Coterra Energy Inc (CTRA) 2006 Q3 法說會逐字稿

Good afternoon. My name is Michelle, and I will be your conference operator today.. At this time I would like to welcome everyone to the Cabot Oil & Gas third quarter 2006 conference call. [OPERATOR INSTRUCTIONS] At this time I would like to turn the call over to Mr. Dinges, Chairman, President, and CEO. Please go ahead, sir.

Thank you, Michelle. Good afternoon, and thank you for joining us for the 2006 third quarter conference call. With me today, I have several members of our team. I have Mike Walen, our Chief Operating Officer. I have Scott Schroeder, our CFO. I have Jeff Hutton, our VP of Marketing, and Chuck Smyth, our VP controller. The standard boilerplate forward-looking statement comments included in the earnings press release applies to my comments today. Getting to the press release, earlier today Cabot announced another successful quarter that included new highs for third quarter earnings and cash flow levels. Removing the significant financial benefit from the results for the asset sale, the quarter ending September 30th, 2006, had net income of 45.3 million, cash flow from operations of 86.7 million, and discretionary cash flow of 122.9 million, in quarterly production of 23 Bcfe. Equivalent production was up 12% versus last year's third quarter, with each region once again contributing to this performance. The regional breakdown of equivalent increases in production included the East up 8%, the West up 3%, Gulf Coast up 17%, and Canada up 26%. Now we have confidence that year-over-year, we will show absolute production growth between 2005 and 2006. When you adjust for the sale in both 2005 and 2006, the pro forma growth is expected to be between 15 to 18%. One additional note regarding production, removing the properties recently sold, in both quarters, third quarters, yields a growth rate of 14%. The highlights, this highlights the expected growth rate from our core assets and also illustrates the significant decline that our divested properties had illustrated. The 110 wells drilled during the quarter with the continued high success led to our production increases for the year Cabot has drilled -- excuse me, 301 wells at a 97% success level. Pricing was less of a factor for the improved financial results. However, oil prices played a role as they remained strong and continued worldwide uncertainty. Natural gas prices were flat year-over-year on the strength of a strong in the money hedge position we had. Actually, our natural gas realized price in the quarter increased by $0.41 per Mcf due to our hedges while our oil hedges during the same period remained within the collared range. With a wide-collared philosophy, Cabot has protection to the downside of about 36% of our anticipated daily production for the remainder of 2006. During the third quarter, we had continued -- we continued to layer on wide collars for 2007. To date, we now have 105,000 Mmbtu of gas per day hedged at a weighted averaged floor of $8.12 per Mmbtu, an average cap of $11.12 per Mmbtu, plus we have 1,000 barrels per day hedged at $60 floor and an $80 cap. This brings our total hedge position for 2007 to approximately 42 to 45% of our anticipated volumes. We have not layered any hedged volumes for 2008 at this time. A detailed listing of our hedges can be found on our website. In response to the market weakness, as prices moved lower, Cabot repurchased 422,200 shares of our common stock at just over $45.69 per share. This leaves a remaining authorization of 397,650 shares. Today, with the confidence in our program, the board of directors authorized an additional 2 million shares for repurchase in the open mark. We will continue to be opportunistic when we move into the market for buyback. Operating expenses have increased over last year's third quarter in total, due primarily to higher expenses from inflationary industry pressures. Again, we remain diligent in trying to control our costs. It is my expectation we will not see service cost increases in 2007 that we experienced over the last 18 months. In terms of our balance sheet, our third quarter net debt to adjusted total cap declined to single digits the proceeds from the recent asset sale and the gain from the sale. Due to the timing of the sale which was on the last day of the quarter, Cabot did not have sufficient time that day to close -- to repay debt, which created a large cash position at quarter end. Subsequent to the quarter end, Cabot did repay its revolving credit facility. That included dollars for the recent stock buyback, and in December, we will pay $101 million of the tax bill for the sale. Once these transactions are complete, we expect our capitalization to settle around 20%, which will be the lowest in our history.

Let me move to operations update now. We currently have 18 rigs drilling. 15 of those operated throughout the company, and we have 28 completions and/or pipeline hookups currently underway, which puts us on track to execute our 2006 program. We have taken delivery of three of our four new builds, with the other rig coming between now and the end of the year. These rigs will be working in our Gulf Coast region for the remainder 2006 and all of 2007.

Our drilling program continues to be the catalyst for our growth, and as today's press release highlights, we have some significant news in several of our operating regions. Let me start first with the North. In the North with our Canadian region, in Canada we have recently completed a confirmation well at our Hinton prospect and established commercial rates on that confirmation well. We have also moved a rig in and commenced the drilling of our third well on this prospect. We're excited about the area and have a significant land position to continue the field delineation. As we have mentioned, we are waiting on pipeline expansion to enhance our deliverability. This prospect will see additional drilling in 2007.

In our other areas in Canada, we have completed and commenced production on our discovery well which we have 63% of in Narraway, and we have also recently completed and tested at commercial rates our confirmation well which we have a 47% working interest at the Narraway prospect. We are in the process of hooking up this confirmation well. We will drill additional wells also in the Narraway area in 2007. Musreau prospect area, which we have a 100% working interest before payout and 75% interest after payout, we have made our initial discovery on that prospect, and we're moving towards our development plans. In our chime area, we have an average working interest across a number of blocks. We are currently drilling our second well on the 37,000-acre position that we acquired earlier this year. Again, each of these last two areas will also see drilling in 2007. Moving South to the Rockies, clearly the key topic in the Rockies was the fall in pricing in the sub-$3 realization during October for the unhedged gas. At press release, as our press release indicated, Cabot, along with its partners, shut in some production, and therefore, our October volumes will be down by about 6 million cubic foot equivalent per day. This production, along with several new wells will be turned back on line and begin producing November 1st, so as to capture, this increase price we have recently realized. Operationally, the Moxa down spacing program has yielded 100% success as expected in 21 wells drilled, with a significant standout success at the Cabot-operated Ballerina well where we have 67% working interest. This well was completed flowing 7.4 million cubic foot equivalent per day at 3,050 pounds flow tubing pressure from the Dakota. This well illustrates the upside remaining on our Moxa acreage position and supports our plan to drill as many wells to test the Dakota as possible. As you can easily discern, a well of this caliber supports the $70,000 incremental cost to drill below the frontier to evaluate the Dakota formation. Needless to say, our 80-acre in-field program on the Moxa targeting Frontier and Dakota continues to meet or exceed our expectations. As we mentioned in our press release, the McKenna well drilled in San Juan County, Utah, that wildcat tested four Paradox shales without being able to establish commercial gas rates. We will further evaluate the results for any future opportunity. We've also spud in the Paradox Basin the Nelson Creek well in San Miguel County, Colorado. We have 50% of that well is currently drilling below 8,100 feet, has projected Td of 10,700 feet. This is an exploratory well with the primary objective being sands and paradox formations. For 2007, across the west region we have five exploration wells scheduled.

In the Gulf Coast, we currently have five rigs drilling with emphasis at the Minden field in east Texas, McCampbell and Raymondville field in South Texas. At Minden, we have increased our production to about 18 million cubic foot per day from 13 wells, with 8 more to be turned online during the fourth quarter. We have three rigs drilling in the area and plan to keep two to three rigs busy throughout 2007, which will translate into approximately 18 to 20 wells. In South Texas, we have two rigs operating for the remainder of the year. This builds on our earlier success where we had completed three wells with flow rates up to 8 million cubic foot per day. At this point, we have increased our McCampbell production to 19 million cubic foot per day and forecast an exit rate at the end of 2006 of 22 million per day from the field. We will also drill some additional wells in the McCampbell field in 2007.

In the East, Cabot continues its R&D Horizontal program targeting the Devonian shale located in our Sissonville area of West Virginia. We have drilled our 8th horizontal well, with the most recent test at 2 million cubic foot per day. We have been successful in driving down our costs to less than $1 million to drill and complete. And we will continue our horizontal program into 2007 with 12 wells scheduled, and do anticipate more success as we continue to learn from this horizontal effort.

When we updated our 2006 guidance today, we also initiated guidance for 2007. In 2007, we are planning a capital program of about $435 million for the year, with 75% of that total going towards drilling. For this investment, we will drill 440 wells, with the majority occurring in the East. The specific breakdown is 270 wells in the East, 108 wells in the West, 51 wells in the Gulf Coast, and 11 in Canada. This will be the first time in nearly a decade the Gulf Coast has not received our largest portion of funding, which is going to the East, which again further highlights the reduced risk in our growth program. From this program, we expect double-digit full-year production growth versus our revised base after removing production associated with south Louisiana and offshore asset sales. The production growth off this base is approximately 12 to 18%, which is what we placed in our guidance. We also anticipate significant reserve growth and a flattening in per-unit expenses. Additionally, we anticipate adding the substantial reserve position at a sub-$2 finding cost level for 2007. With the strong story Cabot has to tell, we will be on the street more this coming year and look forward to receiving the value our program has to offer. With those comments, Michelle, I'll turn it back over to you to see if there's any questions.

[OPERATOR INSTRUCTIONS] And your first question comes from Ellen Hannan.

Couple of questions.

Yeah, Ellen.

In terms of one, in the Minden area. Have you made any plans to spud a horizontal well?

We have not finalized the plan design, but that evaluation is in the works, Ellen.

You think this is something you'd be looking to do in early 2007, or --

We are looking at that.

Also, in the Minden area, have you experienced any need to install additional compression after hooking up any wells?

No, we have not yet. We have been favorably impressed with the rates and how well they're maintaining their levels.

Offhand, what's your acreage position there?

We have continued to expand. We initially started when we first started talking about Minden, we had 3,000 to 4,000 acres. We have accumulated an acreage position now in the Minden area of over 10,000 acres.

And are you still -- are you working on 40-acre spacing in terms of the vertical wells?

We haven't seen anything that has deterred us from drilling up this field on 40 acres.

And one other unrelated question. The budget number that you talk about for 2007, if I heard correctly, 435 million, 75% of which goes to your drilling and, if that's correct, and does that include your planned exploration spending?

Yes. We have about -- about $7 million in our dry hole program right now for the 2007 program.

Great. Thank you very much.

Your next question comes from Brian Singer.

Good afternoon.

Hey, Brian.

Question on Hinton. How do you think about the future potential from this field in terms of the expansion capacity that you're getting on the pipeline side of 25 million a day, relative to what's in your guidance for Canada for next year, 4th quarter, at about 15 million a day? What are the long-term plans for Hinton, its potential, and maybe talk about your thoughts on expanding in Canada?

Well, we have a little bit lower projects in our Canada forecast. We would like to see the field to drill out. The two wells we have drilled, Brian, are successful. We have not reached the maximum capacity in our discovery well. We have not been able to produce it yet because of the restrictions at maximum rates, so we're not sure exactly where that well might take us. And maybe we are a little bit conservative in our Canadian forecast, but we would like to see this third well down also to get a better handle on the field dimensions.

And maybe you mentioned this earlier, but will Hinton be the sole focus as you look to the Canadian program in 2007? Are you looking on the exploration front on other areas?

We have been successful in 2006 in the areas that I mentioned. We'll continue drilling in Musreau. We have the Narraway area. We have this [inaudible], which is a new area, we've had a recent discovery. We have Hinton. We have the Chime area, we have Bolton. All of those areas are areas that we have, besides Musreau, are areas that we have discoveries this year. And we will be exploiting more than exploring in 2007.

Great, thanks.

Thank you.

Your next question comes from Eric Hagen.

Good afternoon, Dan.

Hey, Eric. How are you?

Great, thanks. First, congratulations on transforming the company over the past few years, with finalizing that this quarter with the sale of the Gulf Coast.

That was a big move for us.

Yep. In terms of our questions, I heard in [inaudible] call that Equitable had drilled a very good horizontal well more in the southern part of the basin, I think kind of where you're located. Have you heard anything about that at all?

We have, all we have right now is the press release that we got across the wire which what we had available to us, Eric, was that the, they were very pleased, could significantly expand their 2007 program, and that it could be a game-changing event for them and the area, but they did not give us any rate.

Yeah. I had seen that. I just wondered if you had heard anything on the grapevine or whatnot.

No, I can assure you that our East region is going to make every effort to consolidate this data and give it to us at their earliest possible convenience.

Great. Thanks. Moving West to the Paradox, can you give us any color on the share wells that you drilled and what happened there? Is that play -- does it have any future potential or not, do you think?

I'll turn the future potential part over to Mike. But I'll make a very brief comment. We did test four zones, and it didn't look like we had the firmability that we would have like to have seen. We did test gas, and we did flow gas back. We just couldn't get to the rates that we wanted. And we had a large acreage position out there. Again, it's not much control, and I'm sure Mike and the guys will continue to dissect this data. We just yesterday made the decision that we would plug this well.

I thought Canada had drilled four or five successful tests out there, I think was called the Gothic shale. That the same shale you were testing?

This is Mike, Eric. Well, they drilled terrible wells down into the Paradox, which we were partners on with them, but the one well that they drilled was their Middle Mesa well, which they found a little sandstone in the shale member that has produced the 4 to 5 million a day IP, and those were the shales that we were targeting. On our well, we have actually established at low rates a consistent flow of gas. This has given us some confidence that the system is indeed gas-charged. We need to find a place where the reservoir is enhanced by either natural permeability in this silty sand, or by natural fracturing. Our evaluation of the area suggests that this shale does extend over quite a large area, and we'll be going forward to further evaluate where potential lies and maybe a more fractured environment on that 40,000-acre block.

Okay. Thank you very much. That's all I had.

Thanks, Eric.

Your next question comes from Jack Aydin.

I was going to ask about the Paradox Basin a little bit more. Could you -- I mean, I'm looking at a couple of maps. How far is your acreage from the Hamilton Creek area and the Andes Mesa area? I'm looking at the map, try to compare your map and some other maps together to see, not too far, if I --

Yeah, Jack, as far as the Andes Mesa area, we have acreage right adjacent to the Andes Mesa area at our Double Eagle field. And as far as Hamilton Creek and our Nelson Creek area, Hamilton Creek is to the north of our acreage position about two miles.

[Multiple speakers] --the acreage a little bit more, was the--the flow was not good enough, or what other issues in that, you know, you encountered in that well?

We didn't find any other issues except that it appears that the shales just are not in a vertical well bore, have enough well bore permeability to give us commercial rates. Frankly, Jack, we need to do some more work, but certainly this may [inaudible] to some horizontal drilling. It appears that we just need to get more well bore exposed to this shale unit.

How much this well cost you?

It was a pretty good investment.

Okay.

Part of the reason for that, Jack, is we put it in the testing, we extended some tests and we had four zones that we wanted to test, the and we tried to wring out and gather as much information as we possibly could to try to use in further analysis.

Okay. Thanks a million.

Uh-huh. Thank you.

Your next question comes from John Herrlin.

With the horizontals in Appalachia, what were you that was different, length fracs, for the 2-million-a-day well?

John, right now, as you can see, there's a lot of competitive aspects to the-- and a lot of attention to the horizontal effort out there, and we have not done any one thing. It's a number of things that we're trying to do to enhance the flow rates out there. We've drilled wells in different directions, and we have tried different frac techniques, it's a myriad of things. And at this stage, we're going to continue to evaluate what we're doing to those wells to see if we can continue to enhance it, but until we feel like we have exhausted any competitive advantage, we're not going to discuss everything.

Okay. That's fine. Canada. You've been having good results. Surface costs have really started to drop down there versus the U.S. Is it possible you could change your mix or is the infrastructure and limitations regarding gathering up there such that you really wouldn't? Because you're seeing rig costs go down, frac costs, et cetera.

You're addressing the mix in our capital allocation?

Yes.

We could. We have the flexibility to be able to do that. And we look all the time at what--where we might be able to best allocate the capital and get the most for it. I would venture to say, John, that if -- that we have, I think, seen some of the higher prices that we are going to see near term in the service sector in the United States also. We have seen indications where there is certainly more competition between service companies in the past where we were not able to even receive bids from all parties for a particular service. We are now getting multiple bids, and there's a significant Delta between some of the bids that we're receiving. So I think you're seeing a little bit of that softness here in domestic U.S. also.

Thanks, Dan.

Uh-huh.

Your next question comes from James Mooney.

Hey, guys.

Hey, how are you?

Good. How are you doing?

Good.

Two quick questions. The first, in Appalachia, the 2-million-a-day well, is that a million dollars cost also, and based on the 8 you've drilled to date what do you think -- or can you a range of the EUR's for 2-million-a-day horizontal out there?

Well, first off, on the cost side, we have continued, well by well, to be able to improve our costs. The drilling college was not cheap but we're learning. And we hope to continue to be able to keep the costs in this range. We're talking about a million dollars now. As far as being able to find an EUR, and really early to tell, and too early to tell with confidence what we'll be able to do. Again, the encouraging step at this stage with confidence that we can predict or indicate is the flow rates, which we're very pleased with.

And second question on -- I'm going to play the neighborhood game also. How close is Minden to these monster Cotton Valley horizontals that we've been kind of picking up in the last few weeks.

Probably got 10 or 15 miles. It's in the neighborhood, James. One of the things we're doing in our area, we have drilled the horizontal program, we have been defining the effects of the fracs of each of our three zones that we're fracing, we're getting orientations down on how how we are going to space of of these wells. We've stepped out to prove up and delineate, and help delineate the area of extent a little bit. That is helping us with our infrastructure planning as we move forward. We have accumulated additional acreage out in our area. And with that being said, once we feel very comfortable about the effects and ability, what we can do on a vertical program, we will be looking at the horizontal program in detail.

Thank you very much.

Thanks a lot.

At this time, there are no further questions.

Okay. Thank you, Michelle. I appreciate all the listeners for their interest in Cabot. I think the press release indicated that we're going to finish the year with all expectations on a high note. 2007 certainly sets up as a banner year for Cabot. We expect a strong showing in the production profile, and we certainly expect at the end of the year that we will have a significant add to our reserve base, and this is all per our organic program. Again, thanks for your interest.

Thank you for participating in today's conference. You may now disconnect.