Riley Exploration Permian Inc (REPX) 2011 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to today's Tengasco's second-quarter 2011 financial results webcast. All lines have been placed on listen-only mode and the floor will be open for questions and comments following the presentation.(Operator Instructions). At this time, it is my pleasure to turn the floor over to your host Cary Sorensen. Sir, the floor is yours.

Thanks, Melinda. Good afternoon to all. Welcome to the conference. I'll be making a brief statement here about forward-looking statements and then we'll have a presentation by Mr. Bailey and Mr. Rugen.

I will begin by noting that a pretty detailed description of forward-looking statements contained both on pages 2 and 3 of the slide show on our website to accompany today's presentation, page 33 of our 10-Q form filed this morning, and page 1 of our 10-K, which of course was filed last March, and we incorporate those herein. Remind you that this presentation may contain such forward-looking statements that may prove inaccurate or incorrect over the passage of time. Questions will be taken following the presentation. And I now introduce Jeffrey Bailey, our CEO.

Thank you. I'm going to begin on page 4, talk a little bit about the second-quarter highlights, and then I'm going to pass on the details of the financials to Mike Rugen, and then I'll pick it back up and we'll go through the rest of this year's operation that we've had so far. So if you're with me, you should be on page 4 of our presentation. It's the 2011 second-quarter highlights.

Second quarter 2011 basically $1 million in net income or $0.02 per share. Year to date that puts us to $1.3 million, also $0.02 per share. Net income from operations second quarter 2011, $1.7 million; year to date, $2.8 million. Revenues, nice little rebound there in the second quarter, up from the first quarter of $4.8 million; year to date, $8.4 million. Like where we are at sitting there. If we can do that again the second half that would be really good.

Full production and gross production barrels second quarter of 62,000 barrels and year to date 115,200 barrels. Now I'm going to come back, we'll talk about operations and what we've done, but for right now I'm going to pass on the financial details to our CFO, Mike Rugen. Mike?

If you look at page 5 of the presentation, it's titled second-quarter 2011 financial summary. I just want to point out a few things on this slide. As Jeff mentioned before, the net income from operations for the first or for the quarter ending June 30, 2011 was $1.7 million. That compares to about $600,000 for the same period last year. Year to date as Jeff mentioned also, the net income from operations is about $2.8 million. That compares to $1 million for year to date 2010.

The main driver of the increase, which basically increased about 200% in both the quarter, the second quarter and year to date, were the increase in revenue numbers. The revenues for the quarter -- for the second quarter 2011 were $4.8 million, compared to $3.3 million for the second quarter 2010, or they went up $1.5 million or 45%.

The $1.5 million is really made up of a couple different pieces. One, $1.2 million of that increase related to the increase in oil price, which basically went up about $24, $25 a barrel on average. We also had about $400,000 related to the increase in the oil sales volume. We also had just a small offset of that, a $100,000 decrease in our MMC revenues for the second quarter.

For the year to date 2011, our revenues were $8.4 million, compared to $6.1 million year to date 2010. Once again, that was up pretty considerably, $2.3 million or about 37%. The $2.3 million was once again made up of a significant portion due to increased oil prices. Oil prices went up $20 to $21 a barrel -- $20 to $21 a barrel, which accounted for $1.8 million increase in revenues. About $700,000 increase in revenues was related to the oil sales volume increases. Once again, there was a small offset, MMC revenues were about $200,000 lower than they were last year.

If you look at the net income line you can see as Jeff mentioned, we made about $1 million net income for the second quarter 2011. Looking at the presentation, we have a net loss per share. That's actually a net income per share on the slide presentation of $0.02 a share. That compares to about $700,000 net income or $0.01 a share for the second quarter 2010.

As we talked about before, revenue increases were a big portion of that. In addition, the derivatives also had an impact on both the second quarter 2010 as well as year to date. The gain or loss on derivatives actually decreased about $600,000, $650,000 or so. That was really -- the $60,000 gain this year is really made up of a $900,000 unrealized gain, and that's offset by $466,000 of settlement payments we had to make to Macquarie. And also the $374,000 cost related to the put that we purchased from Cargill.

On a year-to-date basis, our net income was $1.3 million, compared to $1 million last year both at $0.02 a share. Once again, you can see that there was a large change in the gain or loss on the derivative account. On a year-to-date basis, we showed a $300,000 loss on derivatives. That was basically made up of $800,000 unrealized gain. Once again, offset by $745,000 of settlement payments, and the $374,000 cost for the put. That compares to a $900,000 unrealized gain last year and only $29,000 settlements.

If you'll turn to page 6 on the slide presentation, the top of the slide reads second-quarter 2011 revenue summary. This once again just to show you that Kansas makes up the bulk of our revenues in this Company. For 2011, for the three months and year to date, it made up approximately 96% of the revenues in the Company. Now that's up a little bit from last year and primarily due to the increase in prices, but also we did have some decrease in the methane sales, so that impacted that somewhat.

If you'll turn to page 7, the title of it is derivatives. It's a pretty busy slide, but a couple things I just want to point out is during 2011, we've actually made cash payments related to our derivatives to Macquarie of about $745,000. Once again, we only made $29,000 year to date last year. We actually had a $29,000 payment related to April production that we made in May of 2010.

In August, we expect to make a payment for our July collar of about $117,000. July will be the last month of the collar. And so it will be completely done after we make the payment in August.

At the end of June, we actually had an unrealized net asset, derivative asset of about $126,000. That compared to a derivative liability of almost $700,000 last year. A big portion of that is -- we basically have $230,000 asset related to the put we purchased from Cargill, and that's offset by $104,000 liability related to the last month of the Macquarie derivative transaction.

That's all I've got. I'm going to turn it back over to Jeff to talk about the capital and then details on the operations.

All right. If we look at our progress so far this year and I'm beginning on page 8, our capital spending, we spent about $2.4 million on drilling. That's 10 wells in the first half of the year. Really, those are pretty much concentrated all in the first quarter of the year. Polymers make up about $0.5 million, and additional leasehold and seismic make up the other $600,000, for a total of about $3.5 million of total oil and gas capital investment. I'll call it investment spending. Also about $0.5 million worth of spending on the MMC electrical generation. I'll talk a little bit more about the MMC at the end of this slide. I'll get into the details of that [forward].

Following up on page 9 with a slide from the first quarter, remember we reviewed this the last quarter that we drilled 10 wells, we planned 14 more for the rest of the year, we're going to restart drilling in June. Actually that slipped to July. That's why we've only got three wells done as we didn't really begin until early part of July.

That Webster area was our focus in the first quarter. We are moving into the rest of our holdings in other areas of Kansas for the rest of this year probably. We may go back to Webster toward the end of the year. And we still like Webster a lot, a lot of stuff to do up there. I think we're going to see us back in that area at the end of first quarter of 2012. Webster was our area of drilled polymer and produced even more, and we'll see how some of those results worked out.

Go to page 10, activity in the second quarter and more. Three more wells drilled. Actually, those are even beyond the second quarter. Those actually were all done in July, all outside Webster field as we talked about.

Two producers and one dry hole. The two producers have done very well. Together, they're averaging about 90 barrels a day through the first two weeks of August, drilled them in early July, basically had them going up and down good by August, so that's why I kind of gave you a look at those numbers. Off to a good start with both of those.

We're still planning 11 more wells coming up in the rest of 2011. One of the highlights of the second quarter I think for the shareholders and for management is the collar ended July 31. We're happy with where that put us overall, of course, not happy with having to send Macquarie money, but that is what it is.

We like our position here. The new addition in the second quarter of having a $65 floor on a hedge of 10,000 barrels per month. Now that's 10,000 per month for that particular one there.

Okay. Move onto the next page. There's production and gross barrels through July, so that takes you even beyond the second quarter one month. You see we're hanging around 20,000 early, a little bit below, but we pushed up above 20,000, even 22,000 there in May. And you're going to see as production going up, polymers being completed as we phased those in early in June and July, and then in also early August with a new drilling coming on as well, so production through the first seven months.

Let's move on to page 12. The polymer wells in 2011, I could jump down to the big black line there. We added almost 5000 barrels of gross production during that time from the March to June timeframe, a little bit earlier than the second quarter, but then through the second quarter, we saw the contributions of those things. I think that's going to continue some. We're doing polymers as we speak, and we're bringing wells back up that we've just done polymers on, even as late as today. So we're going to see additional influence of polymers.

Typically, a high level of success, we generally end up, of course, hoping we'd produce more oil. Even without oil, as the second line there says, we'll cut back on water production saving our electrical cost and the disposal costs for that water. Even if that's all we ever achieved with the polymer job, we eventually would get payback for that investment, which you see in the next line down below.

Cost us about $90,000 on average to do a polymer job. It takes an average of a few months for payback. Sometimes we get payback in a matter of weeks. Of course, that's dependent upon the price of oil. Each polymer job brings back with it on average about 11,000 barrels of new reserves per application. And overall in Kansas, we have one of the best success rates on a per-polymer per-well return basis of any operator in Kansas.

And then at the bottom and not during this presentation, I think you should have to listen to me continue to talk before you click on that link. But at the bottom of page 12 is a link for the company, Polymer Services, out of Kansas who does most of our polymer work. In fact, they do it all. And there's a link on there to their website. And on their website is an excellent animation about how polymers work. So after the presentation, I encourage you to take a look, go there, and look at Polymer Services' website.

Next page, Kansas is hot, literally and figuratively. Hot in temperature, we had about 30-plus days over 100 degrees in Kansas, maybe more than that. But a lot of hot days out there. But Kansas is also hot for the industry. The industry has rediscovered Kansas.

Now if you're looking at this Kansas map -- I think this is on page 13 -- the yellowish-green color in the middle, that's the Tengasco counties in which we have a presence. That's all on the Central Kansas Uplift. And to our south, our two red circles -- let's talk about those first. One go in on the right side of the Central Kansas Uplift, [Baruva], Sedgwick Basin, into the Salina Basin, and west of the Nemaha uplift. And likewise to the west of the uplift, there's another one going into the Anadarko Basin, those two red circles.

Those areas are being pursued by much bigger companies than Tengasco. A lot of activity following down on both of those red areas, where they're doing horizontal Mississippian wells. Much like the horizontal lessons learned from the shale plays, these are a little bit different. These are conventional rocks with horizontal drilling done to enhance the opportunities to expose the wells and those well bores to additional hydrocarbon results. That is going to be concentrated primarily off of the uplift. Now not everything we have is off of the uplift, so we're paying close attention to all of this activity. That's good news we'll talk about a little bit.

There's a little orange circle up on the Kansas-Nebraska-Colorado border. An additional play is taking place out there. And if you go ahead and go on to the next page, you'll see, I call it bigger new neighbors. And there's two parts, there's the Mississippi drilling to the south, and Niobrara to the west. And this has brought in companies, big companies, Chesapeake, Sandridge, ConocoPhillips returns to Kansas after initial presence many, many years ago. They're back in around Kansas and Colorado side looking at the Niobrara, Shell as well involved on that side. So we're seeing major companies become reinterested in Kansas, maybe for different reasons, but it brings two parts of news.

One, the good news, Kansas in general is worth more. The things we were leasing for $10, $15, $50 and $100 an acre are now -- some of those things as you move out of the uplift area are selling for $3000 an acre just to lease. That may -- in general makes all Kansas holdings worth more.

Since they're doing horizontal drilling, these are companies who are running multiple numbers of rigs each in their various areas whether they are in Niobrara, the Mississippian, they're bringing in more service companies, and there -- by doing that, that gives us additional access that provides a little more competition for the service company support, and it's just nice to have additional companies in our area to work from.

Bad news is of course for us too, we'd like to acquire more leases. Leasing cost statewide has gone up, some places significantly. That affects us when we go out and try to acquire new acreage, even smaller blocks. And the bigger blocks of acreage, well, all those big blocks of acreage has just been difficult to get a hold of. We've had trouble even trying to find acreage of size to put together. So it's a good news, bad news thing with all this new activity from these big, new neighbors, I guess you'd call them.

On top of that, we had hoped through the course of this year, we've made some efforts. We had an add, I think some of you saw, on the webpage that had run in KIOGA, the Kansas Independent Oil & Gas Association, flier that we'd be interested in purchasing Kansas. So on the bigger side of things, we saw three to us significantly large properties come up for sale, ranging between 300 barrels a day up to about the same size as Tengasco.

All three of those properties sold for prices between $110,000 per barrel to $150,000 per barrel. Now we have that on a gross basis, because that's how we had to actually analyze it. Most of that was with working interest total similar to Tengasco, something in the mid-80s on average for those particular working interest totals. So that's a significantly higher price than we saw in even '08 when oil was $140 a barrel.

So while we haven't had the rebound completely in oil price, two things have driven that up -- one, the activities of these big, new neighbors; and two, just a general interest in Kansas-type standard production. We have long-lived, low-decline reduction continuing.

All right. I should look on to page 15, talk about MMC. We did get the system configured, the pipeline, and Atmos has helped us now, and all the gas is being physically delivered to Kingsport. And that's Atmos's doing, they basically are taking both Swan Creek gas and MMC gas out of our pipeline and delivering it to Kingsport. We get paid by Atmos, so where it goes, we really don't care, as Atmos does that for themselves. Obviously, the MMC volumes, they're paying us the $6.42 all-in price.

There's still some ups and downs or maybe I should say there's still lots of ups and downs with MMC. Some of those are related to the ongoing infrastructure improvements that Allied continues to make to improve two parts. Once they got their oxygen fixed, we came up and ran several days in July and (inaudible) quarter off to a good run and, lo and behold, we had a big, big rainstorm, they ran over a well, they flooded their field. It's just another problem for them. But in general, they're redoing all of their entire gathering system through some period of time here, and that's going to help the overall gathering system.

So as not to be totally dependent upon everything that they have to do on that side, we've come up with a modification to the system. There's actually two of them. We're going to have a variation on how hard we can pull the field from our side. It was an all-in compressor, all or nothing. That's not as good as you might think. We now have what we call a variable pool on our compressor we can pull at different ranges. We can tie two compressors together and pull, so that will allow us to match the ability of their delivery system to give gas.

And second, we're going to take a waste stream of gas, or actually it's a bypass stream of gas that we recycle to the MMC unit for sale. It's a little bit higher in oxygen. We're going to pick that off and send it to the electrical unit because one of our highest costs for MMC operations is the electrical charge that we face.

And so both in the MMC use for electricity, we hope to see additional revenue generations by late in the third quarter or early in the fourth quarter from the MMC. And that was if you remember the early slides, it had a capital investment of about $0.5 million on that. We're going to have about another $400,000 of investment for MMC coming up related to that generation facility. But it has a lot of legs underneath it. One is not quite as sensitive to the landfill components as is MMC, so it should be able to up and generate on the electrical side for us even in periods of time when it's maybe too high for MMC. So we're looking -- we're really encouraged by those two steps, it's about all-in for us that we can do to help out the facility.

We're also encouraged that Allied Waste has a very forward-looking idea of working on their gathering system and have been a great partner, and they're going to get better. They're going to improve their system, and it's time consuming. Sometimes for the shareholders maybe even it seems excruciating waiting for MMC to come around, but the maturity of MMC is coming.

Next slide, this will be 16, more drilling in Kansas. Obviously, we've been pretty busy all year. If we get all these wells down these next 11 by the end of the year that includes at least one in Tennessee as well.

It's a mix of development and exploration, 11 years by year-end. At least one of these is going to be a Tennessee well. But we're happy with that whole part. That's going to put us at about 24 wells for the year the Company will have drilled. And that includes 10 from the beginning, the three we've done already in this -- early in the third quarter and then what we're going to do for the rest of the year.

MMC and the landfill progress we continue to talk about. We're really hoping we get all that done and we get it on on time. I'll have some info in the next conference call for the end of the third quarter.

As usual, we're on the outlook for new areas, even maybe beyond Kansas. We're doing what we can do to look outside our areas where we currently are. Prices are high everywhere. Kansas seems to have gone up more than most, so we're trying to see if there isn't a new area we can look where we can find growth.

Now we still have good growth within our generic drillbit patterns. We have some inventory of wells left to do. One of the key drivers for us, we're still primarily doing all of this on a basis of cash flow, a little borrowing this month to keep everything on even keel or a little borrowing this quarter and this year. Not that much, oil price matters to the plan as we go forward. And that's really the last slide that I have.

So I want to bring out --- Melinda, if you would, start queuing up the questions. And then one more comment. That financial slide where we didn't have the parenthesis in there and it said negative, we fixed that. So if you -- back on the financial slide on the website, we've gone back in and fixed that slide.

Okay, Melinda?

(Operator Instructions). Richard Dearnley, Longport Partners.

Good afternoon.

Hey, Richard.

Net production numbers for the second quarter, I didn't see those anywhere. I saw the $6,000 net increase, but what were the --

Yes, in the full Q, that's actually in there. Basically, we report two parts of that. Let's see, Mike, we have --

We have the year-to-date number.

Yes, year-to-date sales. You look at sales -- remember, the difference in gross production and sales are two part -- there's two parts to that.

One, we have some production that never gets sold that month, right? It ends up in the tank and goes into inventory as it's sold. And then we also end up with that part that we don't own. The land owner gets at least 12.5% royalties. In some of the wells, there are other royalties in there. So there's a mixture of gross and net in all that. So Mike's got that for you.

Yes. Richard, it's -- if you remember, the first quarter, we had about 40 net barrels to the Company. We had 48 in the second, so that's the 88. And that's really the Kansas sales volume. We have just a little bit of -- about 1,000 barrels a quarter for Swan Creek.

Okay. Then I was trying to -- I'm looking at the slides, it was number -- the slide 11. And it looked as though given a flattish June, July, I was trying to reconcile that to the comment that you've got 5,000 barrels in March through June from Polymer, and then take that to -- basically, the question is, what's the decline rate of the base production? But --

Yes, I can comment to that a little bit. I think the Kansas everyday base production there runs somewhere in about the 3% range. Remember, the winter months, typically for us, there's a handling temperature effect, so we almost always end up lower. The oil is thicker. It moves on surface less. We have weather issues. So sometimes some of that impacts that time. So some of that's buried in there when (inaudible) to go down and come back.

But in May, that's 22,000 versus, I don't know, it's probably about 17,500 there in April or so [it goes]. So there is some of that in there. So not only are we offsetting that decline, but some of those polymer events, we didn't really pick that up in real earnest until June. So bringing them back in July and bringing a number of them back at the end of July doesn't show up yet in this slide.

Oh, I see. Okay.

So the two weeks we have so far in April, we're seeing more of that -- I mean, August, not April. Two weeks so far in August, we're seeing more of that coming back. So --

Right.

It's buried in there, a little bit offset. Now also we've done some drilling in there. Remember that early group of wells that we drilled in Webster, a number of those are drill polymer drilled, we didn't polymer -- and I think on the press release, I talked about a couple of them.

Right.

We didn't polymer those until late, and they hardly had any opportunity to get much oil volume in.

Are the subsequent polymer wells that you've been doing looking like they have the same results?

Yes, I think if you can stick to that average -- I haven't really gotten too much into it. But if you stick to that average, I think that's pretty good. We are each going to add 11,000 barrels of reserves.

I think one of the ways to look at it, a really good problem for us is we (technical difficulty) know and we'll have a couple of these coming up maybe. We'll see it go from something less than four or five barrels a day, or about that, up to -- for a short period of time, up near 100. And then we'll see a fallback and it will flatten out again about 70, and it will gradually work its way back. But it never works its way back to five. It will work its way back to 8 to 10 and a whole lot less water for us to deal with. So --

Yes, that sounds wonderful. Is the -- what are you looking for in the Tennessee shale well?

We have one well up there. I think one of the -- and we have quite a thick -- what's the equivalent of -- well, it's not really the Marcellus section here but it's the same thing, the Devonian Shale. Actually it's called Utica, which is a new fancy, big, renamed word of shale development in the Appalachian. That's what we have. We have the Utica Shale.

And we know we have about a 900-foot thick section. And we have three or four places in the one well -- we only have one well, so I'm basing all this on the one well we have right now -- has some organic intervals, it has some gas, although it's a relatively modest amount, it's not a properly drilled or completed well. This was done a number of years ago. And we just have to drill a new well. I have to do it myself and make sure that it's set up right, so that we can actually make a scientific real engineering and evaluation of two parts.

One, how much shale -- or how much gas production do we actually have? What's the quality of the gas because there was some issues possibly about the first well? Although, I say it was engineeringly suspect. And then we can handle all that ourselves in-house, no partners, no nothing, we'll know what we have there. And then that will give us an idea about how aggressively to pursue any additional development related to that leasehold position we have with that shale. And sort of give overall if we do want to bring back in or think about bringing back in somebody with a little more shale experience, it will give them also a better idea about expectations.

Eventually, we're going to need at least three wells also to figure out the complexity and the geology. The geology in Swan Creek, this 900-foot shale section, is much ticker than most of the rest of the Appalachian. But it's not structurally a nice blanket, perfectly horizontal, and these guys have the ability up there to drill these long, horizontal wells and (multiple speakers) exactly where they think. This is going to be much more complicated than that. It's got faults (multiple speakers) --

Yes. It sounds like it's more like the Niobrara, which (multiple speakers) --

It's somewhat like the Niobrara other than it doesn't have a liquid component, almost certainly doesn't have liquid.

Oh, I see. Is the right way to think about the collar ending at the end of July that that adds about $120,000 a month to your cash flow?

Cash flow? Well, it will against what we've paid so far this year. Obviously, price is down a little now from (multiple speakers) --

Well, that was -- yes, that was the next question.

Yes, so you get that kind of effect. Tell me what the price is going to be at the end of the month?

Understand.

Or end of the year even. That would really be good. But --- Richard, we should probably move on.

Oh, sorry. Okay.

No problem. Thanks so much for your call.

I'll get back in line.

Okay, thank you. Melinda?

(Operator Instructions).

You can pick Richard back up, if there's not another caller.

Richard Dearnley.

Thank you.

Okay.

Were the three acquisitions you were looking at all in the Central Kansas Uplift?

Yes, primarily. They may have had some things like us that spill over. Like our Southwest Trego, if you go back to that slide, I had a little blue star for Southwest Trego. That would be slide 13. If you go back to that one, we're slightly off the uplift in Southwest Trego. And they would be similar. They would have the county right below is one of them I'm thinking of would have had the one that ends in embayment and that's Ness County, they would have had stuff down there. But primarily, Central Kansas Uplift, yes. Two of them -- well, one of them for sure, exclusively Central Kansas Uplift.

Right.

The other one a mix about like ours and the third one maybe a little bit more down there in that Ness County area.

And the Mississippian doesn't -- that has all the folks, the Chesapeakes and Sandridges --

Right.

-- all excited, doesn't come up into the uplift, does it?

It does not come into the uplift.

Yes.

That's very good. It doesn't, but it does go up both sides. The technology piece of it also is interesting. How far and what would be the next horizontal targets? I think there are probably some additionally on the Central Kansas Uplift that aren't Mississippian. So be interesting to see if any of those are pursued.

And, well, as I understand it, there were a couple of folks that have drilled horizontal wells. I don't know at what horizon they were shooting for. I suppose, they were trying the lands in Kansas City, but I don't know.

Yes. What's currently reported in the industry and what's actually out there is a very small number, less than the fingers of one hand, so it's a very small number. And I would say several of those were done long enough ago that perhaps the steering technology that was used to put them where they thought they wanted to be was not optimum. And those really aren't really good metrics for maybe what some of these other things would look like.

So I'm watching this with curiosity. I also think perhaps the Hugoton Embayment side, even in places like Trego County, now we're producing from the Mississippian in Trego County now where our Mississippian is dramatically affected by the run-off from the uplift. Down there where they're drilling, the Mississippi is again more of this pancake geology.

Right.

But I think there's application in our area, maybe not for these long 5,000-foot horizontal laterals, but a 1,000-foot lateral or something like that, there's possibly some application for that kind of stuff.

Right.

(inaudible) will be right, we have rigs that can do it, people that know what they're doing, service companies who can log it, those kinds of things. So --

Yes, it will certainly help that the service companies are going to be just down to the south of you.

Exactly.

Any thoughts as to when you might give that a try?

Well, we've discussed it internally. That's all about I can tell you. It's expensive. It's a tempting science project. I think as shareholders --

Right.

-- we are more interested in making money than science. But it's something to keep an eye on. I want to see a bit more. These guys are very busy down there. And the results are interesting. Though, I want to see a bit more of the mechanical process that they're going through. And they have a large number of rigs actually down there operating, so they're just building up quickly. So I just have to -- I don't have free access to it, right? I have to get them to let me have access to it. So hopefully as they do, we can see and learn something before I try to take on one of my own.

I understand. Okay, thank you very much.

Thanks, Richard.

[Brian Cayton, Morrison Mill].

Good day, Jeff].

Hey, Brian.

Two questions. Number one, when you talked about the auctions held in Kansas, using the same metrics for those purchases, what would that value Tengasco at?

Well, that's a tricky question. Even in our slides for production, if you go back to slide 11, we're going up and down. So you'd kind of I think to some degree, you'd have to look at that. We're a little more shotgun. Some of those may have had different concentrations and things like that, but you look at that overall and it's an interesting metric.

From that, you can get our daily production there, somewhere in the 600 to 700 barrels a day gross, figure out something along the math lines of that. I mean obviously, there's other things within Tengasco too other than just the Kansas production. Even though 96% of our revenue and all that's coming from there, we do feel like the MMC is a solid growth piece for the future. We should be looking at the land fill in terms of gas reserves. I think we've said before we'd have significant gas reserves, obviously, we have to connect that to operational time. Let us get the operational efficiency up, and we'll start talking about gas reserves from MMC. Right now, I think of biggest concern is efficiency.

So it's hard to say a valuation on terms like that. I think it's just looking at it going forward. Those numbers are big. And nobody is more shocked than us when we tried to take part in some of these sales and we couldn't catch up with those numbers.

We look at those things as -- if some of them had variations on upside too, that captures production. It may or may not capture the upside of those individual auctions. Some of them we felt like they had no upside whatsoever. It was existing production and that was it. And we were looking at 10 years, 10 years and $100 oil for those people to get their monies back who were purchasing that. So, I don't know, maybe -- that, or they're counting on much higher prices, or they think there's an upside we couldn't find.

Okay. And the other part of that would be has there been any interest in the pipeline or Tengasco is a complete sale or buy?

Well, no. And if we've had -- really, we haven't discussed anything about stuff like that as far -- but in the pipeline obviously we talked about it with last quarter and with [Kay] through the writedown.

We still have a number of people with interest in general in that whole goings on up there in northeast Tennessee with [TVA] and stuff. So the pipeline, we have people come visit and people look and things like that. But nobody has beaten a path to our door with a check, and that's really what we're pushing. It's fine to be interested and say you're going to do something, but show up with some money. And that has not happened yet.

Thank you. I appreciate it.

Okay. Thanks, Brian.

Richard Dearnley, Longport Partners.

I'm back.

Okay, Richard.

Were the acquirers of those that you were looking at, were they MLPs perhaps?

Well, they're --

They tend to pay that kind of --

One, no? Two, no?

Two of the three, no. I actually do not yet know -- even though it happened in July, I still don't know who the third acquirer was. Sometimes -- and all of them were private companies, so it's much more difficult to get the details. But the first two, no. They were going to be standard. Now they were both new to Kansas If that tells you something.

Yes.

But, no, the third one I don't know actually.

I see. Okay. Thank you.

You bet.

Okay, sir, there appear to be no further questions coming from (technical difficulty) at this time.

Okay. Well, I'd like to close up by thanking those that listened in for the conference call. We'll be talking back in Q3, Mike?

We put an updated --

Okay.

-- presentation up on the website that has the correction to the financial summary slide and it may have a little bit of rewording and some other things, but it basically is the same presentation with the correction from net loss to net income.

We do thank you guys for listening in, we really appreciate it.

Yes, alright. Talk to you in Q3. Thanks, guys.

Thank you. This does conclude today's webcast. You may disconnect your lines at this time. Have a great day.