Morning, and welcome to the Cabot Oil and Gas Corporation Third Quarter 2012 Earnings Conference Call. All participants will be in listen only mode. Please note this event is being recorded. I would now like to turn the conference over to Dan Dinges. Please go ahead, sir.
Thank you, Maureen, and I appreciate all joining us for this Q3 conference call. We have a lot of good information to go over today and with me to answer any questions is Scott Schroeder, all know him CFO Jeff Hutton, our VP, Marketing Steve Lineman, our VP, Engineering Technology Matt Reed, VP, Regional Manager and Todd Lieberle, our VP of Land and Business Development. Let me just say the standard boilerplate forward looking statements, including in our press release last night, do apply to my comments today. On the call this morning, we plan to cover the 3rd quarter operating and financial results. We'll give you an update on our 12 13 guidance.
We'll also update our hedging program for 12/13 followed by an update of our operations in the Marcellus, Eagle Ford, Marminton and now we're going to add a brief comment in the parasol. Before I do go into the details on those topics, I'd like to highlight some of the items that were brought up in our press release last night. Gabbage production is up 42% over comparable year to date periods. 3rd quarter production was up 6% over the 2nd quarter even with the delays that we've discussed in permitting and gathering lines in the Marcellus Earlier this month, as far as a little bit granular information, we brought on Line 2, a 2 well pad, 1.5 miles west of our ZIC compressor area. That pad site with 2 wells had peak rate of 43,800,000 per day from only 25 stages, which I think further demonstrates the productivity of our Marcellus wells and the benefit of our reduced spacing between stages.
We also recently drilled and completed the first Pearsall short lateral well under our joint venture with Osaka. The well was drilled in Frio County and tested at a 24 hour rate over 1400 barrels equivalent per day. I think most importantly and from a macro standpoint, Cabot will deliver industry leading production growth in 2013 with a cash flow positive program using a $3.50 gas price. I think certainly all those stack up to good information. Last night, our financial results, the company reported clean earnings of approximately $43,100,000 or $0.21 per share for the Q3 of 'twelve, up from $35,300,000 or $0.17 per share for the Q3 of 'twelve excuse me of 'eleven.
The increase was driven by higher equivalent production and higher realized crude oil prices that more than offset weaker natural gas prices. Cash flow from operations and discretionary cash flow for the 3rd quarter was $164,000,000 and a $175,700,000 respectively, both up from last year's comparison. Moving to a comment on production. Cabot continues to provide industry leading production growth driven by our Premier Marcellus assets in Susquehanna County. Equivalent production for the 9 month period ended September 30, 2012 was approximately 189 Bcfe, which represents an increase of 42% compared to the 9 month period ended September 30, 2011.
Taking into account last year's Q4 sale of our Rocky Mountains property, our pro form a year to date growth in production is 51%. This 9 month production level already exceeds our full year 2011 reported production. Now to get a little forward looking as far as our guidance is concerned 'twelve. We have updated our equivalent production growth range to 38% to 44% and our liquids production growth range to 60% to 70% to better reflect our outlook for the remainder of the year. We had hoped for and scheduled earlier timing for Marcellus gathering permits, I.
E. Being able to turn wells into line. However, as previously mentioned, the permits were just recently received by Williams. This resulted in not achieving the high end of our guidance. With that said, we are comfortable with the guidance range that we have just put out.
Full year per unit cost range were also tightened based on year to date results and our expectations for the Q4. We reaffirmed our net capital spending for 12 at $775,000,000 825,000,000 dollars Okay. For 13, we have updated our equivalent production growth range to 35%, which is up from the 30% we had previously posted to 50%, so 35% to 50%. And we've established our liquids production growth range at 45% to 55%. The midpoint of our guidance ranges when you look at 20122013 implies 3 consecutive years of 40 plus percent equivalent production growth, which is an impressive number on an ever increasing base, while at the same time maintaining our capital discipline, not encumbering our balance sheet or diluting our shareholders.
We have also provided initial guidance on cost for 2013, which reinforces our industry leading cost structure and the continued trend for decreasing per unit cost. We've further refined our estimates for capital spending in 2013 to between 950,000,000 dollars $1,025,000,000 with approximately 70% of that capital being allocated to our high rate of return projects in the Marcellus. In a 3.50 natural gas environment and with recent efficiency enhancements, our Marcellus rate of return certainly exceeds industry returns in all gas plays and most, if not all, oil plays in current commodity prices. Additionally, the planned program will deliver a slightly positive cash flow at a $3.50 natural gas and $90 oil price, and I'd say not a common occurrence in our space. For 2012 production, excluding the 5 basis only hedges.
The company has 37 contracts in our hedging book, 27 are gas swaps at 5.22, 5 are gas collars with a floor of 360 and a ceiling of 4.17 and 4 are oil swaps at $99.30 with an additional oil swap at $105.05 Approximately 40% of the midpoint of our guidance for the remainder of 'twelve is currently hedged. For our 2013 hedge book, we have added 25 new hedges since our Q2 call in July. We now have 48 contracts, 45 for gas, which are all collars and 3 swaps for oil. Approximately 45% of the midpoint of our production guidance for 'thirteen is currently hedged at an average for price of 3 point $0.63 per Mcf, which is $0.13 above the $3.50 we're using in our 2013 budget. For additional information, you can go to our website for any additional specifics.
Now let's move to the operations side of our business. During the Q3, we achieved a new milestone with a 24 hour record of 252,000,000 cubic foot of gas produced in our Susquehanna County area. I should note, we will exceed that level, we think, by 10 o'clock this morning in the last for the last 24 hour period touching approximately 780,000,000 cubic foot a day. Probably I'm impressed with the North region's ability and their timing of some of these new releases, I probably should have more conference calls. Our gross cumulative production from the field is almost 400 Bcf with just 60 producing horizontal wells at this time excuse me, with 160 producing horizontal wells at this time, certainly highlighting the prolific nature of this asset.
While permitting delays for gathering lines continued to be an issue this last quarter. We were able to bring online 23 Marcellus wells and have subsequently brought on an additional 5 wells during October. Our wells continue to outperform our expectation as evidenced by the highlighted 2 well pad that recently came online in the ZIC area. The combined IP as I've mentioned of the 2 well pad was over 43 1,000,000 cubic foot a day from just 25 frac stages, which utilized the narrower frac stage spacing of 200 plus or minus feet. The original 5 well pad at Zick has produced over 11 Bcf in approximately 180 days, which I think further highlights quality of our acreage as we continue to expand to the east.
In other news, we recently had a 22 frac stage well reach 3 Bcf of cumulative production in just 105 days. I think that's the fastest record to date. This broke the previous record we had set by 60 days. We're currently operating 4 drilling rigs in the Marcellus and have 4 50 stages completing, cleaning up or waiting to turn in line along with an additional 296 stages waiting to be completed in our Marcellus area. In terms of our plan for 2013, we will increase our rig count in the Marcellus by 25%.
We'll go from 4 rigs to 5 rigs. Scott likes that percentage number by the way. We will stay at this level for the majority of the year and then add another rig as we enter 2014. The planned well count for the 2013 program in the Marcellus is 84 wells with a placeholder for a handful of wells in the Utica depending on the success of the well we currently have shut in. Kind of might add that that is also dependent on whether or not Range and Cabot get together and continue drilling in an area that has all of our acreage HBP already.
The investment level, as previously highlighted, is about 70% of the overall program with 88% of that level focused on Marcellus drilling. Okay. Have a little bit of narrative on the infrastructure. We continue to aggressively pursue our infrastructure goals up in the Marcellus. As you are aware, we have been very clear to specifically outline those objectives in our discussion and presentations.
Last quarter, we reported that the 2012 slowdown in the permit approval process did delay the construction of various gathering pipelines that ultimately affected the dates we turned our wells in line. We believe that issue has been fully resolved and in fact Williams, our midstream provider has now received 90% of the pipeline gathering permits to complete the 2012 program and has acquired 100% of the right of ways needed to complete our 2013 program. In fact, we have no less than 12 different pipelines that are currently in the construction phase. This is great news on the pipeline construction side of the infrastructure. On the other half of the infrastructure picture deals with the timing of compressor stations and free flow interconnect into the interstate pipelines.
These projects have made significant progress. And while we are not going to see any of these individual projects have an in service date earlier than we expect, we do still expect to be close to our original goal of approximately 1 point Bcf per day of takeaway prior to year end 2012. But just to be clear, and as we have previously discussed, when we put your models together, infrastructure requirements grow and the facilities are placed into service throughout our acreage position, we will in some cases have excess capacity in some areas, but still slightly constrained in other areas. And that result of where we need to have our drilling rigs throughout the year. One other point regarding infrastructure, we have already provided Williams with the necessary information for our 2014 program.
We anticipate Williams will submit the completed application for permits in January of 2013 for our 2014 program. Now let's move to the South. This region has 5 rigs operating as we speak, 2 are in the Marminton and 3 rigs are drilling in the Pearsall with 1 of these rigs moving back to the Eagle Ford program fairly soon. This rig level is expected to continue throughout 2013 as current plans call for about 50 net wells to be drilled. The region accounts for roughly 30% of our overall capital program and of that amount 75% is dedicated to drilling.
All right. I have been a little bit reluctant to discuss the status of the Pearsall with just one well. But as I mentioned last night, Cabot has successfully drilled and completed its first Pearsall Osaka joint venture well in Fria County. The short lateral well was drilled and completed with only 11 frac stages and tested at a 24 hour rate of over 1400 barrels of oil equivalent per day. As mentioned, 1 additional Purosall well is completing and 3 wells are drilling.
A total of 6 Pearsall wells are planned for the 2012 program. We hope our early drilling and completed wells will fall in the $9,000,000 to $9,500,000 range. Our first well was slightly over $10,000,000 with the science that we threw in that. But with the learning curve, we hope to be able to continue to improve what our expectations are on the drilling cost. Cabot's net well cost will be 9.75 percent during the Osaka carry period and we will have a 65% working interest in the wells on first production.
We have accumulated over 70,000 acres net in the play. And as I mentioned, we do not normally discuss exploration efforts at this early stages. However, with the level of interest and the number of questions we had been receiving, I felt it was necessary to provide an update. In the Eagle Ford, we announced our release of another successful well with 4,000 500 foot lateral and treated with 15 stages. To date, we have 38 Eagle Ford wells in our Buckhorn area.
As with other plays, we have seen well costs come down as efficiencies are gained and we are now in the $6,500,000 to $7,000,000 completed well cost range. Also in the Q3, the integration of field to full pipeline access versus trucking our oil that occurred just a couple of months ago. We are now able to produce the oil and transport it by that pipeline to Corpus Christi, where we receive LLS pricing. This effort has made a fairly significant improvement in our realizations on an average of approximately 8 dollars per barrel above NYMEX indications. The combination of lower cost and higher prices certainly has improved our overall economics in this area.
Now let's move to North Texas, the Panhandle of Oklahoma and the Marminton. We have recently completed a well with a 15 stage frac stimulation. The well produced at an initial 24 hour rate of 664 barrels of oil a day and an average of 5 93 barrels over the last 20 days. We also drilled our 1st extended lateral well with a lateral length of approximately 9,500 feet. The well was stimulated with 30 stages and is presently in the early stages of flowback.
A second extended lateral well has been drilled and will start completion at the end of October. Completed well costs continue to average around $2,900,000 to $3,300,000 with early drilled extended laterals coming in between approximately $4,000,000 to $4,500,000 To date, we have accumulated about 70,000 net acres in that play. So in summary, our drill bit success continues to drive our significant production and reserve growth expectations. What I'm most pleased about is the continued innovation our team has come up with new ideas that certainly is going to translate into incremental value. It's my expectation that we will post excellent numbers at year end 'twelve.
And it's also, as a forward look, my expectation that Cabot will, in 2013 certainly have industry leading production growth. We'll have a significant reserve addition at a very low cost of finding. We will also have an improved balance sheet with a positive cash flow program using only a 3.50 gas price. I think we'll see Bcf per day of net production at some point during the year, and we will achieve these results with only 10 operated rigs for most of the year. I think a couple of these points may set us apart from some of our space.
Anyhow, Maureen, with that brief summary, I will be more than happy to answer any questions.
Thank you. We will now begin the question and answer session. Our first question is from Pierce Hammond, Simmons. Please go ahead. Good morning.
Good morning, Pierce.
On your capital guidance excuse me, on your production guidance for 2013, you provided the liquids production guidance. Does that include the PureSO?
That includes the PureSO with a risk profile attached to it. In other words, we obviously risk our exploratory, exploitation ideas And by putting together a production cash flow statement, we risk our expectations accordingly.
Great. And then if you look at you're
going to go to the reduced frac spacing in the Marcellus and in a larger way next year. So how should we think about the total number of stages completed in the Marcellus in 2013 versus 2012?
We will certainly be higher. I would expect that the increase will be 3% to 5% or
so. Great. And then finally, just from the industry standpoint, given the recent rise in gas prices, specifically for the calendar year 2013, do you think the industry is going to be more active in the Marcellus and we should see a gradual uptick in the industry rig count in the Marcellus?
Well, I don't know. I think it depends on where companies have rate of return projects in their portfolio that would compete with their positions in the Marcellus. Some of the Marcellus up there is not quite as prolific as the area that we have. And the threshold for economic returns in other areas, the Marcellus, might not compete with the returns that some companies might be able to deliver by drilling in some of their oil portfolio.
Great. Thank you very much.
Thank you.
Our next question is from Bob Brackett, Bernstein Research. Please go ahead.
I had a question on the PureSol Shale. You're quoting numbers of $9,000,000 to $9,500,000 If I just compare that against your $7,000,000 Eagle Ford wells, what's that incremental cost? It doesn't seem like just going a little deeper is going to cost you that $2,000,000
I'll pass it over to Matt for a second. But one of the things that you have to take in consideration is we're trying to determine where we're going to land the well. We're trying to get our mud property straight. And certainly, it is in a higher pressure regime
and the
fracs require a little bit more Well, more pump pressures and we're using ceramic in the frac stages, but I'll let Matt also expand on some of that.
Yes. Dan is exactly right. And actually, it's a different casing program than our Pure saw program. We have an extra string of casing in PureSOIL program as opposed to our Eagle Ford program. And we do see higher pour pressures in the PureSOIL and we do see higher frac pressures as well and we do increase our proppant strength as well during our fracs in the PureSOIL.
And are you landing those PureSO wells in the Bayer Shale or in the Pine Island? Or do you think you're stimulating all 3 subunits?
Right now, we haven't really discussed that, and I can give you a little bit better feel for that after we do some micro size work. We'll be doing that probably in the Q1 of next year as to what we're actually stimulating. I know where we're landing. We're landing in about 70 foot interval there in the PureSOLE. You can call it the Bear.
You can call it the Cow Creek. You can call it the James. People call it different intervals.
Okay.
Yes. And the 70 foot is in approximately 500 foot to 600 foot gross PureSol interim. Correct.
Great. Thank you.
Thank you.
Our next question is Michael Hall, Robert W. Baird. Please go ahead.
Thanks. Good morning. Hey, Mike. Just, I guess, a couple of follow ups on the tighter frac spacing. Just want to make sure I'm, I guess, understanding the initial two wells.
Were those roughly 2,500 foot laterals, if you're about 25 stages between the 2 of them? Is that shorter than your typical lateral? And so on a more kind of normalized basis, we should see even more uplift. Is that a fair way to think about it?
Yes. We have I don't have the exact lateral length of those wells, but keep in mind that some of our wells up there are shorter laterals, not because we prefer that, but because geographically, if we are unable to get a leasehold position that at times we have to shorten the laterals. So again, I don't have the laterals space right in front of me, but that typically well, that is the reason why we shorten our laterals. Okay.
Fair enough. And then I guess, is there any way to quantify or are you ready to kind of quantify a little bit more in terms of what sort of percentage increases in productivity and EUR per lateral foot you're seeing as a result of that program? And then also what all right, go ahead, Dan.
Yes. Well, Mike, we certainly have seen an improvement and that's the reason why we're moving our program to the reduced spacing for the fracs. We're not prepared to give the details. We are still evaluating all the pilot wells that we've drilled with this reduced spacing. Steve Lindeman and his group are currently in the throes of preparing for year end reserve.
And through that effort and evaluation of more data points on the production curve of these wells versus the wells that we're fracking at 250 will go into our bookings on EUR at the end of the year and we'll certainly be able to quantify an efficiency gain by virtue of that process.
Okay. No, that will be helpful. And then I guess last one on that is how much of the 2013 program would you say is going to be utilizing that new approach roughly?
We will be implementing the 200 plus or minus foot spacing for our entire 13 program. Okay,
got it. I think that's all I got for now. Thanks. Congrats.
Thanks, Mike. Yes.
Our next question is Brian Singer, Goldman Sachs. Please go ahead, sir.
Thanks. Good morning.
Hi, Brian.
Can you give us the latest update on the backlog that you have in the Marcellus Cove stages or wells that are drilled but not completed and completed in awaiting tie in? And then can you talk also to as you get to the Bcf a day by the end of the year, how much of that would come on from wells that are already drilled, already producing or wells that still need to be drilled?
Okay. I was going to pass that to Scott, but he got a cough and attack here. We have nice move, Scott. Thank you. We have 19 wells that have are waiting on the pipeline.
Those have 283 stages. We're currently completing 9 wells with or in the process of flowing back 1 of the other 167 stages. And we have 21 wells that are waiting on completion for 200 with 2 96 stages. And I'm sorry, Brian, what was the rest of your question?
The rest
of the question is as you get to a Bcf a day, how much of the difference between where you are now and there will come from wells that are actually already producing today that may be constrained versus wells that are that you just highlighted in your backlog versus wells that you may still have to drill?
Well, we have the expectation between now and the end of the year to bring on, say, another 30 wells. And if you look at what the guys were able to provide me this morning that we think this most recent 24 hour period that we'll be at 780,000,000 cubic foot a day, it's to me, it looks like that we will be able to depending again where these 30 wells are coming online and the infrastructure capacity. It looks like that the wells that we'll bring online will provide that get up to that BCF a day. And as far as capacity restraints or the existing wells being restrained either by lack of capacity through dehire compression or by higher line pressure because we have not yet gone into the phase where we're reducing our field pressures. I think we could see incremental gains from those wells once we are able to implement reduced line pressure.
Got you.
That doesn't answer your question, I know exactly, Brian, but I do think the wells that we'll bring on between now and the end of the year and our existing wells, if we were able to deliver all of the gas that they could produce, we could hit that Bcf a day. However, we will have constraints within the system.
Got you. Thanks. And then when we look at the midstream options for next year, what are your thoughts on major milestones or the trajectory of further debottlenecking and new midstream outlets coming on over the course of 20 13? And how do you think about differential in the content and flexibility in terms of where you sell your gas as you look ahead to next year?
Okay. Good questions and the focus on the infrastructure has been something that we have dealt with through this entire year, I am pleased that we will be able to get this problem behind us for the most part in the as far as the effect it has on where our guidance is. And I think Jeff is the appropriate person to kind of reference the current status of the infrastructure and also where we're going with the infrastructure and the market as a whole up there.
Okay, Brian. I think if you look back to our last presentation, you'll see central compressor station, which is in the north kind of north central part of our play, that is the next major step for Cabot in terms of completing the original infrastructure plan. So that's kind of second half or late Q2 of 2013. We're not relying solely on that. Of course, we have a number of projects, some new interconnects with existing pipes that will be pre flow activity in some units that are coming on late this year, early Q1.
But again, you asked about the major next step that will be central compressor station that feeds a new 24 inches pipeline that's currently being laid that comes down to the old Springville system down to Transco. In terms of moving gas around, we're, of course, are very, very blessed to have 3 interstate pipelines that we're able to take our production to, a Millennium pipe to the north, Tennessee gas pipeline, the 300 line right through the center of our acreage and of course the Transco Leidy system. So currently with the options that we have at each compressor station, we're actually able to, for the first time, start to play a little bit of the pricing game. So better prices on Transco, little more gas goes there, better pricing on Tennessee, little more gas goes there. So it's been fun compared to last December when we had, as you know, 600,000 day flowing into one pipe.
And we expect to continue to build the optionality into the system and the flexibility so that as we as our production grows, we continue to have those options to deliver gas to different markets.
Great. Thank you very much.
Our next question is from Matthew Portillo, Tudor, Pickering and Holt. Please go ahead.
Good morning, guys.
Good morning.
Just a few quick questions for me. On the PureSol, could we get just a breakdown on the hydrocarbon content between oil, NGLs and gas?
Well, right now, I'll say it this way that it's one well in one area of the field. So I'd be reluctant to give it all right now, but we're over 50% black oil right now in the stream. And then we have a high BTU content gas along with it.
Okay, perfect. And then just jumping quickly up to the Marcellus, just a bookkeeping question. In terms of well cost, could you give us an update on kind of as we look at these 12 to 15 stage frac wells, where you're expecting cost to come in at the moment and how you see cost trends heading into 2013?
Yes. We have as we have stated in the past, we've looked at the Marcellus and we've always outlined our typical well as being a 3,500 foot lateral with 15 stages. Now it is our typical well as we build our database now will be most likely reflected as a 3,500 foot lateral with approximately 18 stages in it. That cost of that well is going to be a little bit higher because we'll have 3 additional stages in there. And in regard to cost, we're about $6,000,000 or so now with our typical 15 stage frac well.
So we'll have a little bit of incremental cost with 3 additional stages, but I'll also add that we're currently in negotiations with our pumping providers up there and that process has not executed yet. We have not executed a final contract for our 13 pumping services, but I am comfortable in saying that our pumping service cost will be below our cost we saw in 2012. So I can't say exactly what I think it's going to be until we see where we land with the pumping service contract, but directionally all our costs are going down.
Okay, great. And then just a last question for me. As we kind of look across your portfolio today, you've obviously established quite a few new potential cornerstone assets. And just trying to get a better sense of how you guys think about the potential for acceleration of development on these assets either with your own capital or potentially through JVs over time. So just wondering if you're looking at bringing in any additional partners across any of your either exploration or development plays and then how you guys are potentially thinking about capital acceleration potentially heading to the back end of 13%.
And I know it's a little bit early for that, but just trying to get a better sense of how you guys are thinking about the opportunity set.
Well, we're certainly blessed with a portfolio that yields very good returns and particularly our Marcellus, and we're very cognizant of the fact that our Marcellus assets yield some of the best returns of any asset in the industry and we will continue to allocate and grow that asset as rapidly as we can. Our main objective would be to enhance our present value of that asset and we'll continue to do so. In the other areas of our portfolio, we will continue to capture our acreage out there. That's primary term acreage. We have done so as an example of what we've been able to do is the Ozaca transaction.
We were able to bring a partner in Ozaka and we're very pleased to have them as a partner and we look forward to having them as a long term partner. But we are able to bring them in, give them an opportunity to get a foothold in the States. But also it allowed us to have leverage dollars to drill a little bit deeper in the section, I. E. The PureSol.
We knew the PureSol had potential and we are currently drilling in the PureSol. Those leverage dollars have allowed us to, in essence, maintain all of our acreage, including the Eagle Ford acreage and it certainly has allowed us to compete on a return profile with these with the carry we have at a very favorable rate compared to the Marcellus. In the other areas like the Marminton, we have acreage out there that we would continue to desire to capture because we have very good returns out there in the Marminton, particularly with the very low completed well cost. We will look at that and have looked at that as is it an area that would be right for a partnership. And right now, we have not strained our balance sheet.
Our 13 program has free cash available even as we operate in our area out there without a in the Marminton without a joint venture partner, but we do evaluate and we do look at how we can maximize the capital efficiency of every dollar we spend. We have not taken off the table having another joint venture partner in any of our operations less and except the Marcellus.
Okay, great. So as we think about both in the both the Marminton and the Eagle Ford that could potentially be assets where you may bring in additional partners or just the Marminton at the moment?
No, I think the entire area we'll look at. If it looks like a significant enhancement to us and we have the right party that we would like to be in business with, certainly being able to enhance our capital efficiency, we would consider.
Great. Thank you very much.
Our next question is from Charles Meade, Johnson Rice. Please go ahead.
Good morning, gentlemen.
Quick
a couple of quick questions for you. That those 2 wells in the Zick area, is that the Daniels pad or are we still waiting for results on that?
No. The Daniels pad is another 7 miles to the east further. We are still waiting on that area to get some pipelines to that particular area. So that will be further out in 2013 before we get a line out in that area.
Okay. We want
yes.
I'm sorry, that was so that's like a Q1 2013 or something like that?
No, it's second quarter actually by the time we get that line out there.
Great. And then the second question I had was regarding your PureSol activity in 2013. Is that going to be all in the Buckhorn area or are you going to pull a rig over to Powderhorn for part of the year?
We will have the majority of the activity in the Buckhorn area, but we will also do an exploratory evaluation of our Powderhorn area.
And so do you have in mind, I mean, like a rough percentage? What percentage of your activity is going to be in Buckhorn versus Powderhorn?
90% is going to be in Buckhorn.
That is great. Thank you, Dan.
Thank you, Josh.
Our next question is Joe Magner, Macquarie. Please go ahead.
Good morning. Thanks. Just wanted to, I guess, try to tie some things together in case I missed it. What with the ongoing drilling activity, have you I guess what have you quantified what sort of efficiencies you're seeing in terms of how many wells you can drill per rig per year?
No, we have I haven't broken it out. I've broken it out like that just on the back of an envelope, but we're our efficiencies that we see on a per rig basis kind of reflect in our rate of return number for a well. So when you look at if you want to look at it from a day's drilling and rig to rig or excuse me, spud to spud in the Marcellus, we're looking at 20, 22 days something of that range. Purasoil still a little bit early to make that determination. I will say that Matt and his group had actually penciled in drill time and run pipe about 60 days originally in the Pearsall before we drilled our first well.
And they have come in, in the 40 days to get that accomplished. So, they had already were able to beat initial curve and certainly they have ideas on how they're going to enhance that. So we're fairly good on the type of drilling we're doing in the Marcellus and that 20, 22 days is a phenomenon based on us having to make a lot more rig moves than we would have to than we'll have to make once we get to pure pad drilling. We're only drilling 2 or 3 wells per pad and once we get to pad drilling, certainly that spud to spud time will be reduced once we drill the 10 to 14 wells per pad that we plan on in the future. And I would expect Matt will be able to engineer the drilling of, for example, the Pearsall wells and get that drill time down just like he has in other every other area that we have been operating.
Okay, great. And just to touch on PureSol being a risk component of your year over year liquids growth. What are the, I guess, primary drivers of that year over year liquids? Marmatin, is it just kind of provide a little more detail on that?
Yes, it's Marmaton and the Eagle Ford. And we certainly have in the mix a risk profile of our Pearsall expected completions.
Okay. And just one last one. That 1 DCF a day rate you're referring to, is a net or gross number? Just to clarify.
That is that would be a net number.
Okay. That's all I got. Thanks.
Yeah. Thanks, Jeff.
Our next question is Jack Aden, KeyBanc. Please go ahead, sir.
Hello, guys. Hi, Jack. Dan, could you guess or venture to guess where would you might exit the year in terms of production out of the Marcellus? I mean you have $780,000,000 now.
Yes.
We have a number of wells coming online, and we have a pretty good rate going right now. I would say that if we were and again, Jack, it's a snapshot, so we got to make sure everything is in sync, but I'll do the total company. I think the total company would be 900 $1,000,000 equivalent a day or better.
Okay. 2nd question. Now in the past, you booked certain most of the That's the
net number by the way. Yes. Okay.
In the past, you book your reserve at certain EURs. Now with reduced spacing for in frac stages, now it looks like those 2 wells, you're getting $2,000,000 for the frac stages. If that's what you're going to go through the year 2013, directionally, what kind of uplift we might see in reserve booking? I know it is early, but can you venture in that area also a little bit?
Well, I can say it like this. I do think that our typical well definition of 3,500 feet in 15 stages will go to 3,500 foot and 18 stages or so. And those 3 additional stages are going to have some incremental effect on the a similar lateral length well as we had in our 11 bookings. I'm not going to stretch to say that every frac stage now will be a $2,000,000 a day increment. That's just that's a very aggressive number and we don't have enough data points to say exactly what it's going to be.
But I will say and what we're trying to gather and what Steve Lineman and his group and also Phil Staunacker and his group are trying to determine is the additional frac stages, it's just not additive for the 3 additional frac stages. We think the additional reduced spacing for all the lateral length is going to have some incremental add, some incremental gain by virtue of the stages being reduced from 250 to 200. What that number is and how we quantify it on an IP per stage basis or an EUR basis, I'm not prepared to narrow that at this stage. But I am excited and obviously us moving our 13 program to that 200 foot spacing is indicative of how we feel about it.
Thanks, Dan. Most of other questions were answered. Thanks a lot.
All right. Thanks, Jack.
Our next question is Biju Perincheril from Jefferies. Please go ahead.
Hi, good morning. Hi, Biju. A couple of questions. On this Marcellus completions, how should we think about it? Are you with the more stages in a given lateral lengths, are you still pumping the same amount of proppants and water or are you per stage or are you now proportionally pumping less?
And can you talk about what does it have any impact on the spacing that you had assumed before?
Well, we are still pumping at the same barrels per minute rate and we are also pumping these stages with the similar proppant. And again, the effect on the way we were pumping or the stages and how we were completing wells before, I think it's just the enhancement is going to be recognized through our production charts on each well as we get more data. But I do think the efficiencies gained by reduced spacing and keeping the pump pressures similar and the pump rates similar and the amount of proppant is going to be incrementally beneficial across the entire lateral length.
Got it. So if I think about the frac length laterally, that's about same as before? Yes. Got it. And then on the infrastructure issues you had, was that related to some changes in the regulatory process or was it just a manpower issue with DGP or Army Corps of Engineers?
Yes, Biju, it's actually a combination of those factors. In fact, the Williams has done an excellent job with the agencies that time to time try to venture and interpret the regulations a little differently with each application. So there's a little bit of that going on. There was the typical backlog of so many permit applications that without increased manpower of those agencies, just a number of factors from communications between dual agencies and wetland application, for example. But the DEP has made progress.
The Governor actually has intervened somewhat into the process. And so we feel much, much better today than we did a year ago.
Okay. That's helpful. So when do you think Williams will start receiving permits for the for 2013 program?
Okay. So the applications that Williams files are with both agencies, the Corps of Engineers and the DEP. They are an ongoing process. So it's not exactly a calendar year. If we gave Williams a 2013 program well earlier than some of the other wells, that permit actually could come out earlier or maybe we already have, I think we do have some of the 13 permits in hand.
So it's really not a stop and go process with each program year, it's just an ongoing process.
Okay. So I should think about you have about 30 location backlog today in hand permit? And then, why? Biju, this
is Scott. One of the other things picking up on what Jeff said is, again, Williams had all the permits fully 100% ready to turn into the regulators by July of this year for 13. And so one of the things the dynamics that happened is early in this process if you remember, it was kind of 6 to 9 months to get them out, and then it kind of ballooned out to 18 months. It's moving back towards the 12 to 13 month time period. One of the things we've said in some of our meetings was that by the end of next summer, to directly to your question, we kind of expect we'd have all the 13 permits if they kind of take a little over a year to get.
Perfect. That's very helpful. And then one last question, just a clarification on that pure solar rate. Dan, did I tell you that the rate that you quoted is not does not include NGLs, such as the oil and rich gas?
The BOE over 1400 barrels a day does include the full well stream. I just haven't given the mix of the MMBtu quality of the gas and the NGLs that are associated with it.
Okay. Got
it. Thanks. Our next question is Joe Allman, JPMorgan. Please go ahead, sir.
Thank you. Hi, everybody.
Good morning, Joe. So in terms of infrastructure
in the Marcellus and in particular, the interstate pipes, what gives you the confidence that you can grow your production as much as you've forecast? Are you relying on your own firm transportation? Or are you relying more so on the firm capacity of others? And where might there be some vulnerability?
I'll let Jeff go into that, Joe.
Okay. Well, that's there's always a challenge with that subject, but here's how we plan for that one. We currently hold FD basis around 350,000 a day of firm takeaway. So we sleep well at night knowing that we have that amount of capacity. Of course, we're always participating in expansion projects and we have a number of projects that we're considering participation in.
If you kind of think we're producing or just on an average day in the past few months, 750,000 a day, then you can assume that our firm transport moves X amount of gas and then our customers' firm transport moves X amount of gas. So we have, from the beginning, sold to utilities, LDCs in the Northeast volumes of gas that they move under their in path firm transportation. And that's been our success to date. As we move larger volumes, we've signed some longer term contracts with a couple of parties that have this firm transportation, it is very valuable. There's been a couple of expansions, particularly on Tennessee, the EQT expansion, which added 350,000 a day of firm, that capacity is currently not all being used.
So capacity has freed up on that pipeline and also on Millennium. So we feel good that the interstates have responded with additional by call and additional expansion capacity. Transco is a project right now that will come about in 2 years that will add around 500000 to 600000 day capacity. And last but not least, and I'll use this opportunity to plug Constitution Pipeline, That is our 650,000 a day pipeline that's going to come from Central Compressor Station that I mentioned earlier into the Iroquois Zone 2 market and the Tennessee 200 line market. Cabot will have 500,000 a day of firm capacity on that pipeline.
So we are planning for the future. We're going to end up holding a lot of firm transport, but we'll always be selling to utilities in the Northeast and the Mid Atlantic area that do hold firm transportation. Okay.
That's a good rundown. Thank you very much.
Having no further questions, this concludes our question and answer session. Having no further questions, this concludes our question and answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.
Thanks, Maureen. I appreciate everybody joining us for the call. I think you can see that we have posted some good numbers for our Q3 year quarter end. I expect the numbers to continue to improve as we get to 'twelve year end, and we've given you a little bit of a look at our 13 and our expectation is our 13 is going to be equally as robust as our 12. So thank you for your commitment.
Thanks for the loyalty for those long term holders and we appreciate your support.
Thank you.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.