Coterra Energy Inc (CTRA) 2005 Q1 法說會逐字稿

Good morning. My name is Misty, and I will be your conference facilitator today. At this time, I would like to welcome everyone to the Cabot Oil & Gas first quarter 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 period. [OPERATOR INSTRUCTIONS] Mr. Dinges, you may begin your conference.

Thank you, Misty. Good morning. Thanks for joining us for this 2005 first quarter teleconference call. I'd like to introduce the management team that I have with me today, Mike Walen, Senior Vice President; Scott Schroeder, CFO; Jeff Hutton, our VP of Marketing; and Chuck Smyth, our VP Controller.

Before we start I need to read the following. The 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 activity, future production and cost and other factors detailed in the Company's Securities and Exchange Commission filing.

All non-GAAP measures, financial measures discussed during this conference call have been posted to our website at www.cabotog.com along a with a reconciliation to the most directly comparable GAAP financial measures.

As you all are aware, last night Cabot issued two press releases and reissued the same level of guidance for production expenses on our website. My talk this morning we will touch briefly on the first quarter statistics with a more in-depth focus on our operations.

In terms of the first quarter, the net income and cash flows results were second only to 2001 when industry experienced $9+ January gas. We reported $20.8 million net income level or $0.43 per share, was an improvement over the prior year, and was driven both by improved production and higher realized commodity prices.

For the quarter, realized natural gas prices were 10% above last year's first quarter, with realized oil prices 36% greater. The impact of hedging on the quarter was a reduction of $0.34 per Mcf for the expired natural gas hedges, and for accrued oil, the impact was a decrease of $5.74 per barrel.

Additionally, as the mark-to-market table in the press release highlights, our future hedge positions that require to mark-to-market accounting treatment decreased our quarterly natural gas revenue by $560,000 and decreased our quarterly oil revenue by approximately $7 million. The significant improvement in oil prices late in the quarter drove the decline which had a $0.09 per share adverse impact on the quarter. So without this, we would have been at $0.52 per share.

Cabot management has not added to its 2005 hedge position and remains approximately 40% hedged for its equivalent production for the remainder of the year. Also, we have not added any additional hedges or do not have any hedges in place for 2006.

In terms of expenses, all categories fell within the guidance range except for our exploration expense, which we exceeded the top boundary by approximately $1.4 million. The key driver for this was an increase in our dry hole expense for the quarter, along with the dry hole dollars incurred through the first quarter for wells determined in April.

It's by the dry hole expense our first drilling program for the first quarter yielded an 86% success rate on 44 wells drilled, and today we have 17 wells completing across our regions along with 16 drilling rigs. In our East operation, we continue to see year-over-year production advances. We are well on our way on completing our largest program of 200 wells with 8 rigs drilling at 100% success rate year to date.

In addition, at this point in time we have 102 permits in hand. So we expect a steady stream of drilling through September running between 6 and 8 rigs. The focus to increase this East program is definitely having a positive impact on Cabot.

We have quite a bit to discuss today regarding our North Louisiana project. We have had -- experienced, as you would expect with any play expansion, a mixed bag of results. First, we had previously mentioned I think on our last call some delays in getting our first burning well on-line. I am pleased to report that has now happened.

The Davis Brothers 10A #1 was completed in the lower Cotton Valley and tested at 6.7 million cubic foot of gas per day. Cabot has a 23.5% interest in this well. The well is currently producing and sets up a couple of offset locations, which we plan to see drilled by the end of the year.

We also saw the successful drilling and completion of our first Eros prospect well, with the completion of our warehouse 8A #1 well. In that well Cabot has a 43.75% working interest and the well is flowing 6.2 million cubic foot of gas per day from the lower Cotton Valley section. This success did convince us to drill the Weyerhauser 9 #1 where Cabot has an 84% interest. And this offset is less than a mile to the east. In fact, this well has spud and is currently drilling below 1,700 feet. If successful, we are hopeful these two wells will set up multiple development locations on our Eros acreage and result in a significant extension if that does occur to the Vernon-producing complex.

In our Clear Branch area, we have not yet had the success that we are looking for. In our initial test, the Womack #1 and the Knight #1, both wells encountered an extremely rich gas section in the Cotton Valley, which encouraged us to attempt multiple fracture stimulations in the Womack well. However, we were not able to establish a commercial rate.

Based on those results and our log analysis and core data that we saw in the Knight well, we elected not to test a similar-looking type section. Our plan is to continue prospecting on this 20,000-acre block. As we have previously mentioned, none of this acreage has a 3-D coverage.

We continue to design a 3-D seismic survey to be shot this year over the majority of the acreage, which will be shot in partnership with offset leaseholders. With the information we have gathered so far, we do interpret additional opportunities in the Cotton Valley section. Also as we continue to integrate the information, we feel good about the James Lime and Hosston sand potential for future drilling locations.

In summary, it's a slow start for us, but not the end of the story. In regard to our other Cotton Valley prospects in North Louisiana, we continue to fill in our acreage positions, along that vein we will be drilling our next impact wildcat later this year. That's on the Caster prospect located west of the Vernon complex, which will be spud in July. This prospect covering over 10,000 acres will expose Cabot to a large Cotton Valley resource potential. In addition, we are leasing on six other impact projects in our North Louisiana play.

In other areas of our Gulf Coast region, currently we have six rigs operating with two completions underway. The Cadillac prospect, which is a VK 251 operated by Chevron, has set intermediate casing at 19,380 feet. We still anticipate reaching a total depth of 25,000 feet sometime during the mid-summer on this 50,000-acre structure.

In the West region, the West is currently focused on exploiting our Mid-Continent and Wyoming properties and is working through the Federal permitting process for our summer drilling program throughout the Rockies. Through the first quarter in the West, we have drilled 17 wells with 16 successful. In addition, Cabot has seen a significant contribution from a workover program in the Mid-Continent and we have currently upped our capital contribution to this program.

Cabot's Canadian operation is in the midst of spring breakup, so we don't have a great deal of activity to report at this time up there. We did complete the drilling in the first quarter of our Simon Head Swan Hills reef wildcat. Unfortunately this well did not encounter the refacings [ph] we had anticipated. We also abandoned the Stoberg Wildcat, though we were still prospecting in this -- in this area.

Finally, in our Soldier Wildcat, we are evaluating a long-term pressure buildup test and will be developing a fracture stimulation plan for the Slave Point reef that we did find in the Wildcat. This activity will have to take place, though, after the spring breakup.

Overall, Cabot continues its active drilling program. Some of the upcoming wells of note, we have a priced 2 well, it's Wilcox test in South Texas with about 50% there. We have the Caster well I mentioned, which will have 75% in in North Louisiana. We have the Bristol well offshore that we mentioned previously.

Also, our Highland A 173, we'll have 50% in that offshore marge A test. We have the Eros well I mentioned. We have a Canadian wildcat, Cypress Wildcat, we are 50% and another Canadian Wildcat, which will be a Slave Point reef test. Our Sutton [ph] play will have 100% of that particular well. Each of these wells expose Cabot to greater than 30 Bcf of gross reserve.

We see no significant changes in our scheduled capital allocation for the second quarter, or for that matter, the remainder of the year. Our development program is well underway with exploration opportunities, either drilling or planned from the Gulf Coast to Canada. Our portfolio allows us to have upside exposure as indicated in the list of wells I just mentioned. That adversity also allows us to balance the risk in our program.

With the success we have had and have had year to date, today we're producing approximately 245 million cubic foot of gas per day. And as I previously mentioned, we have 17 completion rigs on the report. With that bit of good news, I'll stop now, Misty, and turn it over for any questions we might have.

[OPERATOR INSTRUCTIONS] Your first question comes from Brian Singer with Goldman Sachs.

Good morning.

Morning.

On the Eros prospect, what are your current thoughts on the spacing of offsets, and could you refresh us on the acreage position? And then both with regards to the Eros, as well as the Davis Brothers, are there any other zones that may be prospective besides the lower Cotton Valley.

Okay, Brian, on the Eros, it is in very close proximity to the Vernon Field. And it's -- we have 2,250 acres that we have -- we got through really the Weyerhauser option that we had taken in October of 2002. With the spacing in Vernon right now, and it's a little bit early to predict exactly what the spacing is, but in the spacing in Vernon, it's 53 acres. And we anticipate that we'll have anywhere from 40 to 45 locations if in fact it spaces out as the Vernon Field has.

We're encouraged with what we saw in the 8A because it was a very similar section to what is being developed in the Vernon Field. And on the Davis Brothers, we have just a couple of offsets in the Davis Brother area, which is more to the north and west of the -- of Vernon Field.

And that's all lower Cotton Valley.

Yes, that is lower Cotton Valley. And we have not seen in the immediate area any Hosston or Lime -- James Lime potential in this immediate acreage, but on the east acreage it's still a little bit underexplored in that regard.

Great. On Appalachia, could you just give us an update and any changes to your thoughts on infrastructure and infrastructure growth?

Yes. On Appalachia, we're progressing well. We had our Board meeting yesterday and operations report and the East is progressing very well. We had a -- one of the big projects that we have, which had -- had added to our 2005 program was a Henson Law [ph] pipeline that we are constructing and it's about 90% complete at this stage, and that's going to set up like 40 different locations for us immediately.

As far as the progress, we are right on -- we're right on track on the 200-well program. We have, in fact, the turned in line a well -- let me see. I guess it was earlier this week we turned a well in line that we had a great absolute open-flow calculation of over 10 million a day. And we turned it in line over -- over 2 million a day. So we were -- we were very encouraged with those kind of wells. Those are obviously anomalies in Appalachia, but it certainly helps the program when we do find those type of wells. But we're real pleased with the Appalachia program, and in fact, we are looking at that program to see what we might be able to do in increasing our number of wells above 200 wells in 2006.

Thank you.

Thank you, Brian.

[OPERATOR INSTRUCTIONS] At this time, there are no further questions.

Well, great, Misty, I appreciate it. And we want to thank everybody for the interest in Cabot Oil & Gas. We have a great deal of activity ahead of us in 2005 and we're maturing our prospects in each of our regions that I feel great about after looking at the operations report yesterday, the progress that we're making. So stay with us. We'll -- we'll be reporting back at the end of the second quarter. Thank you.

Mr. Dinges?

Yes.

You did have a question just pop into queue.

Okay.

And that question comes from Jerry Heffernan with Lord Abbett.

Sorry to keep you busy there, things ended a little quicker than I thought they were going to.

That's okay.

In discussing the Appalachian plan, you made the comment you're reviewing the program to see if you can take that above 200 wells in fiscal-year '06. I'm rereading some information from February, I guess in the East region you said that you had completed 171 in '04.

Right.

What's the limiting factor to that? I mean, you were able to go from 171 to 200. Why should 220 be an issue? What -- what are the issues that you need to review to determine -- other than the obvious of do I have 200 sites? And I believe that we've already discussed that you do.

Yes. It -- it's a good question, Jerry. And it's kind of a multi-prong tackle of what we're trying to do to evaluate what we can do to increase that program. I'll start first with the geography. West Virginia is very unulated [ph], a lot of hills and valleys. And as you expand out in some areas, as we expand out, we have a terrain to deal with in location preparation. When you look at rig moves up in Appalachia, the rig moves every 10 to say 12 days. And as you get into new areas with the terrain, your construction time for roads and rig pads is extended in some areas.

We had up to 18 construction crews running last -- last year to get sites prepared. And in some instances, those locations took 14 to 16 days to prepare. And you can see the logistics on trying to stay ahead of say 6 to 8 rigs and it takes that long to get -- get locations prepared. That is one factor that we're trying to -- to limit -- or trying to get ahead of by getting more construction crews out there, but it's a lot of equipment when you're running that many construction crews.

Two, it is personnel. When you're trying to stay ahead that quick a rig moves when you look at -- fortunately, we have -- a majority of it's 100% interest. But when you're looking at clearing all the permits and getting all the necessary paperwork in place, it's just a paper logistic issue, and in addition to the logistics of equipment, securing equipment and that type of thing.

So we're looking at all of it. In fact, part of our effort is also looking at with the bottleneck being locations. We are going to be drilling a horizontal well up there in the East to determine whether or not we might be able to drill more locations from one pad. If we're successful in that effort I think it would -- would allow us to enhance our program significantly also.

Okay. And correct me if I'm wrong, drilling multiple holes from one pad in Appalachia has not been a common feat.

No, it has not been a common feat.

Okay.

In fact, to my knowledge, you can count the number of directional wells on one or two hands that I'm aware of up there.

And why is that? Just because of the [inaudible].

Frankly, I think it's been because it's been easy to drill straight holes and -- and it's a low-pressure gas basin up there and that's just the way the area's developed.

Fair enough. Fair enough. The -- again, staying in Appalachia, going up towards the New York area, a number of people have been talking about the -- the Trenton Black River type of place.

Right.

Can you give us any of the information on this?

Well, we had some acreage up there, we have five or six prospects up in that area, but the area as far as a lot of available acreage and running room and the need for 3-D to make that play effectively, it limits our entry into the area in any significant way. Though we are looking and probably will drill additional wells up in the Trenton Black River. It's not a play that we're focusing a great deal of attention, primarily because it's hard to get in up there in what we deem is the key areas. But, more importantly, we're focused on expanding our program down in our core area.

Okay. So it sounds as though you don't have significant acreage to make it worth the -- the time and money to go up there.

Right.

And what you have there, would it be more than likely that anything you do up there would be -- where you're making a deal with somebody else?

That would be a fair assessment, Jerry.

Okay.

Yes.

Okay. Again, stay in Appalachia, difficulty in getting equipment. You talk about personnel with the logistics and construction crews for sites and whatnot as far as the logistics in getting projects done, but actually in the big picture, ability to -- to get compression, ability to get pressure pumping, drill rigs, etc.

Yes. Well, it -- two different areas. One, the downstream aspect of it with the compression, that has been, in fact, the catalyst that has created the opportunity that we are drilling into right now. We have spent -- some starting in 2003, we spent $13 million to enhance our deliverability into the pipeline with added compression. We expanded our compression -- our deliverability with that investment in 2003 of about 46 million cubic foot. We continue to enhance the infrastructure with the investment in compression.

And, also, additional pipelines that extend out into the areas on our acreage, and as you're aware, we have over 1 million acres up there, on our acreage to open up new areas for -- for development. So with the pipeline infrastructure investment and the compression infrastructure investment, we have expanded the deliverability and now able in our -- in our four areas out there to scatter our operation and allow us to drill more wells.

I'm going to let Mike Walen talk just briefly about maybe the rigs and any service issues that we see up there, if you will, Mike.

Sure. Jerry, we've -- this year, we have actually tested long-term contract eight, nine rigs. And our peak rig utilization will be nine rigs later on this year. And I think that if we do our planning early enough, we will be able to pick up additional rigs to expand our program.

Services, again is just a matter of contracting and forward planning. We have had no problems getting the services that we need. Although, I will say that costs are escalating and, also, there can be shortages of profit and also nitrogen that we use in our frac -- fracture stimulations. But from -- from a service and an equipment standpoint, we're in good shape in Appalachia and I anticipate that to go forward into '06, too.

Okay. So you have eight or nine rigs on longer-term contract now.

Yes -- .

So you'd be looking to -- at -- at whatever time, continue those contracts and see if you can pick up a couple more.

Yes.

Okay.

We have our rigs contracted for our entire 2005 program.

Okay.

And we think that we can -- we can extend those contracts and find additional drilling rigs to expand our program next year.

Okay. And what about workover rigs?

Again, they -- they are available and we -- we keep them very, very busy. And so far we have not had an issue of getting the equipment that we need to do our workovers and -- and the completions.

Okay. So while it may be fair to say that you are seeing the price effects at the overall oil patches seeing, certainly -- you talk about things in the West where people are -- can't find a rig or even I've heard some short supplies of workover rigs. That actually get -- actually getting equipment's not an issue, it's just the discussions and how much you pay for it?

Really, our team in Appalachia has done a -- an excellent job of managing our costs back there. We -- we are seeing inflation in costs in the East, but nothing to the scale that we're seeing in the Gulf or out West. So in that sense, it's a very attractive place to operate.

Okay. Very good, gentlemen. Thank you very much for your time this morning.

Thank you, Jerry.

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

Okay. Misty, I appreciate it. And, again, thank you again for your interest in Cabot Oil & Gas.

This concludes today's Cabot Oil & Gas first quarter conference call. You may now disconnect