James Park - CEO Augusto Zubillaga - COO Andrés Ocampo - CFO Pablo Ducci - Director of Capital Markets.

Diego Mendes - Itau Darren Engels - FirstEnergy Capital Ben Hoff - PCB Securities.

Good morning and welcome to the GeoPark Limited Conference Call following the results announcement for the first quarter ended March 31, 2016. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session.

[Operator Instructions] If you do not have a copy of the press release, please call Sard Verbinnen & Co. in New York at +1 212-687-8080 and we will have one sent to you. Alternatively, you may obtain a copy of the release at the Investor Support section on the company's corporate website at www.geo-park.com.

A replay of today's call may be accessed by accessing the webcast in the Investor support section of the GeoPark corporate website.

Before we continue, please note that certain statements contained in the results release and on this conference call are forward-looking statements rather than historical facts and are subject to risks and uncertainties that could cause actual results to differ materially from those described.

With respect to such forward-looking statements, the company seeks protections afforded by the Private Securities Litigation Reform Act of 1995. These risks include a variety of factors, including competitive developments and risk factors listed from time-to-time in the company's SEC reports and public releases.

Those lists are intended to identify certain principle factors that could cause actual results to differ materially from those described in the forward-looking statements, but are not intended to represent a complete list of the company’s business. All financial figures included herein were prepared in accordance with the IFRS and are stated in U.S.

dollars unless otherwise noted. Reserves figures correspond to PRMS standards. On the call today from GeoPark is James F. Park, Chief Executive Officer; Augusto Zubillaga, Chief Operating Officer; Andrés Ocampo, Chief Executive [ph] Officer, Pablo Ducci, Director of Capital Markets and Dolores Santamarina, Investor Manager.

And now, I’ll turn the call over to Mr. James Park. Mr. Park you may begin..

Thank you and welcome everyone. We are joining this morning from Buenos Aires, Argentina with our executive team to report on our first quarter 2016 results. Following our positive production and reserve performance in 2015, we entered 2016 in good shape, ready for both growth and volatility with a plan balancing cash preservation and cash generation.

A key tool that GeoPark has developed to manage our deep asset pool with over 120 million barrels and 2P reserves in Columbia, Chile, Brazil, Peru and Argentina is our capital allocation discipline.

This allows us to select from a wide range of projects, generated by each of our business units with different returns, potentials, risks, sizes, timelines and geographies, ensuring our capital goes to the top value adding projects after ranking them on technical, strategic and economic criteria.

Importantly, it provides security in volatile markets, while allowing us to easily add or subtract projects depending on oil prices and project performance and to fine tune our desired risk exposure. Consequently, as prices collapse at the beginning of 2016, we rapidly adjusted and reduced our work program.

Likewise, as prices strengthen into this new current quarter, we can begin to add back some new projects. At the same time, our team continues to muscle down costs after already meaningful reductions quarter-by-quarter in 2015 with big first quarter cuts in operating expenses, G&A, cash costs per barrel and capital investments.

We are the operator of nearly all of our production, so these cost savings are driven by our team. The oil and gas value of our assets was again demonstrated by consolidated production gains of 15%, consisting of 16% oil and 12% gas production increases.

In Chile, we turned our project around by continuing our pivot to the gas business and successfully drilling and putting on production, a new well in the Pampa Larga gas field.

Our workhorse asset, the GeoPark operated Llanos 34 Block in Columbia continued on its production climb with 30% growth and with skimpy operating costs of just $3.40 per barrel to make this block a leading geological and economic success story in Latin America.

Drilling will start up again on this block in the second quarter and we mobilized the rig for a 3 to 6 well program.

Despite oil prices hitting lows into the 20s in the first quarter, our continuing cash preservation efforts proved successful as evidenced by, one, a positive operating cash flows after capital investment and two, having over $200 million in cash and available facilities.

In order to manage continuing oil price volatility, we also initiated a hedging program starting with approximately 20% of our production sold at a fixed price over $45 per barrel Brent for three months. We see this as an important risk management tool for the future management of our cash flows and work programs.

In parallel, with our conservative operating approach, we remain on the offensive to acquire new attractively valued oil and gas upstream projects throughout Latin America.

National and major oil companies, which control some of the biggest and best hydrocarbon acreage, are being pushed by lower oil prices to reevaluate their portfolios and divest assets. Our regional platform track record and reputation give us first-mover advantage in acquiring these low-risk, high-potential opportunities.

We believe GeoPark’s continuing performance during the oil price downturn both operationally and financial has set us apart and demonstrates the resilience of our long-term risk balanced foundation and the collective strength of our plan, assets, people, partners and opportunities.

Our ability to adapt and grow through efficiency improvements, innovation and drive proves our readiness to thrive and succeed in a world of lower oil prices. Thank you. And we now please invite any questions for our team and additional insight..

[Operator Instructions] Your first question comes from the line of Diego Mendes with Itau..

Yes, good morning all. So I have three questions. The first one, if you could tell us a little bit about your hedging strategy going forward, you've started implementing in this quarter.

So how do you think about it going forward? Do you plan to increase the amount of production that you are going to hedge or let’s say, the 20% for three months, it’s the way to go.

The second one is that you guys did amazing job in terms of reducing costs so far, so the question is how much more do you think you can cut? The third one is related to the CapEx. Now that oil prices are little better if you are thinking about changing your CapEx plan to the regional one and not to the more let’s say conservative take. Thank you..

Okay, thank you very much, Diego and good morning. Andrés here. So to your first question about hedging, yes, we have a hedging strategy and the volumes that we estimate to hedge or to fix price or secure a minimum price is going to be or are going to be related to the evolution of the oil prices.

We’ve always said that we generally would like to secure a portion of our production and ensure for a portion of our production at least prices in line with where we hold our base case program. So we had the opportunity to fix a portion of our production to $45 Brent which is $5 of our base case program and we took it.

Generally the way we think around it is in the terms we would hedge probably higher volumes with stronger oil prices and lower volumes in lower case. And so we could hedge higher volumes if the prices continue this strong growth path. Then in terms of your second question was about cost reductions.

I think this was the sixth consecutive quarter of improving cost per barrel. So we've been able to be deliver, quarter by quarter for the last six quarters, continuous improvements in our cost bases on a per barrel basis.

This is an always ongoing effort that we do every day and our teams in each of the countries where operate continue during every day. So we still think there is always room for improvement of our cost bases mainly based on efficiency focus and innovation and in the way we operate our fields.

So, yes, we always think there is room for more improvement, that’s our goal and we expect that to happen also in the next quarter.

And then in terms of our CapEx program, your third question, as we mentioned at the beginning of the year, we moved quickly to our low-case scenario given the prices in the first quarter where - in the area where we dropped at the low case scenario.

And now we are ready to move quickly to increase our CapEx program or accelerate our CapEx program given that prices are stronger and we have also had support in our current production.

Remember that these are not the discrete programs, these are not - we don’t have a one program and then separately a different one, these are more linked to each other.

So to give you an idea, we are moving away to our Colombia operations right now and are really going to be drilling between three to six wells, three wells is what would have been included in our low case, six wells is something more in the base case area. So that is how flexible the program is.

So yes, to your question again, we are ready to move on increasing our CapEx in particular in our Colombia Llanos 34 operations..

Okay. Thank you very much. And the last question, if I may regarding to M&A as you mentioned in the presentation, if you could talk to a little bit about what you see in terms of Colombia, we know that Ecopetrol is trying to do some partnership. And also here in Brazil, with Petrobras willing to sell some of their onshore operations.

If they prefer to their mine in Colombia or in Brazil, again, how do you see those opportunities?.

Sure. Thank you, Diego. Particularly, those two that you mentioned are two opportunities that we - one of the reasons why we focus in Latin America is because we think this is an area of market hydrocarbon opportunity and that has been largely dominated by state companies in most of the countries where we operate.

And Colombia and Brazil are not the exception. We have been working and developing our long-term relationship with Petrobras, we are actually a partner with them in one of their important fields and the same with the Ecopetrol.

So those two opportunities that you mentioned, which are the divestment of assets or looking for partnership from both those companies. We are looking very closely and we are very interested in those..

Okay. Thank you very much guys..

Your next question comes from Darren Engels with FirstEnergy Capital..

Hi, good morning everyone. I had a quick question with respect to the Trafigura agreement, the offtake agreement.

How should we look at the Colombian differential now off of the reference price, is it Vasconia differential of $7 plus $15.50, so it’s about a $22.50 differential, is that the way to look at this going forward now?.

Hi, Darren, this is Andrés. Yes, the very roughly the way to look at it, $7 Vasconia differential flat rates, but yes, that’s a good - I mean, for the last few months, it’s been around that number. And then the Trafigura transportation differential is around $15.25.

The first quarter, you see something more like $13 and is because the Trafigura agreement kicked in in March, so you only have one month of Trafigura. So there are two rollouts that you are in the quarterly report that we just released, you are seeing two rolls that are linked to selling expenses and not on the discount.

So from the second quarter on, you should see everything as a discount to the price at around $15, as you mentioned. That’s the way to look at..

And is that relatively insensitive to changes in the reference price or the reference oil price, like if Brent changes to $50, is that differential going to stay roughly consistent now going forward or is there any levers within Trafigura for your transportation of commercial take to increase?.

Yes, so the reference price or the Brent changes, the discount will not change. The only reason why it could change is the other way around, that means the cost reductions in the whole transportation system, we get the benefit of that.

So we are past-through the cost of the pipelines and trucking to us, so it could go down but it couldn’t go up of our result only of the changes in Brent. And then the Vasconia differential just followed some trend, so it is part of the contract..

Okay, excellent. A similar type of question with operating cost. Obviously a great quarter at a $4 average in Colombia.

With rising oil prices, is there any sensitivities where you could see cost creep back into the system or do you suspect a $4 run rate for the foreseeable future now?.

So I would say two things. So one, as you know, there is a portion of our cost base related to the current [indiscernible] so cost appreciated through Colombian pesos or Chilean pesos, and in particularly, Colombian currency, it is in a way associated to the oil prices.

So if the oil prices strengthen and the Colombian peso as a result of that appreciate, we would have more pressure on our cost or we would have, I mean we would have some impact on our cost basis as a result of that.

And on the other side, if oil prices strengthen, some of the marginal fields that we have today shut in that have higher OpEx per barrel could come on-stream at a cash flow positive, so they may impact our overall OpEx per barrel but in terms of EBITDA we would still be gaining higher EBITDA on the barrels that we produce.

So we are thinking is we have around 1,200 barrels of production that is temporarily shut in because it's not generating positive cash at these prices but if prices continue to recover, we could bring those barrels into production they would generate positive cash flow but on upper barrel basis they may show higher OpEx per barrel..

Okay.

At what oil price do you mean to bring that production back on and what is the Op costs associated with those barrels that are shut in?.

Half of that production can be brought in at these prices. If these prices prove to remain stable, we can bring in half of that production at around these prices and maybe with five more dollars we can bring the other half on-stream..

Your next question comes from the line of Ben Hoff with PCB Securities..

My question is as you said you are migrating more towards the base case CapEx program which I have in my notes is like a $50 million midpoint annual CapEx, so I'm assuming that you're just going to move to that run rate rather than target that for the year as a whole is the way to think about it?.

[Technical Difficulty] thinking about it, thank you for the question Ben. Remember these are not discrete separate programs and we already have one quarter or slightly more than one quarter running or operating under our low case. So we are going to be accelerating or adding back some of the projects that we had included in our base case.

So that should impact our CapEx not all to the $50 million, $55 million that you just mentioned because we already are four months into the year operating at our low case. So we would increase our CapEx not the whole amount for the base case and it would also increase our production for this year..

[Operator Instructions] Your next question comes from the line of Brian Scholl with Pioneering Investments. [ph]..

Just a short question, looking for a little bit more color around the customer advance payments of 10 million, and I assume that the drawdown on the Trafigura agreement. I'm just wondering when the cost associated with that would be true as well..

Good morning Brian, thank you for your question. Those $10 million advance from customers is 100% related to the drawdown on the Trafigura agreement to repay $10 million of installment of our Itau term loan facility and the cost associated to that is LIBOR plus 5% and we are going to be repaying that with deliveries of oil over the next 30 months..

So it's more the operational cost associated with the drawdown, so what is that, is that something we see in the next quarter or that just in over the next 30 months I guess what you're seem to be saying..

The cost associated to that comes embedded in the price that we receive from the buyer. I'm not sure if that answers your question..

You got the $10 million cost associated with for just in the oil to satisfy the customer's drawdown it’s just getting essentially timeframe of which of that comes through the accounts from a P&L perspective?.

Sorry Brian, this Pablo, you're referring to this, I mean on that if it's that, we have since we withdraw that we have a six month grace period and then we pay that $10 million in 24 equally installments over the periods of the total agreement, so the third principal payment will start on October and it will have 24 equally severed..

At this time, there are no further questions, I would now turn the conference back to Mr. James Park.

Thank you all again for joining us today and we encourage you to please contact or visit us if you have any questions, good day..

This concludes today's conference call, you may now disconnect..