All participants, please stand by, your conference is ready to begin. Good morning, ladies and gentlemen, and welcome to the TransGlobe Energy Corporation conference call and webcast. This webcast includes certain statements that may be deemed to be forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. All statements in this webcast other than statements of historical facts that address future production, reserve potential, exploration drilling, exploitation activities and events or developments that the company expects are forward-looking statements. Although, TransGlobe believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements. Factors that could cause actual results to differ materially from those in forward-looking statements include oil and gas prices, well production performance, exploitation and exploration successes, continued availability of capital and financing, and general economic, market or business conditions. I would now like to turn the meeting over to Mr. Ross Clarkson, President and Chief Executive Officer. Please go ahead, Mr. Clarkson.

Good morning everyone, and welcome to TransGlobe Energy Corporation's fourth quarter 2015 conference call. This is Ross Clarkson, President and CEO. With me, I have Mr. Lloyd Herrick, Vice President and COO; and Mr. Randy Neely, Vice President Finance and CFO. As usual, we will start out with a summary of the financial and operating highlights. Randy Neely will now review the financials and highlights of the quarter starting on the next slide.

Thanks, Ross. Good morning. 2015 was by most measures a very difficult year for TransGlobe and the entire industry. At this time last year there was a sense that prices could recover to more sustainable levels, but those hopes faded as summer approached and oil prices resumed their downward trajectory. As a result, the second half of the year, and in particular, Q4 proved to be one of the most difficult periods in memory. These difficult times of 2015 completely overshadowed the company's achievements of obtaining the cooperation of EGPC in directly exporting our crude oil entitlement barrels. Since the beginning of the Arab spring and the first political revolution in Egypt in January of 2011, in our view the biggest overhang on TransGlobe share price was our exposure to EGPC credit risk and the significant delays in the collection of our accounts receivable. In 2015, all of our Eastern Desert entitlement barrels were sold directly to third-parties, or remained in storage at year end. These third-party sale transactions are settled in approximately 30 days after lifting occurs and are backed by guaranteed letters of credit, effectively eliminating all of our credit risk. Unfortunately our sales cycle was irregular at this time and resulting in lumpy revenues, demonstrated by the fact that we did not sell any entitlement barrels in Q4. We have also had difficulty in obtaining adequate advance notice of our tanker slots. At times, we have had only four or five weeks' notice, which is not adequate time to maximize sales target [ph]. We are working with EGPC, and are hopeful we will remain -- we will make improvements on these in the near future. However, we do feel that these items are relatively minor in comparison to the credit risk exposure we previously faced. Sales volumes…

Thanks, Randy. This slide summarizes continuity of our year end reserves by category, as press released on January 22, this year. On a CUPI [ph] basis, reserves at year end 2015 were 28.7 million barrels, which represents a 14% reduction from year end 2014. Year-over-year, reserves were lower primarily due to minimal capital investment, 5.3 million barrels of production from the sale of East Ghazalat reserves in 2015. Year-over-year reduction in respect to reserves was partially offset by performance increases at Arta and at the West Bakr pools. Next slide; this slide summarizes the present guided future net revenue for the company at year end 2015 and '14. At year end 2015, the after-tax NPV of the company's 2P reserves using 10% discount was 195 million, approximately 43% lower than year end 2014. The year-over-year decrease in NPV is primarily attributed to lower reserves and a lower price forecast of year end 2015. Reduction in the after tax future net revenues were partially offset by the reduction in future development capital of approximately $20 million on the 2P basis, which was primarily associated with better recoveries per well and lower drilling cost in K field undeveloped reserves along with a better pricing differentials for West Gharib crude sales stream due to our direct marketing. Next slide; this slide shows daily production by concession for the past 12 months, production was held pretty stable throughout the first three quarters of 2015 despite minimal investment during the year. In Q4, productions have come to minimal investments; natural decline is beginning to impact production. December and into 2016, production has been further impacted by reduced workover comp changes on higher cost wells due to very low oil prices during this period. The recent increases in Brent to near $40 a barrel in the…

Okay, we are on Slide 9, which shows our West Gharib, West Bakr lands in dark yellow and orange. And those are the original core holdings in the Gulf of Suez and currently make up 100% of our producing assets. They are surrounded by the pale yellow lands which we acquired in the 2014 bid round and all of these lands are 100% working interest to TransGlobe. The West Gharib and West Bakr properties were acquired through separate transactions, which meant we inherited two independent JV companies or joint venture companies with independent boards, staff, and operating contracts. In late 2015, we were able to start consolidating those two companies into one JV, thereby saving on cost. The consolidation has resulted in cost reductions for staffing as well as savings through the contracting of only one service rig versus two rigs and running only one field camp, one set of inventory spare parts, and many other areas of duplication. When we bring the new discoveries on the pale yellow, Northwest Gharib land into production, they also will be managed by this single joint venture. We are very pleased that the government has worked with us to consolidate these JVs which will lead to longer term cost savings in our operations. As Lloyd mentioned, we had not been actively working to bring up production in these projects because of negative economics at the current oil price. However, we do have several thousand barrels a day production that we can bring on if we see consistent pricing in the high 40s or low 50s for Brent. The direct marketing of our entitlement oil through the costal pipeline and loading facilities is working well and we are getting the tendering and sale process smoothed out with each tanker load. We sold one tanker…

Certainly. Thank you. We will now take questions from the telephone lines. [Operator Instructions] The first question is from Shahin Amini with TD Securities. Please go ahead.

Good morning, gentlemen. A couple of questions on your -- well, first one, West Gharib storage and cargo lift logistics, so when you reach the peak of 920,000 barrels, I just wonder what are the storage constraints at West Gharib? And perhaps you could shed a bit more color on why you didn't actually have a mix in Q4 '15. You may have explained that, so I apologize if I am covering old grounds. And the second question is your February lift, could you perhaps elaborate further what is the CAGR go-to [ph], and although you mentioned a discount to Brent, what was actual Brent that discount supply history?

Go ahead, Lloyd.

Okay. It's Lloyd here. Certainly on the storage side, we've -- there's quite a bit of facilities on the coast, but really our storage is more of a scheduling exercise. So, some of it's in the barrel, some of it's just scheduled for when we can get a lifting allocated from EGPC. As Randy said, it's been lumpy, and we are working through the process. EGPC had some commitments. So as it turned out, we didn't a quarter -- tanker lifting in the quarter, but we did get one in Q1, and we've already had another quarter of lifting in Q2 which we are going to lift in late April. As far as the pricing goes, it will be on the average of date of Brent. Randy, I am not sure if we have that number.

Yes, I think it was low 30s with the date of Brent average for the month.

So when you take 14 off of that, it's a pretty small amount.

About $18 I think roughly.

Yes.

Yes.

Did that oil tanker go to Europe, or did it head to India?

That particular one went to India.

India.

India as well, okay.

Yes. Because of the sulfur content of the West Gharib Brent, there is limited number of refineries that will take it.

And so, India remains your primary market then for you crude?

That has been traditionally the largest buyer last year of crude. We have had conversations with other markets, and we are working on that to increase the competition, but the closest and the biggest market for that crude is in India.

Yes, but do you have any concerns with the uranium crudes coming back to market? I mean, do you see an impact on the market dynamics in the recent month or so?

Absolutely. I mean, the Basrah Heavy coming on, the RIN [ph] has certainly widened out the differential. That's why we are seeing a $14 differential in this quarter. We expect over time that will close as the prices improve, but yes, we are feeling it, no question.

And -- thanks, Lloyd. Just a very quick follow-up on the EGPC giving you access like giving you a slot. I mean, what drives that force, is it just a case of you having to wait for a window where you could bring your tanker in, and -- or other issues that could be impacting the…

Primarily it's scheduling exercise, and they have tanker commitments, and we are relying on them to give us our window. We are certainly looking -- we will be bringing down that inventory quite a bit, but like we said, it's a learning process on both sides. They are not used to scheduling somebody else into their schedule.

Okay. Well, thank you very much for your time. Thanks.

Thank you. The next question is from Ian Macqueen with Paradigm Capital. Please go ahead.

Hi, guys. Just wondering if you could help me out with respect to sales; so, sales for the quarter in Q4 was 663,000 barrels approximately, but there were no lifitings in Q4. I assume that's later settlements. So once we fast-forward to Q1, you had 554,000 barrels lifted. Does that mean that that's actually going to be the sales number in Q1, or that would be about 6,000 barrels a day?

No. What you're -- Ian, it's Randy. What you are seeing there is when we deliver -- our sales are we include the amounts that we then account for as royalty from taxes. So, we basically deliver the barrel into the system, the government share are also sales. It gets booked on our books as royalties and taxes, and then the remainder of it, the entitlement barrels go into inventory. So what you are seeing there for Q4 sales is principally just royalties and taxes. There is a little bit of volumes associated with East Ghazalat after the first 13 days of October.

Okay. So if we look at your entitlement barrels that will be sold in Q1 is about 544,000 barrels?

Right. So Q1 will produce -- everything we produce there will be a portion of it that gets delivered to EGPC and that they will take in time. So that will be our sales, but we will book that as well to taxes. And then the entitlement portion will be our sales for the quarter, which will be the other portion of it.

Okay. Perfect. Okay, other question is, you said that there is a chance that you'll reduce some of your CapEx budget from the 41 -- by reducing principally development CapEx. You've also said in the past that you are in discussions about potentially delaying some of the commitments for Phase 1. What would be the hurdles and what's the likelihood of being able to delay some of those costs, because obviously it would be nice to see some of the cost push through to 2017?

Yes. It's Lloyd here. So, on the development side, that's entirely up to us. And these prices continue. We would mark off approximately $10 million and push it into the following year. Some of that development dollars is some of those sub-K wells. We are going to drill one. We plan to drill three. If prices don't improve, we are probably just going to drill to push them. The rest would get pushed into next year. The other projects are things like the Northwest Gharib discoveries that we made in 2013. We haven't moved those forward. We are planning to bring some of those on at the end of the year. We could slow that a bit more, but it comes to a point in time when you have to move forward [indiscernible]. Exploration wise, we have had conversations about expansions and it may allow us to stretch it into next year, which will reduce some of that 22 million into next year if we go to a single rig line. Right now, we are starting with one rig. We have the contingencies to bring a second rig in mid-August, which would allow us to meet all our commitments by November, which is kind of the deadline for the first phase, but we've already had the indications we're going to get an extension on at least one of the confessions. So there is a scenario where we could push maybe $5 million-$6 million into 2017, by just going with the single rig line. So there is a number of moving pieces, but that's kind of where we are at, and that's very dependent on oil prices.

Okay.

And we expect some of these drilling costs will be lower just based on the bids that we have been getting, but again, we will see how that plays out as we get the wells done.

Okay, perfect. Last question, which is something perhaps I didn't pick up on before, as your potential additional recovery in the sub-K pool, how much of that would actually be in your 2P reserves now, or do you have an estimate?

Currently it's all in the 2P reserves right now.

Okay.

You could see there in as a probable or proven undeveloped.

Okay. Perfect, thanks.

We have been looking upside to those numbers, but to get drill them and get them producing, you got to go with the third-party estimates.

Perfect. Thanks very much guys.

Thank you. The next question is from Pavel Molchanov with Raymond James. Please go ahead.

Hi. This is Luana Siegfried in for Pavel. Thank you for the call. I have a couple of questions to you; first, I wanted to ask about the dividend suspension, your tax balance actually increased in 2015, despite a flow of oil prices. So presumably the dividend was supported by balance sheet for quite some time, is that in current condition, but obviously I think management around this is a bit different. So maybe you can clarify what was the thought process for the suspension of the dividend?

Well, I think we supported the dividend off the balance sheet all through 2015. And a lot of that was due to the receivable money that were coming in, and not receivable money that we were getting paid debt back, and was really from plus $100 oil sales. And we've largely worked our way through that, and now we're looking out in 2016 at a continued lower longer oil price that really doesn't support our development program and our exploration program let alone the dividend. So it just seemed the prudent thing to do, to -- suspended for the time being until we see higher oil prices.

Perfect. And if I may touch on the acquisitions, so you are often looking for [indiscernible] fees, and I would appreciate if you could share with us more on the topic about any specific location that you have been doing negotiations, the type of facilities that you are looking for, and that will be it for me, thank you.

That's a little difficult to answer, because we are looking at a number of jurisdictions, but we, as I mentioned, I mean we've looked at North America recently, a number of jurisdictions in North America, we have looked at onshore Europe, basically looked at the OECD list, I would suggest, and anywhere there is oil and gas that's where we're looking.

And I think just to add to that; we are clearly continuing on to look for cash flowing opportunities, not explorations. So there would be exploration components to it, but we're looking for existing production and development opportunity, and that's consistent with what we have been saying for a few years.

Yes.

Perfect. Thank you very much.

Thank you. The next question is from Al Stanton with RBC. Please go ahead.

Yes. Good morning, guys. A couple of questions, just first of all on the choice of spending; on the one hand I saw the development cash or CapEx would be immediately cost recoverable, so it would look quite attractive, whereas on the exploration side, you haven't got that benefit, and given all the decisions by M&A and acquisitions, you did not mention anything about divestments. So have you looked at spending money on development activity and farming out exploration activity?

Yes, it's Lloyd here, Al. Couple of things, yes, we have looked at everything, but as far as the cost recovery goes, at the current price levels we are not recovering our costs day-to-day. So we're building cost pools now. So anything we put into those cost pools is just -- it just sits there in the future of waiting for prices to recover. So there is really no acceleration on that. On the exploration side, those are commitments, so to the extent you either drill them or you give the government the money, we much prefer to drill the wells. We are looking at extending them, and yes, we've had conversations around possibly allying off the portion of our interest, but as you can appreciate, it's pretty difficult market to form out exploration opportunities.

And quite frankly on the development side, we'd rather leave the oil in the ground and essentially inventory in it in the ground rather than selling out our assets at this low price. It just doesn't make a lot of sense. So, cutting back on development is essentially restricting your producing assets a bit, and leaving the oil inventory in the ground.

And then the other question was probably surrounding in terms of the debt repayment is now about 12 months away, I was wondering how much of that takes up of your time and intense, albeit that seem amortizing away at the moment as well. So, where you are on looking at the refinancing?

Well, yes, on the RBL that's right. It is amortizing. We've actually consciously chosen not to try to renew it at the time, because we don't use it. We are only using it for LCs, and the LCs are going down as we meet our finance commitments on our blocks. On the convertible debenture, I mean the big thing for us is we have got the cash to pay it, and we are going to continue to hope the cash with the idea that we will repay it. I think, refinancing in the current oil environment, well, certainly a few weeks ago it certainly looked pretty bleak, but although the last couple of weeks have been a lot better, and we have seen a lot more financings get done recently, but we will have to see prices recover above $50 for refinancing of that debenture to occur if it was strictly in Egypt.

All right. And so, just on that last opening then, is the OECD a source of debt finance as well as a source of future production?

Well, we are looking at it as a source of future production in cash flow, and of course the diversification of our asset base, and a lowering of the oil price that's required to make the company profitable. And so, I think with that, of course would be increased ability to finance.

Okay. All right, thanks guys.

Thank you. [Operator Instructions] The next question is from Sean Keller [ph] with FK Holdings Investments. Please go ahead.

Hi, guys. Thanks for taking the time for my question. I just -- and it was partially addressed on the last question, but I just was wondering, you know, looking out to 2017, what does your liquidity look like at that point when the debentures come through? And just assuming oil at a strip price, do you have the cash there to pay back those debentures, or is there a thought to maybe look to convert that debt to equity?

Well, I guess the first question to be which strip today or two weeks ago, every day it makes a difference. I mean, for us effectively at the current production rate, every dollar move in the strip provides an extra 2 million in cash flow for us. So it's -- we are pretty sensitive to strip. Repaying with shares is not something we want to do, but if oil prices stay in this range, $30 to even $40, it certainly is a possibility that at least part of the refinancing could be in shares.

Okay. And part of it, so I guess there is an opportunity to maybe do half cash, half shares or something like that?

Yes. It's up to us Sean [ph], how we repay it. We could repay it of course in cash, or we could repay it in part of the cash and probably shares, or all shares. Our attention is to repay in cash. I mean, we do have a low Canadian dollar, although it's bounced back a fair amount over the past couple of weeks as well, so we do save on that. The debenture is priced in Canadian dollars.

Yes. Okay, great. Thanks a lot.

Thank you. There are no further questions registered at this time. I would like to turn the meeting over to Mr. Clarkson.

Well, thank you for participating in TransGlobe's Q4 conference call, and for the great questions. We will see some reports out on our drilling results as we move through the second quarter. Thank you very much, and good morning everyone.

Thank you. The conference has now ended. Please disconnect your lines at this time, and we thank you for your participation.