Coterra Energy Inc (CTRA) 2012 Q3 法說會逐字稿

Good morning, and welcome to the Cabot Oil & Gas Corporation third quarter 2012 earnings conference call. All participants will be in listen-only mode.

(Operator Instructions)

After today's presentations, there will be an opportunity to ask questions.

(Operator Instructions)

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 third quarter conference call. We have a lot of good information to go over today. With me to answer any questions is Scott Schroeder, all know him, CFO; Jeff Hutton, our VP Marketing; Steve Lindeman, our VP Engineering Technology; Matt Reid, VP Regional Manager; and Todd Liebl, 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 third quarter operating and financial results. We will give you an update on our '12 and '13 guidance. We will also update our hedging program for '12 and '13, followed by an update of our operations in the Marcellus, Eagle Ford, Marmaton, and now we're going to add a brief comment in the Pearsall.

Before I do go into the details on those topics, I would like to highlight some of the items that were brought up in our press release last night. Cabot's production is up 42% over comparable year-to-date periods. Third quarter production was up 6% over the second 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 two-well pad 1.5 miles west of our Zick compressor area. That pad site with two wells had peak rate of 43.8 million 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 '13 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 $43.1 million or $0.21 per share for third quarter of '12, up from $35.3 million or $0.17 per share for the third quarter of '12 -- excuse me, of '11. 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 third quarter was $164 million and $175.7 million 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 nine-month period ended September 30, 2012 was approximately 189 Bcfe, which represents an increase of 42% compared to the nine-month period ended September 30, 2011. Taking into account last year's fourth quarter sale of our Rocky Mountains property, our pro forma year-to-date growth in production is 51%. This nine-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 for '12, we have updated our equivalent production growth range to 38% to 44% and our liquids production range to 60% to 70% to better reflect our outlook for the remainder of the year. We had hoped for and scheduled earlier timings for our Marcellus gathering permits, i.e., being able to turn wells in the 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 fourth quarter. We reaffirmed our net capital spending for '12 at $775 million and $825 million.

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 liquid productions growth range at 45% to 55%. The midpoint of our guidance ranges, when you look at 2012 and 2013 implies three consecutive years of 40%-plus 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 costs 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 million and $1.025 billion, 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, of the 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 would say not a common occurrence in our space. Our 2012 production, excluding the five basis-only hedges, the Company has 37 contracts in our hedging books, 27 are gas swaps at $5.22, 5 are gas collars with a floor of $3.60 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 '12 is currently hedged. For our 2013 hedge book we have added 25 new hedges since our second quarter 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 '13 is currently hedged at an average forward price of $3.63 per Mcf, which is $0.13 above the $3.50 we are 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 third quarter we achieved a new milestone with a 24-hour record of 252 million cubic foot of gas produced in our Susquehanna County area. I should note, we will exceed that level, we think by 10.00 o'clock this morning this morning, and for the last 24-hour period, touching approximately 780 million cubic foot a day. I'm probably 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 two-well pad that recently came online in the Zick area. The combined IP, as I've mentioned, of the two-well pad, was over 43 million cubic foot a day from just 25 frac stages, which utilized the narrower frac stage spacing of 200 plus or minus feet. The original five-well pad at Zick has produced over 11 Bcf in approximately 180 days, which I think further highlights the quality of our acreage as we continue to expand to the east. In other news, we recently had a 22 frac stage well reach three Bcf of cumulative production in just 105 days, and I think that is the fastest record to date. This broke the previous record we had set by 60 days. We are currently operating four drilling rigs in the Marcellus and have 450 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 will go from four rigs to five 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. I might add that that is also dependent upon 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. I have a little bit of a 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 objections 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 freeflow interconnects 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 that we expect, we do still expect to be close to our original goal of approximately one point Bcf per day of takeaway prior to year-end 2012. But just to be clear, and as we have previously discussed, when you put your models together, as the infrastructure requirements grow 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 phenomenon is simply the 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 2013 for our 2014 program.

Now let's move to the south. This region has five rigs operating as we speak, two are in are in the Marmaton and three rigs are drilling in the Pearsall, with one 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 Frio 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, one additional Pearsall well is completing and three wells are drilling. A total of six Pearsall wells are planned for the 2012 program. We hope our early drilling and completed wells will fall in the $9 million to $9.5 million range. Our first well was slightly over $10 million 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 costs. Cabot's net well cost will be 9.75% 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 have been receiving I felt it was necessary to provide an update.

In the Eagle Ford, we announced our release of another successful well with 4500 foot lateral entry 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 these $6.5 million to $7 million completed well cost range. Also in the third quarter, 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 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 Marmaton. Cabot recently completed a well with a 15 stage frac stimulation. The well produced at a initial 24-hour rate of 664 barrels of oil a day, and an average of 593 barrels over the last 20 days. We also drilled our first extended lateral well with a lateral length of approximately 9500 feet. The well was stimulated with 30 stages, and is presently in the early stages of flowback. The second extended lateral well has been drilled and will start completion at the end of October. Completed well costs continue to average around $2.9 million to $3.3 million, with early drilled extended laterals coming in between approximately $4 million to $4.5 million. 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 am most pleased about is the continued innovation our team has come up with, with new ideas that certainly is going to translate into incremental value. My expectation that we will post excellent numbers at year-end '12, and it is also as a forward-look my expectation that Cabot that will in 2013 certainly have industry leading production growth. We will 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 will see a milestone reached in '13 where we will have a 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.

(Operator Instructions)

Pearce Hammond, Simmons.

On your capital guidance -- excuse me, on your production guidance -- for 2013, you provided the liquids production guidance. Does that include the Pearsall?

That includes the Pearsall with a risk profile attached to it. In other words, we obviously risk our exploratory exportation 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 in a larger way next year. So how should we think about the total number of stages completed in the Marcellus in '13 versus '12?

We will certainly be higher. I would expect that the increase will be 35% or so.

Great. And then finally, just from the industry standpoint, given the recent rise in gas prices specifically for the calendar year '13, 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 of the Marcellus might not compete with the returns that some companies might be able to deliver by drilling and some of their oil portfolio.

Great. Thank you very much.

Bob Brackett, Bernstein Research.

I had a question on the Pearsall Shale. You're quoting numbers of $9 million to $9.5 million. If I just compare that against your $7 million Eagle Ford wells, what is that incremental cost? It doesn't seem like just going a little deeper is going to cost you that $2 million.

Well, I will pass it over to Matt for a second, but one of the things that you have to take in consideration is where we are trying to determine where we're going to land the well. We are trying to get our mud properties straight, and certainly it is in a higher pressure regime and the fracs require a little bit more -- well, more pump pressures and we are using ceramic in the frac stages. But I will let Matt also expand on some of that.

Yes, Dan is exactly right, and actually it is a different casing program than our Pearsall program. We have an extra string of casing in our Pearsall program as opposed to our Eagle Ford program, and we do see higher pour pressures in the Pearsall, and we do see higher frac pressures as well; and we do increase our proppant strengths as well during our fracs in the Pearsall.

Great. And are you landing those Pearsall wells in the Bexar Shale or in the Pine Island, or do you think you're stimulating all three 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 microseis work. We will be doing that probably in the first quarter of next year as to what we're actually stimulating. I know where we're landed. We are landed in about a 70-foot interval there in the Pearsall. You can call it the Bexar, you can call it the Cow Creek, you can call at the James. People call it different intervals.

Okay.

Yes, and the 70-foot is in approximately 500- to 600-foot gross Pearsall interval.

Correct.

Great. Thank you.

Michael Hall, Robert W. Baird.

Just a couple of follow-ups on the tighter frac spacing. Just want to make sure I'm understanding. The initial two wells, were those roughly 2500-foot laterals, if you're about 25 stages between the two of them? Is that shorter than your typical lateral, and so on a more kind of normalized basis, we should see more uplift? Is that a fair way to think about it?

Yes, 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, 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.

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 is the reason why we are moving our program to the reduced spacing for the frac. We are 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 were fracking at 250, we'll go into our bookings on EUR at the end of the year, and we will certainly be able to quantify a 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've got for now. Thanks. Congrats.

Brian Singer, Goldman Sachs.

Can you give us the latest update on the backlog that you have in the Marcellus of stages or wells that are drilled but not completed, and completed and 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 coughing attack here. We have -- nice move, Scott.

Thank you.

We have 19 wells that are waiting on the pipeline. Those have 283 stages. We are currently completing nine wells with, or in the process of flowing back, one or the other, 167 stages; and we have 21 wells that are waiting on completion with 296 stages.

I'm sorry Brian, what was the rest of your question?

The rest of the question is, as you get to the 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 need to be constrained, versus wells that you just have 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 million cubic foot a day. 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 -- get up to that Bcf a day. As far as capacity restraints or the existing wells being restrained, either by lack of capacity through de-high or compression, or by higher line pressure because we have not yet gone into the phase where we are 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 will 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.

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 2013? And how do you think about differential and 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 being 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. And as far as the effect it has on where our guidance is, and I think Jeff is the appropriate person to reference the current status of the infrastructure and also where we are 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 will see a central compressor station, which is in the north central part of our play. That is the next major step for Cabot in terms of completing the original infrastructure plan. So, that is kind of late second quarter 2013. We are not relying solely on that, of course. We have a number of projects, some new interconnects with existing pipes, that will be free flow activity; some units that are coming on late this year, early first quarter. But again, you asked about the major next step. That will be central compressor station that feeds a new 24-inch pipeline that is currently being laid that comes down to the old Springville system down the Transco.

In terms of moving gas around, we, of course, are very, very blessed to have three interstate pipelines that we are able to take our production to. A Millennium pipe to the north, a 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, a little bit more gas goes there. Better pricing on Tennessee, a little more gas goes there. So it has been fun, compared to last December when we had, as you know, 600,000 a day flowing into one pipe, and we expect to continue to build the optionality into the system and the flexibility, so that as our production grows, we continue to have those options to deliver gas to different markets.

Great. Thank you very much.

Matthew Portillo, Tudor Pickering & Holt.

Just a few quick questions for me. On the Pearsall -- 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 is one well in one area of the field. So I'd be reluctant to give it all right now. But we are 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 costs, could you give us an update on, as we look at these 12- to 15-stage frac wells, where you're expecting costs 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 3500-foot lateral with 15 stages. Now, our typical well, as we build our database now, will be most likely reflected as a 3500-foot lateral with approximately 18 stages in it. That cost of that well is going to be a little bit higher, because we will have three additional stages in there.

And then in regard to cost, we're about $6 million or so now with our typical 15-stage frac well. So we will have a little bit of incremental cost with three additional stages, but I will also add that we are currently in negotiations with our pumping providers up there, and that process has not executed yet. We have not executed any 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 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. Just wondering if you're looking at bringing in any additional partners across any of your, either exploration or development plays, and how you guys are essentially thinking about capital acceleration potentially heading into 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 are certainly blessed with a portfolio that yields very good returns, and particularly our Marcellus; and we are 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 will continue to do so. In the other areas of our portfolio, we will continue to capture our acreage out there -- that is primary term acreage. We have done so.

As an example of what we have been able to do is the Osaka transaction. We were able to bring a partner in, Osaka, and we are pleased to have them as a partner, and we look forward to having them as a long-term partner. But we were able to bring them in, give them an opportunity to get a foothold in the States, but also it allowed us to have leveraged dollars to drill a little bit deeper in the section, i.e., the Pearsall. We knew the Pearsall had potential, and we are currently drilling in the Pearsall. Those leveraged 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 our return profile with the carrier we have at a very favorable rate compared to the Marcellus.

In the other areas, like the Marmaton, we have acreage out there that we would continue to desire to capture, because we have very good returns out there in the Marmaton, 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 ripe 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 in the Marmaton without a joint venture partner, but we do evaluate it 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 Marmaton and the Eagle Ford, that could potentially be assets where you may bring in additional partners, or just the Marmaton at the moment?

No, I think the entire area we will 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.

Charles Meade, Johnson Rice.

A couple of quick questions for you. Those two 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 seven 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 '13 before we get a line out in that area. We want --

Okay, so that's --

Yes --

I'm sorry. So that is like a first quarter of '13, or something like that?

No, it is second quarter, actually, by the time we get that line out there.

Okay, great. Then the second question I had was -- regarding your Pearsall 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 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.

Joe Magner, Macquarie Research Equities.

Just wanted to try to tie some things together in case I missed it. With the ongoing drilling activity, have you quantified what sort of efficiencies you're seeing in terms of how many wells you can drill per rig per year?

No, I haven't broken it out. I have broken it out like that just on the back of an envelope, but our efficiencies that we see on a per rig basis reflect in our rate of return number per well. So if you want to look at it from a days drilling and rig-to-rig -- or excuse me, spud-to-spud -- in the Marcellus, we are looking at 20 to 22 days, something of that range. Pearsall -- it is 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 now they have come in, in the 40 days to get that accomplished.

So they had already -- were able to beat their initial curve, and certainly they have ideas on how they are going to enhance that. So we are fairly good on the type of drilling we are 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 will have to make once we get to pure pad drilling. We are only drilling two or three 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 every other area that we have been operating.

Okay; great. And just touched on Pearsall being a risked component of your liquids growth. What are the primary drivers that your liquids -- Marmaton, is it? Just provide a little bit more detail on that?

Yes, it is 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 one Bcf a day rate you're referring, is that a net or gross number, just to clarify?

That would be a net number.

Okay, that's all I got. Thanks.

Jack Aydin, KeyBanc Capital Markets.

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 are at 780 million 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've got to make sure that everything is in sync, but I'll do the total Company. I think the total Company would be 900 million equivalent a day or better.

Okay. Second question -- now, in the past you booked most of those --

That's the net number, by the way.

Yes, okay. In the past, you book your reserve as certain EURs. Now with reduced spacing in the frac stages, now it looks like those two wells, you're getting $2 million for the frac stages. If that is what you are 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 3500 feet in 15 stages will go to 3500 foot and 18 stages or so, and those three additional stages are going to have some incremental effect on a similar lateral length well as we had in our '11 bookings. I am not going to stretch to say that every frac stage now will be a $2 million a day increment. That is just -- that is a very aggressive number, and we don't have enough data points to say exactly what it is going to be.

But I will say -- and what we are trying to gather and what Steve Lindeman and his group and also Phil Stalnaker and his group, are trying to determine -- is the additional frac stages. It is just not additive for the three 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 a 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.

Biju Perincheril, Jefferies & Company.

A couple of questions. On this Marcellus completions, how should we think about it? Are you -- with the more stages in given lateral length, are you still pumping the same amount of proppants and water per stage, or are you now proportionately pumping less? And can you talk about, 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 the stages with a similar amount of proppant. And again, the effect on the way we were pumping or the stages, and how we were completing wells before, I think it is 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 is 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 DEP or Army Corps of Engineers?

Yes, Biju, it was actually a combination of those factors. In fact, 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 at those agencies. Just a number of factors from -- communications between dual agencies when you have a wetland application, for example. The DEP has made progress, the Governor actually has intervened somewhat into the process, and so we feel much, much better today that we did a year ago.

Okay, that is helpful.

So, when do you think Williams will start receiving permits for the 2013 program?

So the applications that Williams files are with both agencies -- for the Corps of Engineers and the DEP. They are an ongoing process. So it is 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 are ready have, and 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 is just an ongoing process.

Okay. So I should think about it, you have about 30 location backlogs today, in-hand, permit, all right?

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 six to nine months to get them out, and then it kind of ballooned out to 18 months. It is 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, directly to your question, we kind of expect we would have all of the '13 permits if they take a little over a year to get.

Perfect; that is very helpful.

And that one last question, just clarification on that Pearsall rate. Dan, did I hear you that the rate that you quoted does not include NGLs, it's just the oil and rich gas?

The BOE of over 1400 barrels a day does include the full well strain. 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.

(Operator Instructions)

Joe Allman, JPMorgan Chase & Co.

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 will let Jeff go into that, Joe.

Okay. Well, there is always a challenge with that subject, but here's how we've planned for that one. We currently hold FC 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 are always participating in expansion projects and we have a number of projects that we are considering participation in.

If you think we are producing, or just on 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 [end-path] firm transportation, and that has been our success to date. As we move larger volumes, we've signed some longer term contracts with a couple parties that have this firm transportation. It is very valuable. There has 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 backhaul and additional expansion capacity, Transco has a project right now that will come about in two years that will add around 500,000 to 600,000 a 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 is going to come from a 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 are going to end up holding a lot of firm transport, but we will always be selling to utilities in the Northeast and the mid-Atlantic area that do hold firm transportation.

Okay; that is a good rundown. Thank you very much.

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.

Thank you, Maureen. I appreciate everybody joining us for the call. I think you can see that we have posted some good numbers for our third quarter year quarter-end. I expect the numbers to continue to improve as we get to '12 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 was. So thank you for your commitment; thanks for the loyalty for those long-term holders. And we appreciate your support. Thank you.

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