David R. Taylor - President and CEO Kenneth G.

Pinsky - CFO and Corporate Secretary Mike Kruchten - VP of Capital Markets and Corporate Planning Ryan W. Fowler - Senior VP, Exploration and Business Development Eric Furlan - Senior VP of Engineering

Darrell Bishop - Haywood Securities Nathan Piper - RBC Capital Markets Ian Macqueen - Eight Capital Partners Jenny Xenos - Canaccord Genuity

Thank you, operator. I’d like to thank you for joining us today for Parex second quarter earnings conference call.

With me today is Ken Pinsky, Chief Financial Officer; Mike Kruchten, VP of Capital Markets and Corporate Planning; Ryan Fowler, Senior VP, Exploration and Business Development; and Eric Furlan, Senior VP of Engineering. The format for today’s conference call will be a question-and-answer session with our audience.

So we’re opening the line up to questions right away. Operator, over to you.

Hi, good morning, guys. Can you hear me?

Yes.

Okay. I wasn’t sure if I was the participant or not.

Darrell Bishop here with Haywood Securities. I just had a question related to the Jacana-9 and 10 wells.

I know one of the objectives when drilling these wells was to potentially test the connectivity of this Tigana and Jacana fields. I know while the Jacana sand wells seems to extend the boundaries of the field a little bit further north.

Have you gained any further insight with respect to whether or not the fields are connected?

Eric?

Yes, Darrell, Eric Furlan here. As we put in our press release, we had about a 5-kilometer gap between the Jacana and Tigana pools without any delineation.

So this was our first attempt from the Jacana site to delineate towards Tigana and we delineated about 1.5 kilometers in that direction. Obviously, the result we’ve released is quite positive.

And it’s suggesting that the trend continues towards the Tigana pool. We have a rig that is moving to drill from the other side, from the Tigana side back towards Jacana.

So we expect before the end of the year, we’ll have that question fully resolved. But certainly with the result of Jacana-10, it’s sort of leading in that direction.

Great. Thanks.

And just digging into the Jacana-9 well a little bit more. I know much higher water cuts and lower oil rates after perforing the lowest of the known zones there.

Does that put in oil or water contact into the field now for the first time, or is there still kind of more testing to be done there?

I would say that it puts a water well contact in that sand that we tested. As we continue to delineate the pool, we’re still trying to resolve which sands are connected to which wells and which contacts apply to those sands.

So certainly to understand this more fully, we need to test the remaining zones in the Jacana-9 well and continue our delineation efforts, which will continue with drilling going further west. And of course, continued performance from the pool and the down-dip wells, which seems to be still exceeding our expectations.

So I wouldn’t say that we’ve found any kind of solid hard line to say we’ve got a new water contact for the pool in general, but would conclude that that lowest zone, the lowest 4 feet that we’ve perforated here, that sand appears to be connected to water.

Okay. That’s helpful color.

Thanks, guys.

Thank you.

Hi. It’s Nathan Piper from RBC.

So a few questions, if I may. First of all, on the legal issue which you settled this quarter, I thought you had been dismissed from the litigation in 2014, so I just – it would be good to clarify exactly what’s happened there.

And I assume given the settlement, it’s finished? And then secondly, on Aguas Blancas, just to understand the drilling results from the commentary you put there.

Clearly, some of the drilling on the hanging walls has not been what you expected. And does this produce the upside potential?

So you’ve talked about a top end of 8,400 acres of potential at Aguas Blancas. Does this reduce you down to a more focused area in the western part of the Block?

Nathan, it’s Ken. I’ll talk to you about the legal settlement to get it out of the way.

If you look at our public disclosure and annual information form as well as our financial statements for year-end, you’d notice that there were three jurisdictions on lawsuits active in Bermuda, Texas and Canada with different companies involved in each jurisdiction. So what we did is we were dismissed from jurisdiction in Texas for a couple of the companies, but Ramshorn, our subsidiary that we purchased, which owned the original interest in Block 34 was still involved somewhat.

So look at this as insurance, Nathan. This is a very valuable Block, very valuable asset base and to release ourselves many sort of future costs, liability and executive oversight on managing the litigation, it just seemed that for $15 million, it was worth it.

So we looked at it kind of like [indiscernible] insurance. So does that help clear it up for you?

Yes, I mean I guess so it’s [indiscernible] going forward, so it’s $15 million and essentially you’re done. That’s the issue resolved?

Right. For $15 million, all jurisdictions have had discontinuances of their actions.

That’s clear. Thanks.

On Aguas, Nathan, I’ll just mention some of the high-level discussion about it and then we can talk in more detail, if we need to. But when we went into this, the East area was always a riskier proposition for us, the way the faults were oriented relative to structure there.

We weren’t as comfortable as total traffic configuration on that hanging wall as we were on the footwall area. So we did drill some appraisal wells there to determine what was going on.

And we found it to be more complex and a little less perspective than we were hoping for. So I’d say, yes, that we probably restricted the higher upside area to mostly the West area.

So we now have what we would call a delineated area of the footwall. And then we have the southern area, which we still have to appraise with some additional drilling.

So we’re going to focus on that Western footwall area. It appears that the trapping there is working because that major fault that runs north, south through the Block is trapping in an up-dip direction.

And so that’s going to be our focus. And I don’t know if Eric or Ryan, you want to comment any further?

I guess I’ll just comment on with regards to our focus right now, as Dave mentioned, delineation of that South getting those southern pads drilled to understand the full oil in place on that western half. And then we do have a waterflood pilot underway.

It is going well. The water is going in, as expected, and it looks pretty good.

So those are the two piece of information we’re looking to really characterize the long-term development. I think we’re confident enough right now to say we’ve got a development here at least on primary until we confirm the waterflood response.

But the delineation and the waterflood focus is really what we’re going to be looking at in the next six months.

Sure. But just to follow a few numbers, Ryan, then.

So at the end of 2016, you had a 2P area of 24,000 acres. And you talked about in the release this morning kind of 25 to 21 – 4,100 potentially because it – I’m just trying to figure out how all these numbers come together.

What do you think the size and the price is following the drilling on the East and over to this further potential to the size? How would you characterize the overall container as it were then or do you need some more time over the next – the remainder of this year to characterize Aguas Blancas better?

Well, I think the outline of the areas we provided I think are reasonable as far as Western half. As Dave said, the trapping looks pretty consistent on the Western half, so it’s really a matter of confirming how far south the accumulation goes.

And then the other big thing, of course, is the waterflood that we’re really focusing on. So on the North and typical waterfloods recover 20% to 25% of the oil in place.

Primary is probably more like 8%. So obviously, we get a big upside from the waterflood.

As far as our last year-end reserves, there was a small component of our Aguas booking on that Eastern side. But even at that time, Geo-Jade did recognize it was higher risk on the untested wells.

So it was a very small component of the Aguas booking. So it will be an immaterial change as far as last year.

And the results on the West have certainly proved that larger area.

Yes, and Nathan I think it’s like any appraisal-type project to review an exploration project when you drill the first couple of wells into it. We’re basically narrowing the range.

When we first got into this, there’s a lot of uncertainty. We hadn’t drilled any wells.

There was only six wells that have tested oil or logs. We’ve got a lot of information now.

We’ve got cores. We’ve got just lots more test data.

So we’ve really narrowed the range down. And I think that the range that we’ve put in there, the 2,100 to 4,100 or whatever the exact numbers were, it’s just narrowing that range for us now.

Sure. I guess [indiscernible] good fortune because your appraisal of LLA-34 kept pushing up the upside that there we are.

Okay. And just final one on the waterflood.

How long will it take you then to get meaningful data from that? You only started in July.

So by the end of the year, would you get enough data do you think to start making some conclusions from your waterflood?

Certainly, our models suggest that by the end of the year, we should have some indication. Obviously, there’s multiple steps here.

The first step is assuming we can get continuous injection into the injection well and that the water’s distributing nicely in the reservoir. That seems to be the case.

And now we’re looking for a response and what the response looks like and in which sands. So six months is probably – end of year, we should have some indication.

Probably closer to a year is more firm to understand recovery factors. So we are monitoring it closely and we have a pretty good plan in place to monitor everything and understand that as quickly as we can.

Perfect. Thanks for the clarity.

Good morning, guys. It should be an easy one for Mike just with respect to the H2 CapEx program.

I think somewhere on the release it said there was somewhere in the range of 20 wells. Can you give us an idea of the breakdown between Q3, Q4 exploration and development and some areas for those wells?

Sure. Ian, in the release we mentioned 10 to 20 wells.

That was specifically related to Aguas Blancas West area that would be in 2018. When we look at our CapEx program for the second half of 2017, we’ll have continued development and appraisal with some exploration on Block 34 and that’s specifically going to the very north end of the Tigana field and to the very south end of the Jacana field.

The second part of the exploration/appraisal will be on Capachos Block where we have two wells that we will be – have drilled in the second half of this year and also commencement of the production facilities and some civil works for a third well. That will set us up nicely for 2018.

The other big portion of our drilling program for the second half of the year will be in the Magdalena Basin, specifically on Block VMM-11 where we’ll have four wells drilled in the second portion of the year. I think that pretty well sums it up for this half of the year.

Yes, Aguas drilling will depend on some – to some degree on getting some permits to build those southern pads we were just talking about. So that may or may not start up later this year.

We’ve got some completions that have to be done as well in reentry so that Coyote well in the Magdalena Basin and the De Mares Block, there’s a reentry plan there. We’re going to go up whole and complete the Mirador and Gacheta one.

We’ve got the Kitaro-2 [ph] well to test still. So lots, lots of activity that’s still ongoing here in the second half of the year.

Okay, perfect. And just because it’s mentioned, it’s been in the books for a long time.

But the Glauca prospect is really a corner shot of an existing field. You haven’t talked about it lately.

Can you give us kind of a ballpark idea on what the target size would be or is, I guess?

Yes. Ryan, over to you.

I’ll talk to that, Ian. So for Glauca, it is a corner shot on the existing field there at Palagua.

It’s actually the name of the existing field. And this is sort of a 5 million barrel target for us.

It’s not a really big target for Parex, but a very interesting one. We’ve got the well down that we think we need to appraise it.

But we’re waiting on a completion rate to go in there and actually do the testing.

Perfect. Thanks so much, guys.

Good morning, gentlemen. A lot of my questions have been answered.

But let me ask you about the drilling at Cabrestero. Could you give us a little bit of color please on Bacano-4 and 5?

What have you seen in these wells? And what is the pressure testing telling you?

Is it a continuation of an existing field like Jacana or Akira, or is it going to be a separate accumulation? What is your interpretation of drilling results to-date?

Eric will take it.

So Eric Furlan here. So it certainly looks – the results at Bacano look very similar to the results we’ve seen north across the border into Jacana, the same – obviously the same reservoir section.

We haven’t confirmed the connectivity between Bacano and Jacana. There will be wells drilled and namely Jacana-12 that will be on – in a position to confirm that connectivity.

But it certainly looks like that it is part of the same type of accumulation.

So potentially a continuation of it?

Essentially, yes.

Okay, great. And Ken, could you please give us a little bit of color on what you’re seeing in terms of differentials so far in Q3?

Well, I guess our latest cargoes that we export have been at around $2.88 to $3 a barrel differential. We normally have another $0.20 to $0.25 on top of that for quality adjustment versus our average for the second quarter, our overall average for the second quarter differential from Vasconia to Brent, or from our realized price to Brent was about $4 and change.

So we’re seeing it tighten up or narrow even further in Q3. Going into Q4 is kind of a question mark.

We know worldwide heavier crudes; they’re narrowing on their differentials. And we’ll see what happens in Q4 when gasoline season ends with the Gulf Coast refinery runs.

But for the rest of the year, it looks like it will be less than the historical average for sure. And then going into '18, we’ll get some more color in Q4 to make our own budgets and forecast.

But it’s – to answer your original question, the trend we saw in Q2 is continuing to Q3.

Great. Thank you so much.

Thank you, operator. I’d like to take this opportunity to thank you for your interest in Parex and your continued support of the company.

For further information, we invite you to visit our Web site or call us. And thanks again.

Have a good day. Operator?