Ranger Oil Corp (ROCC) 2004 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen. Welcome to the Penn Virginia Corporation 4th quarter results and 2005 guidance update conference call. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference please press star-zero on the telephone keypad. As a reminder, this conference is being recorded. 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, operator, and good afternoon. By way of introductions I'm joined here in Radnor today by Frank Pici, who is our CFO, Baird Whitehead who runs oil and gas, Nancy Snyder, who is our General Counsel and a Director of PVR, Keith Horton in Kingsport, Tennessee, and Ron Page in Houston. We will endeavor to as a group answer all of your questions as we go forward here. Before we get to questions, I'll just try to summarize the -- the press release as I say all the time, it's not my habit to try to read these things to you because I think you can -- you can read them and come to questions rather than listen to me babble. The table in the PVA press release of February 9, on the first page sort of summarizes the numbers. You can see that on a revenue basis, an income basis, and certainly on a cash basis, Penn Virginia had a very strong year. A lot of this had to do with prices of natural gas on one hand and coal on the other. It also had to do with increases in production. And we'll try to walk through these things. I think we tend to focus on earnings, of course, but we pay great attention to cash, as well, and the cash numbers I think particularly were strong. Starting with oil and gas, however, and looking at the -- at the full year, I'm more I think interested in the full year than the quarter, although I realize people build models and things quarter by quarter, and every quarter is important. Revenues were up a little bit, about -- excuse me, operating income was up a little bit, about 8 percent, which I think is an important measure. Revenues up more than that, about 21 percent, and that's on a 3 percent increase in production. Expenses were up quite a bit. About 30 percent or $23 million for the year.

We try to break those down some for you between this release and the release of February 3 which was the operating release. But of the $23-plus million increase in expenses year-over-year, some of them were noncash, about $7.5 million due to sales. Some noncore high-operating cost properties in west Texas, primarily oil. This is not a -- is not a quarterly for us, it's a high cost. As we've viewed it given that there's water, flood, and whatnot connected with it, there was going to be some fairly significant capital expenses going forward, and we just felt we were better off without it. That of course is a noncash charge, but still a charge. $4.4 million for Kansas between the drilling that we did and the acreage we acquired. That was a coal bed methane play. We kind of got excited about it at first. But as it turned out, I think the coals were too thin and too tight. Didn't lend itself to horizontal drilling, at least in our opinion. We made a lot of water so there was some permeability there, but we didn't make enough gas to think it was worth continuing and have chosen to write the whole thing off. So that's $4.4 million of a noncash expense there. DD&A was up about $3.2 million. Just I think due to our activities there. We had a couple of other million dollars worth of expiring lease hold in south Texas.

So if you add it all up, and not to try to put a cover over it, but of that $23 million-plus in expenses increase year-over-year, about $18.3 million of it was noncash, and about half of it was certainly nonrecurring as far as Kansas and west Texas go anyway. The quarter -- as I said, I generally don't try to read the quarterly stuff to you. I know you'll read it for yourselves. Again, expenses were up considerably. Revenues were up some, production was up some. And many of the things I just said about expenses occurred in the 4th quarter, in particular the Kansas writeoff and the west Texas sale. So that was a significant piece of that. Looking at operations for a minute as I said, production was up, oil and gas production was up modestly, 3 percent. We were, we experienced a curtailment that we did not anticipate, nor I don't think would anyone else have anticipated of our -- mainly our horizontal CVM program, the east cost us a little over a B of production. We had a couple other weather-related incidents that you might not expect to occur every year. Had those not occurred production would have been up closer to 9 or 10 percent, but in fact it was up 3. Reserves were up year-over-year about 10 percent, we replaced about 233 percent of our 2004 production through the drill bid, insofar as we didn't make any oil and gas acquisitions this year. Again, I'm virtually reading to you, and I apologize for that. But this is out of the '03 release.

The CAPEX for the year was about $135 million. $77 million or 57 percent that went to drilling development wells. We drilled 135 of them with 134 successes, about 12 percent of that went to an exploration program that included 17 gross wells, seven were successful, seven were not, three are being evaluated. We spent a lot more on infrastructure. About $19 million or 14 percent of our budget this year in '05, for example, we don't expect to spend half of that money. A lot of that had to do with building a 15-mile, 12-inch line to alleviate the problems we had with our horizontal CVM, and between that and purchasing firm, we think we put those problems behind us. We spent about $9 million or 7 percent of the budget on seismic, we'll spend a little less in '05, and then it should tail off some. As you may recall late in 2003 and coming into '04, we bought $10 million worth of seismic. We're taking delivery of that over time. That delivery will be complete this spring, as far as I know. And you'll see some of those expenses go down. We spent about 10 percent of our budget on lease hold and other. We'll probably up that a little bit as we're trying to build some lease hold. Again, the numbers in the various releases speak for themselves. I think in my mind at least, on the positive side, some of the highlights of the year were we went into this year 2004 with no production and what we call Bethany or north Carthage. Over the course this year we've drilled 17 wells out of 17, gross, that is.

With 100 percent success. We know we've added some acreage there. And what we think is that on the original maybe 15,000 or so acres that we had an opportunity to co-develop with a company called GMX where we're sort of the lead in terms of working interest and net revenue interest, we thought we had 80 to 100 wells to drill over the course of that program. We've added some acreage nearby and would hope to add to that. I think in the Gulf Coast that was maybe a very important element of 2004. On the negative side on the Gulf Coast, our exploration program wasn't as successful in terms of -- of nondry holes or successful wells as it was in 2003. I think to some degree you've got to -- we expect at least that if we're in an exploration program it's that, it's exploration. This isn't wild throwing darts on a board. These are fairly well thought-out things. But there's an element of risk in them, and I think you got to look at a program -- at least we look at programs over a three-year sort of moving average, but this year was certainly not as successful as last year. In the east, on the positive side, I think there's mostly positives. Our horizontal CVM program ramped up this year. CDX, who is our partner on a big piece of the program kept three horizontal rigs running virtually through the whole year which is a good thing. We would -- we would love to run another one, but we're running three right now, and we're -- we're having success over the whole life of that program.

We've drilled 41 wells, 40 of them have been successful. The ROI on those wells is over 100 percent if you use a 450 Henry hub price. We think we've got well over 200 locations left to drill. So that's a very positive element of the company. What we also did in '04 was to go outside of our AMI with CDX and try some other ideas drilling horizontal wells. One in shale, one in the coal. We learned a lot. Neither well was a screaming success by any stretch, but we learned a lot, and we have every reason to think that we can -- we can extend that idea, and we're in the process of trying to add to acreage both in the AMI and outside of it. I don't think there were any real negatives in the east except that Kansas didn't work out quite the way we would have hoped. Again, the theory behind Kansas, and we'll probably see other things like that -- the theory behind Kansas was there was a lot of acreage there, and if the concept had worked, we would have had things to do for years to come. And that's really what we're trying to find is a -- is areas where we can not just drill a well but drill 100 wells or 300 wells. We've got that situation in the Selma Chalk in Mississippi. We have that situation with our coal bed methane in the east. We have that situation somewhat in the Cotton Valley in east Texas. We're looking to do more of that. And those of you who follow this industry know that that is not a unique plan. There's many, many companies trying to do the same thing, and the competition for these kind of areas is intense.

But that's how you survive I think if you're -- if you're our size. On the coal side, the -- the MLP by any measure had an outstanding year. Again, we put out press releases on this that summarized in the press release we put out on the 9th. There was a separate one for PVR that went out on the 9th, yesterday. What it said was that production off of our properties was up considerably. That revenues were up 27 percent, the distributable cash flow which is really the key measure in an MLP was up about 33 percent. The unit price over the course of the year increased 52 percent. By the way, Penn Virginia stock price was up about 42 to 45 percent over the course of the year. So both companies had a good year. For those of you who don't follow PVR as closely, Penn Virginia's stake in PVR today is worth about $400 million. Last year we took out of it about $17, $18 million pretax. So it's been a very good project for us since we did that IPO in 2001. The other thing about PVR, and then I'll get off of it, we did increase our distributions twice this year by about 8 percent in total. And PVR took two very important steps in -- in 2004. One, a joint venture with a company called Massie Energy, which is a large, old eastern coal company. They have little bit of production off of our properties, but this -- this deal was about infrastructure and what we've done is we've bought a 50 percent interest in a subsidiary of theirs. I guess I can say it that way.

That had three separate end-user plants where coal comes into an industrial facility, be it a chemical plant or a paper plant, and is handled and used there in some way. Massie owns and operates those facilities, now we own and operate half of them. The idea there is to find more and more of those things to do, and the idea is you're no longer tied to single mine or a single operator. You're tied instead on the other end to a user and to the extent that those users are successful, you've got a long-term, stable, predictable cash flow. The contracts on the three facilities we're involved with right now, if memory serves me, and I don't have it written down in front of me -- is between 7 and 15 years. So we like that. The other thing we like is something we announced in November of 2004. And that is -- we signed a -- an agreement with Canterra Resources, LLC. To purchase some of their assets. We will get rid of the Canterra name because they'll retain it. We'll call this PVR Midstream. We bought 3,400 miles of pipe in Texas and Oklahoma, three natural gas liquids plants, and a team we hope of very fine people. So between the quality of the assets -- and these are high-quality assets -- it's a very accretive acquisition. And the quality of the people and the quality of our people who we put in place to find, evaluate, and negotiate this thing, in particular, Ron Page who's on this call, we think we've got another platform for growth within the MLP, and we're looking forward to completing that transaction hopefully in this quarter and adding that -- that company to the fold.

And as I say, using it as a platform to grow from. So I'll let that summarize for the moment at least, unless there's questions where we are with -- with PVR. The guidance table that we put out again may speak for itself. You'll notice in there that we're predicting or forecasting I suppose I should say a -- an increase in production and gas, roughly 10 percent. That doesn't, of course, include any acquisitions, and we're looking at several. Notice maybe the least operating expenses drops a little bit and part of that is because this west Texas sale. Coal production off of our properties this year we expect to be fairly flat, but royalties to be up little bit because price increases are rolling through, and we're seeing a piece of that. Sort of at the bottom of the page I'm looking at the last page, the guidance page here, you might notice the breakdown of our CAPEX budget, the range on the guidance is $142 million to $150 million. If you sort of split it, it's about a 6 percent increase over 2003. But the breakdown within that percentage is -- there's some large moves, I think. Development drilling up 10 percent. Exploratory drilling up significantly, about by half or about 50 percent I guess. I'm misreading that. Pipeline gathering down a little bit as I said. So by and large we're living within our cash flow, and we're -- this forecast which doesn't have any acquisitions in it is showing some -- some moderate growth just internally or organically if you will. When we get to it, questions, Baird can and will take you through anything you need to know about exploration or our drilling results. And Frank can handle the finances, and these other guys can handle PVR. With that, operator, I'll turn it over to questions.

Thank you. Ladies and gentlemen, at this time, we will be conducting a question-and-answer session. To allow everyone the opportunity to ask a question, please limit your time to one question and followup. If you would like to ask a question, please press star-one on your telephone keypad. To remove your question from the queue, please press star-two. A confirmation tone will indicate your line is in the question queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. One moment, please, while we poll for questions. Our first question comes from Ray Beacon with Harris Nesbitt. Please state your question.

Baird, I was wondering, you talked last year about a number close to 90 Bcfe of potential from the horizontal coalbed methane. How much of that do you think outbooked in '04 and what do you think the number would be today?

Ray, as of year-end '04, let me check to make sure. We've got -- we've got about 20 Bcf booked associated with horizontal CBM program. We've been telling people over the next 3 to 5 years that we think we can get to the 100 Bcf number based on prospective acreage we have. But it's up materially. Last year we had as of year-end '03, we had about seven Bcf. So we're up to about 19 Bcf as of year-end '04.

Got it. Just can you go over where you stand with GMXR. I know there were bundles there. Do you think you will -- when do you move from one to the next and how many -- was the 100 locations just on the first bundle, or was that including all three? I --

The 100 locations was actually on just the first phase. We drilled 17 wells in '04. In general in the Cotton Valley we have 25 wells planned in '05. About 17 or 18 again associated with GMX, we have -- we have some other ones outside the GMX AMI in east Texas. We have been acquiring additional acreage as time goes on, and have increased our acreage position appreciably here in the last year. We are in ongoing discussions with GMX to bring in a second rig again. We had two rigs through the beginning of the 4th quarter last year. We let one of those rigs go. But we will probably bring in a second rig sometime at the end of the 1st quarter, beginning of the 2nd quarter. It would be our intent to try to bring a third rig in toward the end of the year to drill some wells outside the GMX AMI.

Thank you.

We'll probably have an active program in the Cotton Valley this year. In fact, that is most of our development program in the Gulf Coast.

Thank you. Our next question was from Sven Dalpozzo with John F. Harrolds, Inc. Please state your question.

Just a brief one. Production taxes per oil equivalent unit, it went down in 2004. I was just wondering how that happened even though prices, realizations went up.

Hi, Sven. This is Frank Pici. We had a satisfactory fund that came through in the 4th quarter that was on a couple fields down in south Texas that offset the expense for the year. Otherwise we would have probably seen a slight increase. We project that those taxes along with some ad velorum taxes generally run about 6.5 percent to 7 percent of revenue. In the 4th quarter of '04 they ran lower than that and that was a function of that refund. So going forward, we'd expect it still to be in the 6 percent to 6.5 percent range of revenues.

Okay. Thank you.

Thank you, our next question comes from Scott Handles with RBC. Please state your question.

Thank you. Hi, guys. I was wondering if you could help me out with -- for the 1st quarter of 2005, you guys are projecting, let's say, $25 million, $28 million for exploration expense. Can you kind of give me a breakdown of what's included in that?

Well, I have it for the full year. Oh --

For the quarter -- it's Frank Pici. I think he has more of a year-over-year breakdown. But for the quarter, I know it's a function of a couple of things. We've got -- we've got some seismic pots coming through in the 1st quarter. I think it's the last payment on an installment deal we've got.

It's $4 million.

We've got a fairly active -- if you look at the exploratory drilling CAPEX, I think somewhere around $5 million to $8 million. I think somewhere in that range. I don't have it -- you can get it right in front of me here. But the -- and that's another piece it because you risk -- we basically risk that and take the unsuccessful leg of it and take it to exploration expense since we are successful efforts. And then the third piece is we're drilling in our exploration program, and Baird get into more detail if you like. But we're drilling a well in south Texas that's currently under evaluation that has a heavy noncash, unproved property balance on it.

As you may recall, we've from time to time when we made our synergy acquisition a couple of years ago, we had a gross-up on the purchase price for some deferred taxes, basically. And the way we allocated purchase price, we put a lot of it on some unproved acreage. We're evaluating that acreage now. One of the bigger prospects with the bigger unapproved property balance on it is a well that we're drilling in south Texas that -- depending on the evaluation of it -- if it's successful, it will be capitalized. If it's expensed, it will hit exploration expense. We made the assumption in guidance that it will probably be a dry hole. And doing that, that pumped up the exploration expense guidance by a significant amount. I'd say $10 million to $12 million.

You're assuming all that in the exploration expense, is that right?

We did. We took a conservative view on it.

Okay. Could you give a little more color on the well that you're drilling right now then?

Scott, it's Richard King, Prospect and Oasis County. It's a Jaeger test about 12,000-feet deep. Had a reserve expectation of anywhere from 10 Bcf up to 50 Bcf. The well is Td'd, is currently entering evaluation. We should know something probably by the end of the 1st quarter.

Thank you. Our next question comes from Dan Morris from the Aperian Group. Please state your question.

I've got a couple of quickies. What was the total sales amount on that west Texas divestiture?

Dan, it was about $10 million.

Okay.

And we retained a net profit interest in our property as well.

Good. n the horizontal stuff you've done outside of the CDX, AMI in Appalachia, can you provide a little color on what's gone on either in the shale or in the -- the Cotton or the -- the coal bed drilling you've done so far?

Dan, we drilled one CBM well up in northern West Virginia last year. With Dominion as our partner. That well's making anywhere from 275 to 300 MCF a day. We are currently offsetting that well, that even though it was a marginal success from the standpoint that I guess you can consider a good indicator well because it did make gas, we feel like we need a half million a day in order to make sense out of -- out of these type wells. We are currently offsetting that first one, the first well was actually drilled on a dip, up-dip. This one is actually being drilled on strike. We're trying something different here. But we should have that well, we should know something about that well probably sometime the beginning of the 2nd quarter. We have two offsets planned this year, offsetting that gabruder. Within the budget we also have, since we are -- we made a decision to appreciably increase our lease hold in northern West Virginia, in southwest PA and southwest Ohio, general buy areas based on geological analyses that we have done, we plan on drilling two other horizontal wells sometime this year in -- in those new buy areas.

On the shale side, the well we drilled last year did not meet our expectations. We have some operational problems. We actually had to cut our lateral short because of those operational problems. We went back in and did a stimulation utilizing dry nitrogen and actually saw an increase in the flow rate from that stimulation. We have that well currently on a long-term test on a back-pressure test, on a -- going through a meter run. Even though the -- the production has increased over last test, it probably still is not going to meet our economic expectations. But we have learned a lot from what that -- from how this first well was drilled and has performed. We're probably going to try something different on a well that we have planned in this year's budget. We'll probably approach it more like they approached the shale where they drill these things laterally, horizontally, cement that casing in. Unlike what we did on ours. Which we just ran a perforated liner within the laterals and probably do two or three state frac jobs. There's never any guarantees here but the shale is a huge resource in Appalachia. We think we have a chance at unlocking this -- the code at some point in time. But it is going to take some more experience in getting up the learning curve. But we will try an additional well this year.

What kind of rates have you seen on the production testing you've done?

The first time on the back-pressure test, we tested 40 MCF a day. The second good run, we had an initial rate of about 300 MCF a day. It has declined over the last couple of weeks to about 100 MCF a day, and it's quasi- stabilized. We've increased it by a factor of two but it's still insufficient to make economical sense including the drilling cost. It probably will support laying a line to it. But it's not going to support the drilling costs.

Right. And one final question on your production guidance. Could you give a little feel for kind of the embedded assumptions and where there might be room for increases. or example, how many rigs are you assuming in east Texas, and what kind of activity in Appalachia, etc.

Well, within the budget we only assume 4.5 rigs in east Texas. One for the full year, then bringing one in mid year. So there's upside there because as I said, we plan on having two rigs, probably the middle of the year. But we plan on bringing a third rig sometime in, probably in the 3rd quarter. We have upside with the exploratory program, of course.

Okay.

We risked our volumes as far as exploration goes. So there's upside there if you have higher success than what you had assumed. We -- we think we have upside with our horizontal one. We've taken a conservative approach as far as how we budget our volumes. We have still assumed some pipeline interruptions this year. Not because of firm transportation issues which we resolved but because of -- just because Colombia and Diminue tend to have some mechanical, operational short-term shutdowns to do some upgrades on line. So we've taken that into account. So I say that's probably pretty much it.

Okay, thanks.

Thank you.

Just a reminder. To ask a question at this time, please press star-one on your telephone keypad. Our next question comes from Robert Wegan with New Salem Investment Corp. Please state your question.

Good afternoon. Just want to get a little idea. Are there any assets for pipeline or gathering that there's an opportunity to be put down into the Penn resources and if so, what's the potential timing or even size of those assets?

Well if I'm think understanding you right you're asking -- well, if I'm understanding you right, you're asking in Penn Virginia oil and gas there's gathering assets that you could put in the PVR. The short answer is there are. We spent $19 million in '04 building that sort of infrastructure, and we certainly had some other. And one of the reasons we haven't done it in the past -- one of the reasons is that activity if you will takes its own back room. I mean, there's accountants, there's IS systems etc. That have to be put into place for that to be done in an efficient way. What this acquisition that we're contemplating closing here in this quarter, Canterra will do, is those systems and those -- those accounting types, etc., will come with that so that the -- there won't be a -- a lack of back room capacity to drop those kind of assets in. We will surely look at it. We have said that in the past. The difficulty could come, will come, always comes over valuation.

The Penn Virginia resources board has a three-person committee on it that are all highly independent outside directors, and they'll have to agree with the Penn Virginia Corporation board if you will, or whoever's going to do it, probably it will get to the board level, on what those valuations are. I don't think there's any reason we couldn't come to agreement. But the devil's always in the details. We -- we certainly anticipate over time that there will be synergies between, to use our jargon, PVOG, Penn Virginia oil and gas and Penn Virginia resources midstream. We certainly anticipate that. I don't want to put a timetable on it. We'll get Canterra closed we hope late this quarter. We'll make the transition over the next three or four months. So I wouldn't expect to see any that until late in this year. But ultimately, we would anticipate doing that, yes.

Great. Thanks.

Gentlemen, there are no further questions at this time.

Okay. Well, you know, I appreciate the -- the attention and the interest in the company. We look forward to reporting to you at the end of next quarter. And if we missed something or you want to call, call Frank. Or me or Baird, or Keith, or whoever. But thank you very much.

This concludes today's conference. Thank you for your participation. All parties may disconnect now.