Good morning. My name is Connor, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy, Incorporated third quarter results conference call. [Operator Instructions] Thank you. Lorenzo Donadeo, CEO, you may begin your conference.

Thank you, Connor. And good morning, ladies and gentlemen, and thank you for joining us today to discuss our third quarter 2015 financial and operating results. I am Lorenzo Donadeo, Chief Executive Officer of Vermilion. On the call today are Tony Marino, President and Chief Operating Officer; and Curtis Hicks, Executive Vice President and Chief Financial Officer. Before we get started, I'd like refer you to the advisory regarding forward-looking statements contained in today's news release. These advisories described are forward-looking nature, non-GAAP measures and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion. Earlier this morning, we announced our financial and operating results for the third quarter of 2015. We were pleased to deliver record quarterly production and strong financial results that continue to demonstrate the strength of our diverse asset base, despite the prevailing economic environment. Third quarter fund flows from operations at $129.4 million or $1.17 per basic share were in line with the prior quarter, despite a 20% decrease in oil prices from Q2. Our consistent financial performance was largely attributable to growth in production of high netback European natural gas. Production for the third quarter averaged 56,280 BOEs per day, an increase of 9% as compared to 51,831 BOE per day in the second quarter of 2015. This growth was mainly driven by our Netherlands business unit, which placed two very successful natural gas wells on production in the third quarter. The two wells Slootdorp-06 and 07 contributed approximately 4,000 BOEs per day to the quarter's production rate on a combined basis. Also contributing to the quarter-over-quarter production increase was our Canadian Mannville drilling program as well as increased Australian oil production. We were pleased with the Irish Environmental Protection Agency issued its final determination in…

[Operator Instructions] Your first question comes from the line Pavan Hoskote with Goldman Sachs.

I'll start with a two-part question on European gas pricing. First, what's your expectation for gas pricing in Netherlands, Germany and Ireland relative to the NBP spot price going forward? And secondly, your presentation has some helpful slides on rate of return for your European gas assets. Can you talk a little bit about the sensitivity of this rate of return to lower European gas prices, more broadly is there a price at which you would want to reprioritize your Canadian assets over your European assets?

I'll respond to the first question, and then I'll let Tony deal with the second part of your questions. So I think from Vermilion's perspective, and I think it's Vermilion's and I think in addition of that we've spoken to a number of investors over our marketing efforts over the past year, and I think the consensus is, from our investors and from a number of other publications that we constantly follow is that European gas prices will be trading in the range of about between US$6 and US$8 per million BTU or around $8 to $10.75. And you may see short-term periods of volatility. I could see prices dip down in the range of about US$5, which is about $7.50. I think there is a number of factors that, in our mind, point us in that direction. I won't get into all the details of that, because we can have a long discussion on that. But I think some of the key ones, I guess, if I could speak to them is that Norway and Russia who control over 50% of the European natural gas market really have indicated that -- through their actions, they've indicated that they're working towards the floor in the range of that US$6 per million BTU. And then when you look at the forward strip, it's currently trading between around US$5.70 to US$6 that sort of is reflected of that. And it's being pressured a little bit by weaker demand and mild weather and higher storage levels, but even at that level, with those constraints we're still seeing pricing in that range. And I think as we've mentioned, I think coupled with all that, I think Vermilion's hedged volumes, I think we spoke to them in our conference call this morning, and so we feel we're in a really good position from a hedge position. So I think overall those are the types of pricing that we see in Europe over the mid-term. And we remain quite bullish on European gas. We think that it will provide us the ability to drive some pretty strong returns. And so with that I'll maybe pass it on to Tony to maybe talk to the second part of your question.

If I may interrupt you here for a second, I appreciate all your comments on the European gas price outlook, but on Netherlands, Germany and Ireland specifically, do you expect pricing to be very similar to, let's say, to the NBP price or do you expect the premium or discount going forward?

Well, in the Netherlands, typically TTF trades very closely to NBP with the minor adjustments for transportation. So generally, we don't see that disconnect being much different. I think, Ireland, we're basically getting NBP less between $0.20 and $0.40 per mcf. And so I think those are in the range of what we're seeing. And I think on the Germany side, I think, Tony, can you maybe speak to the Germany side, because I'm not really clear on that one there?

Yes. the German gas trades off of TTF index and the price doesn't tend to deviate much from what we get as spot prices, gas prices per TTF and then it's eminently hedgeable using the TTF forwards. So it is very, very similar in Germany as well.

And Tony, if you could talk a little bit about rates of return for your European gas assets and the sensitivity around that, and if there is a price that you would want to reprioritize your Canadian assets over your European assets?

In our materials we have on the website, our corporate update presentation that we do each month, we include the economics for the historic program that we've drilled in Netherlands and that ExxonMobil has drilled in Germany in the assets that we own a 25% interest in there. Both of these projects have extremely strong economics, and I don't think that the viability of the project is going to be at all threatened if prices end up being lower than their current levels. For example, in the Netherlands, the historic program that we've had there using the historic, approximately 60% to 65% success rate that we've had prior to the drilling of our three most recent wells are not included in this analysis, but they've probably been more successful than anything that we've drilled to date. So using the program prior to that, the actual results at an $8.50 per MMBtu price, we achieved a tax IRR as well in excess of 100% on that Netherlands program. So with the current price for NBP at $7.85 per MMBtu, for TTF at $7.50 per MMBtu on a fairly flat forward, further at along the curve, those projects are still going to have really, really high rates of return and very rapid payouts that current prices that make it withstand substantially lower prices than those that we have today. Remember, that these are extremely productive wells. They're all conventional producers. They don't require fracturing. And you've heard about some of the production results we've gotten on the recent program, the best results we've received, we've achieved to-date, and that's not even reflected in these economics that we're representing here, so not very much sensitivity. In Germany, based on the actual results of the well that our operator there ExxonMobil achieved in 2014 at the same price tag, that is a 26% after-tax ROR, this year not included in there. They've also drilled a very successful extension and development well. So that one too has a lot of margin before it would be impacted by lower prices. That program is just in terms of viability of the program, it's not going to be very sensitive to pricing. We intend a ratable program in line with the regulatory environment in Europe and we don't intend to ramp up or ramp down very much in response to prices within any foreseeable range for the European gas. So does that take care of your question, Pavan?

It does. It's a very helpful and detailed response. And one last question from me, if I may, and is more of a broad question. But can you talk a little about natural gas demand trends that you're seeing in Europe, in response to the lower gas prices recently. Are you seeing a step up in demand from coal to gas substation?

Tony, do you want to touch that one.

Sure, I'll tell you what I do know about it. Over the longer term, I think that there is a substantial opportunity for gas to take market share away from coal. And the first reason is even unrelated to this recently modestly lower European gas pricing that we're seeing. Gas is such a clean fuel in comparison to coal, way less particulate emissions, no mercury generated, and of course, as far as the waste product of carbon dioxide it's much, much lower natural gas. Furthermore there is a desire on the part of certain European countries, I would say, particularly Germany to reduce its use of nuclear power. In fact, I think the objective there, if I remember correctly, is to completely eliminate the use of nuclear power generation by 2021. And so again, there is an opportunity for gas to take market share. Now, the drop in European gas prices that has occurred, this moderate drop has occurred, while there's still a quite strong levels compared to what we see in North America is, I think recent enough, and I simply do not have any data regarding the substitution of coal generation for natural gas. I would think that it's occurring, I simply can't quantify it. I do think that even independent of this of what will undoubtedly occur is response to prices. You'll have a greater effect, just due to the desirability from an environmental perspective of gas compared to coal.

Your next question comes from the line of Travis Wood with TD Securities.

Quick question, and if you could just provide more color actually just around some of the infrastructure, issues that you're facing in Canada, how much of that impacted gas versus oil volumes, and then the timing of -- and kind of the plant projects that are in the queue to get that 2,400 into the market?

Yes, it's kind of the struggle over the past year that began with the integrity work done on the TransCanada system. It is getting better. The capacity of that system has been restored significantly, I would say, although not completely over the past quarters and we think that, that will continue. As far as our volumes that we have down, we have been running at a rate of around a 1,000 BOE/D for the last quarter. I think it was a little bit higher than that earlier in the year. We're going to get part of that on we think during Q4, that there's a larger volume of around 2,400 BOE/D. We estimate that is restricted not so much solely due to TCPL, but more just really localized plant capacity primarily in the Ferrier area. A lot of this gas is non-operated by us and it has to go through facilities owned by other oil and gas operators in a couple of cases. That probably isn't going to get remedied in Q4 and that represents a behind pipe volume that would be coming on production largely during 2016, although given the productivity of some of these wells in that Ferrier area wouldn't surprise me, if the limitation is not-completely corrected even until 2017. All that said we've got a lot of gas and NGL and condensate productivity. And we can still have, I think some pretty good growth, despite these limitations that we see either from TCPL or the plant restrictions from some of the other oil and gas operators out there, in the cases where we're a third-party processors at those plants.

And looking ahead, do you think you could do something similar to how you guys built infrastructure out in the Cardium to help deal with some of the third-party issues that you're facing today in 2016?

Yes, generally we can't do that. We have two areas really there in west-central Alberta, where we've got significant productivity and the very bright investment program ahead of us. The largest of those is at Drayton Valley, where we have the Mannville and particularly the very condensate-rich Ellerslie, member of the Mannville. This formation and set of formations underlies the Cardium, so we already have substantial infrastructure in the area roads, well pads, pipelines, oil batteries and gas plants. We have actually this year completed a major expansion of our gathering and compression in the Drayton Valley area and that is allowing us to move the natural gas production and the associated condensate that we have for most big Ellerslie wells that we've drilled to market. Sometimes it go through our two company gas processing plants. In some cases, it goes through third-party such as Keyera in Drayton Valley, but generally, we're not facing too much in the way of restrictions there as far as plant processing, because we have built out this infrastructure project that should handle our needs for the next few years. The second area where we have a lot of productivity is in the Ferrier area to the south of Drayton Valley and there it's a little more challenging to get to market and I'm not sure that we would affect the major processing expansion in there. What we have done is upgraded one of our key compression facilities and that is allowing us to access more of the third-party plans that they do have room. But the instance that you asked about earlier, about having the 2,400 BOE/d behind pipe is a case, where we're not the operator of those wells and so we have to work on schedule of the operator allowing that gas to flow in their own plans. There might be some little things, we could do to move some of that gas around at the margins through our own compression and to our third-party plants that aren't full, but for the most part that's going to have to gradually come on mostly going 2016.

And last question, just in terms of the Notikewin Wells. Can you give any comparison or contrast between some of the liquids yields on those versus the Ellerslie program?

The Notikewin has lower yields than the Ellerslie. That Ellerslie in the Drayton Valley, although the yields very up there, it's not probably an average for us to 80 to 100 barrels per million of condensate plus additional C3 and C4 in the Notikewin and the also the floor, which exist in the Ferrier area the yields are lower, usually depending on the plan that's being processed at usually in the range of 20 to 50 barrels per million of total liquids.

Your next question comes from of Kyle Preston with National Bank.

I got two questions for you here. First one on your Australia horizontal sidetrack program, can you just remind me how many wells you're drilling there and what sort of production you expect out of that?

Kyle, the original plan that we had for this year's Australian program was to drill a dual lateral sidetrack off of an existing well. What we're doing right now is we're going to go ahead and put the first sidetrack on that we drilled, that is quite a long well, it's about a 3,500 meter measured depth at a total -- at a true vertical depth of only about 600 meters. So an extremely long well, one of the longest, in fact, extreme extended reach wells drilled at this kind of shallow vertical depth yet in the world at around a 6:1 ratio. That well as we drilled it and logged it looks very, very good in terms of how much oil we think its accessing. And so what we've decided to do for now is to go ahead and put that well on production and we're in the final stages of getting it ready to go. And then we'll decide whether depending on the productivity of that well, if it's extremely productive, we might decide just to leave that wellbore alone and not drill the second sidetrack out of it, because if it's very good well, we may not want to take the mechanical risk of intervening in it. So we're going to move the rig off, give it to one of our rig consortium partners to drill with and then we'll come back next year and decide if we want to intervene into that first well that we've worked on off a platform A or go to some of our other targets on platform B for the remainder of this rig commitment that we have. And whatever we do in Australia will be built into that $350 million capital budget that we had talked about in this release. As far as the productivity, the Australian wells when they come on, at least if they're at like what we achieved in the previous program in 2013, and if its at all like what it looks like this well could do based on the logging well drilling that we did can produce a very, very high rates, rates of 3,000 barrels a day or more. Often times, we manage this production to hit certain field targets and to maintain the long term premium market for this crude, so we may or may not produce it continuously at that rate, but we don't know exactly what it will be until we put it on and clean the well up, but it would not surprise me at all if the well is capable of 3,000 barrels of oil or more like the previous ones that we drilled. Again, we may not produce it continuously at that rate as we manage field production.

So you're confident even with this just one well bore, you're able to manage between 6,000 and 8,000?

I think that we would be able to do that, yes. Of course, the wells won't last forever and that's one reason that we would go in and probably drill something else in Australia during number of targets that we have there during Q2 of '16 and then that would set us up probably for a couple of years without drilling maintaining the targeted field production, probably achieving a very slight incline in the field, and all the time throwing off free cash flow, even in 2015, a drilling year and with much low oil prices that we've seen in 2015.

And second question here just on the M&A market. Just wondering what you're seeing here for acquisition opportunities? And whether or not your prioritization has changed it all between Europe, U.S. and Canada, just given the slightly weaker gas prices we're seeing in Europe?

We continue to look at acquisitions globally. What we're seeing in the U.S., the U.S. acquisition market, if you just look at straight production type assets, producing assets, still quite expensive and not seen a big sort of reduction in sort of the bid-ask spread in terms of what sellers are willing to sell for and what buyers are willing to buy for. Canada haven't seen a lot of opportunity, but we're looking at, I would call them, smaller tuck-in deals that are in and around our existing assets, but we can acquire lands that are non-producing where we see drilling occasions and we have good defined drilling inventory that we can bring into the portfolio at a relatively low costs, you tend to get matrix on the non-producing lands, especially when they're in and around your existing areas and you understand them very well, that are more attractive that we think that over long term can have some pretty significant value and increase the depth of our inventory. In Europe, we continue to look for acquisitions and we think that there's going to be some good opportunities there over the next six to 12 months. Generally, internationally, these assets come out, but you have to be very patient and sometimes they take a little bit longer, but we think that there's going to some good opportunities for us to acquire new assets that fit in well with our European focus, and primarily focused on gas, but also potentially some oil as well. And I think that, it will really allow us to build on our substantial footprint that we're establishing in Europe and allow us to continue to grow our momentum that we're going there with Corrib coming on here shortly.

There are no further questions at this time. I will turn the call back over to Mr. Donadeo. End of Q&A

Well, thank you, Connor. And thanks everyone for participating in our conference call today and for your continued support to Vermilion. Thank you.