Wayne Foo – President and Chief Executive Officer Ken Pinsky – Chief Financial Officer Barry Larson – Chief Operating Officer Dave Taylor – EVP, Exploration and Business Development Mike Kruchten – VP, Corporate Planning and IR

Jamie Somerville – TD Securities David Beddis – GMP Securities David Dudlyke – Dundee Capital Markets Victor Vallance – Edgecrest Capital

Thank you, operator, and thank you all for joining us this morning. With me today is Ken Pinsky, our Chief Financial Officer; Barry Larson, our Chief Operating Officer; Dave Taylor, our Executive Vice President of Exploration and Business Development; and Mike Kruchten, our VP of Corporate Planning and Investor Relations.

Before we begin, I’d like to mention that this call is being recorded as it will be available for playback on the company’s website at www.parexresources.com. I’d also like to remind you all that all of the company’s continuous disclosure documents may be found on SEDAR or on the company’s website.

These documents provide more complete information than what may be discussed during the call this morning. Any remarks made by management during this call may contain forward-looking statements that are based on the expectations, current beliefs, and assumptions of management regarding the company’s future growth, results of operations, production, future capital, other expenditures, plans for and results of drilling activity, environmental matters, business prospects, opportunities, and transactions.

Forward-looking statements involve significant known and unknown risks and uncertainties, which are fully disclosed in the company’s disclosure documents as previously mentioned. The information discussed today is made as of today’s date and time, and the company assumes no obligation to update or revise this information to reflect new events or circumstances except as required by law.

Yesterday, we released our audited financial and operating results for the quarter and year-ended December 31, 2014. Copies of the company’s consolidated financial statements and the related management’s discussion and analysis or MD&A are available under the company’s profile at www.sedar.com and on the company’s website at www.parexresources.com.

The format for today’s conference call will be a question-and-answer session with our audience. Operator, over to you.

Jamie Somerville here from TD.

Good morning, Jamie.

Oh, thank you. It is me.

Okay, so my questions with regards to the last paragraph in your restated 2015 guidance where you talk about cost reductions coming from - negotiated reductions in your service costs and also the further depreciation of the Colombian peso. So, I’m just wondering - that’s very nice to hear, but in your new presentation, your cash flow netback guidance for the year hasn’t changed from when you issued revised guidance in early January.

So should I take it that it’s not - the Colombian peso change is not material enough to move you outside of those ranges or have you just chosen not to update those ranges with regards to the cash flow netbacks?

Good morning, Jamie, it’s Mike Kruchten. With respect to the cash netback that we provided in our guidance, that incorporated the significant change in the Colombian peso from 2014, which was roughly COP1,950 to over COP2,500 or COP2,400 at the time and anticipation of having service cost reductions.

So what we’ve stated in our revised guidance yesterday incorporates, I guess, the realization or – what we’re starting to see as realization of those improved margins.

Yes, Ken, here Jamie, also though we did budgeted COP2,400, now it was around COP2,600. So as oils continues to be at the lower end of the range [indiscernible] $50 and $60, we do see continued peso depreciation.

So those numbers wouldn’t reflect COP2,600, but they reflect a COP2,400 to 1, peso exchange ratio with the U.S. dollar.

Okay, thank you. And then with regards to the service cost structure element of that statement, should we assume that most of the benefit of that appears in lower CapEx or - CapEx per well or better capital efficiency or is it - some of that also flowing through to operating cost?

Well, there is two pieces to that. One, we did ask our vendors - our operating or production vendors to help support us during these lower oil prices in line with a number of the players in Colombia and we’ve had good response on that.

So you’ll see a 10% to 15% reduction in actual cost plus, as we alluded to in the past, our operating costs are about 50% peso-denominated, so then we get the depreciation effect. In respect to our capital cost, on drilling, specifically, we are in the process where we have just finalized our drilling contracts.

They will show a lower cost per day or lower day cost than 2014, but not all services yet have we finished the negotiations. So we expect to see a 10% to 15% reduction of our actual drilling cost, but not all those contracts have been finalized.

Right now, we just have them on the day rates for the drilling rigs and that’s about a third of our drilling cost. And again, looking at the peso depreciation effect, about 40% of drilling costs are peso-denominated, the rest are USD.

And when we get into facilities, 50% of those costs are more peso-denominated because of those larger labor component.

Okay. Cool.

Thank you very much.

Good morning, guys. Just wanted to see if we could get a bit of an update on timing of the 2015 exploration program.

I know you’ve talked about getting rig back [indiscernible] shortly. Just wondered if there was any update on that.

Yeah, it’s Dave Taylor. We’re starting moving the rig on to the Rumba location, which is on Block 26, in the next day or so, we expect this by the third week of March and that will kick of our initial program.

We have one rig right now scheduled to go ahead and drill, two wells on Block 26, a well on Cebucan, a well on Block 10, and then a well on Capachos sequentially through to the end of the year. We also have another couple of wells that require shallower rig on a couple of Eastern Llanos programs or wells.

So we will be looking at picking up a rig to drill, two or three wells over in that region here shortly. Part of the program, we are working with the ANH to try and actually move a couple of commitments to another block if we can, just to drill more prospective opportunities and a couple of obligation wells that we think are a little less material.

So that’s in the shallower program, but the deep program is kicking off this week.

Okay, great. And then just on the non-operated stuff, the follow-ups to the Tilo discovery, how long will you long-term test that before they start to drill follow-ups?

It will depend on the performance, but probably a few months and determine how the well performs and then discussion with the operator about adding capital really to look at appraisal locations because at this point in time they are not in the capital budget.

Okay. Okay, that’s great.

Thanks, guys.

Hi, good morning, everyone. Apologies, just came on the line somewhat late, so if this has been covered, just tell me and I will listen to recording.

But obviously there’s been lots of talk about USO and strikes and this and that and the other, and I just wondered what contingency plans you may have made or perhaps top down what your view would be with regard to probability of such strikes in there where the bottlenecks might be in the transportation system, should they go head with such a strike?

Yeah, we can take a stab at that David. The USO operate in a number of the facilities that are controlled by arms of Ecopetrol.

So they do have an influence at certain loading stations. We’ve identified which loading stations are staffed by USO.

We’ve looked at the ways that we can move crude through that situation. And I’m reluctant to discuss specifics of how we plan to handle anything like that because there are contingencies that we would use.

Yeah.

Yeah, David, this is Ken Pinsky. We also like our number of blocks that we have so that we can maintain a capital program that - we have a diversified portfolio.

So if we have an issue on one block, we could move directly to another block, and continue with the capital program or maintain production as we demonstrated last year. So in respect of any striking action, I would see it hard to think that everything strikes in the country for any long period of time because this [indiscernible].

So if there is sort of delivery station by delivery station issues, again, we deliver to multiple stations and we would just swing our transportation and our crude deliveries appropriately. There may be some short-term hiccups, but I think in the long-term, we don’t see a real risk, because we think the country would be well motivated to maintain a steady flow of crude.

I certainly agree. But that’s interesting, I mean, obviously, while you prefer not to release your plan, it’s interesting that - because as I understand the loading stations are in the hands of Ecopetrol, they weren’t devolved to senate as I recall, but what you are saying is there is a variant in terms of USO representation amongst those loading stations, which is an interesting fact.

To the best of our knowledge. And then there is also - as Ken said, we move oil around the basin as we have to, one of the benefits of a lower Colombian peso exchange rate, more favorable exchange rate is that trucking costs don’t hurt us to the same extend as they did.

So if we have to make those moves, we’ll just make the moves.

Okay, and moving to something else. Obviously, you referred to it in your press release, the timings of loadings affecting your - really, ending up with an effective realization way off your historic levels, and is that a direct result of you directly marketing your oil to end customers, perhaps it’s just my lack of recollection but I don’t recall it worked for others players necessarily, depending on essentially where the end sale is, it takes place?

Well, Ecopetrol suffered the same issue. We know that they had a higher differential and lower realization to the timing of crude sales and that was what happened with us.

So typically we would have had a Vasconia type differential to Brent, because we blend to Vasconia, which is a Colombian, sort of a mid-tier crude. And for the quarter, that was around $6 a barrel and our differential was $17.

So that $11 a barrel was the result of our cash flow miss, so to speak. And that $11 a barrel was really just timing of crude prices being that - we had crude sales where exportation lifting that were completed at the end of the month and in a rapidly declining oil price environment the end of the month didn’t represent the average.

Further, we chose to move 260,000 barrels a day of crude inventory out before year-end. Because we are a price taker we were happy to keep our inventory levels minimal and so sell the crude when we can, but that was the last week of December and that was the worst price for the quarter.

So when you have 10% of you crude go out at the worst price, you’re not going to meet the average. I would dare say that if the decline of crude had been less, and you know I’d be rounding our noise in the number, but with that rapid decline, that $50 to $60 a barrel at the quarter, that Brent decline in the quarter, that’s the problem with our realization.

So that caused the problem with our realizations. Going forward, we’re seeing crude realizations of our normal sort of Brent less Vasconia and Vasconia has been $5 to $7 a barrel depending, but we’re getting Brent less Vasconia now.

Okay. Thanks.

David, in the past, you’d ask us questions about inventory and it’s really the same phenomenon. We used to have the odd quarter where we carry over inventory because of the timing of lifting under the Ecopetrol contracts in particular for crude purchase.

We have recorded those at the time of the lifting. And at a time when there is no price volatility it’s just reflected in the inventory numbers, what’s the impact of that rapid fall in crude price.

You can look at it in a same way as those inventory swings. It’s just timing of delivering into [coastal] [ph] system and whether there is an intermediate party or us, it’s usually the same sort of pricing impact.

Okay, thank you very much.

Yes, good morning, gentlemen. Couple of questions, just in the MD&A I noticed that, it was mentioned that the company is shutting about 1,000 barrels a day of production, I was just wondering what fields were production was shut in and if there is any possibility, given prices, whether there is going to be additional shut in?

Hi, Vic, it’s Ken. We shut in some fields like [Cumbre] [ph] on our Block 17 Celtis and [indiscernible] on Block 32 and those are higher cost fields with - and they are higher costs because of higher water cut.

In higher oil prices we could bring those back on and right now we don’t have anything else that we see shutting in because of cost. But as we haven’t incurred in the past we are still managing our production to a target and our target right now is 26,500 barrels a day.

So we’re not producing flat out. But we haven’t shut anything else due to economics.

Okay, and then I was just interested with Trinidad, you are in the process of selling Trinidad and you’ve taken an impairment charge and just from my math, it looks like you’ve written it down to about $2 million, is that what can be expected in terms of the sales value?

We closed that sale in February and it was about - yeah, $1.6 million is what we got for it, including our working capital adjustments. So we’re all done with Trinidad.

Okay, thanks.

Operator, there was a question on the website which - the wording is a little difficult, but I think it’s pertaining to our corporate presentation in slide seven which describes the change in our decline rates over the last four years and asks for a little bit of elaboration. And in the presentations to the market over the last month or so we’d use this slide which did shows the first year declines on every well that we’ve drilled and brought on to production since we began the drilling with this company in 2010.

And it shows that the early declines when we were drilling bottom water driven fields even the ones like Kona that were in the range of 10 million barrels with bottom water in the well bore. We’re looking at declines in the range of 70% per annum.

And the inset slide shows the individual declines in the first year, some of which are negative when we look at 2013 and into 2014, where we’ve been bringing all new wells with Tua & Tigana. And over the last three years, the reason for the declines has been the discovery of large accumulations where we can drill producers on the top of structure that are, in some cases, up to a kilometer away from the water lines.

We’re able to produce those wells and they aren’t contacted by water in the early stage of production. And it’s because these are conventional exploration objectives.

They are large conventional exploration objectives, pools like Tua & Tigana are larger than I’m used to finding in the Western Canada base over the last 10 year, certainly even 20 years. And this is just the impact of our business and how we’ve conducted it.

It allows us to pull back our capital in 2015 and still maintain production. So it’s just a sign of the strategy that we’ve employed, if you go back through the strategic slides that we’ve included such as slide 14 in the presentation, the way we choose to position the company.

That’s it for the day. I think that’s it.

Great, thank you operator.

Thanks operator. I’d like to take this opportunity to thank everyone for your interest in Parex Resources and your continued support of the company.

For further information we invite you to visit our website or call us for further information. Thank you again and have a good day.