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Good morning, everyone, and welcome to Parex Resources Fourth Quarter Earnings Call and Webcast. Yesterday, Parex released its audited financial and operating results for the quarter and year ended December 31, 2018. Like all Parex disclosure documents, the complete financial statements and related MD&A are available on the company's website at www.parexresources.com and on SEDAR.Before turning the meeting over to Mr. Dave Taylor, President and CEO of Parex Resources Inc., I would like to mention that this call is being recorded. So it will be available for playback on the company's website. Parex would like to remind everyone that remarks made during the sessions are subject to forward-looking statements, which involve significant risk factors and assumptions and have been fully described in the company's continuous disclosure reports. The information discussed is made of today's date and time, and Parex assumes no obligation to update or revise this information to reflect new events or circumstances, expect as required by law. [Operator Instructions] I would now like to turn the meeting over to Parex President and CEO. Please go ahead, Mr. Taylor.
Thank you, operator, and thanks to everyone for joining our Q4 conference call and for all your support of Parex. With me today in the meeting are Ken Pinsky, Chief Financial Officer; Eric Furlan, Chief Operating Officer; Ryan Fowler, Senior VP, Exploration & Business Development; and Mike Kruchten, Senior VP, Capital Markets & Corporate Planning.Before we start our Q&A session, I'd like to provide a brief overview to our shareholders on our financial results for the year ended 2018. I'll also provide an operating update, discuss the 2019 guidance and outline future potential growth areas.I'd like to begin by saying that we're very happy with the underlying fundamental strength of our business in Colombia. Our core Southern Casanare oilfields, the SoCa assets continue to grow in both reserves and production and are delivering significant free cash flow.In 2018, the company delivered record funds flow from operations of USD 383 million against the capital program of USD 302 million. This includes annual free cash flow of USD 81 million, surpassing the significant production milestone of 50,000 barrels of oil per day; year-over-year oil production growth of 25%; increasing our underlying value, as measured by our independently audited reserves, the highlights from that include proven reserves year-over-year volume increase of 27%, proved plus probable year-over-year volume increase of 14%. Our FD&A cost on a proved reserves basis was $7.04 a boe and that includes FDC cost, giving us recycle ratio of 4.5x. Repurchase of over 2.75 million shares, adding new inventory to our portfolio with a farm-in of the Llanos Basin CPO-11 block and the acquisition of the Fortuna block in the Middle Magdalena Basin, and maintaining a debt-free balance sheet with year-end working capital of $219 million, which provides multiple options for us to grow our business in 2019. I'd like to give a brief operational update and highlight some of the key projects where we're making significant progress. We continue to be active on our core Southern Casanare assets, that's Block 34, 32 and Cabrestero, where 3 drilling rigs are currently operating. We have approximately 21 wells planned for these assets in 2019.In this area, a flow line from Block 34 into the key Colombian export pipeline system is expected to be commissioned in April and is a major step in reducing our transportation footprint and securing our takeaway capacity. We've had excellent exploration success at Capachos, which is in a difficult but opportunity-rich operating area. We've been able to demonstrate our operational strengths here, where we are producing and selling light crude oil and have drilled a successful multizone exploration well at Andina in 2018. Currently, the Andina Norte exploration well, which is targeting a new undrilled compartment, is drilling ahead at approximately 16,000 feet. We're planning to set the next string of intermediate casing in the next few days prior to approaching the target objectives. We expect to have results during April of 2019. We're also preparing to start our other drilling programs targeting growth opportunities in the Middle and Lower Mag basins at Aguas Blancas, Fortuna, Playon, De Mares and VIM-1 and in the Llanos Basin on CPO-11.As previously released, we expect the 2019 capital expenditures to be fully funded by funds flow from operations with working capital being retained, traditional growth opportunities and to buyback outstanding shares as deemed appropriate. Our 2019 guidance is highlighted by 20% year-over-year production growth, targeting 52,000 to 54,000 barrels of oil per day and generating approximately $450 million to $500 million in cash flow at $60 Brent prices. Our CapEx program is estimated at $200 million to $230 million, evenly split by development, appraisal and exploration categories, including funding for new projects that we have in our business development hopper. The budget plan generates a record amount of free cash flow, likely higher than $250 million. And our expected debt-adjusted per share growth rate will likely be industry-leading. We have tremendous optionality to allow us to invest in additional growth opportunities and return cash to our shareholders. And I'm pleased to announce that in our current NCIB program, initiated on December 21, 2018, we have purchased for cancellation over 5.5 million shares and returned over CAD 100 million, which is significant progress in achieving our 2019 target of repurchasing 10% of our float.With this brief introduction, I'd like to turn the line back to the operator to start the Q&A session. Operator, over to you.
[Operator Instructions] The first question is from Adam Naughton from RBC Capital Markets.
Firstly, on CapEx of $300 million for last year, I believe this is below guidance. Was there a delayed drilling or was there significant cost savings? And secondly, you mentioned the pipeline tie end on Block LLA-34. Do you expect to see any significant cost savings or is that mainly just a reliability and risk management in operation?
Thanks for the questions, it's Ken. With respect to CapEx, $300 million, it's kind of at the low end of our range. Every year, we have some timing issues around the fourth quarter, first quarter, and so no -- nothing was canceled, nothing was really specific that I can put a mind to, but we do typically tend to have some timing issues over the year-end. The question with respect to the pipeline that we expect to have commissioned or the flow line from Block 34 that ties into the Colombian export system. We are not forecasting today any real savings. That was more of an egress option for us. The field there is just getting too large not to have a pipeline connected. We do expect, over time, we'll start to see some savings, and it does reduce our exposure to inflation from increased trucking tariffs over time. So that was really what got us to do it, not instant savings today.
The next question is from Ian Macqueen from Eight Capital.
Just a quick question on Andina Norte. I didn't -- for whatever reason, I had missed the 19,100-foot TD projection on that well. It used to be that 16,000 for Capachos was going to be a challenge for you, but this is obviously a deeper well. I guess structurally, it's just lower. My question really is, in terms of intervals, what's your prognosis for Mirador, Guadalupe and Une and how do you see going that extra basically 300 or 3,000 feet? Is it going to be -- is there significant additional risk with going to 19,100? And can you still get, say, Mirador or Guadalupe zones even if you don't to 19,100?
Okay. Ian, this is Ryan Fowler. First of all, the 19,000 feet is a measure depth here, and this is a long-reach well. So actually our TVD for this is very similar to Andina. And so we still have the option to test all of the zones that were successful at Andina, and we have a plan that's kind of allows us the optionality to go to the deeper target, depending on the results in the shallow targets.
And that -- to get to 19,100 is to the base of the Une, I would assume, or the projected zone in the Une?
Yes, it is. So we would drill through the 3 upper zones there, the Mirador and the 2 Guadalupes, and see what that looks like and see how the wellbore is looking and then make a decision based on what we saw in the shallower, whether we deepen or not. So it's just an option to go deeper.
The next question is from Gavin Wylie from Scotiabank.
Just two quick questions for me. Just one on the Capachos drilling program. There's only one well in the budget this year. Is that the Andina Norte well? And the second question is, if Andina Norte is successful, is there any other follow-up appraisal that you could do in the area or exploration that you could do in the area over the next, say, 12 months, assuming that you probably have to get some additional stuff permitted for that? But just if there's any follow-up that could be put into the 2019 program? Second question, just on the SoCa assets, the 21 wells. Out of that 21, is there a number that you could kind of give us a sense of as to what is being drilled outside of current 2P? That would be great.
Okay. Gavin, it's Eric here. With regards to the Capachos, Andina, we are evaluating what the next steps are in the area for the drilling rig. We've had very good performance in the area. We've got a rig that that's operating very well in the area. So with Andina Norte, the challenge is going to be, this target is a long-reach well and to drill additional follow-ups, we will likely need to build additional surface location, which would push any follow-ups to Andina Norte to the end of 2019 at the earliest. We are currently working our technical models on the existing tools that would be Sur, Central and Andina, things like simulation models to see what is the optimal development. Can we take advantage of the rig in the area at the moment to complete some additional work? So we're in the middle of that work to look at what our final budget may look like. As far as Block 34 and the wells in Block 34, the budget is currently split out between mainly development wells and appraisal wells. So even though we're drilling wells within boundaries of reserves, the critical information that we gather as we start doing development here is what is the rock thickness, what is the reservoir quality, and how does it change. So it is one of our uncertainties still in our reserves reports for these areas. So when you look at the range of reserves from the 1P to the 3P, they're a function of really 3 things: the outline, what's in the outline, and performance and recovery factor. So a lot of the wells we're drilling, although aren't outside of the boundaries, will tell us a lot about the rock boundaries themselves. There are a handful of wells that are still drilling outside of even the 3P boundaries that we are drilling right now in addition to exploration wells in the whole SoCa area.
[Operator Instructions] The next question is from Jenny Xenos from Canaccord Genuity.
I noticed that in Q4, you had a significant increase in transportation costs due to selling oil in cargoes versus at the wellhead. What drove that decision to choose this marketing strategy in particular? Was it to bring down inventory? And why was it done in Q4 when oil prices collapsed? And finally, what should we expect for your marketing strategy in Q1 and for the rest of the year?
Jenny, it's Ken. Timing of cargo exports are a little bit out of our hands and any increase in transportation is offset by a decrease in the differential. Effectively, we are in Brent minus $17, Brent minus $16.50 at the wellhead, which has been pretty constant throughout the year. It's actually Brent minus $15.5 right now because Vasconia has pulled in. But the way the accounting rules have changed on us, you can't just go by transport, you got to put transport in a realized price net of Brent together all the time to see where we're really moving or how our realized price at the wellhead is moving. And it hasn't really moved that much as a percentage of Brent, or the dollar per barrel of Brent. And we will continue to do about 14 or 15 export cargoes in 2019. We think we have the timing down. But every once in a while it's not -- if you miss it out by a week, it becomes January's cargo, not December's cargo. So that's the type of timing we're looking at. We have our oil in the tanks at the export location at Cárdenas and sometimes the ship shows up early, sometimes it shows up late, but it's all within 10 days or 2 weeks. But on a quarter-end basis, it could make a bit of a difference, can't it, because you either have the inventory build or you have a drawdown. So really timing is a little bit out of our control, and you can't read too much into it.
Okay, understood. And I noticed that your commitments over the next 12 months were reduced substantially beyond the level of your capital expenditures in Q4. Could you give us a little bit of color on that? Was it something in particular that you did there that resulted in such a substantial reduction?
It's just our VMM-9 block, as you're aware, it's an unconventional block. And because the unconventional licensing in Colombia is murky right now, it's actually been suspended. And so once it's in suspension, it didn't seem to make any sense to have it in our exploration commitment schedule for something we'd do this year. For instance, we didn't have it in our budget this year because we knew it was in suspension. So we just cleaned up our note disclosure to put it out into the 1- to 3-year category. Arguably, I could have put it out to the 5-year category because we don't see next year, for instance, having any more clarity on that unconventional license. But that's the answer to your question.
And what was that exploration commitment that was taken out over the next 12 months?
Yes, I had said our -- we've always had it on our principal properties list, and I often say $9.9 million. And that's a 2014 bid round block.
Okay. With regards to Andina Norte, is it drilling according to schedule? Or were there any issues encountered during drilling that resulted in any sort of delays? Or is it progressing as you expected?
Jenny, it's David. It's a little bit behind schedule. In the intermediate part of the whole, we had some tool failures. We had just a whole bunch of smaller things that have just put us behind. We're probably 20, 25 days behind right now. But we're just about at the next intermediate and things have been drilling better since we've gotten the last intermediate behind us as well. So we see it proceeding without any potential problems going forward, just some intermediate hole problems.
Okay, great. And could you give me a quick update on the status of the Phase I gas plant commissioning at Capachos? And what kind of impact it will have on production capacity in the near term here?
Jenny, this is Eric. So the construction of the gas plant is well underway. We are targeting commissioning kind of in that April time frame. The intent of the gas plant is to capture all the hydrocarbon in the Capachos Andina area. So as a company, we don't want to flare hydrocarbon. So what we are doing is putting this in place that will allow us to capture all of the produced hydrocarbon volumes, generate an LPG stream and generate power for the local area to use all of the hydrocarbon produced. So what will it do from a production standpoint, well, it will give us capability by mid-year to handle about 10,000 barrels a day and conserve all of the gas. So that is the main focus. We have no real gas restrictions at the moment from a regulatory perspective. This is just something that Parex follows, a policy of conserving all hydrocarbon where possible. So it will allow us to conserve that, wrap things up. With that said, Capachos Andina is also a swing field for us as we will -- we control our production to meet our guidelines specifically. So it will be one of those control fields that we will use to control our corporate production.
Eric, just to confirm, the 10,000 barrels a day you mentioned by mid-year, that's oil production you're talking about?
Correct. Gross, I'm sorry, yes.
Yes, understood. Great. And final question, if I may. Would you consider substantial issuer bid before your NCIB is completed? And if yes, would you need a separate regulatory approval for it?
It's Ken. You would need separate regulatory approval for an SIB or a significant substantial issuer bid. We wouldn't expect that that would be an issue but you would need approval. It's kind of a 30-day, 35-day process with some press releases and some filings. And it really is like a Dutch orchid, so it's kind of an interesting process. We would look at it. So at the current level, the NCIB will be done in 2000 -- in August 31, August 30, will be filled. And then we'd have to wait till December to start the next NCIB. And the NCIB for 2020 is a fait accompli in our view. It's going to be -- it's going to happen. So what we do in between the 2 NCIBs? We would look at doing an SIB. It's going to depend upon a lot of factors, and it's really days in the year yet. So we're just -- it's one of the things we'll look at. We have a strategy session with the board in September and I'm sure that will be something we'll talk about. It also ranks in there with that would we do a dividend at some point? We have a question on that on our screen. Right now, we would favor the share buyback over the dividend and investing in some exploration and growth. When we look at capital allocation, we want to still grow the business through 50,000 barrels a day that we are now potentially through to 70,000 over time, but on a measured pace. And we look at projects that we can do that with and we also like buying back our stock because that adds instant to cash flow per share and instant to reserves per share. And as shareholders, we're very keen on those 2 metrics increasing. So I think right now, our choice is to take excess cash flow or free cash flow and use it to buy back our stock and use it to then see if we can do with the business in the future. But we wouldn't say no to a dividend forever. It's just that right now, I think we have better usage for that cash.
Yes. And one of the questions on the screen is, discuss the use of free cash flow. And as Ken's alluding to and we have lots of places potentially we could use the free cash flow. The first thing we'd like to do is if we have some exploration discoveries, which we hopefully will do with a fairly extensive program we have. We haven't budgeted any capital follow-up for those discoveries nor we included any production in our guidance for that. So one of the uses of cash would be to actually follow-up drill some appraisal wells, facilities, et cetera. The second would be to add new growth blocks. Hopefully, would be through a bid round that's coming up or a farm-in that maybe we can spend cash this year on. Thirdly, would be business development opportunities. Fourthly would be to buy back additional stock. And probably the lower rank to use would be for dividends. And like I said, there's been a 2 or 3 questions about the use of free cash flow on our screen. So I think we've addressed those now.
There are no further questions at this time. I would like to turn the meeting backward to Mr. Taylor.
I'd like to take this opportunity to thank you for your interest in Parex and your continued support of the company. For further information, we invite you to visit our website or call us. Thank you again, and have a good day. Operator?
Thank you. The conference has now ended. Please disconnect your lines at this time, and thank you for your participation.