Riley Exploration Permian Inc (REPX) 2010 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the broadcast of 2010 year-end results conference call. All lines have been placed on a 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, Cory Sorensen. Sir, the floor is yours.

Thank you, Melinda. This is Cary Sorensen, Vice President General Counsel of Tengasco. Welcome to the conference call. I'd like to remind you again that this call is being recorded, and the audio portion of the teleconference will be available on the Company's website at Tengasco.com.

After the presentation, as Melinda just said, you will have the opportunity to ask questions either through the conference call operator or by typing them on your computer if you're participating in the conference by webcast.

Before turning the presentation over to Jeff Bailey, our CEO, and Mike Rugen, our CFO, I must proceed with a formal safe harbor statement and description of three terms you will be hearing in the presentation.

Except for the historical information contained in this call, the matters discussed in this presentation are forward-looking statements that are based upon current expectations. Important factors that could cause actual results to differ materially from those in forward-looking statements include risks inherent in drilling activities, the timing and extent of changes in commodity prices; unforeseen engineering in mechanical or technological difficulties in drilling wells; availability of drilling rigs and other services; land issues; federal and state regulatory developments; and other risks more fully described in the Company's filings with the SEC.

The SEC requires oil and gas companies in their filings with the SEC to disclose proved reserves which are those quantities of oil and gas which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions using unweighted average 12-month first day of the month prices, operating methods and government regulations, regardless of whether deterministic or [probalistic] methods are used for the estimation. We currently do not disclose probable or possible reserves in our filings with the SEC.

In this presentation, the term EUR, or estimated ultimate recovery, refers to the company's internal estimates of hydrocarbon volumes that may be potentially discovered through drilling or recovered with additional recovery techniques such as polymers. These estimates do not necessarily represent reserves as defined under SEC rules or the Society of Petroleum Engineers Petroleum Resource management system, and by their nature and accordingly, are more speculative and substantially less certain of recovery. And no discount or other adjustment is included in the presentation of such estimates.

EUR estimates and drilling locations have not been risked by company management. Drilling results and quantities that may be ultimately recovered from the company's interest could differ substantially.

Factors affecting the ultimate recovery include the success of our ongoing drilling plan, which will be directly affected by the availability of capital; drilling and production costs; commodity prices; availability of drilling services and equipment; drilling results; lease explorations; transportation constraints; regulatory approvals and other factors and actual drilling results, including geological and mechanical factors affecting recovery rates.

Estimates of EUR and other recoverable hydrocarbon potential may change significantly as development of the company's prospects provides additional data. Unless otherwise indicated, other estimates of hydrocarbon volumes contained in this presentation have been prepared internally by the company without review by independent petroleum engineers. Investors are urged to consider closely the reserves disclosures in our annual report on Form 10-K for the year ended December 31, 2010, filed earlier today.

Our core development acreage and related well locations in Kansas refer to acreage and locations where the company believes the relative geological risk for recovery have been reduced as a result of operations to date. However, even though the bulk of our proved reserves are proved producing properties, a small portion of our value has been attributed to proved undeveloped reserves, and ultimate recovery from such acreage and locations remain subject to all the normal recovery risks.

Finally, the last term I will be explaining is the term pretax PV10% value, which is the estimated present value of their future net revenues from the company's proved oil and natural gas reserves before income taxes discounted using a 10% discount rate.

Pretax PV10% value is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes as is required in computing the standardized measure discounted future net cash flows. The company believes that pretax PV10% value is an important measure that can be used to evaluate the relative significance of its oil and natural gas properties, and that pretax PV10% value is widely used by security analysts and investors when evaluating oil and natural gas companies.

Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pretax measure provides greater comparability of assets when evaluating companies.

The company believes that most other companies in the oil and natural gas industry calculate pretax PV10% value on the same basis. Pretax PV10% value is computed on the same basis as a standardized measure of discounted future net cash flows, but without deducting income taxes. The reconciliation of the company's pretax PV10% value to its standardized measure was included in the company's Form 10-K.

That concludes that portion, and I now am happy to introduce Jeff Bailey, our CEO, to continue the presentation.

Thank you, Cary.

I will briefly go over the financial reserve highlights and then I'm going to pass it on to Mike Rugen, then I will be back with the group to talk a little bit about the specifics of what we're doing right now in Kansas and what we did in 2010.

First part of 2010, we basically are reporting a net loss of $1.7 million or $0.03 a share. That is primarily related or also includes the relation of the $5 million pipeline write-down and the positive gain on the derivatives.

If you look at 2010 from the adjusted income point of view, that would be $900,000 or $0.9 million or $0.02 positive per-share earnings for the stock. So basically that is a non-cash write-down effect.

2010 total revenues of $13.2 million proved reserves at the end of that time was $2.5 million barrels of oil. That is up $28 million from the same period of time in 2009, so that gives us total PV10 value discounted 10% of $48.3 million.

Now with that said, so we can look at these financial summary in detail, I'm going to pass that on to Mike Rugen, our company CFO, for the financial summary. Mike?

Thanks, Jeff. I will go over the financial information in a little more detail. Revenues increased $3.5 million from $9.7 million in 2009 to $13.2 million in 2010. $3.3 million of this increase was related to oil price increases at approximately 30% from about $54.48 a barrel to $72.14 a barrel in 2010. There was $100,000 of this increase was related to small increase in Kansas oil sales volumes, and $100,000 of the increase was related to increased sales at our methane facility.

Production costs and taxes increased $700,000 from $5.3 million in 2009 to $6 million in 2010. Approximately $400,000 of this increase was related to well repair and maintenance costs in Kansas. There was $100,000 related to increase in Kansas property taxes and $100,000 was related to increase in landfill expenses, primarily electric costs and changing out our carbon bit there. There was a little bit of the rest that was kind of spread all over the rest of the properties.

2010 depreciation, depletion and amortization was approximately the same levels. 2010 general and administrative costs increased $200,000 from $2.1 million in 2009 to $2.3 million in 2010. This increase was primarily related to $300,000 of bonuses paid to employees in 2010, offset by $100,000 increase -- non-cash charge, excuse me -- related to stock options.

Impairment costs of $5 million were related to the write-down in the pipeline assets. 2010 interest expense was approximately the same as the 2009 levels. And 2010 gain on derivatives was approximately $0.5 million. That was made up of the $600,000 non-cash unrealized gain that Jeff mentioned previously, and it was partially offset by about $100,000 of payments made to Macquarie. Macquarie is our counterparty in the derivative agreement.

As we noted in the past, Kansas is a significant part of the company's revenues. In 2010, $12.4 million of the $13.2 million total or 94% of the total revenues, were related to Kansas. Kansas revenues increased, like I mentioned previously, primarily due to increases in prices. We had a small increase in our Swan Creek oil sales, also related to prices. And we also had approximately $100,000 increased revenues at our methane facility. And this was really due to increase in run time in 2010 over 2009 levels.

As we talked about before, Jeff had mentioned that we had a $1.7 million net loss this year. We also mentioned earlier that $600,000 of that net loss was a non-cash unrealized gain on derivatives as well as the $5 million non-cash write-down of the company's pipeline assets.

If you exclude these items and the associated tax effect, the company would have reported an adjusted net income of $0.9 million. As this is a non-GAAP measure, we have included a reconciliation of the reported net loss, the adjusted net income or adjusted net loss in the case of 2009.

Also during that year, you could see that we have also -- pay $134,000 of -- we actually incurred $134,000 of realized losses on our derivatives. Those are actually cash payments and made to Macquarie.

As you will recall, on July 28, 2009, the company entered into a two-year costless collar agreement. This agreement had a floor of $60 a barrel and a cap of $81.50 per barrel. Those were NYMEX prices.

The volumes included in this agreement were 9,500 barrels per month for the period August 2009 to December 2010; 7,375, 7375 barrels per month for the period January 11 my through July 2011. The initial volumes were approximately two-thirds of the company's production and are currently less than half.

The purpose of entering into this agreement was to help maintain and stabilize cash flow from operations at lower prices as those seen in late 2008 and early 2009 returned, while providing at least some upside if prices increased above the cap.

If lower prices did return, through this agreement, the company would be able to continue to perform polymer and other workover treatments on existing producing wells in Kansas, which would reduce the production declines.

Through 2011 production, the company has made cash payments to Macquarie, as mentioned before, who is our counterparty, of approximately $254,000. We have paid $134,000 for production months through 2010. And in January and February production 2011, we pay approximately $120,000.

The -- at 12/31/2010, the company carried an unrealized derivative liability on their books of $687,000. During 2011, this entire amount will be recognized as an unrealized gain on derivatives. However, keep in mind that this gain would be offset by any additional payments that we would be required to make to Macquarie, should the oil prices exceed the cap.

As we've written down the pipeline assets, we wanted to discuss the carrying values of each of the groups of our fixed assets. Let's first talk about the pipeline.

Prior to the write-down in 2010, the pipeline had a net book value of approximately $12 million. After the $5 million write-down, the net book value of the pipeline was $7 million. The write-down was due to the company's assessment that future cash flows generated by the pipeline assets may not be sufficient to recover the remaining book value. This was prompted by the company receiving expressions of interest from potential purchasers of the pipeline at levels that were significantly below the pre-write-down net book value of $12 million.

At December 31, 2010, the net book value of oil and gas properties was approximately $14.2 million. This compares to the 12/31/2010 proved reserve PV10 value of $48.3 million. The $14.2 million also included $3.5 million of capital spending that occurred in 2010.

This capital spending was made up of $1.9 million spent on drilling, $1.2 million spent on polymers and other capitalized costs, and about $400,000 spent on leasehold and seismic.

The other significant asset on the company's books is the methane facility, which has a book value of approximately $4.4 million at 12/31/2010. The company's assessment was that future cash flows for the methane facility was sufficient to recover the remaining book value.

Thank you for your time. Now I will turn it back over to Jeff.

Thank you, Mike. As you can see if we go back to the slide that you are currently looking at, we have two examples. Reserves on the left, annual production on the right, and basically we see sort of two slopes. We see reserves on the left building from '05 through '07, then the precipitous drop in '08. If you remember, 2008 is the year we had $140 oil in July and $35 oil in December.

Basically at that time the SEC rules mandated that pricing for reserves on December 31 dictated the calculation for volume of oil, so at $35, the volume that we had remaining because the life of the wells were cut short, fell pretty dramatically.

By 2009, they had changed the SEC rules to allow all the company -- industry companies -- to use a 12-month unweighted average, so it will take out events like 2008 going forward in the future.

And with that, basically, I think that is comparable to the previous history. you see basically making a comeback through that time on reserves. Reserves popped back up in 2007 nearly to the -- or in 2009 nearly to the '07 volumes.

And in 2010, again, we're actually exceeding the 2007 volumes just slightly, so we're back above 2.5 million barrels of oil.

If you look at the production, that is even more telltale about the health of the company. Basically again, you see it going from '05 through '08, production kind of increasing, stair-stepping a little bit, but from basically 170,000 early to 255,000 in 2008.

If you will remember in 2009, the company -- we didn't do anything. All we did was hang on. We drilled no wells. We did very few polymers. We drilled a disposal well late in the year. We were survivors for '09 waiting for things to recover.

That continued a little bit into 2010. So we got off to a slow start in 2010 for six months of the year, waiting for cash flow to rebound. We began to get more active in 2010, and you see that even during that time of -- slow time -- that our recovery built back up. And we ended up basically producing about 240,000 barrels of oil for the year this past year.

Next slide that is going to pop up here in a second is going to be about kind of how we go about what we do in both proved reserves for these PUDs, these undeveloped locations and how we target what we drill. We've had some questions earlier about how we do what we do.

So if you look at this particular slide, one of the things that we want to do is we want to limit the exposure to geologic risk in this company, and that is what we generally do because our process for drilling a well are to have cash flow in hand and take that money and basically go out and drill a well and then have the well begin production so that it adds back quickly to replace the cash flow.

So we look at this kind of in the Kansas model here, where pinks are things that are sticking up; they are very high seismic targets. Those are the things we're interested in. The greens are very low and the yellows are kind of that spot in between.

So if you look at this particular seismic target, it's got the big red arrow up at the top, that is an example of an area where our producing wells are the little black dots down along the corner of that square at the top right. And that target that we're interested in drilling in the future -- actually we've already drilled this location -- but that is an example of how -- is in an area that were called held by production; it's held by the producing wells at the bottom. But that makes it a significant interest to the company because we already have that lease. Now because of the seismic, we know we have an additional location that we can drill.

You can see the previous production was sort of surrounded by dry holes, so they did not know -- had they continued to move -- this may have been drilled many years ago. Had they continued to move to the Northeast, if you will, up to the bright pink spot, they would have had an additional location; that is what we do.

And over the last few years having drilled these, our average EUR per well is coming out about 35,000 barrels of recovery. That is our eventual recovery. That gives us about a two-year payback at current prices on about a $300,000 to $400,000 investment on the price of drilling a well.

So you can see from this PUD kind of development process and this technical application of seismic that we go through that we're getting a pretty rapid payback along with a pretty significant gain on reserves when we're booking basically 35,000 barrels for each one of these seismic-type locations that we have.

The second technique that you will hear us using a lot in Kansas and the thing that we have had very good results in is our polymer application. And it's kind of an enhanced application for older wells. This is something we do in the wells that we have producing that have had production of a lot of water and oil; some of them are 30, 40, 50 years old.

And if you look at the pictures and you look at the slide number one, you can see that water is actually -- is represented kind of in a bluish gray material. The oil is represented in black. And in that little picture of number 1, you see the water is drawn up in kind of a little hump. And that is called the cone effect; the water is coning into the well bore. And the oil is being isolated from the area of the pipe that is open through perforations that allow the oil to be produced.

So what happens to a well in number 1 is that you produce more and more water and less and less oil over a life of the well. This may occur over many years, but typically that is kind of the problem with a well.

What we've been doing -- the technique that we've been using is we moved the picture number two or the image number two in there is that in -- through those exact same holes in the pipe that we are producing through, we pump in the polymer which is basically like a plastic material that pushes the water back down out of the way and we leave a little connective surface on top so that now the flow pattern, as shown in figure 3, is now directly into the well bore.

Now you have that water area kind of stuck behind this little collection of let's call it plastic, the plastic polymer effect. And so the water doesn't flow directly into the well bore and now we tend to produce more oil.

As we look at the results that we're getting from these particular wells, we're adding about 11,000 barrels of new production to each well. Also this is in the EUR form. Typically these wells are coming on with payback time somewhere in the neighborhood of nine months to a year. So we're pretty happy with the fact that we do this technique a little differently than a lot of the other operators. And we're happy with the results that we're getting, adding an additional 11,000 barrels to the older well.

It's not actually accelerating the existing production. It's actually adding new oil, because that oil on top had stopped being produced. So it is important for us, and then going forward. And then you will see that we have plans in 2011 for quite a bit of polymer activity.

And that is what this slide represents. To date, for the first quarter here, we have drilled 12 wells. 10 of those are part of the 2011 budget. Two of them are kind of spillovers from 2010 that got delayed around the holidays for weather, so we drilled 12 wells this year. Eight of those are producers; three dry holes; one is currently drilling right now.

One of our most active drilling areas is the area of Kansas we call Webster. Webster is kind of the cycle much like the last two slides. What we like to do in Webster is drill a well. We're going to produce the well for a while. These wells come in with high water cut; they will make five, 10, 15, 20 barrels of oil maybe and 400 or 500 barrels of water. And we will produce them for a while until we get the wells in the kind of mechanical shape, in the kind of formation, cleans itself up and once we've produced them for a while, we will turn back around and polymer them and then we will produce them again. And now hopefully the oil cut goes up, we produce more oil and less water. But right now we're entering what we call polymer season.

The other thing we like to do is we kind of limit ourselves to about eight or nine months in the year, we will start back up. We started in March with the first two of these 16 polymers; we've already done, those. And, we will bring those back up and we will work to about November. We don't use polymers here at Tengasco during the wintertime.

Then the next thing is in 2011, depending on oil prices, once again, remember, we're working off of cash flow, so the future prices matter to us of how much we're going to drill. But it's looking like going forward we're at $106. I saw today, on a barrel of oil going forward, if you kind of hang onto those prices above $80 or so that we would probably be pretty active drilling. We will pick the rig back up again in probably June. And we sort of have budgeted for the out period, drill an additional 14 wells. Some of those are going to be more exploration wells, so there's going to be more risk in some of them than our standard rate that we're getting from just development wells.

And, with that, Melinda, I will turn it back over to you, I guess, if you have anything or Cary.

Any questions in?

Yes. So do we have any phone questions?

(Operator Instructions). Harold Hughes.

Yes, I wonder, are you still acquiring acreage in Kansas or maybe even looking to some other states to acquire some acreage for future drilling?

We are. We're always on the hunt, looking for additional acreage. We have done a -- we've let the oil field communities know that we're looking for additional acreage. And, yes, any state within reason. I think we kind of have two criteria.

We prefer it to be in Mid-Continent to West Texas, North Texas kind of thing. We're not particularly interested in the soft rock country of the Gulf Coast or directly going offshore ourselves in the Gulf Coast, although we do manage, as you know, some properties for Hoactzin offshore. We're not interested ourselves in going offshore.

Then again back in Tennessee, there are some -- we will look in Appalachia. Part of the trouble with Appalachia and the whole thing back here is it is predominantly natural gas. It looks like natural gas prices are trapped to a pretty low point for quite some time to come. So we're, despite our name, really an oil company, and natural gas is not totally wildly appealing.

Is the methane plant now running at full capacity?

No, it's not. Unless -- combine that. We also had an online question asking about the methane projections for 20 years. And yes, the actual revenue from that is not matching up. And there is some -- that's true.

We've had two or one real issue with a methane plant, and that is basically the infrastructure that is used by the waste facility was aging to some degree and they have been in the process of replacing all that. And as such, we have had to be shut down for the period of time that they were working on their stone gathering system.

And so from that point of view, we're dependent upon them. So we're ready. I think about -- let's see now; they've been down for two weeks. About -- we ran good for about two weeks and then they're down again another two weeks here and they found a new problem with their gathering system.

I will say this, that the company has spent, not Tengasco; Allied Waste has spent a lot of time, Republic has spend a lot of time and efforts on their facility and they have gotten in a lot better shape. And we think in the future is going to be a lot better for MMC going forward. So we're really encouraged by all that. When we get good gas and it's not sucking air straight in, the plant is running great.

Is there any chance for any horizontal drilling in the Appalachians for gas?

There is; not particularly on the leasehold that we know as Swan Creek, but we're always evaluating those opportunities as they might be in or near Tennessee and where we could pick up additional acreage or exploration acreage. We have some exploration targets that we've still, once again, at $4.00 gas, is probably not very appealing to spend multi-millions of dollars to do.

But we do have a shale project of our own. I think it is more of an assessment that would be done through vertical wells rather than horizontals at this time. And maybe if we can keep prices up, that is something that we might like to try to do also sometime this year. But once again, prices have to remain up.

Thank you.

(Operator Instructions).

I will go ahead and take a few Internet questions here that I have typed in while we're waiting. So if you get somebody, just tell them to be patient.

I have one here that asked about -- could you please explain our current oil and gas hedging strategy? What exists now and what are the future plans?

Well, two parts. I think we kind of covered what exists now. Basically, our existing hedge is a costless collar with a floor of $60 and a top of $81.50, and it continues through July of this year. And that is for 7,375 barrels or something.

And so that basically is a little less than half of our total net production. So if you look at that, we're going to be making some payments out to the hedging company it looks like going forward. I mean we did a little bit for the year January and February. Mike said $120,000 went out in the combined January and February; about $60,000 a month.

It is probably going to -- right now at $106, it looks like it's going to be a little more than that for March.

And look, the whole process of it is insurance. Do you need insurance or not. You have to pay for it whether you need it or not. If you need it, it's really good to have it. If you don't need it, it seems like wasted money.

And at this point in time with oil prices being $106, we didn't know that obviously when we started this process in 2009. While we started out was to protect that we were able to actually keep at least a $60 floor so we could continue to grow the revenues and not risk going back to the kind of events that we had in '08, where we basically ended up at $35, $40 oil for a long period of time. So, I guess that would be the answer to that Internet question. What else do we have?

Okay we have a question about the 10-well program. It says the 10 well program has various things. Let me cover the 10-well drilling program kind of from the get-go. I've seen where it's headed. I'm not going to read the whole question there.

But the 10-well program is the 10-well Kansas program that we entered into with our partner, Hoactzin. Hoactzin basically had said it in two ways.

One, the first thing that we called a purchase price was basically $1 million over the drilling costs, and that number became a target for us because also involved in that original setup was any event they didn't get enough production from the 10-well program, they were to get preferred stock if it did not reach payout in a certain course of time or at a certain rate.

We've already gotten to the point that we can see that is going to happen sometime this year, before the end of 2011. They're going to reach the point at which they can no longer get preferred stock that is $3.8 million. So at $3.8 million, they're going to get -- they're only about $0.5 million away from that right now as we speak. So they're going to pass that.

The second milestone was what we call the flip point. Right now the rate from those producing wells, they're producing about $100,000 a month; $75,000 goes to Hoactzin; $25,000 comes to Tengasco. Assume that stays flat; somewhere that payout is going to occur about 2000 -- that's the payout point. That's going to occur in -- if today's price it's going to occur in about 2013. Then that payout will become $85,000 to Tengasco and $15,000 to Hoactzin. So there is a flip point coming and there's what's -- a purchase price point coming.

I think in some places, those two things got blended together and it has been confusing for the investor.

Right now, like I said, right now today, the last checks that went out to everybody, that was about $100,000 from that 10-well program for the month. So at this run rate, Hoactzin gets $75,000.

Now if the MMC gets up and running and goes to a profitable state, then we can use MMC's additional revenues to accelerate both of those. But certainly think all by itself the 10-well program is going to catch up to it. It doesn't need MMC to help carry the weight. And we're not counting on it anyway. So, but that is that.

Same question.

How much -- well we have got in here how much oil are the new wells producing daily?

It varies. I mean when we -- each well is different. We don't typically put individual well numbers out there. I mean if you look at us in Kansas, our average production is slightly under four barrels a day per producing well at all of our Kansas holdings.

It is really a stripper area. A stripper well is those low-volume, less than 10 barrel a day wells. So Kansas is full of those things. Many, many companies are built out of that. So basically if we look at the total production over 2010 of the wells we drilled, we began in May and we drilled a few out. We did about 30,000 barrels out of the -- all the wells -- so.

Melinda, did you have any other calling questions?

No questions coming from the phone lines at this time.

Okay, well with that, I think I will -- did we get any more in? Oh, what's that one? Okay.

Well, we do have a question about the Gulf. And I guess basically the Gulf of Mexico for us has been a foray into basically matching of the properties with an opportunity to participate. We entered into that in '08. Gas prices were $6, $8 $10, $12 going up, and we thought that was going to be a good thing, a chance for us to do something.

It hasn't panned out. In so doing in the Gulf, we participated in one well and we didn't do very well at that well, and we haven't participated in any since.

The program for us to manage those properties continues through 2012, the end of 2012. And basically unless we have a pretty remarkable recovery in gas prices, I'm not expecting us to participate in anything else in the Gulf.

As of now, we don't own anything in the Gulf. We were asked about Gulf ownership. We don't own anything in the Gulf. It all belongs to Hoactzin. We're just managing the properties for them. So I think that's kind of the answer.

They want to know if I want to buy the Titans? Okay, we don't make that much money.

Yes, I think -- another question came in. I kind of covered it in the original presentation.

It asks about the payback time and the time on a polymer. Polymers are costing us between $90,000 and $105,000. And typically our payback time comes in two forms. In the oil form that it comes, we get that back. At today's prices, let's say at about $90 a barrel or so, we get that back in about nine months. Obviously if prices are higher or lower, that will vary. But that is a pretty good payback for us, and it cuts -- also it cuts our electric costs because we're not pumping as much water, so we don't get any return on the water we pump out. So since we're pumping less, electric costs goes down. That also helps accelerate that payback.

Well I have a follow-up to the hedging strategies. Well, going forward, I don't know that we really are anticipating anything in terms of a hedging strategy. We have discussed it. I think you have to look at why we did what we did originally, when we took out the original hedge.

Our objective there was to allow us to have a significant cash flow to continue to go back and get into the operational mode. And it's a difficult question to answer. It is not a single point decision. It's a decision about many different things. The state of the whole climate of the oil industry; the world price is upset; problems in the Middle East. At this point in time, it is just a very, very iffy thing to do. The economy is struggling. How high will it go before all that is affected.

There is a very challenging thing for us to decide. And I think at this time, basically, it is always a boom or bust cycle in the oil business. Sometimes people like to live it. We are pretty good at it. We can do better than most.

We're generally kind of conservative, so I think if you can anticipate that if we had to have it at some point in time if prices were -- looked like they were headed down significantly, we would consider it again. But there is no commitment, no planning going forward for that particular event.

I think we're kind of looking forward to the hedge unwinding in July right now, if you ask everybody around here, so.

And at this point in time having only spent through February $240,000 total of real cash out the door, other than this accounting cash, then it has not been horrible to the company.

Question about purchasing property. We're always interested in looking. We make efforts from time to time that go unheard about looking at other properties and everything like that. So we've got time for about one more question.

I mean right now -- he wanted to know about our current cash position and ability to fund operations going forward. Right now, I mean again, once again, the price of the commodity plays a critical role to us. We do have some availability in our borrowing base. Right now we have about $10 million borrowed and a $20 million facility. So we could borrow another $10 million, so we have room under that. We could kind of smooth out the humps.

What we like to try to do what we can do strictly from the cash flow without borrowing. We may use the borrowing from time to time as we go forward through this year to sort of make the plan as we have it go smoothly and try to stay in 2011's sort of budget. But as I alluded to, we are looking at something like 24 wells for the year and 16 polymer operations.

All right. With that, it is about time to draw this to a conclusion here at 5.00.

I would like to thank -- this is the first conference call we've had in a very long time. I appreciate everybody's efforts to get back to that.

A copy and a transcript of this will be posted online, as well as you can listen or somebody else can listen to the audio for the next few weeks. So thank you very much. Thanks, Melinda.

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