Ranger Oil Corp (ROCC) 2009 Q2 法說會逐字稿

Greetings, and welcome to the Penn Virginia Corporation second quarter 2009 earnings conference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Jim Dearlove, President and Chief Executive Officer. Thank you, you may begin.

Thank you, operator. Good afternoon. The other speakers who I'm joined with today will be Baird Whitehead who runs our oil and gas company and Frank Pici who is our CFO. We have some other folks standing by if we need them.

What I think I'll do is follow along the release at least in summary form and I'll let Baird take you through the details of operations and Frank deal with some of the financial matters. As you can see, we're -- as the -- as we say, we're reporting now in the second quarter of 2009 and the comparisons that are in here with the year-ago quarter which is the second quarter of 2008. Oil and gas production for this quarter was 148.9 million a day, which is above what it was a year ago quarter, fairly significantly, and it's slightly off from what it was in the first quarter of this year by about 2%. And these numbers are given in more detail in the operations release that we put out on the 27th of July.

Operating cash flow at 62.4 million is well below what it was a year ago quarter, 136, which was a record quarter for us, I believe, and a little bit off from what it was in the first quarter of this year. Excluding noncash changes in derivatives, drilling rig stand by charges, impairments, PVA recorded what we're calling adjusted net income that was actually a loss of $6 million, again, way below what it was a year ago where we had a gain of almost 49 million and this was a little lower than the result of the first quarter which was 2.6 million. Net income was negative 22 million versus a net loss last year of 4.5 and then the first quarter 7.2.

These lower numbers are, of course, primarily a direct result of lower commodity prices, in particular natural gas which for the quarter for us averaged $3.49 an M and just to contrast with where that was a year ago, it was at $11.24. So a fairly dramatic change, even in the first quarter of this year the average was $4.48 an M and gas is what we are. I mean we have some exposure to oil, but it's really gas. Even if you look at the first half of this year, we've only averaged $3.99 versus almost $10 a year ago first half 2008. Now, our hedges as Frank will discuss with you a little bit have helped, but they can't nearly offset changes of $8 an M when you're comparing one year to another.

Let me just quickly digress for a second to PVG and I do mean quickly, but as those of you who follow the Company undoubtedly know, we own a 77% interest in a master limited partnership known as Penn Virginia GP Holdings trading under the symbol PVG. PVG is just a pass through vehicle. It's the public general partner of a second MLP, Penn Virginia Resource Partners or PVR. The release gives you a brief overview of PVR, basically the partnership has two pieces, a coal royalty piece, which is the bigger piece, usually two-thirds to three-quarters of the cash flow and a gathering and processing piece.

The coal piece, as far as coal goes, does just fine. It was virtually flat with last year in the quarter. It has embedded in it some gas royalties and a timber business, and both of those were negatively impacted by commodity prices. So it was off a little bit and likewise in the processing business, even though volumes were up, prices were down and so PVR was off a little bit compared with last year and I can refer you to our website, PVRresource.com where you can see everything, the press release is out. We had a call concerning that about two hours ago. It will be posted very quickly if it's not posted already.

What really matters to us with regards to PVG and then I'll get off it is its distributions and on an annualized basis, PVG distributes $45.7 million of pretax cash to PVA. It recently announced that it will be making its quarterly distribution for the second quarter 2009 of $0.38 a unit, which is unchanged from where it's been the last three quarters and up about 6% over where it was a year ago. And that distribution will be made on the 20th of this month.

Another thing I'd like to say before I turn it over to Baird sort of following along the quote that's attributed to me in this press release, like most E&P companies and virtually any other company, Penn Virginia keeps a very close eye on liquidity, particularly this year, 2009. And as a result of the commodity price environment we're in, we've curtailed drilling and look to cut costs wherever we can. During the quarter, we were able to raise approximately $365 million of capital, which was very important when one's looking at liquidity. $65 million of that came from new common equity and another $300 million came from senior notes that are due 2016. These capital raises have resulted in our having almost $300 million available on our revolving credit facility, so while drilling is curtailed right now, we're sort of locked and loaded when we think prices are right, we're ready to go at it and resume a fairly active drilling program. But to take you through operations, I'll turn it over to Baird Whitehead.

All right. Thanks, Jim. As I've done in the last couple of phone calls, I'll bring you up to date. I'm going to bring you up to date on our three major plays now, that being the Granite Wash, the Lower Bossier/Haynesville and the Chalk. I'll tell you what I know at this point in time and where we stand and how we're doing and what we think going forward. In the Granite Wash, we drilled four wells in the second quarter, 1.2 net. The IPs of these four wells ranged anywhere from 5.6 million a day to 23.6 million a day equivalent with an average of almost 15 million a day. We now have 23 horizontal wash wells in line with an average IP of almost 12 million a day and an average 30-day rate of 8.2 million a day. Again, all of which were restricted at the end of the 30 days. Today we have about 110 million a day of gross production equivalent coming out of what we refer to as [Southglenn] from these 23 wells.

The average net production in the second quarter from the Granite Wash was almost 23 million a day, for about 58% of our total Company production, so it's had a significant effect here in just a year's time as far as a percentage of our total. And right now as we speak, our net production is actually about 26 million a day from these 23 wells in the line.

To remind you, we typically drill these things with lateral lengths of anywhere from 4,500 to 5,000 feet with four to five state frac jobs through (inaudible) with anywhere from 1.5 to 2 million pounds of sand. We -- the average ultimate -- ultimate reserves of these 23 wells right now, some of which we have production information of a couple of years, is 6.2 BCF equivalent and an an estimated 4.2 Bcf of gas and about 330,000-barrels of oil. We currently model these wells at about 6 Bcf with the drilling and completion costs of a little over $6 million, even though we experienced some drilling and completion costs of even less than $6 million on at least one well that we drilled in the first quarter.

We model these wells with an IP of 8 million a day with 90-barrels per million or 720-barrels of oil a day with a 30-day average of 5.8 million a day at the same 90-barrels per million, plus 90-barrels per million. We've had wells made up to 120, 130-barrels per million in some parts of that play. We've said repeatedly here over the last three or four months that this is clearly the best investment opportunity we have within our drilling opportunities and if you use today's strip prices, it -- we have north of 50% after-tax rate of return. We expect to drill up to 6 net wells in 2009 of which we drilled three net wells during the first half and remind everybody we have about 10,000 net acres within the Southglenn field of which we have about 90 drilling locations within our acreage position.

We expect to stay active in this play. I know that Chesapeake has said that they also expect to remain active and could possibly add to it as time goes on. What makes the economics as good as they are, it's not only, of course, the gas rates, but as importantly or more importantly is oil prices associated with these high liquid rates.

Now to go to the Haynesville or Lower Bossier, to date we have drilled 16 wells including one well that we drilled in the northern part of our acreage that we announced that it was uneconomic. The second quarter we drilled and completed two net Bossier wells, one of which was a steal, two which tested 11.4 million a day with a flowing pressure of 4,600 pounds. The second well was the James Madison Fur 2H which tested at 9.6 million a day with a flowing pressure of 2800 pounds.

So the average of these two wells for the IP was 10.5 million a day, which by the way, these wells are about four miles apart from each other. The 30-day average of these two wells were eight for the steel and 6.5 million a day for the James Madison Fur or an average again of 7.3 million a day.

If you take the IP of the first 13 wells, excluding these last two we drilled, the average IP was 5 million a day and the 30-day average was 3 million a day versus the IP in 30 day of these last two wells at 10.5 and 7.3. So clearly you can see the results of these last two wells are much, much better. In fact, by a factor of over 2, than the first 13 wells that we had drilled. The first 13 wells we typically did a next stage frac job. We pumped anywhere from 1 million to 1.5 million tons of sand. The last two wells had ten stage jobs. We put away 2.5 million pounds of sand in the steel well and 3 million pounds of sand in the James Madison Fur. So not only did we pump away two additional stages, but we also pumped more sand away in each stage.

Other recent adjustments we made as time has gone on is we have -- where we have actually placed the lateral within the Bossier itself and the direction or the azimuth of the lateral drilling now essentially in a northwest direction, about 25 degrees. You can't completely explain the results of these last two wells just compared to the 13 strictly on completion. I mean we know that geologically there are reasons and changes across our acreage so as you go from south to north the geological issues improve, but we do think that the completion costs and the additional emphasis on profit and stages has made a difference in the results.

From a planning standpoint, up until these last two wells, we had been using 6 Bcf, with a $7.2 million drilling and completion cost but going forward we think more realistic is probably around $8 million drilling completion costs, most of which is a result of our -- the increase in frack stages. But at this point in time, we are sticking with the 6 Bcf reserves. We think it's premature that even though our initial and 30-day rates are increased by a factor of 2 to be making those numbers higher at this time, but it does give us a high degree of confidence that we can continue to replicate an approximate 6 Bcf well at least in some part of our acreage. I know there is a -- a lot of numbers flying around with reserves for the Bossier. There's a lot of decline rates flying around.

I think there's a lot of misinterpretation of exactly what these decline rates are when sometimes you see decline rates of 80 to 85%, those 80 to 85% decline rates are instantaneous decline rates as defined within the hyperbolic equation. So over time, by definition of hyperbolic, that decline rate decreases every day. So if you look at our [Fogle Fie] well, for instance, which we've had on line now for about 13, 14 months, the decline rate now of that well is about 25%. So you can see the big difference in initial decline rates versus decline rates over a fairly short period of time and we think that that explains why we think we'll end up with the 5 to 6 Bcf well. Even though we don't have as high of initial rates that you may see across north Louisiana, for instance, this end factor or beta factor we think is higher because it is a tighter reservoir, we think ultimately that we will see the same amount of reserves, it's just going to take a longer period of time to get it out of the ground. So for that reason, we remain confident with the 6 Bcf well.

When we do kick off drilling, we're going to focus in about the bottom two-thirds of our acreage. To remind everybody, we do think that we've got about 160 Bcf of gas in place for 640 acres. If you apply a 20% recovery and apply that to 50% of our acreage, we're talking about 1.3 Tcf gross and if you apply a risk factor for various reasons, we think just in the Lower Bossier itself, we've got about a Tcf upside across our acreage position.

So again, we remain enthusiastic with the results of the last couple of wells, we even feel more confident about the reserves going forward and once gas prices rebound whereas we're confident to start drilling again, we will jump back in and start drilling in these areas where we drilled the last couple of wells.

And lastly, is the Chalk, even though we didn't have any activity in the second quarter, again, we continued to have more confidence in that play. We have 20 wells, horizontal wells in line four of which in our Gwenville field, 16 in Baxterville. The average IP is 1.3 million a day, the 30-day average is a little over 800 Mcf a day, but the 60 day average on these wells is actually 1.2 million a day and it's just a matter of how we've decided to produce these wells because we typically see quite a bit of sand flow back. For comparison, the average IP of all of these vertical wells we drilled since around the year 2000 was about 400 Mcf a day and the 30-day average was about 266 Mcf a day. So there's a big difference in results. There's a big difference in the economics of these horizontal wells.

Again, we drilled anywhere from 2,000 to 3,000-foot laterally, we fracked with 7 to 9 frack stages, putting away about 700,000 pounds of sand. We modeled these wells at about 2 BCF, drilling and completion costs of $2.4 million, which at today's strip is about an after-tax rate of return of pretty close to 20%. This is a great play for Penn Virginia. We continue to improve our drilling and completion results. In fact, if you look out of the 20 wells we have drilled, nine of those wells actually have ultimates that we think right now that exceed the 2 Bcf or the reserve that we use to model the average well and those nine wells are actually the most recent wells we have drilled. So I think we will continue to see improvements not only in the results of these wells, but I think we can continue to ratchet down the drilling completion costs a little.

And lastly, just to bring everybody up to date on our Marcellus, we do plan on trying to get 1 vertical well drilled by the end of the year. Up in northern Pennsylvania we are in the process of getting all of our permits together. We are on track to get that spud sometime the fourth quarter and to remind everybody, we have about 40,000 net acres in that play, pretty much evenly split between northern Pennsylvania and southwest Pennsylvania. And with that, Jim, that's it.

Thank you, Baird, I thought that was very complete. Frank, if you would talk about capital resources derivatives and then sum up our guidance, that would be helpful.

Sure, Jim. Good afternoon, everybody. Just very quickly, as you saw in the press release, we mentioned where we were with our credit facility, DBA. As you know, during the second quarter we completed an equity offering and a high yield offering both of which served to free up a lot of credit facility capacity. So at the -- as of the end of the second quarter, we had close to $300 million available on our revolver, that's the number -- that's roughly the number now as well, a little bit smaller than that, not much. So we've got plenty of liquidity there.

On the hedging side, again, as noted in the press release, we're very well hedged for the rest of 2009 and it gets something like 85% hedged on the gas side for the rest of '09. That drops to about 60% for '10 and then we've actually added some positions for 2011 as well. Those are all at floor and ceiling prices that we consider healthy, above $6 or higher on the floor and, of course, we'd be happy if we didn't pay anything or actually had to pay a few dollars, that would mean that the prices would be high enough that we would make out on what wasn't hedged. We've got some oil hedges on as well, but in any event, it's a little bit unusually high hedge position for us. We did that defensively, but going out in time, we're now -- we've got positions going out a couple of years and we're happy with where we are.

On the guidance side, there's a guidance table in the press release, pretty busy one. Really what we usually focus on are just changes from the last set of guidance we provided as we've mentioned, we did not change production guidance. It's still at the 48 to 50 Bcf number for the year. Our expense guidance numbers haven't changed either on the operating side. Our DD&A guidance was increased a bit just a result of the production mix we've got and the cost basis in our properties. The other -- only other really significant change in the E&P side is CapEx has been increased. We had a range of 130 million to $140 million for the year. That spending's been -- range has been increased to 165 million to $180 million. Those increases are primarily because of some expected increased drilling in the Granite Wash along with our partner up there and then we've increased our -- some spending expectation on our leasehold acquisition side to take advantage of what we think are some very reasonable prices to acquire some additional leasehold in our core areas.

So again, those are the primary changes. We've made a few changes in the coal and mid-stream sides as well, but we talked about those on that call. And feel free to access the replay or look at that press release as you'd like. Jim, that's pretty much it on the guidance side.

Thank you. Thanks both of you. Operator with that, I think we'll turn it over to questions.

Thank you. (Operator Instructions). Our first question is from the line of Scott Hanold with RBC Capital Markets. State your question, please.

Yes, thanks. Jim, just kind of curiosity. When you looked at the price where it makes sense for you guys to become more active, is there sort of a magic level that makes it feel a little bit better and can you kind of also address with the strong returns you're seeing in the Granite Wash, could you get more active there right now and kind of logistically when you look at the -- what is it 90 locations that you have, how many of those would be operated locations?

I think that's a very good question and thank you for it, Scott. Good afternoon. Specific to the Granite Wash, Baird, I think I might let you just -- we've got 90 locations. We're not -- we've not been proposing wells, we've kind of been going along with what Chesapeake wants to do and to this point, Scott, that's because in our efforts to live within cash flow even at those kind of returns, we've been reluctant to spend a lot of money. Now, we -- as we -- Frank just said and I did, too, we've recharged the balance sheet a little bit with this high yield and this equity offering, so we're sort of biding our time a little bit, but I don't think we plan to propose wells and I know your question is at what price would you do it. We're getting good enough returns right now and at the end of this year those rigs that we've put on stand by will come active again and I'm sure we'll put them -- one or more of them to work up there and I would imagine, Baird, between now and then we're just going to wait.

Yes, we've got -- we've probably -- to answer your question, we could -- we would operate anywhere from 25 to 33% of the total 90 locations. We've got two or three wells that we would operate that we could -- that are essentially ready to drill, including location on I think one or two of those and as Jim said, we have a rig that we could bring back on that's on stand by right now if we deem to do so. But if -- for the time being, we're just going to go ahead and just go along with Chesapeake and what they propose and, you know, they told us there's a chance that they may ramp things up even more so than what we have anticipated, but I think it's fair to say if they elect to do so, that we will -- we will stick with them, of course, and continue to drill wells because the returns are so solid.

Okay. Is it -- is there stuff that you all can still learn from them as far as what they're doing versus what you may try in the Granite Wash?

Not really. I mean the last few wells we've drilled, even though we didn't have near as many under our belt, we actually drilled the last one under $6 million. So I -- I don't think so. I think between what we have learned ourself and what we have learned participating with Chesapeake that we feel very confident that we can operate these wells just as well as what Chesapeake does and vice versa. I think that they would elect not to participate with us for their interests in these wells if they thought we were a lousy operator.

Okay. Good. And moving to the Haynesville, can you give us an update on what you're thinking about the upper Bossier and I think if I'm not mistaken, is it Fogel well where you dropped a frack as you went down? Is that something that still interests you and I think there's been some drilling a little over in Louisiana for that formation?

Yes, very much so. Even though we won't get it done this year, we have every expectation to drill horizontally in the upper Bossier next year and we also plan on trying to drill horizontally in the Cotton Valley. With the liquid prices in the Cotton Valley and with liquid prices as high as they are and with the PVR facility, it becomes very compelling economically to get back to drilling Cotton Valley wells, especially horizontally, so you'll see us attempt both those sometime next year.

From a geological perspective, are you aware of anything that, say, differs from the upper Bossier in Louisiana versus where you all are situated?

I'm really not smart enough to know that, Scott. In our case, it becomes more of a fractured shale that's not -- it's not organic. The gases within the natural fractures itself is more of a gray shale. It's a lot thicker. If memory serves me correct, it's 600 to 800 feet thick, something like that. So, gas content is less because it's not organic, but you've got a lot more thickness, so gas in place becomes enough to make economical sense out of trying to drill these things horizontally. So until you try one or two or five, you really don't know, but we do plan on trying to drill our first one sometime next year.

Okay. I appreciate it, thanks.

You're welcome.

Our next question is from the line of Richard Tullis with Capital One Southcoast. Please state your question.

Hey, good afternoon. On the locations for the Granite Wash, the 90 locations, those are gross, I imagine, Baird?

That's correct.

What's your net locations?

I think we averaged working interest is about 35, 36%.

Okay. What do you think the ultimate space is there? Do you think that's as close as it gets or?

Yes, I do. Some of these wells -- some of these fringe wells you could possibly support putting five wells a section, right now. We're using four wells a section. But some of the sweet areas of the -- of the play, four wells per section is more than adequate. We've got some wells that will cume or have ultimates over 12 Bcf. We model 6, but there's some horses out there that, we expect to make over 12 Bcf equivalent, so those are the kind of areas that you need lesser wells because the reservoir is a lot higher.

Okay. And in the Marcellus, what counties is your acreage predominantly located in?

I know we got Potter up in northern Pennsylvania, have a little bit in southern New York, down in southwest PA, West Moreland, Somerset, a little bit of Fayette.

Okay. Any potential to get a little more aggressive there than just the one well in the second half?

I don't think so. I mean we're running in place trying to get things put together to get one well drilled. As with everybody in this play, what we plan on trying to do is to get a well drilled, keep drilling early next year, get these wells in line and test them and see what we have, commit weather we need to drill these things horizontally or stick vertically, stick with a vertical program. So we're further behind than what some of the other players are, but we will probably approach it the same way as they did.

Okay. And then the Haynesville, what are you guys modeling internally for first year decline for your average well there?

If you just take -- if you take year-over-year declines, it's about 50%.

Okay. What's it off of you peak?

Well, using instantaneous decline, I think we're about 80%.

Okay. And last question, I guess more for Jim, any consideration given to simplifying the reporting structure there and/or, selling down any part of the MLP?

Well, the short answer is the same as the long answer. Yes, there is. And if you notice in our Q that we'll issue, I don't know, Friday, or whenever it's going out, but a sentence right out of it says that in order to fund growth, we expect to use a combination of cash flow from operating activities, borrowings, issuances of debt or equity, sales ever noncore assets and the sale of part or all of our equity in PVG. And so it's certainly something that is under consideration. PVG is an extremely important asset to us, but as an E&P Company, it's not a core asset to us. So if it makes sense to monetize some of it or all of it, we'll do that as the market allows us. In terms of deconsolidating or simplifying the reporting structure, that has other complications and as much as we would like to make it easier for you, I think we'll probably stay in terms of reporting the way we are for now.

Okay. Well, thanks very much. I appreciate it.

Yes.

Our next question is from Irene Haas with Canaccord Adams. Please state your question.

Yes, just want to have some update regarding Bakken are you guys going to get a little more active in that play with oil prices firming?

I'm not sure we understood what you said. I'm sorry.

Any news on your Bakken acreage that you're working on?

Oh, Bakken, I'm sorry, Irene. We've actually got it on a market to sell. I think we told people that or I thought we had, but we've got it on the market, in fact, actually, we expect to have bids back here, I think, in two or three weeks. So to answer your question, no. That's why we misunderstood you, Irene, it's been removed from the radar screen.

The other day, what it got down to, Irene, we didn't have enough acreage probably in the core area that made sense and since, the other three plays we talked about, we've got more than enough to do, it just made sense for us to focus on less versus more.

And when would you expect the deal to close and have you sort of any dollar amount in your mind that you might be able to monetize?

Not really. It won't be material. A few PDPs on it, so it's primarily an acreage deal.

Okay. Great. Thanks.

You're welcome.

Thank you.

Our next question is from Steve Berman with Pritchard Capital. Please state your question.

Good afternoon, gentlemen. In Brigham's press release, they referenced the Bayou Postillion having declines higher than they forecasted and on their call today someone asked them about that and they said well, we'll defer to Penn Virginia, so I'm going to defer to you and ask if there's anything -- anything to make of that.

I mean it just -- you try your best on trying to forecast when you think these things are going to start to water out and decline and one of the wells that we drilled, I think, last year sometime has made about 4 Bcf the last well, the Cotton Land 5, it fell off the end of the table and that's what caused the decline rate to be higher and -- but it's nothing mechanical or anything like that. It's just really a natural decline and one of those things that happens in the Gulf Coast and south Louisiana specifically.

And is anything on the radar for either one of those areas for you in the near future? Do we need gas prices materially higher for you to get more active down there?

I don't think you'll see us drilling anything down there in the near future.

Okay. Well, all my other questions were answered. Thanks.

Thank you.

Our next question is from the line of [Mark Neal] with Sidoti & Company, please state your question.

Good afternoon. In looking at CapEx is there anything in the plan to continue to drill in Haynesville in the back half of the year?

Probably not and I don't mean to be evasive, but right now no. It's not just a matter -- well, it's a matter of -- no. We're not -- I'll speak for myself. With we're not real, real confident that -- about gas prices looking forward with the kinds of declines that we're talking about, we don't feel we need to do that and so for the rest of this year, I would be very surprised if we would drill in the Haynesville.

And then I guess looking at your last two wells and I don't know if you can necessarily quantify it, but in terms of the changes in completion versus you having hit a sweet spot in your acreage, what do you think the mix is there?

Well, I think -- I think if you look at our overall acreage position, we're down in sort of the southern part of our -- geographically the southern part of our acreage and, I think that -- I think that sweet spot is a large sweet spot, it's not a one or two or five well kind of sweet spot, it's something that, based on the other wells we have drilled down in there and based on what those decline curves look like even though we only did A stage frack jobs on them, we think that those other seven wells we drilled down in the geographical area would be very similar if we had done a larger frack jobs on all of them. So we think the sweet spot is fairly broad as far as our acres position goes, but in general terms, regional terms, as you go to the north, gas contents get less, clay content gets a little bit more, those kind of things. But in general, we think that 50 to 60% of our acreage would be in this 6 Bcf category.

Got you. And I guess looking at the increase in leasehold acquisition guidance, do you have that targeted in any particular area and can you kind of narrow that down a bit?

Well, if we were to do that, we would kind of destroy some of our competitive position. You can figure that you've emphasized three different areas from the Selma Chalk to east Texas to the Granite Wash and maybe if that's 1A, B and C, then 2A is the Marcellus. It will be among those areas, but we really want to be a little bit circumspect about the mix and the timing.

Understood. Thank you.

You're welcome.

Thank you. There are no further questions at this time. I would like to turn the floor back over to management for closing comments.

Well, again, I see on my screen that there's 50 or 60 of you on the line and we appreciate the interest. We surely appreciate the questions because you guys by asking those questions, allow us to cover things that we don't cover in what we're saying and that's not to evade those things, it's just that they don't get covered. So thank you, all, and we'll talk to you again next quarter.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.