Good morning. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to the Cabot Oil and Gas First Quarter Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
Thank you. I would now like to turn the call over to Dan Dinges, Chairman, President and CEO of Cabot Oil and Gas Corporation. Please go ahead, sir.
Thank you, Tiffany, and good morning. Thank you for joining us for Cabot's Q1 teleconference call. With me today are several members of our management team, including Mike Wallen, Scott Schroeder, Jeff Hutton and Matt Rhee, our VP Regional Manager and others. This will be Mike's last public appearance for Cabot as he retires more. And again, I want to thank Mike for his many years of dedicated service and contribution.
Mike, we're certainly going to miss you. Before we start, let me say the standard boilerplate language and forward looking statements included in the press release apply to my comments today. We have many things to cover and expand on from the 2 press releases that we were that we issued last night. I will briefly cover the financial results, the recent operation milestones and our progress in the matter with the Pennsylvania DEP. I will be brief so as to allow ample time for Q and A following my comments.
On the financial results, last night that exceeded consensus expectations. However, lower natural gas prices even with higher production cannot offset the previous year. As the softness in gas in the natural gas market continues, from a clean earnings perspective, net income was $30,000,000 Select items for 20.10 include primarily stock compensation and mark to market basis hedges. As stated, lower natural gas price realizations were the main factor in the lower net income. On the balance sheet, our debt level increased $110,000,000 from year end to $915,000,000 as we established a sizable footprint in the Eagle Ford Shale and continued blocking our Marcellus position, both of which are certainly key areas going forward.
In terms of production, as we mentioned on the year end call, we would be towards the low end of our guidance for Q1 due to the delays in permitting of stream crossings earlier in the year and the capacity constraints in the second half of the quarter for Marcellus production. You may recall, we reached maximum capacity at the Teal station up in Susquehanna around the middle of February and commenced free flowing Marcellus gas at our Lathrop station in early April. Production for the total company year end ended at 295,000,000 cubic foot equivalent per day. And now at quarter end, we're at 325,000,000 cubic foot equivalent per day and growing. On the operations, let me expand on the operations release.
We have numerous wells that strengthen our position in core areas in the Marcellus, in the Haynesville and the Pettit. And we also have our best well in the Taylor Cotton Valley sand confirming a good rate of return project in Minden and we also have success on our initial oil drilling in the Eagle Ford, another good rate of return project for our portfolio. Now let me move into some of the details. In the Eagle Ford in South Texas, the company has completed its 1st horizontal Eagle Ford well. This well, a 100 percent working interest well, had a lateral length of nearly 3,000 feet and was stimulated with 14 stages.
The well tested at a rate of 3 34 barrels of oil a day and 142 Mcf per day. Cabot holds approximately 61,000 gross 52,000 net acres in the oil win of the play with 300 to 350 potential locations and a resource potential of 60,000,000 to 140,000,000 BOE. A second company operated well is scheduled to spud in early to midsummer with 3 additional wells being drilled in 2010. This is exciting as we continue to build our position. We have had initial success and the concept was significantly reinforced by recent peer presentation along trend with our acreage.
Let's move to East Texas. We continue to focus on 2 main areas there, the Haynesville and Bossier shale play and our Petit oil program. In the Haynesville, as previously announced, Cabot has successfully drilled and completed its first Haynesville well. The King number 1, which we had 69% working interest, was drilled to a depth of 18,364 feet and a lateral of 4,487. After 14 stage simulation, the well tested as we previously reported at 19,000,000 per day and the new data point for us is its 30 day average of 15,200,000 cubic foot per day.
Drilling operations are underway on our 2nd operated well, the Walters number 1. We have 54% in this well and Cabot is also participating in 3 outside operated wells that are currently drilling with working interest between 20% percent 41%. Cabot has participated in the drilling of additional outside operated wells that has been additional operated well that has been drilled encased. We have 29% of this well and we're waiting on completion. With Cabot just starting its Haynesville drilling, we anticipate getting into the stimulation queue some time in June or July for our well.
We're encouraged by the Haynesville wells with the high initial rates and certainly excellent recoverable reserves. And we're particularly excited about the Middle Bossier potential on our acreage in Shelby and St. Augustine County. Moving to the Petit, in our Petit oil play in this area, the Worsham oil number 1 and the Worsham Unit B 1 were stimulated with 1014 stages in the lateral lengths of 5,500 feet and 5,471 respectively. The Worsham Unit A, number 1 is currently flowing back.
The Worsham Unit B, number 1 produced at initial rate of 1209 barrels of oil per day. With these results, Cabot has increased the number of Pettit wells to be drilled in 2010 to 2013. In 2010, four wells have been drilled and completed. 1 well is waiting on completions and 8 wells remain to be drilled. Average initial production from the wells drilled in the field is 4.85 barrels of oil per day and 2,000,000 cubic foot per day.
With prices 20 times higher for oil and natural gas, we look to drill more Pettit, which has added value of which has the added value of holding our undeveloped acreage to all depths. Our James brief comment, at County Line, we had 5 James wells that were drilled encased, but not completed in 2,009. Those have now been completed. The wells had an average initial production rate of 6,100,000 cubic foot per day. Moving up to Minden, our 3rd Cotton Valley Taylor horizontal well has been successfully drilled and completed.
The Birdwell 11H, a 100 percent Cabot well was completed in mid April and initially tested at a rate of 11,100,000 Cubic Foot Per Day. This is a higher rate than the first two horizontal Cotton Valley Taylor Sand wells that we drilled. They had initial rates of 9,500,000, 8,900,000 cubic foot equivalent per day. These wells continue to provide superior economic returns with EURs of 6 to 7 Bcfe and a very low finding cost. In addition, this acreage is HBP, so we'll be very selective as to our timing and pick a more opportune time to drill more Taylor wells, although returns are very compelling.
Now let's move to the north, the Marcellus, obviously continues to be our crown jewel for Cabot and certainly is developing into a true company maker with exceptional economics. Since we started, we have paid 1,000,000 of dollars in lease bonus and royalty. We've also hired 64 new employees with many additional positions yet to be filled. We continue to lease acreage in our core area and have increased our position to nearly 200,000 net and gross acres. More importantly, our Marcellus program continues to yield exceptional well results and production is ramping up quickly.
We are currently producing at a maximum infrastructure capacity of approximately 115,000,000 cubic foot per day from the field. Phase 1 of our Lathrop station is complete, which allows us to free flow gas into the Tennessee line as the press release highlighted. Phase 2, which is the compressor startup phase is well underway with compressors and dehigh equipment set on the site and startup scheduled for late May. I know some of you have expected higher production rates for the quarter, but we are close to ramping up our production. At this time, we have 18 wells in various stages of completion and a number of wells with 50 frac stages will be ready to turn in line immediately at the compressor startup.
Cabot plans to drill 81 wells total in 2010, although we may adjust this schedule by a couple of wells depending on our capture rate of new leasing. Year to date in Susquehanna, we have drilled 11 horizontal wells for a total of 12 wells for the quarter. Cabot recently added a 6th fit for purpose rig in April and has a 7th rig scheduled to arrive in May to fulfill our program. At the end of 2,009, Cabot set forth a series of 2010 initiatives to continue to improve our results and efficiencies in the Marcellus. 3 of those initiatives were completed in the Q1.
Our recently drilled and case we recently drilled encased our longest lateral well to date at 5,000 feet. We drilled our first well in 17 days from spud to rig release and that well had a 4,300 foot lateral. And lastly, we completed a 15 stage frac that went into line at 14,600,000 cubic foot per day and 1730 pounds flow casing pressure. This well was curtailed due to current sales point capacity limits as we've discussed and has been flowing less than 30 days, so it was not included in the population highlighted in the press release. With the robust production rates that we're seeing, we have taken additional steps to ensure that we have adequate physical takeaway capacity with the execution of 3 firm transportation agreements.
You'll recall that we announced at our last operational update, the partnership with Williams to build a 20 inches pipeline to the South that guarantees us a minimum of 150,000,000 cubic foot a day of firm capacity from our Susquehanna compressor stations to Transco. Last month, we executed a binding agreement with a private midstream company that also provides for a minimum of 50,000,000 foot per day of firm capacity with expansion opportunities. This time we're going to go to the north. This project will enable us to move a rig to the northern tier of our acreage position and establish production up there. The pipeline project is slated for 2011.
Also we executed 2 binding agreements that will allow an additional 50,000,000 cubic foot a day to flow directly to Millennium Pipeline in New York via the Tennessee Gas Pipeline. Completion of this expansion is expected approximately November 2011. Regarding the Pennsylvania DEP matter, Cabot takes safety and all environmental matters extremely seriously. As Cabot announced Tuesday night in a press release, we will continue to cooperate fully with the Pennsylvania DEP to remedy and resolve the items from the consent order. I'm not going to rehash the order or the first or second responses from us publicly, but I am happy to answer questions on this issue during the Q and A session.
Finally, on our guidance last night, we posted updates to our guidance for 20.10 that held full year production equivalent guidance in the previously disclosed range at a growth rate of 18% to 22%. Our initial liquids guidance from October of 2,009 expected a little bit more petted volumes at this stage than has occurred, but this is offset by our better than expected natural gas production. We exited the quarter at 325,000,000 cubic foot equivalent per day. And in terms of expenses and capital, those were left unchanged. I would note however that with our leasing success, the potential $65,000,000 wedge should be added.
Additionally, we continue to look for good leasing opportunities in our core areas. I'm very excited about our program that we have out in front of us in both regions. As you can see, we are flush with opportunities, good rate of return opportunities for years to come. Additionally, we have several other interesting projects that are in its early stages of evaluation. Tiffany, with that, I'll be more than happy to answer any questions the group has.
Your first question comes from the line of Brian Lively with Tudor, Pickering, Holt.
Good morning.
Good morning, Brad.
Your natural gas production guidance for the 2nd quarter is up about $40,000,000 to $45,000,000 a day sequentially. How much of that production growth is related to the Haynesville versus the Marcellus?
Well, we didn't have any Haynesville production in that early guidance. And now we're rolling or we had very little. Now we're rolling in a little bit of the Haynesville. But second quarter, we're going to be somewhat limited on the Haynesville production just trying to get the frac crews, the pumping crews in there. When you're not an operator that has lined out multiple wells out in front of us, it's hard to stage in there.
So what we're doing is having to pick windows of opportunity to be able to bring those frac crews in.
Okay. So the production growth then as I take it is largely related to the Marcellus? And is that related to the increase in the infrastructure with the second phase?
Yes. Yes. The free flowing gas that we're able to put through there most recently and that's just basically us putting the wells directly into the additional is going to be once we start cranking up the compressors which should additional is going to be once we start cranking up the compressors which should be later next month.
Okay. On the oil side lower oil production guidance, could you give some more color? And I think you mentioned briefly that the pellet maybe declining a little more than you expected. But could you provide some more color on why the oil production guidance is down a bit?
Yes. I think Brian that we thought that we would have wells drilled and completed a little bit earlier in the quarter than what we actually did. And some of the earlier pet wells are falling off a little bit quicker. They're still very, very attractive, but just not as high of initial rates that we had experienced earlier.
Okay. And switching over to the Eagle Ford. Some operators have talked about completing wells in the Upper Eagle Ford and possibly fracking into the Chalk. Others talked about completing in the Lower Eagle Ford. Could you give some more color on what your completion practice is today and kind of expectations going forward?
Well, right now we have drilled and completed in the Lower Eagle Ford and don't have any short term plans to frac into the Chalk. Although obviously it depends on how much fracture growth you do get that you might access the chalk anyway.
Okay. My question is on the rate that you put on the 1st Eagle Ford well, the 3 34 barrels a day. I think you said today that that was the IP rate. If that's correct. And what is the kind of current rate?
How is the well performing?
It's performing very well. It's still producing around 225, 250 barrels a day.
Okay. Thank you.
Your next question is from the line of Brian Singer with Goldman Sachs.
Thanks. Good morning.
Good morning, Brian.
Couple of questions on the Eagle Ford. Can you just talk about the potential outcomes and strategy assuming the next couple of wells do work? Where are you kind of from an infrastructure perspective? And how significant do you think this could be looking ahead to 2011? That's maybe the first part.
And then the second part is, if you do accelerate activity in the Eagle Ford beyond these next few wells, would you think of that as additive to your CapEx? Or would you pull some activity down somewhere else in the portfolio?
Yes. First off, we have leases down there that we have taken say within this last year. And our primary term expiration and undeveloped lease is a consideration on how we're allocating capital just like majority of the other companies in our peer group out there. We will continue to capture acreage in the Haynesville, Bossier area as we are doing. Again, we have term on our Eagle Ford acreage down there.
The wells that we have scheduled for 2010 are included in our capital program that we've laid out. If we do ramp up the program beyond what we've discussed, it would be additive to our program. And certainly juggling the balance sheet with operational opportunities and leasehold success is something we do on a daily basis and we would look at how we get our arms around all the opportunities we have. But again back to your question, the wells that we had forecast in the Eagle Ford for 2010 are included in our program.
And so I guess when we think about from a natural gas drilling perspective outside of the Marcellus, are you essentially drilling the minimum levels to hold acreage across the portfolio, I. E. If gas prices stay at these levels into 2011, given that you have less or likely to have fewer hedging gains, you would kind of maintain the current level of activity because there's not a lot of room to reduce from here without acreage
expiration? Yes. We have that's correct. We have laid out a program out in front of us that allows us to capture our acreage. But we in our gas areas, we are not over drilling in the gas areas just to be drilling.
We are capturing primary term acreage. A good example of that is the Minden Cotton Valley well we drilled horizontal well. That particular well has excellent economics and the returns are every bit as good as what we've seen in the Haynesville, but we have elected not to drill any additional wells up there because that acreage is HBP.
Great. Thanks. And one last one. Is there anything unique to the particular Eagle Ford location or portion within your acreage that you think would make it either more significant or less significant versus other wells you expect to grow?
No, it's just going to be an area that we had focused on early on. We had bought some leases in this area where some of our early acquired leases and we started moving forward and getting permits and getting lined up and location set and in one of our early area leasing and that's where we drilled our first well. But other than that nothing unique to where we picked a location.
Thank you.
Your next question is from the line of Jack Aden with KeyBanc.
Hey guys. Hello Jack.
Mike good luck to you again. Thanks. Dan, regarding the Eagle Ford, what kind of a decline you've seen? I know it's the first well. What kind of decline you've seen?
2nd, I know you throw numbers about $60,000,000 to $140,000,000 And also you give a little bit the number of wells. So you're talking about in a way spacing somewhere in excess of 140 acres per well. Could you elaborate a little bit more on that?
Okay. Well, I think I could I think it might be summed up because it was a fairly well attended presentation by one of our peers and they laid out a very detailed descriptive analysis of the Eagle Ford that had acreage spacing. They had EURs. They had anticipated flow rates. And our acreage is exactly on trend with that peer that laid all those out.
So versus kind of going over the redoing the presentation that's out there that had considerable detail, we agree with that presentation.
I have it in front of
me. Good.
Okay. All right. Thanks a lot. That's it for me. All right.
Your next question is from the line of Ellen Hannan with Weden and Company. Good morning. Morning.
Just a couple of follow-up questions again on the Eagle Ford. In terms of the acreage position that you've put together, can you talk about again, I'm maybe covering ground again, but how many wells do you think you'll need to HVP your acreage in terms of how you were able to kind of block it up? And secondly, have you run into a situation there where you've had to lease the water rights separately from the mineral rights?
We have not had any circumstances to lease water rights separate from mineral rights. And we are developing our program with discussions with some of our offset leaseholders and making a determination of units configurations and what we'd be doing as far as the development of our primary term acreage. And once we get all that together, which is a dynamic discussions right now, we'll be discussing that in further conference calls.
Okay. One separate question on the results that you talked about in the Pettit. Does this cause you to change your EUR assumptions on those wells?
Not really, Alan. We had these newer wells we've kind of moved to the eastern side of our acreage block and we're getting some excellent results coming forward now. And I think that we'll stand pat with our reserve estimate there.
Thank you very much.
Thank you. Your next question is from the line of Michael Hall with Wells Fargo.
Thanks. Good morning. Good morning,
Mike. Just wondering, can you talk
a little bit more about your cost of entry in Eagle Ford? What you paid on an average per acre basis at this point and what you're paying today as you continue to lease in the area?
Well, our acreage position right now is less than $1,000 per acre.
Okay.
And yes, we continue to look for opportunities out there and it's our policy where we're active in leasing. We do not discuss bonus consideration.
Okay. Fair enough. And can you talk
a little more about midstream availability that you're seeing? We're hearing maybe in the oil window there's a little more investment needed on the midstream front. Would you agree with that? And can you
there's a couple of things. I'll turn it over to Jeff, our VP of Marketing. Yes. Yes.
Well, there's
a couple of things. I'll turn it over to Jeff, our VP of Marketing. I know we've had I've had a meeting with, for example, Energy Transfer. They have a number of projects that are going on down there and expansion projects that they have. They recognize the amount of resource potential in the Eagle Ford and they are moving as we speak to develop a number of areas and expand projects down there.
Well, I would concur with Dan and might add that to date we've not had any hauling issues. Obviously, there's a lot of activity but I think the industry is gearing up to make sure everything moves.
So would you plan to kind of volumes up until call it maybe 5,000 barrels a day give or take that sort of level is what I've heard the economics are kind of breakeven on trucking versus piping. Is that an accurate assessment?
Yes. Right and right now, keep in mind we have our focus primarily with capital allocation going to Marcellus and also primary term maintenance in the I mean primary HaynesvilleBossier. Our first well in the Eagle Ford was successful. I think we will gain efficiencies of our completions technique in the subsequent wells, but we have not put together a large expansive program in the Eagle Ford at this time with the number of wells that we're talking about. So initially, Michael, we are going to be trucking our oil out initially and contemporaneously working on the expansion of our program and other opportunities for transportation.
Okay.
Great. Thanks for the color. One more on the Eagle Ford on completion availability. Any outlook there? I know you've got a pretty limited program at this point, but just curious what you're seeing?
Yes. Let me turn it over to Matt Reed.
We're somewhat limited there, not quite as much as we are in the Haynesville. We can't get frac dates on just a phone call, but we're not basically tied into being restricted by unlimited number of companies that can frac down there. So our frac dates are fairly reasonable in the Eagle Ford.
Okay. And then in the guidance on the kind of production mix, if you will, the somewhat lower oil guidance. Is there any Eagle Ford assumed in that production? I know you'd said it's in the CapEx, but Yes. But a small amount.
Okay. Would it be fair to say then if you have continued success in Eagle Ford there may be some upside within that oil guidance or Yes.
I get ahead. But let's not overjet because remember there's only 4 wells for the total
year program at this point in time too.
Fair enough. And then last one quickly on acreage additions you had in the release upwards of I think $70,000,000 $68,000,000 maybe in potential acreage CapEx. Is that primarily just Eagle Ford and Marcellus? How much of that kind of split between the 2? And then what are your most recent acreage costs up in the Mar
So we have picked up acreage in both areas and continue to acquire acreage in both areas. And I don't have the exact split between those two areas. And we are still active in the our area of Susquehanna. And where we do have active leasing programs, we're not going to discuss what we're paying our potential lessors.
Okay. And then one more if I may in the Marcellus. Have you looked at or are you considering intentionally choking back the wells to help with compression needs down the road? And what are your thoughts on that?
Well, we have a number of wells that we have restricted in the Marcellus. We have wells that as we mentioned we have over 50 stages that are backlogged right now. We have a number of wells that we have in the queue that we are in the process of completing and adding more stages to complete. Again, a number of our wells are restricted at this stage. And frankly, we if you would have looked at this 8 months ago, 10 months ago, we thought we were building out our infrastructure in a timely manner.
We moved up the construction of the laser station, because we saw early success. And as we've continued to expand, we continue to improve our initiatives up there on longer laterals, more fracs and quicker drill rates and efficiencies. We have just overtaken the time frame of our infrastructure startup date and which is a high class problem. Yes. And we anticipate putting a significant volume of gas into the Lathrop station once we can crank up the 3 compressors on-site.
And initially, I might add the initial phase, which is what we're calling the 2nd phase is to start up the compressors. We have 3 compressors that will be starting up early on. That will be about 65,000,000 cubic foot of additional capacity. And then towards the in the summer middle of summer, we'll have 3 additional compressors that we plan on shrinking up there also, which would get us up to total for the facility 165,000,000 cubic foot per day. And obviously, it's going to be our intent to fill that capacity as quickly as we can.
Yes. Good deal. Appreciate the color and agree it's a classy problem to have.
Yes. Love it. Yes. Thanks, Michael.
The next question is from the line of Gil Yang with Bank of America.
Good morning. Regarding the Haynesville frac backlog, is that are you seeing any changes in that? Or is it still sort of as bad as it ever was? Or is it getting worse?
On the you talk about all the getting the pumping equipment to the location?
Right. Well, we're
seeing since as Dan mentioned, we don't have a major program up there like many of the other operators do. We have to get in the queue and take dates that we can get. We try and schedule our fracs 2 3 months in advance in a big time period between 2 3 weeks. Right now, we're scheduled about 2 months out from the end of the drilling and completion right now. So Okay.
We don't have enough activity to really be able to tell if it's changing at this point.
Right.
We do not. That's correct.
I would anticipate however with the announcements that we've heard some of the reallocation of capital that certainly it stands to reason that it might become a little bit better, but we have not seen that.
Right. Okay.
And in the Marcellus, do you have enough wells drilled and not completed and behind pipe frac stages to meet your guidance for the year? Or do you still need to drill and complete and put on additional wells?
Well, our guidance has taken in consideration our full year program as we've laid our guidance out there. We have a high expectation that we're going to have no problem being within our guidance or we have good success, we might even be above it. Okay.
In the Eagle Ford, when you say you're on trend with other operators, are you sort of interlaced with the other operators? Or are you east west north south of the other operators but along the same trend lines?
We're interlaced with the other operators.
Okay. Could you in
the well that you
reported based on what the other operators seem to be reporting, could you talk about what the other operators are generally seeing and what the differences are between what you're seeing and what you need to get do to get to
the same results they have?
Okay. I'm not going to rehash the peer report. It was like a 200 page report and very detailed and available out there. But I will say that this is our first effort. We have seen other first efforts out there.
And I think early time data that we see in our well is very consistent in an overlay of the early time data that we've seen in peer wells out in the area. And again that we have seen nothing to deter us from believing that the EUR expectation and return expectation of our acreage in the Eagle Ford is going to be any different than what's been discussed out there by others.
Okay. All right. Thank you very much.
Your next question is from the line of Marshall Carver with Capital One South Coast.
Yes, good morning. Couple of questions. On the 8 horizontals that you put online in the Marcellus for the 30 day rates, do you have the average lateral length and number of stages for those?
Marshall, those would be in the range between about 2,800 to 3,800 foot something in that order. Not many of those are the long reach laterals yet.
Okay. Thank you. And on the Eagle Ford well, the press release talks about it being at 3 34 barrels a day and strengthening. The 2 25 to 2 50 barrel a day rate that you all mentioned for the well, was that an IP rate or is that where it is now? I'm just trying to resolve the time that the wells have been online and
The threethirty four rate was the IP rate. Okay. And at the time of the press release or before the press release that well was stabilized and was cleaning up and getting somewhat better, but it has turned over and started to decline slowly, which is not unexpected.
Right. And how long has the well been online?
It's been online roughly 30 days, maybe a little longer.
Okay. Thank you. And then one last question. The number of Cotton Valley horizontals, how many what's your inventory locations in that area on a net basis?
Our locations in the Taylor horizontal are roughly 30 to 50 potential locations.
Okay. Thank you. And congratulations to Mike on the retirement tomorrow.
Thank you, Marshall.
Your next question is from the line of Ronny Iselin with JPMorgan.
Hi, thanks guys. My question was already answered.
Okay. Thanks.
Your next question is from the line of Biju Sarincheril with Jefferies and Company.
Hi, good morning. Ben, you talked about stream permits delays earlier in the year. Do you have those permits now and for this year's program or do you anticipate needing more such permits?
No. We do have the permits at hand now and we're continuing to lay pipe out there and we'll continue to secure additional permitting, but we just had a period in there where we had a delay.
Yes, yes. Biju, really that permit was kind of a one off deal. We generally bore all of the streams, so we don't have to get permits across it. In this one case, the boring didn't work and we had to go back and get an actual physical stream crossing. And that's why it took so long and delayed the laying of that one piece of pipe.
But our standard operating procedure is to abort the wetlands and keep away from the permit process.
Okay. So if you for those for the remainder of this year's program, if the boring works, if you have the same issues, do you could this be would you anticipate it needing more stream crossing permits?
We don't anticipate having to have more stream crossing permits. Like I said, that isn't something that we go forward looking to do. It's only if we are have some issue on the physically boring the rock as we did in this one case.
Okay, got it.
And the other thing is that we're getting more wells spread out and not all dependent upon just a pipeline in this particular case that Mike talked about. We had a couple of fresh wells that we had drilled completed, we had in our early forecast. And with our forecast number being a smaller number, it did affect our expectations. Now we're getting a diverse pretty good diverse spread of wells that are coming in from different areas and not all dependent upon a pipeline or a boring that would that I hope would not significantly delay any production expectations.
Okay, perfect. And then the Eagle Ford well, if you want to disclose what the cost on the first well
was? The average cost this well we took deeper and explored some deeper potential, but on average cost is going to vary somewhere between the high 4,000,000 to $5,500,000
Okay.
And then if I look across your acreage, this looks like on the western side of what you have leased up so far. Is that fair?
Bijan, I'm not really following the question.
Is this on sort of on the western edges of your Eagle Ford acreage position, this particular well?
This particular well? No, it's kind of in the middle. Okay.
And one last question between the Eagle Ford and some of your activities in Montana, it looks like there is some effort to add more liquids to your production mix. At this point, with the success you were having, any sort of targets or timeline that you would put to get more oil?
Well, we still are looking at a 5 year company wide program. I've discussed earlier the 5 year actually 10 year program we're developing in the Marcellus area. We are also putting together a company wide 5 year program that again is going to be a pretty dynamic document. But it is our intent in balancing with capturing our primary term acreage to add in this commodity price environment more oil, more liquids to our production profile. There's one thing that would be of note if you look at it from a percentage perspective though that the ramp up that we're going to see in the Marcellus is going to be I think fairly dramatic.
And so percentage wise, we might not see a large change. But in actual number of barrels per day we produce of liquids, we think that's going to go up from this point forward.
Okay. And how much acreage do you have in the Heath?
Have we what's the status? I don't think we put that out there yet.
Okay. That's good. Thanks. That's all I had.
Okay. Thanks, B. J.
Your next question is from the line of Ray Deacon with Pritchard Capital. Yes.
Hey, good morning. Dan, I was wondering, are these the Eagle Ford well, was it about 5,500 foot depth and is 100 to 120 feet of pay sound kind of reasonable for this area?
I don't think we gave the depth.
Okay.
Okay. I got well cost you gave anyway. Yes. And I was just wondering even with not a lot of growth in the Marcellus, it seemed like costs were a lot lower than I thought, cash I guess what was what drove that?
We're I know we're getting efficient on our drilling up there. For example, our last well we drilled was from spud to rig release was 17 days and we just made a trip up there yesterday. Our entire Board we had our Board meeting in Pittsburgh at our new office up there. Our entire Board wanted to visit our Susquehanna operation and evaluate our progress up there under the Safety and Environmental Committee of our Board. We carried our and other members of the Board that are not part of the Safety and Environmental Committee decided to go up there with us.
And we had a good show and tell of all the areas discussed the Pennsylvania DEP operation by some of the wells that DEP has asked us to get involved in and plug. But back to your question, we have our efficiency of our program that is maybe reflective and also the timing of some of our operation.
Got it. So I guess just one more quick follow-up. It seems like well, the DEP must be pleased with what you're doing because it didn't seem like it slowed down your ability to get permits at all. And so I guess does it look like it's not going to affect permitting going forward, I guess is the question.
Well, one thing you have to keep in mind that is just factual that we have an area that we were up there initially that we started drilling in and we did not sample the water wells for methane. Subsequent to this event as we discussed in our press release, we have beginning began to take pre drill samples of not only the entire contents and evaluation of the water, but also now determining the percentage and amount of methane in the water wells up there. And with that information and certainly with our cooperative working with the DEP, all the wells that we are drilling outside this area that has caused the initial concern, All the areas outside of this area we are having no problems with methane in the water wells. Although the water wells had pre drilled methane in them, we're not having any problems with the DEP on them advising us that we have contaminated any wells. And our operations have been certainly evaluated and scrutinized by the DEP.
We've been in compliance with the DEP orders. And we have I think enhanced some of the location building operations out there and to assist the DEP in mitigating any concerns of surface exposures, environmental risk and the cementing and casing operations that we implement in our wells right now are in full compliance of DEP regulations. And we don't have any problems outside of this area that's been identified. So we continue to drill outside that area and we would expect those operations to continue in compliance with DEP regulations and expectations from this point forward.
Got it. Great.
Thank you. And just can I ask also one is the Eagle Ford well, is that on pump after a month or not Yes?
We have took early time free flow grades and then implemented pumping operations.
Okay, great.
Thank you very much.
Your next question is from the line of Brian Kuzma with Wise Multi Strategy.
Hey, good morning guys. Good morning, Brian.
Can you tell me what your Marcellus production average for the quarter?
I don't know. I know we're ramping up and we've been kind of up and down as we have been working with some of that free flow gas in the Laintrop station. But probably say $95,000,000 to $100,000,000 a day would be Scott's telling me would be a good number.
Okay. And that's the net number or the gross number?
Gross.
It'd be the gross number.
Got it. Okay. And I also wanted to ask, you've got these wells that are $8,000,000 a day on the 30 day rate, that's clearly ahead of your type curve. I mean, what happens if as you guys keep drilling these wells, what happens throughout the rest of the year? Because it seems to me you'll have to drill a lot fewer wells to kind of back out the infrastructure.
Again, we are very pleased, Brian, obviously with the results that we're getting and we're excited about our new initiatives and what we've been able to do there. We have started earlier than anticipated in our next compressor station. We have started that operation. And we are also looking now out towards our 4th compressor site and doing some early time work on that particular site. So and as Jeff has been our VP of Marketing has been doing, he's trying to get out in front also on the firm transportation side as we've announced signing up some additional firm.
So we are making every effort to stay out in front of our production. Again this Lathrop station is a fairly significant station. We were up there by that station yesterday with our Board and it's coming along very, very well. 3 compressors on-site, DeHa on-site hooking that all up right now. We have already poured 3 additional slabs for the 3 additional compressors and we are also now doing some engineering design work.
We have enough room on this site for another large compressor beside this train of 6 that would and could possibly get that particular compressor site location up over 200,000,000 cubic foot per day. So we're doing things, scrambling and using all the technical resource and certainly pushing our guys and they're doing a great job getting this thing strung up.
Mike is making a good point here, Brian also. Yes, Brian. Another issue is that of course we're out there building a lot of compression, but this is that dry gas, pipeline quality gas. So we aren't having to strip liquids and that's a big, big positive for getting these wells online timely.
But then the strategy going forward then is not to cut back drilling, it's to build additional infrastructure to handle the higher rate wells?
Well, we have a multi tier options that we're looking at on our multi year program and that is how one we capture our primary term acreage. And we have extensions available under some of our leases on our primary term acreage and we're running dual tracks keeping trying to keep ahead of our existing production capabilities as these wells come in better than anticipated. And we are also trying to capture the primary term acreage and looking at it 2 ways. 1, if we keep drilling without extensions how much acreage we capture and then making the decision that if we do extend some of that primary term acreage into another 5 year term or so, does that give us the flexibility to slow down some of our drilling. We're trying to look at all of that as we go forward.
I got it. And so on the compression side, you'll have 110 at Teal, 165 at Lathrop after the summer. And then these other projects that you're talking about like roughly when would they come online? And again what size would those be?
We would probably look at a similar size facilities. And the first one would probably be mid-twenty 11.
Okay.
And then just as a separate question, I know you guys don't really want to say how much acreage you've got in some of these other oil plays. I was just curious how many different oil plays you guys like including the Eagle Ford and the Heath, are there other plays that you guys have already accumulated acreage on?
Well, we yes. And in the heat, I think you could probably narrow it down. We're over 100,000 acres in the heat.
Okay.
Great guys. Thanks.
Okay, Brian. Thank you.
Your next question is from the line of Ken Carroll with Johnson Rice.
Hey, guys. Good morning.
Good morning, Ken.
Good morning. Just a quick question back
on the Eagle Ford well in terms of the lateral length of 3,000 feet seems to be maybe a little shorter than we've seen out of some other players. Are your plans for the additional 4 wells to push lateral length
a little bit? Or how do
you see that going forward?
Well, yes, we this was just our initial roll at it. As Matt had indicated, we went down. We did some coring in this particular well. We've done some science. We wanted to just get our initial test, initial evaluation out there as the other individuals asking questions talked about where you land the well, is it in the lower Eagle Ford, is it in the upper Eagle Ford all those things that will be looked at as we move forward.
Okay. Got you. But you would it sounds like you would hope to extend that lateral length a little bit as
you just work through the program?
Yes, absolutely.
Very good.
All right. Thanks, gentlemen.
Thank you. Your next question is from the line of Steve Ives with Cheyenne Petroleum.
Yes. On your Eagle Ford well, you announced what kind of frac materials for what kind of frac technique did you use? And are you going to like this prior collar, are you still going to be tinkering with that too as you go ahead? We will be. The frac procedure there was basically just white sand.
The fluids we went to a cross link and we're still tinkering with our designs and what we'll be doing with future oils. Okay. All right. Thank you.
We have a follow-up question from the line of Jack Aden.
Dan, you mentioned you had 18 wells in different stages of completion. Could you tell me how many of those are vertical and how many horizontal? Now the next question for you is this, let's assume half of them are horizontal and if the 30 day average is running about 8,000,000 dollars you've got huge backlog of production that's coming up. Could you care to comment on it? And I have another question to ask.
Okay. Of the 18 wells, 15 of those are horizontal and 3 of those are vertical
and I could do the math, the rest of the math.
I knew you'd circle back
around, Jack. Yes. The next question I
have is this. I'm looking at your 10 ks year end. You got about close to 200,000 gross acres in Montana. Is that the Heath or it is different formation or different kind of play? Could you comment on it?
Well, Jack, I would be disappointed if Mike didn't make one more comment to you before he walks out.
Okay. Jack? Yes. That's that stealth oil play. That's the stealth oil play.
Okay. Yes. But no, it is looking at that Heath is Central Montana and obviously you all picked it up the acreage in the K. So we'll lift our skirts little bit on that. But yes, we're looking at Caffee Heath as an oil target in that part of the world.
Do you have something lends to the Niobrara there too?
Do we have that position in the Niobrara? Yes. No, sir. Okay.
Thanks. You bet. Thank you, Jack.
There are no further questions at this time. Presenters, do you have any closing remarks?
Well, thank you, Tiffany. Again, I appreciate all the questions. As you can see by the questions, the Eagle Ford certainly has garnered a lot of attention. I think both with the Eagle Ford, our Haynesville, Shell and the Bossier opportunities along with a ramped up opportunity in the Marcellus and the labor station coming online towards the latter part of this month. I think next quarter you're going to see a different production profile with Cabot and we're looking forward to announcing that.
Thank you all for your attention and interest in Cabot.
This concludes today's conference call. You may now disconnect.