Good day, and welcome to the Cabot Oil and Gas Corporation First Quarter 2015 Earnings Conference Call and Webcast. All participants will be in a listen only mode. After today's presentation, there will be an opportunity to ask questions. 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 Q1 that were outlined in this morning's press release.
First, equivalent net production for the Q1 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 4th quarter. Of particular note, our daily liquids production for the quarter increased 132% compared to the prior year's comparable quarter and 20% sequentially over the Q4, highlighting the success of our team in the Eagle Ford. Net income excluding select items for the quarter was $49,000,000 or $0.12 per share and discretionary cash flow for the quarter was $240,000,000 Both of these items decreased relative to the Q1 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 reaffirm 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 Q1, the state of Pennsylvania began reporting monthly production data and did report for both January February. Cabot was the top producer in Pennsylvania, which is not bad for a company that has never operated more than 6 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 1st quarter natural gas realizations were $2.46 per Mcf, which is $0.52 below the average NYMEX price for the quarter, an improvement relative to the 1.04 dollars differential in the Q4.
Excluding the impact of hedges, our realizations were $0.75 below NYMEX as compared to 1 point 2 dollars in the Q4 of 2014. 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 prices. Many of these deals do roll off in March have or we do have over 20% of our expected volume sold at a fixed price above $2 in the Q2. Based on our current view of where the regional indices will settle over the quarter, we anticipate that Q2 price realizations will be between $0.82 $0.92 before NYMEX below excuse me, below NYMEX 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 3rd quarter will look similar to the 2nd quarter as it relates to the percentage of sales by index. As we have guided, we have reduced our production volumes for the 2nd quarter relative to the Q1 in response to our expectation of continued weakness in pricing during the 2nd 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 Q2. Most notably is the new looping of the Transco lighting line in conjunction with the Leidy Southeast expansion project.
Although this expansion of 525,000,000 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 throughput on the Leidy line currently in price currently resulting in pricing pressures during this period. We expect to produce between 1 point 55 Bcf and 1.6 Bcf per day of gross production in the Marcellus for the Q2 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 that we have the ability to move volumes in excess of these baseload 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 3 rigs and 1 frac crew down from 5 rigs and 2 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 20.15. However, 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 Q1 call, we had just made a change in The increase 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 cost, 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 1300 locations as a result of our bolt on acquisitions in the Q4 of last year and the success of our 300 foot down spacing program across our acreage position. We have also seen a 30 percent decline in operating cost in South Texas as our team continues to work on driving down our cost structure. We are currently running 2 rigs in the play with plans to decrease to 1 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 FERC certificate of public convenience approving constitution pipeline and the New York DEZ formal notice of complete application for the final New York permit. 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 twenty sixteen. 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 towards the finalization of New York State permits by the end of the second quarter and FERC implementation plan is expected to be filed by Williams during the Q2.
Based on the progress during the last few months, we continue to be optimistic that construction can begin mid summer 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 $1,400,000,000 to $1,800,000,000 providing us ample flexibility in this challenged environment. Our lenders also approved an increase in our borrowing base from $3,100,000,000 to $3,400,000,000 despite the lower commodity price environment. A total of 20 lenders participated in this upsized facility including 6 new banks. 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 form a for this increase in commitments, we had over $1,500,000,000 of undrawn commitments as of the end of the Q1. In this morning's press release, we initiated 2nd quarter production guidance, which implies slightly over 1.5 Bcfe per day of net equivalent production for the quarter at the midpoint. Despite this sequential decline in production relative to the Q1 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 2nd quarter levels later in the year. Our capital program for the current year remains unchanged at $900,000,000 I would however highlight that not only is our 2015 capital program weighted heavily to the first half of the year. The Q1 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 for LOE, taxes other than income and DD and 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 Appalachian. 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 the interim 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 Q2, we remain confident in our production guidance range for the year and continue to be excited about our midterm outlook as we increase our portfolio of firm sales and firm transportation to close to 3 Bcf per day by the end of 'seventeen, 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. Our first question comes from Subash Chandra of Guggenheim.
Please go ahead. Yeah. Hi, good morning. 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, etcetera, and if there's any interest in doing that.
And then secondly, if you can maybe get a more granular on the impressive operating costs experienced in the Q1? Thanks.
Okay. First, I'll respond to the any M and A considerations within our company. We are 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 and A opportunities, considerations. We are 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, I have 2 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.
Yes. For the South region in the Q1, we really tackled our unit saltwater disposal costs. So that's one of the big drivers. 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.
And again for the North regions, it's more of the same thing on the optimization yet looking at our recycling and our trucking costs and just kind of across the board working just to lower costs. If I could just follow-up just on the Eagle Ford. The electrification is I suspect that's for the artificial lift and etcetera there. Do you see that happening in a timely fashion with getting landowner 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 away purchased. One of the main substations that we need for electrification was put in service in the Q1. As a matter of fact, we are 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 field on power kind of into the Q3 of this year.
Okay, great. Thank you very much.
Thank you.
Our next question comes from David Deckelbaum of KeyBanc. Please go ahead.
Good morning, guys. Thanks for taking my questions. Dan, just curious if last quarter you alluded to this or you guys communicated that you wouldn't have a high point in production in the Q1 and that's really with seasonal winter demand and taking advantage of some of the firm 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 just for context, I mean, maybe you could go into a little bit more how you're managing the curtailments. I know that there's downtime associated with project maintenance and construction, But are you just allowing sort of field line pressures to build and that's really curtailing volumes that way? And what sort of recovery in prices are we thinking about before 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 during this period when the maintenance projects were going to be implemented and you were in the shoulder months. In regard to our field operations and methodology of how we are 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 volumes that they were at. It is more of an across the board consideration of how we'd bring field 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 '16, 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 it would naturally be better than Appalachia, but do you have a sense of how close that pricing should be to NYMEX and what you see that how you see that dynamic kind of building
out? Well, certainly on a historic look price points 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 kind of broadcast that we will make that call on how we would roll into 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 Q3, 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 1 100% of Constitution immediately, but it may be just a displacement from the Millennium or Transco or Tennessee lines. Okay.
Thanks for that color, Dan.
Thank you.
Our next question comes from Brian Singer of Goldman Sachs. Please go ahead.
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 500,000,000 a day and then you make that 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 oversupplying or potentially oversupplying the local market versus new production to go on to Constitution?
Yes. It's a good question, Brian. And how I answer the question will be dependent upon how much I might fill Stonak or squirm over here in front of me. But the 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 0.5 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 Q.
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 1st part of 2016, but also looking at 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 in the 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 2 other points. 1, 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 to additional substantive midstream takeaway arrangements?
Once you cover the midstream, kind of 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, with Leidy Southeast this fall being the very important project that we have some long term sales associated with it that's going to improve pricing. There's, of course, following up with that, there's the Columbia Eastside expansion. We have some additional capacity coming on at that point.
After that, we have, of course, Constitution in mid summer 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 once you move gas over into New Jersey area from our production area. So that's the 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 fully just let me know. But we do anticipate seeing additional incremental cost reductions in the in our operations. We have not realized any of the savings as Steve indicated and 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 year end.
Great. Thank you.
Thank you, Brian.
Our next question comes from Pierce Hammond of Simmons. Please go ahead.
Good morning and thanks for taking my questions.
Hey, Pierce.
Hey, Dan. Dan, there
have been many reports in the press about a frac log or a significant backlog of drill but not completed wells. And previously at Q1 earnings you said that Cabot should exit 2015 with approximately 45 wells in the Q for 2016 in the Marcellus and approximately 20 wells in the Eagle Ford. And I know you've talked about this a little bit
in the Q and 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 for backlog, is it real? Is it overstated or whatnot? 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's always seems to be a moving number that you see out there and I see different accounts 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 6 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 the 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 6 to 8 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 kind of coming from that area, 12 rigs and 6 or 8 frac crews are going to have one hell of a time keeping up with any some curtailed volumes that could keep maybe 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 in under those circumstances.
So on 14 at the end of 2014, I think we had a similar number. We might actually have a couple of 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 refracking wells. Do you see the same opportunity for Cabot? And if so, in what region?
Well, I've had a 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 it kind of been in a high level, I'll let him just kind of talk about maybe some of the areas that a refrac might be considered. Steve? So Pierce,
when we look at the successful refracs throughout the industry, really what has been targeted is wells that have had I would say less sand concentration or lower conductivity 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 then 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 towards £1600 per foot. Cabot does have some opportunity for refracs. 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 refrac and on the new well that you drill in a down space perspective. Great. Well, thank you very much for the color.
Thank you.
Our next question comes from Bob Christiansen of Imperial Capital. Please go ahead.
Yes. Thank you. My understanding that 60 days after the public commentary in New York, which ended February 27, under the Uniform Procedures Act that 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 of months and our expectation are that those permits will be issued sometime in the Q2 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. And 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 of 2004 to October February 14 to October 14 like 8 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? 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.
So I
think they've had a very lengthy time to do a very thorough review.
Got it. Well, thank you very much.
Thanks, Bob.
Our next question comes from David Beard of Iberia. Please go ahead.
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 just you seem to have a bit more volatile production here Q1, Q2, and especially with prices being fairly weak, I would have expected volumes to be commensurately lower. Can you just talk a little bit about the pricevolume relationship? And I know we're talking a fairly short term point of view and maybe what to expect going forward relative to that pricevolume 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 Q1 volumes were robust and we felt good about our operational performance in the Q1. But in the Q2, we had anticipation again of the maintenance projects and all particularly affecting the pipes that we sell into up in 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.
No, 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
don't know. 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 6 County area that there's in April, beginning in April, there were 12 rigs running and 6 to 8 frac crews in that area and producing and to the performance levels of Cabot type wells, you were 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 would be inclined to believe at some point in would be inclined to believe at some point in time you are going to see an inflection point on the volumes produced.
No, that's helpful. Thank you, gentlemen. Appreciate the time.
Thanks, David.
Our next question comes from Dan Duffy of Stifel. Please go ahead.
Thanks. You guys continue to generate solid results in Eagle Ford, especially compared to earlier vintage wells. I guess could you give details surrounding your current standard completion design and any technical improvements you're currently testing to further enhance productivity?
Our our lateral lengths are beyond 6,000 feet and our profit per lateral foot is 16 100 or so right now and we certainly are aware that some companies have gone up to 23, 24, 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 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 end of the year with 1 rig and a not a 20 fourseven 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 a somewhat of a holding pattern with 1 rig and 1 crew.
Okay. Thanks for the detail. You kind of touched on the 300 foot 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 kind of 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 space 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 and A previously, but curious if you guys are interested in seeing bolt on acquisition opportunities in South Texas?
Well, again, to not get granular on it, we look at all the opportunities that are available out there. We are just fresh off picking up 2 properties that were good fits to our operation in the Eagle Ford that we closed at the in the Q4. The results that we've seen from that efforts proved out a efficient program and consistency with our expectations or exceeding expectations with the wells that we drilled on those properties. So it all comes together and you get into an environment that is a little bit more robust than a $50 oil price, then if it makes sense, we'll do it.
Thanks. Appreciate all the color today, guys.
Yes. 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 reductions 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 throughout the year.
Thanks again for your interest in Cabot.
The conference has now concluded. Thank you for attending today's presentation.