Ranger Oil Corp (ROCC) 2006 Q1 法說會逐字稿

[Good morning] ladies and gentlemen and welcome to the Penn Virginia Corporation first quarter 2006 earnings conference call. [OPERATOR INSTRUCTIONS] It is now my pleasure to introduce your host, Mr. Jim Dearlove, Chief Executive Officer of Penn Virginia Corporation. Thank you, Mr. Dearlove, you may begin.

Thank you, and good morning. I'm joined today in [inaudible], by Baird Whitehead and Frank Pici and Nancy Snyder. Franks is our CFO, Baird runs the oil and gas piece, Nancy is General Counsel in Kingsport. By Keith Horton, who runs the coal segment of our MLP, Forest McNair, who is our Controller, and, in Houston, Ron Page, who runs the mid stream segment of our MLP. So, we've got the first team here today, we will try to tell you where we are.

For the year, I won't try to read the press release, but I'll follow the order of it. We had a good quarter, $24 million of net income, up considerably from the first quarter of '05, and not surprisingly given the difference in prices and the difference in production between those two quarters. While it was mostly price driven that net income number, the operating income number, cash flow numbers, and operating cash flow numbers, all those numbers listed in the first few sentences of the release, are all up significantly, and that is mostly prices. Even though prices are down relative to the fourth quarter of '05, they're certainly up considerably over what they were in the first quarter. But production is up too. And, in fact, we had a record quarter for production this quarter. And we're also getting some healthy contributions from PVR. So, we will try to talk about that a little bit.

So, I think what I'll start with here is oil and gas. We put out an operations release on April the 27, which I'll refer to a little bit, but subsequent to that release we had events occur with two wells, which are reported in this May 4 release. One was a dry hole in south Louisiana. Which resulted in an exploration expense of $2.4 million. The second also in south Louisiana is apparent discovery, it's significant to us that that is a prospect generated by Penn Virginia. The operator happened to be Brigham, we have about a 40, a little over a 40% working interest in that well. We would hope production would start in the third quarter. So that's the business, good news and bad news.

Returning to the release, and as I said a minute ago, production in the first quarter was a record at 7.3 Bcfe, 14% higher than the first quarter of '05, and flat or little above what the fourth quarter I, believe, of '05. The drivers, we continue to do well with our Cotton Valley production, our CBM production in the east, and our [inaudible] production out of Mississippi, south Texas, also made a contribution to this first quarter. We detailed our CapEx also in that 27 April release, which I don't want to read all of it to you. We spent about $47 million in total 28 million, or 60%, of that on development drilling, just under 10 million on, or 21%, on exploration. As is noted in the May release the board at our May 2, meeting, which was Tuesday of this week, following our annual meeting, increased the authorizations for CapEx for oil and gas to $235 million, up about 13%, I believe. Most of that, virtually all of that, is to fuel increased activities in the Cotton Valley. There is some mention in there of the Williston Basin, we did do some additional leasing in the Williston Basin.

Right now we have got three rigs running in the Cotton Valley, expect two more hopefully in the latter half of the year. We expect to drill about 51 gross wells, on our--including beginning to explore more extensively, I hope, on a hundred percent working acreage. I don't want to go through all of this. I think, one other thing of significance, is we have got three rigs running in our horizon CBM program, we drilled eight successful wells so far. What's significant there to me is CDX was taken over, or bought out, what ever the proper term is, by trust company of the west, which is a good thing I think for both companies and should provide CDX with more financial security going forward. We continue to work on and expect this year to resolve the capacity or take away issues in that part of the world for us. And that hopefully will occur in the latter half of the year, which would allow, allow, not guarantee, that we would be running another couple rigs in 2007. The rest of it's sort of covered in the release.

Operating income for oil and gas was about $33.7 million for the quarter, way up over again the first quarter of '05 and prices, again, were about 76% of that net increase. The expenses and those issues are [inaudible], but they are detailed in the report, the release, I don't think there's anything there that's significant. If there's something that troubles any of you of course you can ask us.

Turning over to PVR, and being fairly brief, we went through this an hour or two ago, some of you may have been on that call, regardless we do summarize it in this release. The partnership itself had a record quarter for distributable cash flow of over $25 million. More than 50% increase over the corresponding quarter in '05, a lot of that of course, is because of the presence of the mid stream assets in the mix this quarter where they were only partially in the first quarter of '05. Virtually every financial measure of the partnership was up. I would remind you that -- not virtually, every, as far as I know, measure was up. Keep in mind that we split the units in April of this year. So if you're doing something per unit comparison, just do keep that in mind. We announced a distribution increase, not increase, pardon me, a distribution of $0.35 a unit for the first quarter of 2006. We did increase our distributions in January, but that was actually effective for the fourth quarter of 2005 and then going forward.

Coal, very briefly, had a very good quarter, $17 million of operating income. 22 million of royalty revenue, which is 24% over what it was in the correspond quarter of '05. We did get, we have enjoyed some higher prize and therefore, some higher royalty rates on a per ton basis, average royalty rate was 2.90, which is higher than it was, I believe, at any time or any quarter in 05. Some of that is steam prices, but a lot of it is the fact, that our leasees in West Virginia in particular have been able, and maybe Virginia, have been able to convert some of their steam coal to met coal. Met coal is getting a much higher price. Coal production, at 7.7 million tons for the quarter, I believe, was a record for the coal company, I believe.

On the mid stream side, margins and volumes are running ahead of our expectations. Operating income was about $5.8 million. And that's before a, as we tried to detail in the release, before a $4.6 million non cash charge, which was charged to the cost of gas purchased. [inaudible] we took that charge really to reserve the amounts related to balances that we assumed as part of the acquisition for which we're still trying to achieve collection, we're still pursuing collection. So, a non cash event, but it did hit the numbers.

I guess, by way then of summary, and before I let Frank take you through the guidance, although gas prices certainly are lower today than they were in the fourth quarter of 2005 and storage is at fairly record levels, we remain very confident about how we're positioned. Our key production areas and exploration plays that we're involved in do not require super high prices in order to be successful, and by successful, I mean, return our cost of capital. I think in most cases, virtually every case, $5 gas is more than adequate in many cases lower than that. We are somewhat hedged, we're between 30 and 35% hedged. Our PDB production throughout the rest of this year. Our hedging mechanism has been collars, the average floor is probably right around $7.50, the average ceiling around 1250. So, while as I say it's a bit of a down period relative to late last year, in terms of gas prices, we're quite comfortable with our positioned. We continue to try to diversify our exposure to new areas and spank the old ones. For example, the Cotton Valley leasing activity continues at a fairly hectic place. The horizontal CBM with the trust company in west relationship, and we're doing some new leasing inside our AMI with them, as well as or trying to, as well as trying to do leasing in northern west Virginia and other places in the east where the thrust is on CBM and/or eronion shale. Our Wilson Basin acreage is now about 84,000 acres. We have a position in the Fayetteville, New Albany shale, and as I said one in the Devonian shale, so the shales, the CBM, we're working pretty hard, likewise the exploration program into Texas, south Texas, and south Louisiana continues.

For PVR, markets look good for coal. Fax spreads are at record levels. We're looking for a number of, add a number of acquisition opportunities, both in coal and in mid stream, although it's premature to announce anything I think we're pretty comfortable that we're going to have a deal or two to announce that will look pretty good. So, with that Frank, I'll let you, if you would, take people through the guidance, and we will try to answer some questions.

Okay, sure, thanks Jim. Good morning everybody, this is Frank Pici, I'm ,CFO here. Before, I get into the guidance one thing I would like to mention briefly is the way our hedging activity impacted us in the first quarter. If you look at our income statement you will see a net loss from derivatives of only 0.2 million, but that includes a gain on the oil and gas side and a loss on the mid stream side, should offset each other. What that relates to is a number of our hedge positions, because of the really the way the basis differentials have gone out of correlation with the underlying commodity after the effects of the hurricanes last year, has resulted in us having to go away from cash flow hedge accounting and go to mark to market accounting on a number of positions, both in our oil and gas and our mid-stream hedges. That's what you're seeing there in terms of the impact in the derivatives line on the income statement. Going forward, we do plan to adopt mark to market hedge accounting on all of our positions that's really to take the noise out of the equation, if you will, and make it just easier to understand than it tends to be now with all the various movements in the income statement and wall sheet that take place with ineffectiveness and trying to qualify for hedge accounting and a lot of things like that. So, What's important going forward, I know those of you who build models on us, we list out our positions in detail for you, so that you can understand, based on your view of commodity prices, how those hedges would expect to settle out. So we hope to have information for you in the future that makes that very easy to understand.

Getting into the guidance for a minute here, as you know we're presenting full year guidance at this point and I guess I would characterize it, as a whole, really just a little bit of tweaking and tightening of some of the guidance numbers. For example on the oil and gas segment, production wise, we're at the same range of production that we gave you at the beginning of the year. What we would expect to happen, we had first quarter production of about 81 million cubic feet equivalent a day. As we go through the year we expect that to increase, primarily as a result of what Jim has already talked about with the investment we have gotten in the Cotton Valley play, and also the horizontal CBM play in Appalachia. So those two areas will probably be the primary drivers for production increases as we go through the year.

With respect to expenses, both lease operating, or what we call, direct expenses, and exploration, the general cost environment is increasing, we have seen that's reflected in our guidance for direct expenses. Our exploration expense, the range there has been reduced a bit, and that's really a function of our capital expenditures program, I think as Jim alluded to, although we have increased the program we have a little less money dedicated to exploration than we had in our original budget. DD&A, on a rate basis, we expect to be a little higher we originally anticipated, once again that's upward cost pressure. We have also noted in the guidance the spread on capital expenditures and that's really in relation to what Jim has talk about.

On the coal side we have got a first quarter production on our property of 7.7 million tons. The range we have got in the guidance, of course, if you annualize [inaudible] it you're a little below that [inaudible] in that range. And what we would expect to see happen is in two properties that we control in particular, one our federal number two property in northern Appalachia and our what we call the Panther property,which is a sub leased property with a long-wall on it, that moves on and off of PVR's lease. We expect that long-wall to move back on to PVR's property in the third and fourth quarter. That accompanied with federal number two, which is a Peabody operated property, should fuel an increase in coal production on our property.

On a revenue basis, on average royalty per ton basis, even though we realize 290 a ton, our guidance for the full year is still a bit under that. That's primarily a mix issue. Really affected by this, to some extent, by this Panther sub lease, this long-wall mine, which has a lower realization on it, although it's of course positive to revenues and margin it's still on a mixed basis it tends to bring the average down a bit. The other thing here on capital expenditures, we're in the same range we have been in on the coal side. We have continued to complete the construction of processing and load out facility on our [Wheland] property in eastern Kentucky, that's the primary driver for the CapEx number in the coal side.

On the natural gas mid stream segment you will see that we have increased our inlet volumes at this point as a result of our historical experience here and as we go through time you will see we're now in the range of 130 to 140 million feet a day. As Jim has mentioned, the processing spreads there have been very strong. While we don't predict them to be quite as strong for the remainder of the year, it's still a very good environment to be in. Otherwise, the rest of the expense numbers there, the capital expenditures numbers, are pretty much in line with what we have given you in prior guidance, so I won't elaborate, I will just leave it open for question. So with that Jim, I guess I would turn it back over to you.

Okay. Well, Dan, we'll turn it over to questions then. Thank you Frank.

Ladies and gentlemen, at this time we will be conducting a question and answer session. [OPERATOR INSTRUCTIONS] Our first question is coming from Joe Allman, of RBC Capital Markets, please proceed with your question.

Hi everybody.

Hi Joe.

This is for Jim or for Baird. Could you just talk about the horizontal CBM play just in general, how you think that's going. Has it met your expectations, any kind of constraints you still need to deal with there. And also talk about the New Albany shale. I know you folks haven't done a whole lot of work over there, but based on the work you have done, what are you seeing, and do you have some pretty high hopes for that shale play as well.

Baird, why don't you handle that.

Okay. Joe, on the horizontal CBM, yes, it's meeting our expectations. As Jim earlier discussed, we have got to get our transportation issues resolved, which we will get them resolved this year. We have got, what we're seeing on these wells, is some of these wells are making more water, especially depending on what the geological issues are, so we have some disposal issues we have to address, and those are being addressed as we speak through three different options that are at our discretion. So yes, I mean we're very, we're very satisfied with the results. We're still picking acreage up. Some of these wells make a lot of gas earlier than others, depending on the water situation, but even the wells that make a lot of water, you still see those things make a lot of gas after three to six months. So, we're very satisfied.

On the New Albany, we drilled the two wells late last year. We have one of those wells fracted. We're waiting to get a [down-hole] pump installed, which is being done as we speak. So, we expect to have that well in production here in the next week or so. The second well we will set back before we complete it, see how this first well does, and just make sure we have our stimulation as we should, or as we expect, to optimize these things. There's still a lot of unknowns associated with the New Albany. It's clearly not a slam dunk, it's a very complex play, because some areas make a lot of water in the New Albany. We're picking up some acreage in a different prospect area as we speak, to try something a little bit deeper. We definitely think it has a chance of working, but it's not going to work in all cases.

That's helpful Baird, thank you.

Our next question is coming from Dan Morrison, of Aperion Group, please proceed with your question.

Hi. Quick follow up on the H CBM stuff. It looked like there were quite a few wells drilled, but pending completion up there, on the quarter. Is there a bottleneck in service industry there or is that something that's going to continue or just timing issue.

Again, Baird, I'll leave that to you.

Dan, it was strictly a timing issue. These wells happen to be almost in one area, we refer to as our, Plum Creek lease, we acquired, I think, it was last year, a 60,000 acre lease we acquired mid last year. These wells are going into CDX's gathering system and subsequently into Columbia. When you get these wells drilled, you go back in there and you actually circulate air and water for a period of time to clean out these cavities, so it just takes a period of time to get those done. You have to get the rigs out of the way. If you're drilling, one pattern, then you turn the rig and go through the articulated well to the 180 degrees, that one pattern is sitting there for some period of time until you get the drilling rig out of the way. So, it was strictly, a timing issue it has nothing to do with anything else, i.e., transportation.

Great. Thank you.

Our next question comes Sven Del Pozzo, of John S. Harold, Inc., please proceed with your question.

How are you doing.

How are you.

Good. How much of the LOE in the first quarter was related to the down hole maintenance that you mentioned in the text?

This is your day to shine Baird.

To be honest with you, I can't remember exactly what the number is. We had, we were doing down hole maintenance in both our Mississippi, Selma Chalk stuff for installing tubing strings and cleaning sand out, those kind of things, for production enhancement reasons. And we also went back into some of these horizontal CBM wells to clean out the cavity. If I had to make an educated--$600,000,Frank, just told me so, that's it exactly.

Thanks. How should I think about that in terms of being recurring or nonrecurring, is this something that's going to happen again in future quarters.

Yes. We have a big push right now for production enhancement in Mississippi especially, so you're going to see that at least for the next year. Cleaning wells out and installing tubing strings, likewise on horizontal CBM stuff, one thing we are seeing, we go back in, and clean out these activities, we're seeing oftentimes 10 to 25% production increase that may sustain itself for six months to a year. So, These will probably be more routine than not going forward.

That's in the Selma Chalk properties for the most part.

If I had to guess it's probably pretty well split between Selma Chalk and horizontal CBM spent.

And you are getting both types of production increases, both those plays, from this type of activity.

To be honest we're actually seeing higher production increases in Mississippi Selma Chalk, even though quantitatively, because they're lesser wells we may see a 30 to 50 Mcf per day increase. Whereas, on a horizontal CBM, we may be seeing anywhere from 250 to 500 Mcf a day because of the size of wells that we're cleaning out. So, proportionately we're actually seeing a higher increase on Selma Chalk then, quantitatively on the CBM.

Okay. And, then on the increase in CapEx there wasn't any mention in the text of that being related to cost escalation. Could you go me an idea of how much of that might just be related to cost escalation.

Probably, if I had to guess, probably 10 to 15%. We build in cost escalations in, this most recent version, in the Cotton Valley because there have been some real day work rate increases. We also bill some cost increases into our Selma Chalk wells that are probably costing us another 10%, a well. So but in general I would say 10 to 15% of the total was associated with cost increases.

Okay. And lastly, what made your unit LOE go down, from comparing the fourth quarter and the first quarter.

I suspect, this is Frank Pici, Sven. I suspect that was primarily just accrual related more then anything. We had, at year end, I think we probably just accrued a bit more than we did in the quarter. But in terms of comparing, because I looked at that before the meeting, the comparisons by area, bare with me one second.

Sure.

The comparisons by type here, by type of expense, I think, really the thing that went down was some of our non-operated LOE, which is really I think what was the primary individual driver for it being lower.

Okay. All right, thank you very much.

Our next question is coming from Ray Deacon, of Harris Nesbitt, please proceed with your question.

Hi, this is Sean, calling for Ray. Just wondering if you had an organic growth rate from last year, excluding the acquisitions.

Growth rate in what?

Production growth rate.

In which segment?

Just overall, excluding your asset sales last year, sorry.

Well, this is Frank Pici. In the oil and gas side, we really didn't make any acquisitions last year, so it's really all organic. All of our growth in the oil and gas segment is organic.

So there was no sales last year.

No. Well, go ahead Frank, sorry

We sold west Texas. Early in 05, so the organic growth really is even higher because of that sale.

Right.

Which was about a BCF for the year so --

Okay. And does the impact of the CDX acquisition, does that affect your agreement with them and how is your own horizontal.

No, it doesn't affect the agreement at all. What it does, I think, is strengthens [their] financial position. One of the aspects of the agreement is, that if adequate transportation is available, they have guaranteed to provide us with a fourth and fifth rig. We're now very comfortable with [in fact], they can do that.

Okay, great, thanks.

Thank you.

As a reminder ladies and gentlemen if you do have a question it's star one on your telephone keypad at this time. Our next question is a follow up come from Joe Allman of RBC Capital Markets, please proceed with your questions.

Yes, hi again everybody. I apologized if I missed this at the beginning of the call, but could you go over the specific transportation issues you're experiencing in Appalachia.

Again, Baird I think you're probably better equipped to talk to the specifics of that.

Joe, today we're not having any problem in general where our assets are, which are almost entirely in southern West Virginia. Because we have got enough transportation on Columbia gas transmission, right now, to adequately take care of our gas. And, CDX also has transportation. The combination between us and CDX takes care of our problems. But, with the growth of our CBM program we exceed [inaudible] that we currently have on Columbia, so we have to do something else. There's two or three options as far as what that something else is. That will probably impact us first quarter '07, that's why we need to get resolved this year. Going forward, with the growth where CBM volumes in the additions of the fourth and fifth rig, we need to get additional [inaudible] transportation on somebody else's pipeline.

Okay, that's helpful. Then another question, the Gulf Coast, I know the Gulf Coast is not your main focus area, but it seems as if things are going pretty well there actually. Is that your interpretation, if so, I mean going forward do you expect to spend a bunch of money and continue drilling these prospects and generating new prospects.

Yes, I mean very much so. I mean with the discovery, [inaudible] with Brigham on Cotton, which is our [inaudible] distilling prospect, we have got another three prospects in that overall fall complex that make, that have now become less risky because of success, that's a lot of up sides. We announced a discovery on our first quarter operations update of our Santa Anna prospect, I think it was Lopez number one we refer to it as in the press release, for up-to-date information that well is currently testing 7.8 million a day, about 300 barrels of oil per day [flown with about 6,500 inaudible], so it's an excellent well. It sets up probably another two offsets, development offsets to it. So, when you expose yourself to this kind of up size, some of these things are going work and when they work it leads to development wells. So I think we're pumped up about the Gulf Coast and some of the success we're having right now.

Very had helpful, thank you.

Thank you Joe.

You have no further questions in the cue at this time, we would like it turn it back over to you for any further comments.

Thank you all for participating. I'm a little bit remote to this site today, so I can't see the list, but I trust we have a representative group out there and we appreciate each and everyone of you for your interest and your time. With that, to my colleagues, as well, thank you very much, and we will talk to you next quarter.

Ladies and gentlemen, this does conclude today's teleconference, you may disconnect your lines at this time, thank you for your participation.