Good afternoon ladies and gentlemen and welcome to the Tengasco quarter results conference call. (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 are an attendee from previous month’s conference calls, you’ll know the drill. We will 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 will entertain questions.
But as always, I'll start with a reference to the second page of the materials, on the website, the forward-looking statements. I'll not burden you with reading all of that, but I'll 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 29th are incorporated in that as well and have 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'll 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. For that first page that you come to you can click on that and move in to that slide show and you can follow along and we will keep you up to date with the pages that we are on.
So I think overall you saw from the press release, we had a pretty good quarter and so we will talk in detail about some of the events, we will talk about our drilling that we have, we will talk about our recent polymer jobs and we will talk about those issues and we will go forward.
But first I want to walk you through the financials and I am going to let my Mike Rugen do that, so Mike go ahead.
Thanks Jeff. For those following along on the PDF presentation I am going to start on slide three and I will try to keep you posted on which slide that I am going through.
Slide three is the overview of the quarterly financials. As you could see that net income increased a $110,000 or 11% from $977,000 or $0.02 a share in the second quarter of 2011 to a 1,087,000 or $0.02 a share in the second quarter of 2012. This was made up of several different factors and I will 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 in polymer programs that we have been conducting not only this year, but the second half of last year. $138,000 of the increase was related to increase in our MMC revenues. We had $62000 in revenues in the second quarter of 2011. It actually was $200,000 in the second quarter of 2012.
A $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 average $95.46 in the second quarter of 2011. We only averaged $85.90 in the second quarter of 2012.
Production cost and taxes increased in $328,000or 20% from the $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,o00 of the increase related to increase in landfill expenses and finally the remainder related to miscellaneous increases in expenses in our fuel 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 increase in volumes that we discussed previously. The other half of the increase related to higher DD&A rates we experienced in that quarter.
General and administrative expenses decreased to $119,000 or 17% from $719,000 in 2011 to $600,000 in 2012. That decrease was primarily related to timing. 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 pretax income times the effective tax rate. 2012 it also included $192,000 which was the tax effect of the million dollar Section 1603 payment. If you will recall this payment we received in June and is pretty well described in an 8-K that we filed on June 29th. We also described it a little more fully in the 10-Q itself. If you will go to slide number four for those that are following along.
We'll talk about the year-to-date financial results. Net income increased $629,000 during the first six months of 2012 over the level of first six months of 2011, which was a $1.331 million year-to-date in 2012, was $1.960 million or $0.03 per share.
The revenue increased $1.749 million or $0.21 or 21% from a $1.8447 million in 2011 to $10.2 million in 2012. A $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 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 a $100,000 related to a $1 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, a $100,000 related to increase in landfill expenses and the remainder related to miscellaneous increases and fuel costs in Kansas.
DD&A expense increased $420,000 or 34% from a $1.237 million in 2011 to a $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 the 2012. G&A costs increased $117,000 or 9% from the $1.242 million in 2011 to a $1.359 in 2012; this increase was primarily related to timing.
Interest expense increased to $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 to a $105,000 in 2012.
Once again, the derivative gained loss in 2012 was related to the change in the fair value of the derivatives, in 2011 we had actually made $745,000 of settlement payments to Maguire and those settlement payments were partially offset by a $439,000 unrealized gains which was related to the change in the fair value of other derivates.
Income tax expense was primarily the pre-tax income times the effective tax rate once again also included a $192,000 tax effect of the $1 million Section 1603 payment. If you go to slide five, you talk a little bit more about the revenue changes as we mentioned earlier in the total revenue increase $445,000 in the second quarter of 2012 compared to the second quarter of 2011.
The increase primarily related to Kansas and as you can see Kansas still makes up the majority of our revenues and the percentages are going down a little bit. This quarter actually made up 94.2% of the companies revenues as compared to 96% of the companies revenue in 2011 Swan Creek made up 1.6% of the companies revenues in 2012 compared to 2.4% in 2011 and the methane plant sales actually jumped up to 3.8% of the companies revenues in 2012 compared to 1.3 in 2011 once again as we talk about the four of that increase in the gas plant sales a $114 related to electricity sales, all of the sales in 2011 from methane facility related gas.
We move on slide number six, the six month revenues once again as we mentioned earlier the total revenues increased a $1,749,000 or 21% in the first six months of 2012 as compared to the first six months of 2011. And once again the increase was primarily related to increased revenues in Kansas, but also the $300,000 increase in MMC revenues.
And 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 of first six months of 2012 compared to 1.1% in 2011.
If you move on to slide number seven, this just kind of gives you 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 are carrying values of $25.5 million, that’s the net book value at June 30th. Just to kind of 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 (inaudible) discounted 10% proved reserves are.
We spend $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 re-completions we did as well as some leasehold.
Pipeline book value was $6.8 million at June 30th, which spend no additional capital on the pipeline in 2012.
At methane facility, the carrying value or book value at June 30th was $4.5 million. You noticed that that actually decreased over what it was at year-end and we spend $400,000 approximately in capital that was finished for the most part installation of the electric generator, but that was offset, fully offset by the $1 million that we got on the Section 16 of repayment. 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 at the properties. So there is a deferred tax impact on that transaction.
Other PP&E, we had about $0.5 million on the books at June 30th, with a small amount of capital that we spent to replace some of the field vehicles. The capital was basically financed through primaries of cash flows, but we also supplemented because those cash flows with additional bank borrowings.
Couple other items I just want to highlight. We talked about this last quarter, but you will notice that the inventory levels are about $0.5 million higher than they were at year-end. They were about $800,000; now they’re about a $1.3 million. If you recall, we spent about $2 million buying casing, tubing, pumping units earlier in the first quarter and about $0.5 million 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 at the end of the year last year to $13.9 million this year; if you 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 am going to turn it back over to Jeff.
Okay, I am going to pick this up on slide eight. 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 eight, we have our annualized production, of course 2012 is through July and so basically as we look back in this on a historic basis, we see the upper trend from ‘05 through 2011 and if we kind of do the math going forward on 2012, you will see we are off to a very good settlement start in 2012, so we can project that up that we are going to finish significantly better than 2011 of total production there. So this is all gross number here, that’s generally quite end-up doing well as we go forward.
Okay, look on page nine, once again this is Kansas only, this is Kansas’ average 2012 production at the beginning of the year, so we can see also here a steady march up January, February going up, we finally get over 700 barrels a day. We are actually are maintaining it through the mid-months there. We set a record in June; we broke the previous November 2008 record which was 800 and something barrels of production by going over 900 for the first time in company history in June; didn’t last long, we broke that record again in July, we ended up with 974 barrels of oil per day, as the company production in Kansas gained that growth. So we can say that the benefits of being very active early in the year and then focusing late on polymer jobs in the last few months in the years had an impact on our production and also pretty quickly.
And if you look at page 10, what actually have here is some actual polymer example results, some of these wells were drilled at the end of ’11, some of them were early in 2012, but there are six polymer jobs listed at the top and corresponding graphs underneath and so lets just look at a few of these. Basically, take a well like Coddington number 6, I called that, lets call it as January through May production there is roughly around about 10 barrels a day, about 300 barrels a month give or take, so we’re between 317 to 280.
So during that period time the wells making about 10 barrels a day, that’s not bad in Kansas, well remember that Kansas average well like it’s to 2.5 barrels a day and this is state-wide for oil companies. So 10 barrel a day well is typically a very good Kansas well. These are the kind of targets of standard drilling and things like that.
However, in our area like Coddington and Marcotte fields, we know that’s going to be feature polymer candidate. Polymer, basically done sometime in late May, early June, the well was brought back up in June and you see that production spike up from 280 barrels in May to 800 in June; some of that’s I might tell you remember June was a bit of short month, there has been a period of time were June was down while the power moves being done; that’s about a two week process.
So there have 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. So 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 on to the next one there and the graph is right below that on page 10 for the Hilgers B6. 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 half a barrel of oil a day. In fact this well was making 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 in March and you see the spike up in oil production. We basically take it from 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 still averaging over 20 a day in May, down now it looks like about 15 a day in June and then down 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've had a really good chance for success.
If we move on down the list, the story kind of goes on, the Veverka A3 again a well making basically one barrel a day through the first four months of the year. Polymer sometimes very late May, only brought back for a few days in late May, but had a full month of June to 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 queued 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 kind of 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 a 100. We didn't really met that in the first half of this year but you know, 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 thought that’s the payback moment.
Story is kind of similar for the other two vertical wells there. And I like the, Zerger A. The Zerger A is a well we drilled early this year. We brought the well in 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. We don’t mind that at all. Well came back making 314 barrels of oil a day, so 314 barrels for the month. So we’re actually pretty happy with that, in terms of at least made some oil.
Then in June, basically part of the reason, that number was down as once again we’re down two weeks while we performed the polymer. We brought this well right up on, right at the first of July. So this basically began July 01 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 a graph of the Zerger A. That’s perhaps one of the best polymer jobs we have had in the company history in terms total spike up and even through this day I know that this morning’s report the well is making 99 barrels of oil per day, so for some period of time there in July it was averaging over a 130 barrels of oil a day.
So those are typically the kind of enhancement we have in a polymer jobs so what happens is when we drill those wells and remember all these are relatively new drilled wells these aren't the old polymer wells that we have gone back in and feel while these are old filed locations but this aren’t old wells these are wells, we have redrilled in those areas and use of the polymer and as I planned event this is going to happen in some time in a wells future, so we drill these wells. We drill them knowing we are 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 oil field application.
So to-date, if you look on page 12, we have drilled 20 wells, 15 producers and five dry, most of the number of the dry holes were exploratory rock as continue to drive to develop additional Mississippi over there in (inaudible).
For those of the 15 producers only five producers actually appeared on our end of the year SEC proved group so that meant we drilled 10 successful wells that are included in our inventory and I think that’s something that we have that as an industry thing it’s kind of 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 locations but still for us we are doing pretty well those things and we are going to continue to drill those because our success rate in the high 60s low 70% and when you included in the polymer follow on we get a pretty good payback actually what we are seeing in these terms now is those who actually grow fully within 10 of knowing they are going to be polymer candidates, actually have a shorter term payback than the conventional wells.
So we are pretty happy with that and then one of bigger is actually show lease position in there, we still we been kind of focused on this, we wanted to have some opportunity here in 2012 to be very active and drilling and then follow that up with an active polymer [time] with Webster and those as a results you see of the pages 10 and 11 before in those charts.
So we still have a more polymers and we are in the process of [billing] but as everybody knows the 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 middle of that and we run into an issue with getting water, both water for drilling fluids and water for polymer jobs and access to water and things like. Some of our larger companies who were drilling horizontal Mississippi wells on the South or even (inaudible) water in from out of state and their cost is still went through the roof, so that’s been an issue for us lately, its kind of slowed us down both in thinking what coming next, but water issues are becoming a big question for us.
Typically we access water from local farms and lakes that we work. Even from there individual water supply at the farmer's house or from a local pond or something like that but they have to reserve those water supplies for their standard work.
Talk a little bit MMC, we have started it up on the electric side earlier in the year, January 25, I enter in that time, it had some ups and downs, its had strategic downs for both maintenance and to add on to the functionality of the electrical generation and during that time basically through July its generated a little less than $0.5 million, about 2.4 million kilowatts through July. We've headed down to you here for a period of time. We did the maintenance of changing out that filter [beds] and things like that as well, but its back up and running today and we are really kind of excited about the future of MMC and you know keeping it up going and as a whole function of MMC really, the whole critical thing is there as up time.
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.
(Operator Instructions) Okay as of right now you have no questions via the phone.
I just have one question on an internet, it's kind of a little bit of an investment question but I'm going to change it into my own answer here, but basically if you look at Tengasco over the long haul, one of the questions to us is about stock performance. I think it depends on when you take the snapshot at any time on any given stock especially in the micro cap universe of oil & gas companies.
I think if you grab 10 or 12 companies about our size, get five or larger, five or six smaller, all 10 larger and you grab those companies and you look back over two, three, four and five year period in time. What you’re going to realize and their [profits] out there in shareholder meeting in June is that Tengasco, pretty consistently manages a stock-based price appreciation that’s right in the mix of the top part of that.
There are always a few outliers, some are underperformers, there some guys spike out and leave the universe, maybe they have a big discovery in the Bakken or whatever they have, there are a few of those. But in general, as our whole group performance iterated, we’re at the thick of being very much near the top of that. So I think that’s basically how I am going to ask questions, the one internet question I have.
Anything else Rachel?
You have one question in the queue, [Mark Konowiska], who is a Shareholder. Please state your question.
I noticed that the production numbers have been up on to the right on a graph, which is a good thing. I would like to know what the sustainability you think we’ll have in the third quarter of maintaining a 1,000 barrels a day production number?
Yeah, there is obviously, if you look at those graphs on page 10 and 11, you can see there is a spiky nature to the polymer, but there is a gain going forward and I promise you that for one-up there that was a little bit of an older well that had some run out kind of focused on the newer grilled wells. But there will be a gain going forward on all of these wells and it’s a cumulative effect. You know, its adding each one of them to the whole mix.
So you take a three, four, or five barrel a day well and over a long period of time, we turn it into an eight or 10 barrel a day, that’s marginal step overall, but it’s a cumulative one of adding 20 or 30 at least every year and moving the company along.
And remember although we use some financing to get especially the investment in the inventory and the pace at which we drilled earlier this year we used some financing, but for the most part, we have done a lot of that just purely of cash flow.
So it’s kind of mix there though not that really answers your question, we won’t be able to maintain that without a continued capital investment, but not at a 1,000 day, because there is spikiness to that, but we still haven’t, go ahead Mark.
Okay. What is your best guess as to number of new wells to be drilled in the second half?
Well still, you know we have run into all these issues both with the question about being able to get water access, theses issues coming up and another thing that we noted is, just in the last there weeks we have seen oil prices come back. If you look back at our July production 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 have 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 lot lower.
So I am really reserved to exactly tell you what 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 are even having troubles sourcing water to begin drilling, all these sort of issues we’re coming our course in Kansas and we have a new set of challenges that we haven’t dealt with before. So I think lets just say where we get to, we’ll keep you informed on a quarterly basis as we have going forward.
And that was your last question in the queue.
All right, well with no further questions Rachel, I think I would like to take this time to thank everybody who joined in for our conference call, you know and we’ll be talking to you soon. Thank you.
Thank you. This concludes today's teleconference. We thank you for participation. You may disconnect your lines at this time and have a great evening.
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