TransGlobe Energy Corporation

Good morning everyone, and welcome to TransGlobe Energy Corporation's second quarter 2016 conference call. This is Ross Clarkson; I'm the President and CEO.

And with me I have Mr. Lloyd Herrick, Vice President and COO, and Mr.

Randy Neely, Vice President Finance and CFO. As usual, we'll start out with a summary of the financial and operating highlights.

Randy Neely will review the financials and the highlights of the quarter starting on the next slide.

Thanks, Ross. Good morning everyone.

The quarter was relatively uneventful from a financial perspective. We did see a substantial increase in realized oil prices, from $22.58 in Q1 to $30.27 in Q2.

Our liftings in Q1 and Q2 were both done at approximately $14 negative differentials to Brent, but we continue to believe that these differentials will narrow as oil prices recover. The lifting in the quarter netted us approximately $16.9 million in proceeds.

Production for the quarter was down approximately 5%, to just under 11,500 barrels a day, and sales were slightly higher than that at 11,783 barrels a day as we lifted some of our opening inventory in the quarter. At quarter end, we had 706,577 barrels remaining in inventory, down from just under 780,000 at the end of Q1.

Funds flow for the quarter were approximately $2 million, up from negative $2.8 million in Q1. Much of this increase is attributable to the higher oil prices we see, but also indicative of the lower overall cost structure we have worked to achieve over the past 18-plus months.

We also note that we achieved further decreases of 5% of both gross G&A and gross operating costs in Q2 versus Q1. During the quarter the company lost $12.1 million, down from a Q1 loss of $16.2 million.

The loss is generally a result of lower oil prices, but as well foreign exchange losses attributable to our convertible debenture. During the quarter, we spent $4.8 million on capital expenditures, and Lloyd will give more color on that in a moment.

We ended the quarter with positive working capital of $65.4 million, which includes approximately $124.3 million in cash remaining at the end of June offset by our entire convertible debenture balance which is held as a current liability. And it is due on March 31, 2017.

As for our future liftings, we have another lifting scheduled for September, and we continue to be in discussions and negotiation with the EGPC for a fourth quarter lifting. I'll now turn you over to Lloyd for operations update.

Thanks, Randy. This slide shows daily production by concession for the past 12 months.

Production declines in Q4 and early-2016 are a combination of natural declines and intentional reductions to operational and development investments in response to the very low oil prices in early 2016. With Brent oil prices returning to the mid-40s, companies began to make select operational investments which stabilized production in the 11,400 barrel-a-day range, which is also guidance for Q3.

West Gharib, shown in red, has been fairly stable, and is expected to increase in Q4 with several recompletions scheduled as part of our production recovery plan, which I'll discuss later in the presentation. Slight dip in production at the end of July relates to a few wells that were waiting on pump and rod changes, while the workover rate was down for the annual maintenance and recertification, which was completed this past weekend.

At West Bakr, shown in orange, production increased in June, with the addition of K-48 and a few well reactivations. Production will ramp up in the fourth quarter with the addition of K-51, and the remainder of the PRP wells and recompletions.

This slide is a summary of the current 2016 plan. Primary elements of the plan are the 18-well exploration drilling program, which commenced in Q2 with one drilling rig, and has been accelerated with the addition of a second drilling rig in Q3.

Today, we have drilled five prospects and made two oil discoveries, which Ross will discuss later in the presentation. Development of the West Bakr K-South field, with an initial three wells scheduled in 2016, two oil wells have been drilled to date; implementation of the production recovery plan, or as we call it the PRP, through the balance of the year targeting production of 13,000 to 14,000 by year-end.

Advanced development plans for existing North West Gharib discoveries, including the appraisal of recent discoveries which will occur in 2017. We will continue with mapping at South Ghazalat and preparing for North West Sitra seismic tender.

And our Western Desert operations continue to look at the diversification through development opportunities, and of course continued focus on cost reduction and optimization to improve our overall cost structure, which are evident in the recent financials. Based on a significantly better drilling cost, which are trending 30% to 40% below plan, and optimized PRP re-completion plans, it's expected that the 2016 capital spend will be approximately $33 million in '16, which is about $5 million lower than the preliminary estimates.

The significantly improved drilling costs are due to improved drilling practices and better contract pricing. During the 2015-'16 drilling hiatus, we conducted a detailed review of over 200 wells that we've drilled in Eastern Desert to optimize our Eastern Desert drilling program.

These well-programmed design changes have been a significant contributor to our lower well costs in the 2016 program. This slide summarizes the production recovery plan as identified in the Q1 webcast.

The program is proceeding as planned with a majority of the fieldwork scheduled for September through December of this year. This slide, our current production comes from West Gharib and West Bakr Concessions in Eastern Desert.

As discussed, we expect production to average 11,400 during Q3. In addition to the production recovery plan, the company completed construction of a new geostatistical reservoir simulation model for the Arta Red Bed pool during the second quarter.

Based on better than forecast pool production for the past two years and the simulation results, we believe that 2 to 4 million barrels of additional oil reserves will be recovered from the Red Bed pool. On a 2P basis, that would represent a 7% to 14% increase to our year-end reserves.

We are working with our independent reserve evaluator to confirm the Red Bed reserve additions. Additionally, two infill wells were identified which are now scheduled for either late '16 or '17 depending on regulatory approvals.

Those two wells are targeting a combined 6 to 800 barrels a day of incremental production and are expected to cost $100 million per well to drill and place them in production. I will discuss the West Bakr, K-South in more detail on the next slide.

This slide is a map of our K-South area which has had limited access due to military restrictions in the area. In late 2015, we finalized an agreement to allow access to South K.

Based on historical oil control we currently estimate that South K contained 55 million barrels of oil in place. Approximately, 5.9 barrels of oil have been produced representing a 10.7% recovery factor.

Our 2P remaining reserves at year end 2015, were booked at 3.9 million barrels, which would equate to an implied ultimate recovery factor of about 18% for K-South. Comparatively, the main K pool to the north has an expected recovery factor of 29%, which if applied to K-South would equate to 8 to 10 million barrels remaining reserves.

Today, we have drilled two of the planned three wells for 2016. The first well, K-48 encountered at 108 feet of net Asl A oil pay was placed on production with an initial rate of 460 barrels a day in June.

The second well K-51 encountered at 120 feet of net Asl A oil pay on the weekend and will be completed and placed on production in September. I'll turn the presentation over to Ross to discuss our 2016 exploration program in more detail.

Okay, this is the exciting stuff. Well, K-South is pretty exciting too, but I've got our 2016 18-Well program here, and the 3-Well Development program in a summary form on the slide nine.

And you can see in this that we are targeting the higher productivity formations in three main play types: the Red Beds which are like those that we found in our Arta field. The Miocene Clastic Prospects which are the safe zones found in Hana Field and A, H, K, and M fields on West Bakr.

And then a new play at the pre-rift level which is the safe zones found out on the offshore fields, but hasn't been done on the onshore. This program is underway now.

And it's going to run all the way into 2017. What is added here are the orange boxes where we show where we are in the testing of these various play types?

We had one test of the Miocene Clastic, which was unsuccessful and six more tests planned there. And then, two out of the four wells we drilled into the Red Bed prospects have resulted in discoveries which I'll detail in the next few slides.

And then, three more Red Bed tests that remain to be done. And then, the pre-rift test will be done later this year.

And the development program that we are drilling on the South K, that's a 100% success so far with two wells drilled and one remaining to be drilled. Now this statistical result assumes 3 to 4 successful discoveries out of some 18 to 20 wells.

And a statistical result of 8 to 26 million barrels recovered on reserves. And that's really using an average chance of success between 17% and 32%.

I mean this is wildcard drilling. It's an oily area for play types that we know can work, but so far we are ahead of those statistics with a 40% success rate on exploration.

And what we believe our internal estimate is that we found about 30 million barrels in place at this point although we do need to do more drilling to prove all that up. If we only assume roughly a 25% recovery factor on that, we are pretty close to our target and we already have -- and we still have 13 explorations wells to be drilled for the remainder of the year.

So, we are pretty pleased with these results so far. We are also now progressing with development work on some of the discoveries we made in our original 2014 drilling campaign.

The discoveries were not put into production last year due to low oil prices. But now that we are seeing the first signs of the turn in the oil market, we will work towards bringing those discoveries into production by the fourth quarter as part of our PRP plan.

Let's move on to the slide with the map. Slide 9, I think it is.

And this is a really busy map. So, I am going to try and simplify what it's really showing us here.

The red area to the west is a structural high that really has no reservoir rock deposit on it. It essentially has bald high at the Red Bed depositional time.

And then on the east side the ballooned purple area is an area of marine shale deposition with no reservoir sands or conglomerates because it's too far away from the source of the sands which come from the west. So, that leads with a green and a yellow area which is the sweat spot or green for go area.

To date, we have four Red Bed oil discoveries in the Green Fairway and have several additional locations to be tested. The key message is that we have developed a depositional model and that's based on our previous success in the Arta Red Bed to the south.

And now we successfully tested that model in another location. This has really de-risked a lot of prospects in the area, which will give us our third round of exploration drilling in the future.

We are currently evaluating an additional 10 leads with the intent of moving many of them into the prospect category over the next few months. The North West Gharib 3 and No.

16 wells were drilled in the 2014 campaign, and we have covered those in the past. So, I am going to focus on the recent discoveries at 27A and 38A.

The first well at 27A highlighted in red on this map found a thick reservoir section and recovered a 23.5 API oil sample. And that's very significant because it is the lightest oil we found in this area.

And, it's actually lighter than the blend that we are currently selling. That really should see a positive value quality adjustment.

It also has a lower risk viscosity which should result in a higher recovery factor ultimately. Let's look at that discovery in more detail on the next couple of slides.

Okay, we're on slide 10, and I am showing a seismic line because it gives a flavor for the challenges in developing the prospectus in this area. I believe we have incredibly talented explorationists who have analyzed a massive amount of geological and geophysical data.

And it's challenging because this data is not as clear as that found in our Western desert lands. And the real key to our success here is to be able to test these ideas very inexpensively.

And then, use that well data to define where to go next for appraisal drilling or further exploration. As Lloyd mentioned, we knew we would have lower drilling cost.

And we are seeing efficiencies and learnings from having drilled over 220 wells in the Eastern Desert. The green blobs on this section are what we are drilling for which is pretty hard to see on this slide.

So, I am going to simplify it on the next slide. So Slide 11 shows a simplified cross section of the North West Gharib 27A discovery.

It's a thick reservoir deposited in the tilted low area between two highs. We generally drill in a location to test for the maximum thickness to find the reservoir, which is what we did on 27A.

And we found a very think reservoir sequence, about half of it filled with oil. The next step is to drill an appraisal well up structure which is identified from the dip logs and hopefully encounter this entire reservoir above the oil water contact.

That should result in a highly prolific well with a capacity perhaps in the 1000s of barrels a day. Based on our mapping and the reservoir attributes of the discovery well, we think there could be 18 million barrels in place in this discovery.

So, we are pretty excited about this opportunity. Moving back to the locator map on the next slide, we find that North Gharib No.

38A which is about 2.5 km to the southeast of No. 27A.

It's highlighted in red in once again. And here we are testing, similarly, for an area for the six Red Beds reservoirs.

And we found those, and came up also with an oil discovery. 38A encountered six Red Bed conglomerate with oil similar to the 27A discovery.

The next slide kind of shows you what it looks like. So, on the 38A we got a 30 meter or 98 foot oil column with just over 39 feet of net pay.

But there was a fault at the base of the oil pay, so we have some more work to do here to determine where to move for the appraisal location and potentially find the basal sandstone that we identified in North West Gharib 27A, we believe that exists in this area, but we're probably going to have to move one direction or another to try and get away from that fault. If we just take the thickness encountered in the well bore we estimate there could be 12 million barrels in place in this accumulation.

However, we do have more work to do and drill a few more wells, because we do expect there is a thicker reservoir if we can move away from the faulted section and full thickness of Red Bed reservoir. That's probably enough technical discussion for this quarter.

We're all pretty excited here at TransGlobe. We are back to drilling, now, with two rigs running.

We have two nice discoveries under our belt, and we have 13 more exploration locations left to be drilled. The balance sheet is strong, costs are down significantly, and we continue to work on reductions.

And we are starting to see some strength in the oil prices as the supply-demand balance comes back, and we'll have a clear plan to increase our production moving into 2017. I'm certainly far more optimistic now than I have been in the past two years.

So with that, let's turn it over to the Q&A session and see if anybody has some ideas about what we've been doing here. Operator?

Good morning gentlemen. Well, congratulations.

This is a very exciting update on the North West Gharib Red Bed discoveries. Ross, you've done a great job of describing the discoveries 27 and 38.

But you also -- I was wondering whether we could quickly revisit the two dry wells in the Red Bed, which is further South. And any color, any detail you could provide with a view to get a feel for the prospect, following [ph] on slide eight, you showed the other two prospects as well, 2016 locations.

And what do those failures mean for the follow-on prospects?

Yes, those two in the south, we also encountered the Red Bed reservoir but however it was wet in both of those. And so we're reworking that, and seeing is there opportunity to either move up dip on those or was there a charge problem or something like that.

But we do know that there is -- oil moves through that area, because they are relatively close to our Arta discoveries. So it's really just an iterative process, okay, now we found the reservoir, we tend to look for that first.

Perhaps the next step is we do an up-dip test closer to the [indiscernible].

Okay. And page five of your report, you have a table that also shows the TBs for these prospects.

Can't really read too much into those, right?

It's Lloyd here. Yes, it varies.

As you can see from the cartoon maps that Ross showed, that you're stepping down quite quickly on somebody's little fault box and [indiscernible], so -- but the message is, they're really shallow wells. I mean, certainly on the Red Bed area, we're looking at $500,000 to go down and do a test on these various wells.

So it's very inexpensive exploring.

Yes. And just two quick follow-on questions, one is, Ross, did you say assume your recovery facts [ph] for 20%.

Just wanted to confirm that I heard you right? And could you give the free drill estimates for the follow-on prospects on the rest?

Well, there's a whole list. There's 13 of them.

I don't think I'm going to be able to go through it.

Well, the next two that are shown on your -- have been highlighted on your slide…

[Indiscernible]

Yes, we haven't press-released those so we can't release that in this call. But certainly the next one, we're just running production casing on North West Gharib 38, and we are moving over to North West Gharib 26, which is immediately west and up in the next structure, up from North West Gharib 27 discovery.

So we're pretty excited about that on. We know there is big sand presence in the area.

So we've got a lot of drilling to do out there.

Okay. Actually, one of your previous presentations show there are eight prospects in North West off the block right on the edge of the boundary.

That seems to have dropped off in your latest presentation.

Yes, we had notionally put in up to 22 in the previous presentation. Our actual commitment is for 18, and will be tight to get all those into 2016.

There's other ones we can drill in 2017. So that's probably the difference.

We're really focused on the 2016 program.

Okay.

Yes, we do have a six months extension into 2017 on North West Gharib. So there may be some additional drilling in 2017 on North West Gharib.

Okay. And just to confirm, Ross, you did say assume 20% recovery facts.

No, I said 25 actually. That's about normal for these kind of reservoirs.

I've had a senior moment. My hearing is going.

Thank you.

Thank you.

Yes, good morning everyone. Interesting to read of your new reservoir simulation, you're having two to four million incremental million barrels.

Are there other field pools that offer themselves up as candidates for such reanalysis within the Eastern Desert?

Yes, absolutely. I mean, one of the key drivers of course was the performance of the pool has been running ahead of what we had been forecasting.

But it took the better part of nine to 12 months to build a brand new detailed simulation model incorporating all the new wells and core data. So these things are big undertakings.

We see a lot of potential, certainly in the K Field with K South, but we held off on redoing our simulation there until we've got the current K South wells. Well, we'll look at kicking that off probably in 2017, but we're not likely to see that new [ph] fully developed model till sometime later next year.

There's other fields like Hana, we could do some more work on, and some of the H fields. But probably the next big one would be the K area where we have this exciting development going on in the K South.

Okay, thank you. And with the third quarter guidance, which is pretty much in line with what you delivered in the second quarter.

Perhaps I've misheard you, is it safe to assume that your PRP program is already in action, and yielding results or what else should I be looking for because obviously you have high production modestly done?

Yes, sure. Really the PRP, a lot of that work, the identified recompletions and workovers, that's in the approval process right now.

We've probably got 10 out of the 16 recompletions have received approvals. They're in the schedule for the completion [indiscernible] and start doing that work.

The only thing that we've really kicked off, I think we've done one re-completion. And of course, we started the drilling in K Field.

So the first K well went on in June. The one that we're just finishing up on today, we'll have that on production sometime in September.

So the plan always envision the actual fieldwork kicking off primarily end of August-September. So we'll be ramping up through Q4.

You got a hockey stick. So in terms of the impact of the various projects and timing, yes, you're obviously still confident you can hit your numbers as published there?

Yes, we hope it's going to coincide with that hockey stick in the oil prices.

Indeed. Just a quick question on costs, it's nice to see a 5% trimmed off both OpEx and G&A sequentially.

Have you identified any further savings that you expect or plan to realize this year or do you think 5% is pretty good?

We think we've largely driven those costs down pretty much to the baseline. There is one area we're still focusing on and working on.

And that is we're in the process of consolidating or trying to consolidate our two joint ventures, West Bakr and West Gharib operationally. We're partially merged.

We're starting to share things like the completion rate. We're looking at warehousing; we're looking at joint tenders.

So as we work that through we expect to see significant efficiencies in cost savings through contracting. But it's hard to put a real number on that, but we still see some running room there.

But baseline costs, we're down around $10 a barrel. These are fairly mature fields, so of course you're always dealing with increasing water cuts and those sorts of things.

So it's a pretty good number. North West Gharib we would expect to see lower cost because they're younger fields, and you're moving less fluid.

Okay. And lastly, regarding your cargo sales, I know we've spoken about this before, but are you slowly getting any further traction through your conversations with EGPC with regard to getting visibility, increased lead times so that you can bet the market you're [indiscernible].

Well, you've hit the nail on the head there, David. That's exactly what we've been working with them on, is trying to get more long-term visibility on it.

It's been difficult. And I think in part that's what's hurt us on our pricing over the past two years, is that we haven't had enough visibility in order for us to properly market these cargos.

But we're working on it with them. And we're hopeful that this quarter -- this next quarter we'll be able to get something worked out so that we'll have full visibility on 2017 cargos without doing this kind of quarter-to-quarter thing that really puts us in a bit of a corner in trying to market lifting with only four to six weeks of lead time.

Yes, I agree. Okay, thank you all.

That's it from me.

Hi, this is Luana Siegfried in for Pavel. Well, thank you for the conference, and congratulations, and the exploration program.

I want to touch a little bit on the potential acquisition. I understand the company is still looking for a good portfolio.

I was just wondering, when the time comes, as TransGlobe has a preference for an all-cash acquisition?

Well, it depends on the size of the asset, and what we're looking at and where we're going. That's kind of an open-ended thing, how to finance the acquisition.

There's lots of different ways to do it.

I'm sure, I understand. If I could maybe have one follow-up.

I was wondering in terms of cash allocation, TransGlobe has definitely a very cash-rich balance sheet. So when the environment gets better where the preference for the cash allocation would go?

Well, with cash, we're holding the cash obviously for the convertible debenture that's coming due in seven months. When you take that off there's actually not that much cash sitting there free.

And we've got a very active program with discoveries which are going to require development. So I wouldn't characterize it as -- I mean, we've certainly got a clean balance sheet but I wouldn't characterize it as super cash-rich.

And a lot of it is also if we're able to do an acquisition, the expectation is we'd be going into an acquisition that may be hadn't had as much capital put to it as it would need to. And so that cash would be deployed in developing the acquisition.

So it really depends.

Perfect. Thank you very much.

Yes, good morning guys. I've got two questions.

One about the portfolio and the other about the debt, I'll do them separately. So in terms of the current portfolio, are you still looking at maybe farming out and getting some help with the expiration campaign?

And also on -- with respect to that, I see from the slide eight that the prospects extend off the block. That's quite unusual.

Usually they die at the edge of the block, particularly if somebody owns the block next door. So I'm just wondering if somebody does own the block next door to the North of North West Gharib.

It's open land to the North, but in our models, I mean, we have a much more sophisticated model on sand deposition. It's unlikely that sand does extend there, because it comes off of the high to the West.

So it is a stratographic [ph] trap, it's not a structural trap.

Right, and farm out?

That's not underway anymore.

Okay. And then just going back to that debt question, I mean you say you are keeping the cash to pay for the convertible but, Randy, we have looked at alternatives.

So I suppose the question is what deck is currently available to company folks from Egypt?

Yes, we are looking at actually a whole host of alternatives that you know -- you'd say plan, Plan A would be that we refinance the convertible debenture, because we have an acquisition and we have plenty of opportunity to invest the cash that we hold. That's plan A.

But time will tell in terms of oil price and receptivity to debt offerings by oil and gas, or small oil and gas companies. So we are looking at a number of alternatives, and they are quite arranged.

I'd say, currently we feel there is definitely interest out there, but we will have to work through that, through the fall, that's sort of objective one for me really starting in September to work up that number of alternatives in order for us to sort of come up with the right one. If the whole market goes south again, we are back to $30-oil, then January, February, and we are going to have to use our, you know, a big chunk for cash to pay that out, but that's not the objective.

Okay, thank you.

Okay, I want to thank all the participants in our Q2 conference call. We should have a mid-quarter update in September to keep everyone up to speed on our drilling results, in our production numbers, as we move through the PRP.

Thank you everyone, and that's all for today.