Coterra Energy Inc (CTRA) 2002 Q4 法說會逐字稿

Thank you for standing by. Good day everyone. Welcome to the Cabot Oil and Gas quarterly results conference call. Today's conference call is being recorded. Today's presentation will be available for replay at 12:30 eastern time through February 26 at midnight. You may access the replay by dialing area code 719-457-0820 or 1-888-203-1112 and entering the pass code of 556856. Again, area code 719-457-0820 or 888-203-1112 and the pass code of 556856.

At this time, for opening remarks and introductions I would like to turn the conference over to the Chairman and Chief Executive Officer, Mr. Dan Dinges. Please go ahead, sir.

Thank you, Phil. Good morning. Thank you for joining us during this fourth quarter and annual earnings conference call. I'm Dan Dinges, the chairman and CEO of Cabbot Oil and Gas. With me today I have several members of our management team. I have Mr. Michael Walen, Senior Vice President; Scott Schroeder, our CFO; Jeff Hutton, our VP Marketing; and Chuck Smyth, our VP Controller.

Before we get under way our attorneys have asked that I share the following, and let me read. The statements regarding future financial performance and results and the other statements which are not historical facts and contained in this release are forward-looking statements that involve risks and uncertainties including but not limited to: market factors, the market price of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in the company's Security and Exchange Commission filing.

The comparative figures that we released recently reflect two different extremes. As you all are aware, 2001 was a year that started strong with price realizations over $9, but quite unexpectedly ended soft. 2002, just the opposite with lower price realizations to start the year, but yet momentum building each quarter until today, and this is the prices that we enjoy today. We had a soft period in 2002 was when we put together our 2002 capital program. As a result of the full year financials, they fell short of our prior year, while the fourth quarter results, I think you'll see showed a dramatic improvement. As highlighted in the press release, we posted 2002 net income of $16.1 million or 51 cents a share. We had discretionary cash flow of $178.8 million or $5.63 per share. For the fourth quarter, we reported a net income of $8.7 million or 27 cents per share, and discretionary cash flow of $58.1 million -- excuse me -- or $1.82 per share.

On our production, we were relatively pleased with our production profile for 2002. For the full year, the impact of lower commodity prices was offset by approximately 12% increase in our equivalent production year-over-year. 2002 we produced 91.1 Bcfe compared to 81.1 bcfe in 2001. The increase was primarily driven by a full year of Cody acquisition production, and that accounted for about 8% of the increase, and we had -- also had about a 4% organic growth in our production. That was really a direct result of successful drilling in both the Gulf Coast region and our east region.

Quarterly production was down slightly, but we do expect this to pick up once some of the wells that we have recently drilled come on line. Those are the wells that we announced last night that I'm speaking of. Let me review a couple of those. In the Gulf Coast, we drilled successfully a well in the Chacahoula field. That's in LaFourche Parish, Louisiana. That's the DS&B 113. Cabot has a 100% working interest in this well. We didn't spud the well until December 15, however we got the well down fairly quickly. We found 64 foot of pay in Cypress section. The well was brought on line just a -- less than a week ago, and it's flowing 5 million a day at 340,038 flow tubing pressure.

Another well we drilled down in our Redfish Bay Area that's down on the Texas Gulf Coast; an area we have had a number of successes. We have -- and did report the success of our south 10352 number 2, the Harbor City well. We have a working interest at 52.25%. We reached TD on that well on February 9 of this year. We -- TD is 14,294. We found over 100 foot of Frio pay in our objective section. We do expect that well to commence in March. The Hayworth well, another exploratory well. The name of the well, Ellender number 1, the Hayworth prospect. We have a working interest of 37.5%. That's before casing point and after casing point we have a 50% working interest. We found 47 foot of pay in our objective section. That well is TDed at 12,000 feet. We expect that well to begin production in March also. A key well that we've talked about several times that is still drilling is our Tasso prospect. That's the rigs number 1. We have a working interest in that well currently of 43.75%. Before casing point and a 56.25 after casing point. We didn't get this well spud until December 23. We are currently drilling below 12,000 feet. We are going towards an objective depth of 16.5. Fairly significant well for Cabot. We have these gross reserves unrisked between 75 and 200 Bcfe. We have our fingers crossed on this prospect.

In the release we also mentioned four Rocky Mountain wells that we drilled in the second half. All these wells were drilled in the Double Eagle field which is located in San Miguel county, Colorado. All four wells we had a 100% success rate. I'll go over a couple of the statistics regarding those wells. Fossil fed 218, that well was spud in July. We began first production in October. We have it at a reduced rate at this point in time at a little over 200 Mcf a day. Flow tubing pressure is 880 pounds. That's producing out of the cutler formation. Our fossil fed 113 was spud in August. We had a couple rigs out there in the field. That well a little bit more substantial, flowing at 6.3 million a day in 42 barrels. Flow tubing pressure is 1840. That was completed in the Honaker Trail. We began production at the end of October from that well. The fossil fed 420 wasn't spud until September. We found both Honaker Trail and Cutler pay it's flowing at 2.5 million a day and a flow tubing pressure of 1,220 pounds. We didn't begin production from that well until the last day of 2002. We fossil fed 118. We found Honaker Trail pay pay. That well is flowing at 8.1 million a day. The flow tubing pressure is 2,220 pounds. We began production from that well in the middle of January. Cabot operates all four of -- all of these wells. We have a 37.5% working interest. The field is producing approximately 30 million cubic feet a day from seven wells. We do have scheduled in our 2003 program for additional wells. We will begin drilling these wells in July or August time period. This area does have a restriction of -- and a drilling window from July to December.

When you put all these wells together, I think it's going to help jump start our 2003 production levels, and let me give you our guidance for our upcoming year. We anticipate -- and I'll break this out into our three different regions, the Gulf Coast, the east and the west. We anticipate the Gulf Coast to average between 8,000 and 8,300 barrels of liquids per day. The east predominantly gas, liquids will be 90 to 100 barrels per day. The west we will produce between 450 and 500 barrels a day. So cumulative liquids production, our guidance is about 8500 barrels to 8900 barrels per day. Natural gas, in the Gulf Coast we anticipate production between 86 and 89 million a day. The east 45 to 47 million a day. The west 62 to 65 million a day. So our total guidance for -- on a Mcf equivalents basis is between 244 and 254 million cubic foot equivalent a day. We do anticipate a slight production increase year-over-year. We do, however -- our first quarter will be down slightly from fourth quarter partly due to natural decline, but also due to the timing as I have just mentioned of some of these recent wells we've drilled.

On the strength of some of these wells, and looking at the capital discipline we employed in our 2002 program, some of the cost control efforts we implemented, and improved pricing, we are pleased to report a significantly improved finding cost in 2002 versus 2001. The $1.07 reported in the press release for additions and revisions is our lowest cost to find number we have reported in a couple of years. And that's despite a shift, really, from some of our -- a larger percentage of our capital being shifted to the Gulf Coast which are all -- you are all aware is a higher rate of return area. The company was able to replace 136% of our reserves through all sources. On additions only, we accomplished a 77% replacement due to our limited program. However, this was 9% better than we had anticipated.

Pricing this past year, Cabot averaged realized gas price was $3.02 per Mcf compared to average realization of $4.36 per Mcf in 2001. Oil prices also reflected a decline, dropping from 24.91 to 23.79 per barrel. To provide a means of price protection in 2003 and beyond, as we have announced, we have been active in layering in hedges. We now have 66% of our natural gas and 45% of our oil production covered by derivatives. At a minimum combined price of $4.38 per Mcf, and $27.35 per barrel. These rates -- these minimum rates that we've set in for this percentage of our 2003 production is $1.36 per Mcf and $3.56 per barrel higher than our 2002 realized prices, which is going to provide us a strong economic base for our 2003 capital program, and provide, also, an opportunity for debt reduction. Going forward, we will continue to actively look for opportunities to hedge additional quantities both oil and gas. Obviously we have limited volumes that we're able to hedge in 2003, but we will continue to look forward to 2004.

Now, let me review our unit cost for the year. Operating expense averaged 55 cents per Mcfe. Taxes other than income 27 cents per Mcfe. Interest expense 31 cents per Mcfe. All at our below our budget I'm pleased to say. Expiration expense was down prior year due to our smaller exploration program. In line with our previous guidance, G&A remained below $25 million and that is if you exclude costs associated with the CEO retirement in the second quarter. Additionally, as it relates to expenses, the company has reduced our employee base by 19 since October. As we continue to make efforts to manage our overall cost structure, this did result in charges to earnings that are incorporated into our fourth quarter and first quarter guidance.

In terms of guidance for 2003, operating expense is budgeted between 55 cents and 60 cents per unit. Taxes other than income budgeted at approximately 4 cents. Interest cost around 25 cents per unit. Exploration is budgeted between 42 and $48 million. G&A between 24 and $25 million. Oh, let me give you a correction. On the taxes, other than income I said 4 cents, that is between 31 and 35 cents. Okay.

One thing we are going to try to do with our unit costs, we are going to try to place these out on our website so we'll be able to provide all our investors an opportunity to review them. We did make a press release recently regarding the [Kurdin] field. I'm not going to spend a lot of time on this issue. I think really, to sum it up, one analyst made the proper assessment and I'd like to basically quote, and the quote is, "The true economic value which Cabot gave to the field is an acquisition. In its acquisition economics was approximately $14 million which is the current appraised value, not the 90 plus million value that was included -- that included the gross-up. So this is not a situation where Cabot is writing off a field which they had valued much higher, it's purely accounting gymnastics where Cabot has written down the value from $308 million, a phantom accounting number to the $230 million which was the actual purchase price of the Cody acquisition." All I really have to say is we concur with that assessment in that quote of the issue.

Moving to the 2003 program and our exploration program, which is really the meat of our business. Our 2003 drilling program has 108 wells scheduled this year, which includes 30 exploratory wells compared to only nine wells statused in 2002. The Gulf Coast region has a total of 43 wells of which 18 of those are going to be wild cats. That will lead our exploration effort during the 2003 program. I'd like to review some of the key exploratory wells that we are looking forward to this year. One is the Beaudreaux prospect; that's going to be in south Louisiana. Cabot will have a 50% working interest in this well. We anticipate spudding this well in the second quarter of this year. It's going to be a 17,500 foot test. It has a dry hole cost exposure gross of $4.1 million. Fairly significant reserve potential with a gross unrisked exposure of 50 to 140 Bcfe. Another prospect of note is the Ellis prospect, also in south Louisiana. Cabot has a 55% working interest. We anticipate this to spud towards the end of the second quarter. It's going to be a 14,400 foot test. Reserves on a gross unrisked basis 30 to 60 Bcfe. Dry hole cost is approximately $2.5 million gross. We have an exploratory well in the Gulf of Mexico, at least we bought last year's lease sale high on 68. We'll have 50% working interest in that prospect. That will be an early fall well. The prospect size is 50 to 150 Bcfe of gross unrisked reserves. Dry hole costs, approximately $4.9 million. If you combine these three wells, three of the 18 wells we have in the Gulf Coast region, it's going to expose Cabot to about 80 to 175 Bcfe of net, unrisked reserve potential. We'll have a dry hole expense on these three wells of approximately $6 million net.

Moving to the Rocky Mountains area, we are going to have our most aggressive exploration program in the Rockies during this year. We have six projects planned. I'll mention several of them. One is the Gold Nugget prospect. We'll have a 50% working interest. That will spud in the mid-2003. It's going to be drilled in the Wind River basin. It's a 12,500 foot test. Fairly significant reserve exposure. High risk, but fairly significant reserve exposure of 120 to 300 Bcfe of gross, unrisked reserves. Dry dry hole, cost however, is only $1.6 million. Another fairly interesting prospect in the Rocky Mountains area, Sabre Tooth. Cabot will have 38% interest in this well. That will also spud in mid-2003. The depth of this well is 6,000 foot. This is going to be another significant resource exposure of 70 to 200 Bcfe of gross unrisked reserves. Dry hole cost we are anticipating less than $1 million. Another that we will be drilling, this well the Hard Left prospect along with the Sabre Tooth is in the Paradox basin. We'll have 38% of this particular prospect. It's a 10,000 foot well. It will have grocery serves unrisked of 24 to 60 Bcfe. And a fairly nominal dry hole exposure also on this well of $1.4 million dry hole cost. These three wells in the rockies expose Cabot to just under 100 Bcfe to 250 plus Bcfe of net unrisked reserve potential with a fairly nominal net dry hole cost of $1.6 million. The increased drilling program this year will expose Cabot to significantly more upside than we saw in our 2002 program, and we're really looking forward to implementing this drilling program we've set forth.

Overall I'm quite pleased with our performance this past year. As I mentioned I'm looking to our 2003 program not only in terms of the exploration potential, but also expansion opportunities that we have, our continuing operation efficiencies that we are implementing. I believe with our drilling inventory, and you couple that with our development base, it's going to allow us to continue to balance our program as Cabot has traditionally been able to do. However at the same time I think what you are seeing creep into Cabot's program is considerably more upside opportunities like the prospects we are going to drill this year. Like I mentioned, I'm not only excited about the program, we are also going to expand our operation into new growth areas into the Gulf of Mexico and Canada. Myself, along with our team is looking forward to the challenge of finding additional exposure opportunities and growth opportunities in these areas. With the current product pricing, the market conditions, in addition to the hedge positions we have layered in, we are not only going to be able to implement this capital program with comfort and possibly look for future opportunities this year, but it's also going to allow us to accomplish some of our debt reduction program and continue to strengthen our balance sheet. Again, overall, I think Cabot's positioned very well, and 2003 is going to set up for a great year for Cabot and I'm looking forward to it.

Phil, with that I'll be happy to answer any questions that our audience might have.

Thank you, Mr. Dinges. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touch-tone telephone. If you are using a speaker phone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you have signaled us. Once again, that is star one to ask a question. We will pause for just a moment to assemble our roster. In our first question comes from Ellen Hannah with Bear Stearns.

Good morning.

Good morning.

Couple of questions for you, Dan. One on your Rocky Mountain wells are you carried on these costs? Why is the exposure on the net dry hole cost so low?

No, we're not carried on them, Ellen. Like the Gold Nugget the dry hole cost on that well is on the $1.6 million and we have a 50% interest in that. The gross dry hole cost on the Sabre Tooth is going to be less than a million dollars. And on Hard Left, the dry hole cost gross is $1.4 million and we have 38% of that. So one of the things that this program in the Rocky Mountains is proving up for us, which is the when we started this process about 2.5 years ago is to provide opportunities that are going to expose Cabot to significantly higher upside opportunity for the reduced risk dollar exposure. And with six exploratory wells scheduled for the Rockies, this really is the first year we are seeing the fruits of that effort.

Okay. One other question. On a couple of the discoveries that you announced, the Harbor city and the Hayworth do you have any reserve estimates just an idea where we can see where you came in versus the previous estimate of what the reserves might have been?

We don't have -- I have not seen because of the recent drilling, I have not seen all of the reserve estimates. I can say that, for the most part, the numbers came in close to pre-drill expectations.

Which were kind of a broad range of sort of 50 to 100 Bcfe on that. Are you at the low end? The high end? Or in the middle? Do you have a feel for that?

Well, that range will be on the low end of that.

Okay. Very good. Thank you very much.

Uh-huh.

Next we'll hear from Sean Reynolds with Petri Parkman.

Good morning.

Hi, Shawn.

Was wondering on the paradox, I thought at one point in the Double Eagle field your facilities were maxed out at about 30 million a day. Is there more capacity there if you had some expansion at the facility?

Yes. We did provide some expansion capacity to that field in 2002. I'll let Mike Walen briefly review briefly what we did out there.

We went out and we spent quite a bit of capital to upgrade our liquids plant at Double Eagle, and that plant is capable now of only producing about 30 million a day. We are looking at setting some additional compression downstream from the plant that's going to reduce our line pressure. And after that's done this year, then we should be able to see our plant capacity increase 35 million a day or even north of that.

And you've got plenty of well head capacity to push that through?

Yes. Our wells are not flowing at full rate out there.

Right.

Okay?

Presume if you had success at Sabre Tooth or Hard Left you would need more capacity, or do they have their own facilities?

Sabre Tooth if it's successful will need its own facilities because it's quite a ways away from Double Eagle.

Right.

Hard Left is just down a few miles from Double Eagle and that field could, conceivably, be linked to our plant.

Okay. In the Gulf Coast you talk about 18 wild cats, you detailed three which have very large net unrisked reserve exposure. Could you give us an idea of the total potential impact from all 18?

I can -- of course I just looked at the -- what I would call the significant wild cats in the gulf. We are dealing some shallower potential wild cats one to five Bcfe type things are good economic opportunities, but they aren't really impact. Looking at our other program. We were looking at eight impact wild cats in the Gulf Coast this year. And our net, unrisked exposure on those eight prospects is anywhere from 250 Bs, maybe up to 500 Bs.

Net unrisked?

Yes. I also included in there the wells up in the Rockies, the Gold Nugget, Sabre Tooth, Hard Left, plus we have one called Nicky and one called Raider that will be drilled later on this year. Large gas prospects and those prospects are also in that number.

Nicky and Raider in the Rockies?

Yes, sir.

Okay. Great. Okay. Thanks.

Thanks, Sean.

Once again, if you would like to ask a question, press star one. Moving on we'll hear from Ken Bier with Johnson Rice.

Hey, guys, good morning.

Hi, Ken.

One, stay on that last comment. I'm assuming with some of the rocky mountain plays, that the single well kind of $1 million type well, with that -- what that's setting up is a cookie cutter type program so you're not talking about any substantial reserves per well, what you're talking about is a follow-on development program that would be mini wells, right?

That's a good point, Ken. As you know the rocky mountains are not like the Gulf Coast in what you get per well. If successful on any of these, it would set up a development program that would -- would proceed to capture the reserve numbers that we've outlined.

Okay. And it's a few more, just on the housekeeping item. DD&A guidance for the year, I think I may have missed that, but I don't think I caught that if you did go through it.

Well, Scott has that right at his finger tips, Ken.

Ken, DD&A is going to range kind of between $1.17 to $1.22 depending on the period.

Scott, while I've got you and while you have that piece of paper in front of you --

That's from memory, Ken.

Just kind of thoughts on reported taxes and then deferred portion of that, just what kind of rates you're looking at?

We're deferring about 50%. The deferred tax line is getting jumbled up by the OCI component that you will see when we file the K later this week.

Okay. And then reported taxes would be still somewhere in that 40 --

38%.

Yeah. Okay. Couple other real quick ones. If I look at just your Cap Ex of $150 million versus any type of stab at cash flow, it looks like you'll have excess cash. How does -- how do Scott and Mike kind of tussle between the excess dollars? Is that mostly geared towards paying down debt, or because it's so geared -- since the program's so geared towards an exploration program do you then turn around and put the money into a development program of any sort of exploration success?

Well, Ken, I have them at each end of the table as we speak, but we will address some of our debt with that excess. In looking forward in anticipation, I think we will see opportunities throughout the year that, if Mike feels strongly about a particular drilling opportunity, he's going to, and certainly been instructed to bring it to our attention, and we're going to look at those opportunities. One of the things that we've done from just a strategic standpoint is we've set our capital program, based on what we have in inventory. Excess is not digging into our inventory, the excess is the opportunities that we are going to have available today if we take advantage of them, and they would be gone tomorrow if we didn't, but not part of our inventory.

Okay. And then just on the production side, the fourth quarter production, do you have an estimate now kind of looking backwards as to what the actual impact of Lilly was? I know you didn't have a lot of Gulf of Mexico production that was affected, but you did have the A2 FA production that was affected for some period of time.

It was affected and we had ramp-ups after the shut-ins and things like that, so we think it was right at 200 million cubic foot.

So .2.

.2 Bcfe, yeah.

Then your comment on first quarter being slightly down versus fourth quarter, even though you get a little bit of a catch of that .2, you really are just talking about fighting a decline curve and not having your drilling program ramped up, is that fair?

That's a fair statement.

And then my last comment just being from south Louisiana to name a prospect the Beaudreaux prospect, somebody's got to change that one.

Well, we have his brother Thibedeaux later.

I knew that was coming. Thank you, guys.

Thank you.

If you would like to ask a question, please press star one. Mr. Dinges, it appears there are no questions at this time. I'll turn the conference over to you for final and closing remarks.

Thank you, Phil. With no further questions, I want to thank all of you for tuning into our conference call. I hope that you all are looking as forward to 2003 after you've heard this conference, and certainly we are. Thank you again for your support.

Thank you. That does conclude today's teleconference. Thank you for your participation. At this time, you may disconnect.