TransGlobe Energy Corporation
Q2 2018 Earnings Call Transcript

Published: 14 Aug 2018

[Operator:]

Good morning, ladies and gentlemen. And welcome to the TransGlobe Energy’s Q2 2018 Conference Call and Webcast. This webcast includes certain statements that maybe deemed to be forward-looking statements within the meaning of the US 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, Chief Executive Officer. Please go ahead, Mr. Clarkson.

[Ross Clarkson:]

Good morning, everyone. And welcome to TransGlobe Energy Corporation’s second quarter 2018 conference call. This is Ross Clarkson, CEO and with me I have Mr. Randy Neely, President; and Mr. Eddie Ok, Vice President, Finance and CFO. As usual, we're going to start out with a summary of the financial and operating highlights and then we’ll jump into a discussion on some of our results and plans for the balance of the year. And then we'll follow that by a Q&A session. Eddie Ok will review the financials and highlights of the quarter starting on the next slides.

[Eddie Ok:]

Thanks, Ross. Good morning to everyone and thanks for joining us on the call. Average production volumes for the quarter were around 13,000 Boe -- 13,800 Boes per day compared to just under 16,500 Boes per day in Q1 '17. We had a substantial inventory draw during the quarter with two cargos of oil lifted and ended out the quarter with just over 500,000 barrels of Egyptian crude inventory. As discussed on our mid-quarter update, we had a third quarter lifting occur in late July and expect to receive those proceeds next week. Our quarterly funds flow from operations continued to stay resilient due to a sustained price strategy across WTI and Brent. For the quarter, funds flow improved by approximately 98% quarter-over-quarter, which is inclusive of $10 million unrealized hedging loss. While crude prices continue to stay resilient, the boosts for the company’s results were partially offset by continued pricing weakness in Canadian dry gas and the shutting of Canadian production in May for our turnaround operations. As expected, Egypt OpEx moderated from the pervious quarter to average around $9.60 a barrel and Canada’s significantly higher of OpEx $12.31 Boe was impacted by shutting production in May due to our turnaround. The strength in commodity prices continues to pressure costs both in Canada and Egypt as service providers are seeking to participate in commodity price rate increases and goods and services. G&A in the period was up significantly. The majority of the $1.5 million in cost related to the AIM listing are incurred in the expense in the quarter. The largest component to the increase in G&A relates to a repricing of stock-based compensation liability. This non-cash adjustment was approximately $3.5 million as a result of share price appreciation post eight months of the announcement. With two liftings in the quarter, we ended out June with $38 million in cash and over $60 million in working capital. Next slide please. Our capital plan was originally budgeted to a $55 per barrel Brent level and we’re now budgeting total capital spend for 2018 of $44.1 million, a minor increase which includes a horizontal evaluation well on the new lands acquired in Canada. We continue to actively manage our debt and capital allocation strategy with the intent of further reducing debt in 2018 and focusing our cash flow accretive investment decisions. As announced, we will be paying a $0.035 dividend in standard shareholders of record on August 31, 2018. The company listed on the AIM at the end of June and we will be establishing an executive office in London to increase investor interest and pursue business development activities. I will pass things over to you Randy for additional detail on our outlook and plans.

[Randy Neely:]

Thanks, Eddie. As you can see we've made a couple of revisions to our 2018 capital program from our original plan. The two most noteworthy changes are as follows

[Ross Clarkson:]

Okay. We're on Slide 7, which is just generally a locator map for all of the assets, the two focus areas which is the Eastern Desert over on the Gulf of Suez and that's where we produce all our current oil production and in the Western Desert where there are three concessions South Alamein, South Ghazalat and Northwest Sitra. On the next slide, on the Eastern Desert. This is really a summary that most people have probably seen before, but we've got the discoveries we made in Northwest Gharib up in the North and two of those discoveries are really just North and South of the Arta field that are really extensions of that field. And then the development leases are the pale tanned colored areas that we received approval for in the last while. Some of the wells that were brought on production following approval of those development leases happened in the last quarter. But the majority of our drilling this year is really focused on the Southern most orange colored block, which contains the Bakr K-South and M-fields. And there is a little bit of drilling up on the Northern area where we're trying to get water injector which I'll talk about. The -- in addition to drilling at various fields, we're doing quite a lot of work on expanding our water handling facility down in the K-field and construction of a similar facility on the H-field. Those fields really have a lot of oil in place and we need to expand our capacity so we can re-inject water with the increasing water cuts and ultimately expand the total oil produced out of the field over time. That doesn't sound like a really exciting project, but it adds a tremendous amount of value, it really is something for the future. Let's review some of the drilling that happened on the next couple of slides, Slide 9. On the K-South field we've already talked about this but we drilled K-46 and K-45 and both wells came in with thick pay sections and are on production. They added initially over 400 barrels of oil per day of new oil. And drilling on those crustal areas really allows us to capture the attic oil that probably never would have been produced from the further down structure wells. We have one additional location here at K-31 up in the Northwest corner of the pool, and that will probably be drilled in 2019. And then the expanded K water handling facilities that I talked about really allow us to produce these fields for a number of years into the future. Moving on to the next slide, on Slide 10. This is where we’ve been drilling the M-field wells that Randy mentioned and you can see this field really straddles the boundary between us and an offset operator called Dublin Petroleum and the regulations used to keep us approximately 250 meters away from that boundary there, just to not to get into competitive drainage but we worked out a deal with the offset operator an A GPC to lower the spacing that the crust occurs at the red area of the pool right up on the boundary. So we’re going to drill two wells for each party. We are drilling and M-North and M-South and we just completed the M-North well recently and have significant pay section there, about 132 feet of Asl A and a little bit of Asl D which we won’t be completing. But we are pretty happy with that result. We’ve just got the rate on to M-South. As a matter of fact we started drilling this morning, we’re just at the surface hole and so that will be finished in a few weeks. And both these wells will be on production very quickly, M-North actually should be on production by next week. And that's going to allow us to drain the crust of the field just like the previous location at the K-South and that's extremely important to get the maximum recovery. We’ve also got a plan here to twin the M-19 well which is a little bit South of the two wells I have been talking about. It's highlighted there on the map. And in M-19 we been producing from a deeper horizon the Asl D section and there is a very a thick pay section behind pipe in the Asl A that we probably at this time will not get to for several years but with higher oil prices it really makes a lot of sense to accelerate the oil production by twinning this well and producing the Asl A. These are particularly quite large wells 300 to 500 barrels a day typically, and they go along way towards offsetting our declines and increasing our production. So we’re actively working on a plan to move that M-19 well into our next drilling campaign. Couple of maps now on the Northwest Gharib development leases. We’re still developing the fields up here that we found and we’ll try to figure them all out and it'll probably be several years before we completely understand what we've got here. The number one lease is the one on the north part there where really getting most of the work this year because it has the more prolific red bed formation. We drilled Northwest Gharib 38 injector location at the south end of pool hoping to get a water injection point because these fields definitely need water flooding and water’s pressure support to get maximum recovery, but darned, we found a full oil column. So we had to complete it as an oil well, we didn't get a water injector. This is -- really kind of reminds me of the Arta field where we kept drilling down structure -- and kept drilling down structure to try and find water injection points and eventually ended up with 1,800 feet of oil column. So eventually we will find the limits on this oil pool also. We’ve got another well now staked and another -- and a third well also further down structure staked and getting ready to drill holes after the M-fields further down the South area. Really trying to get a point where we can get into the water lake so that we can start water injection and ramp up production on the field. We are restricting production on this field right now simply because we don't want to bring the pressure down below the bubble point. And this is the same reservoir that we found in the Arta field. It's the red bed formation. And we put water injection into that field and successfully increased the recoveries and the reserves on that through water flooding. We've also got several up-dip locations on that pool to fully develop it and the structure is quite complex. There is a lot of faulting going on but we have to drill a number of wells over the next few years to figure out these pools. So we still got quite a bit of inventory here to continue on with. The next map, that's the old Arta area where we've been doing a little of work there. We've got couple of new development leases, one to the North and one to the South of the main drilling area. On the Northern leased, we completed and fracked Northwest Gharib 1X got a small oil well then we completed Northwest Gharib 1A well and got about 70 barrel a day well. This is a little tighter up in there. And then in the Southern lease, we’ve completed Northwest Gharib number 5B for 90 barrels a day. And then the adjacent Northwest Gharib 5X in Q2 for about 350 barrels a day of initial rate. And then that came off and we started making quite a bit of water. And we're conducting some core studies and modeling to determine why is this happening. Typically, it's not I mean -- it's a structurally high well, it shouldn't be making the water like that, but we've got to do some work to understand that and see what make sense there. The plan that we've been looking at recently is horizontal redevelopment of this entire field because under the current scenario of all those vertical wells, we're only going to recover about 8% of the 60 million to 80 million barrels in place. So there is a lot of potential if we redevelop the field under horizontal drilling that we could get maybe as much as another 10% of the oil. And we're really working on the analysis on the cost structure to see how robust the economics are. And we're in discussions with the government on that also about how to encourage this project to move it along. These projects are really the cheapest oil we'll ever find, because we've already found it and it's really about improving recovery in the area. Moving on to the Western Desert on Slide 13, East to West our three PSCs, South Alamein, South Ghazalat and Northwest Sitra. And the two Western licensed Sitra and South Ghazalat have been the focus of our drilling campaign. And the first two wells however didn't work primarily due to a source and migration problem. And that's we're still drilling a deep Jurassic test which is different than the first two tests which were Cretaceous tests. And we're drilling at Northwest Sitra 12 right now which should be completed in another 30 days. But the failure in the Cretaceous has caused us to step back a little bit and rethink the area. And if you flip over to the next slide, we've got another map here that -- because of the two Cretaceous wells did not work, we reassessed our plans and decided to move to another location that we've mapped up for our third Cretaceous test. And we were drilling on the far left corner of the map you can see an arrow pointing to where we were drilling. And we were attempting to extend the productive basin westward. But now the third Cretaceous test will be headed in the midst of all the oil pools there in the South Ghazalat 6 location. This prospect is really a look alike to offsetting fields. And we're just finalizing all of the work as Randy mentioned to get this ready to drill in October. We have a rig that can come back to us on that. And one of the attractions here, of course you’re in a known basin where there is -- you don’t have a source and migration and trapping problem or reservoir problem and you can actually try right into some of the existing infrastructure. So it has quite attractive economics. Although it's not a particularly large structure, we are little more confident on doing that so we do want to get some oil out here in the Western Desert. On Slide 15, we’re in the main portion of our Canadian assets where we have horizontal Cardium formation oil wells. This year we’re drilling as a six well program, five nets from a single pad where that star is on the map -- on the inset map and in that we’re also drilling our first 2 mile horizontal, which other operators have experienced significantly better production and recoveries for a smaller incremental increase in cost to go to 2 miles of horizontal drilling. And these new wells will increase our percentage of oil production and increase the overall netbacks and cash flow for the Canadian division. Natural gas prices are still very low and are not projected to get a lot higher. So we’ve really focused all of our investment just on the oil pool. We shut in during May at the main processing plant where our product was shipped in spite and really did maintenance turnaround and that only happens every five years. We also used that time when we were shut down to do our own maintenance on our own installation. So that's now factored into our 2018 forecast, but it's good to get that up behind us. The new lands -- I have got another map here on slide 16, where we got 16 sections of new lands in the Crown mineral rights sales, these happen every two weeks in Canada and we bought in two different sales on 16 sections. And it’s just to the Southwest of our existing Harmattan stuff, you can kind of see on the map where it’s labeled there and there is a yellow band of productive Cardium down through the center of that -- well through the left side of that map. And our plan here is to evaluate this in -- at the end of our six well campaign and really add new well, we added a new well and here. If successful -- I mean if we get commercial quantities of hydrocarbons and we think we’re fairly confident we will get some hydrocarbons just as it’s going to be a commercial amount, and that could set us up for another 30 to 40 additional drilling locations in the future. It’s really simple to get this land and the land sale, but the cost structure is that you can't flare the gas when you're testing or in production, so we have to build a pipeline. We will be building a pipeline and tying it into our existing Harmattan infrastructure that we own 100% and that has significant unused capacity. So once we get the first well tied in then it's easy -- if it works then it’s very easy to continue on drilling and adding in more production from this new area because we have significant unused capacity. And we will see the impact of this Canadian program, both the new six well program to the North and this additional evaluation well in our Q1 2019 production numbers. So in summary, I mean we got our production guidance still relatively intact, a little bit lower on the top end but it's really focused 95% oil and liquids, there’s very little gas in the company. It's all pretty much lower. It’s development growth. We do have some exploration in Egypt and we hope to see some results out of that. It's all high working interest, virtually almost all of it is a 100%, it's virtually all of it, as a result all operated. So we do control our destiny and it's really torquing to oil prices. I mean a number of the analyst have put reports out on that, that we are extremely torqued to the oil prices, which means these higher oil prices recently have significantly improved our financial position and we can get back to paying a dividend. The AIM listing has proved to be very beneficial to us from a share price point of view and investor interest point of view. And as a result, we are also looking at starting up our executive office for a couple of our executives in London in probably mid-September. And part of that reason for that is we're actively seeking acquisitions in Egypt and in the general regional. And we're really focused out on that part of the area. And we have the balance sheet to do it. We really are in a position to go out and do additional acquisitions. So with that, I'm going to turn it back to the Q&A session at this time.

[Operator:]

Thank you. We will now take questions from the telephone lines. [Operator Instructions]. The first question is from Laura Engel from Stonegate Capital. Please go ahead. Your line is open.

[Laura Engel:]

Good morning. And thank you for taking my questions and as always great level of information provided and all the detail on operations. Just related to some commentary also from the press release. Can you give us a little more color or insight into -- you talked about cash reserves and paying down some debt over the year, but then you’ve also talked about potential acquisitions and some business development opportunities. Can you kind of comment on what to expect second half of the year just as we look at modeling and kind of where these allocations will be set?

[Randy Neely:]

It's Randy. Yes, I mean long-term our goal is to grow the company both through acquisitions as well as development. And so we want to balance the overall sort of spending in that regard. Acquisitions, the development keeping our balance sheet conservative, just we've experienced quite the volatility in oil prices over the last few years and having a strong balance sheet suited us well through that. In addition, we want to see go back to paying a dividend which we've done and we want to try to maintain that. And we're going to have a look at that on a regular basis. We said it out to look at it every six months and give consideration to all these factors before we determine what that dividend is. But long-term we want to be a growth company and that's where we're going to focus on principally.

[Laura Engel:]

Right. And then -- so any active discussions in the pipeline for specific acquisitions, or is it just something that you're looking for at the current time?

[Randy Neely:]

I don’t think I could tell you that. But we're always looking and we're pretty -- I think you’ve probably noticed we haven't done a whole bunch of acquisitions over the years. We like to find things that we can get at a good deal and then grow them much like we're starting to show in Canada where we've expanded our footprint here a little bit and we want to grow that organically over time. We did a very good job back when buying West Bakr and West Gharib where we look for those types of opportunities what we call them underdeveloped and [underloved] opportunities.

[Operator:]

Thank you. The next question is from Jenny Xenos of Canaccord Genuity. Please go ahead.

[Jenny Xenos:]

I have a few questions please. I will start with Randy and Eddie if I may. Production and operating costs as well as G&A were up substantially in the second quarter compared to Q1, I understand that you had a number of cost related to AIM listing this quarter that affected your G&A and also you have some increased workovers that resulted in higher OpEx. In addition you mentioned that you saw some cost pressures. So what do you expect these costs to average in the second half of the year and into 2019 and do you expect these upward pressures on diesel transportation and service costs to continue?

[Eddie Ok:]

Hi Jenny, it’s Eddie. Yes, with OpEx we have mentioned before the impact of diesel on our operating costs, and it goes along step with world oil prices, particularly in Egypt where we use diesel to power a number of our operations and we have noticed a [$0.70] to over a $1 impact per barrel on our OpEx as a result of strengthening oil prices, just directly translate through to higher prices we’re paying for diesel. So if oil prices continue to stay high our OpEx will continue to trend higher than we would have seen in ‘17. As for G,&A absolutely I mean the current period cost pressures that we saw from AIM listing cost and then non-cash adjustment that we have for the repricing of our stock-based compensation liability of $3.5 million that was a one-time or hopefully more than one-time increase due to the stock price appreciation that we’ve seen over the last couple of months. And going into the second half of the year, our expectation is that we should be seeing something more in line with Q1’s G&A going forward.

[Jenny Xenos:]

Okay, great. Could you also give us some guidance as to what kind of a discount to Brent you’re forecasting for Q3 and Q4, what you’re currently seeing in terms of trends?

[Eddie Ok:]

Yes, I mean we -- I think we’ll lead out the year with something around the $9 mark. Our last couple of cargos have been pricing in closer to $10 per barrel Brent at a discount. That has been due to some scheduling pressures. We’ve gotten some notifications or scheduling notifications from EGPC that were a little bit tighter than we would have liked and then just seasonal pricing on crude, there heavy crude that we export out of Egypt as well as in Canada we’ve got -- we’re getting hit with some -- a portion in pricing discounts on our crude oil, a portion is on the pipeline.

[Jenny Xenos:]

Okay. So about $9 a barrel is what you're expecting for the second half of the year?

[Eddie Ok:]

Yes, we'll see. I mean we're subject to market forces at this point as a small percentage or so. I’d probably look at $10 as guidance on that.

[Jenny Xenos:]

Okay. And has the fourth lifting been scheduled yet?

[Eddie Ok:]

No, we are in discussion right now. And we'll -- we expect to hear about that over the next couple of months as we work with EGPC to schedule that final ship for the year.

[Jenny Xenos:]

What are the chances do you think that will be in Q3?

[Eddie Ok:]

No.

[Jenny Xenos:]

Q4 likely. Okay.

[Eddie Ok:]

Yes, yes. We've already done our Q3, our Q3 listing is just done so.

[Jenny Xenos:]

Okay, great. And then if I may a question probably for Ross. You've drilled two dry holes so far in the Western Desert. So how has your interpretation of the area’s potential change? Do you still see 21 Cretaceous prospects there in 3 million to 5 million barrel kind of size? Also could you give us some color on the Raml and Southwest Raml field? I saw on the slide, you mentioned that they are about 8 million and 15 million barrels in size. And how -- what are they producing exactly, what quality of crude, how long have they been on production, what is the production rate. Any sort of color you can give us would be appreciated? Thank you.

[Ross Clarkson:]

Yes, Jenny. There is no doubt that these two Cretaceous failures mainly due to migration and source rock presence. That definitely puts a cramp on the remainder of those Cretaceous targets that we had out there. And that's why we've refocused over to the Eastern area. We'll have to evaluate all the data and really identify what the failure reason was. But I think right now we're thinking migration and source which does negatively impact that area. As for the one on the East, yes, the offsetting fields have been producing for quite a while now. And so that 7 million and 15 million barrel recovery -- the reserve numbers are also fairly accurate. It is light oil. It's typical 38, 40 API oil in the Western Desert. And we've got an offsetting target there that we're hopeful it works. And if it works then we got maybe two more follow-ups on that block. So it could work out to be quite a nice little add for us. I wouldn't say it's a giant company maker but it certainly looks like it's got a much lower risk profile for it and a lower cost structure to tie it in and get it on production, which is why we moved. I mean you have to be flexible when you're drilling exploration.

[Jenny Xenos:]

Yes. Absolutely that makes perfect sense. Great. Thank you so much for this color.

[Operator:]

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

[Al Stanton:]

Yes, thank you. Good afternoon, guys. Two questions if I may. First of all on the production guidance. I mean the range was very wide at the start of the year, up to I think it was 15.6. Now clearly that level wouldn't be achievable, but I was wondering what it means with respect to guidance for next year, whether the top-end of this year's range might be a reasonable estimate for where we could be in 2019 given that so much activity whether it’s expansion in Egypt or drilling in Canada is very much H2 - and like H2 weighted?

[Ross Clarkson:]

Yes, Al. Certainly because of the work that's being done and largely in M-field development and some of that shut-in production up in Northwest Gharib which we hope to get water pressure support in there that will allow us to ramp up that area. So those two things coming in the second half will certainly bode well for the first half of 2019. But beyond that, we’re going to have to start adding some more inventory to our position. And certainly Canada, I mean depending on the results of this sort of Southwest Harmattan area that could ramp up a program in 2019 there where we could get in and drill a drill whole new area and expand. So there are a couple of items that are happening here in the second half that could push us up into that 15,000 number in the first half of 2019.

[Al Stanton:]

And then in terms of -- there’s a couple of things the market is rewarding at the moment, one of them is dividend which you’ve announced today. The other is, sort of there’s production growth any which way you can and I know that you really seem to be achieving it with the drill bit -- with the exploration drill bit. I was wondering whether with respect to new ventures, whether you’re much more weighted to redevelopment and new development activities than you are to let’s say exploration.

[Ross Clarkson:]

Well, yes, right now we got quite a bit of focus on new ventures. We’re actively evaluating some stuff. You don’t what it means just like drilling a wildcat well with a new venture whether you actually get it or not, because it is competitive out there. And another thing we've been working on is really consolidating our Eastern Desert assets and looking at an expansion program on development there. But that's a longer-term discussion with the government.

[Al Stanton:]

And then just final question on that. Would we -- or should we anticipate new geography or is it still very much related to Canada?

[Ross Clarkson:]

We’re looking at one new geography but I don't know -- I mean we haven't seen a lot of the comparison -- before you go and step out into a new geography, you got to be pretty confident so -- on what you are going after. So most of our focus is right now in on Egypt for new ventures. Canada is just organic in and around our own stuff, we’re not looking at acquisitions in Canada.

[Operator:]

Thank you. The next question is from Gavin Wylie from Scotiabank. Please go ahead.

[Gavin Wylie:]

Just a bit of a follow-on to Al's question there, just on the guidance for Egypt that you gave. Looks like about 600 barrels just come off that top end. Does that relate to the -- I guess the delays in getting the water flood started up on Northwest Gharib, or is there some other factor that’s contributing to that?

[Ross Clarkson:]

Yes. That primarily is, that probably got 300, 400 barrels a day shut in up in Northwest Gharib, because we don't want to draw the pool down too far and darned we drilled a water injector and found a full oil column. So we couldn’t ramp the field back up, so it’s still shut in. We will eventually find the water, I mean its kind odd to being seeing, we’re actively looking for the water line but that’s the case.

[Gavin Wylie:]

And what you reckon is the kind of the ramp-up rate by year end, assuming that once the M-field development is kind of through -- get that rig back on the next well as an injector well, what you reckon you can kind get to by the end of the year? Is it just the 300, 400 that's added in, or is there a little bit more upside to that?

[Ross Clarkson:]

Well, if we assume the two M-field wells even at the lower end of guidance, they are about 300 barrel a day well, so there’s two of those that could come in and there is probably 300 in Northwest Gharib that we can bring back on, so that’s 900. But we’ve also got some declines in there. So maybe we can push our production back closer towards the top-end of the guidance for the second half of the year. It's not going to affect the entire year's production obviously.

[Gavin Wylie:]

Of course, yes. And then just a point of clarity. I missed what you said on the increased recovery factor for -- was it just the Nukhul pool, is that kind of the one that you're looking at in terms of the horizontal multi-stage development. And the recovery factor you're talking that you said 8%, moving up to what rate?

[Ross Clarkson:]

Yeah it is just the tight Nukhul, I mean it's got a lot of similarities to a Cardium play except it’s probably 5 times thick. And that's why we've been -- since we've been drilling Cardium wells and learning about what the new technology has been doing in North America we have really been refocusing that back into Egypt into this tight play that we've got a ton of oil in. I mean there is probably 80 million barrels in place. And we're only going to get 8%. So can we move that an additional 10? Maybe 12%, take it up to closer to 20% recovery in that tight zone through horizontal redevelopment. We've been quite successful on verticals, but -- and vertical fracs, but we're leaving a lot of oil behind.

[Gavin Wylie:]

And does that require additional approvals from EGPC or some other fraction?

[Ross Clarkson:]

No, there is no real approval process, but we are in discussions with EGPC about incentivizing it.

[Operator:]

Thank you. [Operator Instructions]. The next question is from Stephane Foucaud from GMP. Please go ahead.

[Stephane Foucaud:]

Good morning, guys. A few questions from me. The first, the new -- the well in the -- in Canada in the new license area, what sort of flow rates would you be looking for to fill it to be commercial? And then you talk about the topic on flare. So what sort of CapEx will be required to make this area ready for further drilling -- I expect -- as you said small pipeline CapEx for the period? That was my first question. Second question around dividend. Is there any way we could look at sort of metrics you would be considering to define the dividend or sort of formula and cash flow, free cash flow, earning. And I know that it’s early stage but if you have some thought on that? And also the -- back on acquisitions. Egypt seems to be quite competitive at the moment, many players are looking, it seems that the pricing are quite a bit much more popular. How do you see yourself differentiating in that quite competitive environment? Thank you.

[Ross Clarkson:]

Okay. That's three questions. But I'll work on the first two or first one anyway and I'll let the guys jump into the others. On the Canadian economics, if we got similar rates to the tight curve that we've add on the Harmattan area, I think that project would work quite well, which is typically they would come on around 200 to 250 a day in the initial rates. Now we had to -- because it's a new area and they don't allow flaring of gas and there is some associated gas, we had to tie into our existing system. And I think that was an additional roughly $500,000, $600,000 to build the pipeline back into our system which we add on to the first well. It's not a huge amount but it nevertheless -- it makes that first well economics a little bit tighter. And then -- from then on as we've got 30 more wells, it becomes quite a very attractive project. So it has pushed up the cost on the first well to about I think 3.8 guys? Yes. I will let Randy discuss the dividend.

[Randy Neely:]

Yes, Stephane, I mean the plan really is to look at this on a semiannual basis. I mean our goal is to grow. We do want to be paying out a certain portion of our free cash flow at the end of the day. We don't want to get sort of hands into a certain percent at this point. It’s going to depend on opportunities and we have opportunities to grow through acquisitions or opportunities to grow through expand the capital program. That’s going to be the number one priority. But at the same time, we do see a lot of benefit to our shareholders in paying -- returning capital to them over time and in sort of a systematic way. So we’re going to work towards that. And I think as time goes on, we will get more systematic on how that's done. And we also want to maintain our conservative balance sheet which is served us well over the last few years certainly.

[Ross Clarkson:]

And the third question was on acquisitions. Yes, there is no doubt that there’s a number of people looking at Egypt. We have a pretty strong balance sheet and very supportive shareholder group and almost 20 years of experience in working in this part of the world and very good relationships with the government and knowledge of how to operate there. So we may have a little bit of a leg up on some people but obviously we wouldn't compete with Apache but then maybe we’re not in the same snap bracket as Apache.

[Stephane Foucaud:]

Probably sometimes -- always happen in energy market, often it’s really at the end of the day, only around the overall cash figure or figure being paid and sometimes it’s difficult to differentiate yourself just on that top envelope number.

[Ross Clarkson:]

Yes, sometimes.

[Operator:]

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

[Ross Clarkson:]

Okay, thank you everyone for participating in our Q2 conference call with a lot of great questions. We should have an update on operations some time around mid to third week of September and then of course third quarter in November. And that's about it for today. Thank you very much.

[Operator:]

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