Coterra Energy Inc (CTRA) 2006 Q2 法說會逐字稿

Good afternoon, my name is Lisa and I will be your conference operator today. At this time, I'd like to welcome everyone to the Cabot Oil & Gas second quarter 2006 earnings conference call.

[ OPERATOR INSTRUCTIONS ] At this time, I would like to turn the call over to Mr. Dan Dinges, Chairman, President and CEO. Please go ahead, sir.

Thank you, Lisa. Good afternoon. Thanks for joining us for this 2006 second quarter earnings teleconference. With me today: Several members of our management team. Mike Walen, our Chief Operating Officer, Scott Schroeder, our Chief Financial Officer, Jeff Hutton, our VP of Marketing, and Chuck Smyth, our VP Controller.

I need to read the following before we get started: The statements regarding future financial performance and results and the other statements which are not historic facts may, during this teleconference, are forward-looking statements that involve risks and uncertainties including but not limited to market factors, the market price of natural gas and oil, the results of future drilling and marketing activity, future production and cost and other factors detailed in the Company's Security and Exchange Commission filing. All non-GAAP financial measures discussed during this conference call have been posted on the our website at www.CabotOG.com, along with a reconciliation to the most directly-comparable GAAP financial measures.

I think all of you all saw that earlier we announced several milestones for the second quarter, including earnings, cash flow levels and production rates surpassing the Company's previous high watermark. For the quarter ending June 30, 2006, Cabot recorded net income of $46.9 million, cash flow from operations of $114.4 million and discretionary cash flow of $111.6 million and a record quarterly production of 23.5 BCFE.

Our production was up 10% versus last year's second quarter with each of our regions contributing to this increased performance. The east was up 16%. West was up 2%. Gulf Coast up 10% and Canada was up 84%. These results exceeded the upper end of our guidance, and most importantly, with the majority of the increase coming from the success of our low-risk, repeatable drilling program, I think it demonstrates the impact of our program and the remainder of 2006 and years beyond should also be rewarding. Pricing also was a contributing factor for the financial results. However, while commodity prices for natural gas in the second quarter were off their highs late last year, the prices were still higher than Cabot's realizations last year.

Oil prices also remain strong on continued worldwide uncertainty. A positive impact for Cabot in this year's second quarter and first half of the year, realized pricing was no adverse effect from hedging. Actually, our natural gas price, realized price in the quarter increased by $0.34 per MCF due to our hedges, while our oil hedges during the period remained within the collared range. With our wide collared philosophy on hedges, Cabot has protection to the downside on 33% of its daily production for the remainder of 2006. During the second quarter, we have continued layering on wide collars for 2007.

To date, we have 90,000 MMBTU of gas per day hedged and an average floor for 2007 of $8.83 and an average cap of $12.16, plus 1,000 barrels of oil hedged at a $60 floor and an $80 cap. This brings our total hedge position for 2007 to approximately one-third of anticipated volumes. We have a detail of all of this on our website.

In terms of our balance sheet, we started the year with total debt of $240 million. At the end of June 30, 2006 -- or at June 30, 2006, it is now at $350 million. The reason for this slight increase in debt is entirely related to $27 million we spent in the second quarter, buying in 666,200 shares of our common stock. What the sell-off of the energy sector during June, our shares were trading at levels that valued our reserves below our recent historic binding costs and well below any M&A activity recently announced. We saw this as a prudent investment to pick up some of our shares. With these purchases, our remaining authorization is 819,950 shares. Also, with this activity and the slightly-higher debt, our total capitalization ratio has improved to 33% from 36% at year-end.

Operating expenses have continued over -- to increase over last year's second quarter, due primarily to higher expenses from the inflationary pressures we've been seeing. We will remain diligent in our efforts to contain costs with a more consolidated drilling program. For example in in our [Minden] area, I would expect to see cost efficiencies as a result.

Moving to operations for the quarter, we had scheduled 126 wells to be drilled. We were six wells short of this, however, of the 120 wells we did status, we had a 97% success rate, highlighting the low-risk nature of our program. We currently have 25 rigs, 22 of those operated, drilling throughout the Company and 21 completion operations currently under way with 10 additional wells waiting on completion operations.

We're on track to execute our program for the second half of 2006, to complement our second half drilling. We have four rigs to be delivered from three different providers. Two are coming in August. One in October. And one in December. These rigs will be utilized in our East Texas and North Louisiana program under either a two- or three-year contract. Our drilling program has been the catalyst for growth so far this year. As the press release highlights, we have had some significant news in most of our regions.

I'm going to discuss activity on two areas in the Gulf Coast region, two areas in the west region, two prospects in -- or three prospects in Canada and an update on our east region activity. In the Minden Prospect area in East Texas, we have drilled and completed nine Cotton Valley producers, flowing at rates between 1.8 to 3.5 million cubic foot equivalent per day with an average of these nine wells at 2.6 million equivalent per well.

We are currently completing three additional wells and have three rigs currently operating in the field. On this prospect, we control 10,000 acres with a 100% working interest. The Company will drill at least 12 additional wells this year at Minden. Minden will also be [activitied] with a number of locations we have in front of us for years to come. We are drilling on 40-acre spacing and have about 200 locations out in front of us.

We reported during the last conference call that we were drilling and completing the initial two wells on our Castor Structure. That's up in North Louisiana. That work is now complete and we are pleased to report what we feel is a significant discovery on our 9200-acre block at Castor. The 041 has been drilled and completed in the Cotton Valley Sandstone at a rate of 2.9 million cubic foot per day with multiple Hosston sands behind pipe. At the Weyerhauser 24-1, located about four miles to the southwest of the Brazil well, we have successfully completed two Hosston sands flowing at 5.9 million cubic foot per day. We are currently building production facilities and pipelines to get these new wells on production as soon as possible.

Production start-up is estimated around September 1. Excuse me. These two wells have essentially shown that the Cotton Valley and Hosston sand stones to be productive on the north and south of the Castor structure. We will be drilling an additional well in this quarter. Cabot has 100% working interest in this prospect.

In the east, Cabot continues its R&D horizontal program, targeting the Devonian shale located in the Sissonville area of West Virginia. We have drilled our six horizontal wells that we had scheduled for this year. Five are now producing with the last completion over a million per day. The sixth well is waiting on a fracture stimulation. We will run a microseismic survey in a nearby vertical well bore as we frac this well to ascertain the frac [asmith] and growth characteristics in the shale. We are still improving our stimulation techniques and hope this additional information will lead to improved production rates.

One thing I will point out is our costs have come down dramatically with the sixth well drilled for about $825,000, with total well costs estimated at $1.4 million. This well reached out 3,000-foot laterally, which is the furthest lateral that we've drilled out there to date. We've also drilled the Butler number 1, Our first shale well in our new Hurricane play, west of the Sissonville project. We encountered approximately 280 feet of [Huron shell thickness] as we predicted in this vertical well. Completions will be finalized in early August. We are currently drilling our first horizontal well in the Hurricane program. Hurricane is an extension to our legacy assets in the Sissonville area. Cabot has leased approximately 130,000 acres with 100% working interest and an 87.5% net revenue interest.

Moving to our west region, we are currently drilling the McKenna 1414, which will test the gas potential in the paradox group shells as well as the Hanukkah trail sand stones and the [esne carbonates]. This wildcat, if successful, will be the first step in providing up a -- improving up a new gas trend on our 40,000-acre block. We expect TD in about two weeks. In our Moxa Arch area, we have drilled 11, 6 operated down-spaced wells this year with 100% success, as we expected, in the Dakota and some in the Frontier formations.

These wells have come online -- come online as anticipated at approximately 1 million to over 2.5 million cubic foot per day. For the remainder of the year, we will participate in at least 15, which we anticipate 10 of those being operated, additional downspace wells on the Moxa Arch.

Moving to Canada, we have made several important steps towards a confirmation of our successful grassroots entry into this deep basin in Alberta. We reported earlier on our initial success at Hinton and that we plan to drill a confirmation well to our discovery. We are happy to announce that we have finished drilling that confirmation well where Cabot has 60% interest. The well found approximately 210 feet of sandstone, all fully gas charged.

Production casing has been run and we will begin completion operations immediately. After we integrate this well into our geologic picture, we plan to drill a third well in this prospect with a spud during September. As you recall, we are still constrained by a lack of takeaway capacity out in this area. To solve that issue, we have committed to the expansion of the local pipeline system and anticipate that work to be completed about February of 2007. The expansion will add approximately 50 million cubic foot per day of takeaway capacity. Our initial well, the wildcat well on our Airway prospect located northwest of our [Musro] project has been drilled and completed. That wildcat well tested at a rate of approximately 7.6 million cubic foot per day from co-mingle to cretaceous sand stones. Cabot operates the well and has a 63% interest and approximately 50% interest in the seven surrounding sections.

A follow-up well is currently drilling and finally our initial well on the Chime acreage block is also drilling. We reported earlier that we purchased this 37,000 acre block with a junior operator and hold a 16 to 40% working interest. This block is about nine miles south of Musro area, and we think it should develop into a mult-well, multi-year low risk repeatable drilling program which would have similar results as our Musro development area.

As you can see, Cabot has significant momentum in its organic program. That's an outcome we've been working toward for several years. To continue this effort, we have 118 wells scheduled to be drilled in the third quarter and we anticipate a 95%-plus success rate on these 118 wells. With the confidence level we have in our program for the remainder of 2006, Cabot will organically be growing both reserves and production from a very large predictable portfolio at a profitable replacement cost. Once the death of Cabot's resource base is appreciated, I think you will then see enhanced value from the market for our shareholders.

With that, I'll be happy to answer any questions, Lisa.

[ OPERATOR INSTRUCTIONS ] We will pause for a moment to compile the Q&A roster. Your first question comes from the line of Robert Christensen with Buckingham Research.

Yes. you may have said this, I was interrupted. Are you drilling out in West Texas, in Culbertson County?

No, we're not at this time. We have all our rigs dedicated in other areas.

Okay.

Yep.

Thank you.

Yes.

Your next question comes from the line of Brian Singer with Goldman Sachs.

Good afternoon, thanks.

Hey, Brian.

A couple of questions on -- first on East Texas. You mentioned that some of the initial production rates you're seeing at Minden -- how much are those wells costing? And do you have any sense on what the projected EURs are and what gas price you think you need to make Minden work?

Well, they're working right now with gas prices, Brian. The completed well cost is right at $2 million. And we're not giving reserves per well right now, but they are very economic and, in fact, we think slightly better than the both production and EUR than we went into the project with.

Okay. Thanks. On -- on the Devonian shale, can you talk more about what you're looking for and what you think the ultimate potential might be?

Well, we had -- with the vast amount of acreage we have up there, our effort has been to accelerate recovery of our -- both our approved and our possible and probable reserves out there and when we started this program, we kind of went into it with the -- with the idea that if we could replace with one horse on a well, three vertical wells and with that replacement of those three vertical wells, increase the rate by four times and increase the reserve by four times and also have about a similar cost as drilling three vertical wells, we think we would -- would have made some improvements.

I can say we've drilled these -- we've drilled these six wells now, the last well we got out 3,000 feet. And each well we achieved a lower cost, not only to drill, but we're also tweaking the completion aspects of it right now. And I think we've done good on the -- on the cost side of the equation. We got up a little over a million on this last well. We're looking for a little bit higher rates than that and I think we will be able to achieve it.

It's just a matter of -- of doing all of the R&D work that's necessary when you get into these tight shales or tight sandstones and doing horizontal drilling. It's trying to find that optimum completion technique, drilling technique and combining that for go-forward efficiencies.

What's your goal on costs relative to I guess the $1.4 million you mentioned?

We'd like to get it to about $1 million. That's what we're shooting for.

Great. Thank you.

Which would be about, you know, equivalent of three vertical wells.

Great , thank you.

Yes.

Our next question comes from the line of Eric Hagen with First Albany Capital.

Hey, good afternoon. Great quarter.

Thanks, Eric.

First off, question on Canada, I saw your guidance for volumes went up there. What's driving that? Is that just better than anticipated IP rates? Or -- ?

Well, really, Eric, it's a couple of things. One, we certainly have a -- a start-up production base up there that's not that large. And we have a couple of the Musro wells being online. We have been able to flow the Hinton well consistently, though not at very high rates. We have been able to flow the Hinton well consistently.

And so -- it's not any one particular project. It's really the combination of just being able to -- to de-bottleneck a couple of areas. I will let Jeff Hutton, our VP of Marketing, discuss a -- some of the effort that we have going on up there in Canada on de-bottlenecking because I think it's a very important aspect of our go-forward program.

Okay, a couple of things. One, at Musro, we have laid a short pipeline and are able to divert some of our volumes into a different processing plant. That's been helpful in allowing some of the older wells to get back to their normal production rates. Dan mentioned we have been successful at Hinton, flowing the Hinton well at higher than anticipated rates through the summer months here.

Then a little bit lucky in the fact that some of the local demand in the area has actually increased and we've been able to flow that well at, again, higher than anticipated rates. Also, we've been the beneficiary of some de-bottlenecking by the gatherer in the area. They've actually laid some lines and added some compression and processing that we've benefited from. So, a little bit here and a little bit there. It's kind of all added up for us.

Thank you, Jeff.

Thank you very much. Moving to the east -- in the shale play there, is there any difference in the shales between the Sissonville and the Huron? I think it was a pretty thick section you mentioned, Dan, in the Huron.

Yes, it is a fairly thick section, but we have -- we have a similar thickness, also, over in the Sissonville area, also, Eric. Some of the additional things we're looking at in the Sissonville area right now, also, is the Marcellus and Ryan Street portion of the Devonian.

Adding those in then?

Adding those in, it's going to be even thicker than the 280-foot. But we have not -- we have not yet drilled a horizontal well in either of those sections.

Okay. And the final question is in the Moxa arch. You mentioned you have up to 700 additional locations. Did you put out an estimate of reserve upside, if that works? Or what are EURs right now on those wells?

I will let Mike cover that a little bit. But before I turn it over to him, we don't have any of these booked as spuds right now. So, all the majority -- if not all the drilling right now, is new bookings. And the qualifier that I think Michael will add to it is -- is some of our wells, we are going to -- deep into the Dakota and if we get upside on the Dakota, that could be -- that could be a big plus, but the Frontier is -- is the bread and butter for this play and I will let Mike answer the rest of your question, Eric.

Hey, Eric. And 700 locations, the typical frontier well up there is going to do about 800 to -- 800 million to 1.2BCF per well. And on the Dakota increment, probably we're being conservative here, I know, but anywhere from 200 to 300 million per well in incremental that we'd be looking at for the Dakota. I think the upside on the Dakota is that we stand a chance of -- of running into one of these really sweet sands that could get you some significant reserve potential down -- down there.

So you're talking about 1 to 1.5 Bs across 700 locations?

Yeah, yeah. That would be -- that would be a ballpark number.

Okay. Great. Thank you.

Thanks.

Your next question comes from the line of Ellen Hannan with Bear Stearns.

Yeah, hi. This is Kevin Klare. Ellen had to step off for just a minute. In East Texas, for your Cotton Valley wells, what about is the cost per well on those? And what cost efficiencies do you guys see going forward?

Yeah, Kevin. In our East Texas wells, it's approximately $2 million, completed.

Okay. And do you see additional -- did you mention you're going to see additional cost efficiencies going forward? Or is that kind of where you expect things to be, about the $2 million per well range?

We expect to see some cost efficiencies going forward. When you're drilling on 40-acre spacing, once you -- and these wells have kind of been spread out. We skipped a lot of locations to just look at the consistency of the geology out there.

But once you start drilling these wells and back filling some locations, there's things that we've been doing on the wells to gather information today that we don't necessarily have to run every sweet log we've been running on future logs as we feel like we're going to understand it fairly well. So, that along with just the efficiencies of logistics, we -- we feel like we're going to be able to do a little bit better.

Okay, great. Thanks.

Your next question comes from the line of Larry Busnardo with Petrie Parkman.

Good afternoon. In the Castor Prospect, can you talk about the activity levels for the second half of the year and what to expect there?

Well, we're -- right now the good news is we have more areas to put rigs than we have rigs, even though we have four rigs coming out. Two -- as I mentioned, two in August, one in October and one in December. I'll answer it this way because we have a couple of ideas that we're working on that if successful, they would take a couple of our drilling rigs to be able to, in essence, take advantage of the opportunity. So, I will hedge my answer a little built in that capacity.

But right now we're going to be drilling the well we have in the third quarter and depending upon these other opportunities that I'm mentioning, I think it's going to dictate about how many more wells in Castor we can drill between now and the end of the year because we have a -- we want to do what we're doing in Minden and that is to consolidate our operations to help add the efficiencies to our operations. So, instead of moving rigs around a bunch, if we get into an area, we're going to concentrate very heavily with all our efforts and service equipment in that area. So, I know it's a little bit of a long-winded answer, but it's really these other opportunities that -- that have us a little bit uncertain on exactly where we want to put the rigs.

Okay, so, at least you drill one more well there, then decide what to do with the rig?

Absolutely.

Okay. In terms of the two wells that have been drilled there, Hosston and Cotton Valley in the one and just the Hosston in the other, what do you think you're going to be able to find on the next well? I mean -- does the Cotton Valley look -- does it look good in the next location? Or is it a matter of getting down, drilling it and then seeing what you have?

Well, what we wanted to do with the next well area is -- the well to the north only completed in the Cotton Valley. And we are going to drill this next well, offsetting the well to the north, which is the Brazil, to drill the Hosston sands and effect the completion of the Hosston sands so we can get a better idea about our production facilities and how we lay pipelines and what not.

Okay. And then shifting over to Hurricane. You've got one well down, you're drilling your first horizontal. What's the plan going to be after that? Do you determine the way to go vertical to horizontal? Or do you have a plan in place for the second half of the year there, in terms of how many more of each that you would drill?

Yes, Larry, this is Mike. We're going to be drilling this first horizontal well. We're going to be waiting on the information from that microseismic survey that we're going to run over in Sissonville. And then apply the information from that effort over to Hurricane to determine the type of fracs that we need to run on this -- on the Hurricane horizontal. So, I think it is still a little bit too early to say, if we're going to go out there with multiple rigs for a lot of horizontal wells at Hurricane.

Okay, thanks.

[ OPERATOR INSTRUCTIONS ] Your next question comes from the line of John Herrlin with Merrill Lynch.

Yes, hi. Production-wise in June you said you'd be nominally above the top end of the range. It ended up being about 4%. You've attributed the volume growth to your exploitation projects. I'm just wondering, Dan, if you can give us a sense of how much Minden contributed? Also Red Fish Bay, you had a good recompletion, how much was there? Because it looks to me like the bulk of your production games, at least sequentially, was really Gulf Coast. I wondered if you could give us a sense of the breakdown of the contribution in the quarter since you're tying in so many wells?

Yes. I would -- I'd kind of divide it up where the -- the areas like Minden probably contributed two-thirds of the -- of volumes and our offshore -- our coastal stuff, I will call it, coastal properties contributed about one-third.

Okay. And then with the Castor Prospects, somebody already asked, you didn't have a lot of pay there. So, what do you think the ultimate recoverable is there?

Well, we only gave, I think -- well, we would -- what -- what did we give? Yes, the previous report, I can we gave 14 foot of pay in the Hosston.

That's right.

And -- and we feel -- there's a well to our -- to our east that had some Hosston pay in it. And we think between the Hosston and Cotton Valley that -- that we can have substantial reserves, if that's your question.

More or less. Last one for me is for Scott. Looks like your DD&A rate went down a little bit? Is this kind of a good rate going forward?

Yes, it is, John.

Thanks.

Thank you.

Your next question comes from the line of Monroe Helm with CM Energy Partners.

Congratulations on an excellent quarter. Most of my questions have been answered, but I'm not quite sure on the answer you gave John Herrlin about -- I know it's early on, did you have some predrill reserve estimates for these Hosston Cotton Valley formations in the Castor Prospect?

Well, we're on the -- on the Cotton Valley there, we've just now -- we were flowing a little bit, then made some estimates. And then I think next report we'd be able to give Monroe and give a little bit -- quantify that a little bit better. We think the Hosston could be 1 to 2 Bcf per well.

Okay. Just as a follow-up, can you tell us what are the most important wells, we should keep our eyes on, at least in the North Louisiana, East Texas place, between now and the end of the year that you will be drilling?

I tell you what. Our -- our program is narrowing down so rapidly on specific areas as opposed to specific wells --

Okay.

I would say this, though, that continue looking for our progress reports on Minden. That's going to be a -- a good area for us. And -- and seeing the consistency there, I think is going to be important. Looking at Castor, the next well in Castor, even though it's going to be an offset, I think we're going to be looking at those five Hosston sands we saw up there as opposed to the two in the well we completed and that might be of interest. I know Mike has some 3D that he's been looking at. I don't think in the third quarter we have a well scheduled for -- for Clear Branch yet. But we probably will by year-end. We have a 3D going there that is telling us some things that we had not assumed correctly or interpreted correctly on the 2D, in that particular area.

We have the Hinton third well in the Hinton and the completion in the Hinton. In Canada. Which I think is going to be important. We have the offset in the narrow way field up there. I think is going to be important. We're drilling now and we have even taken cores at this stage in the McKenna well, in the Paradox. That is on a 40,000-acre block for us.

And we have drilled a well in -- that we're evaluating and we would like to see a horizontal well drilled in the County Line prospect, which we're not even talking about in this particular conference call because we're just integrating the data. We also have a development well or exploitation well is more appropriate, in the McCampbell area, down in the Red Fish Bay Area that I think could be an important area for us, also.

And you're going to have four rigs delivered by the end of the year. Do you think you will have the rig fleet that you need to execute your 2007 program or is it too early to know? Or is that really dependent on the exploration success you have between now and the end of the year?

As far as being able to keep the number of rigs we have right now, busy for 2007, we do not require any additional exploration success to be able to put together our 2007 program. As far as the commitments on our rigs, Monroe for the 2007 program, we're confident that -- that we're going to be able to execute it with the -- with the rigs that we have.

Okay, thank you very much.

Thank you.

Your next question comes from the line of John Herrlin with Merrill Lynch.

Yes, one last one for me as a follow-up.

Hi, John.

The shares that you repurchased during the quarter, but your shares outstanding sequentially is basically flat. Given the fact that you have much more visibility than I can recall for the Company, have you considered at all perhaps stepping up a little bit more aggressively with the share buyback?

Yes, we have. We have, indeed, considered that. We have a board meeting this week and that topic usually is a topic at our board meeting.

Okay. Thanks.

Yes.

At this time, sir, there are no further questions.

Okay. I appreciate everybody's interest in Cabot. I think you can see we've had a very good quarter. We think with the drilling we have out in front of us and the predictive nature of our program out in the third quarter, we think we're going to be able to post equally as good of results. Appreciate y'all's interest.

This concludes today's conference. You may now disconnect.