Coterra Energy Inc (CTRA) 2006 Q1 法說會逐字稿

Good afternoon, my name is Tammy and I will be your conference operator today. At this time I would like to welcome everyone to be Cabot Oil & Gas first-quarter earnings teleconference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (OPERATOR INSTRUCTIONS) Thank you. Mr. Dinges, you may begin your conference.

Thank you, Tammy. Good afternoon and thank you for joining us for this 2006 first-quarter earnings teleconference call. With me today are several members of our management team Mike Walen, our Chief Operating Officer; Scott Schroeder, our CFO; Jeff Hutton, our VP of Marketing; Chuck Smyth, our VP controller.

Before we start I need to read the following. Statements regarding future financial performance and results and the other statements which are not historical facts made during this teleconference are forward-looking statements that involve risks and uncertainties including but not limited to market factors, market price of natural gas and oil, results of future drilling and marketing activities, future production and cost and other factors detailed in the Company's Securities and Exchange Commission filings. All non-GAAP financial measures discussed during this conference call have been posted to our website at www.cabotog.com along with a reconciliation to the most directly comparable GAAP financial measure.

It continues to be an exciting time in our space as evidenced by recent press releases, there remains a great deal of opportunity in the E&P industry and Cabot is no exception. Our record first-quarter profits were driven by higher realized prices, increased production and a strong drilling success rate of 97%. This afternoon's press release reported net income of $53.2 million versus last year's first-quarter figure of $20.8 million, a 156% increase.

Cabot's first-quarter results coupled with the best ever fourth-quarter net income numbers established a record six month in the Company's history. In addition, the Company reported robust metrics including cash from operations of $155 million and discretionary cash flow of $117.9 million.

While commodity prices for natural gas softened somewhat from their highs late last year, they remained relatively high to history and relatively high to Cabot's realized prices last year. Oil prices also remain strong on a continued worldwide uncertainty.

The key for Cabot in this year's first-quarter pricing realization was no adverse impact as a result of our hedging activity. Actually our natural gas realized price in the quarter increased by $0.08 per Mcf due to our hedges. With our wide collar hedge philosophy, Cabot has protected the downside on about 33% of its daily production for the remainder of 2006.

On seeing continued strength in the 2007 strip, we have commenced layering on wide collars for 2007. To date we have 30,000 MMBtu of gas per day hedged at an average floor for 2007, an average floor of $8.50 and an average cap of $12.72. Plus we've hedged an additional 1000 barrels per day at a floor of $60 and a cap of $80. Our hedge details can be found on our website.

First-quarter production increased over first quarter in 2005 by 1%. Although it it's not a large increase we are on track as projected and remain comfortable with our future projections partly as a result of our first-quarter drilling success. Our production increases came from the East and Canadian regions. This production profile is within our guidance for the quarter and we remain committed to our guidance for the remainder of the year which has our production increasing each subsequent quarter.

Operating expenses have increased over last year's first quarter due primarily to higher expenses in nearly all categories. Our lone decrease was expiration expense which was down nearly $8 million primarily due to lower dry hole costs. This is a direct result of the change in character of our program that has more predictability and the drilling success we had in the first quarter.

In terms of drilling as mentioned, Cabot is off to a strong start this year as we have already drilled 21 gross wells of a -- excuse me -- 71 gross wells of our forecasted 370 well program. And we've had a 97% success rate so far. We currently have 21 active drilling rigs working with six of those outside operated. We are also completing 22 wells.

Now I'd like to review some of the highlights our drilling has provided so far this year and I will touch on our Minden area, Castor area and McCampbell areas in the Gulf Coast; our horizontal drilling effort in the East; the Paradox Basin shale play in the West; and our Hinton discovery in Canada. In the Minden Prospect area in East Texas the program is progressing very well. We have drilled and completed four Cotton Valley producers each flowing at a rate between 1.8 and 3.3 million per day. We are currently completing three additional wells and have one rig drilling. We will have another rig in the field in June. We control approximately 7800 acres in this prospect area with 100% working interest. The Company will drill 15 to 17 more wells this year at Minden and it's looking like Minden will be an active area for us for many years.

We reported in the last conference call that the initial wildcat on our Castor prospect in North Louisiana was drilling, the Weyhaeuser 24-1 reached a total depth of 14,500 and is currently being completed in the Cotton Valley and [Hoston] Sandstone. Our initial fracture simulation in the Cotton Valley had an IP of approximately 400,000 per day. While this rate is disappointing, it does give us confidence that the structure is gas charged. Our engineering group is currently developing a fracture simulation plan for an up hole Hoston zone and it will be fraced as soon as we're able to obtain all the equipment which we anticipate will be an approximately two weeks.

Because of the information we've seen in this well and the data to date, we chose to drill our second will approximately four miles to the Northeast still on the Castor structure. This well, the Brazil 4-1, is currently drilling at 11,200 feet going to a total depth of 14,500 feet. To date we have encountered log pay in the Hoston Sandstone section in this well. Cabot controls approximately 9200 acres with 100% working interest on the Castor structure.

Down toward South Texas in our McCampbell Field, we've enjoyed a particular success in this area with our development program. The field is located in our Aransis County in South Texas. We recently completed our Grant 10A well flowing approximately 6.9 million cubic foot of gas per day plus 370 barrels of oil per day at 5650 pounds flow tubing. In all of this field we have approximately 92.5% working interest. This follows -- the 10A completion follows the 7A completed at 6.9 million a and 136 barrels per day of oil. The Grant 4A recompletion is flowing 7.2 million per day plus 160 barrels of oil. Cabot's original interest in this field as you might recall was 33%. We increased it to 92% through several accretive acquisitions growing our net production from 2.5 million per day to 21.9 million cubic foot per day.

We recognize 21 additional locations plus multiple recompletions remaining on this property. Our 2006 program includes six wells plus 12 recompletions.

Moving to our East region, Cabot continues its R&D effort on our horizontal drilling program in the [Heron] shale located in our Sissonville area of West Virginia. So far this year we have drilled four horizontal shale wells in the area. The horizontal leg have been between 1400 and 2100 feet long. We have utilized up to four stage frac stimulation in each well bore with initial flow rates of 570,000 cubic foot to almost one million cubic foot per day.

We're still improving our drilling and stimulation techniques and also our directional orientation of our drilling. We expect we will experience reduction in cost and increase gas flow in subsequent operations. After we paid for our education on our first several horizontal wells the latest one was drilled and completed close to our original expectation of $1.3 million. We have one rig operating in our horizontal program at this time and we plan to drill a total of 9 horizontal wells in the area this year which is up from six budgeted at the beginning of the year.

One of our new lease initiative I have referred to in the past is our Hurricane prospect. It's an extension of our Sissonville Heron shale play where we're currently drilling our horizontal wells. Cabot has leased 125,000 acres, 100% working interest, in this new extension area. This activity represents a portion of the 600,000 acres we're leasing around the company. We're currently permitting our initial well on this new area which we will plan to drill this summer. At this time, our plan is to drill a horizontal well in the Heron shale section and extending the well to 3000 feet -- 2000 to 3000 feet I should say.

In our West region we also a have put together a new lease initiative to exploit the Paradox shale in the Paradox Basin. At this time we have leased approximately 40,000 acres over what we believe is a gas bearing shale section. We plan to drill our first well in this prospect with a spud scheduled during the summer months.

Finally I'd like to update you on the progress of our Hinton well in Canada. We reported this whale earlier and at the time we're waiting on pipeline hook up. Since that time we began flowing the well at approximately 9 million a day and that was a restricted rate. We have since then restricted now down to approximately 6 million cubic foot per day because of weather conditions. We are in the area -- in the area, we are in agreement with a pipeline company for 35 million cubic foot per day of firm transportation which will be available around the first of the year following an upgrade to their system. We believe the Hinton well and from all indications we've seen so far with the current production at the Hinton well will be capable of producing at rates up to 25 million cubic foot per day once this upgrade to the system is complete.

Meanwhile we have permitted two additional wells and expect to start building locations this month with a late May to early June spud of our next well. Because of our drilling success, the partner activity, the leasing activity that we have currently ongoing, we are increasing our capital program for 2006 from $396 million to $435 million. This increase is occurring across all regions with 87% of the increase occurring in the drilling and lease acquisition area.

In the second quarter we have 126 wells scheduled to be drilled in the second quarter and we are also actively leasing on several complementary acreage plays so we look for more upside news out of Cabot as the year progresses.

Tammy, with that I'd be happy to turn over the call to any questions.

(OPERATOR INSTRUCTIONS) Brian Singer.

Thanks, good afternoon. With the rest of your CapEx increase, can you talk a little bit more about that? It didn't look like though maybe I was looking at the wrong version like your production guidance had changed. Is this capital spending going into more exploratory activities that have longer lead times or should -- or is a more service cost inflation driving up the capital spending increase?

Well, I will let Mike follow on Brian with what I say but certainly cost inflation we're seeing it across the board. A common theme with the entire space. But we also have allocated additional sums to our lease acquisition program where we're continuing to find opportunities to enhance our future position.

Brian, in addition to those items, we're also experiencing a lot of our partners are drilling a lot more wells and extending their program. So we are being hit with a lot of outside operated ASP's right now.

In regard to our guidance, we all are -- we're comfortable where our guidance is and will refresh that at the next conference call.

Great. And if we look at just some of the areas from a production perspective, Appalachia looked like it was relatively strong. Was there anything there that is kind of recurring? And the Rockies looked a little bit weak, anything there?

In looking at the Rockies, that particular area was off approximately 3%. Some of that is result of some timing and some shut-in issues we had in our [Wamsutter] area. Jeff, do you want to mention any of the -- some of the things that we've seen up there whether it be impression or maintenance operations or things that have affected us?

Yes, Brian, we've had several instances where gathering companies, processing plants have gone down for out of service for several days causing pressure buildup in the fields and hopefully these were onetime events that happened through the winter. But we had some freezing up there also in Wyoming. But hopefully all those problems have been ironed out.

Great, thank you.

I might add on, Brian, we do look for activity in our production profile for the second, third and fourth quarters compared to prior quarters, similar quarters in 2005 to be up anywhere between 7% and 14%.

Great, thank you.

Eric Hagen.

Good afternoon, gentlemen. First question is on the Herring shale in West Virginia. How much acreage do you have perspective for that play? And could you maybe refresh me as to the metrics, I mean spacing and EURs, have you talked about that in the past? I can't recall.

Eric, this is Mike, I would guess -- I would estimate that for the shale play of our 1.1 million acres up there probably 300 to 400,000 acres has shale potential. And if you're looking at a typical shale well for EUR potential, I'd say between 350 and 450 million per well. And of course our concept on drilling the horizontal well is to get us multiples of those reserves as well as the production rates.

Okay, so you'd be talking about something closer to 1.2 bs for the 1.3 million? Is that kind of the metric you are aiming for with the horizontals?

That is correct.

Okay. End in the Paradox shale, what got you excited about this? Is there any well control around you? Did you do some coring work? And what are some of the metrics, if it's not too early stage, in that play?

I'm going to let Mike follow up with this also, Eric. But we have, certainly we had some information out there and we put together a fairly large and contiguous acreage position out there. And there has been some recent area activity that has been encouraging. And I will let Mike pick up from there.

Yes, Eric. We have obviously gathered any information we could. We actually gathered some coring information and some geochemical information that all lead us to believe that this is a gas bearing sand. But more importantly we actually have found wells and participated in a couple of wells earlier that completed in the shale that had attractive rates of production coming out of the shale. And we haven't really talked about this much but we've decided our position now is to tier, so we think that it's a very attractive opportunity for us right now.

Okay then the final question is on the Hinton project in Canada. Did you mention how many additional prospects you have there? And also what is your working interest in that project?

We have a 75% working interest in the Hinton discovery. And we have a 60% working interest on the -- how many total sections do we have -- on 12 contiguous sections around this discovery.

Will this be spaced on is it four wells per section or I mean what is kind of the --? One per section now is that --?

Right now it's early in the game. It is sparse control out there and our plan right now is to drill our next well in the offset section is our plan right now. And we're going to make a determination once we see a little bit more longevity on our production profile and see what we might be able to do with that.

So 25 million a day, it's capable of producing that? What is an EUR in typical well then up there?

Well, we think right now that we're probably at least 10 bs.

10 bs. So you're looking at maybe 60% and 120 bs or 60 bs up there with what you've got right now kind of conservatively?

We have our fingers crossed that the discovery will be confirmed with an offset and we will be able to continue drilling up there. We are optimistic about it, Eric.

Okay, great. Thanks.

[David Adam].

Hey guys. Actually all of my question have been asked and answered, thank you.

Ellen Hannan.

Good afternoon. Just a couple of follow-on questions. One, if you gave this I apologize. What are you looking for in terms of spacing in your Heron shale? You talked about EURs per well and cost but any idea for that?

Ellen, right now we are looking at a 40 acre spacing on the vertical wells. We think that that would work. And on the horizontal wells, obviously if we drill at 2000 to 3000 lateral that would have to be multiplied by three or four or five times.

Okay. And then switching over to the Minden area in East Texas. Could you give us what you're seeing terms of cost per well and your anticipated EURs? And also are you drilling on 40 acre spacing?

We are drilling on 40 acre spacing. Our costs right now are running about 1.8 to $1.9 million drilling complete. And our EURs are in the 1.5 plus EUR Bcfe.

Is that gross?

That would be gross, yes. And these our 100% Cabot wells.

Okay. Thanks very much.

[Donald Texter].

Dan, I think you mentioned an exit rate in the first quarter of about 255 million a day?

Yes.

And you said that you thought production by quarter would continue to move up, I think you said that on the call?

Right.

I was wondering where do you hope to be by the end of the year?

We'll be between 257 to 274 million a day is where we would hope to be in the fourth quarter, Don.

Okay. And the other question I had on the Sissonville, the last well you drilled I guess you said you drilled four wells?

Yes.

Do you know what the numbers were in terms of reserves or do you have your best shot on sort of reserves, flowrate and well cost on that? Was that the one that was 1.3 million a day, $1.3 million?

Yes, and it's too early on that one to -- we don't have all the information yet on that one, Don. We're waiting to get the information on that one.

Don, we have to use rate time analysis to come up with the reserve number. And we just don't have enough history yet on that well.

Okay. So maybe ninety days next quarter conference call you might have better -- some numbers maybe?

We hope so, yes.

Okay, good. Well thanks, Dan.

Phillips Johnston.

Hey, guys, thanks. Can you give us an update on the Musreau project?

Musreau?

Yes.

Well, I'll turn it over to Mike instead of me.

We have, we drilled, participated in two additional wells this year and both of them were successful in the general area. They had been completed and they are waiting on pipeline for hookup. We're in the middle of break up right now so we're all shut down. We have potential for a couple more wells to be drilled out there this year during the drilling season. We're also laying a jumper line to help alleviate some of the bottlenecks that we're seeing in the Musreau gas plant to increase our rates. And we've also are on the verge of getting the approval to down space the field which is our long-term plan is to drill those sections we have at about 160 acre spacing.

Okay. And just to follow up on Eric's question about the Paradox Shale play. Did you say if you partnered with anyone there?

We do have -- we did sell down a piece of that prospect to a third party.

And what is your average working interest now?

75%.

Okay. And have you secured a rig yet for the well that you plan to drill this summer?

Yes.

Okay, great. Thank you.

Jack Aydin.

Hi guys. Coming back to the Paradox shale play, could you give us a little bit more information about the well control, who drills that well and what kind of rates they had testing if anything if you could share with us?

The well was drilled last year drill by Encana and we were a partner. The well was tested in the Paradox shale at a rate of about 1 million a day from a vertical well bore. And we are looking -- there's four different Paradox shale interbedded with limestone and all appear to be source rock. All appear to be gas bearing.

How much did that well cost? Do you have an idea? I'm sure you do have an idea.

Well these are about 10,000 foot wells, a little over 10,000 foot wells and we're looking at drilling complete about $3 million I believe it is.

And so your acreage is you said 40,000 acres, net acres or gross acres?

That would be gross acres.

Okay. And the next question, how, you were talking about adding about close to 600,000 resource play acreage. Could you update us on that where you stand on that total right now?

We have approximately 500,000 acres that we've accumulated and we've certainly authorize more money in this capital expansion for additional acreage also. But in regard to that specifically, Jack, we're 500 plus.

Could you break it down to the areas? I'm asking -- pushing my luck now.

We have some in the East and we have some in the West and probably a greater percentage in the Gulf Coast area.

Thank you.

Jack, I would like to just add something about the Paradox. As you all know, we have about 330,000 acres in the Paradox. And although it doesn't all fall within the shale play, and what we're talking about on this one project, but probably 30% or 40% of that acreage probably has shale potential on it.

What you're telling me that 40,000 gross acres are part of that 350,000 acres?

Yes it is.

Okay.

But it was new acreage.

But it was new acreage, a new initiative that we picked up.

Okay.

Our original position, Jack, out there was through the Burlington deal we made which was 332,000 acres. And we have -- Mike is looking at me here -- it might be 300,000 acres and we have subsequently acquired recently the 40,000 acres.

Okay. Then on the earnings I don't know if I missed it because I was on a conference call, other conference. The incentive compensation that you included in the quarter is that how you consider is occurring or non-recurring item, everybody treats it differently?

Jack?

Yes, Scott I think you I know you are going to answer it.

In our guidance on the last page we give you guidance that kind of says there's going to be kind of 2.7 to $3.0 million of expense related to stock, is what we're guessing at right now going forward. We have been carving out stock comp in our guidance and in our press releases for a couple of years now since we moved to performance shares. Part of what's in this in that below the line cumulative effect is the FAS 123 adoption where we're not quite sure how that is all going to shake out moving forward in terms of the volatility. We're going to have to do some actuarial work each quarter to value options to get a number to expense. So right now all we can tell you is I'd go with the 2.7 to $3.0 million for the guidance.

Per quarter?

Per quarter.

Okay. Thank you.

Thank you, Jack.

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

With that, I appreciate everybody on a Thursday afternoon that is sitting in and I look forward to our next visit. Thank you.

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