Gran Tierra Energy Inc.
Q4 2015 Earnings Call Transcript

Published: 29 Feb 2016

[Operator:]

Good day, ladies and gentlemen, and welcome to Gran Tierra Energy's Results Conference Call for the Fourth Quarter 2015. My name is Melanie and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the initial remarks, 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 Monday, February 29, 2016 at 11

[Gary S. Guidry:]

Thank you. Good morning and welcome to Gran Tierra's fourth quarter and year-end 2015 results conference call. My name is Gary Guidry, Gran Tierra's President and Chief Executive Officer and with me today is Ryan Ellson, our Chief Financial Officer. Earlier today, we issued a press release that included detailed financial information about our fourth quarter and year-end 2015 results. In addition, Gran Tierra Energy's 2015 annual report on Form 10-K has been filed on EDGAR and is available on our website, grantierra.com. I'm going to begin today by talking about some of the key developments for the quarter and the year. Ryan will then take a few minutes to discuss key aspects of this year's financial results. We will then open the line to questions. 2015 was a transformation year for Gran Tierra, with the appointment of new management and the Board of Directors in May 2015 the company began its transition to a Columbia concentrated exploration and production company focused on disciplined capital allocation and net asset value per share growth. We are committed to being a low cost operator that is not merely trying to survive in the current environment rather to thrive and position the company for growth in 2016 and beyond. We have significantly driven down costs both in operating and general and administrative expenses. Equally important, we have reduced the time to drill Moqueta and Costayaco wells by approximately 40% to 50%. These drilling efficiencies will become evident as we start to execute on our extensive exploration portfolio over the next couple of years. We continue to focus on our organic growth through exploration and discipline on accessing new business development opportunities. We have been successful on the acquisition front having recently closed two highly strategic acquisitions of Petroamerica and PetroGranada in January 2016, which increased our risked prospective resource by approximately 50%. Overall, 2015 was a strong year for Gran Tierra amidst the difficult oil price environment. Low declines and the low cost structure at our two core conventional operated oil fields Costayaco and Moqueta highlight the strength of our operating base and assets through a competitive advantage of our operating team in Colombia. We expect that both fields will be fully developed in the first half of 2016 and will provide significant free cash flow in 2017 and beyond. At December 31, 2015, these fields made up 75% or 49.6 million barrels of oil equivalent of our proved plus probable working interest reserve and proved developed reserves comprising 48% of these 2P reserves. With $97 million of working capital remaining after the acquisitions of Petroamerica and PetroGranada, an undrawn $200 million credit facility and cash flows from operations, we believe that Gran Tierra can emerge from this low price environment as one of the strongest exploration and production companies in Colombia. Annual production for 2015 averaged 23,401 company interest barrels of oil equivalent per day before royalties or 19,400 barrels of oil equivalent per day after royalties. This was at the upper end of our production guidance, 22,500 to 23,500 barrels of oil equivalent per day announced June 24, 2015. The company drilled eight gross wells in Colombia in 2015 with 88% success. Base maintenance and development capital in 2016 is forecasted to be $107 million with $50 million allocated to the maintenance of the Costayaco and Moqueta fields. We've planned to drill two water injection wells at Costayaco and three development wells in Moqueta field. Completion of this program in 2016 will conclude the major capital spending portion of the field development plans for these two fields after which point they will generate free cash flow and require a minimal maintenance spend. In total, our base capital work program includes a drilling of six development wells and three exploration wells in 2016. 2016 average working interest production for the company's asset base in Colombia and Brazil is expected to be approximately 27,500 to 29,000 barrels of oil equivalent per day representing an increase of about 20% over Gran Tierra's 2015 average production of 23,400 barrels of oil equivalent per day. 2016 production guidance includes about a 1,000 barrels a day of production from the company's assets in Brazil and 2,500 to 3,000 barrels of oil per day from our two recent acquisitions in Colombia. As of 2015 year-end on a pro forma combined basis, working interest proved reserves would be 53 million barrels of oil equivalent or working interest proved plus probable reserves of 76 million barrels of oil equivalent including the reserves acquired through acquisitions of Petroamerica and PetroGranada. Proved developed producing reserves represents 73% of total proven and 51% of proven plus probable reserves. Internally, we have high graded our exploration portfolio and are now carrying total working interest unrisked mean perspective resource of 682 million barrels of oil equivalent and a risk mean perspective resource of a 178 million barrels of oil equivalent. The risk prospective resources are two times our current reserve base providing potential material growth over the next two to three years. We remain very excited about the N Sands play and the Putumayo basin. Both 2D and 3D seismic reflected at identifying the N Sands potential and there is excellent correlation between the seismic amplitude and net sand thickness as proven by multiple discoveries including the [indiscernible] deals. The ability to predict sand thickness through seismic allows Gran Tierra high graded sweet spots and correctly position exploration and development pads reducing costs and earn environmental footprint. Knowing where the reservoir is derisk the later development. The Putumayo, N Sands is under explored with prospect seismics being more than two to three times those remaining in the Llanos Basin. With our land position and the ability to identify where the N Sands’ potential lies we are able to plan larger cycle developments and positive social and economic benefits to the region. As of December 31, 2015 our estimated pro forma before tax net asset value per share after the Petroamerica and PetroGranada acquisitions now stands at US$4.49 per share and $3.03 per share on an after tax basis using NI 51-101 and COGEH compliant 2P discounted reserves at 10%. Lastly, the company continues the evaluation of all alternatives to maximize value in both Peru and Brazil. The company has significantly reduced the general and administrative costs in both countries. I will now the call over to Ryan Ellson, Chief Financial Officer who will discuss the key aspects of this quarter's financial results.

[Ryan Ellson:]

Good morning. Overall, Gran Tierra had a strong fourth quarter, the focus in Q4 was on the ongoing execution of our increased capital program announced in Q2 2015, improving our cost structure and ensuring capital discipline to protect our balance sheet and the negotiation of the two strategic acquisitions of Petroamerica and PetroGranada, which both closed in January 2016. Overall, our 2015 capital program came in ahead of schedule and under budget, which is a positive indication that our efforts to reduce cost and improve capital discipline have been successful to-date. Much of the capital program was executed in Q4 2015, we will continue our efforts to grind down both capital and operation costs throughout 2016. We believe that the acquisitions of Petroamerica and PetroGranada are highly strategic and will strengthen our position as the premier operator and land holder in the Putumayo basin. The acquired undeveloped land holdings and exploration development portfolios are complementary to Gran Tierra's own exploration portfolio, strong cash flow, reserves base and balance sheet strength. Highlights of our acquisitions are, the net consideration was $89.4 million after given consideration to the estimated networking capital, for us that's was at 2P NI 51-101 compliant reserves NPV before tax of $131 million and $108.5 million after tax. The working interest 2P NI 51-101compliant reserves were 10.3 million BOE at December 31, 2015. This results in consideration paid of $8.71 per 2P BOE of oil reserves. Whilst we only paid $8.71 per barrel, the primary reason for doing the acquisition was a increased unrisked mean perspective resources by a 180.6 million BOE, 59.2 million BOE risk. Post acquisitions Gran Tierra remains debt free with pro forma working capital of approximately $97 million. We have said this before, but it is worth repeating, we continue to aggressively and systematically review acquisition opportunities. However, we continue to maintain our long-term view that any acquisition must offer compelling value and be a strategic fit for the company. With the persistent low oil prices, we continue to see more and more opportunities. However, we will continue to remain disciplined. We communicated that we were going to bid on blocks offered in around 1.3 in Mexico onshore bid round, but our bid would reflect our commitment to capital discipline and we would not enter Mexico at any cost. At Gran Tierra, we do not believe in loss leaders. Whilst we were not successful in capturing in the block, hopefully it demonstrates to our shareholders our commitment to capital discipline and our returns focused business model. Our credit facility is $200 million which is with a very strong syndicate of banks remains undrawn and will provide us with liquidity in the future if and when needed to provide growth in Colombia. During the quarter, we repurchased Gran Tierra shares pursuant to a normal course issuer bid. In total, the company repurchased 1.6 million shares during Q4 and 4.6 million shares in all 2015, an average price of $2.19 per share for total consideration of $10 million. We believe this is a prudent use of funds and we still have ample liquidity to pursue accretive opportunities. Financially, here are some of the highlights from Q4 2015. Average unit production in Q4 was on target at 23,138 BOE per day. On a gross work interest basis, which is a decrease of 1% from Q3 2015 due to latter than anticipated starts of the drilling program. After deduction of royalties, NAR, average daily production in Q4 2015 increased 1% from Q3 2015. Sales volume for Q4 2015, were 17,034 BOE per day, a 21% decrease in Q3 2015. As you will recall Q3 2015 sales volumes were greater than NAR volumes, greater than average daily production due to the buildup in inventory at June 30, 2015, which was subsequently sold in Q3, 2015. Sales volumes for Q4 2015, were 2,707 BOE per day lower than NAR average unit production due to the timing of oil sales. The realized price received in Q4 2015 on a NAR basis was 8% lower commensurate with the drop in oil price in Q4. Operating transportation costs on a NAR basis in Q4 were consistent with Q3 2015. The operating netback for the Q4 2015 was $18.07 per BOE, a decrease of 14% from $21.07 per BOE in Q3 2015. A 13% drop in the price of Brent, the major contributing factor in the decreased operating netbacks. At a Brent pricing of $52.35 per barrel, which we saw in 2015, our full-year 2015 operation netback was $24.04 per BOE and this drove strong funds flow and recycle ratio. General and administration costs on a working interest basis, was $3.24 per BOE, an 11% reduction from $3.60 per BOE on a work interest basis from Q3 2015. In absolute terms, G&A costs have decreased from $7.9 million in Q3 2015 to $6.9 million in Q4 2015 representing a 12% reduction. Since Q1 2015 the company has engaged in significant cost reduction strategy. The company has reduced G&A per BOE by 36% compared to Q4 2014 on a work interest basis. In absolute terms G&A costs have decreased from $11.1 million in Q4 2014 to $6.9 million in Q4 2015 representing a 38% reduction. Funds flow from continuing operations decreased to $16.9 million in Q4 2015 from $36.6 million in Q3 2015 with the main contributor being the drop in oil prices and lower sales volumes. Funds flow from continuing operations for 2015 was a $108 million which is consistent with the guidance provided by the company. The net loss in Q4 2015 was $82.7 million compared to a net loss of $101.9 million in Q3 2015. The current quarter’s loss primarily the result of additional $106.6 million of non-cash asset rate downs, the result of continuing weakness in global oil prices. Capital expenditures for Q4 were $42.9 million and in line with our forecast, 92% of the capital spent in Q4 was directed to Columbian operations compared to 77% in Q3 in 2015. In the second half of 2015 the company spent $67.4 million on capital expenditures with 86% directed to the Columbian operations. The company's finding and development costs or F&D costs on a proven basis was $3.20 per barrel and negative $0.87 on a 2P basis. And these F&D costs includes a $50.4 million spent improved, $44.9 million spent which was spent in the first half of the year before appointment of new management team and Board. The negative F&D costs are result of our capital expenditures being less than our change in future development costs. The change in future development costs are primarily due to capital spent in 2015, more attractive field development plan and reduced well costs. The company maintains a strong balance sheet with cash and cash equivalents of a $145.3 million and working capital including cash and cash equivalents of a $160.4 million as of December 31. Pro forma working capital net of cash paid for the Petroamerica and PetroGranada acquisitions, which closed in January 2016 remains robust at approximately $97 million. The company remains debt free with undrawn credit facility. Based on strip pricing, Brent of approximately $35 for 2016, the company generates approximately $60 million in funds flow. In that pricing environment, the company is proceeding with its base capital program of approximately $107 million. At $35 Brent, the company anticipates further deflation in the industry and would be able to conclude the program for $95 million to a $100 million. In that scenario we would still exit the year with working capital of $50 million to $60 million and zero debt. We believe this separates us from most of our peers in Columbia, internationally and even in North America. In summary, whilst it is a difficult time in the industry as a whole, Gran Tierra remains in excellent shape to grow during these challenging times. With respect to the arbitration there is nothing new to report and we expect the resolution in the second and third quarter of 2016. I will now turn the call back over to Gary.

[Gary S. Guidry:]

Thank you, Ryan. As mentioned, we have seen strong results at both Moqueta and Costayaco fields during 2015, despite the challenging oil price environment. Ryan summarized the strong financial position of the company. We are also successfully executing our strategy refocusing the company on the expansion and diversification of our asset base in all of the productive basins in Colombia. Although we were not successful in December 2015 Mexico onshore bid round, we believe that Mexico is an ideal platform to create value and will continue to monitor future opportunities on the ground in Mexico City. Now, I'll turn the call back over to the operator, and Ryan and I'll be happy to take questions. Melanie, please go ahead.

[Operator:]

Thank you. Ladies and gentlemen we will now conduct a question-and-answer session for Securities' Analyst [Operator Instructions] One moment please for your first question. The first question is from Nathan Piper of RBC Capital Markets. Please go ahead.

[Nathan Piper:]

Good morning guys. Two questions from me, you have partially answered the first one, which is great, but what I want to understand is what oil price do you need looking at that cost deflation that you talked about to and embark upon your broader program for 2016 to sort of go for some of discretionary capital that you talked about. Just be interesting to see what oil prices make you more confident to invest more money?

[Gary S. Guidry:]

What was the first part of the question Nathan? We got the oil price for the discretionary program. What was the first part?

[Nathan Piper:]

That's actually is the first part.

[Ryan Ellson:]

I think we answered this first part okay. I think Nathan, the luster that we have is, we operate all of our production and most of our capital program, so we have a lot of flexibility, but I would say that you would see acceleration anywhere around, anything north for $45.

[Nathan Piper:]

Okay, and so $45 you would tackle the rest of the discretionary capital plan or is there a bit of a kind of ratchet?

[Ryan Ellson:]

It would be a ratchet, right, it would be safe to assume that over $50 we would proceed with that entire program.

[Nathan Piper:]

Understood and just on cost deflation which is my first question Gary. Could you give us a bit of color as to where do you think cost could go to if $30 or $40 a barrel persists for quite some time. So do you think there is significant cost savings to be made on the OpEx side as well as CapEx side through this year or how the easy wins already be made?

[Gary S. Guidry:]

Well, the early wins have been made for sure and a big part of our reduction in capital cost for drilling has been internal efficiencies, the way in which we are doing things and there is probably some more of that improvement to occur. I think the second part is the deflection of cost if low oil prices continue might be on the order of 10%.

[Nathan Piper:]

Okay that’s clear and my final question if I may, just on the OTA pipeline, I mean you have done a tremendous job despite the OTA pipeline this year, which was as you had mentioned for over 200 days. What is the long-term solution do you think in Southern Columbia, if your production volumes begin to increase, I mean if you maybe get 25,000 barrels a day away at the moment, but if that was to become 35 or 40 with exploration success and so on, what are you thinking of in terms of contingencies in the future?

[Gary S. Guidry:]

We are looking at infrastructure in a couple of regards and we do just from what we have seen of the N Sands, we are pretty highly confident, it’s a matter of degree of success and so we are looking at both the Northern routes where we tend to truck oil in times where the OTA is down, the OTA itself of course. And then looking south from the Putumayo-7 and Suroriente block looking at its southern explore routes. So our plan is to continue to have multiple ways to export and transport crude oil including when natural disasters occur, the delta I think part of the reason, Ryan was describing our need to truck more oil during the last year and that was due to a natural disaster, a landslide. So you are always going to have things occur. I think the other part of the focus Nathan is that we're not just focusing on reducing transport costs, we have a very good team working with Ryan on the marketing side as well to make sure we get the premium for our light sweet crude oil as well and we've had some real progress there.

[Nathan Piper:]

Great. So, you don't see an upper limit to current transport solutions that you've got?

[Gary S. Guidry:]

No, we do not.

[Nathan Piper:]

Thank you.

[Operator:]

Thank you. The second question is from Ian Macqueen of Paradigm Capital. Please go ahead.

[Ian Macqueen:]

Good morning guys. You have done a good job on the arbitration, describing what has happened on the arbitration, but there is a very significant difference between the way the ANH is calculating what is odd and high price royalties at $92.8 million and you at $44.8 million. So first of all I think it's taken a long time to go through these and you are not the only one that are subject to, there is just no high price royalty disputes. Can you explain a little bit more about the process and why there is such a significant difference between the way you view it, the ANH views it and how confident you're about timing and the outcome?

[Ryan Ellson:]

One of the things is there is really two components of ANH driver, is just as you know when should HPR start to be calculated and our position is that it is after 5 million barrels has reached in the [Canada] (Ph) and we started paying the HPR once Moqueta reached to 5 million. The second big component is what are the interest in penalties calculated at, is at peso denominated contract and that would LIBOR plus 20% or the U.S. dollar denominated contract which would be closer to 4%, as they get the big difference in the calculation.

[Ian Macqueen:]

So, did they started day one basically saying you should owe high price royalties as of day one, you started I think April 30 of 2015 that's a fairly significant number, if that's the difference?

[Ryan Ellson:]

That's the difference, is when Moqueta reached the 5 million barrels, the ANH position was from barrel one high price royalties should be paid.

[Ian Macqueen:]

Right and you have been paying high price royalties from the 5 million barrel point, so the difference really is whether you start from zero, whether you start from 5 million barrels?

[Ryan Ellson:]

Right and what interest rate do you use whether its 4% to 20%.

[Ian Macqueen:]

I don't believe there's a precedent yet on this as to how the ANH is going to treat this. I mean as I said, you are not the only ones that are subject to this, to the arbitrations, but we just haven't seen an outcome and just it seems there is a substantial difference in all cases, there isn't a precedent yet, is there?

[Ryan Ellson:]

No, not that we are aware of, and in each case, if you look at each case separately because as you know one there is both the geological differences but also the contract difference in each case as well.

[Ian Macqueen:]

Right. And lastly, how confident are you that it’s going to actually be - so there is going to be a conclusion to the arbitration in either 2Q or Q3?

[Ryan Ellson:]

We're confident that we will have the resolution in Q2 or Q3 of this year.

[Ian Macqueen:]

Okay, good. Thanks guys.

[Ryan Ellson:]

Thanks Ian.

[Operator:]

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

[Gary S. Guidry:]

Thank you, Melanie. In conclusion, I would like to again thank everyone for joining us today. We look forward to speaking with you in the next quarter and update you on our ongoing progress. Thank you very much.

[Operator:]

Thank you. The conference has now ended. Please disconnect your lines at this time. We thank you for your participation.