Ranger Oil Corp (ROCC) 2005 Q2 法說會逐字稿

Greetings ladies and gentlemen and welcome to the Penn Virginia Corporation second quarter results 2005 conference call.

At this time all parties 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, Chief Executive Officer of Penn Virginia Corporation.

Thank you, Megan.

Good afternoon to all of you who are listening in and to those of you who are on the Internet as well. I am joined today by -- here in Radnor by Frank Pici, the CFO of the Company; Baird Whitehead, who runs the oil and gas segment of the Company; Steve Hartman (ph), who's our Treasurer. In Kingsport we have Keith Horton, who runs the coal segment of the Company and Forrest McNair, who's our Controller. Houston -- or Dallas excuse me, we have Ron Page, who runs the midstream segment of the Company.

I won't read the entire press release to you. I will try to pick out some highlights and you can ask me questions if you want. We would welcome that. That's why we have all of this fire power on the phone.

At any rate we reported yesterday our second quarter -- quarterly net cash provided by operating activities was $53.8 million, a 58% increase over the corresponding quarter in 2004. Another cash flow measure which happens to be a non-GAAP measure, was operating cash flow, which was $53.5 million, a 46% increase over the second quarter of 2004. Net income in 2005 in the quarter was lower than 2004 -- 7.6 million versus 12.1. Primary reason for that as we point out was a large increase year-over-year in exploration expense, the vast preponderance of that was associated with a noncash write off of an unproved property which we drilled an unsuccessful well on.

We highlighted that a little more completely in our operations release of July the 28 of this year. But that was the primary reason, otherwise net income would have been up for the year as well. Looking year-to-date, the first six months again the cash flow numbers were very strong relative to last year. This first half 85 million of operating -- cash generated by operating activities a 45% increase, again non-GAAP operating cash flow almost $97 million up 37% over last year net income. A little bit lower and again the primary purpose there -- or primary driver there was this one well.

If I look at the oil and gas operations for a moment and I again remind you that we put out a release on July 28 that goes into a lot more detail than is in the release of yesterday. But we reported a record for the Company in terms of oil and gas production for the quarter of 6.9 billion cubic feet equivalent, which is a significant increase over last year and it is 8% higher than the first quarter this year. That increase was driven by really three separate components. One, an increase in the amount of production and drilling activity frankly from our horizontal coalbed methane play in Appalachia.

The second was the Cotton Valley, which is in east Texas, where a second ring -- rig came online in June, and helped there. Parenthetically, I would add that a third rig is due to be deployed there some time this month, sometime in August of 2005.

The third element of the increase in production came from Mississippi, where the Selma Chalk development play has been subjected to some increased drilling. We're running three rigs there right now, we intend to run those rigs pretty much 12 months a year from now on.

Those production increases were somewhat offset by the fact that a year ago we had some properties in west Texas and in south Texas which we have sold since then, so the numbers would look even a little bit better if we had hung onto those properties. A little more color on that, not a lot. I don't want to read the whole operations report here and I'm trying to cull through it as well.

But in this quarter we drilled five successful wells in the Gulf coast, 3.4 net forward development, one was for exploration, and the down part of the quarter was the well we drilled in the first quarter, the Richard King well, which turned out to be dry and is -- has resulted in the increased exploration expense. In the east we drilled -- in this quarter we drilled 39 gross wells, 35 net of which 37 were successful. Seven of those wells were horizontal CBM wells, they all successful. 23 of those wells were in the Selma Chalk in Mississippi.

I think of note, to us at least, and to you as people interested in the Company, we announced during the quarter that we had modified our agreement with CDX. CDX is our partner in drilling those horizontal CBM wells. Up until this modification of the agreement they were only obligated to run one rig in the AMI; they're now obligated to run three. They're running three right now and they have been running three this year.

The difference is that this means they're committed to running those rigs and the modification, under certain conditions, requires and allows for a fourth and even a fifth rig to be deployed in that AMI. We're probably not ready to that right now just due to infrastructure issues but we now have the right to do it.

We have also announced the acquisition of 60,000 acres of prospective coalbed methane leasehold. Got those rights from a private owner. CDX -- that's within the AMI with CDX and they have the right to a 50% interest in that acreage and we expect them to exercise that right.

And then finally we completed a farm-out with EOG on 34,000 prospective acres of CBM. That also is in the AMI and we're looking forward to being able hopefully, to accelerate our drilling there.

Turning to the numbers part of oil and gas and then moving on. Just again back in the August 3 press release here, revenues increased in the quarter by about 35% to $48 million and again about half of that increase was driven by production. The other half was driven by the fact we have higher realizations. Our expenses are up considerably and a lot of that is exploration expense. A lot of it is just increased activity. The press release highlights some of those issues -- DD&A is up some. Again, as is explained in the press release.

With regards then to the MLP, Penn Virginia resource partners, master limited partnership in which Penn Virginia owns 100%. of the GP. That MLP as you undoubtedly know, now has two active segments, one coal and one midstream. MLP had a very good second quarter as this is, I think I said the first quarter we've included in our results, a full quarter of the midstream activity.

PVR reported yesterday distributable cash flow of $22.4 million for the quarter, a 74% increase over 2004. Operating income was up on a percentage basis even more than that, so it just had a very, very good quarter. It's had very good first half as well. As a result of that success, the board of directors of Penn Virginia Resources GP increased the distributions. The distributions now to the limited partner unit holders are $0.65 a quarter, effective for the second quarter of 2005 which means that the payout is sometime this month, the middle of the month. That brings us to 260 a unit per year and represents a 20% increase this year in distributions to limited partners. And just to remind you Penn Virginia, in addition to owning the GP owns 7.8 million limited partner units, so we're doing quite well in our MLP and I will spend a minute on each segment of it starting with coal.

In the second quarter, the operating income from the coal segment was a record $16.3 million, 70% higher than last year. Coal royalty revenues, which is the bulk of the revenue that the coal segment receives, were $20 million, a 15% increase over the second quarter of 2004. And that increase was driven by higher royalty rates, higher realizations. Production was actually down a little bit quarter-to-quarter.

Excuse me, quarter -- second quarter '05 to second quarter '04, and that was a direct result and of a long wall, which is a highly efficient underground mining device, moving off of our property for a period of time and mining coal that's adjacent to our property which we didn't happen to own. I understand it is back on our property now, so we'll be enjoying the fact that it is on there now, but it was that moving off that caused the year-over-year decrease. As you know, the coal segment is also in the infrastructure business and other revenues from that are up this year as well, reflecting the -- some success with our joint operation with Massey and some success -- some Company or partnership owned coal infrastructure activities.

And one last thing, then, on coal, just strategically and including the month of July in what I am saying where we actually completed two acquisitions, the coal team has made four acquisitions this year. None of them huge, but all of them significant in a couple of ways. Added in total 160 million tons of reserves. To put that into some context, we reported at the end of last year, I believe, about 558 million tons of reserves. So, it is a significant increase. Typically we'll mine 30 million tons in the year -- or we won't mine it but people mine it from us. So it gives you some sense this is a significant set of additions.

The most significant of those additions was 95 million tons in the Illinois basin which puts us into that basin for the first time and is something that we're quite pleased to accomplish, have a footprint there and we hope to be able to build from it. All of these acquisitions are organic, in the sense that we expect production to grow from them over time.

With regards to the midstream, natural gas midstream segment, it contributed operating income in the quarter of 4.1 million -- $4.1 million on revenues of $87 million, inlet volumes are listed in the report for the quarter. They amounted to 11.5 billion cubic feet, 126 million cubic feet a day.

I think what's important here is that, with regards to this midstream is, that it is exactly where we wanted to be or better. And in fact, it is running a little bit better in terms of margins. It is running a little bit better in terms of volumes. We have virtually completed the cutovers, we're calling it, of the accounting systems from the private buyer that we bought it from Cantera, to our systems, the IT systems are being put in place. So it is going along very, very well.

Made a -- already a improvement in the Beaver Perryton plant, in the sense that we have added a gather -- completed phase one of an increase in the gathering capacity and that's just to take advantage of the drilling that's being done in the area. Looked at an acquisition or two although we haven't made any. But we're quite active there. And once we get the accounting system completely switched over, I am hoping you will see some growth there. So I think that sort of sums up where we are there.

What I meant to do as I went through this, was to ask each of the operating guys whether I'd missed anything and forgot to do that. But, let me back up. Baird, with regards to oil and gas, is there anything you would like to add to what I said?

I would like to bring everyone up to date on a few of the wells we talked about in our operations press release from a few weeks ago. The Wise number one well's received a lot of attention, that's the well we drilled successfully with Brigham in Matagorda County. That well is shut in right now for a pressure buildup test. The information that will be gathered and the parameters will be utilized -- or an interpretation of that buildup test will be utilized to design a frac job. So the intent is to get this thing fracked, as far as the timing of when that stimulation will be done, probably toward the end of this month, beginning of September.

As far as we know, we still plan on getting an offset well drilled to that discovery, at least based on what Brigham has told us, that first offset should [inaudible] sometime in August. We also talked about a discovery we had in our Finnet (ph) field. It was after a sand discovery in Jefferson County, Texas we had 50 feet of extremely clean hackberry sand that had north of 30% porosity. We decided to perforate a ten-foot interval that was questionable, as far as whether it would produce or not, and that ten-foot has tested here in the most -- in the last few days about 1.6 million a day and 72 barrels of condensate a day, blowing about 4,000 pounds and has shut in pressure of about 4,100 pounds. So that is a pleasant surprise for us. To have that well in line by the end of the month and we a 60% working interest in it.

A couple other new prospects we have taken on, that we plan on getting drilled the second half of the year. We're going to participate with another party in a Williston basin on a bockin (ph) shale prospect. This will be a horizon lateral which will be fracked with today's oil prices and the attention the Williston basin is getting especially in the bockin shale. It makes lot of sense for the type of things we try to do as far as the Company.

Secondly, we will be drilling two new Albany prospects tests in the Illinois basin. This is something we've been working on here for about the last year. We've accumulated about 26,000 acres in two different prospects. Again, ultimately we'll probably end up drilling this stuff horizontally if it works. So, you can see we're continuing to focus on the [inaudible].

Thanks, Baird..

Keith, anything with coal that you want to bring up?

Just to point out that the market is -- looks very solid through at least for the next 18 months. Most of our lessees have their coal sold through 2006, about approximately 80% of our lessee production is sold through 2006. And a fairly reasonable portion sold through 2007 at fairly attractive pricing. So all in all it looks like the market is going to be solid for a year, year and a half anyway, and that's as far into the future as I want to use my crystal ball.

The electrical generation is up this year about 1.7%. Our exports of coal are down a little bit year-over-year. Imports are up, central Appalachian production is continuing sort of a downward trend, down about 6% year-to-date over last year. So fundamentals in the market remain very, very strong. And look to continue to be that way for -- through sometime into 2007 anyway. That's really all I have, Jim.

Thank you, Keith. Hey Ron, anything that you want to add?

Well, not much.

I just want to add that we are having good success with hooking up new gas, drilling around our systems is strong, stronger than we would have anticipated in our acquisition economics, and everything seems to be working well. We're looking forward to getting the accounting and the back office work cut over to make life a little easier for everyone, but things are going well in the midstream business.

Excellent.

I asked Frank if -- Frank Pici, our CFO if he would guide us through the guidance.

Thanks, Jim. Good afternoon, everyone.

The guidance table we put in here is, as it has been in prior quarters, is built on the basis of the main drivers. We don't really give you all the answers, but we give you the main things that we think drive future results and it's found on page 11 of the press release that was issued yesterday.

I will just go through it briefly by segment. With respect to the oil and gas segment, you can see that for the third quarter we've got a production estimate there that's fairly flat with what we had in the second quarter. What we really expect when you look at the full year results, however, is an increase in the fourth quarter. We think that will be driven by our continuing development program in our three key areas of the CBM and Appalachia, the Selma Chalk in Mississippi and the Cotton Valley play in east Texas. Along with that, we've got some new production coming online in south Louisiana and south Texas and I think Baird alluded to some of that earlier in the discussion here.

When you look at expenses, the relationship of direct expenses is holding pretty steady. Of course, exploration expense is a function of the drilling program and as Jim mentioned earlier some unproved property costs that hit us in the second quarter that we don't expect going forward. Our depreciation rate, of course, is a function of the cost structure that we work in, and as most of you probably know costs have increased, service costs, steel costs and so forth. And that's starting to manifest itself in our DD&A rate and you can see that the guidance there is on an upward, somewhat upward trend.

In terms of capital expenditures, as I mentioned, we'll be hitting our big three development projects in the third quarter pretty hard and that's why you can see a pretty good uptick in development spending in the third quarter and a pretty steady program on the rest of our CapEx.

With respect to the coal segment, what you can see there is our third quarter does uptick a bit from second quarter. That's a function of the western Kentucky, the Illinois basin property we acquired in July here, that has production currently on it. Along with that we've got some increases in production occurring in our northern Appalachian and New Mexico coal properties that operated by Peabody. All of those will contribute to an increase in production in the third quarter, we believe.

Our average realizations on the coal side, however, we expect to come down a bit. And that's really a mix issue with respect to tonnage coming out of the subleased longwall facility that I think Jim mentioned. And also a mix of other properties as well that have a slightly lower realization rate to them.

On direct expenses, on the coal segment, we do expect an increase there. Once again, that's caused by the subleased property which is -- we've got some third party payments that result from that -- that mining. And we'll have an uptick in direct expenses there. And our depreciation rate on the coal segment will go up a bit as well as a function of more coal being mined on the properties we've more recently acquired, which have higher cost basis than our older properties.

Capital expenditures on the coal side include the Illinois basin acquisition we made early in the third quarter here in July. And a eastern Kentucky acquisition we made as well and that's the main driver. We're also showing in the other CapEx for coal the prep plant and loadout facility that we're beginning to construct on the eastern Kentucky property.

Switching over to the natural gas midstream segment, you can see the inlet volumes are pretty much stable with the second quarter volumes. We don't expect to have a major bump there, although most recently we have seen some increase there but we want to reserve the right to get more history under our belts before we project that going forward.

On the expenses side we did have a little bit heavier quarter on the direct expense in the midstream in the second quarter. We expect that to normalize down to a somewhat lower level going forward. And our depreciation of course is a function of the assets we acquired in March.

On the capital expenditures side, in the third quarter we've got system expansion dollars in there for our -- one of our systems our Beaver Perryton system e in Oklahoma Texas area -- panhandle area. And then under "other items", interest expense we've got fairly stable with the quarter. We should see some uptick as a result of the increased debt levels on TVR. But rate-wise it should be fairly consistent with what we've been realizing.

So with that, Jim, those are the main functions of -- main components of the guidance table.

Thank you. I am sure everyone can now update their models, Frank and move forward. That's all we have, Megan. So I'd be happy to turn this over to questions.

Thank you, sir. [OPERATOR INSTRUCTIONS]

Our first question is coming from Joe Allmann of RBC Capital Markets.

Hi, everybody.

Hi, Joe.

A question for Baird.

Baird, could you update us on activity in Appalachia outside of the AMI?

Joe, we continue to go after acreage acquisition in primarily our horizontal CBM program. We probably got 150,000 acres outside the AMI. We have drilled two wells up in the north central part of West Virginia, I think in Barber County. Neither of those wells have met, exactly our expectations.

We think the second one actually is a better well than it's behaving, because we've had some hole problems. So the plan is to get a third well drilled before the end of the year, try something differently as far as making sure we get sufficient core holes drilled so as we stay within the coal, rather than getting in and out of the coal. Because apparently there is a reactive shale either above or below the shale that's giving us fits because CBM wells, of course, tend to make fresh water and fresh water and shale don't necessarily --

We have some other prospects we are aggressively acquiring acreage on based on some studies that we have done over the last year to year and a half, so we're pushing it extremely hard. We will probably be pushing our activity up into southwestern Pennsylvania here late this year, and in 2006. So you'll see our activity from an exploratory standpoint, ramp up appreciably in 2006, after we get our leasehold situation in place. Any comments about the Devonian shale? We still plan on getting one well drilled before the end of the year. There is a couple of options as afar as where we drill that well. It is either going to be adjacent to the well we drilled in 2004 that didn't meet our expectations economically. It would include doing it a different way because we will probably drill a lateral and approach it more from a standpoint of what they're doing in the Barnett shale or maybe approach it from the standpoint of how they're doing the bockin shale.

Whereas the first well we drilled we tried to drill it with multiple laterals and that caused us some fits as far as hole stability goes. There is another area that is on existing property that we have that's more in the conventional harder, Devonian shale play area that we may focus our attention on that maybe has a lower geological risk. So we did plan on getting another well drilled before the end --

All right. Thank you.

You're welcome, Joe, thank you.

Our next question is coming from Dan Morrison of Aperion Group.

A couple of quick questions. The Williston basin play you mentioned, that's bockin shale and not the bockin dolomite?

It is actually the bockin dolomite.

It is dolomite? Okay.

It is.

And what's the magnitude of that as far -- is it multi-well? How many -- is it just a few well deal or is it got some more scale to it?

It is a large scale. It is around 20,000 gross acres. We're thinking ultimately we can probably get 25, 22 to 25 wells drilled on a 640 acres spacings. These'll be laterals in two different directions frac-type. Things they're doing up there right now in general in the bockin dolomite, so it's got some scale to it.

Is that Montana or North Dakota side of the thing?

It is on the Montana side.

Okay. One more thing.

On your guidance, Frank, the -- does that incorporate the -- I'm just trying to understand kind of some of the assumptions that are embedded in it and what some of the possible incrementals to the upside can be. Does that include the potential third rig in the Cotton Valley?

Yes, it does.

It does? Okay.

And the -- I have several Gulf coast exploratory wells that are really just now starting to contribute in the third quarter. Is there -- do you take a pretty conservative approach to those or can you kind of give us a little color on that?

With respect to guidance, we've taken a fairly conservative approach. We haven't added much in the way of 2005 contribution from our exploration -- from this third and fourth quarter exploration program.

Okay. So that's all potentially incremental?

Yes.

For instance, this Finnet well I mentioned in our guidance, it was in there as a risk number because we hadn't completed it yet so, on an [inaudible] basis, it sheds a different light on it.

Great. Okay. Thanks.

Thank you.

Our next question is coming from Ray Deacon of Harris Nesbitt.

I had a question about the Finnet well.

How many -- do you think you'll have any offsets there and what's your best guess on what kind of production contribution you'd get out of that well?

Ray, it is a little bit too early to say. Originally when we drilled this thing it was an amplitude prospect, we thought it was a 3 to 5 Bcf-type prospect which one well could handle. It actually looks a lot better on the log than what we had anticipated, so is the areal (ph) extent greater than what we thought it was based on the original amplitude interpretation? We just don't know at this time.

It's going to be the fact of getting this thing in line, now. Since this lower ten-foot of pay that I mentioned appears that it is successful, realistically we probably will not fool with the 50-foot of pay that appears to be a no-brainer at least based on what the log looks like.

Right.

So there is consideration given now from a present value standpoint that maybe it makes sense for us to go in and twin that location and go ahead and just drill a well through the 50-foot of pay and complete both the entire hectare (ph) interval. That's something we're studying right now but it is going to be a matter of getting in in line to see how this thing acts.

Okay. Got it.

And Brigham mentioned on their call, they thought they may not have gotten all the way to the lower Frio in the Wise number one. Is that-- do you agree with that? Do you think you would drill the offset well deeper?

It makes sense to take the next well deeper. We were having -- we were running out of -- we had operational limitations which prevented us from taking it deeper. These wells are extremely abnormally pressured approaching almost 0.9 gradient, extremely high mud way. So the casing program is going to have to be altered and trying to take this thing deeper plus there's got to be some hole size considerations, too.

We were sort of running out of hole size with this first well we drilled, and we were down to drilling some [inaudible] which probably doesn't make a lot of sense when you're trying to drill something to 15, 16, 17,000 feet. So, the answer to your question, yes, but with the caveat being we're going to have to run some bigger casings and drill some bigger holes in order to take this thing appreciably deeper.

Okay. Great.

I guess, I just got one question on the coal side. With the Illinois basin acquisition, is there the same type of transportation issue there that you're having with Patter (ph) River coal now or is it -- I guess I am just trying to figure out whether there is much potential to grow the volumes out of that acquisition, if some of these rail issues get resolved.

I don't think we have those kind of rail issues at all. Keith, do you want to elaborate or I can, if you don't --

The Illinois basin property that we acquired is located at immediately adjacent to the Green River which is navigable and just upstream from a junction with the Ohio River and so it is -- all the coal currently being mined is going on an inland waterway or is trucked.

Got you.

Isn't even exposed to the coal -- or to the rail market, and there is room to grow and it is in an area where there is quite a concentration of power plants.

Okay. Great. Thanks a lot.

Thanks, Ray.

Our next question is coming from David Snow of Energy Equities.

Yes. I wondered if you could tell me the bockin dolomite, is that a -- are you going to do a Barnett-type of slick water frac or what's the thought on how you would do that horizontal?

David, it -- most of the operators who're drilling bockin dolomite wells right now are [inaudible], from what I understand, perforated liners and treating the entire interval through selectively perforated liners in these holes. They're not trying to do any multiple frac jobs which is different than the Barnett shale, for instance. They're pumping some diverters throughout the frac job itself.

But it is a fairly large -- but I guess you could call it as compared to a multiple frac jobs, less expensive stimulation which appears to be working.

Okay. Now, if you could tell me how you're -- give me a little more color on the Devonian shale and the Appalachian basin. How many acres do you have in that play now? Those two plays?

Well, the Devonian shale is -- exists -- is a blanket throughout the Appalachian basin. There are different portions of the basin that exhibit different production characteristics from excellent to not as good, of course. We have a 100,000 acre lease down in Virginia that wells vertically are completed in the shale. So it may make sense for us to do some horizontal type activity down there.

We have acquired probably another 10 to 15,000 acres in this Mason County area West Virginia that we think has potential, and where the first location was located. We've got Lou Creek (ph) and McGraw's (ph) legacy assets in Wyoming County. We've got roughly 70,000 acres that the shale could be prospected there. It is on the deeper side, deeper meaning, 6,000 feet or so. 5,500 feet. You liked a shot at perfect this technology. The shallower Devonian shale depths were these other two areas have these characteristics. But having said that, we've got appreciable amount of acreage that horizontal technology could apply, could make it work in.

And you would be using the Barnett kind of technology for those?

We don't know at this time. That is a consideration. In fact, that's probably is strong consideration where as we will go ahead and try to selectively do two or three frac jobs, slick water jobs along these -- along this lateral. But there is some consideration maybe we need to try and look at the merits of trying this bockin dolomite type method they're using in the Williston basin. Whereas they set a line and just frac this thing in [inaudible].

Okay and finally what are the conditions for being able to use a fourth and fifth rig with CDX?

Basically the conditions are to be able to be assured that we can get the gas out of there for a significant period of time. Before they'll build and man and train and -- build a rig and train a crew they want to be sure that rig will be utilized for a period of time, so it is basically -- we wouldn't ask for a rig if we couldn't keep it busy anyway. But basically, what the deal is we have to demonstrate to them that we can in fact move gas for a certain period of time or commit to the rig for a certain period.

Okay.

And your midstream could it actually do any of that or what would you do to cause -- ?

It is certainly an option that the midstream could be involved in infrastructure plays that would involve PVOG as well. There is issues there with conflicts of interest and everything else, but it surely could be an option.

How would you normally proceed with the infrastructure development?

To date we build it the PVOG level at the PVA level.

Okay. And then just when would you try your first Devonian shale horizontal, in the rest of the year?

We drilled one last year which I think Baird said was a geologic success, a commercial non-success. We learned from that. We hope to drill another one this year.

Okay. Thank you very much.

Thank you. [OPERATOR INSTRUCTIONS]

Our next question is coming from Bill Highler (ph) of H.M. Energy.

Yes. Good afternoon.

Good afternoon.

Yes, most of my questions actually were answered. But I just thought of a new one I would like to bring up. It's a strategic financial question I have been wrestling with for a while with regard to the Company.

Given the multiples that PVR trades at I think upwards of 12, 13 times EBITDA, is there any thought or does it make any kind of sense to consider moving some of the long lived stable cash generating oil and gas assets in Appalachia into the MLP, given the cost of capital advantage that that offers and I guess -- I believe PVA is the GP owner and controls about 8 million units of PVR?

Taking questions in reverse order. We own 7.8 million I believe it is LP units. Yes, we are -- we own 100% of the GP. It has been certainly suggested from time to time that long lived natural gas assets, like you might experience in a conventional, that is to say non-horizontal well in Appalachia might fit into that format. I think there is another company out there that's considering doing that.

We've considered it from time to time and prices being as volatile as they are, you'd want to hedge that gas I think for some period of time. It is not that it doesn't make sense or it does make sense, there is surely can make an argument that it makes some sense. To date, we've chosen to keep things separate but I think we're fairly open minded about it.

Right.

My other thought and maybe the CFO can answer this is, I would expect if gas prices stay at these levels , you're not going to be deferring as much as your income taxes going forward. In other words the oil and gas assets are going to be become larger taxpayers, but that may also be a factor in considering considering the MLP format for some of the assets? Is that true basically you're -- should be paying a lot more current taxes going forward?

Well, hi, Bill, this is Frank Pici.

Yes, Frank.

We'll pay -- we will pay some more taxes although we've got a pretty big ramp up in our capital spending as well which -- you'd get the IDC expense that helps offset some of that current liability for taxes. But there will be some and that could be a consideration. We haven't really felt it was of a magnitude that we needed to do anything drastic with the assets. But we always keep up -- keep a finger on the pulse of what's happening with our tax rates and our current deferred split and today we haven't gotten overly alarmed with it. And I think we have enough capital we're spending to offset some of that current tax bill, but it is a consideration going forward.

Okay. Appreciate it. Thanks.

Thank you.

Gentlemen, there are no further questions in the queue at this time.

Okay. Well, if that's the case, then I would just again say thank you very much to those of you who took the time to listen and who have an interest in the Company and we'll see you next quarter.

Thank you, ladies and gentlemen, for participating in today's teleconference. You may disconnect your lines at this time and have a wonderful day.