Coterra Energy Inc (CTRA) 2010 Q2 法說會逐字稿

Good afternoon. My name is Cynthia and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas second quarter 2010 earnings conference call. All lines have been placed on mute to avoid any background noise. (Operator Instructions) I would now like to turn today's call over to Dan Dinges, Chairman, President and CEO of Cabot Oil & Gas. Please go ahead, sir.

Thank you, Cynthia and good afternoon and I appreciate everybody extending their day and staying with us for this conference call. I have Scott Schroeder with me, I have Matt Reid who some of you all have met, VP of our South region; and Phil Stollhacker, VP of our North region. Also the forward-looking statements included in our press release will apply to my comments today. First and foremost, before I commence my prepared remarks, let me say this. That unequivocally, we will not issue equity to fund our capital program. I know there was a significant level of rhetoric around this today and let me emphasize that the equity issue has been and will continue to be for the value creation of opportunities we might see and not simply to reload our balance sheet. I will also make some comments regarding our capital spending later.

On the prepared remarks, Cabot reported financial results this morning that were in line with consensus expectations. When you compare these numbers against the previous year, lower natural gas prices and even with our higher production could not match the previous year numbers. From a clean earnings perspective, net income was approximately $20 million, with the selected items for this quarter including a gain on sale stock compensation and mark-to-market basis hedges. Certainly highlight of the quarter and I think a very positive trend that will continue was the near 20% production growth that we experienced. A couple of notations to make when you do look at this 20% growth is the fact that last year comparable production volumes included Canada production which was sold in April 30th of 2009.

Pro forma growth is 30% for the quarter, and 29% for the year-to-date period. Also, we had forecast our Lathrup station to start sooner than it did and this obviously delayed some of our production volumes in the second quarter. In a moment I will discuss the volumes we are now moving through the Lathrup station and increase to our production guidance as a result of that. Natural gas price realizations experienced 25% declined and as mentioned impacted margins for the quarter. In terms of our balance sheet, we had a debt level increase of $100 million from last quarter.

As we continue to acquire select acreage, mainly in Susquehanna and also drill to place our prior in term acreage in HBP status. I think many in our industry are continuing to drill primary term acreage and this certainly has been a catalyst for the rig count. However I do think the number of rigs necessary to accomplish this goal is beginning to peak.

In terms of core production our total company daily levels are approximately 375 million cubic foot equivalent a day and as our press release indicated, we have numerous wells in various stages of completion that will continue to add to our production profile. Today we posted new guidance for the third and fourth quarters that, combined with actual production for the first half, generate a 21% to 25% reported growth. Clearly, the pro forma numbers would be greater. Also, because of several quarters of better cost results, we have made improvements in guidance for several of our cost metrics. I also anticipate some of our unit costs will continue to come down. We also moved our capital guidance higher. This spending increase was done for solid business reasons. About one-third of the increase is allocated to Marcellus, infield leasing which allows us more efficient development up there. I will expand on this more later.

The other two-thirds is for drilling primarily as a result of partner well proposals in the Bossier or Haynesville and to a lesser extent a couple of oil wells associated with the new joint venture in the Eagleford we just executed. We do not want to stand out of the Haynesville Bossier wells and lose the opportunity to participate in an additional three to five wells in each of the proposed units in the future. This would cause the loss of a significant resource potential for our shareholders, estimated in each unit from the Bossier and Haynesville to be in the range of 48 to 100 BCFE. Again, the reason why we're staying in those particular wells.

As you can see, our balance sheet is not overleveraged. Let me add that the 2010 growth program we have can be accomplished without any additional new funding. That being said, let me add that we will explore adding to our credit facility or select asset sales. Any one of which can be accomplished within our existing borrowing base and without overleveraging the Company.

Now, let me move to operations. As I mentioned, we have numerous wells that strengthen our position in our areas of most focus, the Marcellus, Haynesville and Eagleford. In the Eagleford, south Texas, the Company has drilled its second horizontal Eagleford oil well. That well is 100% Cabot operating well, located in (Freo) county. And, it was drilled to a depth of 14,660 with an 80 -- excuse me, a 5800-foot lateral. The well is scheduled to be stimulated in late August. The rig is moving to a third location with drilling anticipated to begin next week on that third well.

Cabot holds as you'll recall about 52,000 net acres in the oil window of the play, with 300, 350 potential locations and a large resource potential also. Also in the oil window, but approximately 40 miles east of the well we just drilled, Cabot has entered into approximately 18,000-acre area of mutual interest with EOG. Each Company contributed 50% of the acreage in the JV with EOG as operator. Drilling is anticipated to begin in the fourth quarter of this year. Following the acquisition of a new 3D seismic shoot.

Moving to East Texas and the Haynesville Bossier, as previously announced Cabot has successfully drilled and completed its second operated horizontal shale well. Walters 1COG had 54%, was drilled to a depth of 18,946 with a lateral length of 4900 plus feet. After 16 stage stimulation the well which was placed on production July 9th and tested at 20 million cubic foot per day. Cabot is also participating in nine outside operated Haynesville Bossier wells that are currently drilling, completing or waiting on completion with our working interest generally between the 10% to 40% range. Haynesville wells in the area continue to produce at high rates with excellent recoverable reserves. We're also encouraged by what we're seeing in the middle Bossier potential on our acreage position in both Shelby and St. Augustine county with two outside operated wells presently performing completions and those will be our first completion opportunities in the Bossier.

Several recent industry Bossier wells in the area have performed equal to or better than Haynesville completions. With the information we have in hand, we think our acreage is located in a core area for both zones and this is the reason we continue to participate in these wells. We are still allocating some capital to our Pettit James play. There was a brief break in drilling Pettit oil wells in order to use the rig to drill four shallow James wells. These four wells were drilled for the James production but also will hold approximately 1700 acres of Haynesville Bossier rights. The Pettit oil program has resumed and during the quarter one well was drilled to a depth of 12,100 feet, with a 3900-foot lateral. The well had initial potential of 832 barrels of oil per day, and 1.5 million cubic foot per day. One well is presently waiting on completion and two wells are drilling. Six additional Pettit wells are planned between now and the remainder of the year.

Moving to the north in the Marcellus. That effort continues to exceed all our expectations with production for the second quarter increasing approximately 39% from first quarter of 2010. Production was averaging approximately 165 million cubic foot gross over the last 30 days or so. This past weekend, we brought a couple more wells online and since the weekend we have averaged over 180 million cubic foot gross per day. With the number of wells we have in the completion stage and due to the strength of our wells, as we continue to lengthen the laterals and increase the average number of fracs, we have increased our production guidance for the third and fourth quarters. It is important to note this guidance is set based on the available existing capacity we have with our three current compressors at Lathrup. As we stated in the previous press release, the Lathrup station started June 17th.

Due to the strength of our new wells coming online, we are able to free flow approximately 87 million cubic foot per day through the station, instead of our original estimate of 60 million cubic foot per day. We are reconfiguring the cylinders on the three existing compressors to enable more throughput at an elevated section pressure. We expect this work to be completed in early August, giving us a capacity of 125 million cubic foot per day through the station from these three current compressors. That is over the 60 million a day we had originally thought we would get out of these three compressors. As most of you are aware, we have been anticipating approval of the air quality permit for our three additional compressors at Lathrup.

Permit approval has been delayed because the DEP is evaluating a change in air permitting policy with regard to oil and gas projects. At the time we filed for the compressor permit back in February of 2010, the DEP viewed the compressors as a single source of emission for permitting purposes. Because Cabot's permit application was submitted and reviewed by the DEP prior to the consideration of the new policy we are hopeful and have conversations going with the DEP that they will grant the permit even though the possible change in policy remains under consideration. We do understand they have done this for others. Cabot could then potentially revise its guidance further with increased volume capacity attributable to additional compression.

During the second quarter, Cabot also added a seventh fit for purpose rig and we're on pace to have 75 wells drilled by the end of 2010. Operationally, we continue to see improvement in our well results. A recent well experienced the highest 24 hour IP to date of 18.4 million, at a flowing pressure of 1140 pounds, from a 15 stage frac. As I mentioned, we continue to make every effort to optimize our completions and increase the number of frac stages per well. We recently performed completions on two wells with 18 stage frac and during the third quarter we had some wells planned with 19 stages each. As the press release highlighted, we have a significant inventory of wells in various stages of completion.

On our seismic front, Cabot has completed shooting 250 square miles of 3D seismic data which covers more than 50% of our acreage position in the Marcellus. Right now, we have 165 square miles of data in house being interpreted. Though we have been really successful on picking locations without this 3D, we do anticipate that this data set will allow us to become a little bit more efficient in picking locations and improving our results.

I would be remiss not to mention the macro comments regarding regulatory oversight that has escalated as a result of the BP disaster. Our industry is seeing additional regulation/policies, both on shore and off shore to implement best practices from well bore design, to well cost efforts and completion safeguards. However, when you evaluate procedures that the majority of our industry implements in the conduct of its operations, best practices are being used to mitigate operational risk.

As you're aware, Cabot has been working with the PADEP as a result of a lawsuit affecting a nine square mile area in Susquehanna. I think this issue has cast uncertainty with the Street on Cabot's ability to conduct operations in Pennsylvania. As our press release indicated, we continue to make progress to reserve -- to resolve this issue. Specifically, we are now receiving our drilling permits located outside this affected area. Through this process of working with and getting to know the DEP and its personnel, it is clear to me that the DEP is regulating the gas industry with a common goal to mitigate the inherent risk of a large growth industry and also to protect the constituents of the Commonwealth.

The entire Marcellus effort has a significant learning curve taking place both by operators and regulators and I'm convinced that just like the mining industry or the steel industry and chemical industries, The development of Marcellus will continue and has potential to make Pennsylvania one of the most prosperous states in our nation. Also, Cabot will continue to work with the DEP and the families affected by the operations to the complete satisfaction and a good conclusion. As we continue to execute our program in both our regions I'm confident that we will be able to meet or exceed growth projections in the future and accomplish that goal without issuing equity or over leveraging our balance sheet. I'm very happy and pleased with our program out of both regions, certainly have a lot of opportunities out in front of us and with that Cynthia I will answer any questions.

Thank you. (Operator Instructions) Your first question comes from the line of Brian Lively with Tudor, Pickering and Holt.

Good afternoon.

Hello, Brian.

Just a few questions today. When you think about the different buckets of CapEx to be spent for the remainder of 2010, can you provide some color on how you would bucket that between midstream leasing and D and C costs?

Midstream leasing?

Midstream leasing and then just drilling and --

Oh, okay. Let me see. Midstream I would say that we are probably $15 million bucks, I would say is a ballpark number. Leasing, we might have another $40 million or so to go. And the rest is allocated towards the drill bit.

Okay. And then thinking about just you know increased completion costs throughout the industry, what are you guys seeing in terms of drill and complete costs for East Texas wells, specifically the Haynesville and Bossier?

Well in the - down in the area where it has a little bit higher pressure than it does even in the core area of North Louisiana, slightly deeper, we're between $10 million and $12 million for our wells in that area.

And how much has the completion cost increase added to those costs?

It's in various different buckets. We've seen cementing cost up 30%, 35%. Frac services cost up 50% to 60% plus percent. So we've seen quite an inflation in the cost. I would venture to say that with the margins that you've heard discussed through the service Company press releases and majority margins on the ones that are pumping certainly are coming from their pumping capacity, I would think that there's going to be opportunities out there for others to join in this space to participate in some of that.

Okay. What's the minimum rig commitments you need to maintain the leases in the Marcellus, the Haynesville and the Eagleford?

Well, I think right now we are there and feel like with our Marcellus drilling, because of the efficiencies that we have in our Marcellus drilling, we're on a very good track to maintain our acreage up there. One other footnote about the Marcellus is that we have majority of our leases are five -- plus five on renewals and certainly we have the opportunity to renew those leases at the original price we paid for those leases. So that is a plus.

And we think we're certainly on line with the program that we've outlined and not only with the few Cabot operated wells that we've drilled and we have no other Cabot operated wells scheduled in the Haynesville Bossier for this year. But with the nonoperated wells, we're capturing a fairly significant amount of our acreage and with the drilling as I mentioned in the Pettit James wells that we've drilled, and we have several more wells to drill this year, we are capturing acreage that would also protect our Haynesville Bossier rights.

Okay. That's helpful. And then last question, just on the Eagleford. How many rigs are you planning to run in the EOG, AMI area and then the separate areas that aren't covered by that agreement?

Right now we are planning on two rigs in the EOG area and one to two rigs outside the JV with EOG and that is all in the oil window.

Okay. Thank you.

Your next question comes from the line of Gil Yang with Bank of America-Merrill Lynch.

Hi. Do you, could you give an idea of how many rigs -- how many rigs are in Eagleford right now? And I guess it sounds like you'll go to two in EOG and one to two outside by the end of the year. Is that the time frame?

Yes. We only have one rig in the Eagleford right now.

Okay. And is it too soon to say how many you might go to in 2011?

Well the , again, the JV with the EOG is scheduling two rigs for that and we will float probably between one and two rigs for our Eagleford

In 2011 as well, right?

Yes.

Okay. Could you elaborate on your comment that the need to hold acreage is going to start winding down soon. Is that because of efficiencies or do you see that the leases are being drilled up and you know what regions that get drilled up first.

I think drilling efficiency, certainly the drill time at least what we're seeing, the drill time for the rate of penetration and how quick we're getting this down from spud to spud is improving. The slowdown has been obviously in the completions. But also I think we've heard the industry announce that for example Petrohawk and Chesapeake are two companies that come to mind that they've indicated that the number of rigs that they have out there in that particular area are enough rigs right now currently for them to be able to drill at their acreage.

Okay. But I thought you felt that there was a window where it would begin to slow down. Do you have more specificity on that?

I'm just saying that with the number of rigs working as efficiently as they are working, my guess is that you will see some mitigation in the slope of the adds in horizontal drilling rigs.

Okay. So more a flattening of demand of rigs rather than a lessening of a need to increase the rig count?

Right.

Okay, and finally, could you give us some color on what was the reasoning behind the particular 18,000 acres that went into the EOG partnership. Was it just proximity to where EOG was or was it something other than that that put that into that joint venture?

No, we had leased contemporaneously in the same area and we had a lot of intermixed acreage and it made sense to consolidate an area where EOG and Cabot for the most part are the only ones in this area. Might be a couple of outstanding leases, but we're the vast majority of that area and that's why we formed it.

Okay. Thank you very much.

Your next question comes from the line of Joe Magner with MacQuarie Capital.

Thank you. Might have missed this in your initial comments. Just got on the call late but wanted to see if there was anything about the run rate on spending in the first half that might change during the second half? Looks like the rate will have to drop considerably in the third and fourth quarter to stick at that $725 million total. Just curious if there's a lot of leasing or other spending that -- infrastructure spending that might have taken place that might not be happening again in the third and fourth quarters.

Okay, Joe. Scott's raised his hand.

Joe, this is Scott. Again, let's think about -- let me clarify. I had this question several times today. The issue is not -- the 725, remember, is not comparable to the investment number on your cash flow statement. The investment number on your cash flow statement represents any money that's been spent at the time it actually goes out the door. There was a larger than normal carry-over balance from 2009 into 2010 relating to both Marcellus and in particular the initial leasing around the Eagleford that while it was fully accrued on the year-end balance sheet shows up as a cash outflow in the investing category for 2010.

That number's in the $80 million range. So the $450 million you're seeing in investing when you compare that to 725, you could easily make that assumption that yes, you would have to slow down spending significantly to ratchet that back to go from 450 to 725. The point I'm making is the 450 includes what we had in our guidance for capital in 2009, part of that carried over into 2010. Take the 80 plus million out, you're at about 360, 370, so you're basically going to have a repeat of the second half of the year.

Okay. I guess I'm just trying from a balancing standpoint or matching standpoint, trying to look at the cash flows being generated this year and that even with the $80 million carry over from 2009 what the need or what the shortfall might be to cover -- either need to be covered by the balance sheet, credit facility or the assets that you might --

Well, as Dan indicated, we have enough facilities in place to fund the program. You're looking at a number in the low $200 million plus dollar range in terms of the deficit for the year. And we're at -- we borrowed 210 so far this year. Our numbers show that we're only going to borrow about another 40 for the rest of the year to cover the rest of the program.

Okay. That's helpful. And then Dan, you mentioned possibility of putting some assets out there for sale to cover some of the either need or capital or pay down some of the debt. Can you identify which assets might make that list that might be considered non-core or you know for consideration.

Well, it would maybe be easier to identify the ones that we're not going to sell. Marcellus, Haynesville, Bossier, Eagleford are areas we're going to spend the majority of our attention. Do we form a JV in there or something if somebody really wants to work with us. Certainly we'll talk about that. But if you look at the Rockies, you look at the Mid-Continent, you look at south Texas, and we have other scattered interests throughout that is not core that we're taking a look at, and we would look at all that, Joe.

Okay. Thanks. That's all I had.

Thank you.

Your next question comes from the line of Eric Hagen with Lazard Capital Markets.

Hi, Good afternoon, Dan. Just a question in the terms of how many -- you said 75 wells drilled in the Marcellus this year. How many wells do you think you're going to actually complete and have on-line by year end of those 75?

We would probably have, oh, upper 40s to 50.

Okay. Great. And then looking a little bit forward to sort of 2011, what's your thought about you know growth versus spending to cash flow. Are you still thinking you might need to outspend cash flow next year to hold acreage or are you going to kind of return back to the previous model of spending closer to cash flow? Well, you know -- I know it depends on commodity prices.

Our preference is to actually be cash flow positive. In this opportunity we have, though, with the Marcellus, it's significant and the returns on dollars invested in the Marcellus come back to us so quickly that we are going to continue to spend up there and you know we're getting punished. I think we got hit a little bit today because of our spending program and it's not popular right now to overspend into the headwinds of the gas market and supply picture today. But we do think long-term for us in capturing, making sure we're going to be able to capture the acreage, that we have outstanding, we think that the spending is prudent.

We're not here short-term. We're here long-term. And we know we have a balance sheet that can handle it. We're going to continue to make sure that we can capture our acreage and have a significant future program out in front of us. But the design of the plan and as we put together not only our 2011 plan, which we'll present in October to our Board, as we put that plan together we're also building a 2012, 2013 plan and when we look at that plan, we're going to be identifying exactly the points you're making.

We're going to be identifying where in our program and our spending level do we get to the cash flow neutral, cash flow positive equation. And we know it's not going to be, unless we have a surge in commodity prices, we know it's not going to happen in 2011. So we'll probably be a little bit deficit spending in 2011. But we do think it's going to be within the tolerance of our balance sheet.

Okay. One more follow-up on that. Thanks, that's a great answer, Dan. But you said I think previously that you had I think seven rigs in the Marcellus and that was roughly enough to hold off your acreage on the current run rate. Does that imply that you're nearing sort of the top of activity levels or do you think you might add some incremental rigs next year?

Well, part of that comment is a result of the efficiencies of what we're doing on the drilling up there. Phil had given me some information about a well we drilled recently and the full lateral was drilled in 12, 14 days. And with the efficiency of that drilling, we think we can drill certainly a larger program than we're drilling today, 75 wells, with the same seven rigs for our 2011 program.

Great. That's very helpful. Thanks again, Dan.

Thanks, Eric.

Your next question comes from the line of Ray Deacon with Pritchard.

Yes. Hey, Dan, I was wondering once you complete the retooling of the compressors, what will your total take-away look like in Susquehanna county.

Yes. Ray, the amount we think we can get through on the Lathrup station is going to be about 125 million cubic foot a day and we think we can get through the teal station an additional 100 million a day or so. So we'll be with the existing equipment, we'll be over -- at 225 million cubic foot.

Okay. Got it. And when would you expect to be taxing that throughput capacity? I guess at what point in 2011?

We have had high expectations of each well we drill and each well we've drilled seems to exceed our expectations. And if it continues, I think we could be filling that capacity fairly quickly.

Okay. Got it. And just do you have any updated comment on 30 day rates for recent wells or have you been capacity constrained and maybe there's not much of an update.

Right now, because of what we've been doing with the compressor, Ray, we have some wells that we have completed that we hadn't turned in line and the wells that we have turned in line, we're trying to keep each of those wells producing. But we are -- we had restricted rates on the -- on some of the existing wells and particularly the newer wells that we brought online. We are restricting those rates right now because of this retooling we're talking about. So as far as any near term or recent 30 day rates, we haven't had a well that has flowed comparably to the 30 day rates numbers that we had given you in the past.

Okay. Got it. And just one last quick one. Last quarter you mentioned that there had been some delays in permitting and issues with stream crossings for gathering lines, I guess. Any comments on either of those, whether it's gotten better or worse?

Well, we had stream crossing problems, section what are they, 105 permits when we were connecting our elk school wells, I believe. Phil, do you have any comments on that?

No, those are fine. What we continue to do is permit out ahead of us and so it is a long process but we go ahead and start planning in advance for those stream crossings.

Got it. Great. Thanks very much.

Thanks, Ray.

Your next question comes from the line of Biju Perincheril from Jeffries.

Hi. Couple of quick questions. The Lathrup capacity then that you mentioned, the 125 that you will get to, that's just from the initial three compressors with some retooling?

That's correct.

And when you add the next three or three or four, what would that capacity go? That wouldn't be a doubling of the 125, would it?

It would be close to a doubling of the 125.

Okay. And any visibility on the timing when you might get those permits, you know, in your discussions with the DEP?

Well, you're not going to catch me speculating, but I certainly am aware that there has been permits issued that would be similar to the situation that Cabot is in and we've had this permit and the DEP as I mentioned since February. We have the three compressors setting off just to the side of the location because you have to have that permit to be able to sit it actually on the location, even if you didn't hook everything up. And we were quite optimistic to have that permit in the first week of July.

Frankly, I think we will. I think with the understanding and indications in educating the DEP of the impact and the meaning behind their new program and policy, I certainly would expect that we would get that permit issue.

Okay. That's fair. And so with the Lathrup at full capacity, in teal you have something like 350 to 360 million cubic feet a day of take-away, what are some of the other projects that you have in the pipeline? You talked about a few in the past. Can you bring us up-to-date for increasing your take-away out of the area?

Yes. We're talking about four additional compressor sites right now. We've met extensively and have done some scoping on locations and acreage and we're actively working on that.

And these will be perhaps into the Tennessee pipeline?

Well, not necessarily. It would be Tennessee line is one of the three lines that we are designing this additional compression for. As we've always stated that we want access to the Tennessee line. We want access to the Transco line to the south and we want access to the Millennium line to the north and each of these projects has a connection anticipated to the other lines.

Okay. Got it. And then when you talked about running seven rigs, at current cost levels what would be the drilling and completion cost and then on top of that, you know, for a program like that, what do you think will be sort of your infrastructure facilities cost and you know what you would typically do in terms of in-flow leasing.

Well, with the longer laterals and more fracs and we are seeing some cost pressures on the fracs up there, we're like between 4, 2 and 4, 7 on drilling. Infrastructure cost, what we're doing, our economics, we have been allocating $150,000 to each well, just as an allocation of its share of our infrastructure cost and that's kind of how we've been doing it. And that seems to have been covering our cost up there. So we feel comfortable with those projections.

Okay. And then the amount that you spend in terms of infill leasing this year, is that a reasonable number to expect next year?

No, the in field leasing is slowing down. We will not have as large of a leasehold act program in 2011. We've seen it slow considerably and it's just the nature of the beast. So I do not anticipate a similar number next year.

And one last question. How many wells are you budgeting now per rig, per year?

Let me do some quick math. 12 to 14.

Okay. Thanks. Appreciate the time.

(Operator Instructions) Your next question comes from the line of (inaudible) [Millistand] with Morningstar.

Yes. Hi. Back when you were splitting out your assets to answer the question regarding assets for sale, you indicated you would not sell Marcellus, Haynesville, Bossier and Eagleford. I'm assuming that your oily Pettit wells fall into that Haynesville, Bossier category and you just mentioned that you're planning another six wells. Can you just give us an update on where you see the advantages of drilling additional Pettit wells and what that plan could look like for 2011, 2012 for Pettit.

For Pettit, I don't have our 2011 program. We're in the midst of doing that right now. We have six Pettit wells scheduled between now and the end of the year. I'll let Matt make a quick comment.

For 2011, we have one rig running in the Pettit for the entire year in 2011, in our 2011 plan.

Thank you.

Your next question comes from the line of Robert Christianson with Buckingham Research.

Thanks for taking my call. Great quarter. Tell me, how many drilling permits do you have in hand for the Marcellus and how many right now have been applied for? Can you give me a breakdown of the numbers, please?

Yes, we have 23, 24 permits in hand right now and we have applied for an additional, say, 40, 45 permits.

How is that going these days, the permitting? About the same as the past or is there a little more I guess delay? I'm just trying to get a sense off of that, your sense off of that as to how things are faring.

Robert, in the recent past pursuant to the last -- the consent order that we were working with the DEP on, we had a handful of permit -- well, we had 30 something permits in hand that we'd been operating under with the rigs that we are drilling on out there. During that period of time, he we were not being issued any new permits. As of this week.

And us working with the DEP on a modified consent order, they have now begun processing our permits that we had in their hands and submitted to them and they have issued now the first of I would expect all those permits to be issued now by the DEP. But in the recent past, no new permits have been issued.

Sounds like most of easing of a log jam right now.

Significant easing, and again, we had the permits in hand to keep drilling for a while which we were quite clear on that. But the focus area right now, Robert, as a result of the execution of the modified consent order is we're operating pursuant to DEP regulations and every area outside of this nine square mile area. And we will continue to work with the DEP inside this area under the modified consent order.

I missed an earlier answer that you gave. I think it related to compressor station that you are currently scoping for locations, compressor station, which guess if I look at Lathrup, three compressors installed now with three more to come. Six compressors per station or you're looking at four more sites? Did I hear that correctly, Dan?

Yes, you did. We are -- our model right now is to design these compressors with similar configuration at the Lathrup station.

Thank you very much.

Thank you, Robert.

Your next question comes from the line of Joe Magner with Macquarie Capital.

Thanks. I just wanted to revisit this compressor station capacity issue again. I think initially is designed the three existing compressors at Lathrup were around $20 million a day each. Now you think you can get a little over $40 million a day each. Is that correct?

And then if so, any read or any experience from the larger, the three larger compressors on what those -- I think those were originally designed to deliver $35 million a day capacity, any , anything that suggests those might also be able to double, or do you have enough

Okay, how about I'll have, Joe I'm going to have Steve [Lindemann] answer you, if you don't mind.

Joe, the extra capacity that we're getting at the Lathrup station like we said in Dan's speech is by retooling the cylinder, resizing the cylinders, so we're increasing the suction pressure coming into that station. And that's what we're getting the extra capacity.

Okay. So is there anything that suggests that the three larger, the newer compressors that are still to be added at Lathrup will have the same type of capabilities or -- ?

They'll have the same type of capabilities. Dan mentioned we felt like we could get 125 out of those. I don't have the specific performance curves for those but it will be a you know a comparable number in terms of the jump-up in size.

So it's possible that with those three new ones you could have not just 100 million but perhaps 200 million of additional?

Well, again, a lot of that is depending on what we operate in the field in terms of what the suction pressure is.

Okay. So at a minimum you're going to go from 225 and then the three new large, go to 325 through Lathrup and teal when those permits are granted?

Yes, that's right.

Minimum.

Yes.

Thanks.

Thank you.

At this time there are no further questions. I would like to turn the call back over to management for closing remarks.

Thank you, Cynthia. I appreciate everybody's questions and certainly I can assure you that we're focused on how we're conducting our business and the capital expenditures and our balance sheet. We know we have that out in front of us but we do feel like that we can manage it within our existing capacity. And I think with the areas that we're going to be allocating that capital, that we're going to be able to show a significant growth profile.

And I think the best news is that with the continued growth of this program, that the issues that we're dealing with, both regulatory and also financially are going to I think be very short-lived programs to where we can manage our program as we go forward. I do appreciate everybody's interest in Cabot. Thank you.

Ladies and gentlemen, this concludes today's conference.