the business, two of the guys here, Steve Lindeman, who's running our south region, and Phil Stalnaker running our north region, I'll let them comment on just some of the things that we've seen in the operating side of our business.

For the south region in the first quarter, we really tackled our unit salt water disposal costs. That's one of the big driver. And then secondly, we switched out some of our treating chemicals and have driven that cost down. And we're still looking at -- there are some things we're trying to tackle for the second half of the year in terms of electrification and other things that we can do to reduce our operating cost.

Again, for the north region, it's just more of the same thing on the optimization in looking at our recycling and our trucking costs, and just across the board where we can get some lower costs.

If I can just follow up just on the Eagle Ford, the electrification is -- I suspect that is for the artificial lift and et cetera. Do you see that happening in a timely fashion with getting land owner consent and that kind of stuff? And given a sense of what kind of operating cost efficiencies we can have by maybe getting off diesel, which might be what's being used currently?

Yes, we do. We've made a significant effort over the last half of the year and into the first quarter to get right of way purchased. One of the main sub-stations that we need for electrification was put in service in the first quarter.

As a matter of fact, some of our team was over there for an opening ceremony last night. And we are in the queue for several projects to get put online, and we're hoping to have a portion of the field on power kind of into the third quarter of this year.

Okay, great, thank you very much.

Thank you.

David Deckelbaum, KeyBanc.

Good morning, guys. Thanks for taking my questions. Dan, just curious, if -- last quarter, you alluded to this, or you guys communicated that you would have a high point in production in the first quarter, and naturally, with seasonal winter demand and taking advantage of some of the firm's sales contracts and then decline into 2Q and 3Q, and rebound in the 4Q. Is the plan today, with the reiterated guidance, are you guys more or less within the original plan that you had set out a few months ago?

Yes, we are. We could not predict exactly what the realizations were going to be. We thought they were going to be a little softer. We were glad to see quarter over quarter a little bit of reduction in the differentials. But our plan is still intact with our original guidance.

And then just for context, maybe you could go into a little bit more how you're managing the curtailments? I know that there is down time associated with project maintenance and construction. But are you just allowing field line pressures to build and naturally curtailing volumes that way? And what sort of recovery in prices are we thinking about before you would start accelerating the volumes here?

Well, we're not going to go into specifics on the pricing for that decision process, David. But we do expect to see better realizations later in the year than we anticipated during this period when the maintenance projects were going to be implemented, and you were in the shoulder month.

In regard to our field operations and methodology of how we're reducing the volumes out there, we have discussed in the past that we have a very flexible gathering system that allows us to move gas, even from one particular pad to multiple outlets. We do anticipate that as we raise the fuel pressures in the field, and allow that to happen, that we would naturally bring down some of the volumes that we would be moving into the pipe.

And so it's not a shut-in, a particular portion of the field, and produce the others at those volumes that they were at, it is more of an across the board consideration of how we'd bring the fuel pressures up a little bit to allow the volumes to be reduced.

Got it. And if I could just wager one more, perhaps for Jeff, or anyone that wants to take it, with Constitution potentially coming on in the summertime of 2016, how are you guys thinking about the ends market there right now in terms of pricing? And is it -- I know that you would postulate that it would naturally be better than Appalachia. But do you have a sense of how close that pricing should be to NYMEX, and how you see that dynamic kind of building out?

Well, certainly on a historic look, the price point is up there at that right station and into that line are close to the NYMEX pricing. Various times of the year, it exceeds NYMEX pricing by a considerable margin. We've already broadcast that we will make that call on how we would roll in to the Constitution volumes, whether it would be just total incremental volumes to what our current production is at that point in time of commissioning, or if it'd be a phase-in by displacing the volumes from our current price points to the Constitution pipeline.

I think it's safe to say, at that point in time, regardless of when Constitution is commissioned, whether it's in the middle of the summer or right at the beginning of the third quarter, I think it is safe to say that those price points more likely, if they're consistent with historic, is going to be at a higher, better price point than the current indices that we're selling into. So we would, naturally, move and fill 100% of Constitution immediately, but it may be just a displacement from the Millennium or Transco or Tennessee lines.

Thanks for that color, Dan.

Thank you.

Brian Singer, Goldman Sachs.

Thank you, good morning.

Hey, Brian.

I actually wanted to follow up on that exact point, which is how you strategically determine the appropriate mix of filling Constitution with production you already have versus kind of new production. When do you have to make that call?

Are you planning on increasing your production capacity from where it is today by the full 500 million a day, and then you can make that call at the last second? Or is there a point where, earlier on, where you have to figure out your rig count and make that call on the split between transferring production currently over supplying or potentially over supplying the local market versus new production to go onto Constitution?

It's a good question, Brian. And how I answer the question will be dependent upon how much I make Phil Stalnaker squirm over here in front of me. (laughter) But keep in mind that the capital intensity necessary for us to ramp up our volumes is minimal, comparatively speaking, when you look across the space to be able to find another half of Bcf a day.

The driving consideration for that volume of production is going to be, not necessarily in the rig count, but it's going to be how we stage in frac crews to allow timely completions of those wells that we have in the queue. So the plan, building up to that decision point, it would be our intent to have in the queue that would allow us to have that maximum flexibility, is to have wells drilled and in the queue waiting on completion, if you will, as opposed to backing it up a step and saying that we haven't even drilled the wells or drilled those pad sites yet.

So when you get towards the end of this year, the discussions that we'll have with the north will be, all right, let's look at our capital program, let's look at our cash flow, let's look at the dynamics of the macro market, and let's make a call on bringing on another rig if we felt like we needed it in the first part of 2016. But also looking out ahead at the end of the second quarter, beginning of the third quarter, how many frac crews do we want to have lined up to get ready to move those volumes into Constitution?

Again, keep in mind that Constitution is going to be filled immediately upon commissioning. The decision is going to be, do we backfill Tennessee, Transco, Millennium with those volumes, and how long do we want to take to backfill those volumes? But at the end of this year, as we go into the planning stage for our initial budget for 2016, which we present to the Board in October, we'll have some of these discussions.

Great, thanks. And my follow-up is if you could just address two other points. One, whether you're seeing any substantive cost deflation that, unrelated to your activity levels, could push down your budget this year or not? And then your outlook for committing two additional substantive mid-stream takeaway arrangements?

Why don't you cover the mid-stream and how that's going to roll out?

Okay, Brian, this is Jeff. I think there's a number of smaller projects that we're involved with Leidy Southeast this fall, being the very important project that we have some long-term sales associated with, that's going to improve pricing. There's, of course, following up with that, there's the Columbia East Side expansion. We have some additional capacity coming on at that point.

After that, we have, of course, Constitution, midsummer of next year, and those are the more or less short-term drivers on new capacity. And then Atlantic Sunrise in 2017. And also a new project with Tennessee. It's a smaller scale project of about 150,000 a day that's going to move gas over into the New Jersey area from our production area. So that's kind of the short- and longer-term projects.

Yes, and Brian, on your question about cost, let me just answer this, and if I don't answer if fully, just let me know. We do anticipate seeing additional incremental cost reductions in our operations. We have not realized any of the savings, as Steve indicated, in, say, the electrification of some of our operations in the Eagle Ford.

But we also think that the service providers are out also obtaining and getting additional cost concessions from their providers that would naturally be shared somehow with the operators. So we do anticipate that additional cost reductions would roll through our program between now and year end.

Great, thank you.

Thank you, Brian.

Pearce Hammond, Simmons.

Good morning, and thanks for taking my questions.

Hey, Pearce.

Hey, Dan. Dan, there have been many reports in the press about a frac log or a significant backlog of drilled but not completed wells. And previously in Q1 earnings, you said that Cabot should exit 2015 with approximately 45 wells in the queue for 2016 in the Marcellus and approximately 20 wells in the Eagle Ford. I know you've talked about this a little bit in the Q&A and in some prepared remarks, but I wanted to see if that was still the case.

And then, if so, how do these figures compare to the number of wells that you have queued up entering this year? And if you have any big picture thoughts regarding this industry frac log, is it real? Is it overstated or what not? Love to get that color as well.

Well, first off on our expectations for year-end 2015, we do still maintain our expectations of 20 wells in the Eagle Ford and 45 wells or so in the Marcellus. That is going to remain consistent. I don't see much getting in the way of that expectation.

In regard to frac log and looking at the backlog, it always seems to be a moving number that you see out there. I see different accounts of what is backlog at any one given time. I do know that from an operation standpoint, and I'll talk more geographically about, say, where it could have a larger impact in our northeast Pennsylvania area, in that six county area. If you look at that area, we've talked in the past about how many rigs are running and how many frac crews are up there. Our most recent intelligence is that you had through, say, January, February, March, a certain number of rigs running up there. And most recently in April, we placed a number of rigs up there in that particular area, in our neck of the woods, at only 12 rigs that are currently running.

And we have, at any given time, six to eight frac crews operating in that neck of the woods. Now, if you do the simple math, and you look at the 8 Bcf or so a day that's coming from that area, 12 rigs and six or eight frac crews are going to have one hell of a time keeping up with any natural declines that you might suspect from the volumes that are being produced. I do think that there were and have been, just like we had, some curtailed volumes that could keep maybe backfilling some of that gas volume, and you're maybe today not seeing any type of real inflection point. But it doesn't take a mental giant to do the quick numbers on IPs, and 30-day averages, and all that for those number of pieces of equipment to say that there has to be some depletion of the backlog, if you will, and the ability of wells to keep up with the natural depletion that would occur under those circumstances.

So on 2014, at the end of 2014, I think we had a similar number. We might actually have a couple more wells at the end of 2015 as we had at the end of 2014. But for the most part, we're going to have a similar backlog for us.

Thank you for that color. It's very helpful. And then my follow-up is some oil service providers have highlighted the tremendous opportunity in re-fracking wells. Do you see the same opportunity for Cabot, and if so, in what region?

Well, I've had just a recent discussion with Phil in regard to our Eagle Ford operation, just the industry in general on kind of what's being done out there. And then at kind of in a high level, I'll let him just talk about maybe some of the areas that a re-frac might be considered. Steve?

So, Pearce, when we look at the successful re-fracs throughout the industry, really what has been targeted is wells that have had, I would say, less sand concentration or lower connectivity frac jobs pumped, as compared to what the current standard would be. And then secondly, a group of wells that might have different perf clustering than what's being used.

So a lot of people are targeting wells that may have been, let's say, perforated at 100-foot spacing and now where people are targeting 50-foot spacing. And the same thing kind of on the sand basis, where people may have done 800 pounds per foot versus now what people are pumping closer toward 1,600 pounds per foot.

Cabot does have some opportunity for re-fracs. I would say that we would target those when we would do the down-spaced wells. And do those in conjunction with that, so you could get the full benefit of the zipper frac, both on the re-frac and on the new well that you drill in a down-space perspective.

Great, well, thank you very much for the color.

Thank you.

Bob Christensen of Imperial Capital.

Yes, thank you. It's my understanding that 60 days after the public commentary in New York, which ended February 27, under the Uniform Procedures Act, at 60 days we should have some news out of the DEC of New York. That would imply next week. Is that the case, we should hear from them one way or another next week?

No, Bob. That's not the understanding we have from Williams at this time. The DEC has taken the time to thoroughly review the comments that were submitted in the public comment period. Our understanding is that they are close to releasing the answers so to speak on those comments.

There's still some work in progress surrounding the permits. But we made a lot of progress here in the last couple months. Our expectations are that those permits will be issued sometime in the second quarter, May, June time period.

I think you could answer a little bit about nothing materially that was --

Absolutely. So from the comments that had been submitted, our understanding from Williams is that the comments are very similar in nature, that the comments were submitted to FERC. So there's been nothing in their review of the comments that's been substantially different, I guess, than what they've seen before. So we're encouraged by that so far.

The one worry I have is that they would come with something that said we've got to study this and study it equally to the study period of the FERC. And that period I believe took from February 2014 to October of 2014, like eight months. And we want the same time that the Feds had on studying this. That's the concern I have. Should I have that concern that they could come with -- (multiple speakers)

Well, I think the application for the permit has been in New York DEC's hands for a much longer period of time than what you're referring to.

Okay.

So I think they have had a very lengthy time to do a review.

Got it. Well, thank you very much.

Thanks, Bob.

David Beard, Iberia.

Good morning, gentlemen. I apologize if this question has been asked because I had some trouble getting on the call. But I just wanted to review, you seem to have a bit more volatile production here first quarter, second quarter, and especially with prices being fairly weak, I would have expected volumes to be commensurately lower.

Can you just talk about the price volume relationship? And I know we're talking a fairly short-term point of view, and maybe what to expect going forward relative to that price volume relationship?

Well, we made an early determination and based on our crystal ball, which, again, is no better than anybody else's, but with our crystal ball, we made and placed our guidance out there early on that did take in consideration curtailed volumes. And where we are right now, our first quarter volumes were robust, and we felt good about our operational performance in the first quarter.

But in the second quarter, in anticipation, again, of the maintenance projects and all, particularly affecting the pipes that we sell into up at the Marcellus, we thought that by the continued supply increase and the construction projects and maintenance projects up there, that we would see softness in prices at this period of time. I think that is holding true, we're backing off some of the volumes.

And we think, just from a prudency standpoint, to protect shareholder assets and not to compromise our margin to the extent that the current price would yield, we think it is prudent in this environment to take some of the gas and protect our margins. I think that's a prudent economic decision on our part. And we are going to stick to that.

That's helpful. And just to change subjects on a follow-up. Given that we've seen some reduced rigs operating in the Marcellus both east and west, do you think there'll be an impact relative to production from the curtailment in the second half of the year? Or is it likely to be pushed off into next year for the industry?

I think by the second half of the year, whether or not you see a rollover is debatable. I think you will see a possible inflection point in any of the growth profile. Again, back to just the numbers that are out in front of us, if you believe that up in that six-county area that there's, in April, beginning in April, there were 12 rigs running, and six to eight frac crews in that area and producing approximately 8 Bcf a day.

Even if all those wells were to the degree and to the performance levels of Cabot-type wells, you are going to have a difficult time being able to maintain, much less grow, the production volumes from that production base. So I think the numbers have reflected that the other wells that are drilled out there are not like Cabot wells. And so, therefore, we'd be inclined to believe that at some point in time, you are going to see an inflection point on the volumes produced.

That's helpful. Thank you, gentlemen. Appreciate the time.

Thanks, David.

Dan Guffey, Stifel.

Thanks. You guys continue to generate solid results in Eagle Ford, especially compared to earlier vintage wells. Could you give details surrounding your current standard completion design, and any technical improvements you're currently testing to further enhance productivity?

Well, we won't get real granular on it, and I'll let Steve answer some of this. But our lateral lengths are beyond 6,000 feet. And our proppant per lateral foot is 1,600 or so right now, and we certainly are aware that some companies have gone up to 2,300, 2,400, maybe 2,500 pounds per lateral foot. And our south region will explore with some of that as we continue our operation. We've got our down-spacing program that we feel comfortable with, and have a number of pilot programs that had given us the confidence that a 300-foot down-space is going to be useful and be how we place our wells.

From this point forward, as we have been successful in maintaining our primary-term acreage, and we have had responsive landowners negotiate with us in regard to the timing of the obligatory wells or continuous development wells out there on their properties. Some of those mineral owners do not want to produce their oil into a low-price environment. So we've been able to extend some time on those particular leases. So between now and the end of the year with one rig, and not a 24/7 frac crew, some of the experimentation, if you will, and completion efforts that we would be implementing are not going to be very numerous simply because we're kind of in somewhat of a holding pattern with one rig and one crew.

Okay. Thanks for the detail. You kind of touched on the 300-feet spacing in your prepared remarks and just now. I'm curious, how many pilots do you have at 300-feet spacing? Is that kind of standard completion design? And how are you looking at it? Is it a stacked and staggered? Or are you just landing in the lower zone and keeping them 300 foot apart?

Well, we are in the lower zone with our 300-foot spacing, but we have several points within the lower zone that we are landing our wells. And we have 20 or 30 of the pilots that are out there that have shown good results.

But again, we have not gotten to the point of doing anything yet in the upper Eagle Ford on the staggers that some have been talking about. Our staggers are in a narrower range within the lower Eagle Ford on our placements. But we've also had 300-foot spaced laterals that have been in the same landing points also within the lower Eagle Ford that we feel comfortable about.

Okay, great. And then you touched on M&A previously, but curious if you guys are interested and seeing any bolt-on opportunities in south Texas.

Well, again, to not get granular on it, we look at all the opportunities that are available out there. We're just fresh off of picking up two properties that were good fits to our operation in the Eagle Ford that we closed in the fourth quarter.

The results that we've seen from that effort proved out an efficient program in consistency with our expectations or exceeding expectations with the wells that we drilled on those properties. So it all comes together, and you can get into an environment that is a little bit more robust than a $50 oil price. And if it makes sense, we'll do it.

Thanks, appreciate all the color today, guys.

Thank you, Dan.

This concludes our question-and-answer session. I would now like to turn the conference back over to Dan Dinges for any closing remarks.

Okay, Dan. I appreciate it. I appreciate everybody's focus on Cabot. As you're well aware, and we all are well aware, we're in a challenged commodity price environment in both oil and gas.

Efficiencies are being realized, and cost reduction is realized throughout our operation, both on a cash-cost basis for our unit production, but also in our capital program. And we expect to see continued improvement through the year. Thanks again for your interest in Cabot.

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