Gran Tierra Energy Inc (GTE) 2017 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy's Conference Call for Fourth Quarter and Year-End 2017 results. My name is Bruce, and I will be your coordinator for today. (Operator Instructions) I would like to remind everyone that this conference call is being webcast and recorded today, Wednesday February 28, 2018, at 11:00 a.m. Eastern Time.

Today's discussion may include certain forward-looking information, oil and gas information and non-GAAP financial measures. Please refer to the earnings and operational update press release we issued yesterday for important disclaimers with regard to this information and reconciliation of any non-GAAP measures discussed on today's call.

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 call over to Gary Guidry, President and Chief Executive Officer of Gran Tierra. Mr. Guidry, Please go ahead.

Thank you, operator. Good morning, and welcome to Gran Tierra's Fourth Quarter and Year-End 2017 Results Conference Call. My name is Gary Guidry, Gran Tierra's CEO, and with me today are Ryan Ellson, our Chief Financial Officer; and Rodger Trimble, our Vice President Investor Relations.

We issued a press release yesterday that included detailed financial and operational information on the fourth quarter and year-end 2017 results. In addition, Gran Tierra's Energy's 2017 annual report on Form 10-K has been filed on EDGAR and is available on our website at grantierra.com.

Ryan, Rodger and I will make a few brief comments, and then we will open the line for questions.

After successfully transforming our portfolio in 2015, 2016, our focus on execution in 2017 delivered strong financial performance. Our Colombia value-focused strategy with emphasis on profitable production growth has generated great results. In 2017, our Colombia only average production was up 20% relative to 2016, and 21% on a per share basis, mostly achieved through the drill bit.

In the fourth quarter of 2017, we reached an all-time high for Gran Tierra of approximately 34,500 barrels of oil equivalent per day, 53% higher than Q2 2015, when we refocused the company's strategy.

In 2017, our net loss was dramatically lowered to $32 million, down 93% from 2016, while our funds flow from operations more than doubled to $220 million compared to $105 million in 2016. Our impressive 2017 growth in the funds flow from operations greatly exceeded the 24% increase in Brent oil price in 2017. And is a strong indicator of our sharp focus on controlling our cost structure and optimizing oil marketing strategies.

Ryan, will now summarize key developments, milestones and financial results for the quarter and the year.

Good morning, everyone. In Q4 2017, funds flow was up 25% from Q3 to $69 million or $276 million on an annualized basis. Gran Tierra had an active Q4 with a capital investment of $75 million, which exceeded our funds flow by $6 million, primarily as a result of accelerated Acordionero production facilities. Oil and gas sales increased to $422 million in 2017, up 46% in 2016. And in Q4 were a $127 million, up 23% from Q3. We've continued to have top quartile performance in 2017 relative to our oil rated peers in terms of operating netback on a working interest sales basis, which increased 47% with -- from 2016, and in Q4 grew by 22% to approximately $29 per BOE relative to Q3. These increases greatly exceeded the rise in Brent oil price. Creation of a long-term stakeholder value is at the center of everything we do at Gran Tierra, which we believe is achieved by focusing on capital efficiency and return on invested capital.

As we reported a month ago, during 2017, our robust portfolio delivered proven plus probable growth of 18% reserves, 20% in reserves per share, 27% in total NPV to $2.5 billion and 30% in NAV per share to approximately $5.69 per share, all in US dollars. Our high-quality set of assets is now forecasted to achieve production of approximately 50,000 BOE per day by 2020 based on the 2P forecast from our independent reserve report.

With our large resource base, we plan to drill 30 to 35 exploration wells over the next 3 years, which are expected to be funded by funds flow. This exploration campaign is designed to test the vast majority of our world-class portfolio of unrisked mean prospective resources of 1.5 billion

BOE. Including our dominant position in the Putumayo Basin oil play fairways of the A-Limestone, other carbonates and N sands. A big part of our successful transformation of Gran Tierra was our strategic acquisition of PetroLatina in mid-2016. As you know, we paid $525 million for PetroLatina, whose major asset was in the Middle Magdalena Valley, the Acordionero oil field. At the time of acquisition, there were some external doubts on the value that we paid, however, the results have been spectacular to date. A downturn allows the company to acquire top-tier assets that normally wouldn't be available, or if available, at substantially higher prices.

I'll now give a brief overview of our significant achievements with this acquisition. In the 18 months that Gran Tierra has owned and operated these assets, the results have been stellar and represent some of our most significant operational highlights. During this time, we have more than tripled Acordionero's production to roughly 16,500 BOE per day, by drilling and bringing on 11 oil wells, 2 water ejectors and 1 water source well, and have increased our total Middle Mag production to approximately 17,200 BOE per day. Over the same time period, we have added close to $27 million BOE of 2P reserves, within 2P, NPV discounted 10% has grown to $1.6 billion or triple the value of their original acquisition cost. Acordionero and the other Middle Mag assets have been a cash flow engine, as well generate oil and gas sales of $172 million, and operating netback of $127 million since acquisition, more than covering our $105 million of capital investment in the Middle Mag during this time, and we're far from finished. In our full 2P development plan, we still have another 11 oil wells, 4 water ejectors and another water source well to drill. To recap, we've tripled production from the PetroLatina assets, while generating positive free cash flow, and the 2P, NPV is 3x of what we paid for the assets.

I'll now briefly touch on some highlights from our 2018 budget. As we disclosed in December 2017, our 2018 production guidance is in the range of 36,500 to 38,500 BOE per day, which represents year-on-year growth of 16% to 23% over 2017 Colombia only production before royalties. Based on results so far in 2010, we're on track to achieve this target with current production of approximately 35,500 BOE per day. This strong profitable production growth is forecasted to be delivered by our 2018 development capital program of approximately $160 million, with the majority drafted at Acordionero's ongoing development, where we plan to drill a total of 12 wells and to expand the central processing facility. Approximately 60% of our 2018 cash flow will be dedicated to development activities. Elsewhere in our portfolio, we plan to drill 7 to 9 development wells in the Putumayo Basin and some of our minor fields.

Our 2018 exploration program of 8 to 11 wells and new 3D seismic calls for investments of approximately $100 million, which will represent approximately 40% of our total 2018 capital expenditures of $260 million. The majority of our 2018 exploration campaign is once again planned to be focused on the Putumayo Basin, where we forecast drilling 5 to 6 wells, which are designed to test both the A-Limestone and N sand's oil place.

At a budgeted 2018 Brent price of $57 per barrel, we forecast midpoint annual funds flow of approximately $275 million, which will more than cover our 2018 capital program of roughly $260 million. At $57 Brent, our forecasted EBITDA is expected to be $320 million to $340 million.

Subsequent to 2017 year-end, we believe the market delivered a strong vote of confidence in our Colombia-focused long-term strategy as evidenced by a successful offering of $300 million in 6.25% senior notes with a 7-year term. After paying down our revolving credit facility and placing the excess cash in our balance sheet, we now have pro forma cash of $153 million and net debt of $272 million at December 31, 2017, which represents low leverage of roughly 1x debt to annual, annualized Q4 2017 cash flow.

In addition, our $300 million credit facility is undrawn and available, providing us with substantial liquidity. We believe our bond issue improved our financial flexibility and left us in a strong liquidity position, such as Gran Tierra is well positioned to potentially accelerate current development projects such as Acordionero or future exploration discoveries in the Putumayo and Middle Mag Basins.

I'll now turn the call over to Rodger Trimble, Vice President Investor Relations to discuss some of the highlights of our 2017 operations and potential upcoming capitalist(inaudible) in 2018.

Good morning. I'll briefly mention some other key operational highlights during 2017 and into 2018. The Vonu-1 well of the Put-1 block, where we have an operated 55% working interest continues to be our star performer in the A-Limestone. On a 100% gross basis, it has produced at an average rate of 1,974 barrels of oil per day since October 1, 2017, with only modest natural decline observed so far. Since starting production in July 2017, Vonu-1 has produced a total of 415,000 barrels of oil with essentially no water. Close the act of '19, the first vertical well that we completed in the A-Limestone in September 2016 has produced a total of 537,000 barrels of oil with virtually no water and has averaged roughly 690 barrels of oil per day since October 1, 2017.

In total, on a 100% gross basis, Gran Tierra has produced 1.4 million barrels of oil from the A-Limestone to date, all at less than 1% water cuts. The Costayaco-30 vertical well, which targeted the A-Limestone, yielded encouraging results after the initial completion. However, after simulation, pressure analysis indicates that the completion fluids damage the formation. We are working to redesign and optimize the completion fluids, which should then be more compatible with the A-Limestone. We have brought the completion rig back to Costayaco-30 to restimulate the well with the optimized completion fluids and to recommence production testing. We plan to apply our learnings at Costayaco-30 to the Siriri-1 exploration well on the Put-4 block.

And to future wells in the A-Limestone. At Siriri-1, during December 2017, we perforated and stimulated 15 feet out of 70 feet of oil pay in the A-Limestone. And the oil gradient was measured in the well board using wireline pressure gauges and samples of 29-degree API oil were recovered. Also, fingerprint analysis suggests that the oil is from the similar source as the Vonu-1 well. Siriri is currently shut in with the static wellhead pressure of 1,720 pounds per square inch. And the potential for further stimulation of the A-Limestone is currently being studied. Shallower, potential net oil pay has been identified in this well, and the M2 Limestone, the N Sand and Upper Pepino Sand. And we plan to test the N Sand after full assessment of after the A-Limestone is completed.

At this point in time, our new A-Limestone conventional oil resource player is still in its infancy and is barely more than a year old. As with other resource plays around the world, it will take time to optimize drilling and completion techniques to maximize recoveries and achieve the best economics. We remain very encouraged about the massive prospectivity of this play as indicated by the more than 800 million BOEs of mean, unrisked perspective resources assigned by McDaniel at 2017 year-end all to the A-Limestone. And we look forward to many more years of drilling in this exciting new play in the Putumayo basin. Some upcoming analyst -- catalysts, sorry, in 2018 that might result from our active 2018 exploration program, could be as follows: first, we have drilled the IM barrel one, and are currently drilling the Putumayo-1 exploration wells in the Middle Mag Basin. The IM barrel well is designed to test the LaLuna carbonate formation, while the Putumayo well is targeting the same Lisama Sand as we produced from in Acordionero, but in a separate structure. Testing of these wells could take several weeks. It's worth mentioning that we've seen encouraging signs of oil during the drilling of IM barrel one and from the log analysis of that well; second, we plan to drill 3 exploration wells in the PUT-7 block down in the Putumayo Basin. The Pecari, Pomorroso and Northwest wells are all designed to test both the N Sand and the A-Limestone as well as other perspective carbonate formations; third, is worth mentioning briefly on the development side, we plan to drill 2 development oil wells in PUT-7 in the Cumplidor Confianza field starting in late Q1; forth, back to our exploration program, we're also excited at the prospect of drilling several other A-Limestone and N Sand exploration wells in the Putumayo during 2018. For example, the Colibri well on Put-4, the Chilanguita well on Alea 1848-A, and the Comadreja well on PUT-2. Our A-Limestone conventional resource play represents 56% of our total mean unrisked prospective resources of 1.5 billion BOEs. So our 2018 exploration drilling is very much focused on assessing this massive resource base.

I will now turn the call back to the operator, and Gary, Ryan and I will be happy to take questions. Operator, please go ahead.

(Operator Instructions) And our first question comes from the line of [Leonardo Maqunez] from UBS.

My first question is regarding our 2018 prediction guidance. How many extra wells do you consider being in this guidance compared to last year? And I see as the Brent at $57 per barrel, but with the oil at current level, could we expect a more aggressive number?

Yes, the expected development wells. Our total development wells are 19 to 21 gross wells, where most of that is focused in the Acordionero Field. And with respect to change -- increase our capital program, at this point, we don't intend to increase our capital program.

And our next question comes from the line of Adam Naughton from RBC Capital Markets.

Just a quick question for me on (inaudible) and when can we expect results from the well? Just to confirm, should we expect a result from IM barrel and sometime next month?

I think the answer on IM barrel is, yes. We expect to have test results in the next month or so. We have tested the lowermost zone. We have 2 more zones to test. On (inaudible), we're in the process of trying to log the well. We expect to have logs, and we'll make a decision on what we see from those logs. So again, over the next 4 weeks or so we should have some results on that.

And our next question comes from the line of Josef Schachter from Schachter Energy Research.

First question, I've got a few. Given the success of Vonu-1, is there plans for development locations in the latter part of this year to follow up to see how good the discovery is?

The quick answer to that, Josef, is land access. We're working on land access on the block. The Vonu-1 well was actually drilled from the Chaza Block directionally. We do have the capability of potentially drilling 1 or 2 more wells from the Chaza Block. Our preference is to get -- direct to get land access on the block itself. It makes things a lot simpler to drill the well, and also to ultimately produce the well. And so the answer is, land access, we think, within the next 12 months, we will have that. And we're geared up to start appraising and developing the Vonu field. It looks quite exciting to us.

Second question. Given that the you have that $150 million of cash, and given the presentation Ryan made about cash flow and Capex for the year, is there a potential for some acquisitions in 2018? Are there some things potentially coming on the horizon that you wanted to have a cash war chest or something like that?

I think we -- the answer is, we always look for opportunity. We don't necessarily need anything. We're very opportunity rich, 1.5 billion barrels of mean perspective unrisked resources. So we have lots to do, highly economic. And so we're quite disciplined in what we do look at. Having said that, we always look at upgrading our portfolio. We also look at joint ventures. Echo Petrol have announced several times that they may consider joint ventures in the Magdalena Valley and elsewhere in Columbia. We don't control that base. And then finally, over the last couple of years, we've been quite disciplined at looking at opportunities in Mexico. We continue to do that. We're quite encouraged by the joint venture approach that the Pentax (inaudible) have taken in the last round that we participated in. And economically, we see that at least what we bid on competes with Colombia.

Okay. Last question for me. There's been some articles in The Economist Magazine about national liberation army, the ELN, and also the massive influx of civilians from Venezuela into Colombia over 0.5 million in February 17 article. Does that affect your Juan basin with the massive immigration from Venezuela or the ELN affecting anything in the San Juan basin?

The immigration, crossing the border does not impact the operations that we have ongoing. We're continually looking at ways that we can help, whether that problem through the Colombian government. And -- but overall, it does not impact us. The ELN have been quite active in the country. Have not directly impacted our operations. They've been active in the Magdalena Valley on infrastructure, causing damage to infrastructure, which is logistically made us -- make alternative routes to get to market with our oil, but there's lots of infrastructure in the country. And overall, it’s not impacted us, but they have been active in the area of our Magdalena operations.

Have you changed the security procedures or done anything there to keep your people safe because of that? As that increased your cost structure.

Yes, we are always on alert being in remote locations. We are in continuous communication with the police and the military in the country, who are managing what's going on with the ELN. But I would say, Josef, that in general, our alert is always high being in remote locations.

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

Thank you, operator. Once again, I would like to thank everyone for joining us today. We look forward to speaking with you over the next quarter and update you on our ongoing progress. Thank you.

Ladies and gentlemen, thank you for your participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a great day.