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Gran Tierra Energy, Inc. (NYSEMKT:GTE)

Q2 2012 Earnings Call

August 07, 2012 01:00 pm ET

Executives

Dana Coffield - President & CEO

Shane O'Leary - COO

James Rozon - CFO

Analysts

Nathan Piper - RBC

Jamie Somerville - TD Securities

John Malone - Global Hunter Securities

Matt Portillo - Tudor Pickering

Rafi Khouri - Raymond James

George Toriola - UBS

Ian Macqueen - CIBC

Caio Carvalhal - JPMorgan

Justin Anderson - Salman Partners

Neal Jacobs - Cambrian Funds

Frederick Kozak - Canaccord Adams

Operator

Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy's results conference call for the three months ended June 30, 2012. My name is Christine and I'll be your coordinator for today. At this time all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session for securities, analysts and institutions.

Instructions will be provided at that time for you to queue up for questions. (Operator Instructions) I would like to remind everyone that this conference call is being webcast and recorded today, Tuesday, August 7, 2012 at 01:00 PM Eastern Standard Time.

Please be advised that in addition to historical information, certain comments made during this conference call, particularly those anticipating future financial performance, business prospects and overall operating strategies, constitute forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.

Such statements may be identified by words such as anticipate, believe, estimate, expect, intend, predict and hope or similar expressions. Such statements, which include estimated or forward-looking production and financial information or results are based on management’s current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described in the forward-looking statements.

Listeners are urged to carefully review and consider the various disclosures made by Gran Tierra Energy in its reports filed with the Securities and Exchange Commission, including those risks set forth in Gran Tierra Energy’s quarterly report on Form 10-Q filed with the SEC on August 7, 2012 and in its annual report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission February 27, 2012.

If one or more of these risks or uncertainties materialize or if the underlying assumptions prove incorrect, Gran Tierra Energy’s actual results may vary materially from those expected or projected. Listeners are urged not to place undue reliance on forward-looking statements made in today’s conference call. Gran Tierra Energy assumes no obligation to update these forward-looking statements other than as may be required by applicable law or regulation.

Today's conference call also includes the non-GAAP measures funds flow from operations. The press release disseminated by Gran Tierra Energy last night includes a reconciliation of this non-GAAP item with company's GAAP net income or loss as well as information about why the management believes this measure is useful in evaluating the company's performance and is available on Grand Tierra Energy's website www.grantierra.com.

All dollar amounts mentioned in today’s conference call are in US dollars unless otherwise stated. Finally this earnings call is the property of Gran Tierra Energy Incorporated, any copying or rebroadcasting of this call is expressly forbidden without the written consent of Grand Tierra Energy. I will now turn the conference over to Mr. Dana Coffield, President and Chief Executive officer of Grand Tierra Energy. Please go ahead.

Dana Coffield

Thank you good morning and thank you for joining us for Gran Tierra Energy's second quarter 2012 results conference calls. With me today is Shane O'Leary, our Chief Operating Officer, and James Rozon our Chief Financial Officer.

This morning we disseminated a press release that included detailed financial information about the quarter. In addition Gran Tierra Energy's report on Form 10-Q for the six months ending June 30, 2012 has been filed on EDGAR and SEDAR and will be available on our website at www.grantierra.com.

I am going to begin today about talking about some of the key developments for the quarter. James will then take a few minutes to discuss key aspects of this quarter's financial results. Shane will provide an operational overview and I will return to provide an outlook and closing remarks.

The key highlight for the quarter was a positive mid-year reserve evaluation of the Costayaco field, Gran Tierra Energy's largest asset in Colombia. After producing 1.7 million barrels of oil since yearend 2011, we’re able to still add an additional 4.9 million barrels of crude reserves and 5.8 million barrels of 2P reserves, representing 33% and 35% growth respectively according to SEC figures.

This is remarkable for a field that has been on plateau production for three years and is a testament to our team’s ability to manage this field effectively and extend the expected plateau production and associated cash flow. In addition, we confirmed an exploration success with the Ramiriqui oil discovery in the Llanos basin in Colombia where we're currently evaluating options for implementation of an early production program for the well and the drilling of an appraisal well in the discovery.

Finally, in Brazil we drilled two development wells and expect to soon be drilling production from the [Tia] field. These successes in exploration and reserve additions during the quarter were offset in part by continued challenges to production due to pipeline disruptions on Ecopetrol operated OTA pipeline in Colombia.

Grand Tierra Energy's production in the second quarter averaged 14,127 barrels of oil equivalent per day net after royalty and inventory adjustment, comprised of 10,308 barrels of oil equivalent per day in Colombia, 3,693 barrels of oil equivalent per day in Argentina and 126 barrels of oil equivalent per day in Brazil.

This is a 22% decrease compared with the second quarter of 2011, primarily due to the pipeline disruptions I mentioned in Colombia. Improving the security of pipeline infrastructure is a priority for Ecopetrol and the government of Colombia. Both are focused on implementing programs to improve with that security of transportation. In addition, Gran Tierra Energy is working with authorities outside parties, and Ecopetrol to look at multiple transportation and storage options to help mitigate the impact of pipeline disruptions.

These include more continuous use of the Oleoducto San Miguel pipeline which connects Ecopetrol's retail gathering facilities to Ecuador.

Additional storage at retail in combination with higher capacity utilization of the OTA pipeline when it is operational and higher volumes of trucking to other delivery points.

In the meantime, Gran Tierra Energy production has returned to record levels of approximately 21,000 BOEs per day before inventory adjustments.

In connection with curtailed production and lower commodity prices experienced this past quarter, Gran Tierra Energy is targeting deferring approximately $60 million in capital expenditures, from a previously announced 2012 budget of $440 million.

Deferred expenditures are expected to be from areas that do not impact production capacity or near-term high value reserve addition projects. As before, our balance sheet remains strong and debt free. We continue to expect to fund our 2012 capital program from cash flow, with cash on hand at current oil prices and production levels.

Overall, Gran Tierra Energy had a strong first half of 2012 with reserve additions, exploration success, record levels of production capacity built and tested, and preparations well underway for the significant exploration and development drilling programs pending in Colombia, Brazil, Peru and Argentina for the second half of 2012.

Let me turn the call over to James Rozon to discuss the financial results. James?

James Rozon

Thank you Dana and good morning everyone. Revenue and other income from the second quarter of 2012 was $115.2 million, a 29% decrease from the same quarter in 2011 due to decreased production and lower realized oil prices. The average price received per barrel of oil decreased by 8% to $92.48 per barrel from $100.68 per barrel from the same period in 2011. During the second quarter of 2012, the recognition of additional royalties resulting from an arbitrator’s decision and a dispute with the third party relating to the calculation of the third party’s net profit interest on 50% on production from the Chaza Block in Columbia resulted in a $10.9 million revenue reduction.

This amount related to June or July 2009 to May 2012 production. The recognition of this royalty resulted in $8.48 per BOE reduction and the average realized price in the second quarter of 2012. The arbitrator’s decision will increase future net profits interest payable to the third party. The royalty settlement represented less than 1% of the reported revenue for the periods under dispute and it is not expected to have a materially different effect on future revenues.

Operating expenses for the second quarter of 2012 were $27.3 million, an 18% increase from the same period in 2011. The increase in operating expenses was due to an increase of $2.1 million in Columbia primarily due to the equatorial OTA pipeline oil transportation costs included as operating costs due to the change in the sales point in February 2012 and increased chucking due to pipeline disruptions of $1.5 million in Argentina due to the increased production and then $5 million in Brazil due to new productions.

The increase in operating costs on a per BOE basis was due to these factors as well as reduced production in Columbia. The depreciation, accretion and impairment expenses for the second quarter of 2012 were $32.6 million compared with $47 million for the comparable quarter in 2011, primarily due to reduced production.

On a per BOE basis DD&A expenses in the second quarter of 2012 were $25.34 comparable with $28.45 in the comparable period in 2011 representing an 11% decrease. The decrease resulted from increased reserves, lower production volumes and lower impairment charges which more than offset increased future development costs in the depletable base.

General and administrative expenses in the second quarter were $17.6 million, 7% higher than a $16.4 million for the same period in 2011 reflecting the expanded operations in all business segments. General and administrative expenses per BOE were 38% higher than in the second quarter of 2012 at $13.69 per BOE due to the same factors and reduced production.

Included in the second quarter of 2012 results is a foreign exchange loss of $4.8 million which included a realized foreign exchange loss of $10 million which was due to the strengthening of the Columbian Peso against the US dollar and included the translation of current and deferred tax liabilities denominated in Columbian Pesos. Gran Tierra had net income for the second quarter of 2012 of $13.1 million compared to $31.6 million in the same period in 2011.

In the second quarter of 2012, oil and natural gas sales due to reduced production resulting from pipeline restrictions and lower average oil prices were partially offset by lower depletion, depreciation and accretion expense, income tax expense and foreign exchange losses. Funds flow from operation decreased by 58% to $37.6 million in the second quarter of 2012 from $88.6 million in the comparable quarter of 2011. The decrease was primarily due to lower oil and natural gas sales due to reduced production, lower realized oil prices, increased operating expensing and increased realized foreign exchange losses partially offset by lower income tax expense.

Reconciliation to net income is included in our second quarter 2012 earnings press release. Cash and cash equivalents were $128.5 million at June 30, 2012 compared with $351.7 million at December 31, 2011, the change in cash and cash equivalents during the first half of 2012 was primarily the result of funds flow from operations of $116.6 million and proceeds and from issuance of common shares of $3.7 million being more than offset by an increase in assets and liabilities from operating activities of $141.9 million, capital expenditures $178.6 million and a $23 million increase in restricted cash.

In summary, Grand Tierra remains financially strong with the expectation that our 2012 exploration and development program a $396 million is to be funded from cash flow from operations and cash on hand at given current production and oil prices. That concludes my comments. I would like to turn the call to Shane for an update on Grand Tierra’s 2012 capital plan and outlook.

Shane O'Leary

Thank you, James. The second quarter got off to a strong start when we confirmed an oil discovery with Ramiriqui-1 exploration well in Colombia with 2,525 gross barrels of oil per day test. We are currently evaluating options for implementation of an early production program for the well and the drilling of an appraisal well in the discovery.

Also during the second quarter of 2012, we started drilling the La Vega Este-1 exploration well where operations are continuing. Drilling difficulties have occurred resulting in a sidetrack from the original well bore but results are expected in August. The Bordon-1 exploration well was drilled in the CEPSA operated Garibay Block and plugged in abandoned because Costayaco development well was successfully drilled as part of a program of water injection and producing wells designed to maximize recoverable reserves across the Costayaco and extend the plateau. The program is showing great success as evidence by the increase in reserves in all categories following the review by GLJ our independent reserve auditors.

Our plan work program for the remainder of 2012 of Columbia includes drilling two development wells at the Moqueta field. The Moqueta field 7 well is targeting the oil water contact on the south western flank while Moqueta is intended to delineate the eastern portion of the field. The recently acquired and interpreted 3D seismic program at Moqueta indicates that the T sand and the Caballos reservoirs continue eastwards in the oil laid depths of the field. The Moqueta 8 proves this concept correct, material reserves additions are possible. Also the Moqueta 3D survey covered the northern areas of the Costayaco field indicating a possible Costayaco field extension to the north of C7. This concept is planned to be tested by the Costayaco Norte well in the fourth quarter. Finally, an oil exploration well is planned to be drill on the Turpial Block and a natural gas development well was planned in Seirra and Nevada Block.

Moving to Argentina during the second quarter, we drilled two exploration wells also completed one development well. The RNx-1008 oil exploration well on the Rinconada Norte Block was drilled and completed as a producing well. The La Vega Este-1 exploration well on the Puesto Guevara Block was drilled but was plugged and abandon. On the Surubi Block, the Proa-2 oil development well reached total depth of 12,894 feet in April 2012 and is currently producing approximately 1,500 barrels of oil per day gross.

Our plan work program for the remainder of 2012 in Argentina includes drilling eight development wells on the Puesto Morales block following a detailed G&G in reservoir study of the field. The new wells are part of the program to implement a redesign of the water flood and inject the polymer to enhance performance.

We also plan to drill a horizontal well on the Loma Montosa formation to test this concept for increasing recoveries from that horizon. We plan to also drill that one gross exploration well and two gross development well in the Rinconada Norte Block and conduct workovers and conversions on existing wells.

Turning to Peru, during the second quarter of 2012, we entered into an agreement to acquire the remaining 40% working interest in Block 95. This acquisition brings us from a 60% working interest to 100% working interest, effective June 1, 2012 and we remain the operator.

Our plan work program for the remainder of 2012 in Peru includes pre-drilling activities with the construction of a drilling platform and the commencement of drilling and exploration well on Block 95.

During the second quarter, we announced material contingent resources estimates for block 95 consisting of 1C, of approximately 11 million barrels of oil, 2C of approximately 32 million barrels of oil and 3C at approximately 88 million of oils.

This prospect was originally drilled in 1974 and tested approximately 800 barrels of oil per day.

In addition to aero-magnetic and aero-gravity survey and environmental impact assessments on Blocks 133 are planned, environmental permitting work is ongoing in Block 107 and welcoming activities are continuing in the ConocoPhillips operated Blocks 123 and 129.

Finally, in Brazil we completed two development wells; 3-GTE-03 and 3-GTE-04 on Block 155. Production from these wells will commence once we have finalized crude sales agreements and gas flaring volume limits with the ANP, the regulatory body in Brazil. Our planned work program for the remainder of 2012 in Brazil includes initiating our horizontal pilot project in the Recôncavo Basin and facilities work on Block 155.

That concludes my comments. I would now like to turn the call back to Dana.

Dana Coffield

Thank you, Shane. So in the first six months of 2012 Gran Tierra Energy has delivered excellent success, completed new development wells, added reserves and grown production capacity. We intend to continue the success as we advance our 2012 capital program and I look forward to communicating our progress as we proceed working through our diverse and robust portfolio through the balance of the year. In the medium to longer term, we are in the process of maturing significant drill well prospects for 2013 and beyond in our four countries of operations to continue the exciting growth the company has experienced year-over-year for the past seven years.

Now that concludes our prepared remarks for this morning. And we would now be pleased to answer any questions you might have. Christine?

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. (Operator Instructions) And our first question is from Nathan Piper of RBC. Please go ahead.

Nathan Piper - RBC

A couple of quick questions and parts of bigger one. First of all, on the inventory adjustments, I understand you have changed the delivery point in Colombia; how long should we be – and low for inventory adjustments in our production forecast for the remainder of this year, is the first question?

Secondly you talked about the declaration of commerciality on the Tiê Field in Brazil; I see that’s two appraisal wells you talked about it Shane, but possibly a more color on that if possible? And then lastly, great reserves increase on the Costayaco Field, but how much more is there to come; I mean you do mention that you could grow reserves further; could you give us some guidance on an oil and place figure or the recovery factor that you are thinking about on Costayaco please?

Dana Coffield

I will start answering the questions in reverse order Nathan. We continue to have superior -- I will address the Costayaco question; we continue to experience superior reservoir performance in our wells; lower declines are expected, better reserves per well is expected and the primary change recently which drove the reserve update was the change in water saturation; water saturation is lower than had previously been modeled by our engineers.

Now there is additional potential to the North of the field both from the existing reserves as well as potential growth with more upside than defined in the 3D seismic program. We can’t really provide additional guidance on this additional potential given that it hasn’t been drilled yet, but we’re comfortable that there is additional growth to be had in the field as we have seen in the early years since we discovered the field as we have seen year-over-year since we discovered the field. I am sorry I don’t have a real number for you, but it’s like a good trend year-over-year. It is continuing to grow and meet our expectations.

I guess another question on the inventory; James?

Nathan Piper - RBC

And just highlight, I know you need that kind of back (inaudible) and just wanted understand how we should model that please?

James Rozon

So in terms of our inventory currently and on a go forward basis it will depend on continued, I guess continuing deliveries through the OTA, basically at June 3oth our inventory which we hold in our tanks and facilities were the inventory represented full inventory and that we would expect that if we have regular productions to be more or less around the 50,000 to 60,000 barrel range versus the 140,000 barrels which would been at June 30th depending on where we tuck in all and where we sell our oil though other inventory fluctuations will continue to occur. So again we can say though, comfortably though that our inventory based on continued uninterrupted deliveries to the OTA would be generally around 60,000 barrels and that would be about 80,000 less than its currently is.

Nathan Piper - RBC

Okay James, and does that mean then we have got to see kind of the working and the production number was high and the actual production number was lower this quarter, so that means it reverses in the half in the next quarter to makeup for the difference?

James Rozon

Again that will be dependent on where we sell our royalty and overlay within the next three to six month period, but with continuing deliveries and uninterrupted, we would expect that number to come down.

Dana Coffield

On the declaration of commerciality in Brazil, that formality pretty much we sort of exhausted the period where we can do a long-term flow test and we now are negotiating flaring volume with the ANP in Brazil, gas flaring yeah and there is limitations on how much gas we can flare. Ultimately, we will tie in to the Petrobras gas pipeline to allow us to produce maximum volumes of crude; until then, we have to live within a certain flaring limitation.

Nathan Piper - RBC

Understood, and maybe one final question if I may have on Brazil, when do you expect to get results from the horizontal drilling, is that in the Q3, Q4 or into next year?

Shane O'Leary

Probably this year; although I am not sure how much information we’ll release on them.

Operator

Thank you. Our next question is from Jamie Somerville of TD Securities. Please go ahead.

Jamie Somerville - TD Securities

I was just looking to ask on the G&A; I see the number ticking up quarter-over-quarter and you do have an explanation for it here, but I am just wondering should we assume that it’s going to remain constant at these levels or should we assume that its going to continue to increase; I am talking on an absolute basis so I guess where it’s $17.5 million per quarter now?

James Rozon

So in the current quarter, G&A expenses were slightly higher, mostly due to bank tax that we pay on money that we move into Colombia to pay the Colombian income tax related to 2011 and installments for 2012. So that would be slightly higher, but basically what we are trending for the year-end total would be what we expect further in the remainder of the year.

Jamie Somerville - TD Securities

And my second question is actually on Argentina; you have some interesting wording around the events that have been happening in Argentina recently and I see the one place where you are continuing to reduce your capital expenditures. I am just wondering whether those changes in capital expenditure this year are actually related to the politics or whether this is just, it was just the one place where you could reduce the capital, do you still remain and roughly as committed to Argentina as you were previously?

Dana Coffield

Yeah, the short answer is we remain as committed as we were. The changes to capital I think you are referring to are just changes we made in all our countries to defer some spending into next year and in fact impacting our reserve growth and production. So we continue to reinvest our cash flow in Argentina, continue to endeavor to grow reserves, grow production, so there's no change in our growth plans in Argentina irrespective of the politics.

Operator

Thank you. Our next question is from John Malone of Global Hunter Securities. Please go ahead.

John Malone - Global Hunter Securities

Just sort of broadly, is there any specific you can refer us to (inaudible) to cut down these pipeline outages and tax?

James Rozon

I don't have a specific article or reference to it that I can it direct you to. There may be some websites you could get more information on. I don’t have one off the top of my head. I do know the government is putting more troops in the field that’s been widely reported in the press. They are putting more monitoring equipment on the pipelines and power lines for infrastructure.

So the general press – there is a fair amount of information on it. The government is taking this very seriously and it’s just part of the overall efforts to improve security in the country. I will have to get back to you separately with a specific reference perhaps.

John Malone - Global Hunter Securities

And then just looking on Moqueta, can you sort of walk us through your thinking on the geometry of fields. You said the eastern flag extends out a couple of kilometers after low (inaudible) level of oil. So can you talk about what that might do in terms of expanding the field's potential and there is any possible – I know you haven’t (inaudible) is there any public structure that might be spillover structures and it may extend the field even further.

Shane O'Leary

Yeah, we actually originally had a separate spillover structure exploration prospect to the east on our old 2-D data. With the new 3-D seismic data it turns out this separate prospect appears to be part of the same dome, the same structure as the Moqueta field. So this eastern extension that we will drill with our Moqueta-8 well that’s referred to in our press release.

In addition we still don’t know where the overall contact is in this dome. So Moqueta-7 which ships here shortly this month will drill down the western flank to deeper levels to identify, try to identify that whole water content. So we have both more potential down dip deeper as well to the east based in this seismic data.

John Malone - Global Hunter Securities

Okay and just two very brief. Do you have the rigs lined up for the Brazil Horizontals and also you talked about Block 107 improve in the release. There is no mention of really forming opportunities. Then you talk about cash, is that still the plan for Block 107?

Shane O'Leary

Yeah we are looking for partners in Block 107 as well as a variety of other blocks in our portfolio. The rig in Brazil yes we have the rig contracted in Brazil and I believe it is actually moving or poised to move any day now to the joint location there. I think there is a third piece of your question that I have already forgotten.

John Malone - Global Hunter Securities

No that was just it. Thanks a lot. I appreciate it

Operator

Thank you our next question is from Matt Portillo of Tudor Pickering please go ahead.

Matt Portillo - Tudor Pickering

Just a couple of quick questions for me. In terms of the production at Costayaco could you talk a little bit about the response that you are seeing and maybe how that could correlate to when you ultimately expect to see production declines on the field?

Shane O'Leary

Well we are seeing a really good response to water flood and we are actually seeing increasing pressures in the Tie sand for example and obviously that's supporting our current production which in our guidance was 20,000 to 21,000 barrels a day and barring pipeline disruptions were certainly capable of meeting that target. It's always tough to project when a field will go in to decline. We know there is a lower water saturation which means the reserves are higher. I would say that we believe that the water saturation is still lower than from what GLJ is assuming. So that there is additional upside possible.

One thing you can always tell from a plateau that’s getting extend is, it's drawing from somewhere. So, you know that the field is bigger than you originally thought. You know, so, I think we’re not expecting declines anytime soon. Maybe next year, something like that, but certainly the reservoir is performing at a much higher level than expected.

Matt Portillo - Tudor Pickering

Great and then in terms of the step out on northern part of Costayaco, what do you see as the biggest I guess technical risks with that well or geological risks with that well. Is that a separate enclosure potentially and how do you guys view that?

Shane O'Leary

There is risk associated with it and the trap is defined with the new 3-D seismic. I suppose the (inaudible) risk is that depth conversion of that 3-d seismic. Obviously we have well control at Costayaco-7 which is on the edge of that 3-D seismic program. So the technical risk is the shape of the northern extension based on the depth conversion and then there maybe a component of fault risk associated with it. So, it still remains geologic risk with that northern extension.

Matt Portillo - Tudor Pickering

Thanks and then just on to Moqueta quickly here, you guys have gone through the process of testing at various chokes, production response to dig it the ideal production ramp up for the field.

Can you talk a little bit about how that process is going and maybe how we should think about production volumes in to 2013?

Shane O'Leary

We’re getting a very good data over the last – I guess it's been six months to a year now. And one thing that is clear is we do need to be providing pressure support in the field in the latter part towards the end of this year. So in addition to producing wells, we're going to be planning on injecting water and then reinjecting gas when it's in to the gas cap.

So water below, gas above helped maintain that reservoir pressure given the oil is, the pressure is near the bubble point as far as gas solution in oil. So this is the sort of the key technical findings we've gotten from the test data to date. Now what we need to do is find the reserves, the total volume of reserves that are there Moqueta-7 and Moqueta-8, the two wells I mentioned are key to that.

So once we know the volumes, the gross reserve volumes combined with pressure data we have, we can then fill the reinjection equipment for the gas and water and then come up with a realistic guidance on production from the field.

Right now we don’t have a development plan done. We don’t have a plateau production defined because we don’t know what the reserves are at this time.

Matt Portillo - Tudor Pickering

Okay, and in regards to that, has that changed I guess I think you previously mentioned initial production rates anywhere between kind of 500 and 1500 barrels a day. Does that mean you will less drawdown on these wells potentially and as your view changed I guess on the potential production per well for that field at the moment?

Shane O'Leary

We’re limiting the draw down on individual wells now. We are limiting the draw down until we get the pressure support for the reservoir in place. Now once that reservoir maintenance -- pressure maintenance equipment in place, then typical wells will be anywhere from 500 to 1500 barrels per day per well, would be reasonable based on offsetting wells.

Matt Portillo - Tudor Pickering

And last question for me, I'm not sure if you mentioned this. On Brazil any update on I guess potential for a 2013 exploration well offshore or are those still in discussion at this point?

Shane O'Leary

It's still on the plan you know. So no developments in that regard, still a well planned for next year.

Operator

Our next question is from Rafi Khouri of Raymond James.

Rafi Khouri - Raymond James

Could you give us maybe some more detail on which formations you are actually flowing from Costayaco and if you are seeing some of the signs excluding the water injection and pressure support, are you seeing some of the signs behave differently than you thought they would have maybe a year ago or a couple of years ago.

Shane O'Leary

Not really, I mean really what's changed is we, a few years ago, we did a special core analysis that indicated that the water saturation was much lower than what GLJ was including and with the benefit of production history we've been able to prove that the water saturation is indeed lower than what they were using. So that's really the main reason the reserves have gone up and as I mentioned to another caller that we still think there's additional room for reserves to grow because they are not using a water saturation that's as low as what we think it is.

But in terms of the performance of the wells we are still, we are still the same type of performance and we've taken a lot of pressure data over the field particularly when we are offline with pipeline disruptions it’s a good opportunity to collect a lot of data and we are seeing increased pressures in the T sands and in the Caballos. So no I mean from a production point of view we are not seeing any new behaviors or anything like that on the wells. Water cuts have been very, very reasonable, have not been increasing across the field so it’s a great reservoir that's being well managed is the way I would describe it.

Operator

Thank you. Our next question is from George Toriola of UBS. George Toriola please go ahead.

George Toriola - UBS

Just to follow-up on the reserve increase at Costayaco again, could you talk about some of the values, you are talking about as far as water saturation is concerned, is I assume what you are talking about here is measured, is this estimated water saturation, measured water saturation and you talked about, Shane talked about your idea around more oil and place just based on I guess its probably decline analysis but is there any possibility that the risk here is that you have more sub service charge maybe rather than a larger oil in place?

Dana Coffield

No I think the main change that has taken place is the core space there is less water and the engineers had originally even engineers had initially assumed there is more oil in the core space so the arena oil place hasn’t really change the saturation of oil or lack of saturation of water that’s the main driver here which is as Shane mentioned will be more consistent with the core that was taken. Now but there is additional upside which you are referring to in and there are actually more oil in place if we are successful drilling in the north the Costayaco north so there is additional growth potential to the north for new reserves about and beyond what’s already been defined in the original oil in place, so little bit of both there.

George Toriola - UBS

Okay, and then I guess so with this reserve increase is the potential that you raised production from Costayaco along the same lines 40% or 30% or whatever it is?

Dana Coffield

No the plan is to maintain current plateau production and not increase that plateau production one of the reason for this is we don’t want to risk premature water break through from underlying water column by pulling too hard on say anyone known sort of reserves there but we have based on the data we have collected over the last few years we think is the optimum production rates from these wells to maximize oil recovery.

George Toriola - UBS

Okay but may just finally what Shane mentioned as the water cut was flat or something like that so would that if you had flat water cut would that still suggest that it is optimal or you will go increase in water cut?

Dana Coffield

No, around the planks or the edges of the field, the planks and field those wells we are seeing solely increasing water cut where as the well in the centre field have more stable water cut. So the water cut is rolling around the barges and field as you expect and as the model suggest and we been increasing our water handling capacity over the last year and a half I guess to handle that solely growing water cut.

Shane O'Leary

We got very detailed reservoir models now that tell us that we are producing at the optimum level to maximize recovery from the field.

Operator

Our next question comes from the line of Ian Macqueen of CIBC. Please go ahead

Ian Macqueen - CIBC

Couple of questions, with respect to the third party net profit interest, can you little bit more detail we work using 5% NPI and is that going to different in the future?

James Rozon

In the future basically it will slightly increase that percentage again as we disclose in our 10-Q that NPI relates to obviously third party net profit interest on 50% of Gran Tierra’s production in the Chaza Block. So, again the dispute relates to whether or not a high price royalty deduction can be included to arrive at the interest and it was a determined that it could not be deducted. Now that relates to only 50% of the production from the Chaza Block and if you are trying to model it, I would suggest maybe you can give me a call and then I can walk you through it. It's quite a detail to go through but again looking over the past history over the disputed period, less than 1% effect on our total revenue for that period.

Ian Macqueen - CIBC

Next question, with respect to our cost on production, not sales, it appeared there are about $18.42 of BOE in Q2. So Op costs have snuck up. It's about 15% increase quarter-over-quarter. Where do you expect Op cost to be going forward?

James Rozon

So, based on the increase from quarter-to-quarter, which was mostly as a result of the increased transportation required for moving our production to other delivery points other than OTA pipeline and also having the new agreement in effects for the full three months. So given that we would have less interruption in our pipeline delivery to the OTA pipeline, we would expect that transportation to be more in line with $3.60 per barrel versus $7 or $8 a barrel we paid to truck at delivery points. So we would expect our operating cost to come down related to that but I believe we are trending for the rest of the year somewhat close to where we are year-to-date and probably a little bit above based on the fact that we will be trucking more volumes to other delivery points.

Ian Macqueen - CIBC

Okay and with new reserve adds your DD&A was obviously going to be affected, do you have an estimated what DD&A would be over the year?

James Rozon

So DD&A for the second quarter would be representative of what we expect on a per BOE basis for the rest of the year, excluding the effect of any impairments that might be recorded as a result of dry wells etcetera in our new countries where we have no production specifically related to Peru which or Brazil in this case.

Ian Macqueen - CIBC

One last question, on the Costayaco reserves I would assume that there's no significant additional future capital associated with recovering those reserves. Its just mostly better recovery from the existing infrastructure and wells, is it not.

James Rozon

Yeah, that's correct.

Operator

Thank you and our next question is from Caio Carvalhal from JPMorgan.

Caio Carvalhal - JPMorgan

I have a quick question on Argentina and a couple of questions on Columbia. I will be very fast. On Argentina I just wanted to here from you guys what is the expectation of production increase in Argentina, basically on the current information I mean without relying on new development, how do you see the plateau had been in Argentina and when.

And on Columbia just three comments on the pipeline problem, the first of them we heard on Nacional de Petroleo release that one of the impacts, I know it’s a different pipeline despite at present do know they have the problem (inaudible) as well, but my question is consistently that we saw an increase in the operational expenses when it relates to security cost, I haven’t heard from you guys on this, frankly I just want to check if in your case the main impact on the present pipeline disruptions in the operation expense is related to trucking? And also I just wanted to confirm based on the last question, if OpEx per barrel including the higher level of trucking volumes should be normalized at something about $18 to $19 per barrel; that’s it?

Dana Coffield

So, no we are not seeing increased security costs for OTA; our costs are specifically for the increase in trucking. And I think your question was, should we expect $18 a barrel OpEx on a go forward basis?

James Rozon

Well, just as I said earlier that will depend on the level of trucking, so more or less we would expect somewhere between $17.50 and probably $19 a barrel.

Caio Carvalhal - JPMorgan

You mentioned something closer to $19 a barrel that’s what you said about $19?

James Rozon

Correct.

Shane O'Leary

In Argentina production, I mean what we are doing with the Puesto Morales where most of our reserves are as we are implementing what we hope will be a more efficient water-flood and the recovery to-date from that field has been very low; it’s only around 15% or 16% for light oil, it should be over 30%. So what we are trying to do is drive the recovery up over 30% which should give us another 5 million or 6 million barrels of reserves; whether that will translate into big increases in production or not, given declines in other areas we are looking for either a flat profile for Argentina or a modest increase in production going forward.

Caio Carvalhal - JPMorgan

That’s great; and if you will allow me just a final question; we noticed that we had in the first Q in Colombia now 26 days of interruption in the pipeline and we had 59 days of interruptions in the pipeline in the second Q. This is quite a high number, right? You are talking about almost two thirds of the quarter – you were not able to properly use the pipeline and we also saw in the release that from July 19th on things more or normalized. So from mid July till now, you did have any additional problem in the pipeline or up till now in the third Q we had pretty those 18 days of interruption in July and so far that’s it?

Dana Coffield

Yeah, you know in July things were still ramping up, so since mid July there has been no problems.

Operator

Thank you. Our next question is from Justin Anderson of Salman Partners. Please go ahead.

Justin Anderson - Salman Partners

Just a quick question about some of your planning; I know you had mentioned different options that you may utilize; I am curious if these pipeline attacks sort of continue on indefinitely at the kind of bigger that they were last quarter; which are the other projects for marketing of crude are you going to pursue and what would be the kind of timing on that; so that’s my first question?

And then second question is just regarding the $48 million spending that you have on acquisitions, that’s why I confirm that Brazil and the Peru working interest acquisitions and if that capital is already been deployed or if its still on the balance sheet? Thank you.

Dana Coffield

You know, the acquisition is for the working interest in the Blocks in Peru and Brazil. So that’s correct. And with the pipeline, we've already started to increase our sort of regular ongoing trucking capacity to other pipeline systems and we will continue to pursue that growth potential, you see like in trucking capacity. We’re also working or evaluating to building additional storage at Orito oil storage; Ecopetrol is rebuilding a pumping station on the OTA pipeline that will allow more throughput to the pipeline.

So with more storage in Orito and more throughput capacity on the pipeline that would be say the second in terms of timing with trucking happening now. This storage and throughput capacity building into third and – well I’ll say fourth quarter, to finally a pipeline system South in Ecuador will take more time in terms of putting together new agreements; it’s already used on a regular basis over the last couple of years. But in terms of having more continuous larger throughput capacity that will be a longer-term project probably sometime next year.

Operator

Thank you. Our next question is from (inaudible) of SunTrust. Please go ahead.

Unidentified Analyst

Just two quick questions; do you have any takeaway concerns around OTA or other pipelines and what are the types of production decline do you expect next year at Costayaco?

Dana Coffield

I am not sure I understood, we don't have any other, there are in the other pipeline systems there are restrictions in downstream, so there are capacity constrains with some of the other pipelines in Colombia. So we are dealing with users with commitments on those pipelines to help their commitments.

And I am sorry, I have already forgotten your second question, decline in Costayaco, sorry yeah. We don't have concerns around declines, you know typical decline rates on typical wells in the basin and our other producing fields are 20% to 25% per year. Some of our wells are declining at those rates; other wells are not declining at all.

So we don't have concerns about maintaining our current plateau production in the field this year and into next year. And then also we’ll catch-up production ramping up next year, so when Costayaco does hopefully start declining, we will be able to offset that or perhaps even grow with our new Moqueta production.

Operator

Thank you. And our next question is from Neal Jacobs of Cambrian Funds. Please go ahead.

Neal Jacobs - Cambrian Funds

Just curious what spurred the decision to go forward with the reserve report mid-year for Costayaco?

Dana Coffield

It’s really the magnitude of the materiality of the adjustment. We continue to see superior performance from the wells. We had this core data that Shane mentioned before ahead of and explained why we are getting the superior performance, so meaning with GLJ acknowledge that the performance of the wells was in fact exceeding without any public domain so we have to do this reserve update given it’s materiality and the investors should know about it and we had a fiduciary duty to share with our shareholders given the size of the reserve adjustment.

Operator

Thank you. And our last question is from Frederick Kozak [Canaccord Adams]. Please go ahead.

Frederick Kozak - Canaccord Adams

Just couple of quick questions guys, first of all, can you just refresh our memory on when you are going to spud the Block 95 well in Peru and the timing of that drilling?

Dana Coffield

It’s looking like December spud for Block 95 in Peru and it’s about a 30 day well; we started the location construction, the rig contracts signed, so sometime in December we will spud.

Frederick Kozak - Canaccord Adams

And secondly can you offer any more color on the ANH dispute that you are having on the Chaza Block and is there any decision when you might go to arbitration, have you considered that sort of where are you going with that dispute with those guys?

Dana Coffield

There has been no substance of change; we do have this disagreement with ANH with regards to the application of the high price royalty to the Chaza production. We don’t think it applies; but we have not gone to arbitration yet at this point, we are still talking to ANH about it, so it’s not formally in arbitration process; if we have to, we would go there, but we are not there yet.

Frederick Kozak - Canaccord Adams

And do you have a sense that you might make that decision this year sort of I don’t know how long these discussions take with ANH, but obviously one of the other companies down there has entered into that process?

Dana Coffield

Yeah, well I would have thought we would have been there or not by now and so for over six months I think. So presumably we will get – that decision we made, we expect this year, but I assume this year.

Operator

Thank you. We have no further questions at this time. I will now turn the call back over to Mr. Dana Coffield.

Dana Coffield

Alright thank you Christine. I would once again like to thank everyone for joining us today and we look forward to speaking with you next quarter to update you on our progress. Have a good week everyone.

Operator

Thank you ladies and gentlemen. This concludes today’s conference. Thank you participating. You may now disconnect.

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