Good morning. My name is Jody and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Incorporated Third Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Mr. Anthony Marino, President and CEO, you may begin your conference.

Good morning, ladies and gentlemen. Thank you for joining us. I am Tony Marino, President and CEO of Vermilion Energy. With me today are Mike Kaluza, Executive Vice President and COO; Curtis Hicks, Executive 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 outline the risk factors and assumptions relevant to this discussion. During this call, I’ll provide you with an overview of our third quarter 2017 financial and operating results and our 2018 budget and guidance, which was announced with our Q3 results this morning. Third quarter production was approximately 67,400 boe/d, an increase of about 200 boe/d from Q2. Production was negatively affected by downtime at Corrib, which reduced Q3 production by approximately 2400 boe/d. Higher production in Canada and the US was achieved through successful drilling programs in the first nine months of the year, while Netherlands production benefited from receipt of permits and reduced turnaround work. FFO for Q3 was $131 million or $1.08 per share which was down approximately 11% quarter-over-quarter primarily due to the unplanned downtime in Ireland and lower realized commodity prices. The downtime at Corrib had an estimated FFO impact of approximately $8.5 million or $0.07 per share in Q3. Despite this quarterly decrease in FFO, our payout ratio for the first nine months of 2017 was 94%. Q3 operations review, with respect to operations let's start with Europe. In Q3, we drilled two gross 1.0 net wells in the Netherlands. The Eesveen-02 60% working interest encountered 24 meters of net pay in two separate intervals targeting Zechstein 2 carbonate and the Rotliegend sandstone. The…

[Operator Instructions] Your first question comes from the line of Greg Pardy of RBC Capital Markets. Your line is open.

I've got three quick ones for you Tony. The first one is just with the lower - with the – just Western Canada, you referred to the Mannville, are all of those wells lower Mannville and then can you just comment on what the liquids and condensate cuts would be roughly.

For the Mannville question, are you referring to the drilling that we did in Q3?

Yes.

In the Q3 drilling, in fact in the entire year program and for next years, the vast majority of that is in the lower Mannville or the Ellerslie. I think we have - I think for this year’s program as a whole we have two or three wells in the upper Mannville and that’s the same plan that we have for next year. Typically just drilling expiries in the upper Mannville which is not as liquids and condensate rich as is the lower Mannville or Ellerslie. For the yields, we typically are - I’m just going to refer to our investor deck for a second to quote these for you, in the Ellerslie our overall yield is a little bit over 100 barrels per million of hydrocarbon liquids per million cubic of the sales gas. And of that 100 barrels a million, two thirds of it is condensate, the remainder is NGLs.

And then just for the 2018 program, could you give us a set up in terms of what the plan is for both the Turner Sands and then just for Germany?

Mike, would you like to address that for starting with - starting with US and then Germany?

In the US and the Turner Sands program we're going to be drilling a total of five wells. Four of those wells are on two well per pad locations down in the southern end of our lands and the fifth well will be up in the new federal unit that we just formed as a well to stabilize that unit. In Germany basically what we're going to be doing there is preparing for the 2019 program, getting ready for the Burgmoor Z5. That will be our first operated well in the Dümmersee-Uchte. We do have another well that [indiscernible] well, a non-operated drill that we’re just doing preparatory work on that one. So in Germany, it's mostly just getting ready for the ’19 drilling program.

Your next question comes from the line of Nima Billou of Veritas Investment Research. Your line is open. Nima, your line is open. [Operator Instructions] Your next question comes from the line of Darren Engels with GMP.

Could you tell me what the ramp up looks like in production in the Netherlands for 2018?

Yes, Darren. Give us just a second. Thank you for the question and we’ll refer to that production plan for next year. So we will be ramping up Q1 through Q3 and declining slightly in Q4 in the production plan that we have. For an overall production level for the year, that is a little bit in excess of 10,000 boe/d.

You next question comes from the line of Nima Billou of Veritas Investment Research.

Just wanted to talk about a couple of different strategic issues. With respect to the international operations, you guys have always been adept at handling the regulatory environment, but you mentioned permitting issues in the Netherlands for French production, it looks like growth will likely be off the table. Where is there a reshuffling in order to I guess go to areas where those challenges aren't as longstanding or sort of volume inhibiting, like, what are the countries internationally next that are going to receive some of that capital, that attention that are going to be going away potentially from France.

Let's start off with the specifics of the French and the Netherlands units and then we'll go more generally to Europe. So for France actually, the unit’s production profile I don't think is going to change as a result of the new climate plan. We're going to continue to invest at a moderate level in France as we have previously. I think it will be a low single digit grower over time. I think that can continue actually for quite a long period and during that time, it'll be generating quite a bit of free cash flow as it has in the past. So really no change at all in the way that we're going to be managing France. It’s really quite a long term program that the French government has put in place. It's mainly going to come out of our development activities. But we will be conducting some seismic and ultimately drilling on an exploration license in Alsace-Lorraine. So, I think there's actually quite a diversity of -- quite a diverse set of projects that will lead this French production profile to continue as we have managed it previously. In the Netherlands, we are resuming growth in 2018. We had actually recorded seven straight years of growth, prior to 2017 and we were quite proud of that record. It's been a very strong unit for us. We had program to be up in ’17, but due to some of the permitting setbacks that we experienced, we're actually going to be down a little bit this year, but resumed growth along the same profile that we had previously expected in ’18. I think we have a very bright future there as well. And I see it as a long-term moderate growth unit, again one that will generate a lot…

I appreciate your very thoughtful answers, just that I, you know, that's something that needs to be communicated and reinforced because people see the headline on those government initiatives and they think that it permanently impairs your businesses and given your operational track record that may be one of the reasons it's sort of holding back the share price. My final question is on the Mannville side, clearly you’re putting more attention on the Canadian opportunities set, I think intelligently so you guys have always gotten good acreage, you see a good opportunity on this liquids rich side. And I'm going through your presentation and I see that certain wells are good even with a zero AECO price, but AECO weakness can’t really be ignored right now. The 12-month strip is at 2.16 and your economics begin at 2.50. Do you still see the same attention and same levels of capital expenditures, given a weak AECO price or is it flexible that you can adjust downward, if need be, because these liquids rich opportunities, when you still see the production profile are 60%, 70% gas when I look at your bar charts and that gas price has to inherently affect the economics of that well. So I just want to see or are there any things that you can do to mitigate AECO weakness. There are some producers selling directly into Chicago. So I just wanted to get your take on facing that wall of low AECO pricing and how it may change your outlook with respect to the near term inherently on your Canadian opportunity set?

For sure. So let's take those questions piece by piece. The first thing is there flexibility in the Canadian program. Well, absolutely. I mean that's the beauty of the North American business and particularly in Canada where most of this permitting is routine. It is quite easy to ramp up and down the program in response to prices. The next part of it about the about the returns on the projects, these wells that we're drilling, with the exception of just a couple of expiries in the Notikewin or Fahler. These wells that we're drilling on the Ellerslie actually have very little dependence on AECO. Of course, it’s better to have a higher gas price than a lower one, but even though one third of the production mix is liquids, primarily condensate for us, the economics are still carried by that conde. The wells are just so productive at pretty low cost and continue to come down that you can achieve extremely high rates of return even with low or zero gas prices and this is illustrated in the investor deck where we point out that even if we have no AECO price and we have $50 WTI, we would still make a 31% return on that Mannville program. So, certainly we’ll accept the higher gas price, but -- if it occurs, but we are drilling those wells to make the liquids again with the exception of the ones that we drill for expiry just to hold those lands in the Ferrier area. Now addressing the dynamics of the gas market, it's true these AECO prices were very, very weak, particularly in September and I think everybody's aware of the causes of this increasing flows on to the system, at the same time that there's been a lot of downtime for pre-planned maintenance by TCPL. Prices have begun to recover in October and of course the forward curve is better, especially during the winter when there's more seasonal demand for gas. All that said, the long term AECO basis is still well above a dollar deduction to NYMEX and I would find it hard to make a case that it's going to get too much flow of that. I'll point out that we're 80% hedged in Q4 for our Alberta gas. And again we're conducting this business to produce the condensate into a lesser extent the NGLs because that is really what drives the economics.

[Operator Instructions] There are no further questions in the queue at this time. I’ll turn the call back over to Mr. Marino for final remarks.

Thank you again for participating in our conference call. We look forward to speaking with you again after our annual release in March 2018.