Coterra Energy Inc (CTRA) 2007 Q1 法說會逐字稿

At this time I would like to welcome everyone to the Cabot Oil & Gas first-quarter 2007 conference 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 very much, Therese, and I appreciate all of you joining us. I understand there's a couple of calls that are kind of on top of each other; so I do appreciate you all attending Cabot's at this time.

I am going to introduce several members of the team that are with me today. Mike Walen, our Chief Operating Officer; Scott Schroeder, Chief Financial Officer; Jeff Hutton, VP Marketing; and Chuck Smyth, our VP Controller are all with me at the table. Before we start, the forward-looking statements included in the press release apply to my comments today. Let me begin.

Cabot issued two press releases last night, both illustrating success -- one with financial highlights in the quarter and the other reporting achievements in our first-quarter drilling program. The financial release per-share numbers that you saw reflect our March 30, 2-for-1 stock split.

Financially the Company again reported solid net income of $43.6 million or $0.45 per share after removing the benefit of the leftover asset sale activity in the quarter. This level of net income was Cabot Oil & Gas Corp.'s second-highest first-quarter results ever reported. Though our net income levels are very good, the main drivers for the quarterly comparison to last year's record quarter were prices, a 10% decline in natural gas prices and a 13% decline in oil realizations.

Our hedge position did mitigate some of the declines, with a $17.6 million pickup adding about $0.89 per Mcf to the unit realized gas price. Oil settled mostly within our collared range with a $182,000 increase in value.

In regard to expenses, overall expenses were slightly lower than last year's first quarter levels. For the remainder of 2007 Cabot has about 50% of its anticipated production hedged with wide collars at a weighted average floor price of $8.00 per MMBtu. Additionally Cabot has recently commenced a hedging program for a portion of our 2008 production with three different collared arrangements, two for gas and one for oil. You can go to our website to review the specifics on those new hedges we have placed.

Now I would like to discuss a very positive area for Cabot, our production. In absolute terms, compared to last year that had the benefit of production from our sold South Louisiana and offshore properties, our equivalent production was down only 1%. In fact our absolute natural gas volumes increased 5%; and increased 25% on a pro forma basis. Our oil production showed an absolute decline of 48% due to the impact of the sold properties; but on a pro forma basis our growth rate was 38% for oil.

In summary, our press release indicated our going-forward assets grew production at approximately 25% rate. These production results are all attributable to a highly successful drilling program and a tremendous effort by our staff. Our program was 99% successful in the first quarter on 100-well program.

In regard to Cabot's financial position, it remains at the best standing we have ever been at. Our capitalization is below 20% and affords us significant flexibility, which will allow us to continue to exploit the opportunities in our portfolio.

Now let me move to operations. Last night we also gave a brief update on a couple of our projects. I will offer some color on those projects and several others.

First of all, Cabot is well on its way to meet our goal of drilling over 440 wells in 2007. In the first quarter the Company drilled 100 gross wells compared to 71 wells drilled the same time in 2006 -- the same period in 2006. We have the equipment secured, many of the locations in hand, and the manpower to continue or even expand this pace during the summer to meet or exceed our scheduled program expectations.

Now let me talk about some of the operational highlights. In our Gulf Coast area, our Minden project in East Texas continues to exceed expectations. We have successfully expanded the field to the Northeast and the Southeast from our core area around the [Herald] discovery. We have drilled 49 wells to date, all successful, with 41 currently producing and eight waiting on completion. We currently have four rigs operating in the field.

We indicated earlier that we have Travis peak potential under most of our acreage. We have started developing that resource, drilling our first two Travis Peak wells that were disclosed in the press release. Also we have recently gained approval to commingle the Travis Peak. It is our plan to continue to develop the Travis Peak and commingle this zone with the Cotton Valley.

Another new operation in the field -- we have finished the drilling of our first horizontal Cotton Valley test in the Minden area. The Pinkerton 9H has reached a total depth below 12,600 feet, and production casing has been run. We drilled a 2,200-foot horizontal leg, and completion operations will begin in mid-May. This well will test the lower Cotton Valley sand section, which is -- that section is analogous to the zone completed in the Devon Haygood well, Number 11 well, which is located approximately 15 miles to our East.

We are drilling this well for really two reasons -- to test the concept of economic horizontal development in our Minden area, as well as to determine whether or not we can use horizontal drilling to effectively exploit where surface access issues prohibit us from drilling. Right now, with midterm operations, we will have to let you know shortly once we complete both of these operations.

Additionally we noted earlier that Cabot would install centralized water disposal systems to handle our produced water at Minden. The initial disposal well has been completed. The water gathering system is being laid. We anticipate the project to be completed by June. The positive economics are a savings of over $1.00 per produced barrel of water. A similar pod is located in the Northeast extension area of the Minden field, is currently under construction.

Moving to the Southeast at our County Line prospect, we have drilled our third and fourth wells in this prospect. The Timberstar #1 is a horizontal test of the Pettet limestone. The Timberstar #2 is a horizontal James lime well. The #2 well is currently drilling below 7,400 feet and should reach total depth in approximately seven days. Both wells will be fracture-stimulated in mid-May, with seven treatments for each well.

This prospect could see increased level of activity this year. We are in the planning stages to potentially drill additional locations offsetting our current wells, as well as exploiting the successful extension we are participated in on the Southern portion of our acreage. That well in the Southern portion of our acreage tested over 4,000,000 cubic foot per day for multiple completions over a 7,000-foot horizontal section in the James. That is highlighted in the press release.

In our McCampbell field development in South Texas, this is a field we have not talked about much since we have taken over operations and we have moved our working interest up from 33% to 92%. In this field we plan to drill seven wells during 2007 to exploit the Frio sands. Year to date we have drilled three wells. A recent well, the Davis 5A, was completed in the Frio Q1 sand, flowing approximately 1.5 million per day plus 40 barrels of oil. We are currently drilling the [Flynn] #1, which will test the same structure.

In another area which is also under our Gulf Coast region, we have disclosed a new significant acreage holding position we have in Mississippi in our 2006 10-K. This is our [Mayberry] play in the Black Warrior Basin and is targeting tight Mississippian and Pennsylvania sandstones as well as the Floyd shale.

We are looking at depths between 2,000 feet to 10,000 feet. We have leased over 600,000 gross acres in the play across several counties. We believe this portion of the basin holds tremendous upside in the tight sand section. It is a hydrocarbon system similar to that we see in the Appalachia Basin. Our plans are to transfer some of our Appalachia expertise in air drilling and completions to this underexploited gas basin.

This is a new area for us. We have just started this effort. We will continue our work for the foreseeable future. It is too early to report any details, but please stay tuned for additional information as we continue to gather some data points.

In our West region, our Moxa Arch area of Western Wyoming has evolved into one of our premier development areas due to the success of downspacing from 160 acres to 80 acres for the Frontier and Dakota sections on the Arch. Based on a successful downspacing program in 2006, we are expanding our program in 2007 to drill between 40 to 50 wells, including some outside operated wells.

Our year to date program, we have drilled five wells at 100% success, averaging about 1.2 to 1.4 Bcf per well from the Frontier, which is in line with our pre-drill expectations for the Frontier.

Paradox basin -- that is to the South in Utah, Colorado area -- is in the forefront of our Company's exploration effort as we feel there remains significant hydrocarbon potential in this basin. With over 400,000 gross acres under lease and numerous potential pay zones, the basin is going to be one of our focus areas for exploration in 2007.

We will spud our next test at McKenna in August. This 10,000-foot well will continue to evaluate the gas potential in the Paradox group shales. As you well recall, we drilled our initial McKenna well last year and found the upper Paradox shale to be gas charged. We did not connect the well due to the distance from available pipeline; but the well did give us encouragement to do additional drilling in the area.

We plan to drill two other high potential targets in the Paradox Basin later this year. The South Gypsum prospect is a 9,200-foot Leadville test and will spud in September. The Vancorum prospect, a 16,600-foot Leadville test, will spud in October.

We have approximately 8,600 gross acres around these prospects. We will drill these wells with a 40% to 50% working interest. The prospects range in size from 45 to 250 Bcf gross potential. Remember that the drilling restrictions in this area is limited access to only six months per year; and that is from mid June to mid December.

Moving South to our Mid-Continent area, we continue to ramp up our drilling program, where we plan to drill 50 to 60 wells this year, about half of them targeting the Chester limestone with the rest of focused on the Morrow sandstones. This area has developed into one of our top-performing plays. We have drilled 11 wells with 100% success this year, utilizing two drilling rigs. With over 265,000 gross acres across this basin, we expect to see significant opportunities to continue to expand this program.

Now we will move up to our East region. This region continues to expand its program both in the traditional tight sands in Central and Southern West Virginia and the vertical and horizontal Huron shale plays in the Central and Western part of the state.

We are on track to meet our 270-well program in 2007. We have drilled 56 wells in the first quarter. We have nine rigs operating and plan to ramp up 14 -- up to 14 rigs during the peak summertime drilling season. We are very busy with 14 completions, or 14 of those wells also waiting on pipeline. We have 20 crews building locations and access roads trying to stay ahead of our drilling rigs.

In our horizontal play, there has been a lot of talk about horizontal going on up into the Appalachia area. It continues to improve, as we can now consistently drill horizontal leg out to nearly 3,800 feet of lateral extension in less than 15 days at a drilling cost of under $800,000. Total completion cost should range up to $1 million or less depending on the number of fractures we do on each well.

To date we have drilled a total of 13 horizontal wells. Six of these wells have been completed and turned in line. We are currently building a gathering system into our Hurricane project area and anticipate first production from the wells in our Hurricane area by early June.

Also we are currently drilling on our sixth horizontal well this year. As we have mentioned before, an integral part of our growth strategy in the East is the continuing expansion of our infrastructure to ensure the adequate takeaway capacity for our future drilling. To that end we are investing approximately 35 to $40 million in total pipeline and facilities in 2007, the majority of which will be catalysts for our 2008 program.

Moving to the North, our greenfield growth plan in Canada continues to yield significant new finds which are beginning to contribute to Cabot. So far this year we have drilled three exploration exportation wells, all successful. Currently all are waiting on either completion or pipeline. Right now we are in the spring breakup period, and operations should recommence up there in June.

In our Hinton area, our initial well, the Hinton 1-11-6, is producing at a rate of approximately 14 million cubic foot per day. We are very pleased with the results of this well. The other two wells, however, we are still evaluating the lower producing rates from those two wells. The wells appear to have a similar productive section. However they have not responded to the fracture stimulation as did the 11-6 well.

We have six subsequently purchased a new 3-D survey over the field to help us image the significantly complex geologic section. A 3-D interpretation, though complex, does support our belief of a significant potential on the structure for the Mountain Park and Dunvegan. As a result of our 3-D interpretation, we have recently spud the Hinton 4 well, which is currently drilling below 9,600 feet, [falling] to a total depth of below 11,500 feet.

We have experienced continued success in other areas in the Deep Basin. As we highlighted in the press release, our initial wildcat at our Boltan prospect was recently completed, flowing 5.3 million per day from commingled Dunvegan and Gething sandstones. We have 16 to 20 additional locations identified on this 5,000-acre prospect.

So in summary, as you can see, we have a significant level of activity in each region. With our continued success, the program is on track and we reaffirm our guidance, with only one small adjustment to our DD&A expense, which has been adjusted to reflect the last couple years of increases in cost. Speaking of cost, we have seen the cost of services moderate, unlike the last few years of increases.

I am very pleased with our program, and the tremendous effort of our staff, and the progress we have made year to date. I fully anticipate our organic reserve growth target to be met at year-end, with a top tier finding cost. Additionally I anticipate us to meet our double-digit pro forma production growth targets that we have reflected in our guidance.

It is our strategy and our goal to find efficient methods to accelerate our significant inventory of opportunity while still maintaining our financial strength. We are continuing to evaluate all of these opportunities.

Again I want to thank you for the support of the Company. I look forward to the updates. In some of our operations we are in midstream and just now running pipe or moving towards the completion stage. I will look forward to those updates in the near future. With that, Therese, I will be happy to answer any questions.

(OPERATOR INSTRUCTIONS) Larry Busnardo, Tristone Capital.

Good morning, Dan. At County Line, can you talk a little bit about how you envision that the play would be developed? You know, with your early success on the horizontal plays targeting both Pettet and James lime, how will that transpire throughout the year? Do you see an equal program going, targeting each separate formation there? Or will there be a focus on one formation or another?

That's a good question, Larry. I think it will be a progressive development process out there. I will tell you what we are doing right now. With the Timberstar #1 and the Timberstar #2, what we elected to do is use the same pad site where we drilled the first Timberstar #1 as a Pettet horizontal. We just skid the rig over to utilize the efficiency of one pad site. We are drilling a separate well, the Timberstar #2, but it is for the James lime. So they are parallel, just one is a little bit deeper than the other.

Our group -- and I don't know if Mike wants to comment any on it or not -- but our group certainly is looking at a dual lateral. Again, a difficult mechanical operation and one we are not yet prepared to try; but certainly we are trying to evaluate that.

Yes, Larry, we are looking at the engineering of that. But as Dan mentioned, it is a challenge to engineer that properly in a cost-effective way.

I would just follow up with a little bit on County line. We are in the process of identifying additional locations and preparing additional locations land-wise to potentially expand the drilling program on that prospect going forward this year.

How many wells do you think you could get drilled there this year?

Well, we have not gotten to that number. That number is still growing at this time.

Okay. Looking at the non-operated well, it had a 7,000-foot lateral whereas yours are 4,200. Can you just talk about that, the difference, in terms of how that well was designed versus what you are targeting with your laterals?

Yes; I will let Mike go ahead and answer that.

Larry, really there is no -- the only reason why that we drilled ours a little bit shorter was the fact that we just had some lease boundaries that we had to honor. We have larger blocks within the project that we could certainly drill out to 7,000-foot horizontal.

Okay. All right. Is the plan though, going forward, would you -- do you drill the shorter lateral? Or do just kind of see how these first ones go, and then you will determine that, how you will--?

As Dan mentioned, we are going to be doing seven different stages in each one of these wells. It really is an economic issue of how far we drill.

Okay. Shifting over to Hurricane, can you just talk about what you are able to do to lower the drilling days by a deal? It looks like you shaved a couple of days off of that; the costs have come down. Can you talk about what you have done on these last couple wells?

Well, we have continued from day one -- as we have mentioned numerous times -- to reduce our cost. There is a number of things that we have implemented throughout the process that has allowed us to reduce our drilling cost. The guys have certainly gotten comfortable with the horizontal drilling. The steering technology that we are using is good. The methodology of us running pipe has been quite effective.

We are not going to mention all of the things that we have done to reduce the cost. We are just pleased that we can -- we have found some of the secrets and we're able to duplicate it.

Okay. That's it. Thank you.

Thank you, Larry.

Ellen Hannan, Bear Stearns.

Good morning, just two quick questions for me. One, could you talk about -- and I apologize; I came in a little late. But you were talking about improving the cost of the water disposal in the Minden area. What kind of an impact do you think that would ultimately have on your LOE, if any? I see you haven't changed your guidance for this year. But would that change going forward?

Well, as we drill more wells -- and these wells produce a little bit of water with them as we bring them on. In fact, that is just characteristic. We are producing approximately 4,000 barrels of water a day out there right now, so, with the number of wells that we have online, which is 41. As we continue to expand the field, it will continue to have a cost benefit in our LOE.

My second question is nothing to do with that. But about your Mayberry play over in the Black Warrior, what do you consider the kind of couple of biggest risks from a geologic standpoint in this play? Is it the tightness, or the thinness, or how would you describe that?

I will flip it over to Mike in a second. But my comment is going to be that it is not a densely drilled area. Control points are fairly wide spaced in a lot of the area. There is not any 3-D up there. The efforts to the Floyd are virtually -- there has been a handful of efforts to the Floyd at this stage; so that is extremely early in the program.

Our lease position covers a several thousand square mile area. We probably have maybe half of that position leased. There are again several old fields; and I am talking about old going back to the 1960-vintage type of fields. New technology has not been applied to some of those areas that we think we can maybe exploit and find some new areas. The challenges, though, from a geologic standpoint, I will let Mike answer.

Ellen, we think the Warrior Basin is very analogous to the tight sand plays that we are very familiar with in the Appalachian Basin. We see the same type of sands, roughly the same age sands, thickness of sands, the same range of porosities and permeabilities. And these are gas charged. We think that there is an awful lot of opportunity to exploit those tight sand things using Appalachian knowledge.

The challenges that we see out there, of course, are just how good are the sands? How continuous are the sands? Obviously, can we get effective frac stimulations on these sands, sandstones? So.

But overall we are very, very early in the play. We are just gathering data. I think that you should expect some additional information as we go forward.

Great. That's it for me. Thank you.

Bryan Singer, Goldman Sachs.

Shifting to Appalachia, you talked about the drilling days and the well cost. Could you talk about some of what you have seen just initially from well performance from the horizontals?

Well, in the Hurricane area -- well, let me go back to the first area. The first area we started drilling the horizontal wells is in an area that we had considerable control. We had wells that had been drilled vertically that had been completed in the Huron section.

We drilled some horizontal wells within those vertical wells. Those are the six wells that we have turned in line. We turned those in line from anywhere from an IP of a couple of hundred to about 0.5 million per day on those wells in that area.

Moving to the Hurricane area, which is a new area for us, there has not been drilling going on. We have drilled and we have tested several of those wells. We have tested one well up to a couple of million a day.

We are optimistic of what we have seen in a Hurricane area. We have seen some natural flows when we were drilling the wells in the area. Again, the rates that we see and the expectations we have in Hurricane are markedly above what we had seen where we had our initial pilot.

Great. Then I guess looking at some of the verticals, you had some high rates from verticals that you mentioned in your operations review. Is that something that you see as repeatable? That the decline rates also [that] seem to be high, and what does that mean for horizontal developments (inaudible) for an area of Appalachia?

Well, we have not drilled any horizontals down in our Southern and South Central area of our acreage position. That is an area that historically we find these wells throughout the year in our program. We wish every well would be like the ones we reported; obviously that is not the case. But we do find wells like this in our program.

The opportunity to drill horizontal in this area is not precluded. But when you look at the zone and the section that we drill, it has multiple pay sands in it. If you do go horizontal, then it could be at the exclusion of other pay zones in a particular area. Not to say that we wouldn't do it in the future, but that is one of the reasons we don't do it. Mike, you want to add anything to that?

Yes, Brian, we have anywhere from five to seven different sands and/or limestone beds in the Southern part of the state. These sands generally are tens of feet thick individually, and probably would not make the best horizontal target. By going horizontal in one, you would probably be passing up potentially another sand above you and under you.

Got it. Thank you.

Jack Aydin, KeyBank.

Mike, on the Southern part of West Virginia, in the press release talking about the sand play, those wells, what is the average -- what is this costing you, average well?

Anywhere from $400,000 to $450,000 drilled and completed and hooked up. Reserve numbers our range -- our average is about 400 to 500 million per well.

No, I am talking about the well you mentioned, that the line 2 tested 3.5 million; the other one about -- you know. Are we talking about the same wells?

Yes, we are. Those kind of wells down in Southern West Virginia, that is kind of our average number. Obviously you will start off at a much higher IP. So that well could be on the upper end of the range, or it may be even surpass it.

But that type of a well in Southern West Virginia, as Dan mentioned, are the ones that we find every so often. We certainly don't use that well as our average well.

Thank you.

At this time there are no further questions.

Great. I appreciate everybody's interest in Cabot. We hope to continuing being able to perform and look forward to our next conference call. Thank you, Therese.

You are welcome. Thank you. Have a great day.