Ranger Oil Corp (ROCC) 2010 Q1 法說會逐字稿

Good day, everyone and welcome to the Penn Virginia Corporation's first quarter 2010 earnings conference call. Today's conference is being recorded.

Now, at this time, I'll turn things over to Mr. Jim Dearlove, President and Chief Executive Officer. Please go ahead, sir.

Thank you, operator and good afternoon. I'm joined today by Baird Whitehead, who is our Chief Operating Officer, who will as the name implies, take you through our Ops release, and Frank Pici, our CFO, who will handle most of the financial issues that we raise today.

Let me just walk you through the release or at least the beginning of it. I'm not going to read every word, of course, but I will hit the highlights. Quarterly oil and gas production for the quarter that we are reporting on was 10.3 billion cubic feet equivalent, which is down considerably from where it was at the first quarter of last year, where it was at 13.7 and it's down a bit from where it was the fourth quarter of 2009 where it was 11.3 Bcfe. We'll get into some of the reasoning behind that in just a minute.

Operating cash flow, which is a non-GAAP measure, was $60 million for this quarter as compared to $73.4 in the same year quarter last year. Operating income, $27.1, compared to a loss in the first quarter of 2009 of $7.4 million. Net income was $13.6 million, or $0.30 a diluted share, compared to $7.2 million or $0.17 a diluted share a year ago.

A new bullet, but one that I think is important, financial liquidity at the end of the quarter for March of this year was approximately $550 million, and that compares to -- if I compare it to the first quarter, the end of the first quarter of last year, our financial liquidity was about $68 million. So a fairly dramatic improvement there.

Before Baird walks us through the Ops results, which I think is really the heart of the call here, let me just say a couple things. Compared to the first quarter of 2009, clearly we've experienced a decline in oil and gas production and that resulted primarily from decisions that we made last year where we suspended drilling from May through November. And while that saved us some cash and we didn't want to be drilling into that very low gas price environment, especially with high decline wells, we're paying the piper a little bit this year. That's one of the reasons you'll see in our Ops release that we give you quarterly guidance, which is fairly new for us, and that's just to show you that at least our expectation is that we'll ramp up quarter by quarter, going through 2010.

Another negative effect that we had to suffer through this quarter was our difficulty in getting equipment related to completions in East Texas, particularly in somewhat the Granite Wash. These are 15,000-pound equipment as opposed to the 10,000-pound equipment we can use in the Cotton Valley and use in some of, at least, the Granite Wash play. And this problem, getting equipment, is affecting many companies. In fact, pretty much every company, except the very large ones. We hope to announce a solution to that problem in the very near future, and don't expect it to have a big impact going forward beyond this quarter we're just reporting on.

Commodity prices, again, comparing first quarter this year to first quarter last year, were higher. We also, as the release says, we've had an increase in our production from the liquids-rich Granite Wash and that's priced at a premium to natural gas. What I mean by that is, roughly 35% of what you produce or what we produce in the Granite Wash is oil and on an energy equivalent basis, oil has a significant premium over natural gas. Also, there's a fair amount of natural gas liquids produced in the Granite Wash, and ultimately these two are priced at a premium and we'll expect to enjoy the fruits of that as well. As a matter of fact, we believe that we can produce gas in the Granite Wash profitably at under $4 an (inaudible).

Not to dwell on the Granite Wash, because Baird's going to talk about it more than I am from an operational point of view, but we do expect a third rig will be arriving there next month, in June. Chesapeake has five rigs running there. Our Mid-Continent team continues to generate new ideas, which exploit our horizontal drilling expertise and in fact, we've got 13 new prospects that we're pursuing, some are nothing more than strong leads and six of them are areas where we're actually leasing, and we don't want to put numbers to what this could mean, but taken at a whole there's several PCFs of risk reserves there. It's not to say we're going to be able to tie those up or a significant percentage of them, but you don't need to tie a significant percentage of that number up to make a difference.

Let me emphasize, though, we don't intend to try to turn Penn Virginia into an oil company. We focused our 2010 drilling program on liquids-rich plays to be sure, the Granite Wash, I just talked about, and the horizontal Cotton Valley in East Texas, but in the long run, we believe in gas as the fuel of choice. We think that the drilling we're doing in Marcellus and in the Haynesville in East Texas is very important, if for no other reason than the information it's giving us to guide future drilling decisions and by the way, we make money on those wells as well.

And with that, Baird, I think I'll just let you walk us through the Ops release, please.

Thank you, Jim.

I'll start off with the Granite Wash, give you some highlights. We did drill five gross, 2.2 net wells in the first quarter, two of which were completed and three were waiting on completion at the end of the first quarter. Out of those three that we're waiting on completion, two out of those three are actually in the completion phase as of right now. We drilled as the operator the Benke 1-;, we had almost a 50% working interest in it. Had an IP of over 16 million a day equivalent. The Snyder 1-5, which we had about a 53% working interest IP at 5.7 million a day equivalent.

I want to remind everybody that we put a tight curve in which is our average well of about 6 Bcf. But there are legitimate reasons, both geological and land reasons, that we will drill wells less than what we think that mean is, knowing geologically it may be sub 6 Bcf kind of wells. We have good reasons to do it and occasionally we will drill wells like that, but on the other hand we will drill wells north of 6 Bcf also for geological reasons. To remind everybody, this is 100% V tax rate of return project, flat $5 gas prices, $75 oil price. Even if you drill a 4 Bcf equivalent well, the rate of return is still around 35%, so it's still very attractive.

Since the end of the first quarter, we had TD two additional operated wells. In fact, both of those are in the process of being completed. We have two operated rigs, Chesapeake has five rigs drilling within our AMI and for the entire year now we expect to drill 41 gross, 17.2 net development wells in our south Clinton field. In addition, as Jim mentioned, we will get our exploratory program kicked off. We now have seven gross, 3.1 net wells planned. We have a rig planned to show up here in June.

I'll give you a little bit more information on some of the prospects, which I have been reluctant to do in the past for competitive reasons, but the first prospect that will get drilled is a prospect called Mountain View. It's a large prospect. It's primarily located in Caddo County, Oklahoma. We have almost 10,000 net acres in this prospect right now with a net unrisked reserve potential of about 330Bs equivalent and about 200Bs equivalent of risk. So there's not a high degree of risk, again, as I have said in the past. There's plenty of vertical penetration, vertical well penetrations that gives you a good idea what these prospects look like going into it.

Soon thereafter we're going to spud a prospect we referred to as East Sayer. It's in Beckham County, Oklahoma. It's a lot smaller size. It also has less risk, in our opinion. It will be oilier, it will be borderline oil well kind of wells. We've got about 1,000 acres. We think the net unrisked potential of it is about 70Bs with risk potential of about 50 B's. For the remainder of the year, we'll test two to three additional prospects with any of the other five wells we plan on drilling. In my view, we will probably drill more than one well, just because it's so large in size to get it adequately tested.

But right now we're leasing in six different prospects and as Jim mentioned, we have a good number of prospects teed up, ready to go, with a significant potential associated with them. In East Texas, we have drilled five lower Bossier wells since we got things kicked off at the end of last year. We just completed the Bryant 6. We just got it turned in line. We've had -- even though we have not formally established an IP rate, we've seen rates over 10 million a day with flowing pressures north of 4,000 tons. But as many of our peers in the industry today, we have cut that back because of overall concerns of deterioration of the prop frac, so as we speak today, it's about 9 million a day. We let the pressure come back up.

I realize that which rate to pull on these wells is subjective and at the end of the day, longer term, you're not really sure how much benefits you may have in increasing reserves. But we do know, the industry knows that pulling on these wells too hard, too soon is not an ideal situation and a situation to avoid. As a side note on this well, and we have not included this in our numbers, the distance of an existing well with this Bryant 6 was about 1,000 feet away of our Bryant 8. We actually did see some communication in the reservoir between these two wells and there's actually been an increase in production from the existing well, which has been producing now for about a year. Production has jumped up about a half million a day. The flowing pressure's increased by quite a bit, so this is good information to have and could help us going forward as far as how to drill these laterals, the spacing on these laterals, the direction of these laterals, all these other kind of things.

The Bryant 6 was a fairly long lateral for us. It was about 5,000 feet. We put away 15 stages. We attempted 15 stages. One of the stages we did not get away and two of the 14 stages, one stage was put away in the middle Bossier and one stage was put away in the upper Bossier.

We have had delays in getting equipment, as Jim mentioned. We expect to get caught up by the third quarter some time. Because of that, we are drilling our last Bossier well, temporarily. We're going to take that rig, move to the Cotton Valley, which means we will have two rigs committed to the Cotton Valley going forward until we get caught back up on the inventory of wells that we need to complete.

We have one Cotton Valley well that we will -- that we just TDed. We will get it fracked here in a couple weeks. It's about a 3500 feet -- skews excuse me, about a 4,000-foot lateral. We'll put away about 12 stages within this Cotton Valley. We actually drilled this lateral within the Davis B zone. We're going to do some microscopic work because of the sheer number of vertical wells we have, Cotton Valley wells we have to help us design not only exactly what direction to drill these laterals, but, of course, also in the design of the frac jobs.

And as a reminder, the Cotton Valley well is liquid-rich. We model these things with about 3.5 Bcf of residue gas with another 80 barrels of processed and wellhead liquids on top of that per million. Right now we planned on drilling eight gross Bossier wells and five gross Cotton Valley wells, but there is a possibility they may actually get switched around because of the inventory issue on trying to get our Bossier wells fracked, but we'll just have to wait and see how things go. In the Chalk in Mississippi, not a lot to say. We drilled four wells to date. Two of those are completed, which tested 1.4 million and 1.9 million a day. The other two wells that are waiting on completion will be fracked starting next week. They'll be fracked starting next week back to back since they're on the same surface pad and the plan is to drill with one rig for the remainder of the year to get 18 gross and 18 net wells drilled, this year.

And lastly, the Marcellus, we did drill our first vertical well in north central PA. We also obtained about 100-foot of full core. We have done a lot of testing. There is ongoing testing on some. Some tests we're continuing to do on that core. We did frac this well about three weeks ago. We have not seen a lot of gas at this time, but it continues to flow back some load water and chloride's increased over time. Admittedly, we would have liked to have seen some gas as of today, but from the core sign and from the information we've been able to gather, we feel we have all the right characteristics of a successful Marcellus Shale program. This includes the total organic carbons, and some of the other parameters that you look for with a positive shale play. And in any case, even though we have yet to see any measurable gas on this existing well, we still are very enthusiastic going forward about the play.

One reason that we may not have seen any gas to speak of is the frac job could have grown upward. Really the only barrier you have above the Marcellus is a formation called the lime which in our case is about 600-foot above the Marcellus and in discussing this with some of our peers and experts that we have looking at the results to date, this is not necessarily uncommon and in fact is one of the reasons why you drill horizontally to minimize this effect. We do plan on drilling four more wells this year, all of which at this time, I think will probably end up being horizontal wells. We do have a rig under commitment and that rig will show up sometime in July. And lastly, we continue to lease. Right now we have about 35,000 net acres in Pennsylvania, of which about 20,000 of that is in Northern Pennsylvania, and we do continue to expect to lease throughout the remainder of the year. So with that, Jim, I think that brings everybody up-to-speed.

Thank you, Baird. As always, a very complete report. The release, going back to the release of yesterday, provides you with some detail regarding the expenses in our oil and gas segment. I'm not going to read it to you, but as you can see the quarter to quarter comparisons are greatly influenced by the sale of our Gulf Coast and that means south Louisiana, south Texas. The assets in January of this year as well as a big drop in exploration expense and that drop comes primarily from the fact that unlike last year we don't have any standby risk charges which last year were almost $10 million in the quarter. The other differences in exploration are basically driven by timing.

Just let me, before I turn it over to Frank, talk a little bit about PVG, the MLP that we own a piece of. In March of this year, we completed the public sale of ten million units of PVG, Penn Virginia GP Holdings and then on top of that a piece of the SHU was exercised in April of this year, leaving us with about 23% of PVG. PVG owns the general partner of Penn Virginia Resource Partners, which is the co-royalty and midstream MLP that we formed back in 2001. As previously announced, on the 21st of May PVG will pay a quarterly distribution of $0.39 a unit, that's a $0.01 a unit increase over the preceding quarter, the annualized rate is now $1.56. PVA excuse me will receive about a little over $3.4 million, closer to $3.5 million for the quarter or about $13.8 million annually.

I'm not going to report on PVR in this call. I would refer you to the fact that they made a -- they had a very thorough conference call two hours ago, will be posted on their website. And I refer you to that for an update on exactly what's going on there. That is not to be evasive. There is really nothing, but good news coming out of PVR. They've formed a venture in the Marcellus with Range Resources, and are probably the lead -- will soon be, if not already, the lead sort of gatherer of gas in the Marcellus, taking it from producers to the pipelines. That's going to open a bunch more opportunities for them, but beyond that, I would refer you to their website.

With that, Frank, I would ask you if you would cover the hedging and the capital resources, credit facility, that sort of thing and then take us through the guidance, if you would.

Sure, thanks, Jim. Good afternoon, everybody.

Just to touch on a few highlights of the hedging program. In both the earnings release and the operations release we made some reference to that so it's been pretty well covered in the release. The key points there is with the hedges we had on in the first quarter, we increased our effective realizations on our natural gas sales by about $1.04 an Mcf and about $0.79 or $0.80 on our oil price realizations as well so a nice healthy supplement to the cash flow stream as a result of the hedging program. That was in total about $9 million on an absolute basis.

Going forward, I think we've said we're approximately 50% hedged for the rest of the year. We've used costless collars. The floor of that collar is $5.72. That occurrence drip today for that same period around $4.36. That provides again a pretty healthy supplement if that price drip did hold for the remainder of again. We do have positions going on into 2011 and into early 2012 as well. Of course the percentages of those as a percentage of production drop as we go out in time, but they are still, again, healthy positions with floors in the $5.50 to $6.00 range. They provide good support for us.

With respect to our cash liquidity, and we mentioned in the bullet point in the earnings release, we've got about $550 million in cash liquidity, made up of $250 million in actual cash on the balance sheet, and then an unused credit facility for $300 million. We're expecting that borrowing base in that facility to be increased here. It's a $380 million facility as we speak. We're only using, committing to $300 million of it, just to keep fees down. But we think that will go up from $380 million to over $400 million if we choose to increase it. Again, with our current liquidity situation, we don't think we'll need to increase it over the $300, at least not in the foreseeable future.

The other item would be guidance and as you look at the guidance table in the release, just to point out a couple of changes from prior guidance; and this was mentioned in the operations release and the earnings release, I believe. We've pulled the high end of the production guidance down a little bit from 51B's to 50 Bcf equivalent. One thing to point out there is that the mix of that production has shifted a bit. We've actually increased the guidance with respect to NGLs and I think that's primarily with respect to NGL production that we would expect to start to see in our Mid-Continent, in our Granite Wash production. I think we're expecting that, right now, that gas is being sold as wet gas. We do, of course, get a BTU premium for that, but as we begin to see those volumes get processed, we would expect to see a little bit better margin from a revenue standpoint as those NGLs get extracted and sold to the market. You would expect to see a little bit of an overall price improvement, if you will, at least on a relative basis compared to where we are today.

On the other items, there's not really a whole lot of other changes. The exploration guidance and the expense section was tightened a bit. Otherwise, no real changes on expenses from what we had guided you to in the operating side. The center of that guidance table relates to PVR and, as Jim said, you can refer to their conference call in more detail in their release if you'd like to get more color on that. And on the corporate side we increased our corporate G&A guidance to allow for some additional expense items related to the reorganization that's been mentioned in prior releases.

I think otherwise that's pretty much it, Jim.

Thanks, Frank.

Just before I sum up, I omitted to tell you that while we are -- have reduced greatly our holdings in PVG as is obvious in looking at the release, we still file a consolidated set of statements and we like to remind you that if you want to see what PVOG, the oil and gas company looks like on an equity basis, I refer you to page ten and 11 of the release.

And let me just sum up before we take questions. You heard us refer to this a couple times, Frank did, and I did, but compared to last year at this time, Penn Virginia Corporation is in a much stronger position. As we said, our liquidity, our financial liquidity, has improved to $550 million compared to the $68 we had at the end of the quarter last year and as Frank just pointed out, that's without stretching our revolver to its -- the limits we could stretch it to. I think our strategy is more focused now than it was a year ago. We have -- we are engaged in a few high profile, high potential, high return plays. And our structure, while complex, is much less influenced by our affiliation with the MLPs.

This is clear as I watch the stock market today and our stock is getting beat up like everybody else's and like the market is, but the world and the economy clearly remain in turmoil. And there's enormous uncertainty out there. I'd be less than candid if I told you that I could predict the price of gas this summer or next winter or just exactly how the world is going to turn, but I do believe that what we've done over the last 12 months and what we're continuing to do now positions and prepares us to be an increasingly important player in the domestic E&P industry under virtually any circumstances.

With that, operator, I'd be happy to take questions.

Absolutely, Mr. Dearlove. (Operator Instructions). We'll go first to Steve Berman with Pritchard Capital Partners.

Good afternoon, guys.

Baird, can you talk a little bit about this -- if I'm pronouncing it right, cat or Caddo County in Oklahoma, I'm looking at county map and a) has there been any Granite Wash activity there by anybody and also it's fairly close to where there's been success in the Anadarko Woodford shale. I don't have the stratographic column in front of me, but is this anywhere near where that activity is and do you have rights to that, if there is any potential for Woodford there?

Steve, we have not spent a lot of time on the Woodford. The Woodford would be extremely deep. Doesn't mean it's not prospective. It would just be deep and expensive. For that reason we have not spent any time on it.

Where there is potential and to be honest with you, we will probably participate with another company with a small interest to gather information, not only for the Granite Wash, but there is a deeper well-being drilled that we're going to take a small interest in that it's -- they're taking it to the Springer, which is a deeper interval, which has also been a renewed objective in today's world. It's been drilled in the basin for a long time, with seismic acquisition and interpretation and processing, the identification of those Springer channels has been perfected somewhat so the risk has gone down.

But again, we're focused on the Granite Wash. We think this prospect in general has 38 to 40 sections in size and potential. It's a big number, if you try to put a value to it on an unrisked and a risk basis, we've gone in there and picked up, as I said, about 10,000 acres and continue to lease, but for the time being, we're strictly focused on the Granite Wash.

Has anybody else produced from the Granite Wash in that county or is this really real exploratory stuff you're doing here?

There have been a number of vertical wells drilled back in the '80s that again, you have some logs, you have some vertical completions that made gas and smells like, looks like some of the stuff that happened in south Clinton where as you figure out you can't make any sense out of it vertically, but horizontal drilling unlocks the potential so that's the approach we're taking.

And is it your sense at this stage that this is going to be wet gas like some of the other sweet spots where you've had success up until now?

Yes, there is. We think it will be sort of a south Clinton look-alike where as that East Sayer prospect I mentioned also, it's probably going to be oilier based on some vertical control, but yes, Mountain View will look like, we think, wet gas.

All right. Great. I'll get back in queue, let someone else go. Thanks a lot, Baird.

You're welcome, Steve.

Moving on to Brian Corales with Howard Weil.

Hey, guys. Couple questions.

One, can you talk about where you drilled that well in the Marcellus?

Brian, it's right on the Potter/Tioga County line. It's about, I don't know, 300 feet into Tioga County, so it's right there.

So there's other guys that have drilled in that area, so it's not a --

Oh, yes.

And is that where you plan to drill the next four -- the four horizontal wells?

Probably drill three up in that neck of the woods, probably farther south. We are close or fairly close to some of the things that Ultra and East Resource have done, but we will drill the next three wells out of the four probably south of that in the same -- in Potter County area.

We're probably going to try to get one on the state acres we picked up back in January which is more toward the south and west part in Potter County but we'll also get one drilled hopefully down in Somerset County, western Somerset County.

Okay.

And just one other question regarding the Granite Wash. You're bringing the rig there I guess you said right now, currently, or soon, and that's going to be drilling Mountain View first?

Well, we actually have two rigs coming in. We have one coming in that will get Mountain View started early June and then we have a second one coming in, it's going to go drill East Sayer. The one that's drilling Mountain View, we will release that rig after it drills that one well and then stick with one rig for the remainder of the year.

Okay.

So a lot of activity really this summer with the new Granite Wash wells and then when do you plan on spudding the horizontal in the Marcellus?

Probably in the July time frame.

Okay, guys, thank you.

Our next question will come from Irene Haas with Canaccord.

Hi, everybody.

A question on the Marcellus. How do you guys feel about your acreage, specifically, on the transportation angle and also understanding that your subsidiary PVR has been doing some work in the Marcellus. How are you set up in that particular acreage location? Do you need to build new pipelines, gathering with your subsidiary have any parts to play in the future?

Irene, we have an interconnect with Dominion that has been approved that we will test our early wells into that we will not have to lay all that much pipeline to do that.

I'd say longer term, once we get into a full-blown out development program, whether we decide to lay those gathering systems our self or get PVR or somebody like PVR, we would probably entertain offers to do that.

One more question, if you don't mind.

Do you like the Marcellus better than you like the Haynesville?

Is that a loaded question?

Which do you like better?

I'm sorry, Irene. We won't ever be able to hear that.

You know, they're two different kind of animals. I still think the Haynesville has a lot of upside to it. And I think as we continue to tweak our frac jobs and drill longer laterals and those kind of things, we'll get better at this. This -- the problem with the Haynesville, operationally, it's probably the most challenging play domestic play that's being drilled in this resource category, I think. Whereas the Marcellus, the cheaper wells are not a challenging operation to get drilled, so from a drilling engineer standpoint which I once was, I'd rather drill a Marcellus well than a Haynesville well. But there's more upside I think to the Haynesville.

Okay.

Thank you.

(Operator Instructions). Moving on to Dan Morrison with global Hunter.

Hi, guys.

Quick follow-up on the Granite Wash completion pump capacity availability. What's the outlook -- I know it's been tight t but but do you see some more visibility in the frac schedule getting on calendars there?

No, we're not having the problems we're having in East Texas with Bossier. You can use 10,000-pound equipment in the Granite Wash, and to be honest with you, we're getting our frac jobs away fairly quickly. The two wells we've already TDed, the second quarter, early second quarter, we've already started the completion of those. So we're trying to get these things scheduled out far enough in advance, knowing that -- what it takes to drill one of these wells. We can -- from spud to TD and run casing, we can be on and off in about 40 days. So we plan our frac jobs accordingly and we're not having any serious problem there.

What's kind of your spud to sales that you're using for planning purposes?

On the Granite Wash, probably about 45 days.

Just 45 days?

Yes. These two wells we spud, I don't know, early April, we're fracking them as we speak and we already had the lines laid, things like that, so you just go ahead and frac them and turn them in line.

And the Haynesville, I think you mentioned you all are doing some restricted rate practices there on bringing those on. Have you looked at -- seen enough to have any view on the impact on the EURs yet?

No. It's going to take a period of time to understand that. Realistically it's going to take years.

Yes. That's pretty much your practice going forward, though? I mean, for --

Yes, it is. Even our existing wells we continue to hold quite a bit of back pressure, even on our wells that have been online for a few years. Probably the lowest line pressure we have is 1,100 pounds or so, 1,000 pounds, something like that.

Okay. Thanks.

Thank you.

Our next question will come from Welles Fitzpatrick, Johnson Rice.

Hey, good afternoon. I think you guys said that completion really shouldn't be an issue in East Texas after this quarter. Is that just a function of moving to the Cotton Valley and the lower horsepower equipment that's needed there?

I think it's more than that. We expect to be able to have lined up some of that equipment and be able to use if we choose to.

We're working on something, admittedly, right now to resolve this problem. We can't talk about it right now until we get it done.

In the wash, in the new areas, I think you said it's several TCF of unrisked reserves and you outlined the 400Bs. Presumably those other four areas will be significant and almost the magnitude of a Mountain View. Am I looking at that right or is there something I'm missing there?

No, you're right. And again, it depends ultimately how much land we can get picked up. That's a key factor. But yes, your math is right.

And one last one, if you don't mind.

On the NGL processing in the wash, when do you think that might be resolved and do you think it's going to be a 20% boost to realizations? Do I have the right ballpark?

Probably here in a month or so. I think what we figured out, it's going to increase the reserves by about 15%.

Perfect. Thanks so much, guys.

Thank you.

And that is all the time we have for questions. Mr. Dearlove, I'll turn it back to you for closing or additional remarks.

Thank you, operator, you're right. We're a little bit pressed for time, so I appreciate all of you who called in and we'll talk to you again next quarter. Thank you.

Thank you. Again, ladies and gentlemen, that concludes our conference for today. We thank you, all, for your participation.