Gran Tierra Energy Inc.
Q3 2014 Earnings Call Transcript

Published: 8 Nov 2014

[Operator:]

Good afternoon, ladies and gentlemen, and welcome to Gran Tierra Energy's results conference call for the quarter ended September 30, 2014. [Operator Instructions] 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 reports on Form 10-Q for the quarter ended September 30, 2014, filed with the Securities and Exchange Commission November 5, 2014. 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 measure funds flow from operations. The press release disseminated by Gran Tierra Energy this morning includes a reconciliation of this non-GAAP item with the company's GAAP net income or loss, as well as information about why management believes the measure is useful in evaluating the company's performance and is available on Gran Tierra Energy's website, www.grantierra.com. All dollar amounts mentioned in today's conference call are in U.S. dollars unless otherwise stated. Finally, this earnings call is the property of Gran Tierra Energy Inc. Any copying or rebroadcasting of this call is expressly forbidden without the written consent of Gran Tierra Energy. I will now turn the conference over to Mr. Dana Coffield, president and chief executive officer of Gran Tierra Energy. Mr. Coffield, please proceed.

[Dana Coffield:]

Thank you, operator. Good afternoon, and thank you for joining us for Gran Tierra Energy’s third quarter 2014 results conference call. With me today is Duncan Nightingale, our new chief operating officer, and James Rozon, our chief financial officer. First, let me start by welcoming Duncan back to our corporate executive team in Calgary. Duncan recently returned to Calgary after a successful three and a half year tenure as president of our Colombia business unit and has just recently assumed the position of chief operating officer. As some of you may recall, Duncan was previously vice president of exploration for Gran Tierra Energy. Now, yesterday, 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 three months ended September 30, 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’s conference call talking about some of the key developments for the quarter. James will discuss key aspects of this quarter’s financial results and Duncan will then take a few minutes to provide an operations update. I will then return to provide a budget update, including remarks. Gran Tierra Energy delivered strong results in the third quarter by focusing its core assets and operating capabilities while we approached the major milestone of first production in Peru in December 2014. In Colombia, the Costayaco and Moqueta fields continued to deliver strong production and cash flow. I am happy to announce the Moqueta exploitation license was finally approved, and we continue to work towards reaching production levels of approximately 8,000 barrels of oil per day gross in 2015. The Moqueta-15 and 16 wells were recently drilled and Moqueta-17 is expected to spud in November. Production from the fields is approximately 6,000 barrels of oil per day gross, up from 4,500 barrels of oil per day gross at the start of 2014. Also on the [Chaza Block], the Costayaco-19 and Costayaco-21 wells were both drilled in the third quarter. The Costayaco-21 well was put on production while the Costayaco-19 well will be used initially as an oil producer and eventually converted to a water injection well to help maintain reservoir pressure. The Eslabon Sur Deep-1 exploration well was spud on October 19, 2014 and those operations are continuing, with further drilling in the Eslabon area to be determined after the Eslabon Sur Deep-1 explore results are evaluated. This prospect is located 10 kilometers west of the Moqueta field and the well is targeting the same Cretaceous reservoirs encountered in the Costayaco and Moqueta discoveries. Also in the Putumayo Basin Gran Tierra Energy was the successful bidder for the Putumayo-31 block in Colombia’s National Hydrocarbon Agency in 2014 bid round, where we continued to build our land position and our core operating environment. In Peru, the Bretana field development is progressing as you get closer to first production. The long term test production from the Bretana discovery well is expected to begin in December with production expected to reach a rate of approximately 2,500 barrels of oil per day gross. Equally important, mobilization of the drilling rig for the Bretana Sur appraisal wall has begun, with drilling expected to be executed through December 2014. Upon success, this well will have a substantial impact on reserve bookings in the field. And finally, in Brazil, the appraisal plan for two new resource plays, light oil in tight [unintelligible] and light oil in shales, for blocks 129, 142, and 155, was approved by Brazil’s National Hydrocarbon Agency. Our production from continuing operations for the third quarter of 2014 averaged 25,340 BOEs per day working interest or 19,297 BOEs per day net after royalties, before adjusting for any inventory changes and losses, or 20,641 BOEs per day net after royalties, before adjusting for inventory changes and losses. 99% of this production was oil. Funds flow from operations increased $89 million for the third quarter compared to $85 million in the second quarter of 2014. Our balance sheet remains strong, with cash and cash equivalents totaling $360 million at the end of the quarter. We remain debt free. 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. 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 third quarter of 2014, revenue and other income increased by 9% to $162 million from $149 million, compared with the second quarter of 2014, due to increased production, partially offset by decreased realized prices. Average realized oil prices decreased by 9% to $85.40 per barrel for the three months ended September 30, 2014, compared with $93.72 per barrel in the second quarter of 2014, due to lower benchmark prices and higher volumes sold in the current period, for which the price is adjusted for transportation costs. Revenue and other income in the third quarter of 2014 decreased by 5% to $162 million, compared with $171 million in the corresponding quarter in 2013, as a result of decreased realized prices, partially offset by increased production. And oil inventory on losses reduction, primarily in Colombia, accounted for 1,344 barrels of oil per day of increased production, compared with an oil inventory increase of 407 barrels of oil per day, which reduced production in the comparative quarter. The oil inventory reduction was due to the liquidation of inventories to a new customer with a protracted sales cycle and the reduced impact of pipeline disruptions. The average price received per barrel of oil decreased by 12% to $85.40 for the third quarter of 2014, from $96.69 in the third quarter of 2013, primarily due to decreases in the benchmark prices during the three-month period, a reduction of the Ecopetrol price of $2.94 per barrel as a result of an increased port operations fee charged to us and higher volumes sold to alternative customers to Ecopetrol during periods of OTA pipeline disruptions. During the third quarter of 2014,62% of our oil and gas volumes sold in Colombia were to alternative customers. The effect on the Colombian realized oil price for the third quarter of 2014 was a reduction of approximately $3.07 per barrel to $85.47 per barrel, as compared to delivering all of our Colombian oil through the OTA pipeline. Sales to alternative customers during the corresponding quarter in 2013 were 38% of our oil and gas volumes sold in Colombia and the effect on the Colombian realized price was a reduction of approximately $7.61 per barrel. Sales to two of the alternative customers were made at the beginning of the third quarter at the highest prices of oil for the quarter, decreasing the downward pressure on realized prices that results from selling to alternative customers. Beginning July 1, 2014, the port operations fee component of the OTA pipeline pricing structure increased by $2.94 per barrel, resulting in a reduction of realized oil prices by this amount on sales delivered through the OTA pipeline, reducing our Colombian realized oil price by approximately $0.89 per barrel for the third quarter of 2014. Operating expenses in the third quarter of 2014 increased by 35% to $34 million from $25 million in the comparable quarter in 2013. For the third quarter of 2014, the increase in operating expenses was due to an increase in the operating cost per BOE, combined with the impact of higher production. On a per-BOE basis, operating expenses increased by 26% to $17.88 in the third quarter of 2014 from $14.14 in the corresponding quarter in 2013, primarily as a result of higher pipeline and trucking costs due to sales to alternative customers with delivery points which carried higher transportation costs and increased work over expenses. The estimated net effect of OTA pipeline disruptions on Colombian transportation costs for the third quarter of 2014 was an increase of $0.28 per BOE as compared with delivering all of our Colombian oil through the OTA pipeline. In the corresponding quarter in 2013, the net saving was $2.02 per BOE. Operating expenses increased by 34%, or $9 million, from $25 million in the second quarter of 2014, due to higher transportation costs associated with inventory liquidated in the third quarter of 2014 in Colombia, and increased workover activity. Depletion, depreciation, accretion, and impairment, or DD&A, expenses in the third quarter of 2014 were $54 million compared with $51 million in the corresponding quarter in 2013, primarily due to higher production, partially offset by a lower depletion rate. On a per BOE basis, the depletion rate decreased by 2% to $20.40 from $28.92. On a per BOE basis, the decrease was due to an increase in reserves combined with a decrease in costs in the depletable base relating to lower future development costs. General and administrative expense, or G&A, expenses for the third quarter of 2014 increased by 13% to $13 million, compared with the corresponding quarter in 2013. The increase was mainly due to increased activity related to expanded operations in Peru, increased employee-related costs, and higher consulting expenses. G&A expenses per BOE in the third quarter of 2014 of $7.03 were 6% higher compared with $6.64 in the comparable quarter in 2013, due to increased costs as previously discussed. In the third quarter of 2014, the foreign exchange gain of $12 million comprising a $14 million unrealized noncash foreign exchange gain and a realized foreign exchange loss of $2 million was a result of a net monetary liability position in Colombia, combined with a weakened Colombian peso. For the third quarter of 2013, there was a foreign exchange loss of $400,000 comprising a $1.5 million unrealized noncash foreign exchange loss and realized foreign exchange gain of $1.1 million. Financial instruments loss of $3 million in the third quarter of 2014 was primarily related to losses on the Madelena Energy shares we received in connection with the sale of our Argentina business unit and our nondeliverable forward contracts. We had income from continuing operations in the third quarter of 2014 of $44 million, compared to $40 million in the comparable quarter in 2013. In 2014, decreased oil and non-GAAP sales as a result of lower realized oil prices and higher operating, DD&A, and G&A expenses and financial instrument losses were more than offset by foreign exchange gains and lower income tax expenses. Net income for the third quarter of $44 million was higher than net income of $9 million in the second quarter of 2014 and also increased compared with $33 million in the comparable period in 2013. The increase was due to the absence of loss from discontinued operations and higher income from continuing operations. Funds flow from continuing operations was $89 million an increase of 5% from $85 million in the second quarter of 2014 and a 6% increase from $84 million in the comparable quarter in 2013. The increase was primarily due to decreased oil and natural gas sales as a result of lower oil realized prices, higher operating and G&A expenses, and realized foreign exchange losses, which were more than offset by lower income tax expenses. Cash and cash equivalents were $360 million at September 30, 2014 compared with $429 million at December 31, 2013. In summary, we remain financially strong. We continue to expect that our 2014 capital program of $472 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 over to Duncan for an operations overview and update for the remainder of 2014.

[Duncan Nightingale:]

Thank you, James, and good afternoon to everyone. Gran Tierra once again delivered strong results this past quarter by successfully executing its operations plans. On the Chaza Block in Colombia, development of the Moqueta field is progressing with Moqueta-15 drilled, completed, and put on production in September. To further develop the field, the Moqueta-16 well was drilled to test a deeper adjacent fault block outside the existing booked oil reserves area and encountered water. This well is now being sidetracked into the existing booked reserves area and will be used as a producer and potentially converted to an injector at a later date to maintain the reservoir pressure. We plan to spud the Moqueta-17 well in November 2014. Production from the Moqueta field has grown to approximately 6,000 barrels of oil per day gross, and is expected to average 4,700 barrels of oil equivalent per day net after royalty in 2014, consistent with the original production guidance issued in December 2013. The development of the Costayaco field is ongoing, with the Costayaco-19 development well drilled in the third quarter of 2014 and will be used initially as a producer, then converted to a water injection well to help maintain reservoir pressure. That well is now being completed for production while the Costayaco-21 development well is now undergoing a workover and expected to be back on production before the end of the month. Production from the Costayaco field is expected to average 11,300 barrels of oil equivalent per day, net after royalty, in 2014. Also on the Chaza Block, subsequent to end quarter, Gran Tierra Energy spud the Eslabon Sur Deep-1 exploration well. Operations are continuing and the well is expected to reach TD bteo2 November. Gran Tierra Energy has deferred the Corunta-1A exploration well on the Chaza Block and may include this well in the 2015 exploration drilling program. Meanwhile, due to delays in the [civil’s] works, the Cabanas-1 exploration well is expected to be drilled in the first quarter of 2015 in the Putumayo-1 block. The Putumayo-1 block is immediately south of the Chaza Block in the Putumayo Basin, where Gran Tierra Energy has encountered multiple exploration successes. The future Putumayo exploration wells will be targeting the same cretaceous reservoirs Gran Tierra Energy has encountered with multiple exploration successes. The future Putumayo-1 exploration wells will be targeting the same cretaceous reservoirs, along with a new play type that has proven very successful nearby. On the Sinu-1 Block in northern Colombia, we commenced the acquisition of a 2D seismic program and on the Sinu-3 block, we also have commenced another seismic program. We also completed the interpretation of new 2D seismic acquired on the Piedmonte Sur Block and the [Calca] seven block. As Dana stated earlier, in the third quarter of 2014, we were the successful bidder on the Putumayo 31 block in the Putumayo Basin of Colombia in the National Hydrocarbon Agency 2014 bid round. We have received final government approval and will be the operator of this block with a 65% working interest. This block is deemed to have prospectivity in previously proven reservoirs and will allow Gran Tierra Energy to evaluate an additional play type, similar to that that’s being targeted in the Putumayo-1 Block. In Peru, on Block 95, rig mobilization for the Bretana Sur appraisal well has begun, and we expect the well to be drilled in December 2014. This well will gather additional reservoir data and is expected to further substantiate oil reserves in the field. Equipment for the first LTT long-term test production from the Bretana discovery well is being delivered to the location, with commissioning expected in November and first production in December. Production is expected to reach a rate of approximately 2,500 barrels of oil per day gross. The LTT will provide valuable information on reservoir performance and allow us to optimize the development going forward in addition to providing early cash flow. In Brazil, the appraisal plan for blocks 129, 142, and 155 was approved by Brazil’s National Hydrocarbon Agency. This evaluation plan contemplates evaluating and integrating data collected to date on the blocks through next year, and then undertaking the drilling of three wells in the next exploration period, should we elect to enter into that period. Gran Tierra Energy continues to evaluate the unconventional opportunities in oil saturated tight sands and shales in the Reconcavo Basin for this work. In summary, Gran Tierra has shown strong performance with planned operational goals and is well-positioned operationally to deliver on our future plans. I will now turn back over to Dana for his concluding comments.

[Dana Coffield:]

Thank you, Duncan. So Gran Tierra Energy’s planned capital program for exploration [and production] operations in Colombia, Brazil, Peru, and Argentina for 2014 has been reduced to $472 million from $482 million. This includes $248 million for Colombia, $26 million for Brazil, $18 million for Argentina, $175 million for Peru, and $5 million associated with corporate activities. Gran Tierra Energy is well-positioned technically and financially to continue growing reserves and production on our existing land base from existing assets, all supported by a strong balance sheet. I can’t emphasize enough the importance of the pending startup of production at the [unintelligible] field that is expected to begin in December. We continue to work extremely hard as we approach this important milestone, a milestone marking the first revenue in a major new development in the [unintelligible] Basin in Peru. Now, that concludes our prepared remarks for this afternoon. We would now be pleased to answer any questions you might have [unintelligible].

[Operator:]

[Operator instructions.] And the first question will be from the line of Nathan Piper with RBC Capital Markets.

[Nathan Piper:]

Thinking about Peru, two aspects of this. First of all, do you need some of this production test data to allow you to submit a field development plan for the Bretana field? And then the second question is, given the current oil price and let’s hope it doesn’t stay here forever, but if it does, how do you assess the economics of Peru, which at one point was to be cash flow funded, but may now have to be funded in a different way? What contingencies do you have to fund the project in a different way?

[Dana Coffield:]

So the first question is no, we don’t need the long term test data to submit the development plan. We’re doing the feed study right now from an engineering design, and our intent is to submit that sort of March/April timeframe, say early second quarter, to the government. And that development plan will have a whole variety of options available to us to modify as we gather more data. So we don’t need the LTT test results for the development plan submission. Now the second part of the question, of course, is all pricing. It’s got everyone anxious on the duration and the [unintelligible] point at which it levels off. [We’ve sort of been] considering oil price in the development plan, as well as the timing of the development plan. It was never actually contemplated, I don’t think, or perhaps it would have been [plays] that would be entirely funded from cash flow and cash available. If we accelerate the development, bring forward the plateaued production, which is what we’re currently contemplating doing, then that would require additional funding, some sort of a project financing. There’s a variety of options that we would call upon for this additional funding, if and when needed. So right now it’s a moving target. We’re still doing the development plan, so we don’t actually currently even know ourselves what the actual timing expenditures, magnitude expenditures, will be. We won’t know that until, again, the second quarter of next year, and then hopefully by the second quarter of next year, we’ll have more color on oil prices, and then we can plan the timing of spending, the pace of development, and financing options that may be required at that time.

[Nathan Piper:]

I assume that [unintelligible] have made some inquiries to the banks about the appetite for project finance of development in Peru. I guess you don’t want to start that in Q2 of next year, or maybe you are. I guess wanted to see what contingency, what sort of work you’ve done already, just in case the current oil price, and just in case you want to bring the project forward. Have you had some preliminary discussions with lenders?

[Dana Coffield:]

We have lenders coming to the office all the time offering financing, but as far as any substantive discussions, the answer is no.

[Operator:]

Your next question is from the line of Jamie Somerville of TD Securities.

[Jamie Somerville:]

Just wondering, with regard to capex, maybe my math is wrong, but it looks to me like your guidance implies that you’re expecting to spend $200 million in the fourth quarter, which would be roughly twice as much as you’ve ever spent in any quarter. So can I just ask what your conviction is that you’re actually going to complete that capex budget program?

[Dana Coffield:]

Yeah, it’s going to be a challenge to get it all done before year end. May be some slippage. But the current plan is to do what we have in our current forecast.

[Jamie Somerville:]

One specific item within that is the Bretana Sur appraisal well. Can I just ask you for your conviction that you’re going to get that well done in time to have it included in year-end reserve estimates?

[Dana Coffield:]

It’s going to be tight to do that [unintelligible]. The rig is actively moving, but [unintelligible] water, etc. So it may be a challenge to get it done by year end. If the drilling does carry over into, say, January, we will still do a reserve update for the field, and depending on time, it would probably come out in early February, along with our year-end reserves update, which typically comes out in early February. So if there’s a slippage of a week or two into January, but [unintelligible] to do the reserve update, and it will still come out more or less same time as the year-end reserves.

[Operator:]

Your next question is from the line of Jean Blanchette of Amber Capital.

[Jean Blanchette:]

I was just wondering, your stock is trading at a significant discount to the net asset value of proven reserves. I was wondering what you thought about this, and if you intend to do anything about this in the current market. Maybe drilling less wells and doing something else with your cash?

[Dana Coffield:]

We’re certainly thinking about it. We’re all thinking seriously about it. Given the magnitude of the capital spending coming forward with Bretana, at this time, we’re not considering using that cash for buying back stock or paying dividends or other things like that to try to change the share price. We’re tracking exactly with our peers, some of whom are buying back stock or paying dividends. You know, we’re pushing [unintelligible] with the current change in oil price, so really with our cash, we’re really focused on being prepared to execute on our developments, execute on our work programs, execute on developing reserves and growing production, even if oil remains where it is or falls lower. We want to keep a strong balance sheet so we can continue delivering on those reserves.

[Jean Blanchette:]

You’re the worst-performing stock of all the Colombian stocks this year. Maybe the market is signaling something that you should listen to?

[Dana Coffield:]

I disagree with you. Our closest peers are [RX] and [Rubiales]. Rubiales has outperformed us primarily because of the take out rumors associated with, I would suggest, the government, associated with one of the big funds in Mexico. [RX] certainly had an outstanding year in growing [unintelligible] reserves in the first six months of this year. If you look at the three companies, the three closest peers in Colombia, you’ll see they’ve tracked each other almost exactly for the last six months, three months, one month, and one week, since oil price has dropped. It depends on the timeframe you use. If you use one year, they’ve done better. If you use six months, three months, which are probably more relevant today, we’ve tracked each other very closely.

[Jean Blanchette:]

That’s fair, but your stock price has been almost as low as where it was during the crisis in 2008, 2009. I mean, obviously there’s something going wrong with the formula that you’re currently going on with. I mean, seriously, is there any other plan going forward?

[Dana Coffield:]

Well, we can’t change reality. We’re in Colombia and Peru, and oil prices are what they are. We plan to execute on our [unintelligible]. So we’re not going to reallocate capital to Eagle Ford Shale and we’re not going to change industries.

[Operator:]

Gentlemen, there are no further questions at this time. Please continue.

[Dana Coffield:]

All right. Well, gentlemen, I’d like to thank everyone for your time, for joining us today. And we look forward to speaking with you next quarter and more importantly, we look forward to updating you on our [unintelligible] in the coming month to two months. Thank you.