Gran Tierra Energy Inc.
Q1 2014 Earnings Call Transcript

Published: 8 May 2014

[Operator:]

Good afternoon, ladies and gentlemen, and welcome to the Gran Tierra Energy's results conference call for the quarter ended March 31, 2014. My name is Crystal, and I will be the coordinator for today. [Operator Instructions] I would like to remind everyone that this conference call is being webcast and recorded today, Wednesday, May 7, 2014, at 4

[Dana Coffield:]

Thank you, Crystal. Good afternoon, and thank you for joining us for Gran Tierra Energy's First Quarter 2014 Results Conference Call. With me today is Shane O'Leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer. Yesterday evening, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's 2014 report on Form 10-Q for the 3 months ended March 31, 2014, has been filed on EDGAR and SEDAR and will be available on our website at www.grantierra.com. I'm going to begin today by talking about some of the key developments for the quarter. James will discuss key aspects of this quarter's financial results, and Shane will then take a few minutes to provide an operations update. I will then return to provide a budget update and closing remarks. Gran Tierra Energy has just delivered another strong quarter of production and funds flow from operations, exceeding our budget for the first quarter or this year. Quarterly oil and natural gas production net after royalty and adjusted for inventory changes of 21,819 barrels of oil equivalent per day was consistent with production of 21,556 barrels of oil equivalent per day for the fourth quarter of 2013. Before inventory adjustments, production in April 2014 averaged approximately 21,900 barrels of oil equivalent per day net after royalty. Cash flow for the first quarter of 2014 was ahead of expectations due to lower than budgeted production deferral resulting from a continued successful execution of measures to mitigate the impact of disruptions in the OTA pipeline Colombia. In addition, in Colombia, production from new wells had a positive impact in the first quarter of 2014. As a result, Gran Tierra Energy continues to anticipate 2014 average production to range between 23,500 and 24,500 BOEs per day net after royalty before adjustments for inventory changes. Approximately 97% of this production consists of light oil and the balance is natural gas. Funds flow from operations increased to $91 million for the first quarter from $68 million in the fourth quarter of 2013. Cash and cash equivalents were $391 million at the end of the quarter, compared with $429 million at December 31, 2013. And as before, we remain debt free. Now Shane will go through the operational results for the quarter shortly, but highlights include the Zapotero-1 exploration well on the Chaza Block has completed drilling operations and testing is underway and is expected to be completed this month. The Bretaña-1WD well has -- or was spud last month and is drilling ahead. This water disposal well is being drilled as part of our preparation for our first production in Peru later this year. We will also investigate additional resource potential of a thick oil-water transition zone, which has not been tested, where no reserves have been booked to date. Work continues on preparation for initiating long-term test production from Bretaña in the fourth quarter of this year, at a rate of approximately 2,500 barrels of oil equivalent -- of oil per day, gross. Work also continues on an appraisal well in the Southern lobe of the Bretaña field to be drilled in the fourth quarter. It will provide additional reservoir data for full field development and, if successful, may move substantial reserves from the possible category to the probable category. Finally, in Argentina, we completed drilling the Proa-3 appraisal well, and are now preparing a testing program to determine fluid in the reservoir properties. Let me now turn the call over to James Rozon to discuss the financial results in more detail. James?

[James Rozon:]

Thank you, Dana, and good afternoon, everyone. Our operational success has translated into another quarter of financial success, allowing us to retain a strong balance sheet to continue funding our growth strategy. For the first quarter of 2014, revenue and other income increased by 6% to $170 million from $160 million compared with the fourth quarter of 2013, due to higher production and realized prices. Average realized oil prices increased by 7% to $88.45 per barrel for the first quarter of 2014, compared with $82.30 per barrel in the fourth quarter of 2013, due to lower volumes sold in the current quarter for which price is adjusted for trucking costs. Revenue and other income in the first quarter of 2014 decreased by 17% to $170 million compared to $205 million in the corresponding quarter in 2013, when realized prices were higher and a larger inventory reduction in Columbia accounted for additional production of 1,556 barrels of oil equivalent per day. The average price received per barrel of oil increased by 11% to $88.45 for the first quarter of 2014 from -- sorry, decreased by 11% to $88.45 from -- for the first quarter of 2014 from $99.17 in the first quarter of 2013, due to a lower Brent oil price and a higher percentage of volume sold in the current quarter for which the price is adjusted for trucking costs. During the first quarter of 2014, 48% of our oil and gas volumes sold in Colombia were to a customer where the realized price is adjusted for trucking costs related to a 1,500-kilometer route. The effect on the Colombian realized price for the first quarter of 2014 was a reduction of approximately $8.33 per barrel to $89.73 per barrel, as compared to delivering all of our Colombian oil to the OTA pipeline. Sales to this customer during the corresponding quarter in 2013 were 28% of our oil and gas volume sold in Colombia. And the effect on the Colombian realized price was a reduction of approximately $5.39 per BOE. Operating expenses in the first quarter of 2014 decreased by 31% to $28 million from $41 million in the comparable quarter in 2013. For the first quarter of 2014, the decrease in operating expenses was primarily due to a decrease in the operating cost per BOE and lower production. On a per BOE basis, operating expenses decreased by 26% to $14.41 in the first quarter of 2014, from $19.46 in the corresponding quarter in 2013, primarily as a result of lower transportation costs. The inventory volume liquidation in comparative quarter in 2013 carried high transportation costs due to the delivery point to which they were sold and to which they -- we did not deliver in -- or delivered to in the current quarter. Furthermore, there were no transportation costs related to the portion of volume subject to alternative transportation arrangements, whereby trucking costs related to a 1,500-kilometer route are netted to arrive at our realized price rather than recorded as transportation expenses. The estimated net effect of OTA pipeline disruptions on Colombian transportation costs for the first quarter of 2014 was the savings on $1.81 per BOE as compared with delivering all of our Colombian oil through the OTA pipeline. In the corresponding quarter of 2013, the net saving was $1.24 per BOE. Operating expenses per BOE also decreased in the first quarter of 2014, compared with the corresponding quarter in 2013, as a result of deferred workover expenses, lower field consumption and lower training costs. Operating expenses decreased by 30% or $12 million from $41 million in the fourth quarter of 2013 due to lower workover expenses and deferral of maintenance and other costs in Colombia and Argentina and reduced electrical and equipment rental costs in Colombia. Depletion, depreciation, accretion and impairment, or DD&A, expenses in the first quarter of 2014 were $53 million compared with $58 million in the corresponding quarter in 2013. On a per BOE basis, the depletion rate of $27.07 was comparable with $27.71 in the corresponding quarter in 2013. Increased costs in the depletable base were offset by increased reserves. General and administrative, or G&A, expenses for the first quarter of 2014 increased by 33% to $15 million, compared with the corresponding quarter in 2013. Increased employee-related costs, higher consulting expenses associated with increased activity, expanded operations in Peru and higher stock-based compensation expenses associated with restricted stock units and stock options granted, were partially offset by higher G&A allocations to operating expenses and capital projects within the business units during the first quarter of 2014. G&A expenses per BOE in the first quarter of 2014 of $7.74 were 43% higher, compared with $5.42 in the comparable quarter in 2013 due to lower production, partially offset by higher G&A allocations to operating expenses and capital projects within the business units. G&A expenses in total and per BOE in the first quarter of 2014 were comparable to those in the fourth quarter of 2013. In the first quarter of 2014, the foreign exchange loss of $0.1 million, comprised a $4.2 million unrealized noncash foreign exchange gain and realized foreign exchange losses of $4.3 million. The unrealized foreign exchange gain was a result of a net monetary liability position in Colombia, partially -- or combined with the weakening of the Colombian peso. This was offset by foreign exchange losses resulting from a net monetary asset position in Argentina and the weakening of the Argentina peso. For the first quarter of 2013, there was a foreign exchange gain of $5 million, comprising a $7 million unrealized noncash foreign exchange gain and realized foreign exchange losses of $2 million. Financial instrument gains of $2 million in the first quarter of 2014, was related to unrealized gains on our nondeliverable forward contracts. We purchased these contracts in February 2014 for the purpose of fixing the exchange rate to purchase Colombian pesos to settle our income tax installment payments due in April and June 2014. We had net income in the first quarter of 2014 of $45 million, compared to $58 million in the comparable quarter in 2013. In 2014, lower operating, DD&A and income tax expenses, financial instrument gain and the absence of other losses were more than offset by decreased oil and natural gas sales, increased G&A expenses and the absence of foreign exchange gains. Net income for the first quarter of 2014, up $45 million, was $58 million higher than the net loss of $13 million in the fourth quarter of 2013 as a result of higher revenue, lower operating costs and the absence of impaired -- impairment charges in the current quarter. Funds flow from operations was $90 million -- $91 million, an increase of 33% or $23 million from $68 million in the fourth quarter of 2013, and a decrease from $109 million in the comparable quarter in 2013. The decrease compared with the corresponding quarter in 2013 was due primarily to the affected inventory adjustments and higher realized prices in the comparable quarter. Cash and cash equivalents were $391 million at March 31, 2014, compared with $429 million at December 31, 2013. The decrease in cash and cash equivalents during the first quarter of 2014, was primarily the result of cash capital expenditures of $75 million and a $55 million charge -- change in assets and liabilities from operating activities, partially offset by funds flow from operations of $91 million. In summary, we remain financially strong. As Dana said, we expect that our 2014 capital program of $495 million will be funded from cash flow from operations and cash on hand. That concludes my comments. I would now like to turn the call to Shane for an operations overview and an update on our 2014 capital plan and outlook.

[Shane P. O'Leary:]

Thank you, James. On the Chaza Block in Colombia, we drilled and started completion work on the Costayaco-20 development well in the Costayaco field and commenced drilling the Costayaco-22 development well. The Costayaco-20 development well was completed as an oil producing well subsequent to the quarter and has been producing approximately 2,000 barrels of oil per day gross. We drilled the Corunta-01 exploration well, but encountered drilling problems prior to reaching the reservoir target on this long-reach deviated well, and the decision was made to abandon the well. The well location is expected to be drilled again in 2014 with a revised drilling plan. We drilled the Zapotero-1 exploration well, another long-reach deviated well. After encountering and overcoming similar drilling problems, we were able to reach total depth, down depth into the East of the known oil accumulation in the Moqueta field. The well reached total depth within the Caballos formation at 10,672 feet measured depth or 7,550 feet true vertical depth. The Zapotero-1 bottom hole location is approximately 7,400 feet northeast of Moqueta-12, and the reservoir sandstones were encountered approximately 2,000 feet lower than the lowest known oil encountered at the Moqueta-12. Testing is underway to confirm the fluid content and productivity of the encountered zones and is expected to be completed in May. Initial testing and evaluation of the Miraflor Oeste-1 exploration well on the Guayuyaco Block, we expect to initiate long-term test productions in June of 2014. On the Llanos-22 Block, the Mayalito-1 oil exploration well started long-term test production in late January. We completed 2D seismic acquisition on the Piedmonte Sur block, continued 2D seismic acquisition on the Cauca 7 Block and 3D seismic acquisition on the Putumayo 1 block and commenced an arrow gravity and magnetic survey on the Sinu-1 and Sinu-3 blocks. Our planned work program for the remainder of 2014 in Columbia includes drilling 3 oil exploration wells on the Chaza Block and 1 gross exploration well on the Putumayo 1 Block. We also plan to drill a total of 6 development wells on the Chaza Block, both Costayaco and Moqueta fields. In addition, we plan to commence the acquisition of 2D seismic on the Chaza, Guayuyaco, Putumayo 10, Sinu-1 and Sinu-3 Blocks and 3D seismic on the Putumayo 1 Block. Facilities work is also planned for the Chaza, Garibay and Llanos-22 blocks. In Argentina, during the first quarter of 2014, we commenced drilling the Proa-3 development well on the Surubi Block and completed workovers on wells on the Puesto Morales and El Vinalar Blocks. Proa-3 has reached total depth and preparations are being made to start testing. In addition, we also plan to perform facilities work on the Puesto Morales Block, the Surubi Block, the El Chivil Block and the El Vinalar Block. On Block 95 in Peru we commenced drilling activities for a water disposal well in the Bretaña field. This well will also test additional resource potential in a thick, previously untested oil-water transition zone. In addition, planning continues for an appraisal well to be drilled at the L4 location, which if successful, may prove substantial -- may move substantial possible reserves into probable reserves and will provide additional reservoir data for field development planning. Finally, crude oil processing and loading facilities are expected to be completed in order to initiate long-term test production in the fourth quarter of 2014 at approximately 2,500 barrels of oil per day, our first production in Peru and our first milestone in developing this substantial asset. On Block 107 and Block 133, we continued work to obtain the necessary environmental and social permits for seismic programs to be undertaken this year. We also completed aeromagnetic survey data analysis on Block 133 and refurbished the seismic camp on Block 107. Planning continues in preparation to drill our first exploration well on Block 107 in 2015. Finally, we continue work to obtain the necessary environmental permits in anticipation of drilling our first exploration wells on Blocks 123 and 129 in 2016. In Brazil, on Block 155, we successfully completed the dual completion of the GTE-4 development well, which is now capable of producing over 1,000 barrels of oil per day. We also completed the single-stage fracture stimulation on the exploration well, GTE-8. Our planned work program for the remainder of 2014 in Brazil will focus on facilities work in the Tiê field along with seismic acquisition on Blocks 86, 117 and 118. We will continue to study our 2 unconventional resource plays in 2014 through core analysis, geochemistry studies, 3D seismic acquisition and reprocessing, and evaluation -- evaluating ongoing fracture stimulation test results, among other activities, in an effort to establish the commercial viability of the resource opportunity in the oil saturated tight sandstones and shales in the Recôncavo Basin. I will now turn it back over to Dana for concluding remarks.

[Dana Coffield:]

Thank you, Shane. Gran Tierra Energy's planned capital program for its exploration and production operations in Columbia, Brazil, Peru and Argentina for 2014 has been revised to $495 million from $467 million. This includes $246 million for Columbia, $38 million for Brazil, $48 million for Argentina, $161 million for Peru and $2 million associated with corporate activities. The majority of the increase is associated with the increasing cost for the long-term test facilities on Block 95, acceleration of the base camp construction on Block 107 in Peru, where we are planning to drill an exploration well next year. Additional Zapotero-1 and Corunta-1 exploration well costs and 2013 budget spillover into 2014, in both Colombia and Brazil. The capital spending program will allow us to grow production this year, continue exploration drilling for new reserves, and most importantly, continue developing our vast undeveloped reserve base. Our focus will be developing the Moqueta field in Columbia to drive near-term production growth, while continued development at Bretaña in Peru will drive our midterm growth profile. Gran Tierra Energy continues to execute these programs while retaining a strong balance sheet with a substantial undeveloped reserve base, an unusually long reserve life index, and, after exploration program and appraisal drilling program, have a growing production base and a strong balance sheet. We are perfectly positioned to continue growing our company and look forward to communicating continued success with you for the remainder of this year and beyond. Well that concludes our prepared remarks this afternoon. We would now be pleased to answer any questions you might have. Crystal?

[Operator:]

[Operator Instructions] Our first question will come from the line of John Malone from Mizuho Securities.

[John T. Malone:]

Just looking at the release, you're talking about Peru, and now you're saying that Q4 will be the likely start for the long-term test. I think Shane mentioned some processing and loading construction you're doing, is that the reason that you delayed it from a Q3 start you talked about previously?

[Dana Coffield:]

We had planned on September 1 for a start. And just to answer, yes, it's a variety of different construction issues, long lead items and finalizing barges that's caused -- looks like it's probably a month or so delay, pushing it into the fourth quarter.

[John T. Malone:]

Okay. And then in Columbia, just on the kind of the back of the envelope numbers you're running so far, it looks like relatively flat year-on-year in terms of production. Am I reading that right, is Costayaco going to decline or is it going to stay flat for the balance of the year?

[Dana Coffield:]

Costayaco has not started decline. We are expecting to start declining in late this year, perhaps early next year, but it's still on plateau production. Moqueta production is more or less flat. It's going to drilling towards the end of the year. And it looks like that, obviously, continue growing next year. So overall, it's actually flat as you say. There's a few intakes on the different wells, but it's essentially flat.

[John T. Malone:]

Okay. And one last one for me. Just I'm kind of taking a step back in looking at Brazil, when you talk about what you need to do, ascertain the commerciality, on the unconventional play there. When do you think you'll have a better handle on whether or not the commercial -- whether it would be -- unconventional play will be commercial and how are things different now than they were looking at it 6 months ago?

[Dana Coffield:]

Well, now we have more rough data, we've recovered some oil, we have not had commercial flow rates. So what we're doing is stepping back, as you said, evaluating all of our data. We still have another fracture stimulation we want to do on a tight sand. And that point, just have a complete fresh look at all our data, the rock properties, the various test results and decide where to -- where and how to proceed with that program. So I think the decision on next steps will be made later this year, but we won't see any more drilling this year, that would happen next year.

[Operator:]

Our next question will come from the line of Alan Knowles from Haywood Securities.

[Alan Knowles:]

A question on the seismic, you've made a shift from your -- in the amount of 2D down and the 3D up, can you just give us some color as to where you're moving your program around?

[Dana Coffield:]

What do you mean the program? We got -- and I don't know that we've actually moved the program around. It's the same program. There's been slippage in time on different projects. To tell you the truth I can't think of how we changed the 2D versus 3D on any of our programs.

[Alan Knowles:]

Okay. I'm just thinking of the emphasis from your -- because you had 2,200 kilometers in your original guidance down to 1,700 on the updated?

[Dana Coffield:]

I'll have to get back to you, Alan.

[Alan Knowles:]

Okay. And then, just on Moqueta. So I know you're expecting to get that approval this quarter still. As soon as you get that, is there -- can we look to see you more active in the drilling front-end and then maybe getting after the wells that you want to drill and you've been delaying them, is that fair to say?

[Dana Coffield:]

I wouldn't say you'll see a quick increase in drilling activity this year. With that permit we'll decide on whether or not and where to build the road and platform, construction, et cetera. The real advantage to getting that permit is, one is the appraisal drilling, which would happen late this year into next year to further delineate the limits in the field, avoid the difficulties we've had with Zapotero and Corunta. In terms of developing the reserves we have now, we're going through a process now to determine whether or not we can actually just proceed with that development from existing pads, not actually need new pads for the water injection and additional development production well drilling. Shane?

[Shane P. O'Leary:]

Yes, I mean, I think it's important to note that we've done a lot of work already without the permit. And we can continue to do a lot of work without the permit. It's just not optimum from a cost perspective because we've got to move everything by helicopters. We can only drill from certain pads, which means we have to drill more deviated long-reach wells than we'd like. And so, we can actually develop this whole field from the existing pads we have, but it's just not optimum. But we'll continue to do what we have to do to grow production and not wait on the permit, which is what we've been doing.

[Alan Knowles:]

Okay. And I guess lastly on Proa-3, can you -- do you know the timing on when we might see the results of the testing you're going to be doing there?

[Dana Coffield:]

Testing is going to take place over the next, I'll say, 2 weeks. So results maybe, end of May.

[Operator:]

Our next question will come from the line of Ian Macqueen from Paradigm Capital.

[Ian Macqueen:]

Just a simple question for James, actually. One of the things I noticed for sure is that DD&A on a per barrel basis went down. Is that mostly a function of a higher depletable base on the 2P reserves?

[James Rozon:]

Sorry, depletion is calculated on 1P reserves. And the reason why -- the most significant reason for change compared to prior year is the fact that our 1P reserves increased back up in Colombia. We replaced our production. So essentially moved 2P to 1P last year at the end of the year, which results in a lower DD&A rate at the last quarter and moves into this year. So that's the most significant reason from Colombia. And then, as a reminder, last quarter, we -- in the fourth quarter of 2013, we did have an impairment in our Argentina cost center, which also decreased that depletable base, which will move through into this year.

[Ian Macqueen:]

Right. So we should expect something fairly similar to what we saw in Q1 for the remainder of the year? That's the idea, I guess.

[James Rozon:]

Yes, excluding any potential write-downs that may occur for reasons that right now, we don't -- we're unaware of.

[Operator:]

[Operator Instructions] Our next question will come from the line of Felipe Santos from JPMorgan.

[Felipe Dos Santos:]

Just some quick questions. What's the company's idea for developing the Peru assets and would it be -- considering finding out to consider considering doing alone and how do you see, I mean, there's increase in CapEx. Do you think that with CapEx, Q4 should be the same?

[Dana Coffield:]

For Peru, for Bretaña, our plan is just proceed as developing it on our own. At this time. For exploration typically, we will typically bring on partners to help offset our capital exposure, risk capital exposure. So that's something we may evaluate in the future. But right now, for Bretaña, the current plan is just continue alone. I forgot what your second question was.

[Felipe Dos Santos:]

That's okay, it's just about the development of Peru, that's perfect.

[Operator:]

And now, I'd like to turn the call back over to Mr. Dana Coffield for closing remarks.

[Dana Coffield:]

All right. Well, I'd like to everyone for joining us today. And we look forward to updating you with our results next quarter.

[Operator:]

Ladies and gentlemen, that concludes today's presentation. You may now disconnect. Have a great day.