TransAtlantic Petroleum's CEO Hosts Q2 2012 Operations Conference (Transcript)

| About: TransAtlantic Petroleum (TAT)

TransAtlantic Petroleum Ltd. (NYSEMKT:TAT)

Q2 2012 Operations Conference

August 10, 2012 10:00 AM ET


Malone Mitchell – Chairman and CEO

Wil Saqueton – VP and CFO


Neal Dingmann – SunTrust

Jonathon Fite - KMF Investments

Arvind Mallik - KMF Investments

Jamie Somerville – TD Securities


Good day, ladies and gentlemen, and welcome to the TransAtlantic Petroleum Second Quarter 2012 Operations Conference Call. At this time, all participants are in a listen–only mode. Later, we will conduct a question–and–answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this call is being recorded.

I would now like to introduce your host for today’s conference, Mr. Malone Mitchell, you may begin.

Malone Mitchell

Good morning, ladies and gentlemen. We got Wil Saqueton and Chad Potter with us. As you can see from our press release, we have filed a five–day extension to file our financials. And this morning we’ll be discussing operations. Now, Wil will discuss this accounting further in his part.

In the Thrace Basin where we spent the majority of the past several months drilling three deep tests in our Tekirdag Field Area and drilling several exploration wells based upon seismic. The accumulative result of the completions has not been sufficient to offset our base decline in production. Conditional results other than Hayrabolu area north of our Tekirdag Field have been relatively poor.

Our Hayrabolu Field structure continues to have good results and we expect to drill several more delineation wells there this year and begin a development program there next year. We have fracked the first of our deeper wells in Tekirdag, the BTD–3 was fracked in the 2,500 meter interval, and initial production rates are in the 1 million cubic foot per day range for that single site.

We have not yet recovered our fracked load or run tubing [ph] in this well, so it’s too early to make any meaningful estimate of reserves or economic profile. We are moving our frac crew to Southeast Turkey for the next 60 to 75 days or so to work through nearly a year’s backlog of wells needing fracs in that area.

This will give us time to evaluate the BTD–3 well further and to drill wells to commence the 50–acre development wells in our Tekirdag Field Area. We would expect to have an accumulated backlog by the time the frac crew returns. By near year–end, we expect to have two frac crews in country, so we won’t have this either/or situation from our fracs. It is likely that despite connecting and optimizing existing gas wells, remove water and hook up additional wells, we could see further gas production declines in the third quarter of this year.

In the southeast, our drilling for the first half of the year has generally resulted in reserves a little better than our pre–drill estimates. We have approximately 15 wells to frac in Selmo, and our objective is to do two to three of these wells per week. We do not have an external reserve estimate on this but the average of our 2011 fracs indicate that an average incremental gross increase of around 40,000 barrels at 100 barrels of oil production per day is releasable. We currently produce about 2,600 barrels or more per day gross at Selmo.

Due to drilling opportunities and obligations for deeper wells we’ve made a rig out Selmo in July and do not expect to resume new drilling there until the fourth quarter.

Our Goksu discovery continues to perform well and we have one rig operating to drill the initial horizontal test to the Mardin formation. We reentered and drilled a short horizontal leg [ph], about 1,000 feet in the Alobay [ph] well and western blocks of the southeastern basin.

Mechanically, the operation went pretty well and we encountered oil shows and fractured swarms and porosities as we had hoped. We cased the well for 3[ph] days and ran full set of Selmo Shale image logs and are currently having those analyzed by [inaudible] Mississippi Group in the United States which we think is the best analog to this particular formation.

Once we receive these definitive results, we can better understand the reservoir characteristics and plan a completion. After four months effort, we secured a location for our Goksu number three, there’s a multi–well pad. We expect to begin drilling that well this month. On this well we’ll be setting 7 inch through the curve and drilling to plan approximately 3,000 foot lateral open hole. But we still don’t know what the right completion will be, and that could be anything from open hole to cased and fracked. So we’re going to have to evaluate the data and fill our way through these completions in this Mardin formation. This was approximately 1,500 feet south of Goksu–1 and 2 wells, so it’s typically lower risk.

We are completing the Bahar–1 well now, back to perforating the well, the well flows on 1,200 btu gas. Some of it pressured. The buildup on the well and the simple completion process has indicated high skin damage factor for the well. Just this morning, about an hour ago or so, we received the preliminary lab analysis for the Bedinan rock and we expect to utilize this to design and stimulate the Bedinan while our high–pressure type equipment is in the southeast. We’re not so [inaudible] or frac.

We’re also evaluating the Dadas [inaudible] QPO [ph] and Core Labs laboratories. We expect the vertical test for Dadas shale oil [ph]. Now, we expect it’ll still be several more weeks before we receive a definitive frac analysis [inaudible] so that we can plan those completions. We expect to utilize that time to pass the Bedinan.

The Hazro and Mardin formations above the Dadas also appear productive from both the drilling shows and wild analysis we have there. I don’t know when and how we will confirm the test for these formations until we’ve completed test at the Bedinan and Dadas. But we do appear to have a significant conventional and unconventional running room in the Molla and our recently awarded West Molla block just blasting the existing blocks.

So we will commenced about 100 kilometers of 3D seismic from West Molla about October 1st to confirm the gross structures indicated by gravity on this block. There’s been really no prior seismic leader than they were old [inaudible] nor there any wells on the block but we expect to confirm the gravity structures with seismic and to follow that with a large 3D shoot to define both development and exploration prospects.

In the southeast, we’ve also set surface casing and drilling below on our Konak exploration on our year [ph] outlook [ph].

At joint venture with Shell, we expect to complete the initial 1,000 kilometers of seismic acquisition in the service basin on September on the client acquisition phase, but we have completed the [inaudible] and we expect to analyze this data along with shale geologists through the end of the year as part of deciding what the next steps will be in the development on the [inaudible].

We’re making progress on the JV partnership that we looked at where we’re looking for one or more partners to help us fund and accelerate development and exploration of about 2.2 million drill site in [inaudible] Turkey. There are several groups in the due diligence process. Activity in August has been limited due vacations by the decision makers in the company that will move to pull trigger to invest. So we expect to get some decisions made in September and as we had earlier said close this transaction before year–end. And we expect this to result in a combination of cash and capital budget carried for TransAtlantic.

In Bulgaria, we’re in kind of the final process and expect to be awarded a production license on our [inaudible] and we expect to be able to resume activity and consummate a JV partnership in that area before year–end as well.

I’m going to turn the call over Wil Saqueton, our CFO and then I’ll be glad to take questions after this.

Wil Saqueton

Thanks, Malone. As announced in press release, TransAtlantic is filing a form 12B25 today, providing five additional days to file our Form 10–Q for the second quarter. The primary reason for needing additional time is the added accounting complexity associated with the oil field services divestiture we experienced this quarter. The transaction closed on June 13, which meant we had to completely close the service company’s books before we could begin on the gain–loss on sale calculation and the sub–period accounting.

Having to recognize service company activities through June 12 as part of TransAtlantic’s discontinued operations and the remaining 18 days of June as third party activity has posed additional challenges as well.

Finally, there were several other elements of the transaction that added accounting complexity. Nevertheless, at this point, we do expect to file our second quarter Form 10–Q within the five–day extension period.

Turning to our debt, we paid off 100% of our outstanding debt Dalea of $84 million with the proceeds from the Viking sale, 100% of various other notes amounting to $2.7 million and about 60% or $45 million of the outstanding principal due to Standard Bank and BNP Paribas. Our total remaining outstanding borrowings are – it’s about $33 million and we have cash on hand of approximately $28 million.

We also have $45 million – approximately $45 million of borrowing capacity available on our credit facility. We are keeping this level of cash on hand due to covenants in our current credit facility which limit the ability to utilize cash between our various entities. However, we are actively working with our current lenders to amend some of the covenants to allow more flexibility and for loan terms to coincide with our transformed balance sheet.

I’ll turn the call back over to Malone.

Malone Mitchell

Well, we would be glad to take questions from the listeners at this point.

Question-and-Answer Session


Thank you. (Operator Instructions). We’ll hold for questions.

Our first question comes from Neal Dingmann of SunTrust. Your line is open.

Neal Dingmann – SunTrust

Hey, good morning, guys. Say, Malone, just one –

Malone Mitchell

Good morning, Neal.

Neal Dingmann – SunTrust

Malone, your comments in Selmo why not – I guess going forward, why wait to add a regulator in the year and just kind of your thoughts on that play. I guess, going forward, do you see production remaining about the same or is there things like acidation or different things that you can do to that besides maybe some new drilling area to prop that up a bit?

Malone Mitchell

Well, number one, we don’t have enough big rigs to cover all of the opportunity in the southeast. And right now, we’re trying to press through getting these initial horizontal wells done this year. We’ve got two high–impact exploration wells that were going as well.

We would expect those to be covered under a JV but at this point we’ll drill those with or without. Foreign activity standpoint in the Selmo area, we expect an increase in our production base again. Over the course of the last year since we’ve last had frac equipment in the southeast, we fracked approximately eight wells last year in Selmo, so we have a good statistical analysis of what the results of those were. We used two different methods.

So as I said, we expect to frac approximately 15 and kind of the variance on that could be anywhere from 13 or 14, up to 18, just in Selmo field. And again, since we expect to do those in relatively rapid, repetitive order, we would expect an impact from that both in terms of reserves and in terms of production.

And while that will largely impact the third quarter average numbers, it should impact the exit numbers and fourth quarter numbers as far as our production in Selmo.

Likewise, we will use that frac equipment to stimulate some of the wells in other areas or in other areas or in other areas down at [inaudible]. So we do expect production to grow in Selmo, as a result of just the accumulation over the years’ time of about 15 wells but we want older laws [ph] that would benefit from stimulation.

Neal Dingmann – SunTrust

Okay. Just a few more if I could and that Bahar–1 the discovery you indicated there and then the slides accompanying that I think looks quite interesting. Just say, that it’s produced some oil and then you mentioned btu of the gas it’s produced, could you give us a color on that as far as – it looked like – are you still doing the swabbing operations and kind of what are the plans to bring that on production in Mollan.

Malone Mitchell

Well, we are perforating the well, not just on swabbing. We’ve produced at a rate of approximately 100 barrels of oil per day relative to test volume of [inaudible] personally, some reasonable volume as everything below the Mardin has pretty decent gas on it.

On build up, the well – the well has got a bottom hole pressure in excess of 0.6, we’ve got about 6,500 pounds in bottom hole pressure in the well and the buildup curves indicate high damage. As you may be aware, we lost that well, the first time we drilled it, due to bottom hole flows of oil and gas. We had to redrill it; we drilled it with pretty heavy mud. It took us a little better than 13 pound mud to control the well.

We’ve run just simple tubing and packer around and tried to do an acid job. Well, we basically had a failed packer and we had some acid on our backside on our tubing. We got that out. We don’t think we got any damage to chasing [ph] but we are changing out tubing right now and bringing basically, putting a new string of tubing in the hole to re–stimulate that. But the well completely full of shale fluid. The well had buildup 1,000 pounds overnight and will flow roughly 20 barrels of oil, no water and gas as we’re looking on two oil shale operations every day to get in and out the hole in the tubing and to get back where we can stimulate it.

So the amount of gross feet we have compares very favorably with the only other Bedinan field from the country which is Arpatepe. And we have close to twice the bottom hole pressure that Arpatepe has. And just as I said just this morning, I looked at before the call, just looking at notes kind of the x–ray diffraction analysis of the rock in the Bedinan and they passed right onto our engineers just to work for some kind of forward design and stimulation design there.

We expect further result to the Bedinan. We would expect to come up to the Dadas cuttings local grid based on a preliminary analysis they looked as we would hope they would look which would indicate a broader, unconventional [inaudible] thing that we’re at a point where we can say definitively what’s the year–end and of course it will take stimulations to get on but they are now – the size of the reservoirs, we are only about 3 to 4 miles away from the field that is going to make 15 million barrels out of the mug of the Hazro Field. We’re about 1.5 million barrels of oil well in the Mardin. But the field’s deepest well got to be Dadas; it did not penetrate the Bedinan.

The structures we have – I mean a series of structures both on a conventional basis are relatively similar although at least in the Mardin – I mean, there’s no production below the Mardin Kastel Field. The long characteristics are better and Kastel and the Mardin than they are in our Bahar well, so I don’t know that we would project that kind of recovery. And Kastel field is about 2,300 to 3,600 acres based on our best understanding of the geology with logs bit access [inaudible].

So it’s all significant, a good offer to the reserve base we have. That’s kind of where we’re at right now. I don’t understand and we’re seeing a lot of these deals here, so, you’re the only guy near the first guy, you kind of have to feel your way along on the completions. Sometimes, it goes fast and sometimes it doesn’t. Well, I guess in our case, it never goes fast.

Neal Dingmann – SunTrust

And then just one more, Malone [ph], if could. Just on the frac results that you provided, again, is that kind of what you’ve been expecting. I was just looking at like last fee on the TDR–8 and some of these others, it still looks – I don’t know if it’s fair to say a bit low but is that – I’m just kind wondering – well, on your opinion now that you’ve seen more than a handful of these frac results kind of – if you could comment on the program and sort of the anticipation of kind of the speed of the program up in Thrace going forward?

Malone Mitchell

Well, we – again, those are all individual zones. The only well – we frac one well, the TDR–8 where it appears fairly clear to us that between – we fracked the Kesan zone, which is deeper, good result in a set of bunch flow over [ph] come up and we fracked the Tashma core, we fracked two zone from that. Other zones carrier [ph] are gas productive and now they’re in between [inaudible] cleaning out some water. And in some cases where we’re talking on, we just got first [inaudible] kind of arrived in the country. We’ve just got the first mono–pumps to – unload on some of those.

I think we’re still very confident of the results on all of the single zones and in all of the stuff down through – the upper 300 meters or so of the Kesan which was the other thing we’ve talked about in the programs. We’re not concerned about the result we’re seeing. Now, we see some variance and that’s probably more related to the individual zones we’re doing. But we don’t see anything [inaudible] that bothers us or concerns us with regard to being able to achieve the results we’ve talked about. We still think 58 per gallon pricing fits the drainage models we see.

So we’re ready and are going ahead about just starting to do to just drilling, adding drilling and develop and get more multiple fracs there. We’re going to have a fairly an all–week long propaganda for our partners in Dallas the week after next along with the US frac groups and set there and just go through it so that we’re kind of locked and loaded on process. We have used a number of different – still a number different types of fluids. And different types of processes and we’re going to do a look back, so [inaudible].

The frac crew gets back there and we’re just doing the same thing over, over, and over again. We think we’re really through kind of experimenting and we’re at the point where we just – we don’t need to experiment anymore on our fracs, we pretty well know what works and what doesn’t work and you just think about all of the program there. Now, the deeper stuff – as I’ve said when a gas shows down the 2,500 meter below that, we really didn’t see a thing that looked very good. We had to post rate test some of that to decide whether – to prove ourselves – to prove to ourselves so that we won’t be be [inaudible] point in time saying, okay, let’s go drill a 3,800 meter well because there might be something there and we didn’t test it.

When you look at that on a gross basis, it looks like there’s some gas down at 2,500 meters. Frankly, the BTD surprises me a little bit on the strong side. I think we need to give it a couple months to see what we’re at there. So it’s hard at this point to project what we get from, say, 1,600 meters down at 2,500 meters.

But despite the variance in the outcomes, I could come back a couple of months from now and tell you, 2,500 meters didn’t work but fizzled out. But we don’t see anything associated with the 1,600 meters in [inaudible] that we’ll change our conclusions from both the [inaudible].

Neal Dingmann – SunTrust


Malone Mitchell

There will be another. I just thought that we need to do more experimentation. I think we’re down there.

Neal Dingmann – SunTrust

Okay. That’s good. Great answer. And then, well, justly Malone, just wondering now that you’ve got the debt down very much to a minimal level. Your thoughts on either you want to keep around this level or as you sort of progress forward on looking at opportunities, you certainly have a lot of acreage and a lot of opportunities, what’s your thoughts as far as kind of on a spending pattern for the, I guess, at least just the reminder of this year and then go onto next year, Malone.

Malone Mitchell

Well, we – I’m focused on getting a JV done. We can cash flow, we’ve ran slower than we needed to run. Sometimes because we – we concerned on how much capital we had. I’m not anxious to get back into that position again ever. I think the most important thing for us to do before we accelerate in the southeast – and I think we have a lot of opportunity to be there and kind of just [inaudible] to just bring in and get close to JV deal where we put a reasonably significant amount of cash on our balance sheet as well as financial to restructure – similar to what we did in the US on our Mississippi place privately or what a number of the US companies have done. And that will allow us to have the cash on the balance sheet and have the financial partners structured so that we can really pick up meaningfully our development pace and I just feel better about doing that. And I’ll be going out and trying to draw down our credit lines or expanding and build down our credit lines to do that.

We’re in good shape, the wells we drilled even though we’ve been slow, have been very supportive – the seismic [inaudible] have supportive of what we’re trying to get done on the JV and establish the viability to do some bigger plays. And to me that is the smartest thing to do right now because as you can see, what we don’t have a lot on it, that situation, we don’t have much cash or any net cash. So we’re not – because of the available credit lines, we’re not really in much issue there and our spending is fairly – our spending and our income are fairly flat. So we’re not burning a lot.

But the best thing I think I can do is to do that because we have a tremendous amount of acreage. We have a tremendous amount of opportunity and in order to meaningfully act on all of it at the same time, I think the best thing to do is to follow through with the JV but that – obviously that’ll, hopefully, that’ll lead us at the end the year with an even stronger balance sheet and allow us to significantly, probably double our CapEx next year without really changing at all what the – what we’re looking at from a financial impact to our shareholders.

Neal Dingmann – SunTrust

It’s a great color. Thank you, Malone.

Malone Mitchell

Thanks, Neal.


Thank you. Our next question comes from Jonathon Fite with TransAtlantic Petro. Your line is open.

Jonathon Fite - KMF Investments

Hi. This is Jonathon Fite with KMF Investments. Good morning, gents. How are you?

Malone Mitchell

Great. How are you doing?

Jonathon Fite - KMF Investments

Doing well. Just a follow up on the kind of cash flow question that I just spent some time answering and then I’d like to pivot to a strategy question. I understand the desire to fund kind of the outyear CapEx plan through some JVs but – in the release last night, you indicated you guys have a plan of about $50 million to $70 million just for the back half of this year. And exiting ‘11, it looks like you guys are kind of in $22–ish million EBITDAX per quarter range, that seems to be kind of consistent in Q1. Is that a fair view kind of where we’re tracking, exiting Q2 and that kind of $22 million per quarter EBITDAX range?

Malone Mitchell

I think our expectation would be to increase and then obviously per barrel we expect in the third and fourth quarters to increase oil production. It’s a differential to gas production. In the third quarter, we saw a drop in [inaudible] and then a recovery of [inaudible]. So, I guess our expectation would be to do better in the third and fourth quarter on an EBITDAX standpoint.

Jonathon Fite - KMF Investments

Is it – is your expectation to increase that enough to fund the $50 million to $70 million run rate through EBIT – through your EBITDAX generation or is that plan really requiring some type of JV partnership to come on Board to enable the capital spend just for this back half?

Malone Mitchell

No. Consistently with what we’ve said all–year long, we expected our spend to be in the neighborhood of $10 million to $20 million more than our EBITDAX. And at this point, I don’t know – but then on product process and our production, we would carry through with the CapEx budgets we have. We would not expand our budgets to allow us to run more rigs if we’re looking at our JV plans or just the JV CapEx. On a gross model, that’s a $340 million or $350 million a year budget. But we would work to – if we were successful of selling JV, we’ll probably look at our budget for 2013 being something closer to $350 million –

Jonathon Fite - KMF Investments


Malone Mitchell

Versus $120 million. But no, we’re not going to be there until we get that done. We’ve got enough acreage. We have our acreage position in hand but we’re not forced to do that. But no, we would not be able to accelerate that without doing what I think would be a serious stress for balance sheet. And we’re just not [ph] probably going to do that anymore. It would not – it would not bother me. Now that’s again subject to Wil and to the Board’s discretion.

It would not bother me to see us spend it – in the absence of any JV closure, which I think is unlikely between now and the end of the year which put cash on the balance sheets, it would not bother me to see us go down 10 to 20 more on our revolver associated with seeing through the program that what we had this year.

Again, we talked about [inaudible] and the payout of the of the wells and the economics of what we’re doing in Tekirdag and the profile of that production [inaudible] payout of that. So it could be that we outspend ourselves 10 or 20 if not the most happens [ph]. But I think that’s probably what we’re looking for.

Jonathon Fite - KMF Investments

Okay. And just to clarify, not really looking at 2013, but just for this year, to the extent that JVs aren’t done, you would look to draw on a credit line to do the $50 million to $70 million of spend this year rather than curtail some of the planned activities, is that right?

Malone Mitchell


Jonathon Fite - KMF Investments

But that’s subject to Wil’s feedback and the Board’s feedback?

Malone Mitchell


Jonathon Fite - KMF Investments

Okay. Just so the – moving on, I guess, more to a strategy question. Over the last couple of years, it seems like there’s been a shift in strategy from kind of a go, go, go, let’s get the production number up to kind of mid–last year, let’s shift to not worry about big production targets and let’s spend more of our time smartly identifying where we go next. And it seemed like the activities that then followed on from that were more focused on transitioning some P2, P3 type of reserve estimates to more firm estimates, moving the P3s to kind of a P2 status or the P2 to kind of P1 status through the 60 day review that you did and through the exploratory activities you’re doing. It seem to be that kind of the current activities are less focused on increasing production and more focused on kind of proving out the reserve base so that when you do transition to a more full–blown production environment you kind of know exactly where to go and that those reserves start flowing more quickly. Is that a fair characterization?

Malone Mitchell

Well, we won’t be very successful trying to build fast and be successful. So at the end of the day, we really needed to slow down to the point where it became more critical that we were able to execute on something that would provide real reserves than it was – what we found ourselves over a couple of years was doing things fast and then becoming surprised when the reserves, after we put on production, not matching what the volumetric analysis did or what we were seeing later. And it was challenging to get it executed in a non–sloppy, non–wasteful way.

So we really decided, we’re already unpopular so we’re not going to worry about popularity. We’re going to worry about getting our financial house in order and we simply need to locate these acreage blocks that we have that we have just compared to the US, an unremarkable manner to hold those blocks without being concerned by expiring licenses or delayed rentals. And let’s slow down and let’s do the work. We think what we have is right. What we have a hard time doing is affording to do several wells quarterly and recover from either people’s loss of confidence in that or our loss of confidence in that and being able to move through to success that what we really needed to do is we probably needed to slow down, do more analysis on the rock, do more analysis on the completions we were doing and make sure that we’re going to get something to what we’re spending and then move forward into developing that from a stronger cash flow basis, which really has been – your stock price get caught up in the expectations that are different and at the same time that’s about what our expectations of what we can do and what we communicate and what we think we can do.

I think in general that’s the deal. We feel very good about our rocks. We feel better and better about our people’s ability to execute the things. Now just like the horizontal [ph] there’s still tremendous challenges of getting the rack completion, things that are just so easy to get access to in the US are a very challenging thing. On our [inaudible], we’ll most likely have to compromise at completion just based on what’s available to do completion work versus what you would have the options to do in the US.

I’m just trying to make sure, okay, let’s slow down. Again, it takes us some time and it takes us some money. Let’s try – let’s try to get it done as best we can and then let’s really evaluate the results. If we get a well that comes on really well to start with, rather than running out and offsetting it three times and seeing that, we want to make sure that we’re going to see production – a production profile that really means something economically and then go forward.

But what we have right now generally tells us that we have those three bit – now, right now, we have these two big resource areas and that we have some [inaudible] opportunities elsewhere. But we just – but we can’t get any more unpopular than we are, I don’t think.

So it makes more sense to me to get it right with the financial position, put together on the company and go from there. On the product business and obviously, let’s – people have obviously, that was weird and [inaudible] bad and I guess progressed horrible on the product business, we’d never worry about some of the progression that you worry about in the public business because you have to announce things very fast. But you normally just be quiet and look at it on a private [ph] basis. I guess –

Jonathon Fite - KMF Investments

Sure. But just to kind of clarify some of your early comments around what we’re doing in Selmo this, I guess, in September with the 15 fracs there and the spud stimulation activities and all that. Are these activities more of the – kind of focused on proving out the reserve base or are some of these shifting into more production focused activities. Or how would you kind of characterized this [inaudible]?

Malone Mitchell

Well, no. Selmo has always been a matter, I don’t think we’ve ever had a manner of knowing how much oil is there. I think we always know how much oil is there, it’s either we get it out the most effective way. And you drill wells, they are, the number one, really well and then you drill wells that are better tight. You’re drilling a well that comes on producing 20 barrels a day or something like that. The fracs we did in 2011 tell us that if you get a well like that that you frac it, you generally get a pretty good result. I mean, we fracked, we go in there and frac well – 15 wells, we’re going to expect some wells to make good [inaudible] and then we’re going to expect some wells to make 300 barrels a day.

You know, if we look at range of results. We have from 0 to 180,000 barrels incrementally, 0 to 300 plus barrels of production on a smaller subset. So this is just a matter of – this is just a matter using normal reservoir. I mean, if we had the frac crew stationed down there, we’d be doing those as they occur on the drilling basis because there is only one frac crew in the country and you have to mobilize everything. You got to understanding there’s only one set of frac tanks in the country.

But you got to mobilize everything one direction or the other. That’s part of why we split the service back which is part of what – well, the service company going out on its own and spending another $125 million to build service capacity, it is going to be beneficial because – and still having a lot of yield to frac a well. You’re going to frac a well [inaudible] still a year later like you would in the States. But there’s nothing – we always know and I think we publish, there’s – we have a pretty good [inaudible] on the total amount of oil that’s in the tank at Selmo, we have a pretty good idea of how much oil you got to be able to get around down spacing and doing [inaudible]. If you could drill horizontal wells there. It would be great. I frankly don’t think you can because of the unstable shale that sits just above Selmo. So we’re going to have to develop that field on verticals.

The drilling group has got really, really good and effective frac getting those drills through. Everything we drilled for the past year has been multiwells off of simple pads. Those guys have got from spread to set casing. They got [inaudible] drill a well, in a range of 10 to 12 days. That’s better than I thought. We would get through and that is better than I would expect in the US. So they’re cost effective on doing that.

And it’s a relatively simple thing to go frac the wells but you got to have fracking group [ph] to do it. So that’s – we’ve been waiting a year. Some of these wells have been waiting a year. We have the well that are amounting to 18 barrels, we have 20 barrels and trying to go frac it and spending [inaudible].

Jonathon Fite - KMF Investments

Okay, last question. Given the activities through the CapEx today, has it really impacted production much this year but it’s been more focused finding out where to do next and kind of a reserve base view.

Based on the progress to date, do you have – can you characterize kind of what the impact has been on the P3, P2 type of reserve evaluations. I mean, obviously, that has to be done at the end of the year; where, based on kind of the data that you’re getting, is there any way for you to kind of characterize the impact of the spent to date on that broader reserve base?

Malone Mitchell

So, we never had anything on the books, really, with regards to these type of sands in Tekirdag. So, the data that we have generated this year we believe will allow us to put a significant amount of reserves for development and proved on to the books next year. We only have five locations in all of the Tekirdag Field Area coming out in 2011.

So, it’s not a matter of we’re converting that in, in a large case, on our standpoint, we’re putting that into the book for the first time. Hayrabolu, we think is – Hayrabolu is a very interesting field area as well. It’s probably – we’ll probably know more about that.

If you look at basically the Southeast, now Selmo is pretty well on the books. So, Selmo is just a matter of producing and doing the proved undeveloped, doing the conversions of probables to produce by P2s and P1s by proving out frac recoveries. And then we still would like to do some water injection efforts there and which by the way [inaudible] Field out of essentially the same geological formations has been on water flood for a long, long time.

It’s obviously impacted possible [inaudible] there. And you would expect it to do the same things in [inaudible] Goksu and things like that. We have no reserves on the books for the Goksu area or any material reserves on the books for Goksu, Bahar, for Molla, for any of that. We protect this kind of [inaudible]. We don’t have control of operations [inaudible], so it’s very challenging to predict any things that are going to happen in Molla.

But on the Molla area, we don’t have anything in the books. So, what we see there will be a model of just putting things under the books. At the end of this year, that we’ll know how it works.

Jonathon Fite - KMF Investments

Okay. I appreciate that comment. One last thing, I’m sorry, at what point, or is there ever a point do we get to where share repurchases at half of P1 are more beneficial than further growth CapEx?

Malone Mitchell

So, I think our shares are severely undervalued, the sooner we come out of the lockups, like, obviously, you’ve got to get the financials filed. I intend to buy more. I’ve already said, to me, personally, it doesn’t make sense for us to borrow money to buy shares from a [inaudible] standpoint where we set today, now, if the Board disagree, obviously, I’m not – I don’t control the Board.

But I would believe that if we were successful at putting in a significant amount of cash on our balance sheets, that we believe there’s some excess of what we’re going to need and what we could reasonably expect to use as leverage. And I expect our opportunity to leverage our credit lines to fund [inaudible] in 2013 in capacity, maybe not in growing capacity but in capacity.

But our shares are extremely cheap. I mean, if you look at the reserves, if you look at the productions, if you look at the cash flow, I think our shares are very, very cheap relative to what we have. But it’s probably [inaudible] based on our perform.

But as I said, I think our balance sheet will allow us to act as a company probably ahead of the market’s reaction to what we’re saying. So, I’m confident that the company will be able to act in a manner that will probably take advantage of that situation if there’s a market disconnect upon the value of the shares and what we believe the value is and what it should be.

Jonathon Fite - KMF Investments

Well, we appreciate your personal actions over the last couple of years. I think you’ve definitely put your money where your mouth is. It would be great as the JVs come online and as the CapEx plans are developed to the extent that you can get kind of a proven number out of no risk, cap off simply by hitting a buy button versus drilling any well. I’d love to see the company being able to exploit that as well. So, we look forward to that and keep up the great work. Thanks.

Malone Mitchell

Well, thank you.


Thank you. (Operator instructions) Our next question comes from Arvind Mallik with KMF Investments, your line is open.

Arvind Mallik - KMF Investments

Yes, thank you, Jonathon. I already closed my question, so I appreciate it. You can go to the next person.

Malone Mitchell



Thank you. Our next question comes from Jamie Somerville of TD Securities. Your line is open.

Jamie Somerville – TD Securities

Oh, yes. Hi. Thank you.

I just wanted to know around – when you talk about moving the shallow frac program onto other structures here, I appreciate the presentation where you’re showing the location of all the different fracs that you’ve done.

You’re still showing the task of proving up the shallow frac concept outside of the Tekirdag area as in progress. I was just wondering when you expect activity on that process in particular to go forward, and particularly as it relates to the previous question with potential reserve additions. I’m thinking outside of the Tekirdag area. I was aware that there was somewhat successful well on the structure to the northwest, I believe. And I think it’s [inaudible] – so go ahead.

Malone Mitchell

Yes. Jamie, we’ve got – well, [inaudible] Hayrabolu. Hayrabolu is a very large anticlinal complex. It’s got – it comes out, structure it, all the way from their Suleymaniye wells. So, that structure from end to end is probably 30 plus miles long.

So, our expectation, as I said, that belongs for drilling and limited amount of fracturing they’ve done this year in Hayrabolu area. We expect Hayrabolu area to be the next field. We focus around having a development program. And it may not be exactly similar. The field has got a little more faulting in it, probably a little more compartmentalization and we have less deeper wells, even to match kind of Kesan, Teslimkoy sand sequences that we have tested that are the better type targets in Tekirdag area.

Tekirdag, as I said, we think is kind of done and ready to start there and do some more delineation. But you won’t notice that; we’re during the development drilling, per se.

We expect Hayrabolu to be the next one. We hope to have at least another four or five wells drilled on that big Hayrabolu anticlinal structure. Even though it will, right now, I think there is four or five different field names within that same [inaudible]. But after we get the next four or five wells drilled, we think that that will enable us to plan something approaching the development program.

I don’t know if I could say at this point in time whether it’s the same size or bigger than the last size than Tekirdag. We just don’t have enough data there. We don’t have much hooked up there right now. But that’s the next one we would expect.

Now, we’ve also had some successful fracs on structures that are back to the west that are further away from our pipeline. We like Hayrabolu, obviously, because we have a pipeline there. The blocks north of that, we’re working on getting the JV done in order to develop these three anticlinal structures; it’s set immediately north of Hayrabolu that we own 100% of. But we think Hayrabolu – Hayrabolu is connecting the pipeline. Hayrabolu is the next structure we see producing the kind of results that we need to go forward.

We also had successful completion on a well back further to the east in [inaudible] from our main pipeline infrastructure. So, it’s important to us to get – it’s important to us to spend the money where we can get a good payout, fast payout frac because we’re connected to the infrastructure. So we’ll probably – Hayrabolu is next.

Jamie Somerville – TD Securities

Thanks, Malone. Just with regards to those four or more wells you mentioned, now, what’s the potential timeline for those? Because that’s probably going to be quite important as to whether you could book reserves for – and I realize you’re not going to be able to book really meaningful reserves to that structure at year end, but four or five wells might be able to get you somewhere.

Malone Mitchell

No, those are all on the immediate drilling lines. Some of them are deeper wells. We are moving the rigs from [inaudible] to one of the deep wells in Hayrabolu. We had a truck driver actually turn the truck over, so we had to send a rig in to complete re–inspection on the [inaudible] anymore.

So, that’s the latest about three weeks on spreading that well while we flew in an inspector. We did everything on that big rig to make sure that it was good as new from an inspection standpoint. But most of those wells because we’re, again, stocking shallow or known production along with deeper objectives that have been driven off the system [ph].

We’ve really got two rigs that are suitable on drilling, I should say. We expect to get those wells drilled and at least some initial tests on before the end of the year.

Jamie Somerville – TD Securities

Perfect. Thank you very much.

Malone Mitchell



(Operator Instructions) Again, to ask a question, hit star and then one on your touch–tone phone. I’m not showing any further questions in the queue. I would now like to turn the call back to Mr. Malone Mitchell for any further remarks.

Malone Mitchell

Again, we would encourage anybody to touch base with Chad or Will or myself if you have additional questions. We’re going to be very – obviously, we’re not going to be able to answer on actual questions until the filing of the queue in the financials.

We thank you a lot of what you see there. But if you can comment, you can post until we get signoffs on that. We appreciate your patience being a shareholder. And if there’s anything we can do to give you further information, please come visit us or call us.

Thank you and have a good weekend.


Ladies and gentlemen, thank you for participating in today’s conference. This concludes today’s program. You may all disconnect. Everyone, have a great day.

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