Ranger Oil Corp (ROCC) 2005 Q1 法說會逐字稿

Greetings, ladies and gentlemen, and welcome to the Penn Virginia Corporation first quarter results 2005 conference call. At this time, all participants are in a listen-only mode to prevent background noise. 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, Chief Executive Officer of Penn Virginia Corporation. Thank you, sir. You may begin.

Thank you, Ken, and good afternoon to all of you.

I'm joined in various places by -- here in Radnor by Frank Pici, our CFO; and Baird Whitehead, who runs our oil and gas operations; in Kingsport, Tennessee is Keith Horton who runs our coal and coal infrastructure operations; and in Houston is Ron Page, who runs our newly acquired midstream operation, which is obviously part of our MLP, Penn Virginia Resource Partners.

The -- I will try to follow the -- the format and the -- and the -- of the press release with a couple of exceptions. I won't read it to you. I'll let you read along as I go along, and I presume you've had a chance to read it. But following that format we begin the -- the R release -- excuse me, PVA release with a table that summarizes the quarter. I guess I'd remind you that because we consolidate and we're consolidating now really three different segments, our oil and gas segment, our coal segment, and our midstream segment, makes perhaps quarter-to-quarter type comparisons difficult, particularly since we didn't have the midstream until March of this year, so I just would remind you of that and I'll try to separate things out a little bit for you as we go along. For example, with revenues, 88 million of revenues, about 42 million of that came from the oil and gas segment. About 20 million from coal, and about 26 million from the midstream, and that's after only a month. So you see that the midstream will have quite a dramatic effect on the revenues of the Company. And as I say, to compare those things back to 55 million is kind of -- doesn't accomplish very much.

If you -- if you were to compare the -- the oil and gas revenues in the first quarter of 2005, which I just said was about 42 million to the first quarter in -- or excuse me the fourth quarter, which is perhaps more relevant in 2004, you'd see that those revenues were about 45.6 million, so they were a little bit higher; and that's really due to two things you should keep in mind. One, we sold some assets in west Texas, basically oil, effective the first of the year this year, which would have accounted for close to 2 million of revenue. And the other thing to keep in mind is that the fourth quarter, our average price on gas was 7.11 per M and now it's -- for this past quarter it was about 6.47. So if you -- if you put that other production back in, production would have been higher in the first quarter than -- than in the fourth, but prices would have been lower and that accounts for some of the change in revenue.

Dropping down to the operating income line, again, total 27.7, 15.7 of that delivered by oil and gas, 12.3 by coal. About 2 million by the midstream. That would compare favorably to the fourth quarter for both gas and coal and it compares somewhat favorably to the first quarter for both gas and coal. There is no comparison obviously for [technical difficulties] and continuing this line of reasoning for one more second, which cash flow from operations sort of the same thing. 26 million of that came from oil and gas, 16 came from coal, about 3.2 from the midstream and those would compare favorably with the fourth and -- quarter of last year and the first. The net income line however, doesn't compare, and I can't really break those out as easily because of tax effects and what have you, but as we point out in the first paragraph and then later on underneath the midstream segment, and we took some pains to try to point out in the PVR release as well, we did get -- see -- we do see the effect of a -- of a noncash charge that we took at the PVR level, and then when we consolidate it out and account for the minority interest and the rest of it, this unrealized loss resulted in a -- in a negative impact on our -- on our net income of $3.6 million.

In our -- if we get into the accounting issues and all of that, I'll defer to Frank, particularly, who knows a lot more about this than I do, but I'll just try to tell you what we did and why we did it. The -- the acquisition that we made at the PVR level of these Cantera assets, this midstream oil and gas which we closed on March the 3rd of this year, was for us, the largest acquisition Penn Virginia's ever done, over $190 million and something that we wanted to make sure that we could hit the ground running. So once we were extremely sure that -- that we were going to close this acquisition, we actually entered into a series of hedge contracts to -- and to try to protect the economics and particularly protect the cash flows vis-a-vis the model -- the acquisition model we used to acquire these assets. And by the way, that did work. Those hedges are all now completed and -- on a sort of a net, net, net basis we actually will realized more cash over the first 21 months at least for the part of the commodities that we hedged, than we would have in our economics. And cash clearly in an MLP is the most important element of it, so we thought it was prudent to do that and we still do think it was prudent. However, because we took possession of the commodity before we owned it, we have to account for it differently than we do now that we do own it, and what's -- we use now is called hedge accounting. It's very standard in the industry. Prior to that, we would have to mark-to-market on the day we converted over to hedge accounting. We'd have to mark-to-market the difference between the values of our hedges -- the commodities we'd hedge and the actual market value of them over the life of that hedge. Since the prices kept going up, the value of the commodity kept going up, the difference the day we closed it all out was $13.9 million and that drops back through. But it's noncash and again, we -- we feel as though it did protect our -- our Cantera acquisition through the end of 2006. At least that part that we -- we did hedge.

So with all of that said -- and I hope I didn't add to the confusion, and if there's any questions, we'll let -- we'll let you ask them. Let me get back to the press release and the order it goes and the first thing that we talk about is oil and gas. I would remind you that on the 28th of April, just a few days ago, we put out a much more detailed description of what's going on from an operating standpoint within our oil and gas business and this more summarizes it. And I don't want -- as I said, I don't want to read it to you. As I -- also a minute ago, sort of the bottom line of it all is that the operating income delivered by our oil and gas business in the first quarter was $15.7 million, which is up over last year fourth quarter. Or first production was 6.4 Bcf, and the average price was $6.47 per annum. I'm talking about gas now. We don't have much oil left. That price is a little lower than it was in the first quarter of last year, and we did sell that production out of west Texas.

One of -- a few things are working well and are probably worth mentioning on the oil and gas side, which I think, frankly, is going well for the quarter, but we did drill this quarter 8 gross, 5 net -- 5.1 net of these horizontal CBM wells that we drill in Appalachia. These things have sort of a high cost to them that affects our DD&A rate, but they have a rate of return -- an after tax rate of return that you can do it at various times, but it's 60 to 80 to 100%. It kind of depends when you take the snapshot, but they're a very, very high return program for us. It's a very return program for us, and one we're pushing just as hard as we can.

In Mississippi so far this year we've drilled 14 wells into the Selma Chalk with 14 successes. We have a virtually 100% working interest there, and importantly to us, especially in this last year, '04 and going into '05 is what's going on in the North Carthage Field. Basically the Cotton Valley, but there's a Travis Peak and Pettit formation there that we pick up in many of the wells we drilled. The 28th press release says, I believe, that we drilled 4 gross, 2.8 net wells so far this year. I think over the course of the last five quarters we've drilled 22 of those wells with 100% success so far. We've been -- we've been running one rig. We said in our earlier release that we would want to run additional rigs. In our board meeting of earlier this week, board approved us entering into a contract and accelerating our drilling such as -- and that's what's -- a lot of what's reflected in the change in our guidance. We expect to be running three rigs, Baird, by late in the second quarter?

Late June.

Late June. Sometimes things get delayed but certainly by late in the -- this quarter or early next, we would expect to be running three rigs there and pushing that, again, just as hard as we can. We've also had some fair success in exploration. Baird, I asked you to think about how we could describe that.

You've probably seen, or have seen a press release that was put out by both Brigham and Penn Virginia, our operational press release last week. This was a Lower Frio discovery that the Company made in Matagorda County, Texas. It was a internally generated prospect by Penn Virginia. We retain a 50% interest and Brigham retained a 50% interest as a drilling operator after which Penn Virginia becomes the production operator. This well was completed in a Lower Frio sand called the Anomalina. It was completed through about 40 feet of perforations. After 22 hours, the well is making about 3.8 million a day and 480 barrels of liquids a day, flowing with about 6300 pounds of flowing tube in pressure.

At this time, we think it could be a material discovery for this Company. In adjacent fields in which we own about a 40% interest in which is to the northeast called Rhusly [ph], we'll make 60 Bcf out of ten wells. At this point in time, there -- there are some unknowns as far as the it size of the reservoir because there is enough room [ph] fault block which is adjacent to the discovery fault block that until we drill an offset well in it, we won't know how large this thing is. Plus there's 90 foot of pave behind pipe on top of this 40-foot interval that we perforated. But at this time, it could be anywhere from 28 Bcf to 92 Bcf in size depending on thickness and area. At this moment the plan is, of course, is to get this thing into the pipeline. Those arrangements are being made as we speak. There's also an evaluation going on on whether the frac this well, and in all probability because the wells in Rhusly will fracked in this Anomalina section, we will frac this well. And it's also the plans, as outlined in the Brigham press release that an offset well will be drilled probably starting sometime this summertime.

Going forward in the Gulf Coast, as you know, we've been internally generating prospects and in south Louisiana. We have a number of those in the hopper at this point in time, and between Iberia Parish and St. Martin Parish we have some high impact prospects to get drilled before the end of the year. These prospects will be anywhere from the 15 to 90 Bcf range, in which we'll retain anywhere from a 30% to a 40% working interest. In addition, Bayou Sale, which is a 3D area that we shot a few years ago and have interpreted with about 14 prospects in hand right now. We have some partners in 4 of those 14 prospects. The plan is to get two of those prospects drilled before the end of the year. One of those prospects in which we'll have a -- carry 25% to TD is a high impact type prospect that has the potential of around 100 Bcf. The second prospect in which we'll retain anywhere from, again, on a carried interest basis retain anywhere from a 40 to 50% interest will be anywhere from 10 to 40 Bcf.

So we expect to get some of our own ideas drilled this year, and we have some good opportunities and good prospects on our plate.

Thanks, Baird.

And I wanted Baird to be able to talk about it, A, because he talks about it better than I do, but this -- as he said, you can't count it until -- the chicken until it's hatched, but there certainly seems to be some eggs in the basket anyway.

Let me then move on to coal operations quickly and then on to the midstream. Basically the press release, I hope, is fairly clear. Coal royalty revenues for the first quarter of 2005 were -- were $18.1 million. That was up over the first quarter of 2004 by some 7%. It was up also over the fourth quarter of 2004 by about $900,000. Those royalty revenues were up despite the fact that production was down. Production in the quarter was about 6.7 million tons. It was about 8 million in the first quarter. Last year it was about 7.3 million in the fourth quarter of last year. The -- the culprits here, apparently two basically. One is in New Mexico, there is a mine that's operated by Peabody called Lee Ranch which has had some difficulty with one of its customers, Tucson Electric who's had trouble with their rotary dump, which is how they receive coal. They can't receive coal in near the quantity that they normally would without that facility working. It's been down for a bit. I'll let Keith Horton update you a little bit on it. I believe it will be at least through the second quarter before that can come back online and that certainly has hurt us a little bit.

The -- the other issue is in West Virginia, which we had been trying to inform you all about going through last year. We knew we had a -- a longwall operation on that property that was, as all long walls do, making a lot of coal and we knew it was going to move off. It has. It's operated about one month out of this quarter on our property as opposed to three months last year on virtually all year long. I believe it was on all 12 months, and that's simply not a problem as much as it is that the operator is deploying that longwall where he thinks it can be most efficiently used. Sometimes that will be on our property, sometimes it will be off. Late this year we would expect it to come back. Nonetheless, production was down for those two -- for those two reasons.

On the other hand, realization per ton was up. We see -- we point out it was $2.69 per ton on the average in the first quarter of this year versus about 2.12 in the first quarter of last year and about 2.36 in the fourth quarter last year, and what's going on here is prices have gone up and most of our royalties are tied to prices so we get a higher price -- we get a higher realization as those prices go up. There's -- more met coal come off the property and that's a very high priced product right now. So again, that impacts the rate and the fact that the Lee Ranch in particular has come off -- the tonnage has come off a little bit, and that is one of the lower dollars per ton type royalty rates we have because it's not tied to prices, so if the lower -- a lower value in that sense, coal comes off, it changes the -- obviously across the board then, the dollars per ton rate that you're getting. So all of those things combined and net, net, net we're getting about $2.69 a ton, up considerably from last year, so even with production down, royalty rates are up. And operating income is up with about 12.3 million for the quarter versus 11.2 for the fourth quarter of last year. 9.2 for the first quarter. A lot of that, again, is rate driven.

A note on production, I think the -- I'll let Keith speak to this, but I think the production that we've lost this year, we don't expect to get it all back. You'll notice in our guidance we've adjusted it down about a million tons for the year, and going into the year it was about a million below last year. We're endeavoring to do something about that. Obviously we've made two acquisitions this year on the coal side. They haven't been huge, but they've added about 50 million tons of high quality Appalachia coal, if you contrast that to what we produced, for example, last year which was about 30 million tons or 31, we're replacing -- we've replaced already this year, a hundred and -- more than 150% of last year's production. Clearly that's not going to all be produced at once. In fact, it's going to come on over a period of years, but both of these acquisitions were accretive. One of them included some royalties from oil and gas. One of them included something called wheelage which is basically a charge that you charge to people to transport their coal over your property.

So we're finding other ways to drive revenue in the coal business as well as our infrastructure business that we're in with Massey and that we're in with -- on our own property, so all of these things combine and I don't expect coal to have -- I expect coal to have a perfectly fine year. Over and above that, we've -- we've got another four -- depends on how you want to count. But four, five, six different bids outstanding and on various coal reserves, and some of these involve operations that are up and running in a significant way. I don't expect a big impact this year, but -- but all of these things are moving forward at one rate of speed or another and some of them may welcome to fruition.

On the midstream side, there's not as much to report there because we can't do comparisons. We've owned the business since March 3rd of this year. We're not going to go back and compare to the previous owner because the comparison wouldn't mean anything. So what we've tried to do for you there was give you a -- a kind of a factual here's the revenues, here's the costs, et cetera, and try to give you some comfort or I will that -- that we have inherited here or acquired or whatever word you'd like to use, a very solid group, we think, of operating people. They've stayed with us with one exception, and we've replaced that gentleman virtually immediately with someone who was consulting. I think Ron Page -- his team have made great efforts to make our new employees feel a part of this organization, and that's working. We're building our own accounting systems and IT systems, and as far as I know, and I think I do, that's on schedule. And going quite well. So aside from this issue that I touched on with these -- these hedges, we couldn't be happier with PVR. We're trying to grow it -- PVR Midstream. We're trying to grow it. We're going to walk before we can run there, but we've got some projects in mind to improve the efficiency of what we already bought, and we've got a couple of things that we're talking about which would be logical extensions to what we bought.

So before I go on, Keith, anything that you want to bring up on coal that I missed?

No, I think you've covered it. The -- both the steam and the met market is very strong right now. Looks to be strong over the next couple of years. I think for most of our lessees that are capable of producing, it has ratcheted up certainly our average -- or the average selling price and thus the royalty to us, so all the coal coming from Buchanan is going into the market and a large percentage of the coal we have produced from our Spruce Laurel property is also in the met market. So the market looks very strong and -- and should continue that way.

Thank you, Keith. Ron Page? Anything you want to add?

Not really, Jim. I think you covered it well. I -- I would just comment that our volumes are a little bit above our acquisition case that we ran, and drilling is strong on the -- on the systems that we bought, so we're certainly pleased with the way things are going.

Well, great. Thank you.

Let me just add one last thing on the partnership since we are, and therefore the people I'm talking to are, or are reporting to or representing the largest unit holder of PVR. PVR will raise its distributions effective to shareholders -- from unit holders of record on May 3rd of this year to $0.62 a quarter. We came into the quarter -- into the year, pardon me, at $0.54, so that's a 15% increase over the course of the year already; and I think that -- I can assure you, that's not done without a vote by boards of directors so I think it reflects some confidence on their part that in fact PVR is on track to grow.

With that, there is a note in here on capital resources. Again, it just gives you some detail and color on -- on the Company, both the partnership and the corporation's credit situation. I would say that with regards to PVR, the acquisition costs $191 million. We went out and funded most of that by doing a secondary within a few days of closing. The secondary went off pretty well given that we were in a fairly tough market for MLPs and coal MLPs in particular. In fact it went more than pretty well, I think it went -- I think it went quite well.

With regards to guidance, I guess if I look down the page versus what we put out in February, there's not a lot of change, but there certainly is some. Gas production pretty much -- oil and gas production pretty much, I think, what we said. Where the -- where the changes come is in exploration where there's been a -- some -- some -- there's some less money is expected to be expensed in exploration, and that's just the normal shifts you have in a program and we can dig down to that if you're interested. Coal bed methane is up. With regards to the coal, I told you about Lee Ranch, which lowered our guidance -- original guidance was about 28.6 to 31.9 million tons. It's now, as you can read, 27.8 to 30.7. The price deck -- we didn't -- the way we did it the first time we did guidance we actually gave you a royalty revenue number. Now we're giving you a range of prices, but if you take the midpoints of the -- this guidance on production an this guidance on royalty rates, 29 million tons at $2.70 I believe you'll get $78 million of royalty revenue. The guidance we put out at the end of the first quarter was about 72, so this higher realization is having an effect.

Obviously the midstream segment of the guidance is new. We didn't put it in on the first quarter because we didn't own the assets. The other thing that's changed somewhat is the CapEx. You'll see development drilling has gone from a range of 83 to 88 to a range of 107 to 112. Basically that's the Cotton Valley that we talked about, the new wells we're going to drill, accelerating that program by bringing those rigs, number one -- one of them on, which we didn't even plan on, and the other one on quicker. There's some workovers in the Cotton Valley that actually already complete. We had planned to stretch them out, but in this price environment we got them done early. There are 20 extra Selma Chalk wells in the program versus the first quarter -- the first shot we took at guidance, and again, that's just taking advantage of higher prices. And we think there's going to -- we think and hope there'll be another 3.5 net to us horizontal CBM well drilled because of a lease we're hoping to get our paws on here any day now. That may or may not happen.

On the other hand, the exploratory drilling has been backed off a little bit. We've certainly had some successes. It's not a lack of confidence, it's just these opportunities move around a little bit, especially when you're trying to get partners, and we backed off from having a -- a exploration drilling CapEx budget of 24 to 25 million to one of 17 to 18. I think, accepting that now you'll see these coal acquisitions, which we didn't have in our original guidance, we don't put acquisitions in guidance, at 24 million. And of course, the midstream at 196 to 200 million is new, and also then there's the midstream will carry with it certain maintenance capital, which we're estimating to be around $5 million. So I think that kind of sums up the -- the changes in the guidance. If I add up the -- the development drilling and the exploration drilling that's in this guidance, it's 119 to 130 million. If I add it up in the old guidance, it's about 15 million less than that. So these new wells basically are -- are causing us to -- to accelerate our -- our development drilling again to take advantage of the price environment that we're in.

So with that, Ken, I'll be happy to answer any questions.

[OPERATOR INSTRUCTIONS]. Ray Deacon, Harris Nesbitt.

Hey, Baird. I had a question about the exploration expense in the second quarter. The overall dollars out the door is going to go down for the year, but why the big -- big jump in exploration expense in the second quarter? Is it just a function of timing of the drilling?

Well, to some extent it was. We also had some wells we expensed the first quarter, Ray, as dry holes. One of which was one of these horizontal CBM wells we drilled down in Virginia last year that was under evaluation for some period of time, and this quarter we recognized the write off. The other -- the other big component is -- was seismic. Under our deal with Western GECO, we bought those -- 5,000 square miles of seismic over three years, and we ended up paying the last year of -- of that installment in the first quarter, so that's why things sort of look out of whack in the third quarter as compared to the rest of the year.

Okay, Actually I meant second quarter. It looks like the guidance is exploration expenses is going to go up to 18 million roughly? That's --

That's -- what that is -- what that is is a Richard King well. That was the well -- I think we have reported in the past, we drilled in Oasis [ph] County. It was a high risk, high upside type well that was drilled to the Yegua. The Yegua was dry. There is a zone behind pipe in the Lower Frio that could be productive as an oil well. So what we have done, we have forecasted we will complete that well in the second quarter so there is a risk -- unproved property component, which is a noncash component, the reason that it looks so high in the second quarter.

Okay. Got you.

Ray, this is Frank Pici. It was originally built into our guidance for the first quarter but we haven't evaluated the well yet, so now we expect to evaluate it in the second quarter and that's why the -- this big noncash charge would be -- it's forecasted to be in the second quarter because it's not a high probability of success type well.

Okay. And it doesn't affect your cash flow so --

Right.

And just one more quick one. On east Texas and that first package with GMXR that I guess you're part way through now, what -- what's your best guess as far as ultimate reserves, number of locations there at this point?

Right. [inaudible] is coming as we expected. We have found some sweet spots as we continue to drill wells in which you subsequently go in and drill some downspace wells on a 40-acre spacing, but if you look at the stuff you have with GMX and the stuff outside of GMX we continue to expand our [inaudible] position. At this point in time, we're -- we have shown at some -- at a prior conference, we're estimating on a risk basis, we've got about 300 Bs and about 500 locations in the Cotton Valley. It is a -- it is a focused plate type at this point in time.

Right. Would you add another rig there or is it just -- you don't want to go too fast or --

Well, Jim, basically we have three rigs we'll be working here in late June, two of which will be within the GMX and my third one will be on the 100% acreage that we've acquired. We'll get some drills on 100% acreage as the year goes on. Depending on the results of those well, then we'll subsequently evaluate bringing a fourth rig in to have two rigs working on that 100% acreage. I doubt if that will happen until early 2006, but that's the plan right now.

Okay. Great. Thanks a lot.

Thank you.

Joe Allman, RBC Capital Markets.

Hi, everybody.

Hi, Joe.

A question for Baird. Baird, besides the horizontal CBM program you have with CDX, can you remind us what can look forward to in terms of other CBM or shale type lays for the rest of the year?

Yes, Joe. We drilled a horizontal CBM well in northern West Virginia last year, which -- and we reported the results didn't meet our economic expectations. We drilled an offset to it the first quarter. It's acting a lot different and better than the first well. It's making more water which is always a good sign on a -- on a CBM play. We've got some lock [ph] pressure issues that have to get resolved before we can say it's a slam dunk success, but the plan is to drill two additional offsets to that as the year goes on.

In addition, too, we're active in acquiring leases up in northern West Virginia and we have two exploratory horizontal CBM wells planned on new leases for the remainder of the year. As far as our devoting a shale [ph], we do plan on getting a subsequent well drilled, the location of which has not been defined at this time. We may drill it as an offset to the well we drilled last year. We're going to approach it differently from an operational standpoint than what we did last year. What we tried to drill multiple laterals. We will probably drill single laterals and -- and maybe two different directions. We will try to case those things off and more approach this like a Barnett Shale type thing, where as we do two or three stage frac jobs along those laterals, so that's the plan in Appalachia as far as CBM and shale for the rest of the year.

All rightie. Thank you.

Thank you, Joe.

Dan Morrison, Aperion Group.

That covered me on the outside traditional stuff in Appalachia, but back to the coal side, what percentage of current production is being sold into met market?

Keith?

That production is going to be about -- between 10 and 15% right now.

Is that an increase from what you've done in the past?

Yes, it is. It's increased from the -- from the historical, because of the robust met market we're currently experiencing, and of course, met coals have different quality characteristics than the steam coals, and many of those coals that are capable or have the correct quality are moving into the met market now where they hadn't in the past.

Okay. Is that a trend you see continuing -- an increasing percentage going into that market or --

No, I don't think the trend continues. I think it -- it's largely going to be based on the exchange rates of the dollar.

Right.

If -- if the dollar stays weak, it continues. As the dollar strengthens, it -- we're less competitive on the world markets and that's really what strengthens the met side.

Okay. Great. Thanks.

Thank you.

Sven Del Pozzo, John S. Herold.

Hello. Yes -- just -- I'd like to know about operating costs in the -- for the oil and gas division. Just seems like positive developments there, operating costs trending downward and also according to your guidance and so on such a tough cost environment, would you tell me how those costs are being kept under control?

To some extent, Sven, as a result of that stuff we sold in west Texas and in south Texas, it was -- it was like 95% oil. The operating costs were 2.50 to $3 in equivalent Mcf. It's saving us a lot of money going forward, and it had an effect in the first quarter.

Okay. And how about -- is there any update on being able to get more rigs for horizontal CBM generally?

Well, we -- we are doing all we can to -- to influence our partner, particularly in the AMI to -- to add a rig. We're working on trying to acquire some additional leased acreage, which if we get it, we're hopeful that they will. We don't have much leverage, though, to cause them to do that, so right now we're running three horizontal rigs and a vertical rig which is better than we were doing last year. We're -- we're again, we're trying to urge them to run a fourth horizontal rig, but I don't want to build up any false expectations. Maybe they will and maybe they won't. It really is up to them. All I can tell you is we're working it as hard as we can.

Okay. And any update on drilling with Dominion? I mean, is that what you were referring to when you said you were going to drill an -- when Baird said he was going to drill an offset to a well that was dry --

Yes, that's who he was talking about, and as far as I know, and he can answer for himself, of course, Dominion is quite enthused about this project, and -- so we expect that we cracked the code a little bit and simplified the wells a little bit, and we expect it to be a success or we wouldn't be telling you we're going to drill some more.

Okay. And when might we have some initial indication on that? Like, when will you start drilling those?

Well, I'd say it's going to -- probably in the third quarter. We'll probably get one drilled in the third and one drilled in the fourth. We have worked real hard on getting our costs down on those wells, and the guys in our team support office have done a good job in doing that. We originally started -- that first one, I think, cost us about 1.5 million, 1.6, something like that. The first offset we drilled was done in the 1.1 million, 1.2 million range, and our goal was to get this down in about the $900,000 range.

Okay. All right. Thanks a lot.

Thank you.

[OPERATOR INSTRUCTIONS]. Todd Wakefield, The Boston Company.

Oh, hi. I have another question on the coal pricing. I'm just trying to figure out how much your operator's coal is being priced at or near current prices, and how -- how much is still at older legacy contracts? I don't know if you would break out for us what the average realized price for central Ap and northern Ap and for the met markets are for your operators.

Well, Keith, I'll let you gather your thoughts for a minute. You can undoubtedly do better than I, but I remind you, Todd, that a good bit of our production, mainly the -- the production that is associated with Peabody's Lee Ranch mine, which at some -- even though it's down is going to be over 5 million tons this year, if memory serves, and their Federal Number 2 mine, which is a longwall in -- in northern Appalachia. In both cases -- and that's about, what, that's another 5 million a year, is it? So that's -- I've just accounted for roughly a third of our production is not tied to prices. So that makes it a little harder for you to -- to do the arithmetic there because those leases escalate -- and my memory is not real good, but about 8% a year. But they started from a fairly low base. For example, Lee Ranch this year is about $1.74. Next year it will be about 8% higher than that. And I believe that Federal Number 2 is in the $1.40-ish range. So with those thoughts in mind, it's a little harder to break it all out, but Keith, I -- if you had a chance, can you give some guidance as to how many contracts are yet to roll off?

We have in --

Keith, you've got to turn your volume up, at least for us.

Okay. We have about 65 to 70% of our coal out of Virginia is moving at current prices. We still have roughly a third to roll off. And that's roughly 9 million -- or 9 -- 9.5 million tons a year. In West Virginia, a fair amount of our coal out of our Coal River property is -- is on a year-to-year basis, so it's -- it's at current market prices. I'm going to say that probably 85% of our West Virginia production is -- is currently sit -- sitting at -- at market prices. So we're -- we're getting pretty close to having all our production in. Everything coming off of Buchanan, which is a small amount of coal, is 100% at current prices. Again, Jim mentioned the northern Ap and the New Mexico properties are not price sensitive, so I'd say overall, I haven't got that number, but I'm going to say we're probably at least at 70% at current prices.

Great. Thank you very much.

Thank you.

Gentlemen, there are no further questions at this time.

Okay. Well, I'll say two words here and if someone wants to jump in at the last minute they surely can.

I want to thank everyone who's on this call for being -- for taking the time and having the interest to listen to us. I think if I look across the Company, I'm sure there's going to be problems and I'm sure there's going to be issues, but basically, we think we're off to a pretty good start this year. The -- the exploration program on oil and gas side, of course, is exciting. The Cotton Valley is exciting. The horizontal CBM is not going as fast as we want to spend, but it's going and going well. We're very pleased with the midstream oil and gas and are looking for great things from Ron and his team, and then Keith has made some interesting coal acquisitions this year. We're hoping this -- this Massey project gets some legs under it -- some additional legs under it. As I say, we've got some ideas that we're pushing pretty hard to grow the coal business. So across the board, we feel as though we're off to a pretty good start, and we look forward to talking to you next quarter, so thank you very much.

Ladies and gentlemen, this concludes today's teleconference. Thank you for your participation. You may disconnect your lines at this time.