Coterra Energy Inc. (CTRA) Q3 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to the Cabot Oil & Gas Corporation Third Quarter 2012 Earnings Conference Call. [Operator Instructions] After today's presentation, 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, and with me to answer any questions is Scott Schroeder, you all know him, CFO; Jeff Hutton, our VP, Marketing; Steve Lindeman, our VP, Engineering and 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'll give you an update on our '12 and '13 guidance. We'll 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'd 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 2-well pad, 1.5 miles west of our Zick compressor area. That pad site with 2 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…

[Operator Instructions] Our first question is from Pearce Hammond, Simmons. Pearce W. Hammond - Simmons & Company International, Research Division: On your capital guidance, you mean, 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. Pearce W. Hammond - Simmons & Company International, Research Division: 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 '13 versus '12?

We will -- we'll certainly be higher. I would expect that the increase will be 35-or-so percent. Pearce W. Hammond - Simmons & Company International, Research Division: 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. It -- I think it depends on where companies have rate of return projects in their portfolio that would complete -- 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 in some of their oil portfolio.

Our next question is from Bob Brackett, Bernstein Research. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: 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's that incremental cost? It doesn't seem like just go it a little deeper is going to cost you that $2 million.

I'll pass it over to Matt for a second. But one of the things that you have to take into 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's 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.

Dan is exactly right. And actually, it's 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 profit strength as well during our fracs in the Pearsall. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: And are you landing those Pearsall wells in the Bayer Shale or in the Pine Island? Or you -- do you think you're stimulating all 3 sub units?

Right now, we barely -- we haven't really discussed that, and I can give you a little bit better feel for that after we do some micro seis work. We'll be doing that probably in the first quarter of next year, as to what we're actually stimulating. I know where we're landed, landed in about 70-foot interval there in the Pearsall. You can call it the Bayer, you can call it the Calcreek, you can call it the James. People call it different intervals.

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

Correct.

Our next question is Michael Hall, Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Just, I guess, a couple of follow-ups on the tighter frac spacing. I just want to make sure I'm, I guess, understanding the initial 2 wells. Were those roughly 2,500 foot laterals, if you're in about 25 stages between the 2 of them? And is that a bit shorter than your typical lateral, and so on a more kind of a 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 shortened our laterals. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. Fair enough. And, 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, then.

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 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 are frac-ing at 250 will go into our bookings on EUR at the end of the year, and we'll certainly be able to quantify a efficiency gain by virtue of that process. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: 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 utilized in that new approach, roughly?

We will be implementing the 200-plus or minus foot spacing for our entire '13 program.

Our next question is 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 -- you -- 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 have -- are waiting on the pipeline. Those have 283 stages. We’re currently completing 9 wells with -- or in the process of flowing back one of the other 167 stages. And we have 21 wells that are waiting on completion or -- with 296 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’ve got entitlement [ph] 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. It's -- to me, it looks like that we will be able to, depending again where these 30 wells are coming on line and the infrastructure capacity, it looks like that the wells that we'll bring on line 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 dehy or 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. 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 year in 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. 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 outlooks coming on over the course of 2013? And how do you think about differential and the content of flexibility in terms of where you sell your gas as you look ahead to next year?

Okay. Well, 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 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's kind of a second half or second -- late second quarter 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 free flow activity; 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's currently being laid. It 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 3 interstate pipelines that we're able to take our production to: a Millennium Pipe to the North, a Tennessee Gas Pipeline on the 300-line right through the center of our acreage; and, of course, the Transco lighting system. So currently, with the options that we have with 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 more gas goes there; better pricing on Tennessee, a 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.

Our next question is from Matthew Portillo, Tudor, Pickering & Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: 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's one way all 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. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: 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 -- 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 million 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 yet 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. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: 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 potential 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 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're firmly 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 Osaka transaction. We were able to bring a partner in, Osaka, and we're very pleased to have them as a partner. And we look forward to having them as a long-term partner. So 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 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 a return profile with these -- 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 it is 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 -- 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. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. So as we think about those, is it both 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'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 it.

Our next question is from Charles Meade, Johnson Rice. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: 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 '13 before we get a line out in that area. We wanted... Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: I'm sorry. That was -- So that will be like a first quarter '13 or something like that?

No, it's second quarter, actually, by time we get that line out there. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: Okay. Great. And 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. Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division: And so -- I mean, 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.

Our next question is Joe Magner, Macquarie.

Just wanted to, I guess, try to tie some things together in case I missed it. 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 -- I haven't broken 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 per well. So when you look at -- 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're looking at 20, 22 days, something of that range. Pearsall 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 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 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 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 touch on Pearsall being a risk component of your year-over-year liquids growth. What are the, I guess, primary drivers that your liquids? Is it Marmaton? 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 Bcf a day rate you're referring to, is that a net or a gross number? Just to clarify.

That is -- that would be a net number.

Our next question is Jack Aidan, KeyBanc.

Dan, could you guess or venture to guess what would you might exit the year in terms of production out of the Marcellus? I mean, you have 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, you’ve got the 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 million equivalent a day or better.

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

That’s a net number, by the way.

Yes. Okay. In the past, you booked your reserve at certain EURs. Now with reduced spacing for -- in the frac stages, now it looks like those 2 wells, you're getting $2 million for the frac stages. If that's what you're going to grow through the year, 2013, directionally, what kind of uplifts we might see in the reserve booking? I know it is early, but can you venture in that area also a little bit?

Well, I can tell you 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 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 million 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 Lindeman and his group and also Phil Stalnaker and his group were 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 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.

Our next question is Biju Perincheril from Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: A couple of questions. On this Marcellus completions, how should we think about it? Are you – with the more stages and doing 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 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 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'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 in 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. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. So if I think about the frac length laterally, that's about same as before?

Yes. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. And then on the infrastructure issues you've 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's actually a combination of those factors. In fact, the -- Williams has done an excellent job with the agencies, at 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. Bit 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. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. That's helpful. So when do you think Williams will start receiving permits for the FY 2013 program?

Okay. So the applications that Williams’ files are -- with the agencies, the Corps of Engineers and the DEP, they are on an ongoing process. So it's not exactly a calendar year. 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 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's just an ongoing process. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. So I should think about -- you have about 30 location backlog today in hand, permit. And then...

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, 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, directly to your question, we kind of expect we'd have all the 13 permits, if they kind of take a little over the – a year to get. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Perfect. That's very helpful. And then one last question, just clarification on that Piersall rate. Dan, did I hear you that the rate that you quoted is not -- does not include NGLs, such as the oil and rich gas?

The BOE of 1,400 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.

[Operator Instructions] Our next question is Joe Allman, JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: 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, there's always a challenge with that subject, but here's how we plan for that one. We currently hold FT basis of 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. On a -- if you kind of think we're producing -- we're 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 end-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 in use, so capacity has freed up on that pipeline and also in 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 2 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's going to come from a central compressor station that I mentioned earlier into the Iroquois Zone 2 market and a 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.

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 marks.

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, 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 has now concluded. Thank you for attending today's presentation. You may now disconnect.