Coterra Energy Inc. (CTRA) Q4 2012 Earnings Report, Transcript and Summary

Good afternoon. My name is Kayla, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Energy Fourth Quarter Results Conference Call. [Operator Instructions] Mr. Mark Burford, you may begin your conference.

Thank you, Kayla. Welcome, everyone, and thanks for joining us today for our fourth quarter conference call. In Denver, we have Tom Jorden, President, CEO; Joe Albi, EVP and COO; Paul Korus, Senior Vice President and CFO; John Lambuth, VP of Exploration; and Jim Shonsey, our Vice President and Controller. We issued our financial and operating results in the news release this morning, a copy of which can be found in our website. I need to remind you that today's presentation will contain forward-looking statements. However, a number of factors could cause actual results to differ materially from what we discuss, and you should read our risk disclosures on forward-looking statements in our latest 10-K, other filings and press releases for the risk factors associated with our business. We have also posted a copy of the year-end investor presentation on our website, which we'll also be referring to, from time-to-time, on today's call. So with that, we'll go ahead and jump into the call, I'll turn it over to Tom Jorden.

Thanks, Mark, and welcome, everyone. It's a pleasure to be releasing our fourth quarter and full-year results this morning. We had a very nice year in 2012, and I really want to give credit to our organization across the board, for executing and performing on target with the plan we laid out this time a year ago. We had some headwinds to overcome, as those of you that follow us, in the past years. Very pleased that the underlying growth of our asset base is showing, and that Cimarex is on firm footing today and -- as we march through an uncertain future, so we've never felt better about the position of the company. I'm going to be walking you through our results and will be referring to the slides that are posted on our website. I'll start with Slide 4, and will just be letting you know when I move a slide. So to start, we had a solid fourth quarter, reporting record production for the quarter of 677 million cubic feet equivalent per day, and that was 13% greater than our Q4 2011. It's a very nice growth. We grew fourth quarter oil 28%, to another record, 35,099 barrels per day. Very, very nice oil growth. Our full-year 2012 production averaged 625 -- excuse me, 626.5 million cubic feet equivalent a day or 6% greater than our 2011 production. Oil was the biggest driver of that growth. Oil production for 2012 averaged 31,463 barrels per day, increasing 17% over 2011. Our oil and gas sales for 2012 are relatively flat, with higher production being offset by lower prices. Gas prices fell 35%, natural gas liquids prices, on average, dropped 28%, and oil was down 4%. So we reported strong cash flow from operations of $1.1 billion and net…

Thanks, Tom. I'm going to give you an update on our 2013 exploration drilling program. I'm going to first start with our most active region, as Tom mentioned, Permian Basin. I'm on Slide 15, for those of you following along with the presentation. You will note that for 2013, our total expected capital investment will be approximately $900 million, which is just a little bit of an increase over 2012. You will also note, though, that the number of gross and net wells is down relative to 2012, with 150 gross for '13 relative to 182 for '12. The primary driver of that is just our overall portfolio, the type of wells we'll be drilling. Where in '12, we had quite a large inventory of shallow Paddock-Blinebry wells, we really don't have much of an inventory of those left for this year, thus, for the same capital, you get fewer wells because the overall portfolio is slightly more expensive. Going onto Slide 16. As Tom mentioned, our bread-and-butter play has been the Bone Spring. In 2012, we drilled 107 gross, 60 net Bone Spring wells, with 64 in New Mexico, 43 in Texas. We continue to have very strong performance from this program. In New Mexico, our average 30-day IP for the 2012 wells was 640 barrels of oil equivalent per day, with those wells being primarily 90% oil. In the Texas part of the Bone Spring, where we're mainly targeting the Third Bone Spring sand, the 30-day IP rates were 1,000 barrels of oil equivalent per day, with 85% of it being oil. We continue to see great results in both of these plays, and we expect that this will continue throughout 2013. Of course, as we drill these wells, we learn and we try to look for areas…

Thanks, John. I will be going over our fourth quarter and 2012 production statistics. I'll hit a little bit on our 2013 guidance and then just a few comments on where we ended the year with LOE and where we see current service costs. For those of you following along, I'll start here on Slide 29. And to echo Tom's earlier comments in the call, we really did have a great year. We had some strong October and November new well adds that helped prop our fourth-quarter volumes up to a level of 677 million equivalents a day. That was right at the upper end of our guidance of 652 million to 677 million, and up 13% from where we were in Q4 '11 at 601 million a day. All the while, we set a new record in the fourth quarter for total company production, and the driver to that growth, as we've alluded to already in this call, was our increased oil production, which grew 28% over Q4 '11 to a record of 35,099 barrels a day in Q4. Also helping the quarter were minimal production disruptions for plant turnarounds, ethane rejection and other downtime, which, those of you following us for a while have known, did impact us a little bit more, earlier in 2012. We dig deeper into the numbers, we continue to see production growth from our Permian and Mid-Continent programs. Our record fourth quarter Permian net equivalent volume of 292 million a day was up 6% or 17 million a day from Q3 '12, and up 36% or 77 million a day from fourth quarter of 2011. Our oil growth was the real driver here, with our Q4 Permian oil volumes averaging 27,091 barrels a day, another record for the company, and up 42% from…

Thank you, Joe. If you'll page forward to Slide 34, I'm a little brief, I only have one slide. Despite the fall in gas and oil prices during 2012, we had reasonably good earnings, driven by nice growth in production and proved reserves. After investing $1.6 billion in 2012, we ended the year with $750 million of debt. That was inched up, if you will, from about $400 million at the end of 2011. So still plenty of capacity on the balance sheet, but please do recognize that our prior tolerance of note debt has at least evolved into a tolerance of some, albeit still low, amount of debt. We had -- as we mentioned repeatedly, we had good growth in production of 6%, which actually met the midpoint of our very original guidance for the year. And we increased our proved reserves by 10% to 2.3 Tcf, adding 750 Bcfe of reserves through new drilling, which was more than 3x our production for the year. And we had good finding [ph] costs and good rates of return doing it. So as we look to 2013, our expected capital, at the present time, gives a very narrow range for us of $1.4 billion to $1.5 billion. But as Tom mentioned, please appreciate that we reserve the right to increase it some or decrease it some, as the year evolves. Still, at the tight range that we're giving, our expectations are for double-digit growth in production and reserves in 2013. Those are my comments. Kayla, we would be happy to entertain questions at this time.

[Operator Instructions] And we do have a question from Phil Jungwirth from BMO Capital Markets.

On the oil production guidance for 2013, 32,000 to 33,000 barrels a day, it seems to be a little bit lower than the 4Q average, even adjusting for the assets. So can you address why this would be the case? And is it mostly just conservatism on your part, given that greater allocation of capital is going towards the Bone Spring and you've seen better results there?

Phil, this is Joe, I'll answer that. Yes, if you look at the slide, it says, hey, without the property sales, we're showing 1% to 5% growth. When we throw those back in there, 7% to 11% growth. Our projections do incorporate risking. And if we're off, I think what it's basically telling us is that we've got a very strong chance of having another year of double-digit production growth. There's a couple of other things that are at play here, too. At any one given point in time, new wells make up 40% to 50% of our total company production. And those new wells, even these permian wells, they can come screaming off pretty hard. So we're always constantly fighting the snowball effect of new well decline, which can impact the rates of production growth and certainly have an impact on what ends up being the final product of our modeling. But as Tom alluded to earlier in the call, as those of you who've known us for all these years, we are focused on rate of return. And it's all about rate of return. And to the degree that production is a byproduct of that, so be it. Obviously, we want our production to go up. That year or -- all that said, our model is really showing that we have a very, very good chance of another year of double-digit production growth. And we're really pretty pleased with that. Being able to have double-digit production growth is not something to not be proud of. So that's, I guess, our answer to that question.

Yes, this is Tom. If I could just follow up that up. Joe has done this for a long time and he's gotten quite astute at making these models. Our business units send in what they think they're going to do and they time it out, and Joe takes that and looks to see what historically they've done. In the oil patch, things tend to go more wrong than they go right. You have delays in timing, you have delays in equipment. And so Joe factors in what he thinks is our historical average and he risks those business unit models down. That said, the business unit modelers are getting better and better at it. They're going to challenge him and if all goes right, we're going to beat that number. But we'll just have to see as we go through the year. It'd be nice to have a year where all goes right, but it would be our first.

The other thing I want to add because I'm guessing we'll get the question, is on Q1, with our guidance being lower than Q4. Well, a couple of things at play there and this is also impacting our total number. But the Permian Basin sales that we closed on at the very end of the month last year, took about 15.5 million a day off our first quarter production. We also had a number of freezing issues and pipeline issues, and particularly in Culberson County, in early January, that hurt January to the tune of about 16 million a day, that built into that number. We also had a handful of good strong fourth quarter wells that came on in October and November that were on a very good screaming decline here in November and early January that we were fighting. And all of that, when you add it all up says, hey, we're going to be at about flat with Q4, which was strong quarter for us. We were at the upper end of our production guidance. All that said, the model is also saying that we anticipate production to start picking up here pretty quickly in February, and our early indications are that production is doing just that. And when you take a look at our production guidance for the year, and you look at 675 million to 705 million and you compare it to where we were in Q1 or what we're given guidance in Q1, hey, it smells an awful lot like what we told you guys last year. We're going to be kind of flat for the first half of the year and we expect to ramp up here at the end of the year and, lo and behold, that happened. And that's what we're modeling this year. We're going to have a little bit of a delayed start here in the first quarter, primarily as a result of the property sale. Our model is saying that, come around second quarter, we're going to start to see some real nice production growth. And ultimately, I hope, allow us to talk quarter-to-quarter about continued record numbers. So kind of a long answer to your question but I thought I'd knock off the second question because I thought it was going to get asked.

Here's a third question on the guidance. On the NGL production growth of 33% to 39%, is any of that driven by a change in processing contracts and then reporting the NGLs as opposed to leaving it in the gas stream?

No, most of that is all due to the existing contracts, which have already been modified. Most of the old contracts that could be rewritten or revised, all that's been done. So anything really showing up now is all through new adds.

And then final question here, I appreciate all the Wolfcamp disclosure. It looks like there could be some variability in the GOR as you move from the south to the north. Is that the case or am I just drawing some conclusions from 2 wells here?

I don't know. You should -- this is John Lambuth. I don't know you should draw any conclusion from just 2 wells. I would say, clearly, based on how we understand that formation, there is variability. But we tend to think as more of an east-west trend than north-south. But again, we still get surprises as we continue to drill this. But I would say not north-south necessarily, just based on those 2 wells.

But we also see a primary variability, stratigraphically. And that's a complex system.

It is, and that's something again, I want to emphasize. It's a very thick shale and we have really honed in on a particular interval, where we're getting our best results. And you would expect us then to get much more consistent results as we go forward, because that's the interval that we're primarily going to be drilling in.

And we're obviously -- our excitement about the Wolfcamp comes through in our comments. But we're really early times here and, with the interval as thick as it is, we have a lot of that stratigraphy we haven't tested. So we're, as yet, uncertain as to what our ultimate spacing will be, either laterally or vertically. I mean, there's an argument that says 8 wells per section is not adequate to fully exploit this resource. But the truth of the matter is, we don't know, and we really would like to get data rather than speculation.

And our next question comes from Mario Barraza with Tuohy Brothers.

Mario Barraza here. Just want to dive a little deeper on the Second Bone play on the Texas side. Last quarter -- are we still thinking just over 125 well locations is a comfortable count for this point? I know you guys said right now, 100 to 200 locations. But what percentage of your acreage in Culberson do you think this is prospective?

Well, this is John Lambuth, again, and I guess, I would say 100 to 200 locations. I mean, we are very, very early. If you think we're early in Wolfcamp, we're very early in this play. We have 2 very good, very exciting wells that we wanted to tell you about. We have very limited well control. Basically, our well control in that area is our Wolfcamp drilling. It helps define that shallower Second Bone Spring. But unlike the Wolfcamp, there's quite a bit of stratigraphic variability in the Second Bone Spring, so with each well we drill, we learn a little bit more, some to the negative, some to the positive. All I can tell you is, just looking at our acreage position and the current wells we have, we see definite potential and it's in the range that I just mentioned. This year will be very important for us because we have a lot of wells. We will be drilling to test it and further define it. So maybe during the course of the year, we might be able to give you a little bit better update. But we're just being honest, this is how we see it right now, based on the limited well data we have.

This is Tom, if I could just follow-up on that. We've long recognized the potential of Second Bone Spring in Culberson County. This is not news to us. The reason that we haven't talked about it prior to the last call or 2 is because we expected it to be gassy. Based on our overall trend in the basin, we looked at that and this part of the basin and thought, it's probably gassy. We had good shows and we drilled through it, but we hadn't tested it. And these first tests, ours and there are some offset operators, have really surprised us pleasantly. We really didn't expect the Second Bone Spring to be as oily as it is. I mean, these are fantastic oil wells. And so when you ask what controls these 100 or 200 locations? We have that sand map throughout this Culberson block. We have very good shows when we drilled through it. We're just hesitant to get too out in front of ourselves and say how oily or gassy it is, and that's the main controlling factor. Is it going to continue to be oily or will there be pockets of this land where it's a little heavier gas? So that's why we are not waving the checkered flag just yet, but we're very, very encouraged by the results we have, limited though they may be.

Okay, appreciate that color. If I can shift gears towards the CapEx budget for this year. On the last call, you talked about -- you were going to exit the year with 4 to 5 rigs in Cana, but if gas prices stayed depressed, you might -- you were considering shifting out, possibly some rigs and transferring some more CapEx dollars to the Permian. What's kind of the price lever you're thinking about for -- where would you pull back on the number of rigs in Cana?

Well, this is John Lambuth, again. I really couldn't pick a particular price. Again, it's going to be a matter of rate of return. And that's going to be dictated by the type of section we have an opportunity to drill. Again, the yield, the NGL mix, really dictates that rate of return, more than the gas price even. So we're constantly monitoring both our results to make sure we're hitting our expected volumes and our drill costs. Right now, we're very encouraged, I mean, very encouraged with what we're seeing coming out of Cana but, that said, we're always keeping an eye toward gas prices. And yes, if it drops to a level where we don't see it to be economic, we will slow that down or even shut it.

Yes, it's Tom. It's really a function of how much money we want to borrow this year, more than anything else. Our cash flow is what it is, and we're trying to allocate it. Our returns in Cana are quite good. Our returns in the Permian, in general, are slightly better, and it's a function of how much money we want to borrow.

It's Paul. I'll just add that, whether we run these 4 rigs through roughly the middle of the year or whether we run them all through the year, it's only about a $50 million swing. So it really won't move the needle that much in terms of capital or production volumes in 2013, because the wells drilled in the first half will be frac-ed in the second half, roughly. It would have further implications for 2014, perhaps, in terms production volumes. But it's not a needle mover.

I mean, I would just say, again, I would emphasize, we're getting some really great results and they're really making it hard for us to not want to go ahead and get those rigs going. I'll leave it that way. I mean, really good results so far as we start this year.

But we have not made a final decision. We currently have 4 rigs running at Cana, and we've not made a final decision.

That is correct.

And your next question comes from Jeff Robertson with Barclays.

Tom, in the Wolfcamp play in Culberson County, can you talk about where you think you'll be with some of these questions, just around stratigraphy and spacing, by the end of the year? By the end of 2013, that is?

Well, there's really 2 issues, Jeff. And I'd invite John to chime in here. One is, we're still sampling real estate. If you look at our current penetrations, although we think we've got a lot more than we know, there's still a lot of that area that's very finely sampled. So we need to just sample the real estate over that acreage block. We don't currently have planned this year a spacing pilot. Now that's something else that we're still kind of arguing about, because that's -- our experience in Cana is that, that's something you want to know as early as you can for full development. But right now, we don't have a spacing pilot planned for the Wolfcamp. And so we don't know yet what the spacing will be, both laterally and vertically. So your question is, what are we going to know by the end of the year? I think under our current plan, we're going to know the liquids yield and the producibility of that rock over a wider area than we've currently sampled, but in our current plan, we probably won't know any more about spacing than we do now.

This is John Lambuth. I agree. I mean, the only thing I'd add, besides just the overall productivity of these wells is, again, we're very excited about what we're seeing with our drilling complete costs and, really, right now, as we look at these wells, that really is going to be one of the bigger drivers to the type of rate of returns we get. And so far, we're very encouraged by what we see going on in regards to those costs, both from the drill side, but especially on the completion side, is something Joe alluded to earlier. We're definitely seeing a decrease in our completion costs, and that really is very impactful for these wells.

Second question on that play. I think you said there are several different zones within the Wolfcamp. Is all of your drilling going into what you think is the same Wolfcamp interval?

This is John Lambuth, again. Early on, we were, how do you say, all over the court? I mean, trying to understand, optimally, where we should be. It's fair to say, going forward, we've kind of honed in on the particular interval. We break it up into A, B, C, D and E. In our case, we have a particular interval that we now feel really good about and that's where you'd expect us to put the majority of our wells going forward.

If I might add to that, Jeff. Some of the new drilling you're seeing over in Reeves County is in the shallow-most stratigraphy in that Wolfcamp. That's something that we haven't sampled in Culberson County, and there's a -- it looks interesting to us, we don't have a well in it. And it might be additive to everything else were doing and it might not be either/or, it might be additive. And please take that with a grain of salt, don't run out and update your model on that. We just don't know. I mean, we're just -- it looks to us like this Wolfcamp is going to be a legacy asset that can stand tall next to Cana for the future of Cimarex. That's the message this morning. The detail, whether it's $7 billion, $10 billion, $15 billion of future capital, we just don't know. But it's here to stay and we like it.

One last question. Is there the ability to increase acreage in the play, in the areas that you think are promising?

Well, we did increase acreage in 2012. We made a couple of acreage acquisitions that we talked about. It's getting skinny on the broad brushes. But we still get up every morning, and we wrestled home some things and we're continuing to do that. But I wouldn't want to start from scratch today in that part of the real estate, that part of the world.

And your next question comes from Joe Magner with Macquarie Capital.

I just wanted to, I guess, get a sense on when, during the year, do you think you'll have enough information or insight into some of these new opportunities? And the results seem very encouraging, rates of return seem very equivalent across different plays and competitive with existing development opportunities. I'm just curious when we might start to expect to hear decisions on increasing capital or drilling additional wells?

Well, I guess -- this is John Lambuth. What new -- which ones you're referring to, just specifically, so I can....

Well, I guess, the Second Bone Spring opportunity in Culberson, in particular, and then the Wolfcamp Shale, over in that same general vicinity, seemed like the 2 areas, at least where results could be supportive.

Well, I would just say, in Culberson, I think we're pretty set on that 1 to 2 rig schedule for this year, as we continue to identify the opportunity there.

For the Bone Spring, in addition to the Wolfcamp.

For the Bone Spring, in addition to the Wolfcamp, you're absolutely right, Tom. That all -- like we say, that's always subject to change based on performance. But right now, we think that's the adequate rig schedule and capital we need to fully define that opportunity. Clearly, by the end of the year, we'll have a much better understanding of it. In terms of Reeves County, all I'll say is, we really need some more well performance and perhaps even a couple more wells, before even we're ready to talk about it. We need time there. Again, I'll just say we're encouraged. But we need a couple more wells, and we just need to see some more consistent performance, and then we'll probably be in a better position to talk about it.

Okay. And I guess with respect to the Horizontal Wolfcamp that's been focused in New Mexico, 33 wells drilled to date, how much of that acreage has been held now? And what is required, I guess, through this year, to be able to -- this year into next year, to lock up more of that acreage?

Yes, in the New Mexico, in that Wolfcamp trend, it's by and large, I won't say 100%, but it's almost all held. We have a couple of obligation wells that we drill every year but other than that, we don't have any kind of an acreage exploration that's driving our New Mexico portion.

Okay. And there's one last one for me. I believe you all have been working on some other shallow liquids opportunities, or other Mid-Continent liquids opportunities. Any update on any of those new initiatives?

No, no new update as of today. You are right in that there are a couple of plays that we have been pursuing. We still have some more evaluating and drilling to do in those plays. We really can't add any color to that today.

Your next question comes from Ryan Todd with Deutsche Bank.

A question -- I don't mean to beat a dead horse, but I just wanted to follow up on the guidance for this year. The 60 million cubic feet a day that you talked about that was affected by shut-ins in Culberson County, is that just 60 million cubic feet a day in January or is that across the entire first quarter?

This is Joe. That, for the most part, those were very mature properties with very shallow declines.

So it came from the shut-ins, Joe.

Oh, for the shut in. I thought -- the freeze-outs [ph] , for the most part, appear to behind us. We will have, in the Culberson County area, probably in the first part of Q2, some work done to high-grade some of our pegging facilities and improve some of the line itself. So there'll be a little bit of downtime there, but it looks like the freezing issues in January are behind us.

But it's just January. It's built into our Q1 guidance.

So if you were to divide it by 3, I guess, if you want to take a look at that.

And then on the -- how would you describe -- I mean, can walk me through to the state of infrastructure, I guess, as you look forward over the course of 2013? I mean, how much conservatism did you build into the numbers from potential infrastructure downtime? I guess, I'm still having a little bit of a hard time wrapping my head around the fact that, for 18 months, you've done kind of 2,000 barrels a day sequentially each quarter, Permian oil growth, and it seems to have flattened off. I'm just trying to figure out is that -- how much that it's infrastructure downtime conservatism you're building in versus anything else?

There's maybe, if you were to take a look at the Permian, I'll just tell you in equivalents, I don't know how it's going to answer the oil side of it. But I venture to say that we, just on base properties, have integrated somewhere the range of 7 million to 10 million a day of a risk in our base property production that you could attribute to being directly associated with downtime, because that's about what we saw last year as an average. Second quarter last year, I think, we had a 14 million a day impact for the quarter, and most of that was in the Permian. And let's face it, the Permian is a tight deal out there. And we're constantly finding it. We had a few wells here in Q1 that we delayed fracs on, waiting to get the connections put into place. So I guess, if you're looking for a number, that'd be about the number I'd give you. Other than that, I always take a minute when I answer this question this way, too. What we're trying to do with our guidance, heck, the majority of that number is coming from new wells, and we're trying to predict when we're going to drill, and when we're going to hit the good ones, what they're going to produce, and for the most part, I'm really pretty amazed, as close as we all get playing this game, when you're trying to project what you're going to see. So we inherently put, maybe, a 70% to 80% risk into our region on risk numbers, based on history. And that's kind of how we end up where we end up. We look at capital utilization, how well we spent money and added production and so forth, and then come up with our final number.

Ryan, this is Mark. I have one other thought to add to that discussion, is that, as you pointed out in the slide, for the guidance slide, we talked about oil growth, excluding property sale, being 7% to 11%. And the risking that Joe is alluding to and then further risking, if you take our risked/unrisked team's wedge, as Tom alluded to, probably be adding a few thousand barrels a day to these numbers. And if we add that back into these guidance numbers, it'll probably be close to 20% growth year-over-year in oil. So we definitely have tried to build in some uncertainty with the infrastructure, uncertainty in well timing, all those factors that go into guidance. But definitely, there's a lot more upside in these numbers if we hit our plan, but we know historically, there's always timing -- issues with timing, infrastructure, and those things. And so we try to build in, we think, would be a reasonable amount of conservatism for the numbers we can think we can reasonably achieve.

I guess, one last thing for me from an infrastructure point of view, as the pipelines come in, connecting the Permian to the Gulf over the course of the year, I mean, how do you -- you've obviously seen the differential come in quite a bit up to this point, I mean how do you view that playing out over the rest of the year? Do you see upside in terms of potential to narrow that differential or maybe even go at a premium to WTI at any point? Or...

WTI premium -- WTI, no, Ryan. We don't see that potential occurring. We're grateful to see it tightening to where it's gone. But I mean, we've -- when we look at the forward curve, I'd say it's still at around $1 range, that's -- we look at our models, and we don't assume it to go to premium, but we don't also assume to buying [ph] back out like we saw early late last year and early part of this year.

And there are no further questions at this time.

Great. Thank you all for joining us on the fourth quarter conference call. I look forward to reporting to you next quarter. Take care. Bye-bye.

This does conclude today's conference call. You may now disconnect.