Ranger Oil Corp (ROCC) 2009 Q4 法說會逐字稿

Welcome to the Penn Virginia Corp. fourth quarter 2009 earnings conference call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr. Jim Dearlove, Chief Executive Officer. Please go ahead, sir.

Thank you, Sara. Good afternoon. I'm joined on this call by a variety of people including Baird Whitehead, who runs our Oil and Gas Company, Frank Pici, who is our CFO, Nancy Snyder, who is our Chief Administrative Officer and General Counsel who's here to keep me out of jail.

Let me start and I'll follow along the format of the release. We lead off by mentioning that we had a -- we ended the year with 942 billion cubic feet equivalent of reserves, which was a new high for us, a little bit over where we ended 2008 which was at 916. Production for the fourth quarter, again, just reading the release was 11.3 billion cubic feet equivalent or 123.1 million cubic feet per day, which was lower than it was at the end of last year, the fourth quarter, and was a little -- was a little bit lower than the third quarter of 2009.

That's to be expected, because we actually suspended all Company-operated drilling for the second and third quarters of 2009 and so there was the expected decline has occurred. That may flop over even at the beginning of 2010. We would expect the trajectory in 2010 to be positive, that we would increase the amount of production each and every quarter. That's predicated on the notion that prices don't collapse again. We suspended our drilling program last year primarily because we didn't want to drill into those prices, especially in the shales where you have such high initial production and if that -- faced with that situation again, I think we would be willing to make that decision again. Despite all of that, we actually ended the year, 2009, with slightly higher production than we had in 2008 and that just shows you how prolific some of the shale wells are as well as our activity in the Granite Wash.

Prices for the fourth quarter of 2009 for natural gas were 32% lower than the same quarter of 2008. And that, of course, had a deleterious effect on our financial results. You can see several bullets on the first page of the release dealing with operating cash flow and various ways of measuring income. I'm not going to read all of those to you. They speak for themselves and the release itself is full of numbers and detail which would be silly, I think, to read to you. We're here more to cover what's going on.

And one of the things that's going on, one of the things that we focused on especially in 2009 was improving our liquidity. And the last bullet on the first page tells you that we have a little over $400 million of liquidity today as opposed to about $150 million when we came into 2009. So, we spent a lot of time and effort on that. I think including the sale of some Gulf Coast assets which actually closed in 2010, we raised over $500 million, and thereby really shored up our balance sheet. In fact, we have nothing drawn on our revolver right now.

Along with improving our liquidity in 2009, we refocused our strategy and we concentrated our efforts in four areas; and I think you'll see that carrying over into 2010 and I think Baird will probably touch on it himself. Those areas, namely the Granite Wash in Oklahoma and east Texas where we have several different opportunities in the 60,000 acres that we have there. We've begun a pretty serious leasing effort in the Marcellus and we've drilled our first well, which Baird will talk about. We've increased our presence in the Selma chalk. Gone from the mix are the Gulf Coast, the activity we had in the Bakken and Fayetteville is gone and it is, I think, reflecting a more focused strategy going into 2010.

And before I let Baird and Frank talk about the operations and the numbers respectively, let me just get PVG out of the way. PVG is an MLP, a master limited partnership, which Penn Virginia owns the general partner of that master limited partnership as well as the majority of the units. PVG itself is nothing more than the public general partner of an underlying MLP, while Penn Virginia resource partners. PVG has no operations. It is totally dependent on PVR for its cash flow. Because we have such a large position in PVG, we consolidate our results but we try to make it easier for you to understand and compare us one-to-one with our peers in the oil and gas business. If you look on pages 11 and 12 of the release, you'll see a non-GAAP version of our statements using the equity method of accounting. So, we hope that will make it a little easier for you.

At any rate, PVR, the underlying MLP, had a very good fourth quarter and a very good year from the standpoint of distributable cash flow. Both were records. We just completed our conference an hour and a half ago where we discussed the results for the year and for the quarter for pvr and we welcome you to go to pvresource.com. You can get the press releases there and within sometime today that, conference call will be posted.

And finally, most importance to us at PVA, PVG will pay a distribution on the 19th of this month to the shareholders of record on the second of the month. It is $0.38 a unit, unchanged. That accrues to us about $7.6 million for the quarter or $30.5 million for the year. So, enough on PVG. We put out an operations release a few days ago, and Baird, I think between that and what's -- the segment information in here, why don't you walk us through that?

Okay. Thanks, Jim.

As you all know, things were slow for us last year. At least after the end of the first quarter and we just started to ramp things back up late last year and in early 2010 and the first play type in which we started to get extremely busy in, especially with our own rigs, was in the Granite Wash. Results of the Granite Wash today, again, have been excellent. As we included in our Ops. report last week, we participated in four gross and 1.3 net well during the fourth quarter. We reported on a [Zwaski] 112 which we had a 45% interest in. It tested ten million a day and 1,089 barrels a day or 16.5 million a day equivalent. The Jansen I, which was another (indiscernible) operated well, we had a 19% interest in it. It tested nine million a day and 1,086 barrel a day or 15.5 mill a day a minute.

And since that operations report, of last week, we have -- we, of course, have been drilling ourself. We've got the first two wells we have drilled completed. One of those is the McGirk 2-6. We have a 51% interest in it. It was just turned in-line early this week. That well is making 11.2 million a day and 792 barrels of oil a day or about 16 million a day with a flowing pressure of 5,000 pounds. And we just turned in the Benke 1-1, which is actually drilled in the first quarter of this year. It is producing 11.1 million a day, 1,176 barrels of oil a day or 18.2 million a day equivalent with a flowing pressure of 4500 pounds. So, you can see that we have turned in line here in a fairly short period of time four excellent wells. And if you look back at the average we had drilled to date, which is about 12 million a day, all four of these wells have done much, much better than what we had experienced to date.

We have one operated rig drill a Snyder 1-5 well. We have a 53% interest in it. We just set intermediate casing and as pointed out in our Ops. report, we'll be moving a second rig to south Clinton field to increase our development program, probably late this quarter early second quarter. We are getting good at this. Ourselves at drilling the wells. The McGirk well, we drilled from spud to rig release in 45 days. The Benke well from spud to rig release was 38 days. So, in any case, we feel very confident in drilling these wells ourselves and are getting good at it. In 2010, we now expect to drill 38 gross and 17.4 net Granite Wash wells on our joint acreage with Chesapeake. We expect to operate two rigs. We expect Chesapeake will operate up to four rigs throughout the year.

Over the last couple of phone calls, we've talked about how we have been busy internally generating our own ideas in the Granite Wash. We have been actively leasing on four new Granite Wash prospects, one of which is at least big is south Clinton. We've doubled our Granite Wash acreage position up to about 24,000 net acres over the last six months and we continue to lease not only in this floor but some other new ideas that we have. These four prospects that we will tentatively drill in 2010, we have unrisked reserves of about 500Bs net to Penn Virginia. In any case, you can see the magnitude of the size of these prospects in which we will test.

We're also generating some new horizontal conventional or unconventional ideas or some other play types in the mid-con. Product pricing has made it very difficult to justify drilling vertically, but again, like a lot of these plays, we think they have a horizontal twist to them and even though we're not prepared to talk about specifics right now, we will start leasing on one or up to two of these kind of plays sometime in 2010.

In the Bossier, we just got back from drilling here late last year. We have one well that is drilled waiting on completion, the Braun 6. We're just finishing up on the Timmons 3; we just got our production liner set on it. The Braun well, we drilled about 4,000 foot lateral. The Timmons well, we drilled about 5400 foot of lateral. It is longest lateral we have drilled in any of our lower Bossier wells. And as with the last two wells we drilled, the fern steel wells. We will continue to put at least away ten frac stages on these last two wells, we'll get anywhere from 11 to 12 frac stages and we'll probably add a frac stage up in the upper Bossier. We consistently see good mud log shows in the lower part of the upper Bossier. We feel, based on a completion we made in it, and actually the first well we drilled in Texas, based on some post-production logging that it contributes a critical amount of gas and justifies continuing to treat that lower part short of drilling a lateral within it at some point in time which we'll do.

The James Madison fern steel wells that we drilled late -- not late last year but mid-last year, they continue to meet our expectations, our type curve now is about a 5.5B well, plus liquids. After being in line from May and June respectively, the fern well is still making 1.2 million a day. The steel well is making about 1.5 million a day and to date, the fern well has made about 600 million and the steel well has made about 750 million equivalent. In any case, we feel like we're on the right track. We feel that this type curve we can continue to replicate with an on-going program and considering a $7.5 million to $8 million drilling and completion cost, which we feel is probably the right range, we'll generate probably about 20% after tax rate of return, at today's gas prices.

For the year, we will drill seven net lower Bossier wells. We're also going to have a fairly active Cotton Valley program drilling horizontally. The Cotton Valley just will not fly vertically at today's gas prices. We feel based on offset activity, that we can justify drilling these wells. We have modeled these wells at 4 Bcf plus liquids; the wells will make about 50 barrels per million of liquids, which appreciably adds and contributes to the economics. In any case, the plan will be to drill eight of these. Everything we have booked or almost everything we have booked on the Cotton Valley year end was vertical and the plan would be to convert those to a horizontal puds over a period of time.

In the Chock, there's not a lot to report. We just got back to drilling early this year. We have one well drilled. It is currently being completed. We have spud the second well. The plan is to drill 18 gross and net wells this year with one dedicated rig.

And lastly, as Jim mentioned, the Marcellus, we're just finishing up on our first Marcellus well. We have actually spent some science dollars on this first well. We cored about 100 feet of Marcellus, the full core. We got about 100 foot of full core at the surface. There was some good indications as far as free gas being evolved from that core. We have some good mud log shows that we were drilling.

The plan is to go ahead and get these cores analyzed, help us determine where to complete the Marcellus, but with this well and tentatively five other wells planned to drill this year, the plan is to get our Marcellus acreage tested. To date, we have picked up about 33,000 net acres in the play. We have about 8,000 acres that we have acquired since late last year, once we reinitiate our leasing activity. About 3,700 of that 8,000 acres was part of that state acreage we picked up in Potter County. In any case, the plan is to try to get to roughly 50,000 net acres here over the next month or two, which we think will give us a good foot print that we can start drilling a well.

Jim, I think that gives everyone a pretty good summary of what's going on operationally.

I would say. Thank you.

Frank, you want to talk about capital resources, et cetera?

Sure. Good afternoon, everybody. I think Jim's has already mentioned the current liquidity status we've gotten which is really quite strong. It's over $400 million on the Penn Virginia side. When we look at our hedging program, I normally give a brief recap of that as well. Our hedging program did improve our realizations in the fourth quarter by $1.09 an Mcf, $1.28 for the full year. Those are pretty substantial increases, 25% for the quarter, 33% for the year. They also improved our oil realizations, not as significantly from a $1 standpoint but nonetheless, significant increase on a percentage basis. And the hedging program for the year provided about $11 million in the fourth quarter and about $60 million of cash flow support for the year. So, that's been a significant contributor to our cash flow for the year.

Looking forward, based on current volumes, we're about 70% hedged on natural gas at floors that are above the current strip for 2010. For 2011, that number drops to about 35%, as is normally the case. We hedge over time and then we've actually got a small position even going into 2012. So, natural gas, of course, is the primary product we hedge given the depth -- the bulk of our production stream, and we think we've got a good, strong position there.

I guess the other thing I would just point you to would be the guidance table in the back of the press release on page 13. We've already covered sort of in the middle of the page or the full and midstream segment guidance items. Those have been covered in the PBR call we had a couple of hours ago. I won't go through those again. With respect to the oil and gas items, we've covered most of them in the operations rulings we put out last week. If you look at production, we are anticipating an increase of 6% to 13% over our 2009 volumes. We would expect the shape of that increase to probably hit a low point in production early in the first -- probably in the first quarter then start to grow off of that based on our capital expenditures program which, as you can see in the guidance section on Cap Ex, we're currently guiding to $3.75 to $4.25 in total. The drilling portion is of that is $2.50 to $2.75. That's a significant increase over what we spent in 2009, and as Baird mentioned, he gave you the areas where we're going to focus those activities.

The other large component in the capital expenditures would be the lease acquisition area where we are trying to add acreage in the areas that Baird mentioned as well. You can see that's $68 million to $81 million of estimated capital expenditures for the year. When you look down below, at G&A expenses, you'll notice a spike in the fourth quarter of '09. To drive us to about $25 million of G&A for the year. That was primarily due to some accruals first from reorganization and back office restructuring costs that we've undertaken. Looking forward, you can see the guidance shows a slightly lower range than the '09 level. That's because we would expect the run rate to come down a bit over time.

So, Jim, I think those are the primary things in the guidance. And we can answer questions.

Thank you, Frank.

As I said earlier, Penn Virginia enters 2009 with strong balance sheet, a focused strategy, and I daresay, a track record of growth and solid operating performance. So we can't forecast the future of energy prices, that's why we hedge. However, we're comfortable and confident that we're well-positioned to be successful and we are looking forward to 2010 and the years beyond.

And with that, operator, we'd be happy to take questions.

Thank you. (Operator Instructions). Our first question is from Joe from JPMorgan.

Good afternoon, everybody.

Hey, Joe.

Jim, in terms of your interest in PVG, what's the plan going forward in terms of potentially selling some more units of PVG and would you expect to do that if you do plan on selling anymore, would you plan on doing that in one large chunk or would you plan to dribble that out?

Well, dribble it out is an offensive term but that said, Joe, a good question and somewhat of a difficult one to answer, in this sense. Clearly, we sold a third of our position in September of 2009. We still own over half of the units. We still own the entire GP of PVG. So, it is an important asset.

We take some pains in our releases, our 10-Qs to say it is important, but non-core. I think that's exactly right. It is an important asset. It has been good to us. It has performed very, very well, but it is not core to what we do. And what we do more -- what we're trying to do with Penn Virginia is make it into a more easily understood oil and gas company, and certainly, our ownership of PVG does not facilitate that. That said, there's not a concrete plan that exists today with a timetable associated with it to sell our interest in PVG, either all of them or part of them. We don't really need the cash right now.

On the other hand, there's a lot of opportunities out there. Baird just walked you through what we're doing and beyond that, I think in those four core areas, there's opportunities to make acquisitions and do some other things that are outside of a capital budget that you just heard discussed. And one obvious way to help finance that is to monetize again some or all of PVG.

Long answer, there's no concrete plan to do it. There is no concrete plan to -- as to how to do it, in one piece or two pieces or three. On the other hand, we have taken some pains to say that it is a non-core asset.

That's helpful. Just a follow up. In terms of your ability to sell it and shield some of the taxes, what are some of the mechanisms you can use to shield some taxes if you do sell some of PVG or all of it. And then a follow-up there is any other non-core asset sales you've got planned?

One thing at a time. I may ask Frank to bail me out here if I misspeak.

The Gulf Coast sale that we just completed offers us an ability to shelter some of the gains we may have on any potential sale of PVG. There is the IDCs, until the Obama administration takes them away that can be used to shield some of that stuff and there are other non-core assets. Again, Joe, there's no specific plan, but you didn't hear Baird talking about much in the east except for the Marcellus; and we actually run our Mississippi operations out of the east which, by the way, we've just recently moved -- are in the process of moving to Pittsburgh to be more in tune with what's going on in the Marcellus.

You didn't hear him talking either very much about things like the Hartshorn coal and some of those sorts of things. Does that mean they're for sale? No, it doesn't. Does it mean they're not core to what we're trying to do, again, in a more focused strategy? Yes, it does. Selling some of those things obviously depends on what you get for them. I think would probably generate book losses for us that again could shelter potentially the gains on selling some of the PVG.

Okay. Very helpful. Thank you.

Yes, thank you.

Our next question is from Brian Corales with Howard Weil.

A quick question on the Granite Wash. Can you talk about some of the new prospects you are pursuing? Are they close to your current operation or other activity in the area? And what is the timing to begin drilling there?

Brian, yes, there are -- I would say in general, they're fairly close to what we've already done. There are some that are not real close. It is a mixed bag. The one that we feel is -- could be as large as south Clinton is not real far away. The beauty about the mid-con, there's plenty of vertical penetrations that give you a good sub surface picture of what all of these formations look like. So, really, it is just rolling your sleeves up and churning through a lot of data.

We're looking all the way from the Texas panhandle all the way down to south central Oklahoma. I mean it is a large geographical area. But there are plenty of wells drilled through the Granite Wash. A lot of data, and a lot of data to build some maps. The timing, we'll probably spud our first exploratory well probably early second quarter.

Just if I can have one more follow-up. Is there a lot of additional acreage to be had in the area?

There really is. We haven't talked about where these things are because we're still actively leasing but yes, there are -- there are plenty of open acreages -- or acres in -- I don't want to say all of them, but most of them. And you'll pay anywhere from -- I would say an average of $800 to $1500 an acre. We've been able to keep our acreage cost down to less than $1,000 an acre.

So, it makes it very attractive as compared to some of the other resource plays where acreage is going anywhere from $3,000 to $6,000 an acre. In any case, yes.

Ok, thank you, guys.

Thank you.

Our next question is from Irene Haas with Canaccord Adams.

Yes, just a quick question here. When you're talking about lower Bossier, do you mean Haynesville or do you mean other Bossier on top of the traditional section?

Secondarily, could I have more color on the horizontal Cotton Valley? You said it has liquid content. You're going to drill at about 18 gross of net well. How do you find which Cotton Valley zone you like to go horizontal? What is the thinking process behind that?

Nomenclature, Bossier, middle Bossier, it is totally confusing. It confuses me sometimes, to be honest with you. We refer to lower Bossier as most folks refer to the Haynesville, which is right on top of the Haynesville line. That's the area where we have the drilling of the horizontal wells.

Got you.

This upper Bossier, we're talking about completing within the curve section of the lower Bossier wells we're drilling, probably refers to the middle Bossier, people were speaking to. We refer to it as the upper Bossier in gross thickness, but there are a couple of zones within this overall upper Bossier that we think are suitable for horizontal candidates, and for the time being, we're going to complete that upper Bossier with a completion in our lower Bossier wells. Since we have decided to defer drilling any horizontal lower Bossier wells as I think a lot of you probably picked up on.

The Cotton Valley, we will drill eight gross of these wells. We will focus probably in the southern part of our acreage. We will focus primarily within the Davis sand part of the Cotton Valley. The good thing about having a number of vertical wells drilled, it gives -- being able to correlate all of these open whole logs, it does show you know, the contiguous or continuous members of the Cotton Valley itself. So, we'll focus on those members in which we can follow well to well to well in the vertical wells. And we will drill laterally in those zones. But primarily, we'll be in the Davis part of the Cotton Valley.

Okay. Great. Maybe you can help me a little bit. How are your Haynesville Bossier well holding out in terms of the decline curve? Are you guys cranking the wells on pretty high or are you producing them at restricted rate? How are the wells behaving thus far?

Well, the last two wells we drilled where we put away ten frac stages, they're right on the tight curve for the 5.5 B. The other eight wells that we drilled down in the general area are north of 4 Bcf wells average. The reason being, we think is because we didn't put enough frac stages away. We think the more frac stages clearly helps your initial production and ultimately helps your reserves.

To answer your question, we are -- every Bossier well we have drilled across our entire acreage position, we are -- we have been restricted. I think there's only one well in which is not restricted. It is a poor well, it is a very poor well. We hold back pressure on all of our wells.

And then do they behave better when you hold that pressure?

Well with the concern of sand crushing and embedment and all of those bad things that happen, at these kind of depths and closure pressures, we think holding some back pressure on these wells is beneficial early in their life. So, I can't prove to you that it is advantageous and beneficial, but I guess intuitively, we think it is.

Okay, thanks.

You're welcome.

Our next question is from Welles Fitzpatrick with Johnson Rice.

Good afternoon. On the newer Granite Wash acreage, can you talk about what you might know from previous penetrations about the gas/oil ratio there?

Well, the previous penetrations in most cases, they were going for deeper zones. Most of those wells are not completed. Because there's such a long history of drilling vertical Granite Wash wells in the Anadarko Basin and you know, people tended to walk away from that kind of stuff and did not in most cases complete those vertical wells. So, I can't tell you with the -- the oil and gas ratio may be. So, really, all we're gathering is geological data, thickness, crossity, salt water saturation calculations that help us determine gas in place and whether they have a good chance of being a commercial. But there's nothing really to point our finger to that shows what liquid gas ratios will be.

Okay. And on testing new areas of the wash, you talked about new geographical areas. But can you talk for a little bit about any plans to test the additional zones either on your older acreage or on the newer stuff?

Well, it will probably be in different prospects, not on either existing -- on existing acres that we have either acquired within south Clinton or outside of south Clinton, so these will probably be new ideas with new acreage blocks. That could include a different kind of wash. It could include some carbonates, some (indiscernible) carbonates, without getting real specific, but those kind of unconventional opportunities.

Okay. Thanks, guys. That's all I've got.

Thank you.

Our next question is from Jeff Robertson with Barclays Capital.

Question for you on east Texas. Can you talk a little bit about the comparison of the economics between Cotton Valley horizontals and the Bossier horizontals as you've seen them so far?

Well, at least based on offset activity on the Cotton Valley since we have yet to drill our first one, we think the after tax ratio returns because of the high liquid content and of course, because of higher oil prices, will probably be in the 25% to 30% after tax, whereas lower Bossier is probably around 20% after tax.

Okay. Are the Bossier wells you all are drilling this year designed --a program mainly to hold acreage or just to continue to delineate it.

Most of it will be just an exploitation program based on what we know to date. A few case we will be holding acres, but in most cases, it is just drilling the best opportunities.

Okay. And one question for you on the Granite Wash. The new prospect areas that you have put together, do you anticipate that the drilling cost on those will be similar to the $6 million to $6.5 million you guys are using in your tight curves or are they deeper or shallower? Can you talk about that?

They're about the same depth, maybe a little bit shallower in some cases. They will cost us a little bit more money because these initial wells, we will drill them vertically first just to get an open whole log, see what the rock looks like.

Those kind of factors. Then based on that open whole log, we'll plug these things back and sidetrack it and go ahead and drill horizontally in that Granite Wash.

Okay. Thank you.

You're welcome.

Our next question is from Steve Berman with Pritchard Capital Partners.

Good afternoon, guys. Baird, on the two operated Granite Wash wells you just announced, how do those stack up relative to the typical well cost on the recent slide of $6.3 million. How do you think those two will come in?

They will be in and around that ballpark. Because of the timing that -- in which we got those wells drilled from spud to rig release, drilling costs were extremely low. The completion costs tend to be going up right now. In the mid-con and east Texas. But the $6.2 million to $6.3 million dollars is a good number right now.

And BURs of the recent wells have been in the 7.5B range? Is that still a good number for the more recent ones with the higher rates?

We think so, yes. Yes.

Our results are only improving, but we're also drilling most of our wells right now, some of the sweeter spots, of course based, on our delineation of our overall acreage. But higher number you just -- you just said is a good number, yes.

And a quick question. On the Davis Cotton Valley horizontal, what do you think you can drill and complete those for?

Probably in the -- probably in the $4 million to $4.5 million range.

And I'm curious. A lot of the other companies down there, they've either drilled or talking about drilling horizontal Cotton Valley's more in the Taylor sand. You guys are talking Davis. Can you talk about that a second? Why not the Taylor?

Just happens to be we feel like our Davis sand, down in the southern part of our acreage is the major contributor to overall Cotton Valley results. We drill some extremely good vertical wells down in the southern part of our acreage. There is never a slam dunk in this business. But based on the vertical results, the continuity of the zone, in our overall acreage position, we think it is just the most suitable part of the Cotton Valley for horizontal drilling.

All right, great. Thank you.

Thank you. Our next question is from Biju Perincheril with Jefferies.

Hey, good afternoon.

Good afternoon.

Can you guys talk a little bit about your 2010 Cap Ex program in light of a potentially weak year for natural gas prices? You guys have picked up activity pretty dramatically over the last couple of months.

How flexible is that program if gas prices average say $4 to $5 in Mcf and, more specifically, which plays would we see a reduction in activity if gas prices head south?

Well, you know, just like in 2009, when prices deteriorated, we turned off the spigot. And we don't anticipate doing that again. But if it happens, it happens. And we're not going to drill in a sub-four S environment, not with these high initial rates.

If history holds and gas prices deteriorate, but oil prices don't deteriorate as much, the Granite Wash becomes that much more economic -- already our most economic play in terms of returns. The horizontal Cotton Valley, as you've just heard repeatedly, the appeal of that is that it has some liquid, a liquid content and so I would imagine -- a liquid content, assuming they work the way we think they will, those would also survive longer than, for example, Mississippi and maybe the lower Bossier.

The Marcellus is so important to us in the sense that we want to learn what's going on there. I would be reluctant to back that off unless you're talking about $2 gas or something horrendous. We don't have an issue, if this is where you're going with expiring leases. So, it is not that we have a gun to our head necessarily to drill anything. That's why if prices go to deteriorate, we can back it off, and we've shown in 2009 we're not afraid to do it.

Okay. I realize this isn't a static number with an ever-changing asset mix, but can you give us some sense of what maintenance Cap Ex might be in the EMP business in terms of how much you guys need to spend to keep production flat?

Order of magnitude we've said that's around $200 million.

Okay. Great. Thank you.

Okay, thank you.

Thank you. Our next question is from Richard Tullis with Capital One Southcoast.

Thank you. Good afternoon.

Hi, Richard.

Baird, looking at the Marcellus acreage, could you give us rough split of the acreage by County, the 33,000 that you currently have?

Well, without telling you exactly where some of our new acreage is because we are leasing, we wanted to hold that tight. Most of the acreage we have picked up here recently is up in the Potter/Tioga County area. We've got some acreage that slops over into -- into southern New York, adjacent to the Potter/Tioga County area. So, we've got about 20,000 net acres in that overall Potter/Tioga County/New York area.

Okay.

The other -- we've got about 9,000 net acres down in southwest PA that we will probably drill one well on this year. The other five wells, one of which we of course just finishing up on, in all likelihood will be up in the northern tier of Pennsylvania there. The other acreage that we picked up, which is about 1,500 to 2,000 acres is in our new area that we have just started leasing; and I will tell you it is in Pennsylvania.

Okay.

Not very descriptive, I know but it is the best I can do right now.

That's fine. At this point, when are you planning to do your first horizontal up there?

We'll do it this year. I can't tell you if we'll drill another vertical well first or go ahead and drill our second well being horizontal up in northern Pennsylvania. We're going to go ahead and get this first vertical well completed. We probably won't complete this thing until probably be late March, April time frame.

Sit back and see what it is going to do, of course, get this core analyzed which we feel is very valuable information. And sort of take it from there. But we plan on drilling the most of our wells horizontally this year.

Okay. Then looking forward, you know, beyond this year, down in east Texas, hearing the good prospects that you have for the Cotton Valley horizontal,could you see totally shifting out of doing lower Bossier at all and just concentrating on the Cotton Valley Davis sand horizontals?

Well, I think in all candidness, we need to see if we can continue to replicate what we did last year with the last two wells. If we can, we feel like it is very viable candidate. We'll continue drilling lower Bossier wells. If we can't convince ourselves that it is the right thing to do economically, then as you say, we will -- because of the sheer number of opportunities we have right now, we'll move some money around and do some other things.

You still looking at around $8 million well cost for your lower Bossiers?

Yes. There has been some -- numbers have been all over the place. That's short changing yourself on the completion side, which we don't think is the right thing to do. We think that $8 million number is a good number to use.

Okay. Then just finally from me, if you could talk a little bit about your reserves report, particularly, Granite Wash and Haynesville? What did you receive per well?

What did we receive per well? Well, we're using a type curve for the Granite Wash. Typically.

Okay.

We're using the 6.2 Bcf equivalent, which is about 4 Bcf of gas and the remainder, the 2.2 Bs is tied up on the oil phase. The Granite Wash -- we have some other puds both in the Granite Wash that are less than the 6.2 based on offset performance that still cut the mustard economically. Because the returns are so attractive based on the average well of being pretty close to 100% after tax, you could drill 4 Bcf wells equivalent and still make a lot of economical sense. That's not what we're focusing our effort on. We still have some of the wells booked.

In the Haynesville, we're not booking anything going forward unless we are convinced that it is -- that 5 Bcf threshold range. Now, we do have again some lesser puds in the Haynesville, but going forward, we will not drill anything -- book anything less than 5Bs.

Okay. That's all for me. Thanks very much.

Yep. Thank you.

thank you. Next we'll hear from Greg Brody with JPMorgan.

Good afternoon, guys. Just a follow-up question on the reserves. In your revisions number, the negative 90 Bcf, is that from the Cotton Valley? What's driving that?

Is that a performance number?

Yeah.

Okay. Well, some part of it is Cotton Valley, yes. There were some there were some liquid issues, NGO issues that we -- efficiency issues on the plant, but for that reason, our liquid yields came down. So, that was part of it.

There were some performance revisions in the Bossier on the PDPs. We had booked -- a number of those wells we had drilled in 2007-2008 based on a type curve across our entire acreage position and some of those wells have not met that 5 Bcf type curve so we've had to deal with that. That was probably the bulk of it between the PDP on the Bossier side and the Cotton Valley puds because of liquid issues.

And then how much -- how much additional pud did you book with the new SEC rules and what type of additional offsets did you take? On Haynesville?

If you're asking me the question what we booked that we would have typically booked as a prob, we booked about 150 Bs in the pud category that typically would have been in the probable category which we're allowed to do under the new SEC. A lot of that -- the Granite Wash of course, for apparent reasons. Part of it was in our Chock, for apparent reasons. And some part of it was in our east Texas Bossier for apparent reasons. So, those would have been the three biggies.

Did you -- you take one offset?

Yes.

We did not get real aggressive with this by the way. In fact, we held back quite a bit. We didn't want to get crazy with this. But we -- we're ourselves in -- Wright & Associates felt comfortable with it, of course, based on the well control we had and the results we had that was the basis of our new pud bookings.

That's very helpful. That's it for me. Thanks.

Next we'll go to Lee Rimaldo with Stone Harbor.

Just one question left. In the cash flow, the reconciled cash flow statement, there was outflow of $23 million characterized as -- I have to find the page. I think it was investment back into PVG, PVR. Oh, yeah. Investment in PVG and PVR for the fourth quarter of $23.2 million. Could you just clarify that?

We're looking for this.

It is on page 12. The negative $23 million net. That reflects the -- that's the adjustment you make to get to the PVA equity method numbers. It represents the portion of the cash flow that's attributable to partnerships.

Okay. Okay. So, that was the equity pickup that was then subtracted out?

Yes, from using the consolidated method, it overstates it by $23 million by making that adjustment, you get it to the equity method.

Okay. All right. Great. Thank you.

Yes.

Thank you, our final question is a follow-up from Joe Allman from JPMorgan.

Thank you. And Baird, in terms of the Cotton Valley horizontals you're talking to about to the Davis sands, have any other operators drilled horizontals near your acreage?

Yes. Forrest has drilled some wells, XTO has drilled some wells, Comstock drilled some wells. So, yes, there's been activity in and around our overall Cotton Valley acreage position, Joe.

Okay. And those results are encouraging enough for you to pursue that?

Yes. Yes, we spent a lot of time looking at this. BP has done some offsets, some horizontal offsets, not too far away. So, we're going into this with our eyes wide open here.

Based on our geology, based on the continuity of the Davis in and around our acreage, based on the vertical results, it has all of the makings of being very attractive and we're not going in to depleted areas by the way. This is going to be going into undeveloped areas in which we have vertical puds booked that we feel there's not going to be any drainage issues. So, for all of those reasons, we feel pretty good about this.

Okay. That's helpful. And then Baird, I think you said the cost of the horizontal, you would expect to be $4 million to $4.5 million. What kind of EURs would you expect for that program to be successful, and I think today, if you were to drill vertical, would it be $2 million to get about a B?

You could actually drill a vertical Cotton Valley well today for about $1.7 million and the B number is a pretty good number. We're using 4 Bcf in gas plus liquids. We think there are about 50 barrels per million of liquids. We don't think, we know, based on the processing that our Cotton Valley currently goes through with our PBR facility, so we feel good about this.

Okay. That's helpful. Then Baird, switching over to Granite Wash, for a second, the two recent wells, I think you said one was $60 million cubic feet per day, the other, 18.2. What time period is that initial production rate at?

You know, those were turned in line. That's a good point. I didn't mention this. Those were sorted two days after they were turned in line and these wells were still cleaning up. So, there should be some modest improvement over time, at least based on how the wells typically act. These are not necessarily IPs. I'm just giving you current production based on being in line now for about three or four days.

I didn't get a chance to listen to the conference call or really look at the PVR release, but could you talk about -- I know this is not for you, Baird, but processing volumes versus the gathering volumes? It seems that your processing volumes were quite high and were a big contributor to the fourth quarter. Is that right and is that Granite Wash? And what is the forecast going forward for volumes overall processing versus gathering?

Are you talking about -- you're talking about PVR midstream

I'm sorry. I'm talking about PVR midstream.

Yes and their processing volumes went up basically in their panhandle region, their key region, it is not our Granite Wash. There is some Granite Wash wells around there but they don't process any of our gas and the reason the processing volumes went up in the fourth quarter say versus the fourth quarter of 2008 is that in the first half of the year, we opened up -- we built a $40 million a day plant that we called Spearman two and we bought $60 million a day plant both in those areas. So, a lot of gas that we were bypassing, almost $50 million a day is now being processed.

And that's accounting for -- as well as the fact that when we did this, we lowered the line pressures from about 150 pounds to 75, I think is the number. And a lot of gas that was being pushed back in is now coming out. I can't give you that number.

But those two factors, the plants themselves and the fact that the whole system became much more efficient contributed to the fact that we're processing a lot more gas. But that has nothing to do with Baird's activity.

I understand. There was a bad transition on my part. I understand it was the PVR midstream. So, with that, what's the thinking going forward there, Jim? Do you expect continued uptick in the Granite Wash volumes for the PVR midstream just because of industry activity and then could you also address were you gathering volumes down for PVR midstream and what's the thinking going forward there?

Well, we expect a gradual increase from processing volumes and that is predicated on the fact that the people who are PVR midstream's customers are telling us that they are going to continue drilling or in fact increase it. And again, you referenced the Granite Wash.

I want to make it clear it is not our Granite Wash. I know you know that, but for people on the call. We're aware our Panhandle region does intersect and gather some Granite Wash gas, but it is not from Oklahoma. It is from the Texas side.

I'm not sure if I -- why is our system throughput down fourth quarter to third quarter I sure what you're asking me. I don't think I have a clear answer to that. The drilling activity in the first and second quarter of 2009 slacked off some and it hasn't recovered greatly and I guess that's probably the reason. I should have a better command of that but I think that's right.

Okay. All right. Very helpful. Thanks, everybody.

Yes. Okay, operator, I think that wraps it up. We appreciate everybody's presence on this call. And we look forward to doing it again at the end of the next quarter.

Thank you. Once again, that does conclude our presentation. Thank you for your attendance.