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Tengasco, Inc. (NYSEMKT:TGC)

Q3 2012 Earnings Call

November 14, 2012 4:15 pm ET

Executives

Cary V. SorensenVice President, General Counsel, Secretary

Michael J. RugenChief Financial Officer

Operator

Cary Sorensen, the floor is yours.

Cary V. Sorensen

Good afternoon ladies and gentlemen, please accept our welcome to the Third Quarter Conference Call Results for Tengasco. We’ll be doing something a little different this conference call. At the end of the call, we will be taking questions via the internet, you can go to our website, and there is a link pretty clear on the first page and you can follow that to submit questions in writing, and we’ll take those and Mr. Bailey will answer those at the end of the presentation.

I will make my customary short remarks about forward-looking statements. This presentation may contain forward-looking statements addressing future events or possibilities. And as we’ve said out in the Q and in the 10-K and in the first slide or two of this presentation, there is no guarantee that future results will match those forward-looking statements and we just note that we are not in the business of predicting the future, so those may turn out differentially than any such statements that occur in this presentation.

With that, I am going to introduce Mike Rugen, our CFO to make a financial presentation summary of the third quarter.

Michael J. Rugen

Thanks, Cary. For those of you that are following along with the slides that were included in the presentation on our website. All references to those slides as I discuss the results. For those of you following if you will just turn to slide 3, that slide is about the quarterly financial summary.

As you can see our net income for the quarter was $1.2 million, or $0.2 a share, it was actually the same in each of the quarters. The third quarter ending in 2012 and the third quarter ending in 2011 both were $1.2 million and $0.02 a share.

Revenue increased $1.4 million, or 33% from $4.4 million in the third quarter of 2011 to $5.8 million in the third quarter of 2012. $1.1 million of this increase was due to a 13,000 barrel increase in our net oil sales volumes in Kansas, and that was a result of the drilling and polymer program that we had conducted at the end of 2011, as well as all through 2012.

200,000 of this increase was actually due to a $2.81 increase in the average Kansas oil price from $82.49 in 2011 to $85.30 in 2012. Production cost and taxes increased 300,000 or 19% from $1.5 million in 2011 to $1.8 million in 2012. This increase was actually due to a franchise tax refund that we received in the third quarter of 2011, it was $240,000 and it was booked at that time. I think if you remember, we actually talked about that in the previous calls that we had during that period.

DD&A expense increased $300,000 or 42% from $700,000 in 2011 to $1 million in 2012. Approximately $170,000 of this increase was related to the sales volume increase that I spoke about earlier. The remaining amount really relates to the increase in the oil and gas depletion rate.

General and administrative expense increased $400,000 from about $500,000 in 2011 to $900,000 in 2012. Approximately, $240,000 of this related to recording an allowance in the third quarter of 2012. For the receivable that offsets the Hoactzin-related payables. There had been no reduction in these payables since early to mid second quarter of this year. Therefore the Company felt it was appropriate to establish allowance at this time.

The remainder of this increase related to higher accounting, consulting and legal expenses. Interest expense increased $30,000 or 18% from $160,000 in 2011 to $290,000 in 2012. This increase was due to higher average bank borrowings in 2012 and the increase in the bank borrowings was related to additional cash used to supplement our cash flow in order to conduct our drilling and polymer programs.

Gain and loss on directives decreased $455,000 from a $420,000 gain in 2011 to a $35,000 loss in 2012. The $35,000 loss in 2012 related to the change in the fair value of the derivatives. In 2011 they actually had a $540,000 gain related to the change in fair value. But that was partially offset by $120,000 of settlement payments that we made to Macquarie.

If you move over to slide number four, it discusses the nine month financial summary. Net income increased $660,000 or 26% from $2.5 million or $0.04 a share in the first nine months of 2011 to $3.2 million or $0.05 a share in the first nine months of 2012.

Revenue increased $3.2 million or 25% from $12.8 million in 2011 to $16 million in 2012; $2.7 million of this increase was due to a 31,000 barrel increase on net oil sales volumes in Kansas. Those volumes went from 139,000 in 2011 to 170,000 in 2012. Once again this increase was a result of the drilling and polymer programs that we conducted in late 2011 and all throughout 2012. The increases in the volumes were primarily related to the Coddington, Hilgers "B", Liebenau, McElhaney "A", Veverka "A", Zerger "A" leases.

In addition $350,000 of the revenue increase related to an increase in revenues at MMC from $180,000 in 2011 to $530,000 in 2012. Of this methane sales increased all of it related to electric sales. If you remember we put the generator in place at the beginning of this year, so we had no eclectic sales last year and we realize electric sales throughout the year.

Reduction costs in taxes increased $860,000 or 18% from $4.7 million in 2011, to $5.6 million in 2012. As we discussed earlier $240,000 of this increase related to the franchise tax refund received and recorded in the third quarter of 2011. $190,000 of this increase related to change in crude oil inventory for the year, 150,000 of this increase related to increase in landfill expenses, and the remainder of the increase is related to increases in miscellaneous field cost in Kansas.

DD&A expense increased $700,000 or 37% from $1.9 million in 2011, $2.6 million in 2010. Approximately $400,000 of this increase related to the increase in sales volumes with the remainder due to an increase in the oil and gas depletion rates.

General and administrative expense increased $500,000 or 29% from $1.7 million in 2011 to $2.2 million in 2012. As discussed earlier, approximately 240,000 of this related to recording the allowance in the third quarter for the receivables that offset the Hoactzin-related payables. Remainder of this increase related to higher accounting, consulting and legal expense.

Interest expense increased $114,000 or 24% from $471,000 in $2011 to $585,000 in 2012. Once again this increase was due to higher average bank borrowings in 2012 and once again the increase was due to using those funds to supplement our cash flows to conduct our drilling and polymer programs.

Gain, loss on derivatives decreased $254,000 and $114,000 gain in 2011 and $240,000 loss in 2012. The $140,000 loss in 2012 related to the change in the fair value of the derivatives. In 2011 there was a $976,000 gain related to the change in the fair value of the derivatives, that change in fair value remembers the non-cash items. This was partially offset by a $862,000 of settlement payments that we made to Macquarie.

If you look on slide 5, it’s just a quarterly revenue summary, once again it gives you a breakdown of the revenue, the different components between Kansas, Swan Creek methane sales. As you can see, in 2012 as was in the case of 2011, Kansas oil revenues for the quarter made up approximately 95% of the Company's total revenues.

Couple other things to point out though is, you can see that Kansas oil sales revenues actually doubled from $61,000 in 2011 – I am sorry, Swan Creek and $223,000 in 2012. The methane plant sales increased 55% from $90,000 in 2011, $245,000 in 2012. Once again this increase was due to the electricity revenues.

If you move to slide 6, the nine months revenue summary, on a year-to-date basis, Kansas oil revenues to be up approximately 94% of that Company's total revenues in 2012. That was down slightly from the 96% it made up in 2011. This change in revenue that make up really related to the increases in the methane plant sales more than anything else. 2012 the methane plant sales made up 3.3% of total revenues as compared to 1.4% of total revenues in 2011. Once again as we discussed earlier this increase really related to the electricity revenues recorded in 2012.

If you move to slide seven, which kind of talks about carrying cost and capital spending. The oil and gas properties the net book value at September 30, 2012 was approximately $25.3 million from a ceiling test review standpoint, we still have a significant cushion between the proved reserves discounted 10% as compared to the carrying cost of the oil and gas properties. Remember at the end of last year our proved reserves discounted 10% before taxes was approximately $69.8 million compared that to the current carrying cost of $25.3 million and you can see we still have a pretty significant cushion.

Capital spending on oil and gas properties for the first nine months of 2012 was approximately $7.2 million most of that spending actually occurred in the first half of the year. We spent $5.7 million on drilling. We didn’t do any drilling in the third quarter of this year. We spent $1.1 million on polymers, $300,000 of this $1.1 million was actually spent in the third quarter and those funds were primarily spent on polymers related to the Harrison A11 and the Veverka A4 polymers. We spent about $400,000 on recompletions and leasehold, 200,000 of this was actually spent in the third quarter to acquire additional acreage in Trego County.

Pipeline had a book value of $6.7 million at September 30 of this year. We spent no capital during the year on the pipeline. The methane facility have a book value of $4.5 million at September 30. We spent about $400,000 of capital this year primarily related to finishing the installation of the electric generator, most of those costs were actually incurred in the first and second quarter. In addition as we discussed last call, we received in June of $1 million section 1603 payment and that reduced our book value by $1 million.

Other PP&E we had approximately $400,000 net book value, this year we just spent a small amount of capital really to replace some of the field vehicles. All of this capital spending was either financed through cash flows or we supplemented with some additional bank borrowings.

Just one more thing I wanted to kind of highlight, as we talked about we really had little capital spending during the third quarter. This actually resulted in a fairly significant decrease in our bank borrowings. At June 30 our bank borrowings were approximately $13.9 million. At September 30 that borrowing level actually decreased $2.5 million down to 11.4% once again this was a result of less capital spending that we’ve had in the previous quarters.

With that let me turn the presentation over to Jeff to take it from there.

Jeffrey R. Bailey

I’m going to pick this up on Page 8 where we can look at the annualized oil production. I have 2012 summed in a gross basis; all these are gross oil production for the company through October 2012.

So you can see through 2012, 10 months, we are only 5,000 barrels behind the total production from last year. So assume by this date November as we speak, we are now at all time company record and of course we’ll have the rest of this month and December to go. So we fully expect to set production record for 2012, most of that has been on the back of the additional 7.2 million in capital that was – and a portion of that 5.7 million that was related to drilling especially in Kansas.

If you look at the next slide, Slide 9, altogether we drilled 20 wells to-date, 15 producers, five of those were dry hole, of the original proven reserve only five of those 15 producers were SEC PUD group, producer are already proven. So we are moving wells up out of categories such as probable and possible that don’t appear in the SEC results.

Our focus area of West area continues to be our focus. Next slide coming up after this one will tell you some more about that. That’s where we drill and we produce for a while, we kind of give a performance indicator of which wells are going to be the best polymer candidate, we come back in polymer now and producing more. We have a number of ongoing interest and then continuing to drill in the West area sometime in the future.

We have been doing both evaluation and performance of polymers. Although we only did two in the third quarter, we just finished up one in the last week or so, here in the fourth quarter. So we’ve only done three over this period of time. So for us the third quarter was a quarter of reduced activity compared to how busy we were in the first half of the year.

The third quarter we saw with no drilling only two polymers and only so far in the fourth quarter. So we would temper – and we’ve mentioned this in the last quarterly conference call, we tempered the rate which we were being busy by a couple of different issues.

If you go onto the next slide that will show you basically, here is about 12 wells of the 15 that we drilled that fit nicely on the page. Basically it’s the monthly production from each of the newly drilled wells. The little orange blocks on there indicate months in which those leases after having been drilled were later polymer and you can see the polymer are very – some of them are two months later, three months later, five months later and even six months later.

And then Veverka C #6 is the well that we just finished putting the polymer in place this week. So this kind of gives you an indication of the cumulative effect of drilling and production in some of these wells.

One of the interesting things here is to look at the cumulative total, the right most column, in each of these individual well categories and I will tell you basically what the production total for that period of time whether the well was drilled in March, April, May, June, how that is done. And basically a good measure of – and if you think $80 oil and 4,000 barrels of production and roughly in a gross basis we need a little bit more than that, so we need about 4,500 barrels of oil production and $80 oil, it’s pretty much a breakeven case for the drilling cost.

So if you look at that, out of those 12 producing wells that are on that list, we have four or five of them that are already at or very near that 4,500 barrel limit. But even some of the lower ones, even those guys down in the 400 and 500 barrel range that they’ve only had a few months production.

When you look at that over a period of time and graph data of the decline versus these were probably at the peak, right initially either after a polymer or after production it’s been established and it’s going down after that. Kansas is still one of those very favorable places to drill on a dollar for dollar basis. You’ll hear lots of stuff about all the activity in the U.S., our oil production is going up. We’re going to take over again number one producing spot of countries in the world. The U.S. is going to be once again the largest producer.

But on a dollar for dollar, Kansas is really one of the very best areas that achieve an actual net return for the base of your money. Even though you’ll hear a lot more about these other areas, lot of infrastructure, having a much longer timeframe in some of this. So that’s kind of one issue I want to bring up related to those Kansas drilling activities.

If you go on to page 11, we still have an ongoing good inventory of wells to drill in the future, both proven wells and then what we will call the geologic interesting wells, they’re still out there and a problem loan possible, which will continue to make up a good deal of our drilling inventory in those for which we hope to have the same kind of continued success we’ve had in the past.

One thing in our industry, while the rest of the world might be suffered with the challenging economy, we’re challenged more of the customer different thing and one is that it’s very challenging in this industry to keep people. You know some here we’ve also had our own losses, basically we lost our geologic staff, basically they were taken out by competitors. So, there is another issue that paces us, so as we would cover that extensively in the 10-K.

One other things for a company that this model is hard for us sometimes to remain competitive in the marketplace where the industry has its demand for the caliber or the kind of people, especially long lined to geologist, petroleum engineers and such.

The oil price forecast is sometime one other things we’re going to kind of keep an eye on. As we look back and when we slowdown at the end of the second quarter, one other things we thought is we have several things working against us, going forward that kind of way that we were the best we can looking into future, one it was a weak economy that is going to affect demand, an unknown political outcome, which even though any outcome now may not be any better.

So most of these things are going to weigh heavily on the future oil price, oil price matters to us because as you see from our financials, we primarily operate this company and the boards direction has been to operator this company primarily on cash flow. Then we have it gone out and leverage the company. We haven’t done much of a actual borrowing. We haven’t used equity in order to finance our programs. We’ve done all those things through cash flow and targeted limited bank borrowing.

Sometimes we support that with and without hedges. Obviously the floor hedge at $65 a barrels is kind of the worst case scenario. It was a relatively inexpensive to give that considering that the cost and sometimes borrowing things like collars and stuff like that.

I know I have a question up coming about hedge. And I’ll just answer that, by saying we have not made any determination at this time about whether we would hedge it in the future or not. We usually have a Board meeting later in the year and this current hedge expired at the end of the year, that will be something that we’ll talk about at the Board level and decide if it makes sense and our current conditions or for things like that.

So if you kind of look at the board level and beside if it makes sense in our current conditions or things like that.

So if you kind of look at where we got through the first half of the year, we had very good success while we were a busy we had a little bit higher price, we’ve seen almost of $30 slide in the price of oil from the highest parts in the first half of the year. We saw Kansas encounter and still suffering from really what basically turned western Kansas in the desert. They are still suffering from almost drought like conditions and all the cost associated with the water usage and the polymer usage and other companies that are moving in the Kansas and taking other water resources that all of those things have gotten more expensive and more expensive.

So, that all came into play, all of these factors came into play, a reduction in our staff, this week all forecasts prices we saw, the difficult in getting all the resources we need to continue drilling. But even with all that, even with baring all the burden that looking ahead, I think the company is still poised to be pretty solid and sound and we are at risk at this moment time, unless we see a really major, major change in the overall whole economy and the drop in the price of oil.

So if you go on to Phase 12 a little bit about MMC, that come through in much better for MMC on a year-over-year basis. This again runs a little bit longer than the economic results through the third quarter, (inaudible) in through September. So and this is really growth basis, so that give us a little bit, with a little different inventory growth and what Mike showed as net. So I have just down as growth. But we run both gas and the electric went up off and on and most of the time both of them and sometimes just gas, but most of the time electric, but we’ve done pretty good 30,000 MMBtu's through September and about 3.3 million kilowatt hours through September, and as about 640,000 barrels, so we can go back to the net number in the previous slide.

And basically at that point in time you will give me just a minute to check and see if I got other questions in. All right, I’ve got four questions, the first one kind of covered I’m able to get at one end is basically about hedging. And as I said, we really at this time have many, sort of direction of the board as to whether we would do pretty kind of hedging in place or what we think about the situation going forward in the cost to bare. I mean hedging is one of those things, it’s much like the insurance. If you’re smart and you take that as the right place, you will look really, really smart. But if you just do it as a condition for kind of having a set performance going ahead and you need those conditions in order to achieve that, but don’t do it, that can be very bad, because you can end up paying either also the top end when price goes, having put too much money into it just to balance on forecast.

So at this point in time still we actually sit down at the board level, I don’t really have an indication yet, not really sure what I would support about hedging. I have three other questions, one is, so MMC currently seeing any renewable energy credit. And the answer to that is indirectly we are, those are preserved, we get the benefit of those renewable energy credits being embedded within the gas that we sell to the purchaser, because they retain some of those in order to, all the gas that used in order to be sold in their market for resale. That’s how we are able to get the beneficial products for gas sales that we get. Those electric – those renewable energy credits remain within that.

Also within the electric, it’s embedded also within that as part of the program that will generate about PVA/ the federal government, renewable energy credits, that’s the basis indirectly for the 1603 credit that we got. It's all the interest in this green energy think that’s currently being driven by the federal government. So gas indirectly we do, in terms of what you sometimes see these other companies like solar and wind, things like that count for renewable energy credit, as they are more embedded in a standalone feature like that. So we are getting them, but it's a little bit.

The other question I have here is, are there any share buyback plans active? My answer is no. Not active, we’ve never had to the best of my knowledge in the ten years up in here, we’ve never asked a share buyback program. Typically those are for very mature companies, who have more cash flows and capital need.

And generally if you look at us we preserve almost all of our cash flow to reinvest in additional development of other resources. So we are not really poised to have the kind of company that will do that. We will be poorly suited to serve as either a direct dividend MLP type company or as a buyback sort of opportunity. I mean, if you think about to make a significant in rose to our share buyback plan decision, we would have to borrow the money to do that, and that is really a key or a component of that. So that's not the case.

The last question looks like I'm getting in is, please explain the Hoactzin situation in more details. I guess basically one thing to note looking forward this year we are at the 14th of November, we basically got until December 18th, the agreement with Hoactzin. And since the Sandy, we are making arrangements on our end to disconnect our involvement and all of these things are kind of coming up. Although they create something that we need to account for, we don't really consider that to be any material impairment or involvement to the company and what’s all that stuff is concluded, it is all going to be wrapped up.

And just one other thing, I kind of see and I have heard some things about this. This is in no way related to the original Hoactzin drilling program. Those two things don't go together. Think of them as completely separate events. So the drilling program it’s not related to the management issues in the Gulf.

It looks like we're roughly based on today's current prices, if everything stays the same. Right now we're getting a 25% interest in the drilling program and as the part of Hoactzin that will revert to an 85% interest sometime next year, late third quarter something like that, all are subject to price. Roughly the whole operation there is producing somewhere in the neighborhood of about 20 to 25 barrels a day. Forward growth, 20 to 25 net to Hoactzin’s interest and that eventually will become – 85% of that will become our interest.

So that’s basically where that program sits. Let me see, if I've got any other questions. I don't think so.

All right, with that I guess I’ll just end this conference call by saying, I appreciate the interest shareholders have in the Company. On a go forward basis, I think you're seeing from our performance that basically we’ve done really well during this period of time and third quarter despite a drop in activity, we been able to maintain certainly a pretty good level of production and we look forward to talking to you, we’ll try to have another conference call here prior to the 10K sometime after the first of the year to sort of bring you up to date, but next communication will be with the 10K that will be coming out in the March. So, well the actual 10-K will be out in April.

Cary V. Sorensen

All right. Thank you very much.

Operator

Thank you. So this concludes today’s webinar. We thank you for your participation, and you may now disconnect your lines and have a great day.

Question-and-Answer Session

[No Q&A session for this event]

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