Ranger Oil Corp (ROCC) 2005 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen, and thank you for holding. Welcome to the Penn Virginia Corporation's 2005 results and 2006 guidance conference. [OPERATOR INSTRUCTIONS] 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.

Thank you, and good afternoon to all of you on this call or listening in on the Internet. I'm joined here today, as usual in these quarterly conferences here in Radnor, with Frank Pici who is our CFO, Baird Whitehead, who runs our Oil & Gas business, Nancy Snyder, who is our General Counsel. We also have our Treasurer, Steve Hartman, here today. Off site, we have Ron Page, Keith Horton, who respectively run the operations of P.V.R. and Forrest McNair, our Comptroller. So, I think we are fairly well represented today and hopefully we can answer your questions.

I will walk you through the press release of yesterday. I won't read it to you. I am going to skip over a lot of the -- of the detail. You can ask us anything that you want. I'm more interested in trying to give you a sense of where we are and where we're going. So with that, I will try to follow pretty much the order of the release. As the numbers might indicate, we're very pleased to be able to talk to you about our performance in 2005.

If I look at some of the financial numbers, net income set a record at $62 million, up 85% over the previous year. Cash flow from operations at $230 million, operating cash flow at $240-some million were both up over 55% for the year. The fourth quarter results were similar kinds of percentage increases. These all represent records for the company in its 123 year history. This was the best year that we ever had. A lot of these increases, in fact, most of them are based on the performance of our oil and gas company but we're also very pleased with and benefited considerably from our ownership in the [MLP]. I might just say, in terms of records and this and that, production for the year of oil and gas was up about 12% to 24.5 of Bcfe equivalent. Reserves were up about 9%, to 385 Bs, which when you take into account we sold about 27 B.s of noncore assets in the first quarter and the effects of the hurricanes and some of the other things things, which really didn't hurt us all that much but nonetheless had to be dealt with, this year we replaced about 310% of our production and all of that through the drill bit.

We feel we had a pretty good year. Of course a lot of the record financial performance was aided by the very strong price environment that we and everybody else in the industry enjoyed. But again, I think our strategy of positioning ourselves to grow and having some of those projects work out for us, really helped these results as well. For example, I'm referring kind of back and forth between our press release of yesterday and our press release of the 3rd of February, which was an operations release for oil and gas which you can get a hold of on line and if you can't you let us know; we'll get it to you.

But that said, we had these record levels of production, and they were driven by, for example, the Cotton Valley project, where the ends of the year we were making a little over 8 million a day in the fourth quarter. And if you think about it, we had no presence in the Cotton Valley in the fourth quarter of 2003. Now we've got about 36,000 acres there, a good bit of it 100% working interest, a good bit of it in a successful partnership we had with a company called GMX. HCBM, horizontal CBM, increased about 76%, fourth quarter to fourth quarter. That's been around for a few years, but again, it's a project we've been focusing on in the last few years, and it's beginning to -- not beginning to but, it continues to bear fruit. Mississippi is up 48% year over year; simply because we were able to make a few more acquisitions and ramp up our drilling there. So again, I refer you to the operations release of February 3, but I just wanted to highlight a little bit of what's going on in '05.

Skipping around just a little bit and going back to the guidance table, you don't need to read refer to it; I will read it to you. In this sense. I am only going to talk about CapEx for a moment. Our oil and gas CapEx is - I am just going to take the middle of the guidance is $208 million this year, increase over about $175 million last year. This includes $130 million of development projects, most of those in the areas that I just mentioned.

Our exploration effort remains strong. The focus this year is on various shale plays including the Devonian in the east and New Albany in the Illinois Basin. Some ideas we are exploring with Barrett in the Williston basin. We've got a few other ideas that are a little bit premature to mention right now. And of course, our exploration continues to include and as it should our efforts in south Louisiana, South Texas.

I said a minute, ago - turning now to PVR for a moment, that we benefited this year from our ownership of PVR which is an ML P that we formed back in 2001 in which we own the GP and 39% of the limited partnership units. That partnership contribution to Penn Virginia Corporation this year was about $21.2 million pretax to cash contribution. We mentioned in the -- in our press release that PVR also raised its quarterly distribution to $0.70 a quarter per unit effective for the fourth quarter of 2005, which represents -- this increase represents a 24% increase over the same quarter in '04. What that really means in practical terms is that we have a fairly strong if not a very strong cash position and a good deal of confidence going forward that we could maintain those distributions.

It's germane to -- again -- the ownership of PVA that we own 7.8 million units. When we brought this thing up they were all subordinated. Now, only about -- oh not about -- in fact of them remain subordinated. The other half should come out of subordination in November of this year. For that to occur all we need to do is maintain a $0.50 per quarter distribution for the next three quarters, which we surely will intend to do. As I just said our distribution rate right now is running at $0.70 a quarter.

The PVR which is the MLP release also came out yesterday, and I again refer you to that. It's on our Web site and on theirs, but briefly, the partnership had record levels distributable cash flow, they were up 56% over what they were in '04. Net income was up 46% over what it was in '04. A lot of that driven by the fact that we added to the partnership some midstream assets in March of 2005 and, of course, that acquisition contributed significantly to PVR's results.

If I look at coal by itself for a minute. Revenues from the coal group were $96 million versus $76 in '04. The royalty component, that was about $83 million versus $70 million in '04. I realize this is a lot of numbers, but I'm just trying to give you a sense of these things. These are fairly dramatic increases. Virtually all of that coal increase came about due to pricing, although during the year, we made four separate coal acquisitions that added in round numbers 160 million tons of reserves -- 100 million of that again in round numbers, 95 to 100 million.

In the Illinois basin in western Kentucky we will expect that those reserves which contributed on an annualized basis, and they were acquired over the course of the year so it didn't -- wasn't all from -- from -- the full contribution wasn't seen this year, but on an annualized basis, they are delivering about 3.1 million tons per year. By the end of 2009 we would expect them to be delivering about 7 million tons. So there's some organic growth in the coal group. Also the coal group was able to ramp up its participation in what we call midstream coal or infrastructure preparation plants, load-up facilities, hand -- coal handling facilities, that was up significantly year over year, and we're looking for some more growth in that area.

As far as the midstream assets go, again, we acquired those in March of this year. They contributed just under $15 million of operating income. We don't have comparative numbers in any of the releases because there aren't any. We didn't own these assets a year ago, and to try to compare them with the people who did, really doesn't make any sense because we didn't buy all of their operations. And so there's no legitimate way to compare them. What you can compare them to, and we have, is our acquisition economics. And through the first ten months of owning this, we've more than exceeded -- well, we have exceeded, excuse me, the acquisition model that we built when we made the -- when we made the purchase.

And perhaps more importantly to us, as we look at what we really got here, unwrap the box if you will, we're finding a lot of thing to do that will either -- bolt-on-type acquisitions or the opportunity to make better deals with the producers whose gas we gather, or to extend our gathering systems, and so I think, or I hope that what we'll able to report going forward is not anything huge but a steady organic component to what we are doing in midstream. And both coal and midstream are very active in seeking new acquisition opportunities.

If I turn to the guidance table which in my -- in the printout I have here is the 12th of 13 pages, so it's near the back of your release. Again, I touched other gas for a minute, but I'll just repeat myself and kind of take the mid points. We're projecting that oil and gas production -- this does not include any acquisitions -- will be up roughly 8% over '05. You see direct expenses up about 13% and that's simply reflecting the cost of doing business. Day rates are up, tubulars are up, rigs are [expletive] -- are darn hard to get. There goes the FCC, I suppose. But anyway, rigs are difficult to get, and we are finding ourselves signing longer term contracts in order to ensure we have rigs. You'll notice, as well, a strong commitment again to exploration, and we also list, I am getting a little beside myself here, we also list out some of our capital expenditures As I said the total is about $208 million if I take the midpoint. Most of that, of course, going to development drilling but a healthy dose of exploration and lease acquisition activity.

With coal we are expecting our lessees to produce about 9% more this year than last. Again there is no acquisitions built into this. Our realization is down just a little bit, less than 2%. And that's merely the mix of lessees and the types of contracts that we expect to be performed on this year. The Capex budget is infrastructure-related, looking at midstream again, we've put no acquisitions in there, so inlet volumes are fairly flat year over year by our projections, although as I say with will be looking for organic things to do. Expenses are up a little bit as is the norm in that industry right now. CapEx is confined here to maintenance CapEx which we're expecting to be about $9 million. So that is a, admittedly brief but nonetheless, I hope, somewhat thorough reading of the press release. And I guess rather than listen to myself talk I'd rather listen to you talk, so please, ask any questions that you'd like.

[OPERATOR INSTRUCTIONS]. Our first question comes from Sven Del Pozzo, with J. S. Herold.

Sven? Operator, we are not hearing anything if we are supposed to be.

Our next question comes from Joe Allman with RBC.

Hi, everybody.

Hey, Joe.

I guess for Baird, outside of the -- in Appalachia outside of the horizontal CBM play, what most excites you over there in Appalachia, and what are your plans kind of for some nonhorizontal HBM stuff in that venture with [CDX]?

In Appalachia alone, Joe, it would be the Devonia shale. We drilled one well two years ago, back in 2004. We decided not to the drill one in '05 for a couple of different reasons. The plan is in '06 to probably drill two gross and one net. There are two different areas we are currently working on, one of which is the area in which we drilled the original well back in '04. The other one of which is about 12,000 acres we recently signed a deal on in Boone County, West Virginia. Probably the second most exciting thing we are doing in West Virginia is -- or in Appalachia is expanding our horizontal CBM program outs of the [CDX AMI] primarily into the northern part of the state, northern part of West Virginia. And probably in '06, you will probably see us do something in southwest Pennsylvania.

And then moving outside of Appalachia, could you talk about, besides about East Texas Cotton Valley play and besides the Selma Chalk play in Mississippi, what are some of the more exciting things from your perspective?

I think Williston basin is very exciting for us. We've got the two different projects with Barrett. Both of them, if they work, we got a lot of running room, a number of development wells to drill. So we're excited about that. We're -- you'll see us probably start doing some things in the [inaudible] shale subject to finding a rig. We've got roughly 5,000 acres now, continue to expand our acreage position, so you will probably see us drill a couple of wells toward the ends of the year in that play. The New Albany, we're taking a wait-and-see look at this time. We drilled the two wells late last year. We took full cores, both those cores are being lab analyzed for gas content and TOCs, those kind of things. We just recently did a pump in test on one of the two wells we drilled to establish some [frak] barrier parameters, so we will be completing both those wells probably toward the end of the first quarter. As far as whether we have a successful project, I would estimate it would be toward the ends of the year subject to what kind of dewatering issue we may have in front of this. It's just unpredictable what the New Albany is going to do. That's one of the risks. We are playing or looking at some other shale opportunities. At this time it's premature to talk about those. And lastly, we're involved in another CBM play, at Wilcox CBM or [coals], in this case it's in Mississippi. We moved in the shallower part of the basin from a well that we drilled a few years ago that was deep and too tight. At this time, I mean we have yet to establish any production but at least based on preliminary gas contents, [inaudible] thicknesses, those kind of things, there is enough gas in place that makes sense economically. So we're excited about that play, also.

All right. Very helpful. Thank you.

Okay. Joe, thanks.

Our next question comes from Sven Del Pozzo with J. S. Herold.

Hello. Can you hear me?

Yes.

Okay. Good. Yeah, I beeped in a little bit late, so tell me if you've already answered this, but what is the range in your production guidance due to?

The range, Sven, this is Frank Pici. Hi. The range we have in there the 28.5 to 30.5?

Oh, for 2006, sorry.

You want to know what the range is due to?

Yes.

Well, we've got a number of new projects, in our drilling program which, you know, our capital budget in general is I think around 20% more than last year, so there's some variability built in there on how many wells will get drilled, and we have our big three -- I call them development plays -- in the HCBM., the Cotton Valley and East Texas and the Mississippi play, and there is always some variability in how many -- we've got a number of rigs that we've got committed and expect to run all year, but there's always variability between the rigs and the weather and things like that we may not be able to drill as many wells or have -- have continuous production as we might like so that's why we build the range we do. A two Bcf range is what we've got there. That's pretty much the norm from what we've been guiding in prior years as far as the range goes sizewise.

So you think you'll have the gathering line built and you will be able to get another CDX. rig toward the end of the year with relative certainty?

I wouldn't go that far because we don't control that situation. There is lines that have to be built that we are not building and so I don't want to -- one thing we don't want to do, Sven, in these conferences or in speaking to people is build up false expectations. We expect to have an extra rig running this year but I don't want to say any more than that.

And the other thing, I just noticed -- unit, these direct expenses, unit direct expenses for the E&P segment don't seem to be escalating that much. It looks like about a 4% to 6% rise in these direct expenses which are, -- look like G&A and listing costs and production taxes all wrapped up. Could you explain why, I mean that seems good. I was wondering what are the reasons for that, for that relatively minimal cost escalation in 2006?

Well, some of that would be in terms of direct expenses. Some of that gets tempered a bit by the tax issue because based on the price -- there is a little bit of a price assumption in these numbers, and I think it's probably a lower price assumption than 2005 with the record prices we had in '05. We don't -- we don't expect to see quite that high a price deck in 2006. That directly affects the production-related taxes. So there is some buffering going on on that line itself. Other than that, Baird, as far as the LOE goes, I think we expect some excalation in the cost.

Yeah, we do. I mean, I think if I'm not mistaken, our direct LOE costs were sort of flat year-to-year because of synergies of scale. We are drilling more Cotton Valley wells. Your costs are always higher up front. After you get the disposal wells drilled, those kind of things, your costs tend to get down over time. Our horizontal CBM program, the same thing. We expect to have a surface land use permit, whereas we can start spreading -- produce water on the surface which reduces our disposal cost considerably, of course, and the same thing with Mississippi. It's a -- it's just drilling more wells over a -- over -- essentially some of your costs are fixed, and it tends overall on a unit basis to bring those costs down.

Okay. So the jump we saw in the fourth quarter appears to be -- you already mentioned in the write-up that -- seems to be more transitory things, like having to do well maintenance, down-hole maintenance charges associated with HCBM wells and Appalachia, Selma Chalk. I mean, that sounds like something that will, can come and can go but just correct me if I'm wrong.

That's correct. Fourth quarter we had some unusual subsurface expenses, and not only the horizontal CBM but there was also some Gulf Coast and specifically some [off-site] operated properties that came through in the fourth quarter. But they are cyclical.

Okay. All right. Thank you.

Thank you.

Our next question comes from [Rhett Bruno] with First Albany.

Hey guys.

How are you?

Pretty good. As far as your CapEx projections for pipeline and gathering facilities, how much of the increase is going towards Appalachia, and how much additional capacity do you expect to add there?

I, out of the total is around plus or minus $15 million that are earmarked towards horizontal CBM, and that's some new compressor stations, extension of some large gathering lines, those kind of things in order to handle our drilling program. So essentially a lot of our increment incremental production is -- is -- requiring new pipelines and compressor stations.

Okay But you don't expect any spare capacity from that?

There will be spare capacity. As far with -- I can't remember exactly, but we are -- the line size itself is sufficient whereas we can move significant volumes of gas through it. We actually set enough compression to handle the production we would expect to develop in '06, but we have the ability over time to add horsepower to that station. So ultimately the one compressor station we are building we'll be able to move around. I guess 12 to 15 million a day gross and about half of that would be utilized in '06.

Great. Thanks.

Thank you.

You're welcome.

Our next question comes from [Andrew Coleman] with FBR.

Good afternoon, gentlemen.

Hi.

Had a question, what is the conversion factor, you guys are using for your hedges to get from MMBTUs to Mcf. Are you guys using a one-to-one or or is your gas a little higher content than that -- , higher BTU content?

It runs a little higher, Andrew. I think it's roughly, the BTU content, Between 1025 and 1030, Andrew.

Okay. Secondly it look like you were hedged almost 45% or so in the fourth quarter, seven by $12. These are all at NYMEX hedges, right? Do you have any basis hedged in there?

We didn't, no. it's all NYMEX.

Okay. And your basis is, you say it's probably, given your Appalachian kind of component of production, you are probably sitting at probably a net zero kind of basis.

Overall, you mean?

Yes.

That's probably about right. I mean when you take the production that's, that's a discount to Henry hub based on being in the West that's probably about right on a weighted basis.

Okay. And you'd said on the last call, you had a little bit of hurricane impacts. Are those all back on?

Everything is back on.

Great. Thank you.

Our next question comes from Joe Allman with RBC.

Hey, Frank. Do you plan on putting any more hedges in place or are you satisfied for now, with -- I mean based on our model you got like something like 30% or so of the gas production hedged.

We are looking at, it. We look at it pretty continuously, Joe, but at this point we're pretty set where we are. I mean we'll -- As we get out in time, our policy allows us to hedge up to two years out based on calculations of standard deviations off the trailing strip, and on that model with the strip dropping we can't really do anything to -- to really add much to the positions. But we also think we are pretty well protected where we are so we are probable the not going to do anything special to add to the positions right away.

Okay. Thanks for that.

[OPERATOR INSTRUCTIONS] Our next question comes from [Darren Carpenter] with Sturdivant.

Good afternoon, gentlemen. I'm wondering can you give me a feel for what percentage of your service costs that you've locked in for 2006, and for that which you haven't, can you sort of give us a feel for when those costs will be re-upped, will be rolling over, in terms of what part of the year?

That's a tough question to answer. We have -- we have almost all of our rig contracts locked in. Our -- we have one rig under long-term contract in East Texas. The rigs we use in Mississippi are all under a fixed contract, turnkey contract for '06. CDX stuff, those rig rates fluctuate to some extent. Everything else associated with service costs, i.e. pumping and those kind of things, is dynamic as the market is today, it's pretty tough to lock that kind of stuff in. In fact the service companies, in most cases, are unwilling to lock it in. So it's a tough question to answer but we have some of our rigs locked in. everything else we do on the service sector side on the drilling and completion side would not be locked in.

Okay. A follow up to that, then, on the service cost side, the pumping side, et cetera, what type of cost inflations are -- cost inflation are you assuming in your outlook for '06?

I think we had incorporated about a 15% to 20% -- in a case-by-case basis, some areas we assume more, some areas less but I think overall 15 to 20%.

Okay. Oh. One other question. In your '06 capital budget, did you have -- did you give a range or a point estimate for your commodity price assumptions underlying that budget?

No, we don't give that out. Everybody has their own price deck. We try to give you production numbers and enough expense numbers you can build a model around your own price deck.

Okay. Great. Thank you.

Our next question comes from Andrew Coleman with FBR..

I just want to ask one follow up. What kind of cost inflation are you seeing specifically in Appalachia?

Andrew it really has been behind the rest of the domestic activity. There have been some recent escalations across the board by joint contractors and pumping companies but I -- if I had to guess probably around 10%, 10% to 15% would be on the lower side than the other areas we've had, where we have seen cost increases.

And you said the biggest piece of pumping, that [inaudible] like sourcing sand and water for the -- for fraks and that or.

Well, I mean that is part of the cost increase. It is materials, but the pumping service, the horsepower whatever else you have out there in order to get a job complete, all of these costs are going up.

Okay. Great.. Thanks.

Gentlemen, there are no further questions at this time.

Okay, well, again, thank you to all of you who listened in or tuned in on the Internet and we'll talk to you again next quarter.

Ladies and gentlemen, this concludes the conference. Thank you for your participation. You may disconnect your lines at this time.