Good morning. My name is Kim, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy's Third Quarter Results Conference Call. [Operator Instructions] Anthony Marino, President and CEO, you may begin your conference.

Thank you. Good morning, ladies and gentlemen. Thank you for joining us. I'm Tony Marino, President and CEO of Vermilion Energy. With me today are Mike Kaluza, Executive Vice President and COO; Lars Glemser, Vice President and CFO; and Kyle Preston, our Director of Investor Relations. I would first like to refer to the advisory on forward-looking statements contained in today's news release. These advisories describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today and outlined the risk factors and assumptions relevant to this discussion. During this call, I'll provide you with an overview of our third quarter 2018 financial and operating results and 2019 budget, which were included in our Q3 release. The third quarter marks our first full quarter with the integration of the Spartan assets and our first quarter production and cash flow contribution from our Central and Eastern Europe business unit. We also completed a U.S. acquisition in the quarter, expanding our position in the Turner Sand fairway of the Powder River Basin in Wyoming. Vermilion is a much larger entity today, with a production base over 50% greater than it was 2 years ago. From this expanded land base, we delivered record quarterly production of 96,200 boe/d and record FFO of $261 million, which is twice the amount we generated in the third quarter of 2017. Our Board of Directors has approved the 2019 capital budget of $530 million with associated production guidance of 101,000 to 106,000 boe/d. The midpoint of this guidance range represents year-over-year production growth of 18% or 7% on a per-share basis. Including our projected 2019 results, Vermilion will have delivered compounded average production per share growth of 9% over the past 5 years, coming primarily from high-margin barrels with premium or advantage pricing relative to…

[Operator Instructions] Your first question comes from David Popowich from CIBC.

I guess I had two questions, the first is just with respect to drilling activity in Canada. I was just wondering if you can comment on whether you've seen any fluctuations on how you plan to deploy capital in Canada over the course of 2019, just given recent weakness in differentials? Would you still expect to have upfront weighted program in the first quarter as you've had in the previous years? And then the second question I had is just with respect to share buybacks. And I guess, was wondering if just given the performance of the stock this year, if you guys have any change in your view on share buybacks in the capital allocation decision-making process?

Okay. Thanks very much, Dave, for those questions. The first one, in regard to -- do the diff changes affect our capital plan? As we have outlined in this release, they do not at the current levels. They did enter into where we decided to plan to deploy the capital for '19. As an example of that, we have -- actually in industry terms, we have a very high quality, probably the highest quality Cardium light oil halo position in the industry. Nonetheless, because the current diffs are so wide for MSW or Edmonton par crude, we decided to not drill any wells in the Cardium. So it has affected the mix a little bit but the wells that we're going to be drilling in Southeast Sask, the conde wells in West Central Alberta and the Powder River Basin wells, all benefit from a significantly better differentials in MSW. In particular, Powder River Basin has very low diffs to WTI, current contract for us is minus 260 from WTI, including transport. So LSB in Southeast Sask has moved to a significant, very significant premium to MSW and although its diff has widen a little bit, it's still leads to quite strong pricing and very, very high project returns because those wells are very productive and not very expensive. Conde has also widened out some from where it traded previously, usually typically flat or at a premium to WTI now. Its most recent data has showed about a $10 discount to WTI, probably, that will narrow. But in any case, the returns from those wells are extraordinarily strong, so we're going to continue to drill the conde wells. As far as the timing, we have a higher capital deployment as usual in Q1, just driven by weather and ground conditions. We're…

[Operator Instructions] Your next question comes from Patrick O'Rourke from AltaCorp Capital.

Just a couple of quick questions on the capital allocation of the Powder River Basin assets next year. I noticed 6 of the 8 wells will be on the new property. Wondering what the purpose of these 6 wells are. Are they still in the delineation phase? I know that there is some vertical -- or pardon me, a horizontal well control already there in the Turner Sands and then that would this be from the 93 future locations? Or is there potential to add to that in the reserve report with this delineation drilling?

Yes, I think I'll take that one as well. Thanks, Pat, for the question. The existing production is about -- I know it's roughly half the split between the muddy waterflood and between Turner Sand production out of horizontals. So there are -- I feel like there is extensive outpost delineation of land base to identify where we ought to be drilling horizontal and a few Parkman wells as well going forward. So I don't think that this program is going to be characterized as delineation. It would be, I would say, broadly speaking, within existing control. The -- as far as the well count, we identified 93 locations for the Turner and the Parkman. However, only around half that number is on the initial GLJ report. So they would represent, over the course of the development of the property, if that's exactly the number, they may well go up over time. Roughly half of them would represent locations that are not recognized by the reserve engineering firm right now. At present, we have not expected any drilling in the Mowry or Niobrara shales. We -- our assessment at this point is probably immature in this location, however, industry activity has a tendency to expand that, and that maturity question is something that we're going to continue to evaluate, and I think, really, over the longer term, that would represent some upside as well to the location counts that we've quoted.

Your next question comes from the line of David Ramsay from Calrossie Investment.

Your stock is up quite sharply this morning, about 5.2% in an otherwise pretty good day for oil and gas stocks. And I haven't -- maybe I missed it, but I haven't heard any discussion as to anything particularly being disappointing in the results. Although, I did hear from one source that there was maybe some concern about Corrib declines being faster than expected or that the 2019 cash flow per share forecast in your present corporate presentation was lower than people were expecting. Can you address either of those as being -- in your view, is everything kind of unchanged from past guidance? Or it's in fact, there is some new news this quarter that we actually haven't discussed yet.

Thank you for the question, David. I mean, on each of those 3 points you raised, first of all, Corrib. We, first of all, attempted to be much more detailed in the disclosure of the future decline rates at Corrib based on our numerical reservoir simulation. The property over -- roughly the next 10-year period, will have an average decline rate of about 15%. In fact, as we calculate it, it's a little bit below 14.5%, but we have just rounded up to 15% in all of our disclosure. The decline rate that is projected for next year is 17%. The year after that, the simulation has a very slight bend on a similar clot, it's essentially exponential but just a tiny hyperbolic shape to it, putting it at about 15% in the second year from here. And then after that, we're bouncing around 14%, some years lower than that, with an average of about 14% as you finish out the coming decade. So those are the decline rates from Corrib. There may well be, in some quarters, a concern, I guess, about Corrib declining. It is a very high quality pool, and over time, it is going to recover the big, big majority of the gas that exists in this very large high permeability structure. And so it is just inevitable that as we pull those molecules out of the reservoir, that's what we seek to do, it is going to decline. Now the company is -- we're over 100,000 barrels a-day company. And so whether the decline next year is 17% or, for example, 15% in a single year, on a roughly 8,000 or 8,500 boe/d asset, it comes to about 170 boe a day. So this is not a -- it's a difference that perhaps the market…

So that's a great answer. If I can just do a couple of supplementaries related to that. Are the Corrib declines consistent with what you'd have in your engineering reports that are part of your net asset value. So that is the first question. Secondly, is there any risk related to those engineering reports, the reserve component of it because of these declines you see at Corrib? And I fully understand that reserves decline. And then third point would be, roughly, what percentage of your NAV would be Corrib today and post the taking over of the additional portion that's upcoming?

I can answer those first two, I don't have the NAVs. None of us have it with us here. But the first two, the answer is yes, consistent with the engineering report, there could be minor variations, but I don't think there's anything significant there. Secondly, are there risks to that engineering projection? There are always risk to it. It could be lower, it could be higher. Probably, it's a pretty reliable property. It's very high quality reservoir, very well described with, I think, over time 3 3Ds, including our most recently an ocean bed cable 3D for very accurate resolution, which should reduce any uncertainty around the size of the tank. Secondly, the numerical reservoir simulation that we performed has a great deal of pressure and rate data by well as well for the field as a whole. And since you take what I think is an accurate geologic description, tank size, from a well-logged core and 3D and then combine that with a history match of all this great pressure data, I would expect it to be quite accurate, really, there's so much better data and such a higher reservoir quality that I feel like it should be more accurate than the vast majority of pools and wells that you will work with in the worldwide oil industry. And so I think it would be pretty accurate, although it certainly could vary off a bit for any number of reasons. The risk on the upside, I would point out again is something that we're going to seek to evaluate as operator to see of this PDP decline rate could not be mitigated and maybe recoveries increased through some of the activities of that I outlined earlier in the question -- in the answer to your question.

Your next question comes from Arun Jayaram from JPMorgan.

I was wondering if you give us a little bit more color on the Netherlands drilling program. It looks like you're doing 2 wells for next year. What's the permit status? And just talk to us about the plans to accelerate to up to 6 wells or so by 2021.

Thank you, Arun, for that question. I'll start answering, and I think after that, I'll turn it over to Mike Kaluza, our COO, who will go on to maybe a little bit greater detail about the permitting sequence there. So to start up in more general terms, this Netherlands question is one that seems to generate a large degree of focus. And again, kind of inexplicably to us, given the diversification of our asset base and the amount of disclosure that we've attempted to make on it previously, the -- we did not drill in 2018. The permitting system over the past year or couple of years has changed in the Netherlands and it had slowed down due to seismicity in the Groningen field in the northeastern part of the country. Now we are not an owner in Groningen, it's a very large field, very large withdrawals. And unfortunately, there have been earthquakes that have been associated with gas withdrawal there. In our fields, some of which are good-sized fields to us but nonetheless, everything outside of Groningen falls within what is called Small Fields Policy in the Netherlands. We have, I think, overall, similarly have been slowed down by about -- by the knockoff effects from the seismicity in Groningen. And that is the reason, ultimately, that we did not drill in 2018. So the permitting system in the Netherlands is and has been clarified over time. We intend to drill 2 wells, I would say at least 2 wells in 2019. Mike in a second, we'll give you the details around that. Over the longer term, and then there is a small amount of production, I think, that comes on perhaps late in the year associated with some of that drilling, but I believe it's about 2% of…

Sure. Thanks, Tony. So in the Netherlands, when you're going to drill a well, you basically have 2 sequential components to the permitting to get that well drilled. First is the environmental impact assessment and then the second is the actual drilling permit. So for our 2019 drill, we actually -- we've received the positive results for those -- for the EIA assessments, and we've submitted the actual drilling permit. So we're anticipating an approval date on those -- on the drilling permits probably in the order of 6 to 8 months, those have already been submitted, so that's given us ample time to get our final permit approval prior to our anticipated spud date, which is during Q3 of 2019. In regards to future programs, really, what we're trying to do is build a 3-year inventory of drilling permit. This would give us some certainty on the predictability of our capital programs. And by the end of 2018, we will have initiated 9 additional permits and then through the first half of 2019, we'll probably have another 4 to 5 permits in for approval. So that will give us a good start on that to set us up for the drilling beyond 2019 and 2020 going forward.

Great. And just my follow-up, Tony, I wonder if you could just set up the first operator, the well opportunity in Germany, supposed to occur in first half of the '19.

Certainly. So we're looking very much forward to drilling in Germany. We've had pretty good production profile there without drilling, just out of workovers. And the most significant event I'll speak, to a minor one at the very end, but the most significant event we have would be drilling at the Burgmoor Z5 well. This is in Dummersee-Uchte license. It is an extension really as play off of the existing pool kind of a semi-development prospect. It's in the order of 50 DCF gross. It has ultimately been worked into the original ExxonMobil producing Germany farmout that we made there. So under the deal that exists today, it's really in a sense the first farmout wells lower risk prospects. And we're very, I think we have a 46% post capital working interest in that well, and we're very much forward -- are looking forward to the drilling of it over the next number of years, about 1 well per year. We have set a very significant exploration prospects that will also be drilled on the ExxonMobil farm. And these very large prospects would still, in our view, pretty good chance factors are outlined on Slide 64 of the investor deck in terms of the -- at the higher end of the probability distribution, the larger potential field sizes, certain of these prospects could be as large as the TCF. And generally, we would have a 50% to 60% working interest on those as we've moved out later in that long-range plan period, getting probably 4 years out or so, we have some 100% very, very large prospects to drill as well outside of the farm in. So in addition, next year, we'll be doing a 1 to 2 sidetracks of existing wells in the development properties in Germany.

Your next question comes from [ Ming Feng ] from [ Pica Mulhane ].

Hey, Anthony. I just have a couple of follow-up questions. My first question pertains to crude oil marketing. For the Spartan assets, do you primarily just sell at [ Cromer ]?

We -- for Spartan, almost all of the crude is priced off of LSB. It's either LSB or Midale crude. Midale is a little lower quality and has a couple of dollar discount to LSB but all sold actually in Southeast Sask. There is a very small component, I think it's on the order of -- I don't know, maybe 800 barrels a day of Viking crude that does not go against the LSB marker. It is still in Saskatchewan. It's in Southwest Sask though. And sells into corroborate. It is really referenced into MSW. So our MSW components would be that small amount of Viking oil that we got from Spartan and then our legacy position, mainly in the Cardium in West Central Alberta.

Okay. So what percentage of your crude production for next year is using budget assumptions as exposed to MSW? It will be smaller?

It is. It is 8% of the global oil production and oil production's about half of our product mix, so it's about 4% of the boes and 8% overall.

Okay. My next question is just on the PRB. One is currently -- what kind of wellhead pricing are you getting on the PRB? And two, are you worried about egress because from what I'm hearing, EOG and TransEx ramp-up volumes and the outcome pipelines are completely full?

The answer to your questions are -- the first one, our price at the wellhead, this is after transport, is minus $2.60, minus $2.60 from WTI, so that's a very good dip in today's world. Secondly, there may be, probably given the quality of the Turner throughout the basin and the potential from some to shelf the projects there. In addition a few of the other stands apartment, which will have some of the Shannon Sussex, there is probably going to be a ramp up in the Powder, it's a good basin. However, it is that least a present overserved by the local refining. So I don't have a basin wide forecast to compare to, but I think in comparison to the other basins, this one would be probably have the best the demand/supply characteristics.

There are no further questions at this time. I turn the call back to Mr. Marino.

Kim, thank you, and thank you to all of our participants today. We look forward to speaking with you again after Q4 2018 year end results are reported in February.

So this concludes today's conference call. You may now disconnect.