Cabot Oil & Gas Corporation
Q4 2011 Earnings Call Transcript

Published: 21 Feb 2012

[Operator:]

Good day, and welcome to the Cabot Oil & Gas Corporation Fourth Quarter and Year End 2011 Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO of Cabot Oil & Gas. Please go ahead.

[Dan O. Dinges:]

Thank you, Valerie. I appreciate everybody joining us for this call. I have with me today, Scott Schroeder, our CFO; Jeff Hutton, VP of Marketing; Steven Lindeman, our VP of Engineering and Technology; Matt Reid, our VP and Regional Manager; and Todd Liebl, our newly appointed VP of Land and Business Development. Before I start, let me say that the forward-looking statements included in our press releases do apply to my comments today. All right. At this time, we have many things to cover and expand on, particularly the press releases that were issued last night. I will briefly cover full year financial results, the results of our year end reserve analysis. I will discuss our outlook for Cabot, followed by a discussion of our operations in Pennsylvania, Oklahoma and Texas, including a brand-new takeaway project that we announced in the Marcellus. Before I go on the details of these topics, let me give you a couple of cliff notes of the 2011 for the company. We grew production 43.5%; grew reserves 12% absolute or 22% pro forma taken in consideration asset sales. All-in company-wide finding costs of $1.21 per Mcf, including an all-in $0.65 per Mcf Marcellus finding cost figure. We had doubled the level of proved reserves associated with liquids. 2010 Marcellus wells, we revised up to 11 Bcf from 10 Bcf. Undrilled cut [ph] percentage is 36%, flat with 2010. Net income exceeded $100 million for the seventh consecutive year even with the lowest natural gas price realized in that same timeframe. And our debt levels were reduced year-over-year. On the financial results. Cabot reported for 2011 clean earnings of $139 million with discretionary cash flow of about $549 million. The year experienced the lowest natural gas price since 2004. Fortunately, this was offset by the highest production growth recorded by Cabot. In terms of full year production, the company posted a 43.5% growth rate in 2011 compared to '10. This was driven by a 42.5% expansion in natural gas volumes, which was driven entirely by the Marcellus and a 68% growth in oil and liquid volumes. From our organic program and net of asset sales, Cabot had another stellar year adding reserves to surpass 3 Tcf mark, just 2 years after reaching the 2 Tcf mark. Our oil and liquids reserve bookings contributed by doubling between 2010 and '11. However, the main driver of this growth was the Marcellus effort and the continued strength of this drilling program. As we have highlighted in previous presentations, we have wells that rank as the top performers, included -- including released last week by Pennsylvania, 8 of the top 10 for cumulative production during the last 6 months of 2011. For 2011, the typical 15-stage well has been booked at 11 Bcf, while the 2010 Marcellus program EUR average was raised to 11 Bcf from 10 Bcf. Also of note is Cabot did book a couple of wells with EURs in excess of 20 Bcf, creating a high watermark for Cabot and, most likely, the industry. At the end of 2011, we adjusted our PUD portfolio removing the EUR in the Marcellus, moving the EUR in the Marcellus slightly higher to 7.5 Bcf for the representative 10-stage well. We also, once again, removed legacy PUD bookings throughout our portfolio, which were not in the queue for drilling, totaling 190 Bcfe. As result and as mentioned, our undrilled PUD reserves account for 36% of the totals with another 5% drilled but not yet frac-ed, and we have a 59% proved developed percent. In terms of economics, the Marcellus finding cost of $0.65 per Mcf is a standout for the 2011 program. And considering the oil and liquids efforts by the company, the $1.21 per Mcf oil source number is also very competitive. As you're aware, the oil dollars are converted 6

[Operator:]

[Operator Instructions] Our first question comes from Brian Lively of Tudor, Pickering, Holt.

[Brian Lively:]

Just a few questions on the -- Dan, your comments on the Marcellus simulation model. Just curious, what is the assumed EURs for the upper and lower Marcellus?

[Dan O. Dinges:]

Let me see, well, in the lower Marcellus, we have 11 Bcf as our assumed EUR, which is what we have been drilling today, Brian. And the assumed EUR in the Purcell, upper Marcellus as we stagger these wells, we kind of used what our PUD number is right now at 7.5 Bcf until we get further information.

[Brian Lively:]

Okay. And that's -- I assume that's what's loaded in the simulation work. So what key -- what are the key history match variables?

[Dan O. Dinges:]

I'll let Steve Lindeman answer that.

[Steven W. Lindeman:]

Brian, the key history match variables are really the production rate and pressure that we've seen on the 2 offsetting wells that we have modeled, and then, obviously, as we get an in-fill well, we will then look at that similar information to see how it matches our model.

[Brian Lively:]

Then I'm curious too just because the wells have been so productive as you guys have history matched, I guess, some of the production pressure data so far, what type of permeabilities are you guys able to match to?

[Dan O. Dinges:]

Well, Brian, I'll have to get back with you. I don't remember exactly what the permeability numbers were in the model. I was more concerned about the match and how it corresponded to the history. What they did is took the petrophysical data that they had from the logs and then correlated that back to what core data we had to then get a permeability match. And that matched extremely well and then we applied that to the production history, again, to validate the model.

[Brian Lively:]

Okay, that's helpful. Just a last question on the simulation work. Are you guys integrating the downhole with the surface conditions? Meaning do you have a long-term forecast of compression and pressures and that sort of thing?

[Dan O. Dinges:]

Yes. The initial modeling that we did was at the -- a higher line pressure but the really, the ultimate model when we looked at our NPV analysis, we looked at a lower line pressure.

[Brian Lively:]

Okay. Dan, on the $100 million of lower CapEx, the question, I think, is probably out there for everyone is at what gas price would you guys add that $100 million back?

[Dan O. Dinges:]

That's a good question. What we see and what we're able to accomplish with this $100 million reduction, we're able to maintain our acreage, we're able to deliver still double-digit production growth, we're within the $50 million, $75 million of cash flow. We have a production growth of 35% to 50%. And with that being said, we're comfortable in delivering that program, and if it looks like that more on a macro sense, that the market has corrected itself in a way that will not create volatilities, then we would probably start adding additional capital. If it's just kind of a near-term spike in prices or something like that, we'll probably stay the course that we've outlined and until we see some macro improvements in the market.

[Operator:]

And the next question comes from Joseph Allman of JPMorgan.

[Jeanine Wai:]

This is Jeanine Wai. I just had a quick question on your lower Smackover. I know you said that you're just slowing back the first well. But I was just wondering if you could give a little more clarity around the acreage position you have and where it's located.

[Dan O. Dinges:]

No, we have not gone into that at this stage, but as soon as we come up with some well results and all, we'll be able to come out with more detailed information.

[Jeanine Wai:]

Okay, great. And then the second question, as far as your decline curves in the Marcellus, are they really representative, or are the production curves kind of flatter because of the physical constraints that are going on right now?

[Dan O. Dinges:]

I would say that because we're producing into a higher line pressure, they're a little bit flatter than what we would see if we have the opportunity to flow into a lower line pressure. But again, I think, they're pretty consistent through from well to well, and we see a pretty good decline that's consistent.

[Operator:]

The next question comes from Gil Yang of Bank of America Merrill Lynch.

[Gil Yang:]

Dan, you said that the PUDs were moved to 7.5 Bcf for 10-stage well. What were they booked at before?

[Dan O. Dinges:]

We had those at 6.5.

[Gil Yang:]

6.5 for all the 10 stages?

[Dan O. Dinges:]

Yes. That was again 10 stages, correct.

[Gil Yang:]

Okay. And the 2010s were how many stages?

[Dan O. Dinges:]

Yes 20 -- go ahead, Scott.

[Scott C. Schroeder:]

Gil, 2010 PDPs, we assumed 14 stages.

[Gil Yang:]

Okay. And the 2011 was, you said, was 11 -- 15 stages but 11 Bcf?

[Dan O. Dinges:]

That's correct.

[Gil Yang:]

Can you talk about how many PUDs per PDP you've been booking?

[Dan O. Dinges:]

We're at just slightly below or right at 1

[Gil Yang:]

Okay. Is that going to change anytime soon?

[Dan O. Dinges:]

We're comfortable with that. We've been managing our PUD book, as you're aware, in light of the SEC 5-year rule and in the last couple of years, we've been managing that PUD book. We probably have just a handful of PUDs still that we'll continue to manage into next year and that will be taken care of. But we're comfortable with our PUD booking at this stage.

[Gil Yang:]

Okay. How much lower -- could you cut more capital and still maintain your acreage? Or what kinds of resistance to cutting additional capital would there be in your program? Are you obligated to the 4 rigs for this year, and you're going up to 3 later in the year? Or what kind of limitations do you have in terms of additional changes to your budget?

[Dan O. Dinges:]

Well, there's a number of things that balance in making a decision to cut capital. We're still trying to retain as much efficiency in our program as we can, and the greatest gain of efficiency is when we can drill multiple wells from a pad site. That gets strained a little bit as we have to incorporate the development of our acreage out there. And to reduce capital further, create somewhat additional inefficiencies if we have more rig moves. And it'd be difficult, in my opinion, to reduce capital much further than we are right now in the Marcellus. Obviously, we could still reduce some spending in the Eagle Ford by maybe only having 1.5 rigs for the entire year versus 2.5 -- versus 2 rigs. But we don't anticipate doing that.

[Gil Yang:]

All right, great. And just a last question. What's your -- what's the current total backlog of wells that are, at some stages, not being -- not producing? What do you expect it to be by the end of the year?

[Dan O. Dinges:]

Are you talking about in the Marcellus?

[Gil Yang:]

In the Marcellus, how many frac stages are not yet producing in some stages being completed or waiting on pipeline?

[Unknown Executive:]

Yes. Gil, in the speech, we said we've got 198 stages completing, cleaning up or waiting to turn in line and an additional 326 stages waiting to be completed.

[Gil Yang:]

And where is that going to go by the end of the year?

[Dan O. Dinges:]

Well, the simple math is even if you drill just, say, 1.5 wells per month with the rigs and assume a 15 Bcf -- excuse me, a 15-stage completion and averaged somewhere between -- even though they've done really good on the first 2 months of 82 and 92 stages for the frac crew, assume 70, 80 stages a month by the frac crew, that's -- you can do some good math with that.

[Operator:]

The next question comes from Pearce Hammond on Simmons & Company.

[Pearce W. Hammond:]

You guys had a lot of success last year of reducing your well cost in the Marcellus. I'm just curious how you see that trending this year.

[Dan O. Dinges:]

Well, this year with the program that we've announced and having a number of rig moves as opposed to just parking on a location and drilling out that particular location, we anticipate the efficiency gain to be relatively flat from the gains that we have to date. We don't anticipate gaining a great deal more just because of the nature of how we're having to conduct our operations.

[Pearce W. Hammond:]

Now I know you've already signed your frac-ing contract, the 13-month frac-ing contract. Do you see on other services potential for lower cost that would flow through to your walls?

[Dan O. Dinges:]

On the -- and this is a little bit of speculating right now, Pearce, but on the vendors that we pick up on a spot basis and the announcement made by a number of companies that they would be reducing their rig count whether it's because of natural gas or whether it's a result of the Pennsylvania impact fee that has been imposed, I could see where spot vendors and that type of service could be coming down as some would desire to keep their crews or services busy.

[Pearce W. Hammond:]

Great. And then on a leading-edge basis, how many stages are you completing per well right now? And is there a difference between the North and the South within Susquehanna County?

[Dan O. Dinges:]

No. We're -- right now, we have -- are completing, as our '11 program indicated, about 15 stages per well. And when you move to the -- and do we hope to be able to get that a little bit higher? We would hope to be 16 to 17 for our total program in '12. And what we did in moving up in the North area, we recognized certainly with our size that it was a little bit more complex at the very northern end of our acreage and to additional faulting, and we went out there and frac-ed a couple of our early wells and -- but we did set up our micro-size work and as we were frac-ing the early wells, we just kind of went through the fracs. And then after we integrated the micro-size work, and we started looking at the micro size, we determined that the efficiency of some of the fracs along the line drill, if they get off into a fault, we're not getting good efficiencies in those frac stages and in fact, through our micro-size work in the northern end when we started pumping, if we had -- did not get to the pump pressures we wanted to see and felt like we were losing efficiency, we just shut down a couple of the fracs on those wells and said we're just not going to pump that stage and move to the next stage. And that's how we monitored the frac-ing up there with micro size. And that's why I made the statement that as we place these laterals up in this faulted area, we're going to have to just be a little bit more selective on not only where we lay the laterals but how we pick the frac stages.

[Operator:]

And the next question comes from Biju Perincheril of Jefferies.

[Biju Z. Perincheril:]

Dan, a couple of questions. Just going back to those -- the northern wells. How many do you have now producing there? And do you have a number on what the average well is up there?

[Dan O. Dinges:]

We have about 9 wells producing right now.

[Biju Z. Perincheril:]

Okay. And then how many of those wells had issues, didn't have -- had an ineffective assimilation?

[Dan O. Dinges:]

Well, we had -- at least half of those wells had issues with what we would deem getting effective frac stages put away.

[Biju Z. Perincheril:]

Okay. And then do you have a number on the well frac, did it have an issue what those wells are producing now?

[Dan O. Dinges:]

I don't know.

[Unknown Executive:]

That group, that path just went online, so it's very early. And because it was right on the pipeline, Biju, we limited our flow back and we're cleaning these up in the line. But we believe that early indications are that they are performing a lot better than the first pad sites.

[Biju Z. Perincheril:]

Got it. Okay. And then I think you mentioned you're going to go 3 rigs by the end of the year. What is sort of the timeline from going to 5 to 3? When is that first and second rig's going to come off?

[Scott C. Schroeder:]

Biju, this is Scott. The first one kind of rolls off in the July time period, and the next one late third quarter or early fourth quarter. So again back to the earlier question, if we do see some positive changes in the macro that Dan talked about, we could change that decision at that time.

[Biju Z. Perincheril:]

Okay. Got it. So if you do end up going to 3 rigs, then how do you think about your program the next few years from an HBP requirement standpoint, like what kind of rig activity do you need?

[Dan O. Dinges:]

We have every expectation of maintaining our acreage and, again, we balanced our '12 program and I realize it's kind of a snapshot. But with the efficiency we have in drilling out there, I think we can maintain our pace if we look at the horizon and see optimism, we can maintain our pace and catch up fairly quick. And certainly our intent is to stay ahead of the frac rate.

[Biju Z. Perincheril:]

Okay. And then on the oil side, if I look at your first quarter guidance, if I look at the midpoint, you're guiding to a sequential decline. Is that just some conservatism bolt into the guidance? It doesn't look like you changed it from the last time you updated it. Or is there something from a completion schedule that could cause that?

[Dan O. Dinges:]

No, we're just -- we just are relatively conservative with our guidance. We think the range of 5,000 to 6,000 barrels is okay at this time. And again, once we get deeper in the year, then we'll look at both our gas and oil, and, I think, certainly our oil is anticipated to increase.

[Operator:]

[Operator Instructions] Our next question comes from Jack Aydin of KeyBanc Capital markets.

[Jack N. Aydin:]

A question for you guys. How quickly could you respond to change in prices and what is the price inflection that you might get 50% plus ROR?

[Dan O. Dinges:]

Well, I'll let Scott visit about the ROR a little bit because he's been in a lot of work on that, but as far as the price change, Jack, again I'm not trying to dodge the question, but it is going to be more of a fuel of the overall market and the strength of the overall market and make sure that we have some support and that we feel like that the supply-demand function is in fairly close balance. And as far as the ROR, I'll let Scott visit about that.

[Scott C. Schroeder:]

Jack, as we highlighted in our press release back in January when we announced the exit rate for the Marcellus and reinforced the rate of return, and that was on account of a $3.18 when we telegraphed the realizations for the fourth quarter, at $3 we're still modeling a 50% for tax rate of return. And so these things, as Dan alluded to in his speech, are still highly economic even at this $3 strip that we're hanging around at this point in time.

[Jack N. Aydin:]

The next question I have is basically when you look at 3,000 locations and you -- the simulation and everything, what percentage of those locations is going to be Purcell or upper [indiscernible]? Do you have a number there?

[Dan O. Dinges:]

No, I haven't looked at it exactly, Jack. I think it'll probably be 25% to 30% would be in the -- maybe 40% would be in the Purcell, upper Marcellus.

[Operator:]

And then next question comes from Joe Stewart [ph] of Citigroup.

[Unknown Analyst:]

On the 2011 Marcellus wells, what's the average 24 IP in those?

[Dan O. Dinges:]

On 2011 wells, Joe?

[Unknown Analyst:]

Yes, 2010 was 16.4 million a day if I remember correctly.

[Dan O. Dinges:]

Well, I think it's going to be similar to that. It's going to be 15 million to 16 million cubic foot a day.

[Unknown Analyst:]

Okay, got it. So the cume [ph] production, that's probably going to be pretty close to in line with what you had pointed out in a couple of your presentations about 2.75 Bs in the first year, does that sound right?

[Dan O. Dinges:]

That's going to be...

[Unknown Executive:]

We're modeling about 22.5% in the first year in terms of what the cumes [ph] would be.

[Unknown Analyst:]

Okay, got it. And then you kind of hinted to it a little bit earlier but on the absolute well cost in 2012, with the 30% reduction in the completions, aren't you still expecting a decrease in the total well cost?

[Dan O. Dinges:]

Yes. We're looking at plus or minus $6 million for a 15-stage well.

[Unknown Analyst:]

Okay, great. So plus or minus $6 million versus average of about $6.75 million before right?

[Dan O. Dinges:]

Yes.

[Unknown Analyst:]

Okay. So really that should get your pretax IRR to something closer to 70% at $3 gas if everything else stays the same but you have the 11 Bcf EUR now versus the 2010, right?

[Scott C. Schroeder:]

Yes. I don't know that I'd go as high as 70%, but I know the number would be above 50%, maybe somewhere in the 60% range.

[Unknown Analyst:]

Okay. All right, great. And then -- so the PUDs in the Marcellus, how many PUDs do you have booked now?

[Dan O. Dinges:]

We have about 150 undrilled PUDs.

[Unknown Analyst:]

150, okay. Great.

[Operator:]

And the next question comes from Andrew Coleman of Raymond James.

[Andrew Coleman:]

I had a question on Btu content for the Marcellus, I guess, what range of Btu content have you seen in...

[Dan O. Dinges:]

We've seen 1,020.

[Andrew Coleman:]

Okay. And, I guess, what sort of -- do you have any CO2 or nitrogen up in that -- up where you produce?

[Dan O. Dinges:]

No, we do not.

[Andrew Coleman:]

Okay. And, I guess, how low down -- I mean, I've heard folks talk about ranges throughout the state as low as 800. I mean, is that consistent with what you've seen in your analysis of the state?

[Dan O. Dinges:]

800 what?

[Unknown Analyst:]

800 Btu per Mcf.

[Dan O. Dinges:]

No, where we are, we're at 1,020.

[Unknown Executive:]

[indiscernible] have you seen that? We haven't looked at that.

[Dan O. Dinges:]

No, I'm sorry, Andrew. I have not looked at that across the state.

[Operator:]

[Operator Instructions] We do have a follow-up question from Biju Perincheril of Jefferies.

[Biju Z. Perincheril:]

A quick question, Dan. You mentioned $1.4 billion future development costs. Is that for the wells that are undrilled only? Or does that include the wells that are waiting on completion?

[Dan O. Dinges:]

That's all-inclusive. That is -- is for reserve report capital.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.

[Dan O. Dinges:]

Well, thanks, Valerie. I appreciate everybody's interest in the program, and I hope everybody appreciates a little bit more of the adjustments that we've made to the program and some of the reasons why we did. Kind of the top 5 takeaway is that certainly we have top-tier Marcellus production and that's evidenced by the most recent DEP release on all the wells in the Marcellus. We have a new catalyst and a new pipeline coming, the constitution pipeline, which we think is setting the stage for a very opportune time that we see out on the horizon for the natural gas market. We have seen some 20 Bcf wells in our area, and we are excited about how they perform. Our cash flow focused investment program even at the current strip price, I think, is going to yield very, very good returns, both in production and in reserves. And with the year end 2012, I think, we're going to be able to mimic what we've done in 2011, and that's have a double-digit growth in both production and reserves and our balance sheet is going to be very strong moving into '13. Thank you for your interest in Cabot. Goodbye.

[Operator:]

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