Riley Exploration Permian Inc (REPX) 2012 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Tengasco quarter results conference call. All lines have been placed on a listen-only mode and the floor will be open for questions and comments, via the phone, following the presentation. (Operator Instructions).

At this time, it is my pleasure to turn the floor over to your host, Mr. Cary Sorensen. Sir, the floor is yours.

Thank you, Rachel. Good afternoon, everyone, and welcome to the second-quarter conference call for Tengasco. If you're an attendee from previous months' conference calls, you'll know the drill. We'll start with Mr. Bailey with an overview of the quarter; followed by comments from Mr. Rugen on the financials; and return to Mr. Bailey for a close up. And then we'll entertain questions.

But as always, I will start with a reference to the second page of the materials on the website, the forward-looking statements. I will not burden you with reading all of that. But I would urge you to read it. And be aware, as well, that the risk factors and the forward-looking statements contained in our annual report on pages 22 and 52 of our 10-K filed on March 29 are incorporated in that as well, and have a very full statement of the risks -- some of the risks involved in the forward-looking statements -- comments, stated on the second page there.

So pay close attention to that. And that's an important thing we need to emphasize to you all -- our forward-looking statements in this presentation, perhaps; and if so, the future may bring different results.

With that, I will introduce Jeff Bailey, our CEO, and he will proceed with the call.

Thank you for joining our second-quarter conference call. Just wanted to go over again, if you want to follow along, if you are listening in and you want to follow along with the presentation, the PDF version of that presentation is on our website at tengasco.com. So that first page that you come to, you can click on that, and move into that slideshow. And you can follow along. And we'll keep you up to date with the pages that we're on.

So I think, overall, you saw from the press release we had a pretty good quarter. So we'll talk in detail about some of the events. We'll talk about our drilling that we had. We'll talk about our recent polymer jobs. And will talk about those issues as we go forward.

But first, I want to walk you through the financials. And I'm going to let Mike Rugen do that. So, Mike, go ahead.

Thanks, Jeff. For those following along on the PDF presentation, I'm going to start on slide 3. And I'll try to keep you posted on which slide that I'm going through.

Slide 3 is the overview of the quarterly financials. As you can see, the net income increased $110,000 or 11% from $977,000 or $0.02 a share in the second quarter 2011, to $1.087 million or $0.02 a share in the second quarter of 2012. This was made up of several different factors. And I'll go, basically, line by line and discuss the changes between the quarters.

Starting with revenue. Revenue increased $445,000 or 9% from $4.785 million in the second quarter of 2011, to $5.23 million in the second quarter of 2012. Of that $445,000 increase, $[900,000] was actually related to a 9400-barrel increase in sales volumes in our Kansas production. Sales volumes went from 47,900 barrels in 2011 to 53,300 barrels in 2012. That resulted primarily from the drilling and polymer programs that we've been conducting, not only this year but the second half of last year.

$138,000 of the increase was related to an increase on our MMC revenues. We had $62,000 in revenues in the second quarter of 2011. It actually was $200,000 in the second quarter of 2012. $114,000 of that $138,000 increase actually related to electricity sales. If you remember, we started selling electricity out there in January of 2012.

These increases were partially offset by a $9.56 per barrel decrease in the oil price. We averaged $95.46 in the second quarter of 2011. We only averaged $85.90 in the second quarter of 2012. Production costs and taxes increased $328,000 or 20%, from $1.678 million in 2011 to $2 million in 2012. $150,000 of this increase really related to the change in the crude oil inventory. $100,000 of the increase related to increase in landfill expenses. And, finally, the remainder related to miscellaneous increases in expenses in our field cost in Kansas.

DD&A expense increased $238,000 or 36%, from $666,000 in 2011 to $904,000 in 2012. The increase was primarily related to higher oil and gas depletion costs. Approximately half of the increase was due to the increase in volumes that we discussed previously. And the other half of the increase related to higher DD&A rates we experienced in that quarter.

General and administrative expenses decreased $119,000 or 17%, from $719,000 in 2011, to $600,000 in 2012. That decrease was primarily related to timing. And Interest expense increased $42,000 or 26%, from $164,000 in 2011, to $206,000 in 2012; primarily related to increased bank borrowings, which was used to supplement cash flows in funding our drilling and polymer programs.

Gain on derivatives decreased $45,000 from $60,000 in 2011 to $15,000 in 2012. In 2012, the entire $15,000 related to the change in the fair value of the derivatives. In 2011, we actually had a $530,000 gain related to the change in fair value. And that was partially offset by $470,000 of settlement payments that we made to Macquarie.

Income tax expense was primarily the pre-tax income times the effective tax rate. In 2012, it also included $192,000 which was the tax effect of the $1 million Section 1603 payment. If you'll recall, this payment we received in June. And it was pretty well described in an 8-K that we filed on June 29. We also describe it a little more fully in the 10-Q itself.

If you'll go to slide number 4, for those that are following along, we'll talk about the year-to-date financial results. Net income increased $629,000 during this first six months of 2012, over the level -- first six months of 2011, which was $1.331 million. Year-to-date in 2012 it was $1.960 million or $0.03 a share.

The revenue increased $1.749 million or 21% from $1.8447 million (sic -- see slides, $8.447 million) in 2011, to $10.2 million in 2012. $1.6 million of that increase related to an 18,000 barrel increase in oil sales volumes from 2011 levels. That all resulted from increases related to the drilling and polymer programs in 2011 and 2012.

$300,000 of the increase related to increases in MMC revenues. We recorded $90,000 in revenues for the first six months of 2011 compared to $382,000 for the first six months of 2012. $237,000 of the $300,000 increase was primarily due to the electric revenues that were recorded in the first half of this year. As we said before, electricity sales actually started in 2012.

These increases were partially offset by $100,000 related to a $1.00 per barrel decrease in the oil price, from $91.57 in 2011 to an average oil price of $90.57 for the first six months of 2012. Production costs and taxes increased $566,000 or 18%, from $3.202 million in 2011 to $3.768 million in 2012.

$200,000 of this increase related to the change in the crude oil inventory. $100,000 related to increases in landfill expenses. And the remainder related to miscellaneous increases in fuel costs in Kansas.

DD&A expense increased $420,000 or 34%, from $1.237 million in 2011 to $1.657 million in 2012. The increase was primarily related to higher oil and gas depletion. Once again, approximately half of that increase was due to higher volumes. The other half related to higher DD&A rates that we experienced in 2012.

G&A costs increased $117,000 or 9%, from $1.242 million in 2011 to $1.359 million in 2012. This increase was primarily related to timing. Interest expense increased $85,000 or 28%, from $309,000 in 2011 to $394,000 in 2012. That was primarily related to the increase in bank borrowings used to supplement our cash flows to help fund our drilling and polymer programs.

Loss on derivatives decreased $200,000, from $306,000 in 2011 to $105,000 in 2012. Once again, the derivative gain/loss in 2012 was related to the change in fair value of the derivatives. In 2011, we had actually made $745,000 of settlement payments to Macquarie. And those settlement payments were partially offset by a $439,000 unrealized gain, which was related to the change in the fair value of the derivatives.

Income tax expense was primarily the pre-tax income times the effective tax rate. Once again, it also included a $192,000 tax effect of the $1 million Section 1603 payment.

If you'll go to slide 5, we can talk a little bit more about the revenue changes. As we mentioned earlier, total revenue increased $445,000 in the second quarter of -- excuse me, yes, in the second quarter of 2012 compared to the second quarter of 2011. The increase primarily related to Kansas. As you can see, Kansas still makes up the majority of our revenues. The percentage has gone down a little bit. This quarter, actually, it made up 94.2% of the Company's revenues compared to 96% of the Company's revenues in 2011.

Swan Creek made up 1.6% of the Company's revenues in 2012 compared to 2.4% in 2011. And the methane plant sales actually jumped up to 3.8% of the Company's revenues in 2012 compared to 1.3% in 2011. Once again, as we talked about before, of that increase in the gas plant sales, $114,000 related to electricity sales. All of the sales in 2011 for the methane facility related to gas.

If you move on to slide number 6 -- the six-month revenues; once again, as we mentioned earlier, the total revenues increased $1.749 million or 21% in the first six months of 2012, as compared to the first six months of 2011. Once again, the increase was primarily related to increased revenues in Kansas, but also the $300,000 increase in MMC revenues.

The Kansas oil sales were, once again, about 94%, compared to almost 96% in 2011. And the methane facilities, the sales from those facilities, was 3.7% of the Company's revenues for the first six months of 2012 compared to 1.1% in 2011.

Move on to slide number 7. This just gives you a snapshot of where we are as far as carrying value of our significant assets that we have on our books. The oil and gas properties right now, our carrying value is $25.5 million. That's the net book value at June 30. Just to give you a reference point back to the beginning of the year, you'll recall our proved reserves, on an undiscounted basis before tax, was almost $135 million; the discounted, at 10% before tax value, was $69.8 million. So you could see that our carrying value is substantially less than what our PV-10 or discounted 10% proved reserves are.

We spent $6.6 million in capital, including accruals, during the first six months of 2012. $5.7 million of that related to drilling. $700,000 related to our polymers. And $200,000 related to a couple of recompletions we did, as well as some leaseholds.

Pipeline book value was $6.8 million at June 30. We spent no additional capital on the pipeline in 2012. The methane facility -- the carrying value, or book value, at June 30 was $4.5 million. You notice that that's actually decreased over it what it was at year end. We spent $400,000, approximately, in capital. That was to finish up, for the most part, installation of the electric generator. But that was offset -- partially offset -- well, fully offset, by the $1 million that we got on the Section 1603 payment. That $1 million actually went -- the entire balance went to reduce the carrying value on our books. Half of that actually went towards reducing the tax basis of the properties. So there is a deferred tax impact on that transaction.

Other PP&E -- we had about $500,000 on the books at June 30. We had a small amount of capital that we spent to replace some of the field vehicles. The capital was basically financed through -- primarily, these are cash flows -- but we also supplemented those cash flows with additional bank borrowings.

A couple of other items I just want to highlight; we talked about this last quarter. But you'll notice that the inventory levels are about $500,000 higher than they were at year end. They were about 800,000; now they are about $1.3 million. If you'll recall, we spent about $2 million buying casing, tubing, pumping units, early in the first quarter. About $500,000 of that $2 million was used in the first quarter. Another $600,000 or so was actually used in the second quarter.

The bank debt increased $2.4 million from $11.5 million at the end of the year, last year, to $13.9 million this year. If you'll recall, it was about $13.6 million at the end of the first quarter. And that was related to additional borrowings, primarily used to continue our drilling and polymer programs.

And with that, I'm going to turn it back over to Jeff.

Okay, I want to pick this up on slide 8. Once again, you can follow along on the presentation on our website. Also you can gear up to ask questions, either over the phone at the end of this, or through the Internet; through the sign-in page, you can ask a question.

So, page 8. We have our annualized production, of course 2012 is through July; and so, basically, as we look back in this, in the historic basis, we see the upward trend from 2005 through 2011. And if we kind of do the math going forward on 2012, you see we're off to a very good seven-month start in 2012. So we can project that up, that we're going to finish significantly better than 2011 for total production there. So this is all gross numbers here. That's generally what we end up doing with, as we go forward.

Okay, look on page 9. Once again, this is Kansas only. This is Kansas average 2012 production since the beginning of the year. So we can see, also, here, a steady march up; January, February, going up. We finally did over 700 barrels a day. We actually are maintaining it through the mid-months there.

We set a record in June. We broke the previous November of 2008 record, which was 800-and-something barrels of production by going over 900 for the first time in Company history in June. It didn't last long. We broke that record again in July. We ended up with 974 barrels of oil per day. That's the Company production in Kansas. Again, that's gross.

So you can see that the benefits of being very active early in the year and then focusing late on polymer jobs in the last few months of the year has had an impact on our production. That follows through pretty quickly.

Then if you look at page 10, what I actually have here is some actual polymer example results. Some of these wells were drilled at the end of 2011; some of them very early in 2012. But there are six polymer jobs listed at the top, and corresponding graphs underneath. And so, let's just look at a few of these.

Basically, you take a well like the Coddington #6. I'd call that pre- -- let's call it the January through May production there. It was roughly running about 10 barrels a day; about 300 barrels a month, give or take, somewhere between 317 to 280. So during that period of time, the well is making about 10 barrels a day. That's not a bad Kansas well. Remember, the Kansas average well makes 2.5 barrels a day. This is state-wide for all companies. So a 10 barrel a day well is typically a very good Kansas well. These are the kinds of targets of standard drilling and things like that.

However, in our area of the Coddington and the Marcotte field, we know that's going to be a future polymer candidate. Polymer was basically done some time in late May, early June. The well was brought back up in June. And you see the production spike up from 280 barrels in May to 800 in June. Some of that is [maintained]. Remember, June would have been a short month. There would have been a period of time where June was down while the polymer was being done. That's about a two-week process. There had been two weeks in June of no production. So there is kind of a spike-up there from the last few weeks of June, where we had production, and then in July, an ongoing production. Since the time of that -- through the course of that year, that well there has produced about 3000 barrels of oil in the course of 2012. So, an interesting well.

If you move onto the next one there -- and the graph is right below that on page 10 -- for the Hilgers B #6. Again, that was a well completed late in 2011. And you can see that that well was really not very good in some ways, in terms of initial production. It's only making 15 barrels a month for January and February. That's a half a barrel of oil a day. In fact, this well was making more than 500 barrels of water at the time. We began the polymer in late March, mid-to late-March. It actually came on the last few days of March. And you see the spike-up in oil production. We basically take it from a half a barrel of production a day to in excess of 30 barrels of production a day.

So in April, it averaged over 30 a day. And it's still averaging over 20 a day in May. It's down to, it looks like, about 15 day in June. And then down to about -- a little over 10 a day -- 10, 12 a day there in July. So those are typically the kind of results that we see from a couple of different areas where we've concentrated both our leasehold position and acquisitions that we've made.

We have a number of wells up there that we've targeted to be drilled. Some of them are listed in our PUD category, and some of them are even beyond that into our other reserves. Those are the kind of target wells that we have in our inventory of things to continue. Because that's something we felt had a really good chance for success.

If we move on down the list, this story kind of goes on -- Veverka A #3, again, a well making, basically, one barrel a day through the first four months of the year; polymered some time in very late May; only brought back for a few days in late May, but had a full month of June in production. And you can see it ramped up there to close to 70, 75 barrels a day of production in June. Obviously, it's going to have a bit of a decline after that, and July goes on. But once again, during that period of time, the well [cued] 3600 barrels of oil.

Now, if you sort of do the back-of-the-napkin kind of math, and you look at 3000 barrels of oil to us -- and that's on a gross basis -- you can rough it out and say we're going to average about 80% net. And of that, maybe half of that is going to be real money for the Company. It takes about 4000 barrels to pay our drilling and polymer costs, give or take the price of oil; that's close to $100. We didn't really net that in the first half of this year. So that's kind of a number that we really focus in on -- 4000 barrels. When we get to that number, generally that's a pretty good time for us, because we feel like that's the payback moment.

The story is kind of similar for the other two Veverka wells there. And then, I like the Zerger A. The Zerger A is our well we drilled early this year. We brought the well completion in April. Basically, the well came back really making a lot of water. Which, in the terms of where it's located -- Webster -- is actually a good thing for us. And we don't mind that at all. Well came back making 314 barrels of oil a day -- or, 314 barrels for the month.

So we were actually pretty happy with that, in terms of -- it at least made some more oil. Then in June, basically, part of the reason that number went down is, once again, we're down two weeks while we perform the polymer. We brought this well right up on -- right at 1 July, so this basically began July 1. And you see, that was an outstanding well. That's come back really strong on the polymer job.

That's perhaps -- and, if you look on page 11, there is the graph of the Zerger A -- that's perhaps one of the best polymer jobs we've had in the Company history, in terms of total spike-up. And even through this day, I noticed this morning's report, the well is still making 99 barrels of oil a day. So for some period of time there in July, it was averaging over 130 barrels of oil a day.

So those are typically the kind of enhancements we have in a polymer job. So what happens is, when we drill those rolls wells -- and, remember, all these are relatively new-drilled wells. These aren't the old polymer wells that we've gone back in and filled -- well, these are old field locations, but these aren't old wells. These are wells we have re-drilled in those areas, and used the polymer as a planned event that's going to happen sometime in a well's future. So when we drill these wells, we drill them knowing we're going to polymer these wells. And the more fluid they make, the more water they make, sometimes the better it is. It's a little contrary to normal oilfield application.

So to date, if you look on page 12, we've drilled 20 wells; 15 producers and five dry. Most of the -- a number of the dry holes were exploratory wildcat, as we continued to try to develop additional Mississippi over there in Trego County. Of the 15 producers, only five producers actually appeared on our end-of-the-year SEC proved PUD group. So that means we drilled 10 successful wells that aren't included in our PUD inventory.

I think that's something that we have that, as an industry thing, it is kind of a little bit abstract; that we have a number of these locations, like these polymer jobs, that typically don't hit the standards of an SEC-proved location. But still, for us, we're doing pretty well with those things. And we're going to continue to drill those. Because our success rate is in the high-60%s, low-70%s. And when you include in the polymer follow-on, we get a pretty good payback. Actually, what we're seeing in this term now is, those wells that we drill fully with the intent of knowing they're going to be polymer candidates, actually have a shorter-term payback than the conventional wells. So we're pretty happy with that.

And then, one of our big areas there where we still have a good lease position, and that we still -- we've been kind of focused in on this. We wanted to have some opportunity here in 2012 to be very active in drilling, and then follow that up with an active polymer time with Webster. And those are the results you see of the -- pages 10 and 11 before, in those charts.

So we still have a few more polymers we're in the process of doing. But, as everybody knows, especially if you live in the Midwest, the weather has been really pretty awesome this year, as far as drought and dry and hot conditions. And Kansas is right in the middle of that. And we've run into an issue with getting water; both water for drilling fluids, and water for polymer jobs, and access to water, and things like that. Some of our larger companies who are drilling horizontal Mississippi wells in the south are even hauling water in from out of state. And their costs are just going through the roof.

So that's been an issue for us lately. It has kind of slowed us down, both in the -- thinking about what's coming next. But water issues are becoming a big question for us. Typically, we access water from the local farms in the leases that we work; either from their individual water supply at the farmer's house, or from a local pond or something like that. But, now, they have to reserve those water supplies for their standard work.

I'll talk a little bit about MMC. We started it up on the electric side early in the year, January 25. And during that time, it's had some ups and downs. It's had strategic downs for both maintenance and to add on to the functionality of the electrical generation. And during that time, basically through July, it has generated a little less than $500,000, about 2.4 million kilowatts through July. We've had it down here for a period of time. We did the maintenance of changing out the filter beds and things like that, as well. But it's back up and running today.

And we are really kind of excited about the future of MMC, and keeping it up and going. The whole function of MMC, really, the whole critical thing of that, is uptime. We think the combination of these two, both the gas sales and the electric sales, gives us the best opportunity to continue to increase the uptime, as we go forward.

And that's really all I have at this time. So, Rachel, if you want to poll for questions?

Okay, absolutely. (Operator Instructions). Okay, as of right now you have no questions via the phone.

I just have one question on the Internet. It's kind of a -- it's a little bit of an investment question, but I'm going to change it into -- put just my own answer here. But, basically, if you look at Tengasco over the long haul, one of the questions is about stock performance. I think, it depends on when you take the snapshot at any time on any given stock, especially in the microcap universe of oil and gas companies.

I think if you graph 10 or 12 companies about our size; get five or six larger; five or six smaller; or all 10 larger. And you graph those companies and you look back over a two- three- four- and five-year period of time, what you are going to realize -- and I brought this up during the shareholder meeting in June -- is that Tengasco, pretty consistently, manages stock-based price appreciation that's right in the mix of the top part of that.

There are always a few outliers. There's some underperformers. There's some guys that spike out and leave the universe. Maybe they have a big discovery in the Bakken, over whatever they have. There are a few of those. But in general, as our whole group performance is rated, we are right in the thick of being very much near the top of that. So I think that's basically how I'm going to ask the question, the one Internet question I have. Anything else, Rachel?

You have one question in the queue. Mark Kunewizca -- who is a shareholder -- please state your question.

Yes, I've noticed that the production numbers have been up and to the right on a graph, which is a good thing. I'd like to know what the sustainability you think we will have, in this third quarter, of maintaining that 1000 barrels a day production number?

Yes, there's obviously -- if you look at those graphs on page 10 and 11, you can see there's a spiky nature to the polymer. But there it is a gain going forward. And I probably should have put one up there that was a little bit of an older well that had some run out. I kind of focused on the newer drilled wells. But there will be a gain, going forward, on all of these wells. And it's a cumulative effect. It's adding each one of them to the whole mix. So you take a three- or four- or five-barrel-a-day well, and over a long period of time, you turn it into an eight- or 10-barrel-a-day well, that's a marginal step overall. But it's the cumulative one of adding 20 or 30 of these every year and moving the Company along.

And remember, although we've used some financing to get -- especially the investment and inventory, and the pace at which we drilled early this year, we used some financing. But for the most part, we've done a lot of that just purely off cash flow. So it's kind of a mix there. I don't know if that really answers your question. We won't be able to maintain that without a continued capital investment, but not at a 1000 a day. And there is a spikiness to that. But we still haven't (multiple speakers). Go ahead, Mark.

Okay, what is your best guess as to the number of new wells to be drilled in the second half?

Well, we're still -- we've run into all these issues, both in with the question of being able to get water access, these issues coming up. And another thing that we've noted is in -- just in the last three weeks, we've seen oil prices come back. If we look back at our July production, and our average Kansas price was only about $81. Now, it sounds like a good number. And if we were certain that was our price going forward, we could customize all of our cash flow expectations, and everything on that.

But what we've seen over the longer lookout is NYMEX, and the futures for NYMEX, have been coming down. And even since the shareholder meeting in June, even though the prices were lower on the daily price in June than they are today, the NYMEX future numbers for oil are a lot lower. So I'm really reserved to exactly tell you what's going to -- the future is going to hold. Because all these things are new things that we haven't dealt with before -- the politics of the oil price, let's call it; the fact that we're even having trouble sourcing water to begin drilling; all these sort of issues are coming up for us in Kansas. And we have a new set of challenges that we haven't dealt with before. So I think -- let's just see where we get to. We will keep you informed on a quarterly basis, as we have, going forward.

Okay, thank you.

And that was your last question in the queue.

All right. Well, with no further questions, Rachel, I think I'd like to take this time to thank everybody who joined in for our conference call. And we'll be talking to you soon. Thank you.

Thanks to all.

Thank you. This concludes today's teleconference. We thank you for your participation. You may disconnect your lines at this time, and have a great evening.