TransAtlantic Petroleum's (TAT) CEO Malone Mitchell on Q2 2014 Results - Earnings Call Transcript

| About: TransAtlantic Petroleum (TAT)

TransAtlantic Petroleum (NYSEMKT:TAT)

Q2 2014 Earnings Call

August 08, 2014 8:30 am ET


Taylor Beach 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

James R. Huling - Chief Operating Officer

Todd C. Dutton - President


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

Jonathon Fite

Andrew M. Smith - Global Hunter Securities, LLC, Research Division

Jamie Somerville - TD Securities Equity Research


Good day, ladies and gentlemen, and welcome to the TransAtlantic Petroleum Second Quarter 2014 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, Taylor Beach. You may begin, ma'am.

Taylor Beach Miele

Thank you for joining us. On the call today, we will have Chairman and CEO, Malone Mitchell III; President, Todd Dutton; Chief Operating Officer, James Huling; 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

Thank you, Taylor. Thank you, ladies and gentlemen, for joining. TransAtlantic had a good quarter, and we are ahead of that performance now.

Last quarter was a good demonstration of what the impact of production growth on a high net back country like Turkey is to us. As you see, as we control our costs of what the dramatic impact for our income and EBITDAX is as we grow production.

The past few months have been characterized by consistent operations as several people with whom I have a lot of experience and history joined the company and have become more familiar with the company, which they had less experience with. We expect to be able to deliver on our year end production and financial targets, and for this team to continue growing TransAtlantic in a professional manner thereafter.

Now we've got a good number of people on the call this morning, and so therefore, I'm going to turn it over to Wil Saqueton, and then onto James Huling and Todd Dutton for their comments, and I'll be available for your questions at the end. Will?

Wil F. Saqueton

Thanks, Malone. We are pleased to report several record highs accomplished in the second quarter. Our average net sales volumes were 5,000 BOE per day, up 8% from the first quarter and included oil sales of 3,500 barrels per day, a record high for TransAtlantic, and gas sales of 9 million cubic feet per day.

We've now delivered 4 consecutive quarters of increasing total net sales volumes.

Second quarter revenue was $41.1 million, a record high for the company, up 22% from the first quarter and up 35% from the second quarter of last year. 81% of our second quarter revenue came from net oil sales.

Our adjusted EBITDAX from continuing operations was $27.5 million, a record high for TransAtlantic, up 26% from the first quarter and up 60% from the second quarter of last year.

We generated discretionary cash flow of $26.7 million, or $0.71 per share, and our CapEx and seismic expenditures were $28.7 million, a slight increase from last quarter.

We expect to spend $45 million to $55 million of CapEx in the second half for a total annual CapEx of $100 million to $110 million.

During the second quarter, we operated at nearly free cash-flow neutral, with total net cash consumed of $2 million, down 62% from the first quarter.

In summary, we're pleased to have delivered very strong financial results in the second quarter. And on that I'll hand the call over to James.

James R. Huling

Okay. Thank you, Will. I thought I'd start off with a short introduction. First off, I'm honored and excited to have the opportunity to manage here at TransAtlantic. My association with Mr. Mitchell goes back over 20 years. I served as engineering manager for Riata Energy in the 1990s through the development and sale of Packingham Field, as well as the initial acquisition of assets from the Longfellow Ranch.

I subsequently worked for Encore acquisition company through their IPO, where I worked extensively on numerous field developments, reactivations and exploitation campaigns.

Additionally, I served as a partner in 2 private equity companies.

In the last 2 years, I served as Chief Operating Officer for Longfellow Energy, where I've helped manage nearly 100% production growth and over 200% reserve increases.

With that introduction, let me move on to production and general updates. As Wil touched on production, I'm pleased to announce we have record-high oil production for our company.

Average net production for the first 4 weeks of July was approximately 5,400 BOE per day. This equates to 3,900 barrels of oil per day and 9.1 million standard cubic foot per day.

We're currently operating 3 drilling rigs in Southeast Turkey and 1 in Northwest Turkey.

Year-to-date, we have spud 15 wells and completed 14. This year, in total, we plan to drill between 30 and 35 wells.

We anticipate capital expenditures between $45 million and $55 million in Turkey for the second half of the year.

Total for the year, this will result in annual capital expenditures between $100 million and $110 million.

Moving on specifically to Selmo field and the redevelopment there in Southeast Turkey. We're concluding drilling operations on the Selmo-68H3, which is our 10th MSD horizontal. We completed 3 Selmo MSD wells in the second quarter of 2014. The most recent well is Selmo-85H had an initial production of 500 barrels of oil per day without stimulation.

Current average gross production for the 5 most recent wells is 270 barrels of oil per day per well.

The average cost on these 5 wells was approximately $3.5 million.

We are continuing to focus on the underdeveloped Southeast portion of the field. We plan to continue to operate one rig and spud at least 4 additional horizontals in this area of the field in 2014.

We remain optimistic about horizontal development and redevelopment in the field. Results to date illustrate our focus to drill parallel to the faults, reduces mechanical risk and yield favorable economics.

We plan to continue our waterflood pilot expansion with the conversion of 2 additional wells to water injection in the third quarter of 2014.

So far this year, we have converted 2 wells to injection and have cumulative injection excess of 250,000 barrels of water. The fact that we have not seen water breakthrough is positive.

We will commence second phase of polymer injection in the third quarter of 2014. Current assessments show we have at least 20 additional polymer injection candidates within the field.

Okay. State in Southeast Turkey, moving on to the Molla drilling. Our GNG team has recently received initial process data on the final block of the Molla 3D seismic survey, which includes the Göksu field and surrounding areas.

This area encompasses approximately 300 square miles and will cover all fields in the area. We will utilize this data to select future locations.

We're currently amidst operations to complete the Bahar-2 sidetrack directional well and the Bahar-3 vertical well. The lower and upper Bedinan sands at the Bahar-2 sidetrack produce noncommercial oil. We believe this well is in a separate fault block to the other Bahar wells. We are currently in the process of completing the Hazro formation at a depth of approximately 8,700 feet. This interval tested commercial in the Bahar-2 after an asset job. We plan to perform a larger scale asset frac on this interval and anticipate turning the well over to production later this month.

The first stage of the Bahar-3 completion, which is in the lower Bedinan at approximately 10,400-foot tested in excess of 200 barrels of oil per day. We will add the Bedinan sand -- the upper Bedinan sand, excuse me, and the Bahar-3 later this month. Based on long character, this interval in the Bahar-3 looks favorable to the Upper Bedinan in the Bahar-1. And the Bahar-1 is currently producing 170 barrels of oil per day and has cumulative production in excess of 130,000 barrels of oil.

After testing the Lower and Upper Bedinan in the Bahar-3, we intend to also test the Hazro. We're currently drilling the Bahar-4 at a depth of 10,179 feet. The well encountered oil shows in the Mardin, Hazro and Dadas formations.

We're about to drill into the Bedinan, and remain optimistic we will encounter the zone in a structurally high position.

The company is also drilling the Bahar-6 at a depth of approximately 3,663 feet.

Summarizing Molla drilling. Current estimates to drill vertical Bahar wells are approximately $5.5 million. We plan continued operation of 1 or 2 rigs and expect to drill at least 2 additional vertical wells, targeting the Hazro and Bedinan formations on the Bahar structure later this year.

Now moving to Arpatepe drilling, also in Southeast Turkey. We plan to drill the Arpatepe-8, which follows the success of the Arpatepe-7, which was drilled in the second quarter of 2014. The Arpatepe-7 has not been stimulated and IP-ed at a rate of 330 barrels of oil per day.

After 2 months on production, it's currently producing 245 barrels of oil per day.

We're taking the lead to provide cooperative technical support to develop plans to initiate a waterflood pilot to affect secondary recovery in this field.

Staying in Southeast Turkey, but moving to the Idil expiration license. We anticipate drilling of vertical exploration well on the Idil license during the second half of 2014. Our joint venture partner, Onshore Petroleum, will fund 100% of the cost and will earn 50% in the license.

Moving to Northwest Turkey, and specifically Thrace Basin development. In July, we commenced our development program with one rig. We plan to drill 2 horizontals, 4 verticals and 1 reentry over the next 60 to 90 days. We are currently finishing the drilling operation on the TDR-5H, a horizontal well targeting the Teslimkoy formation at a TBD of approximately 3,200 feet and the total measured depth will be -- or is 5,800 feet.

The aforementioned development program targets shallow, conventional wells in the Osmanli area that are based on 3D seismic data that was taken last year in 2013.

Moving on to Bulgaria. On June 26, 2014, our technical team submitted a request to the Bulgarian government to acidize the Deventci-R2 well. Upon approval from the government, we will stimulate the well to enhance productivity.

In summary, it's pleasant to announce to our shareholders we have record-high oil production. We're excited about the project opportunities ahead, pleased to see the technical and operational progress we're making. We continue to build a seasoned and multi-disciplined technical staff and look forward to more success.

With this, this will conclude the operational update portion, and I will turn the call over to Mr. Dutton.

Todd C. Dutton

Hello. I'm Todd Dutton, this is my first earnings call at TransAtlantic, and I want to thank each of you for joining us. I've known Malone Mitchell for 13 years and I've worked for him for the past 9-plus years. First as Chief Operating Officer at Riyadh Energy, now Sandrich, and as President of Longfellow Energy since 2007.

I believe in Malone, and I'm excited by the opportunity that he's given me to be President of TransAtlantic.

As you just heard, we had record quarter. Our highest oil production, highest revenue, highest EBITDAX in the company's history. We expect to break these records again in the upcoming quarters as we continue to drill our horizontal wells in Selmo and use our 3D in seismic to select well locations in our Molla block in Southeast Turkey.

James Huling and I spent the 4th of July week in Turkey, catching up with our staff, visiting the fields and the facilities, and I was very impressed with what I saw. Our team continues to streamline improved operations, and that's reflected in our increased drilling rates in Selmo and our low production cost per BOE, which remain below $9 this quarter.

Our security is top notch, and logistically, I thought the highways were better than I had expected. Our access to the fields and the roads and the facilities were all in good shape and our employees were very optimistic about what we have going on.

I'd like to say a word about our Selmo field. It's obviously our largest asset, but I don't think that investors truly understand the outstanding economics and the long-term reserve potential that is our MSD horizontal program.

For example, our recent Selmo-54H1 well produced almost 35,000 barrels of oil in its first 60 days at a total cost of $3 million. That's a 2-month payout, and the well is still producing 600 barrels a day or almost 600 barrels a day. It's wells like that one, along with our 36H and 92H wells in Selmo, that will have larger reserves than we had expected.

In my experience, reserve estimates in large oil fields continue to increase generally over time as the size and character of the reservoir is revealed and as new development technologies are utilized.

I believe we're seeing that now in Selmo with our horizontal drilling program. To me, Selmo couldn't be much larger than even we were thinking, and I'm optimistic about it. I believe that TransAtlantic has a unique niche working in Turkey and Eastern Europe that gives us access to exciting investment opportunities with far less competition than in saturated markets like North America. Plus we've got Brent oil prices and European gas prices.

As you've heard from us in the past, we continue to evaluate business development opportunities in this region. We've seen a lot of our regional competition disappear over the past couple of years. We really believe we'll be able to pick up some interest in some proven hydrocarbon basins in the coming year.

I do want to mention that besides James and myself, we’ve added some key executives to oversee our geological drilling and legal teams. These new additions will strengthen what was already a very good team, and ultimately, we believe the company's success depends on the competency and work ethic of our employees, and James and I are very excited to have these new people with us.

We really appreciate your interest in TransAtlantic. Our team is energized by the projects and the potential, and I think you will be pleased over the next few quarters as you see where we are headed.

And with that, I'll turn the call back over to Malone. Thank you.

N. Malone Mitchell

Thank you, Todd. And we're pleased for everyone who joined, and we're now happy to take questions.

Question-and-Answer Session


[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust.

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

Question, Malone, just around, obviously, Selmo. It does seem like it just continues to improve. I guess now when you've looked, how many -- guess you kind of run through the type of identified drilling locations and besides sort of the -- and then sort of existing what you're seeing just on sort of, I guess, sort of the current depletion rate on the existing wells.

N. Malone Mitchell

You still have some fractures. When we're able to stay in the MSD, we actually have relatively low decline curves. But I think those are still going to be on average if we look at historical field basis, the baseline productions declines in the neighborhood of 18% per year. We've had a couple of wells that have come on and declined more significantly than that and some less. I will put out -- now that we're getting to 10 wells, I tell you, in the upcoming quarter and one of our presentations coming up, we'll go ahead and put out 10 wells statistical data on what the MSDs looking at -- looking like there. LSD wells are more spotty. We really at this point in time, we've got 1 improving, but we've only got, really, 1 of those 3 that we consider easily commercial and the other 2 are -- don't look that great, so we had to quit to drilling the LSD wells and focused on the MSD. But with 10 wells will turn out kind of a statistical curve analysis for that on one of these upcoming presentations. As far as running room, right now, we've got identified locations we think that take us through the balance of 2015, given a one-rig pace. And it may be that we're able to increase that pace at some point in time. We had slowed from 2 rigs to 1 rig because we were having problems staying in zone, but we were trying to drill perpendicular to the faults. We're doing a better job of that now, but I don't know that we're yet confident enough in our geological mapping and understanding to get beyond one rig running in the field right now.

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

Okay. And then now that you've got that seismic survey done in the Molla area, I guess, besides the Bahar, the 2 ST and I think that's completed and I think there's one other, I think, the Bahar-4 that's drilling, what type of activity do you see or how much is, I guess, same question there, Malone, what type of -- now that you've seen that seismic survey, what type of running room do you see this year?

N. Malone Mitchell

We're starting to do kind of the early mapping on that, and we have one more kind of final iteration of the processing that we're expecting around August 18, although it’s not [indiscernible] we’re receiving on that exact day. But right now, we can see we expect to resume running a rig down in the Göksu area. Göksu 3, 2 are still producing some very good rates. Göksu 2 is producing like 158 -- or at least producing 158 barrels a day and it's over 160,000 barrels now. So we can see more structure, we can see more definition on what we're doing down there, so we expect to have a rig running if not at the latter part of the third quarter, but in the fourth quarter in that area. We continue to expect to drill up north. We've got a little bit of a surprise on some of our Bahar stuff, probably one of the bigger surprises, we picked up multiple sands in the Bedinan, which we really hadn't seen in other places. We had a fall clip, part of the #2 -- where the -- the fault block where the #2 well sets, so we had low production there but kind of a separate sand that we hadn't seen before produces over 200 barrels a day of just pure oil force than the #3. So by the time we get the 6 down, the 4 down, probably the 5 down, we'll start having enough there to kind of feel confident about our seismic ties, and hopefully we can accelerate up there. I think right now for us through the balance of the year, staying consistent in Selmo and allowing that to grow, staying consistent with our rigs in Bahar and the rig down in the Göksu area, along with Idil expiration well, we're going to drill in the Thrace program. It’s probably a good focus for the team right now and that we think that's probably -- that'll give us a high success ratio in addition to the activity level, which is important for us.

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

Absolutely. And then the last question, Malone. I guess, just given the potential in sort of southern – most southern part of Turkey, was surprised you went back with a rig up in Thrace. Your thoughts around that? And if you would go back to the frac program or exactly what you're going to do up there?

N. Malone Mitchell

Well, we've got -- I tend to believe that the engineering teams are getting better, the drilling teams are getting better and more experienced. So we do have identified reserves and a couple of horizontals that we're trying -- a couple of a little bit of things that we can see what we see an improved performance out of those wells. So we do only plan to probably have a rig drilling up there and will drill that program and we think we'll get it accomplished within 60 to 90 days, and then we'll go into just the production mode again in the Thrace for another couple of months, and we'll evaluate that. And spend most of our money, continuing to spend most our money, focused on the oil in the Southeast.


The next question comes from Jonathon Fite with KMF Investments.

Jonathon Fite

I might spend just a moment trying to relate the success that you guys have seen since the framework that you outlined at the general meeting in May where we started out kind of 4,800 BOE a day then with a goal of 6,000 to 6,500 exiting 2014. Would you say that the growth that we've seen so far over the summer has largely come from one of those basins? You talk...

N. Malone Mitchell

No, it's all coming from Selmo.

Jonathon Fite

It's all coming from Selmo?

N. Malone Mitchell

It's all come from Selmo. We'll put more Selmo wells on, we'll put more -- we’re really just putting on the Bahar wells. We'll probably put 3 Bahar wells online this month into our production stream, and then we'll put some more gas online in the Thrace. We've been just sitting there declining basically with our gas and the Thrace month after month without drilling wells to offset it. One of the things we looked at is really the production growth we saw in the second quarter is, by and large, a result of completion of only 3 to 4 wells. So a big focus is just to keep increasing the pace at which we're adding wells, and we're -- so far, we're ahead of where we were there in a number of wells we spudded, the number of wells we’ll get completed and get online in that -- in this quarter. So everything, all of the production increases over the course of the last periods come out of Selmo. So we'll see production increases coming on now, coming out of Bahar and more out of Selmo and more out of the Thrace and then by the fourth quarter, we expect to see some production added probably from drilling in the Molla or Göksu field area as well.

Jonathon Fite

And you talked about the average production I guess, of the most recent 5 wells in Selmo being in the 250, 270 range. Do you see the -- are there particular lessons learned from these last 5 wells versus the first 5 wells that indicate that the hit rate and the success rate of the next 4 that you're planning would be more, I think, the last 5 versus the first 5?

N. Malone Mitchell

I think the strength of the last 2, in particular, are a result of having stayed in zone for a longer period of time. So it's kind of like you see laterals measured, although it's based on fracs, they're measured based on some standard exposure to the zone, and we haven't talked about that a lot, but it matters a great deal to us, both in the cost of the wells, and it matters to us a great deal both in the performance of the wells. If we're only able to contact the MSD because of faults, or because of some issue for a very short interval, we'll generally have a poor well that declines faster. Whereas, if we're able to drill a well and stay in zone for a couple of thousand feet, we have a better well that doesn't decline as fast. So the #1 thing for us when we look at it internally, that is that matters now that we've seen we really basically have oil down to -- which surprised us, we have oil in the MSD down basically to our leased lines is -- the whole thing for us is about mechanically being able to predict and stay in zone. And there we're dealing with a -- we're dealing with an older seismic shoot that doesn't have some of the attributes associated with our most current shoots. We've strengthened our geophysical team and our geological team under -- lean months it’s coming in and is recruiting and directing that. And maybe they'll be able to do more, but right now, on parallel to the faults is resulting in better success for us. We're still only 2 wells completed and a third well just finished, and that well we weren't able to stay in zone the whole time, so we're now kind of 2 out of 3, but we do have better exposure than we had in some earlier wells. So for us, in zone is relative to both your production IP and your decline.

Jonathon Fite

And so as a framework to understand, maybe the potential of these next 4 wells, that 250, 270 run rate kind of appropriate expectation if you stay in zone what these next 4 wells might deliver in Selmo?

N. Malone Mitchell

I don't think we're willing to increase our projection. I think we'll just kind of let the numbers. I'd tell you in addition to what Neal asked, probably some correlation with regard to exposure to the zone is probably appropriate and correlating those. But I don't think we're ready at this point in time to increase our pro forma projection on our wells based on these last couple of wells' performance because we don't know that they may be outliers to the positive side. We still need more wells, I think, to be able to make that jump.

Jonathon Fite

And in the past, I think you've been hesitant as well to provide any framework around the benefits to the polymer injection candidates. You talk about 20 candidates in the plan there. Is there a framework for understanding what that might deliver? Is that just replacing existing declines or does that actually result in net new?

N. Malone Mitchell

Well, let me let James explain that a little better and probably the -- kind of maybe some thought process on that.

James R. Huling

In general there, on the projected polymer campaign, what we're looking at are wells that are currently poor producers, usually with higher water cut, trying to mitigate water production and either maintain the existing oil rates and hopefully, in cases, increase. So most of the focus is going to be on wells that are either shut in or very low water or very high water production and reducing water, increasing oil in those. So basically, it's rejuvenation of older established wells in the field. Does that answer your question?

N. Malone Mitchell

I might add that if you look at it, the first 5 we did, all 4 MSDs were successful, the LSD was less successful, although it's now improving. It actually, we didn't think, worked at all, and now it's actually starting to improve. Based on the cost we had, based on the performance we got, this was about a 60-day total campaign payout. We think we can reduce the cost of this program now that they feel like it works. Engineering group under Justin and David have done more work about trying to deliver a lower cost application, targeted more around the MSD than the LSD. So from that standpoint, we think that's going to be decent economics. But it's very hard, I think, to project. We gave the average, the average well, at about 50 barrels incremental, but really it was out -- really most of that was out of the 4 wells, and that's coming from wells that made very little, whatsoever, before we treated them. So I think it's -- the 4 wells, say, your average is going to be maybe more like 60 barrels of well of incremental production. So that's the numbers we have, but I don't know that we can project some sort of a number going forward to say every time we do a polymer squeeze, we're going to get 60 incremental barrels. And there's nothing that prevents us from doing subsequent squeezes on existing wells that have already been done. It's kind of a patch that chemically shuts the water down. Anytime within the zone, water tends to flow more aggressively than oil flows. So if you can make the water quit flowing, then the oil will come out of the rock better in this type of reservoir.

Jonathon Fite

Great. And then just 2 last quick ones. Once you guys complete the campaign in the second half of this year and we get into the December, January timeframe, do you feel comfortable publishing a similar type of framework for what the 2015 campaign might drive by basin and similar to what you did for the general meeting where we kind of look at the decline by basin, the program planned by basin so that we can kind of track progress against plans for next year?

N. Malone Mitchell

Yes. We'll give you more clarity on all of that, upcoming in the fall, the budget and allocations for the entire company. Now based on our continuing, better understanding of the seismic in the Molla area, we're going to take our understanding we develop in kind of the proven fields like Göksu and Bahar, and we're going to use that to go drill the other structures and other places that we see. So by the very nature of it, we're going to be drilling some exploration wells next year that are based off the seismic we learned there. So for those, we're going to have -- it will be easier for us to project in our known fields than it'll be for us to project in all of the additional acreage that we’re showing up in Molla that we think is productive based on our seismic evaluation.

Jonathon Fite

Sure, understood. And last question, and I'll shut up here. You guys have shown a lot of success so far this year, and Todd's comments talk about the nature of that success likely translating into not only better performance than we might forecast, but larger reserve developments in relation to baseline plans. And so I'm just wondering, in the past, you talked about kind of $16, this P1 PB10 level as kind of a floor value for the equity of our company currently trading at a massive discount to that. Have the results thus far give you confidence where really that floor value is actually higher than that level given some of Todd's comments and your success to date?

N. Malone Mitchell

We certainly think we're going in the right direction and our cash flow shows that. I think that I've been completely puzzled about why our stock is going down other than general political events and kind of market and the price of oil over the past couple of weeks. Everything I see internally, we continue to do better and better and better. So I continue to state that, in my mind, there's nothing that would make us work less than our proved reserves, and that number continues to be -- although as last updated on the first of the year, continues to work out to be better than $15 a barrel or $15 a share.


Our next question comes from Andrew Smith with Global Hunter.

Andrew M. Smith - Global Hunter Securities, LLC, Research Division

Quick question on the Idil well. When do you expect to have results from that?

N. Malone Mitchell

It's a cretaceous well, so it will be a little over 6,000 feet deep, based on our drilling on a vertical well. On that type of well recently, we wouldn't expect even in that area for it to take us much longer than 30 days to drill it. We are drilling in the proximity of an old Getty well that had oil. We know that the reservoir won’t flow. At least it didn't under just the DST conditions, so we'll have to run pump and pump it and see what the analysis is. So all of that would still lead us to believe if we get that well spudded in September that we'll have results by year end.

Andrew M. Smith - Global Hunter Securities, LLC, Research Division

Okay. And how do you think about kind of the potential in that area?

N. Malone Mitchell

Well it's really large, but it’s really wild. It's adjacent to big fields and Kurdistan and Syria, and we have really large internal numbers, but nothing that rises to the point of being able to put any kind of a proven number, a number that we want to give the public. But it's on a structure that you can easily go get on Google Earth and look at it, and go, “Oh wow, that looks like an interesting thing.”


Our next question comes from Jamie Somerville with TD Securities.

Jamie Somerville - TD Securities Equity Research

You may want to wait until you're doing the statistical analysis, but I wanted to dig a little bit deeper on what you're seeing with the Selmo wells. Malone, you mentioned an 18% base decline rate. And, obviously, these are fantastic results from the MSD wells. But I imagine the initial decline rate on the newer horizontals is significantly higher than 18%. And I'm just wondering if you're seeing any -- how that decline rate is evolving, if you're seeing some stabilization. Obviously, the lead on to that is -- leading into Todd's comment about reserve growth potential. Have you seen anything that suggests that these wells are -- have a drainage area that is influencing adjacent wells? And maybe you can -- Malone, in the past, you've commented that there might not be that much reserve growth potential at Selmo from the 2P level, so maybe you can just kind of address how that thought has changed over time.

N. Malone Mitchell

Well, we spent on, I believe -- I'm actually in London right now, but I believe on Wednesday we spent a couple of hours with all of the technical team, all of us in a room just looking at Selmo for a couple of hours. What we were seeing and knowing, and I'm probably going to stick with the fact that through 2025, mostly what we're going to be doing is we're going to be converting reserves, not necessarily finding new reserves, but that's still a fantastic answer for us from a financial standpoint. And I don't know -- I don't -- I think we know that everywhere we're going to drill is productive and that the payout profiles look good. I don't know because we spent some time talking about it if we were yet able to give a conclusive answer with regard to the reserves. James is -- this will be James's year end. His first run with D&M on that end, so I don't think we have the ability to give you much more answer than what we're currently giving you. James, do you feel confident saying something different?

James R. Huling

Yes. I think the early results, I will say this, are very encouraging on performance. And we're still definitely getting our arms around it, but everything we see is very encouraging at this point on the recent horizontal drilling campaign. And as far as offset -- effect on offsets at this point, it's still early, but I would say we're not seeing issues there. But again, we'll have a lot better assessment at year end as you outlined, Malone.

N. Malone Mitchell

Yes. I still internally think that while Selmo is the best thing we have now, the potential of it does not look to me to be as great from a company ultimate production-performance standpoint as what we see overall through the Molla area.

Jamie Somerville - TD Securities Equity Research

Great. Maybe just I'll switch to that then. Just the Bahar-2 and Bahar-3 results, can you -- it's not clear to me if you're significantly disappointed by Bahar-2 and worried about the implications of that noncommercial oil or whether you have a reason to think that you can just dismiss that, and then move on and look at Bahar-3 with a decent result with upside potential from additional testing.

N. Malone Mitchell

Well, the biggest thing that kind of was new to us, and we'll see here at #4. #1 only has 1 sand. And when we drilled our closest wells, the Göksu or the Cataks only had 1 sand. The #2 and the #3 both have 2 sands. The #2 did come in still a little lower than what our prognosis was. #3 was within 15 feet or so of our prognosis. And the #1 -- #2 well when you look now -- and again we got better geophysical, we're seeing some faults there that seem to be tied back up into the Hazro and that may answer why we have all this oil up in the Hazro, but we just didn't have much pressure there in those sands. They are good sands, but they just weren't that great. From a pressure standpoint, while the number -- the #3 well is tied in the same pressure, at least the lower sand is, as to the sand that's the main producing sand in the #1 well. Now, I’d rather sell 500 barrels than 225 barrels a day, flowing rate out of the #3 lower sand and I would certainly hope to see equivalent flow rate to the #1 well out of the main sand there. So I don't know, it's great to have 2 sands, but it’s kind of -- at the same time, we weren't expecting it, so that's -- anything new is -- we'd rather find exactly what we expect nearly than find something we don't expect that's a little more. So as we still have a little more learning to go as to how exactly what we see on seismic and what it means on surface. So results from a production standpoint on the well, there was really -- the sand we saw the most show out of the #3, is the one we still are getting ready to complete and frac. So yes, I'd rather have seen a lot better performance out of the #2. I think we can understand it from our seismic now, but that's part of the reason that we're saying we're going to continue to drill a few more verticals before we try to go horizontal, and we're going to try to understand, probably even more committed now to spending through the balance of the year nearly drilling these wells and making sure we understand seismically what we're seeing. And if we need to continue or change our understanding or interpretation of our seismic before we step out much further away than a couple of locations away.


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

N. Malone Mitchell

Well, I'd hope that every call we ever have goes like this. It's always pleasant to be able to report record production, but what record production translates into in a country where you have the kind of netbacks we do or the kind of cash flow and the kind of sales we have. So here is my best wishes to all of our shareholders that most of our calls go like this one rather than some of the ones we've had in the past.

So thank you, all, very much for participating in the call, and please have a very good weekend. Please call us if you have questions. Obviously, we can't answer every question, but we would love to keep you informed on your company and help you understand where we see the potential of the company going over the next couple of years. Thank you very much.


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

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