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TransAtlantic Petroleum Ltd. (NYSEMKT:TAT)

Q2 2013 Earnings Call

August 8, 2013 08:30 am ET

Executives

Malone Mitchell – Chief Executive Officer

Wil Saqueton – Vice President & Chief Financial Officer

Ian Delahunty – President

Analysts

Neal Dingmann – SunTrust

Curtis Trimble – Global Hunter Securities

Jonathan Fife – KMF Investments

[Doug Shroegel] – Private Investor

Jamie Somerville – TD Securities

Operator

Good day, ladies and gentlemen, and welcome to the TransAtlantic Petroleum Ltd. Q2 2013 Earnings Conference Call. (Operator instructions.) As a reminder, today’s conference is being recorded. I would now like to introduce your host for today’s conference call, Mr. Malone Mitchell. You may begin.

Malone Mitchell

Hello, ladies and gentlemen. Thank you and welcome to our Q2 conference call. We do expect the quarter we just reported to represent probably a low spot with regard to our production and given process, probably also a low spot in cash flow. We’re pleased to have completed our filings timely and I will now turn the call over to our CFO, Wil Saqueton, to review the financial highlights.

Wil Saqueton

Thanks, Malone. Through our efforts over the past twelve months to correct prior-period errors, improve our accounting processes and add key resources and expertise to our team we are pleased to file the 10(q) on time. We fully expect to continue to deliver timely quarterly filings and are also working to improve our internal controls over financial reporting.

Q2 included several nonrecurring items resulting in additional net operating expenses of approximately $4.9 million, all of which have been excluded from our adjusted EBITDAX figure.

For Q2 2013, total revenue was $31.8 million as compared to revenue of $35.5 million in Q1. This revenue decline was largely driven by a reduction in Brent oil price of $9 from $112 to $103, as our differential to Brent remains flat at approximately $9. Sales volumes were down slightly at 7000 barrels of oil equivalents and our other revenues were down approximately $0.5 million.

Net income from continuing operations was $2.9 million or $0.01 per share, which were approximately flat to Q1 2013. Adjusted EBITDAX from continuing operations was $17.6 million as compared to $19.5 million in Q1. This reduction was driven by the revenue decline I mentioned earlier partially offset by a decline in normalized production costs of $1 million due to the headcount actions we took in Q1 coupled with fewer work-overs. Additionally our G&A costs were down about $600,000 due to lower auditor fees combined with the headcount actions in Q1.

Q2 adjusted discretionary cash flow was $16.1 million or $0.04 per share. Our CAPEX and seismic expenditures were $28.1 million and include the acquisition of the [Bolton] properties in the Molla area of Southeastern Turkey.

We ended Q2 with $15.9 million of cash and approximately $50.0 million of cash availability on our credit facilities. I’ll now turn the call over to Malone.

Malone Mitchell

Thanks. One thing I would note on our current production rate, our production is growing. Oil is steady. Gas sales during the month of Ramadan, and Ramadan moves every year because it’s on a lunar month, is low. In fact, this week will represent our lowest gas sales most likely for the entire year as we see a significant number of plants and a significant number of office buildings shut down entirely for days; and during this week for the better part of a week.

We have accelerated our activity to now five drilling rigs. Operationally the company continues to see improvements in drilling efficiency and completion success. We believe a good deal of this is related to the transfer of these functions to Dallas at the beginning of the year and the leadership from North American experienced technical management.

We are well underway on executing the Molla area 3D. We have shot over the part of our license adjacent to the new TPAO oil discovery and we expect to have that data processed near the end of this quarter. We should have acquired data over our Bahar Field area in September and have that data processed before year end.

Our Catak well was projected before we drilled to be structurally low-test and actually came in high to our Bahar-1 and Bahar-2 in our primary zone, so that the further indication we are really looking for to having 3D over this large area and expect us to enable better development of these fields than we are with our current 2D. Now, the rig has been released from a prior well and the contractor is preparing to transport it in Bulgaria to resume drilling our Deventci-2 well. And we are circulating documents on the JV and expect those to be executed very soon, and we’ll send out an update as soon as that is finished.

I’ll now turn the call over to our President, Ian Delahunty, to further review our operations.

Ian Delahunty

Thank you, Malone. Good morning everybody. I’m going to go into a bit more detail on what Malone has just mentioned. And primarily at the June 24th Annual Shareholders Meeting we set out a pretty aggressive second half of the year drilling campaign and I want to give you an update on that.

The week after the AGM we did move the rig count up from two to five rigs. I’m going to run through what those five rigs are doing in Turkey at the moment. On Catak-1 we’ve completed the drilling to the Paleozoic. It’s important to note that in Catak we drilled an intermediate hole which is about 6000 ft. with a single bit run. That’s a first for our company.

It’s essentially proving that we can drill through the Cretaceous and into the Hazro Paleozoic very quickly and very efficiently. And what it means to the bottom line is we should be able to drill a vertical Paleozoic well for about $3.5 million in about 40 days. So it’s a big leap forward in terms of our drilling performance there. In terms of the petro physical analysis and the core analysis, both are underway now. We’re shipping the core to Houston for some analysis there and look forward to announcing results of our testing and our work there soon.

Also in the Southeast we’re drilling a horizontal well in the Cretaceous Mardin play. This is the Goksu-5H well. We’re currently drilling laterally through the Mardin. There are some zone issues that Malone has hinted at considering we have 2D seismic over that area. We are encountering oil shows throughout the lateral and are moving forward with the planned trajectory.

In the Selmo Field we are drilling the first MSD horizontal in the field’s history. Now we did complete drilling the first LSD horizontal in the field’s history which went extremely well in terms of drilling performance and also in terms of the production performance on the well. So we’ve drilled about six days now in that well and we’re two days ahead of the curve already, so knock on wood that should come in under AFE as well.

Moving to the West, to the Thrace Basin, we’re drilling the first Teslimkoy horizontal in the country. This has just offset the DTD well we’ve recently completed. And we’ve added a coring program actually based on some of the positive results we saw in the [Balak] high COC shale intervals. And to get into that a bit more, essentially we’ve identified a couple of stone shale members which seem to have some potential there and we’re moving slowly but it’s positive so far. So on the BTD-4H, a Teslimkoy well we’re building the curve now at 22 ft. per hour and it looks like we’re going to be ahead of AFE on that well.

We completed drilling a vertical conventional well in Thrace Basin which I don’t think we’ve talked about in quite some time. We haven’t been drilling conventionally in Thrace Basin. This has been the first. This is on our JV with a national oil company. We set a record certainly for TransAtlantic; I imagine it’s a record for the country of Turkey. We drilled for two days at 70 ft. per hour which resulted in 3300 ft. of holding made. The well came in six days under AFE, 50% lower drilling costs and the logs looked like they had 15 m., 20 m. of net pay. So we’re pretty encouraged by what we’ve seen there and we’ll complete that well in the next couple of weeks.

In the Southeast we finished drilling the Goksu-5 and the Catak. We’ll move to two additional exploration wells. They’ll both be vertical Paleozoic wells. Those are the Mardin and the Ambarcik prospects. The Selmo rig will continue to drill the MSD horizontal campaign. We’re currently adding LSD locations to our prospect inventory based on the results of Selmo-13 and then we’ll move to six conventional shallow well targets in the [Adarnei] Field after Gocerler-7.

Moving on to completions and production, update on the first horizontal well we drilled in Thrace Basin – we fracked that well with about seven stages and a million pounds prop-in. We were able to drill out about half of the lateral section of Packers Plus system with a conventional polling unit. We encountered some difficulty drilling up a [heel] so we pulled out and put the well in test production from essentially the first three stages. It looks like it’s doing about a million a day. We’ll continue on test production until we have coil tubing in the country to go in and drill up the remainder of the lateral.

As I said earlier we continue to be encouraged by the results of the shallow Mezz frac. We have four positive commercial tests; now we’re evaluating the area and the zone for horizontal development. We’ll keep you posted on the extent of that play as we progress.

The last frac was three days ago. We fracked a new well completion in the TDR structure. This well had been waiting on completion for quite some time and that’s because it sort of fell in kind of the mid-range of our frac priority. We were surprised by the test. It looks like it’s doing about 1.8 million on this morning’s flow back report, so positive there.

The [Caransotupic] bore which we recently completed and published rates for continues to flow at excess of 2.5 million a day, so that well tested at 3.5 million and then down to 2.5 million, and then climbed back up to 3.5 million. So it’s very pressured up. We still like the nose of that structure on a shallow, conventional sands and we’re actually going to drill a second well offsetting [Caransotup-4] oil. It’ll be the [Caransotupic-5] and we’ll move there after we finish drilling the BTD-4H Tesla coil well.

Moving to the center of the basin we’re less encouraged by the deep prospects of the Thrace Basin center deep gas play based on the results of the Hayrabolu-10. We’ve done a decent amount of core work looking at the potential of the lower zones and from what we’ve seen so far I think that well will encourage us to focus more on the shallower horizons going south and more central to the basin.

In terms of exploration in the center of the basin, we’ll continue. We recently announced the discovery on our 100% block [Temrez] with the [Yildurn discovery]. We plan to drill two offsets to that well in the coming months. So we’ll still continue in the center of the basin but we’ll focus on the shallow, more conventional targets.

A quick update on production in the Southeast. The Bahar-2 Hazro test was very positive. We went up hole in that well, we got into the Hazro. We stimulated it with a pretty small [assam] job and production from that zone is 200 barrels a day with no water. And so we’re converting that well to artificial lift at the moment. We’ll put it on rod pump.

So that coupled with the Bahar-1 work over, production is probably a little bit lower than what it should be right now and that’s because both of those wells are sort of waiting on completion activities. Bahar-1 is being converted to kind of an optimization gas lift which should bring the well to a much higher rate than what it was doing prior to the work over, which was 235 barrels of oil per day. And we’ll keep you posted on that. That’s been a hit to our production and we’re looking forward to getting that thing back online.

The first horizontal Selmo, the LSD test is on a long-term production test. We continue to evaluate the water cut to optimize the capacity of the pump. For that reason we ran a variable speed drive with the ESP and we recently increased the pump output. We should see that hitting production over the next week or so. So as I said we’re encouraged by the LSD result there and we’re adding LSD prospects to the inventory.

Oba-1 was our third Mardin horizontal and we’re waiting on a coil tubing unit to isolate the two there. We’ve recently done some processing on what we saw from the logs on that well and we’ll re-complete it to produce from the midsection lateral up to the heel and we’ll provide an update when we have that as well.

Well, that was a bit of a longer operations update. I wanted to give some detail on the rig count. With that I’ll turn the call back over to Malone.

Malone Mitchell

Thanks, Ian. Now TransAtlantic will be presenting next week on the 14th at EnerCom in Denver and we’ll post an updated presentation showing some maps and data on some of these things that we’ve discussed today. We also expect to present an activity update with production rates on or before October 4th for the remainder of Q3 and we’ll try to continue to focus on a little bit more detailed activity reports twice a quarter – once on our operations call and then once on or immediately following the close of the quarter.

And again, as has been our longstanding policy, if we have an activity that materially affects the value of the company either positively or negatively that we estimate to be over 10% of the value of the company, then we’ll make interim announcements on that part.

Now with that we are pleased to take your questions this morning.

Question-and-Answer Session

Operator

(Operator instructions.) Our first question comes from Neal Dingmann with SunTrust.

Neal Dingmann – SunTrust

Good day. Malone, for you or Ian, I just wanted to know obviously it appears that you’ve got some horizontal opportunities. I’m wondering Malone, when you go in there how will you decide as far as kind of like they have here in the US – sort of the lateral length, best ways to frac, all those sorts of things that have helped in the costs around these and just the results here in the US? You’ve seen some super fracs and what have you – how will you make those assessments, Malone, as you go into the Molla area and some of these other areas?

Malone Mitchell

In these areas, it really has to be done as much by just trying to apply engineering principle; and then unfortunately that’s somewhat of a trial and error. The greatest difference between operating in the United States or Canada and operating internationally in my opinion has come to be the fact that there really are not a lot of other operators that we can share data with and that you can glean kind of best practices.

It’s kind of like we have a wide range of things that we think we could do with our Selmo-13 oil and we’re in the process of having to be pretty slow and experiment with what is going to achieve the best result. And particularly when we’re at a lower production rate with a lower number of well we’re a little bit more cautious to be I would say radical on our stimulations or radical on our exploration of some of the alternatives there.

So it is a trial and error process and I think we’re learning something with each well. That’s not a terribly satisfying answer but unfortunately where we are that’s probably the right answer.

I think that the success of the Drilling Group achieving such better timing and such better cost efficiencies on getting the wells landed and getting tight down… Now, we had problems on the Mahar-2 – we got in a fault zone, we had problems finding our zone and it really is apparent that when we get our 3D we’ll be better able to project where we are. Right now with our 2D in a lot of cases we’re jumping as much as 3 miles to 5 miles between lines, and we just have a hard time when you have very few wells figuring out exactly where you need to be.

So I don’t think that now we can say we’ve figured out the answers to completions on any of the different horizons we’re in, but I think we’re getting a little better. I think we do have in the Thrace a pretty decent program there.

Neal Dingmann – SunTrust

That’s what I was going to ask you, Malone, just to build on that – that was my second question. As far as that program you have, Thrace, it looked like in the press release you talked about the 8 million cubic feet a day. Is that the type of results? That looked quite good, especially versus some of your previous frac results in that area. Again, is that kind of the potential that you think now you’ve got for some time in Thrace as you go in and frac some of these?

Malone Mitchell

Yes we do. We think the seal zone is pervasive over a lot of the area now. I want to be cautious because we’ve been probably too optimistic on zones previously: so far our results have all been very good and positive on that. Now with regards to our horizontal, we’ve executed good fracs there. We didn’t flow back any of our frac balls on our flow back on that well. As we started drilling out plugs we had sand behind every plug, and we started getting stuck with our tubing on our second and third plugs so we really decided we needed to back out and wait until coil tubing was there.

And coil tubing’s in-country; it’s just getting licensed by the government. You can’t just bring it in and start using it – you have to get it licensed. And we expect that to be completed by about the end of this month so we’re estimating operational and coil tubing about right at the end of August, first of September, and that will facilitate. We’ve had to have that in order to work on these horizontal wells so we’ve kind of been handicapped on that.

But based on looking backwards at some of these stimulations we’ve had a nearly 100% success ratio. I caution that that will predict where we go forward on that but it looks really good right now to us, but…

Neal Dingmann – SunTrust

Okay, lastly Malone, give me an idea of how you see this year wrapping up as far as number of rigs running. And just again it doesn’t have to be exactly specific but just kind of Thrace versus Molla, Selmo, etc., just kind of where do you see the rig count ending of the year and where?

Ian Delahunty

Hi Neal, this is Ian – I’ll jump in on that. We’ll continue to drill with five rigs for the next several months and possibly end one more by the end of the year. Thrace Basin will have two rigs for the remainder of 2013 and the Southeast [Adadash Basin] in addition to Selmo will see three to four rigs for the rest of the year.

Malone Mitchell

Plus we’ll have one rig in Bulgaria that should be spouted in the next 30 to 60 days, so six rigs.

Ian Delahunty

Correct, right. So the Bulgarian rig would make six in the next several months and then we’ll move up. So we’ll stay within that window, and I would also add to Malone’s comments earlier that both technical groups, the Drilling and the Completion – it is similar to a US resource play where you see teams advance when they climb the learning curve. I wouldn’t put the 100% out as a projection but this year so far we’ve done very well on selecting zones we want to frac. We have a better idea of what petro physical properties we want to go frac and that’s been a big step forward, so pretty good work there in trades as you mentioned.

Neal Dingmann – SunTrust

Got it, thank you guys – great color.

Malone Mitchell

Thanks.

Operator

Our next question comes from Curtis Trimble with Global Hunter.

Curtis Trimble – Global Hunter Securities

I wanted to dive in a little bit more on the essential Thrace Basin commentary on the deeper horizons and potential. Is it just a lack of trapping mechanism there that you saw or absence of hydrocarbon? Can you give me a little bit more detail on what you discovered there?

Ian Delahunty

Sure, I’d be glad to. It’s a combination of factors which, you know, it’s probably a little bit more complicated than trapping mechanisms or lack of hydrocarbon. It probably has more to do with when we get to the deeper sections of the basin, what we’ve seen in what is essentially the temperature history of the rock and the data that can be recovered from vitrinite reflectance tests, which essentially is mapping the gas and the oil window, tells us that the center of the basin and the deeper horizon is probably a little bit too hot.

And we’ve also tested paraffinic oil, we tested water. We’ve tested fluids other than dry gas, and without getting into the technical attributes of a deep basin center free gas play it’s probably unlikely that we have that in the deeper sections. There are other plays to chase there; the problem with chasing those plays is that the wells are very deep, the formation is very hot and the costs associated with those wells are very high.

At this time we’re not sure, you know, we’d rather allocate the capital to the southern flanks and Thrace Basin and try to appraise the [Yildurn] discovery; and we’d rather allocate capital to the southeast of Turkey.

Malone Mitchell

I would make a further comment on that. TPAO has just put out I guess a new, I think it’s linked in our website – there was a speech made by the new chairman and it does appear that they’re going to do some additional work. In Turkey there’s not a situation where if we have a well that’s 1000 feet deep it holds all depths and all rights. So unlike the US we’re not in a situation where we’re concerned about we either drill it or lose it on a deep basis.

So at this point in time I don’t think we can conclusively say there’s absolutely nothing there, but at this point in time the results have been disappointing and that’s one of the reasons we went ahead and wrote off the Pancarkoy well in this last quarter even though the expenses were incurred pretty much earlier – it’s because of really the lack of success that we’ve seen on these deep wells.

That doesn’t mean we’re going to lose our rights to the deep. It probably means from our standpoint we’re happy to sit and watch maybe some other people spend some money and see if they can generate results. We’ve certainly spent a lot of money over the last year or two and to date we’ve not really seen any kind of satisfying results out of the deep part of the Basin.

Curtis Trimble – Global Hunter Securities

Good deal, I appreciate the color. And then obviously with so much activity going on, trying to categorize maybe what’s near-term impact, what’s being drilled for what we’ll call maybe a medium-term impact? Can you kind of judge maybe based on the five rigs you’ve got or on the areas where you think the nearest-term bang for your buck is going to be? Is it going to be maybe something that’s more medium-term driven?

Malone Mitchell

Well, the Thrace Basin is all by and large focused. Our cash flow there is focused on development of what we believe are high-probability , comparability cash flow reserves. All of the wells in our well line have a high probability of success. In the Southeast and the Dadas Basin of course our big investment we’re making this year there that we think will really give us a lot of running room is the 3D. We’re shooting nearly 900 km of 3D. Now part of that is on adjacent license leases in partnerships with those companies, and we think that that will have tremendous value for us as we start understanding how to develop those structures and understanding how to develop that geology in that area.

A number of wells we drill in that area will be on structures where we know we’re within the known oil-producing part of the Basin. They’ll have some of these like our Ambarcik oil, our Mardin and actually TP well – we’ve actually changed the name of the Mardin to TP to keep it a little bit more distinct from the Mardin formation. They’re on fairly good sized structures on trend with oil fields that are currently producing, so those if they’re successful will have fairly good potential and we think that we will have evaluated those by year end so that we will be understanding kind of what our 2014 program looks like with those.

In Bulgaria again we’re offsetting the discovery we had in the Deventci-1. Geologically, geo-physically it looks like there’s a lot of running room on our acreage there. It’s been so long since we’ve been able to engage activity there. It came nearly to a standstill in our minds and everything but we’re back going again there, forming a relationship with a group that we think will turn out to become more than just Bulgaria over time who we’re very pleased with.

So all of those projects lead us toward what we think is going to be a lot of future development. Now, we are actively stepping up our activity level in Selmo Field and some of our activity in Selmo, particularly the discovery of commercial oil in the LSD is something new than where we were six months ago. We think we’ve got probably some reenergized plans for what is really a development field project there. Did that answer your question?

Curtis Trimble – Global Hunter Securities

Excellent. I was just looking for a little bit more background and maybe where to look obviously in the near term or will it be something that might be a little bit longer term, so I definitely appreciate the color.

Malone Mitchell

Thank you.

Operator

Our next question comes from Jonathan Fife with KMF Investments.

Jonathan Fife – KMF Investments

Thanks for taking my call. I had a couple follow-up questions regarding the current production levels and I guess the plan exiting 2013. In your release last night you specified current production was around 4000 Boe per day or a little less than 4100 Boe. Just to clarify, did that figure include everything through July and early August or is that an end-of-Q2 number?

Malone Mitchell

That was a spot rate for basically Wednesday’s production.

Jonathan Fife – KMF Investments

Okay, alright. I appreciate that. Looking at your last couple operational updates, that seems kind of in line with where you were at the end of the quarter at kind of midpoint Q2. But when we went back to the July 22nd operational update that particular update seemed to imply some incremental production north of that. I recall I think there were kind of three major areas that were contributing some incremental production. I know that the 25 million gross number out of Thrace after you net out TransAtlantic’s interest I thought implied an increase of about 5 million MGF or around 800 Boe per day; and then there were a couple other contributions from Selmo and Bahar that I thought got us pretty close to the 5000 Boe per day at the current production levels. Can you clarify if those incremental production numbers are off or were those just offset by well declines in the existing production numbers? Or can you help us kind of close the gap there?

Malone Mitchell

Well, net-net-net all the way down – what we report is net of everything, and we have not been back up to 5000 barrels since the end of 2011. Now we’ve been higher and as I said, during the period of time particularly on our gas production, the current takes from the vast majority of our production in the Thrace is to direct plants. It’s not sold into the main transmission line. We only have really one field that sells into the main transmission line and that production is cycled every week based on weekend/weekday, and it cycles during holiday seasons.

And as I said the takes during the end portion of Ramadan are extremely low. It would result in higher production if we were at full takes from the plants. We believe over the course of the next six months or a year we will have largely got away from individual plant takes that are quite as cyclical as they are but we’re not there today. As Ian said, we’ve got a couple of oil wells offline, particularly our Bahar-1 has been offline while they’ve been doing a work over.

I don’t think with all of that restored we would quite be at 5000 but we’ll stick with what we said. I think again based on the activity ramps we will report where we’re at at the end of this quarter, and we’ll very confidently stick with where we said we’d be in excess of it by the end of the year.

Jonathan Fife – KMF Investments

Okay. Just to kind of probe into that a little bit more, it seems like you’re characterizing that as a fairly conservative exit rate whether than a stretch goal or something in between. Is that fair?

Malone Mitchell

It is what it is. We just said what it is and I’m not going to get into trying to change the parameters of that number.

Jonathan Fife – KMF Investments

Okay. Turning to your reserve valuation, I know there was a bump this quarter with some reassessments. Going forward with what you guys have been delivering of late it seems that your recent drilling performance was often coming in productive and under budget. Based on these excesses would you say that it validates the PV10 assessment or does it actually seem to make the PV10 number a bit conservative in your mind given the improvements in execution vis-à-vis maybe the PV10 assumptions?

Malone Mitchell

We believe DeGolyer and MacNaughton is one of the best and more conservative engineering firms in the world. We think they are, just as KPMG is with accounting we think that their answers are something that people can take with confidence versus somebody that you maybe have never heard of. Because a number of our fields are relatively new and a lot of the plays are still developing they’re cautious in looking at reserve form.

We and I certainly believe the values attributed to our proof production and those things represented in DeGolyer and MacNaughton are accurate and if anything probably we are fairly conservative with regard to what we think the potential is. But those are reflected in probable and possible that are presented in our Annual Report. We have not engaged in trying to do contingent resource reports or prospective resource reports so I believe that based on the firms that have hired… It’s not an audit of engineering. They do engineering.

We do have a much upgraded Reservoir Engineering Group within the company now and I think that we’re going to be able to better, more timely appraise some of the things that we’re doing on a more accurate basis. But if you can find a better engineering firm than DeGolyer and MacNaughton please let us know. We think they’re the best.

Jonathan Fife – KMF Investments

We would agree. Given the I guess rather conservative and believable estimates within the PV10 estimates or evaluation compared with the dislocation of the current equity price I was wondering if you could comment on your perception of the company’s intrinsic value in relation to its current price and if there are any prohibitions preventing management from more aggressively buying shares on the open market?

Malone Mitchell

You know, we believe that the reserves, and this kind of value of the reserves. And purchasing, selling companies, you look at the reserve value, you look at the potential. I think that obviously we’ve had a hard time both arresting production decline and growing production. We’ve set out a plan to do that by pivoting. We think that the prospects that we’re drilling on both on a developmental basis as well as more or less a developed cat or exploration are well warranted. We think the value of the company should be higher.

One of the reasons that we disclosed the change in reserves, although it’s an immaterial GAAP number is so that there was no inside information with regard to the company. As far as the purchase of assets, purchase of interests I believe that if you’re referring to me I probably own a greater percentage of a public company than nearly any other CEO out in oil and gas land. I think all of us are pretty optimistic about the company and I think that we feel the value of the company is greater than what the shares reflect.

Jonathan Fife – KMF Investments

Okay. I know in quarters past, over the last ten to twelve quarters, Malone, there have been certain quarters that you have been very emphatic about that gap and very emphatic about exploiting that to your own advantage. We appreciate that and it’s one of the reasons we’re aligned to this investment opportunity is because of the owner/operator nature of TransAtlantic. We’d be interested in kind of hearing more of those comments from you and then seeing actions from the other management team kind of demonstrating their view of where’s the best place for their personal capital. We haven’t seen that over the last probably three to four quarters as much as we did maybe in ’11 and ’12.

Malone Mitchell

I’m probably in different financial condition than many of the other members of management and I am building a refinery in Florida which is chewing up a bit of my capital right now. [laughter] So as soon as I get through building that refinery I will be a little bit more flexible in my financial aggressiveness.

Jonathan Fife – KMF Investments

Has there been anything that’s prevented other than just financial availability individually, is there anything that’s prevented the other members of the management team from exploiting what seems like a very cheap opportunity in the marketplace?

Malone Mitchell

You know, most of the other people in management, I’ll let them speak for themselves, are in their early 30’s with families and you know, they’re young in our program. I think they’ve invested their capital and I think that if you look at our salaries and what we pay I don’t think that you’d say we overpay everybody. So I think that within regards to where and what they make I think that that’s a pretty aggressive stance that they take, and we also compensate our people with restricted stock units so they are accumulating ownership in the company.

Wil Saqueton

This is Wil. The only other thing that I’d add to that is because of the delays we had in filing the (k) and the (q) this year it’s extended the blackout periods in which management can actually purchase shares. So there wasn’t a large window available this year as there has been in prior years. So for this cycle I think our blackout lifts on Monday, so that’s the other piece I’d like to add.

Jonathan Fife – KMF Investments

Great, thanks Wil. Given we think there’s a lot of potential with TransAtlantic we’ve been shareholders for several years and kind of lived through the hiccups of late ’11, early ’12 and are looking forward to the production ramps in the back half of ’13. And we’ll look forward to that success over the next couple quarters.

Malone Mitchell

Thank you.

Operator

Our next question comes from [Doug Shroegel] who is a private investor.

Doug Shroegel – Private Investor

Hi, congrats guys on the improved pace and efficiencies you’re demonstrating. Ian, I had a question, and Malone may have answered part of this already. Can you tell us any insights of what we learned with regards to Bahar-2H down in the Bedinan and the challenges that we face there?

Ian Delahunty

Sure, sure. We certainly learned that the control on some of our structural mapping is probably not at the resolution that we would like to drill horizontally. We were pretty encouraged by where we saw most of the formation tops coming in in Bahar-2. We saw basically what we wanted to see, and when we kicked out on the lateral we drilled along a fault and it’s very difficult to steer out of a fault and it’s also very difficult to ascertain what lobe of the sand or the shale we’re in.

So I think the lesson that we took from Bahar-2 was let’s get a little bit more mapping resolution before we drill horizontally in the Bedinan. It’s something we still want to do. It’s clear that the economics associated with going horizontal in that sand with the permeability of the Bedinan is better than drilling vertically. That being said, if you can drill a vertical well for $3.5 million, you get a one-stage frac and it IPs at 600 barrels a day that’s fantastic. I mean those are phenomenal economics.

One of the questions earlier was “How do you apply lessons learned from North America to what you’re doing in Turkey?” You talk to any shale completion or reservoir engineer and what you will hear again and again and again is that they wish they would have gone bigger faster earlier in the life of the play. In any play in the US, the answer will be “I wish I just would have ramped up earlier.” And so it was a prudent decision for us to try that in Bahar-2, and we’ll try that again but we’re going to do that after we get the seismic.

Malone Mitchell

One of the things that I think we’ve mentioned on the deal, there’s actually in the Catak well, we’ve drilled that well a little deeper in the section of the Bedinan than the previous wells, and our Ambarcik well is actually going to go down we think to the base of the Bedinan to a reflector we see down there. In the Catak well we encountered six different horizons of Bedinan sands interspaced with shales.

Our target objective in the producing interval has been the first sand but when we came out at the Bahar-2 I think it’s harder to discern what shale and sand sequence you’re in. In the Catak well we had oil shows while we were drilling in the first and the third sands but not the second sand. So again, it’s still a little bit hard for us to tell. If you come out an you haven’t landed exactly where you need to be it’s hard to tell whether to go up or go down, and that may seem like a hard answer but that’s the case because in some of the cases the shale signatures look pretty similar.

And that’s one of the reasons we took and we cored, cut three cores on the Catak well. We’re trying to get a little better petro physical evaluation, understand the rock a little bit better so that we can understand some of those things.

Doug Shroegel – Private Investor

Thanks. Malone, you gave some direction with regards to working out a JV with a group in Bulgaria. There’s been no further advancement at the Board level or seeing that with regards to a JV in the southeast. And you made a little bit of a reference with regards to a group in Bulgaria that you’re looking at JVing with that might have additional interest elsewhere. Can we extrapolate from that that that would be down in the southeast?

Malone Mitchell

No, I don’t think so. As we’ve said we’ve now gathered some additional information, we’re now fairly well along on our seismic with regard to what we’re shooting up in the Bahar area so it’s still a matter of… I don’t think that that’s an accurate assessment. The direction we’re working is still on two different lines with different groups.

Doug Shroegel – Private Investor

Great, thanks.

Operator

(Operator instructions.) Our next question comes from Jamie Somerville with TD Securities.

Jamie Somerville – TD Securities

Good morning, guys. I just wanted to clarify on your current production and then your guidance for the exit from Q3. Is the difference between those two mainly the impact of Ramadan being there? Or maybe you can quantify what is the actual impact of Ramadan roughly or is the difference between those numbers roughly 300 barrels a day, is that just steady progress on the drilling program towards your 5000 barrel a day exit target for the end of the year?

Malone Mitchell

Part of it is Ramadan and part of it is disconnection of wells. As we’ve stepped up our pace we also have to connect the wells that we’re then drilling and completing, and execution against the activity level towards the end of the year. But we are trying to be conservative in the numbers that we’re putting out.

Jamie Somerville – TD Securities

Okay, thanks. Does that mean I can think about Ramadan as having an impact of about a couple hundred barrels a day on your sales?

Malone Mitchell

Yeah, for a period of time. It accentuates and it becomes more severe. In this week it may very well account for over 1000 barrels a day or greater.

Jamie Somerville – TD Securities

Okay, perfect. I probably shouldn’t need to ask this but your exit rate of 5000 Boe’s a day at the end of the year, that is net after royalties, right?

Malone Mitchell

Yes, we report on a net-net-net basis. Obviously many companies report on a net working interest basis. Some of our partners that are public companies I think report on a net working interest basis. So many US companies report that way. We’ve chosen to report the lowest net number.

Jamie Somerville – TD Securities

Yep. Then just thinking about some of these horizontal wells, and I think this question is maybe too early because you’re still working on the Selmo-13H well and trying to figure out the optimum pump configuration. But can you talk about what you actually expect or what are you targeting in terms of IP rate UR from these horizontals in Selmo?

Ian Delahunty

Hi Jaime, good to hear from you. You know, the two formations are very different. The MSD and the LSD have different characteristics. The LSD, we really didn’t know. I think we said in an earlier call, I remember Malone mentioning the well could do a huge amount of [fluid] or it could be a lot of oil or a lot of water or a mixture, and that’s essentially what we have. The IP we saw on the Selmo-13 was about 500 barrels of oil per day with a lot of water.

And I think Selmo is an engineering play for the most part, and what we’ve done this year as I said on the 24th is remodel the field into kind of a dual-porosity model to figure out where you’ve got dolomite porosity and then take advantage of it. In the LSD, there’s so much pressure left in Selmo and the oil/water contact has moved so little over a 40-year course in the history of the field that what we needed to do was demonstrate that it was possible to drill in the LSD above the current oil/water contact. And that’s what we demonstrated with the Selmo-13.

It’s not on the structurally highest place in the field. It’s not in the structurally highest fault block in the field but it’s a commercial well. So there is certainly potential that other Selmo LSD wells will have similar or higher IPs. There’s potential here that what we need to do in Selmo is move a lot more water and draw down these LSD horizontals more, and those are things we’re evaluating now as an engineering group.

Now when you go up hole to the MSD, that’s a tighter dolomite and those won’t be open hole completions. Those will be controlled stimulations. So I think we’ve come up with a pretty good risk IP of what we expect to have on these first two horizontals we’re drilling now. I say two because we’re drilling two off the same pad. But yeah, we don’t know to be honest but we expect the economics to be far better than what they are for a vertical well in the MSD.

I would also add that we’re looking at Selmo. Again, if anything we’re more encouraged by some of the reservoir engineering work we’ve done on the tail end of the geologic remodel because there’s a lot of oil left in Selmo. And as I’ve said before the global average for fields of that nature, fractured carbonate on secondary recovery is around 32%, 33%. Realistically we’re sitting at about 10% recovery in Selmo now.

So you know, Jonathan asked the question earlier “What are you doing to close the gap between production and reserves?” and that’s the way to close the gap. There’s a lot of potential there and it’s been bypassed from the standpoint of doing infield campaign. So I think to answer your question on the horizontals, yeah – lots of potential. We don’t know what the IPs are going to be but we feel this is the best way to develop the field and then in parallel we’re looking at flank pressure support, flank sweep efficiencies, things of that nature.

Malone Mitchell

From a pure production model standpoint we modeled the horizontals to produce both on a reserve and an IP basis exactly what a vertical, a single vertical well would. And we had modeled the LSD well to be dry. So we certainly expect the answers to be better than that but that’s what we built our models on what we think our production will be and what our reserves will be.

Jamie Somerville – TD Securities

Thank you very much. I’m obviously going to be very interested to see how your assessment of these wells comes out over time. Thank you.

Malone Mitchell

As will we.

Operator

And I’m not showing any further questions at this time. I’d like to turn the conference back over to our host for closing remarks.

Malone Mitchell

Well thank you again. We encourage you to contact Taylor Miele for any ongoing information and to check as we expect to post on the 14th or the 13than updated presentation with some maps and activity. So thank you for your time this morning and please have a good day and a good weekend. Bye.

Operator

Ladies and gentlemen, that does conclude today’s presentation. You may now disconnect and have a wonderful day.

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