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TransAtlantic Petroleum (NYSEMKT:TAT)

Q1 2014 Earnings Call

May 09, 2014 8:30 am ET

Executives

Taylor B. Miele - Director of Investor Relations

N. Malone Mitchell - Chairman and Chief Executive Officer

Wil F. Saqueton - Chief Financial Officer, Principal Accounting Officer and Vice President

Ian J. Delahunty - President

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Jonathon Fite

Dougie Youngson - finnCap Ltd, Research Division

Jamie Somerville - TD Securities Equity Research

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2014 TransAtlantic Petroleum Earnings Conference Call. [Operator Instructions] As a reminder, this conference call may be recorded.

I would now like to introduce your host for today's conference, Taylor Beach, Director for Investor Relations. Please go ahead.

Taylor B. Miele

Welcome to TransAtlantic Petroleum's First Quarter Earnings Conference Call. On the call today, we have Chairman and CEO, Malone Mitchell III; President, Ian Delahunty; and Vice President and Chief Financial Officer, Wil Saqueton.

During today's call, we will make forward-looking statements, which include statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that there are a number of factors that may cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings press release, which we issued yesterday, and the company's SEC filings. Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

Now I will turn the call over to Malone Mitchell.

N. Malone Mitchell

Thanks for taking the time to take the call this morning. As noted in our release, we're pleased to have finished the new credit facilities and extended our debt maturities. While the quarter showed improvement from the prior quarter and year-over-year quarter, it was frustrating with essentially fewer oil completions from those at year end, in early January until near the end of April as we do the drilling complications. Likewise, we are not yet finished drilling the well through our Molla 3D mapping to confirm geological fix in our Bahar field. While [indiscernible] zones matched our mapping, the Bedinan was not reached before we got stuck and again had to sidetrack.

Also in our release, you would note that we are discussing a much smaller transaction in Poland, which matches the portion of San Leon and Hutton's acreage, which fits our risk parameters.

I will now turn the call over to Wil Saqueton and be available later for questions.

Wil F. Saqueton

Thanks, Malone. Before I discuss our financial results, I would like to briefly walk through our new $150 million credit agreement to refinance our existing reserves-based loan. This is a 5-year facility with an initial commitment of $80 million and commitment reductions deferred until the second quarter of 2016.

The initial borrowing base is $78 million and still provides $28 million of additional credit capacity during the initial period. Our borrowing rate is 3 months LIBOR plus 5.0%, which is 50 basis points lower than our borrowing rate on the expiring facility. As a result of this RBR refinancing, we have reclassified $23 million of short-term debt back to long-term debt as of March 31st.

We are pleased to continue our relationship with BNP Paribas in this new credit agreement, and to welcome IOC as a partner in our credit financing arrangements..

Now on to our first quarter financial results. Our average net sale volumes were 4,622 barrels of oil equivalent per day, which is up 5% from the fourth quarter. We generated net income from continuing operations of $4 million or $0.11 per share compared to a net loss from continuing operations of $14.4 million, a 39% [ph] share in Q4.

Adjusted EBITDAX from continuing operations was $21.9 million, up 5% from the fourth quarter. Discretionary cash flow was $21.4 million or $0.57 per share. Our CapEx from the seismic expenditures were $26.1 million, down 15% from the fourth quarter. And as a result of the items above, total net cash consumed was $4.7 million, down 55% from the fourth quarter.

In January, when the Turkish Lira was volatile, we borrowed $6.7 million on our yuppie [ph] credit line reserved as cash capacity. As of March 31, we still had approximately $4 million of this draw in our ending cash balance.

I'll turn the call over to Ian.

Ian J. Delahunty

Thanks, Wil. Thanks, everybody, for joining us on the call. I'm going to add some details to Malone's initial comments on our operational highlights.

The first quarter, the company spud 8 wells and entered the pilot phase of 2 projects at its Selmo oilfield. Those 2 projects are the pilot waterflood and the polymer treatment pilot. We also initiated testing on the Bulgaria well, Deventci-R2.

Starting with the Southeast of Turkey, we spud the S-64H1, the S-86H1, the S-84H1 and the S-92H1, and most recently, we spud the S-54H1.

We initiated the first phase of Bahar development with a sidetrack operation at Bahar-2.

I'd like to add a little color to the lag on new well production and also on our drilling activity. In Selmo, the S-86H1 and the S-84H1 are waiting on completion while the 2 LSD horizontal wells we drilled earlier, the S39 and the S64, will require higher artificial lift capacity and therefore, are on a limited production test. We recently took receipt of the higher capacity ESP and will hopefully have those in the whole within 1 to 2 weeks.

The 2 MSD wells that I mentioned, which were the S-86 and S-84, are both wells which were designed with complex targets and trajectory to test untapped fault blocks. The S-86 took much longer than was anticipated to drill and is the primary reason why we have not added new well production in Selmo, with the exception of the F2H well.

On the polymer treatment project, we have seen about a 250-barrel per day increase in the 5 wells included in the pilot. We are currently in design phase for second stage of work on additional wells and we'll look to reduce the cost of these jobs significantly by using tanks and equipment fit specifically for the treatment process.

We continue to monitor the waterflood injection on the first pilot. We have nothing new to report there. We're still on observation mode as expected.

Coming back to the Bahar-2, it continues to be a bit more difficult than we initially anticipated due to geology and the deviation of the hole. We're optimistic, however, about the level of Bedinan mapping after the initial drilling phase and the structure itself and our proceeding with the Bahar field development plan, we anticipate spudding the top of structure Bahar-3 well and -- on May 15 and we'll drill 2 rigs in Bahar for the remainder of the year.

In Thrace Basin, we spud 2 Mezardere horizontal wells, those were the TDR-11H and the BTD-2H. We're currently cleaning out the TDR-11H for coil tubing following its initial production test phase and hope to see increased production following the cleanup. At this point, we're still evaluating the performance of both wells but are confident that the BTD-2H is the first commercial Mez siltstone well, also first to be drilled in the basin and that the TDR-11H will require additional production observation.

To give you an idea of why we perform long-term production tests and observation periods, the 2 attachment core wells we drilled in 2013 have now been confirmed to have estimated ultimate recovery of about a BCF each. And we see those as very positive confirmation of the viability of the attachment core and horizontal play. And we'll move into new phase of drilling this year starting in the summer.

In Bulgaria, we tested the Deventci-2 well by jetting out the open hole section -- sorry, the Deventci-R2 well by jetting out the open hole section of the [indiscernible] and by perfing it behind the piped section of the [indiscernible]. We saw gas and gas condensate at rates in the range of 1.5 million to 2 million a day and are moving forward with pressure buildup operation to evaluate for new wellbore skin damage. Following the determination of new wellbore skin, we look to perform an acid wash or an acid cleanup on the wells to increase the production.

N. Malone Mitchell

Thank you, Ian. Follow-up to our Molla area 3D seismic, as was noted in a previous release, we completed the acquisition of that 3D in early April, in about April 7, and that's now at processing. We received in our mapping on the first and second stage. The third stage of that will be received about the end of June according to the processor's schedule. And that process block will include the acreage that covers Göksu field and Molla field. We, at that time, expect to be able to map and then begin some development within the Göksu area. So with that, we will take your calls and questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question will be coming from the line of Neal Dingmann from SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Well just your thoughts on -- it looks like that if you said that you ran a little behind on the Selmo area, how do you, I guess, as far as run a rig or so there versus the injection program, how are you going to balance that out? I mean, do you wait and see kind of the results you're going to get from the injection program? And I guess the question is how much could that ramp things for the remainder of the year, should we think about a rig or so remaining there? I'm just wondering how you're going to sort of tackle Selmo for the remainder of the year.

N. Malone Mitchell

Well, thanks Neal. We will have a rig remaining there. I'm going to let Ian address the injection and the polymer. On a simplified basis, as we drill wells, we're drilling wells basically perpendicular to the major fault system in Selmo field. And what we found is we crossed those faults and in a lot of cases, the faults were small enough that we could not identify them from seismic. But they had enough throw that they would throw us again out of the -- we didn't really have difficulty drilling our Lower Sinan Dolomite wells. Those wells have fairly large water cuts and good oil cuts if you move the fluid. The MSD, the upper zone, which is just below the shale, which is a fairly unstable shale, is a thinner interval. It's a 30- to 70-foot interval. And what we found and what had really ate us up in the first quarter in drilling wells is as we crossed one of those -- as we would cross faults, if we crossed the fault and the block we went into was upthrown, we really didn't have a problem. We could steer back up into it. But if we crossed it and we went into shale, the shale is so unstable we were losing the holes. And it was resulted in us having to back up and whipstock and kind of second guess that. So what we've done right now is we have moved to drilling a series of wells because we have found oil far, far, further down, I think, in our block than our original mapping last year had expected to find oil on some of our tests. So we're drilling wells basically parallel between the major faults in the field. And we're not dependent upon a cross fault structure like you would in maybe the Mississippi play or something where you're trying to drill perpendicular. We're really looking at more a matrix flow there. If we can drill a few of those wells and have a lot less trouble than we have had on the last couple of wells that we've drilled, then we can pick the pace up further there. But these are some of the first wells that we're drilling intentionally in that manner. And we just need to back up a little bit and see that we can have a lot less mechanical difficulty on drilling our wells. And I'll let Ian go over the other aspects of what we're doing in Selmo.

Ian J. Delahunty

Well, I think that was a very astute, accurate summary on Selmo at -- on the drilling portion. On the 2 injection programs, the first is the waterflood pilot through the Middle Sinan Dolomite and the LSL well. We're going to continue to inject at S19. We're ramping up to start another pilot elsewhere on the field. It's difficult to, at this point, forecast water bank hitting the first producers. The polymer treatments were something that we had played around with for quite some time and finally got the -- got a few wells that we wanted to try it on. It's essentially a way to turn high water cut wells into lower water cut wells. And we see from the first 5 wells that we produced quite a bit more oil than I think we initially anticipated. So the costs were a little bit higher. I think you'll note on our press release, we said we've spent about $1 million. And that [ph] is probably $500,000 more than we'd like to spend on a 5 hole like that. So we'll try to get the cost down. And surely, in a fractured carbonate system like Selmo, every producing well is a candidate for this treatment. On the rig, I'll add a note that coming off of the interpretation of the 3D seismic in -- on the Bahar structure, we feel much more confident at the Bedinan level mapping. And for us, it's -- that's our -- as we stated, I think, on every public occasion, that's our strategy for growth. And so we moved the second rig into the Bahar field and we'll drill, as I said, Bahar-3 and then we'll drill a delineation well, essentially down dip of the Bahar-3 and the Bahar-1 to try to prove our reserves going toward that side of structure. And we'll continue to drill with one rig in Selmo and we'll likely target the sort of untapped southeast part of the field.

N. Malone Mitchell

Again, we need those wells to be about 20- to 25-day wells. And in the first quarter, we had -- probably our average well time was in excess of 60 days because of well problems. And that's impactful from both the timing of production, as well as the cost of oil basis.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Got it. A good summary there. Just wondering on obviously, going back up to Thrace now. Ian, your thoughts now, obviously, when you run the coil tubing, just trying to get an idea -- sense of what the potential is there obviously, when you go after the multi-horizons there. Again, trying to get an idea, obviously, you had the prior sort of flat campaign there. And now obviously after running the seismic, just wondering now that you've gone back and it seems like most of that seismic shoot is done, Malone, if you and Ian can kind of comment on just sort of the perspective or the size that you -- kind of what you're anticipating now for that area?

N. Malone Mitchell

The seismic is over an additional area. The seismic is over a field area that's called Osmanli. And we're still in the process of interpreting it. We think what we'll find there will be incremental to the recent horizontal wells that are in Tekirdag that are covered by an earlier 3D. So as far as running room and Tekirdag.

Ian J. Delahunty

Yes. We feel, obviously, confident about the touching quarter [ph] results and plan to drill 4 to 8 additional horizontals there this year. We felt confident with the budget numbers that we put out early in the year in January and it's likely we'll stick to those numbers. On the Mez siltstone horizontal very early on and as you said we'll see what they'll do after this cleanup operation. But we anticipate picking up a rig in the summer and picking back up in Thrace and shoot and drilling some sheet verticals off of this 3D with a shot of well.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. Then just lastly, Bulgaria with that well test about 2 million a day with condensate. Is that about what you were expecting there? And then I guess the other question is, in the press release where it talks about having to get that request from the government approval for -- to stimulate a well. Is that typical, I guess, in Bulgaria and is there going to be some delays because of some government difficulties there? How should we think about sort of activity in Bulgaria going forward?

N. Malone Mitchell

I don't think that the 2 million is much different than what we see off the records of the old wells that are there. Typically they're perforated and then acidized a number of times. So we've now -- we would expect to go back and acidize. I think it's safe to say that nothing is typical in Bulgaria. There is a frac ban in place. It's our intention to deliver the buildup analysis with an estimation then from the scan and the buildup as to what -- from the part of the zone that's been contacted by just perforating. What we expect, post-well, to do after doing an acid cleanup or really an acid job on the well the way we would tend to typically think of it. And that's historically been the way wells were completed in Bulgaria. So we certainly expect it to do significantly more in the flares and shales [ph] we saw while drilling certainly indicates that it's got the capacity to do that. How long it takes the government to respond to that? We don't really have an idea. The government wants production. The entire -- political environment everywhere over there has placed a greater emphasis on energy production from domestic sources. But we don't know whether that will be 2 days or whether that will be what exactly that time period is. We don't certainly think that this represents anything like what the time period it took when we were initially negotiating the licenses for that. We think that they'll be responsive. And this is, again, a simple process. It's been done many, many times in the country. It's really the historical stimulation method in the country. We just want to make sure with the wells that are in place that we are clear to go on all of that.

So -- and 2 million a day after perforating is not so bad.

Operator

Our next question will be coming from the line of Jonathon Fite from KMF Investments.

Jonathon Fite

At year end, the company was producing at around 4,400 BOE per day and we are pleased to see that run-up to 4,700 and drop that down to about 4,600 and now we're back down around 43. Is that decline largely due to your efforts to take some producing wells off-line to help fuel the injection programs?

Ian J. Delahunty

Well, as I said earlier in the -- hi, Jonathon, by the way, in the ops update. We've got 2 MSD wells sitting and waiting on completion right now. And...

N. Malone Mitchell

LSD wells.

Ian J. Delahunty

And MSD. Yes, 2 MSD wells waiting on completion with the 86 and 84. And 2 wells, besides the 92, before that, were LSD wells. And what happened with those is we modeled them off of the Selmo-13H and put it online and found that we needed to run some larger lift equipment.

N. Malone Mitchell

Yes. Really on -- our oil production from that time period has stayed relatively -- are all up result and this is April we're actually we're back up because we completed oil wells right at the end of April. Our oil production is off about 3%. Where our gas production is really where some of the decline is. And we have announced all year long that we would kind of underspend in the gas area relative to what our normal offset is, so gas was off about 11%. What we didn't get done is we didn't get enough oil wells completed because we projected the growth in oil production in Southeast to be far greater than what we had as a decline in natural gas. And we have to get that done. We projected we would have -- we would obviously have Bahar-ST on and we projected we would have more oils in Selmo on. So we're behind as a result of drilling that and that's -- that's resulted in that. As soon as we complete these additional wells, we'll see an increase. But we really need a faster production rate -- time from spud to completion in order to stay on schedule. Our production rate with regard to kind of our forecast development of natural gas is pretty well on plan for where it was going to be. We'll see an increase in the summer and then another tail off in the winter as we go through drilling this kind of a summer campaign on gas. But we have to be able to get to where we can drill -- drill wells faster in the Southeast. Production is a function of getting enough wells drilled and completed to match that. It's not that we drilled bad wells. It's we simply didn't get enough wells drilled fast enough. We didn't drill bad wells with regards to cost and time, but not with regards to the completion or the outcome of the completed wells.

Jonathon Fite

Okay, let me turn to your...

N. Malone Mitchell

One clarification probably from [indiscernible] or an expansion on the potential of the polymer, when we talk about the number of wells and kind of the number of wells that you're calculating. The polymer, based on those costs which we believe can be cut about 50% of payout on those polymer treatments, as a batch -- is about a 60-day payout based on the 250 barrels a day and the CapEx. So we're just nearly there on evaluating that. We do like to see production rates go through a period where we're confident on what the ultimate recovery is going to be. And we're not going to see some sort of a failure there. What we are working through a significant additional series of wells. As Ian said, literally the whole field kind of benefits from that particular technology as well.

Jonathon Fite

Sure. Let me turn to those waterflood initiatives or those injection initiatives at Selmo and Arpatepe. Specifically, in Selmo, if these initiatives are successful, can you specify additional impacts to your reserve profile? Based on our estimates, we think that the Selmo efforts could potentially double the existing crude reserves there. Are we framing this opportunity in the right ballpark?

N. Malone Mitchell

Well I think it's important to observe the pilot response. As I said, it's clearly a reservoir that has a lot of remaining barrels in it. And it's a great candidate for secondary recovery. Beyond that, I don't know if we could say for certain what we think it's going to happen to recover back on the field. We estimate the field is currently at a 12% or 13% recovery factor. And you'd see something obviously, much higher with a properly applied secondary recovery project. I suppose I'd encourage you to look at our P2 and our P3 numbers in Selmo. And you'd look to see some of those transfer over to the P1 category pretty quickly.

Jonathon Fite

And on the same lines, how should we think about the benefits of the Arpatepe project? What reserve profile is that targeting and how should be frame those prospects?

N. Malone Mitchell

That project actually, I didn't really speak to Arpatepe. But we just drilled an Eastern Arpatepe field well on the east side of a fault system that we hadn't looked at. So this well which was just drilled, the Arpatepe-7, had oil shows while drilling a larger [ph] positive and it was DST. So we anticipated it's probably early days to put out a production forecast. We think it's going to be as good as the Arpatepe-6, and are actually quite enthusiastic now about that side of the field. We've got another well to drill there in the coming months, which is the Arpatepe-8. And David [ph] I guess gives the call an idea on what Arpatepe-6 did and you're looking at 300 to 350 barrels per day IP on the well.

On the waterflood, it is a fantastic candidate for a sort of a flame conjection [ph] project because it's closed by faults and it's closed by structure. And we have a wellbore, which we could inject water into the Bedinan. That's relatively high perm stuff, and probably we'd see the impactful production. And the economics on the waterflood there are phenomenal. I think we forecast something like $35 million of return for about $1 million to $2 million of investment. The issue with Arpatepe is -- it will continue to be the fact that our partner there is not as comfortable with technology as we are. And so it's going to be slow for us there. I thought we would probably get a well cored there this year, take a look at the core, get the service facilities planned, get them designed and implemented. That hasn't been the case. And that's largely due to our partner in the project. So we'll continue to push there and, hopefully, get the work done on Arpatepe-8 that we need to design the waterflood and then get the first injection into the ground toward the end of the year, early 2015.

N. Malone Mitchell

The Arpatepe-7's success, again, that well sat across a fairly significant fault that we mapped, that divided the field. We've not had, subsequent to the drilling and logging and testing of that well, a joint meeting with the operator. We own 50% of that license, 2 other parties own 20% and 30%. And the 30% owner is the operator. We've got to have a follow-up meeting that obviously is encouraging a broader expansion of that field and that would play into both primary and secondary recovery in that area.

Jonathon Fite

Okay. Moving on to Molla. Your past comments indicated that with the 3D seismic in hand, the hit rate on the Molla well should improve substantially. Can you guys discuss what insights have been obtained from the seismic so far and when we might see a full well by well drilling plan for the back half of '14?

N. Malone Mitchell

So far, the 3D, the mapping that the geologist put out with regard to the Bahar was really pretty well spot-on all of the way down, we literally got stuck and we've got -- we've been stuck twice on this well that resulted in additional sidetracks. Both times we've stuck and end up in the nonproductive section of the Cretaceous, at about 7,900 feet where there's a zone that just has fairly unconsolidated, large pieces of limestone and chert that have fallen in and stuck the drill string, as far as the tops of the Hazro, the tops of the Dadas, the tops of everything we expected. And we're drilling this well from a surface location to a bottom hole location close to half a mile away. All of those tops, as we expected them, came in absolutely within the tolerance of what we were expecting based on our 3D mapping. Unfortunately, we got stuck right above -- within literally about 30 feet of where we expected anticipating the Bedinan. One week ago, Saturday night, we were unsuccessful at being able to fish the string, we've already set a plug, kicked off and are going back in to re-drill that. We're going to case through that section of pipe. We typically case through that on our intermediate string of pipe on our vertical wells. So we've not had a problem on our vertical wells -- a significant problem on our vertical wells with this particular horizon. And it took a little bit of time to diagnose exactly what the problem was because you can diagnose it as being something else. We're going to set -- because we're milling a window in the 9 5/8-inch casing. We're going to set a 7-inch liner to about 8,200 feet across that interval and then continue on drilling. We really had no problems drilling below that. But again, you would have -- when you'd shut in, you would have just essentially the equivalent of a 2-inch diameter gravel falling on you from above. And again, on a typical vertical well, and we're accelerating. We'll probably drill another vertical well or 2 in Bahar field to make sure we're comfortable with handling that horizon on planning, coming up to 3D. But so far, the mapping is good. As Ian said, we'll spud another rig in Bahar here, this coming week. And so we'll see what -- how we do with our tops there. Again, it's not a matter of we drilled a bad well. And frankly, the drilling issues with Bahar-2, when you accumulate them altogether, probably has had more sidetracked sections in it than at any other well I can remember in my career.

Jonathon Fite

And so when we look at the rest of the seismic being processed and your CapEx plan for Molla in the back half, is that CapEx really targeting the 5.5 million barrels of probable reserves in Molla and kind of converting that into proved status?

N. Malone Mitchell

Yes, we actually believe, and we will update in our -- we will have a budget meeting, a midyear budget meeting with our board just after our annual meeting this year and look at first of the year versus second of the year. It's our intention to drill Bahar in a manner that we can basically bring on to the books the reserves that we see throughout that structure. Today, we're limited on proved to only the offset wells to the Bahar-1 on pretty limited basis. So we expect to drill kind of -- to delineate that entire structure this year.

Jonathon Fite

And then is the little over $7 million tied for exploration in Molla resulted in any new kind of reserve categories?

N. Malone Mitchell

I don't know that I understand your question there.

Jonathon Fite

I think earlier in the year, you'd released a CapEx plan and kind of outlined how much CapEx is targeted at what production profile. And there is a large chunk of CapEx targeted at your probable reserves in Molla, but then there was another $3 million, and that was labeled exploration, kind of just pure well cutting on things that aren't necessarily tied to any existing reserve profile. I was wondering if any of that spend has resulted in any...

N. Malone Mitchell

Yes, that's -- well, part of that was we had a remaining budget in seismic. We have identified additional structures. And we do expect to drill at least 1 or 2 additional wells that are not related to the Bahar field within Molla. We also expect to drill wells in the Goksu area but not until we have the 3D back associated with that. So...

Jonathon Fite

And then finally, I guess can you walk us through the production bridge that gets us from kind of the 4,300 today to the 6,500 target at year end. I'm just trying to understand if that largely rests on your efforts in Selmo, PUD conversions in Thrace or the new oil finds in Molla or is that kind of a mix of all of the above?

Wil F. Saqueton

Yes, Jonathan, that's a good question. So on the P2 volume, we anticipate something larger than 5.6 million remaining in the Bedinan of Bahar. I mean, I think a 5.6 P2 is actually spread across 2 horizons. So getting the 3D done on Bahar, the structure, it's much larger than we initially thought. And right now, we've moved a second rig into the field. And we anticipate those wells coming in as high as the Bahar-1, which essentially did 500 or 600 barrels per day. So for us, the highest sort of priority is to develop the Bahar field and drill with 2 well rigs there. And we should see, if we are correct about the geologic mapping of the Bedinan as it relates to the Bahar-1, we should see very linear production drills from that field. If you take a look at the analog production curve at Bahar-1 and then stack a 2-rig campaign, it is very doable to bridge the production gap. Second to that, we are going to drill continuously with 1 rig at Selmo. And we think that, that will build production, not only maintain the current production rate at Selmo. And so we see our production gap being bridged in the Southeast, and we look to see gas with some growth starting in summer. I hope that answers your question.

Operator

Our next question will be coming from the line of Doug Youngson from finnCap.

Dougie Youngson - finnCap Ltd, Research Division

I have 2 questions relating to Toreador. In your opening statement, you said that you think this is going to be a much smaller transaction. I was wondering if you can give me a bit of guidance as to what the transaction might look like in the future. Secondly, you mentioned that there may be an element of discomfort regarding the risk profile of these licenses. Could you give me some more information on what perceived risks you've identified during the DD process?

N. Malone Mitchell

Well, I can tell you that our objective, we are continually looking at what would be suitable projects for TransAtlantic. And those are easily defined outside of the projects that we have in hand in Turkey, is to restrict ourselves to projects that we believe have very much a known petroleum system and that really what is needed is the application of horizontal drilling and/or stimulation, multiple stimulations. We are not looking to enter into transactions or acreage that have a significant amount of exploration where it's not a matter of an identified oil or gas pool that can be -- that needs to be exploited. And I think that's probably the best way to discuss that. We think that when we looked at that original area, some of the area fits that and some of the area does not. And it's a better use of our capital and a better use of our focus to focus on that part that we think we can get in and we can work a continuous program and be profitable and impactful for all of the companies involved. As far as the size or nature of that transaction, that's not something we can discuss on the call. And as we declared in the early release, which was a response to a release from San Leon, we do feel like we've done a significant amount of due diligence both on a legal and a geological basis. So we do feel like we're at a point where we're now in a point of not needing to do a lot of due diligence. It's a matter of determining if there's a transaction that fulfills the needs of both parties. And today, I cannot give you an answer whether that will be achieved or what the size of that or what that will look like. As we -- if we have more definitive answer on it as to either a positive or a negative outcome to that, we will then announce that.

Operator

[Operator Instructions] Our next question will be coming from the line of Jamie Somerville from TDC (sic) [TD Securities].

Jamie Somerville - TD Securities Equity Research

Most of my questions have been answered. I just wanted to follow-up on the Molla area. The Catak well, very briefly, can you explain why -- what happened there? And why it's potentially not relevant?

N. Malone Mitchell

Yes. When we had -- we drilled that well and had shows when we tested the well, we had about 40% oil cut, but at fairly low rates. After we got through running our 3D, what we found was that the Catak well had wound up in a position where it was kind of between these field structures. It's not really on one of the structures that we see now with the 3D. I don't think it's -- I don't think you can say that we understand everything we see on a 3D basis. There's probably -- and one of the things that we think we'll ultimately understand is sand quality. We went in and did a small frac on Catak, and it came back at still just low volumes. Even after the frac, we didn't really see a lot of improvement in production. When Bahar-1 went from like 25 barrels a day -- 25 to 30 barrels a day to 500 barrels a day. And at Catak, we were still at 20 barrels a day. And when we got through fracking and cleaning up, it was 25 or 30 barrels a day, which is really pretty marginal on an economic basis. We're holding that well again, although the whipstock of the Bahar S-2 has gone on kind of a very, very bad basis. The wellbore construction of Catak is different in that it had a long string. Intermediate in the case of Bahar, we had a liner set and the 9 5/8s, which required us to do some -- probably compromise things in the way that we were sidetracking it. So we're going to hold that well and then decide whether, as we get a little better handle on what the quality of the rock means that the well was not drilled on a structure as identified by our 3D. But it's not too far away from them. We'll decide whether we will either come out and whipstock that well by cutting the long string and then coming out from under the intermediate string, which is kind of a normal sidetrack so that you're not having to go out a window and casing and go into some of the sand surrounding that. But in general, it's just low productivity and the result of the low productivity is that sand is very tight where it is, versus sand is -- it's still tight on a general basis at Bahar, but it's not as tight as it is immediately where Catak is.

Jamie Somerville - TD Securities Equity Research

And then just with regards to guidance, I mean, you talked through how you are expecting to increase production through the rest of the year. But just wondering if you can kind of maybe address the extent to which you're standing by or feel that guidance might be slightly out of date with regards to both your exit production guidance, which I think is 6,000 to 6,500, but also the capital side if drillings been going slower, the day rate's still the same, but there might be changes there, too.

N. Malone Mitchell

And Jamie, our annual meeting is the 26th (sic) [27th] of this month. And the data we intend to produce at that is a more detailed look at field developments and timing. And coincide that with a -- an update on both a budget and a forecast following the board meeting that we have. So I would prefer to wait until that point in time to be able to deliver something that's a little better, that takes into account a little better look at what budget versus actual, where we're at from a timing standpoint and what the board approves from a budget spend in the second half of the year.

Operator

Our next question will be coming from the line of Graham Tanaka from Tanaka Capital.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Sorry, I got on late. We had trouble getting on the webcast when I called in. Just on the guidance. Do you give guidance on -- you were talking about budget -- spending, but on production out for like the rest of the year, is that possible to get any kind of range on that?

N. Malone Mitchell

I will follow-up on what we said to Jamie. We've only given guidance on kind of a range of between 6,000 and 6,500 for year-end production rates. We have internally -- internal rates that we use in discussion with the board and internally, we have not -- we do expect to give at the -- we do expect on the 26th -- the 27th, I'm sorry, thank you, Taylor, we do expect to publish a presentation which shows in more detail, fields and shows basically, what our drilling and production schedule is coming out of that, that will require board approval, obviously, for the program. But we expect to publish something that has a little more quarterly expectation with regard to production coming out of our annual meeting here at the end of this month. We do not, at this time, publish quarterly production estimates.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Okay. Could you just give an indication as to, roughly, cash flow relative to wherever that budget is going to be for -- spending for the rest of the year? Are you going to be cash flow negative, cash flow positive? What will the balance sheet maybe look like at the end of the year?

N. Malone Mitchell

Well, I can tell you, under the current budget, we'll be cash flow -- we expect to be cash flow positive. But as I said, we have all along expected to, if we can confirm our 3D seismic is hitting the zones where we believe we will hit them, we've expected and we've planned in the first part of our -- in the budget for this year that we would address the results of the 3D and probably supplement a budget with increased activity in the second and third quarters. Now we've been behind schedule on some of our activity levels. We've not been behind schedule on our spending levels. So we've again got to -- we've got to address that from a board level. Originally, in our budget, we had very little activity forecast or budgeted for the fourth quarter of this year. And that's simply not what we expected the ultimate outcome would be. But that was the limit of our activity on budget that the board would authorize until we had seen kind of what the geological mapping results were from our 3D program in Molla.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Great. Just wondering what -- how you're doing in terms of price realizations year-to-year. And also, if you can address takeaway production, how are you getting a takeaway from the projects?

N. Malone Mitchell

We have the realized prices in the kind of the first page of the press release. And as you can see, one of the things for the quarter, we've had a little bit of a decrease in both our realized oil price and our realized natural gas prices. To a certain degree, the team has done production engineering, and the team has done a great job in continuing to make headway on cost control. Our lifting costs per BOE was just a little over $8. Some of that is a function of volume and some of it is also a function of cost control at a field level. But we did see about a $6 decline on realized price in oil and close to a $0.60 decline in realized price of gas. Now we've seen a improvement in the value of the TL [Turkish lira] relative to the dollar. So that seems to be going the other direction. During the quarter, we had kind of a net negative TL impact, which impacts our gas more than it impacts -- it doesn't really impact our oil. And I'm not sure if that's what you're asking, or if there's a different aspect.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

Yes, that's the beginning of it. I just was wondering what are the pricing dynamics affecting where you are producing. Just wondering if that's -- if there are external, sort of market things going on or what is the outlook for the oil and gas prices, say, next -- rest of the year [ph]?

N. Malone Mitchell

Our business there is pretty simple. I mean, the natural gas and our development in the Thrace is price-sensitive. It's price-sensitive, cost-sensitive. Everything we've done in the Southeast is really -- it seems to be more geological-sensitive. It's -- you make a well that tends to typically payout pretty well. I mean, even with all of the issues we've had on the Bahar-ST, I was thinking about it today, it probably results in a well that takes 1 year to pay out versus a well that takes 3 to 4 months to payout, all of which would still be considered good return. There, it's simply been a matter of being able to get a hold of the mapping and understand the geology well enough to make those good wells, because in the Southeast, it's typically tended to be a good well or not a well at all. And we need the 3D to allow us to drill more of the good wells and fewer of the not a well at all or in the Northwest. That is a price-sensitive -- it is more price-sensitive as to our return. We tend to make a well all of the time. It's just the volumes and the overall return are more price-sensitive than they are in the Southeast.

Graham Yoshio Tanaka - Tanaka Capital Management, Inc.

And what has been the success rate in the Southeast versus the Northeast? I'm sorry, I don't have a lot of history on the company, sorry.

N. Malone Mitchell

In the -- well, in Selmo field, typically, you tend to make a well every time you drill. So contacting the maximum amount of formation, where you're dealing with a 30 to 70-foot formation is important. And utilizing horizontal wells to be able to do that is important. So that makes the difference between whether we make a well on a vertical well that makes something not too far over 100,000 barrels versus a horizontal well that will make several hundred thousand barrels on a cumulative basis. So that's the importance in that area. And we've added a couple of wells that we've done pretty good at staying in contact with formation and we've had a couple of wells that have just been very, very difficult because of the faults we've crossed. But we're changing the orientation of those wells so that we believe we'll stay in the same fault block rather than crossing faults. And we're yet to be able to prove how consistent that's going to be. We're in the process of drilling that now. Outside of that, in Goksu and Molla, our success ratio with regard to good wells and bad wells has been something less than 50%. And we believe the 3D will enable us to increase that percentage to a much higher percentage of what we would consider the good successful wells relative to the wells that we just kind of have a bust on a geological basis. And there, it's been a matter of being able to encounter and stay within the formations that are productive that have been challenging.

Operator

And at this time, I'm not showing any further questions. I would now like to turn the call back over to Malone Mitchell for any closing remarks.

N. Malone Mitchell

Thank you. We will be having a simulcast of the Annual Shareholders' Meeting on the 27th. Taylor will have detail out on our website that will identify the manner in which you can join that on a video as well as an audio basis. And again, we welcome anyone to that and would encourage you to RSVP, if you are. We do expect to deliver -- our focus is going to be to deliver more detail with regard to granularity on fields around that meeting, rather than kind of a general, broader basis presentation, it will probably be more detailed with regard to fields and wells. And we continue to appreciate your interest in the company. And we wish you a good weekend.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.

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