Ladies and gentlemen, thank you for standing by and welcome to the Vermilion Energy Inc. Year-End 2019 Earnings Results Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Anthony Marino, President and CEO of Vermilion. Thank you. Please go ahead.

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; Kyle Preston, Vice President of Investor Relations; and other members of our management team who may be called on during the Q&A session. We will be referring to a PowerPoint presentation to discuss our fourth quarter 2019 financial and operating results and year-end reserves update. The presentation can be found on our website under Invest With Us and Events and Presentations. Slides 2 and 3 in the presentation refer to our advisory on forward-looking statements. 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. Let me start off with our dividend. Slide 4, dividend reduction. Our Board of Directors has approved a 50% reduction in our monthly dividend to CAD11.5 per share in response to the recent weakness in commodity prices resulting from the outbreak of the novel coronavirus, also known as COVID-19. We didn't take this decision lightly. It has been an extremely challenging environment ever since the oil price crash in the second half of 2014. Throughout this period, we've maintained focus on profitability by grinding costs out of all phases of our business ranging from field operations to financing expense, upgrading our capital project slate and adapting our capital markets model to focus even more acutely on returning capital to shareholders. We have been unique among our traditional competitor group and maintaining our dividend while still providing a moderate level of growth. We have paid a monthly dividend, or distribution in the trust era, for the past 205 consecutive months returning over CAD40…

[Operator Instructions] The first question comes from Dennis Fong of Canaccord Genuity. Please go ahead. Your line is open.

Hi, good morning and thanks for taking my questions. I've got a couple here. The first is just in terms of your current leverage position. Obviously kind of just given the oil price pullback just outside of your range, can you kind of reiterate what the target is that you've kind of focused on here? I know you talked towards some of the abilities or the levers that you guys can pull towards moving towards that if we kind of stay in a protracted oil price environment similar to this one? And I've got a second. Thanks.

Yes. Well, first of all, our projected debt-to-FFO at the end of the year under the strip is about 2.9 times cash flow, and our target is 1.5 times debt-to-cash flow or FFO. It's our intent to self-fund. And under the strip, we ran at the end of the day on Wednesday, we were at that level. Keep in mind that when we quoted the 99% number, that includes two months of dividends in January and February at a higher level. So, under the prices that we had as of the end of the day on Wednesday, that would give us a payout ratio on a pro forma basis with the new dividend level of 94%. We do intend to remain self-funded, and we'll be looking closely at commodity prices not reacting to any single day event. We do think -- as I mentioned in the opening remarks, we do think that this in the short to medium-term does qualify as a structural change in the market. And therefore, we made the response on the dividend because of that assessment that we had made. We're not going to make any further changes today to the -- to our outlays. We will be seeking to reduce cost where we can in the operating side of our business. With respect to the CAD450 million capital program that we have for the year, if we have continued additional weakness as we have seen in the last couple of days in the commodity, we would react on the capital program side. And I had a question about this earlier today, what the magnitude of that change could be. We haven't made any decisions. I think we'll complete our Q1 program, we've always pointed out that the growth component of our budget for 2020 rates comes to about 5% of our CapEx. There's about another 5% that is devoted toward projects that have impacts beyond 2020. So, our seabed [ph] CapEx for the year is about CAD410 million and we would consider reductions in the capital program at that level or perhaps into the range of 15% of the capital program. We make that decision, I think, after completing the Q1 program, and in time in the post breakup period for us to adjust activity in Q2 and beyond. So, Dennis, did that get your question there?

Yes. No for sure. And then, my second question is maybe shifting gears here to European natural gas pricing. Obviously there's some near-term weakness there in. How should we be thinking about -- and there's still relative strength as we look further out down the curve, how should we be thinking about your hedging policy longer term and how are you guys trying to kind of moderate the risk around '21 and '22 volumes currently?

Okay. Yes, Dennis, I'm going to start off on this answer, and then I'll turn it over to in a minute to Adam Iwanicki, who is our Risk Manager and Marketing Director for the company. So, the first comment is that -- and this is a part that I want Adam to cover in greater detail later -- we do have a weak market in Europe, particularly for this winter and summer. The forward curve for European gas is in significant contango. As you go into winter 2021, it's much higher for next summer than it is today and continues into contango as you go into the next winter. The forward curve in our view is reasonably reflective of the fundamentals of that market. It's -- European gas has a more active set of both normally sellers, but also buyers who hedge into that market. And so you got a different market structure that has allowed for contango that does not exist in the oil markets where the -- really it's primarily -- the hedges are primarily the sellers. And that's a market structure feature that has probably restricted the longer-term prices in oil. So what this means is that as we hedge for the out years, we can do that still at quite strong prices for European gas prices that do ensure a lot of free cash flow and strong project economics. We're in a very strong hedge position for this year on European gas. It's outlined in our IR deck on the website. These hedge percentages for European gas and it's a whole variety of two-way three-way contracts with some swaps total about 78% of our expected production for 2020 and about 50% of our production for 2021. The hedge position continues on into 2022 and 2023. With the curve that exists, we are willing to further hedge into that curve, and I think you will see us doing that. The European gas forward curve is a hedging advantage that we have. It's not available to most of the other independent E&Ps, and it is something that we take advantage to lock down a portion of the cash flows for the -- not only for the current year, but for the later year period. I do want to turn it to Adam for a minute just to discuss the fundamentals and our view of the market.

Sure. Hi, Dennis. Yes, the current price weakness in Europe is really the confluence of a few factors. We've had two consecutively warm winters in Europe and warm winter in Northern hemisphere. And then, LNG supply growth globally has outpaced LNG demand growth namely in the Asian markets. And so, LNG has been seeking a home that home is Europe. This is not a stable or a situation that can continue into the future. If you look at LNG economics out of the US Gulf Coast, the arbitrage is right at the variable cost right now. And so, to get more LNG to these markets, prices just have to go up. And this is where we see improving price conditions going out into '21 into '22 and further '23. But as Tony said, we have 50% hedge level for 2021, 2022 are about 25%. The curve still does allow us to lock in very good economics for our gas production, and so we will continue to hedge.

Okay. Perfect. Thanks. I'll turn it back.

Your next question comes from Asit Sen of Bank of America. Please go ahead. Your line is open.

Thanks, good morning. Hey, Tony, on the capital flexibility, just wanted to make sure I got the two numbers right. Your sustaining CapEx you mentioned CAD410 million and then you mentioned you could potentially trim up to 15% if commodity prices weaken. Did I get those numbers right? So essentially getting back to sustaining CapEx would be what you're thinking about?

We haven't made a decision on reducing capital. We're going to look at the development of the markets and coronavirus and overall economic situation, while we complete the Q1 program. But your understanding of it is correct. I'll maybe just elaborate a little bit on the terminology. We estimate our seabed [ph] CapEx cutting the growth CapEx and some longer-term expenditures at about CAD410 million. We haven't made any decisions on a reduction in the capital program. But I think, if we are to do that, we would think in terms of reductions in the 5% to 10% to 15% range for the annual capital program. It is possible to bring down capital further than that. We'll have a little bit over half of our capital employed in Q1 with this strategy of front-loading. We did that in part to get some cost advantages on a bigger program. We did it because it's more efficient in terms of timing to generate more production for the year, and we did it to reduce risk in the capital program, risk that confronted us before like weather delays due to kind of a shifting wet season in North America in general and Alberta in particular. So, we have capability to go deeper if we needed to than 15%, but the scenarios that we're modeling would put us between this roughly 5% to 15% level at this point.

Great. Tony, that's very helpful. And again, a more difficult question, but when you're thinking through trimming CapEx, I know it's not easy to do. But could you kind of speak to potential areas you could revisit first to trim the drilling program?

Yes, we'd be looking at some of the later-year drilling that is -- that wasn't initiated in Q1. A portion of this would be in North America. And there are some European projects that could be delayed as well. And we'll look for other general efficiencies in the program. I mean, I feel we do have quite an efficient capital budget as it stands. Nonetheless, it's been our history ever since the oil price crash and even before that to grind costs out of our system, and capital has been a key part of that. We're not going to stop trying to find just those cost efficiencies today. So, it'd be a combination, but those would be the main drilling areas, I would say, that would be candidates.

Appreciate the color, Tony. Thank you.

Your next question comes from Josef Schachter of Schachter Energy Research. Please go ahead. Your line is open.

Good morning and thank you very much for taking my call. I have a few questions. You mentioned that your front-end load is about CAD200 million with that CAD450 million in the first quarter. You drilled 176 wells last year gross, how many do you see drilling in 2020 if you go with the CAD450 million budget?

Yes. Josef, thank you for the question. We'd be a little bit over 50% employment of the annual CapEx in Q1. So it would be more than the CAD200 million, I think our total is 55% that we're projecting for Q1. I can only give it to you in terms of net wells, but we project 116 net for 2020 currently.

So, the growth that might be given in comparison to the last year bumping it up by about 10% gives the difference between gross and net over the last year or so?

Josef, that sounds accurate, and I guess that would put us in the range of 130 gross. It seems like a reasonable estimate. I apologize just don't have that one at my fingertips.

No problem. Now, going to the spend of the money that you have for the rest of the year, last year you were able to spend in -- for the year CAD38.5 million on acquisitions and CAD9.2 million in the fourth quarter. In terms of drilling versus buying, given the problems out there in the industry with a lot of distress assets, are you finding in terms of the areas that you operate in Canada or Germany, where the chances of being able to be a buyer versus direct spend might be advantageous. Are you looking at things in that ilk?

Yes. With respect to acquisitions, we discussed in a few different forums that we're actually pretty unlikely to be an acquirer in Canada, and I think that would apply to North America as a whole. We feel like we've been through the property set that would be reasonably available within our operating core areas. We don't see the particular asset set of any meaningful size that would likely to be available that we think would be kind of a quality addition to our portfolio, and we're quite deep in our inventory already. In general, a slightly different set of reasons perhaps, the same thing applies in Wyoming. We don't think there is anything really dealable at a reasonable price adjacent to our core operating area and we like our position geologically exactly where it's at within the basin there, also with quite large and probably expanding inventories work the asset more. So, no, I don't think it's very likely. I mean, in general, probably even quite low cost and real high rate of return M&A. We would -- I'd say from this point forward, there is always a collection of very, very small land additions that could potentially be made. But I would say that even at the very low-cost and high rate of return M&A, we would probably -- if we did it, we probably seek to fund it out of the E&D budget just keeping a really strict focus on how much total CapEx we would be using.

One more for me. If we had a recovery in commodity prices, I'll say, Q4 we're back over $60 million, you probably generate CAD200 million for the quarter. So the dividend is CAD53 million, you might have $50 million for CapEx left in your budget. Would the extra funds go only to paying down debt or if you saw comfort in the CAD60 environment post the virus resolving, would you also activate the NCIB or is that a 2021 prospect?

Yes. With the set of numbers that you've laid out, CAD50 million of excess free cash, meaning cash beyond dividends. I'm not -- we'd have to check and see what price scenario that would be ended up -- that would end up being tied to. But I think that the direction of that magnitude of excess free cash would be debt reduction. At this point, it's our intent given the uncertainty that's developed in the economy over the past month to take that excess cash really and just use it to retire debt. In different macro environments, we have the option to employ the NCIB. We're not going to do that at this time because of the focus that we have on the balance sheet and really the great degree of economic uncertainty that the virus has created. So, yes, for the time being, it's all earmarked to debt reduction. It would -- the lowest priority use of additional cash flow on the total pool [ph] would be for capital increases. I don't think we're going to do that.

Thanks very much. That covers it for me. Thank you.

Thank you, Josef.

Your next question comes from Jeremy McCrea of Raymond James. Please go ahead. Your line is open.

Hi, guys. Just given the volatility in all the discussions and the questions here so far, and where you want your leverage ratios to be? I just want to going to get some more insight into the Board discussion on why the dividend wasn't a bigger cut, why you wouldn't take the opportunity to do more, pay down more debt, maybe even cut the CapEx just to get ahead of this volatility that we all kind of see is coming here?

Okay. Well, yes, Jeremy, on the question of -- I'll take the first one on the question of one on an earlier reduction in the dividend. Maybe I could use the slides that we have in the deck to run through maybe a longer term view of this first and then a shorter-term view second. So, I'll start with Slide 5, the kind of total uses chart that we have that incorporates dividend split historically into DRIP and cash and CapEx, but it also includes our expenses for ARO retirement. So, it's the full uses of cash for those three purposes. If you look at the first half of the decade, the payout ratios were in excess of 100%. The sea change -- the first sea change, I would say, in the industry occurred in 2014 with the reduction in commodity prices. We reacted and it took a bit of time to pull down -- further pull down the cost structure of the company. And a lot of this work has been going on even prior to the oil price crash. And the work was to move up the learning curve in the programs that we had to reduce cost and improve the productivity of the completions. It was a big changeover in the project slate. Certainly, post mid-'14 and especially once we got into 2015, we were assisted by oil service cost reductions which have persisted throughout this period. Through doing all those things and trying to enhance as well the cash flow profile of the company over the second half of the decade, we were able to get the payout ratio down very close to 100%. We didn't quite get there in '19, we're at 103%. We were determined to bring it down further. And as we're going…

Okay. I guess, I was just -- why wouldn't you have, kind of, say 70% or that now as opposed to -- like, just given how quickly your leverage ratios have gone up to -- I think you said 2.9 times at the current strip, like -- versus your target. So the payouts back down to 100%, great, but the leverage ratio seemed like they've gone up almost too much here, where you almost have to put the payout closer to, say, 85% or 90% just to pay down the -- get the balance sheet a little bit fixed sooner, I guess.

Yes. I'm going to start with that and then I'm going to turn it to Lars to discuss the composition of our balance sheet. But the pricing change has been very, very rapid. It changes a lot every day. And we can't say with any certainty if today's price is appropriate, if Wednesday's price was appropriate, if the price we had a week ago was appropriate. The market is very sensitive and we're going to take the time to see what the -- a little more extended oil market reaction is rather than we could -- rather than taking it on any single day's price. We can evaluate it at the strip on any day, but we're not necessarily going to change the dividend based on what it is on a single day. So, with that, I want to turn it to Lars to discuss the quality of the balance sheet.

Yes. Thanks, Tony. And Jeremy, we've discussed this in the past. And I think it's important to look at the construct of the balance sheet. So, first off, we do have the US senior notes that are termed out to 2025. What we just announced today as well was a one-year extension of the $2.1 billion covenant-based credit facility to May 31, 2024. Something that we look at, as well, in markets like these is that debt to FFO. We also look at the credit metrics. So we have three financial covenants on that credit facility, in terms of senior debt not to exceed 3.5 times; we're 1.57 at year-end '19, and then on total debt not to exceed 4 times, 1.94. I would call those two of the most stringent of the covenants that we have to meet during 2020. To put that 2.9 times into perspective, that would translate into about just under 1.9 times on that senior debt versus 3.5, and then about 2.3 times on the total debt relative to the 4 times. So, we are looking at things on a debt-to-FFO as well as debt-to-EBITDA perspective. I think, the other important part of it is liquidity that we were able to maintain. You are correct, in terms of not a lot of incremental cash flow to pay down debt at March 4 strip pricing, but at the same time, not a lot of absolute debt being added to the balance sheet as well. So those ratio is going up to that 2.9 times is really fundamentally caused by the underlying cash flows depreciating, but importantly we are targeting that 100%, which results in very little to no absolute debt being added.

Okay. Thanks, guys.

Your next question comes from Greg Pardy of RBC Capital Markets. Please go ahead. Your line is open.

Yes, thanks. I mean, Tony, just to be clear, smart in terms of addressing the dividend, I think you've kind of answered it in terms of evaluating the capital program and dividend in the context of oil market conditions. It's kind of full stop there, but just wanted to ask two quick ones. One is, just operationally, you alluded to a pretty big premium, I think, you're getting on your Australian barrels right now. Just curious how that's looking in the context of IMO 2020? And then, I just had a follow-up question on cash taxes.

Yes, I'll turn the Wandoo question to Adam Iwanicki. Thanks, Greg.

All right. So, we did participate in very strong IMO-related low sulfur fuel oil pricing, and that's basically what our Wandoo crude is pricing off of most of the fuel oil in Singapore, very strong over the first quarter. The majority of this production is tied to a one-year sales contract to some Japanese refinery buyers. And so we can't actually disclose all the details -- the economic details of that commercial arrangement, but they are protected at a higher price level.

Okay. So a significant premium to Brent continues to be right?

Yes, yes.

Okay. Okay, great. And then, just the other thing is, I mean the cash taxes were, I guess, a lot lower than we were expecting in the fourth quarter. Can we still use just that rule of thumb of 6% to 8% of pre-taxes as a reasonable proxy for cash taxes for modeling purposes this year?

Yes, thanks for the question, Lars here. I think that's a fair range to use. I think that as the commodity price environment depreciates, I would be comfortable sort of referencing a range of 5% to 6%. I think that 6% to 8% is when you get into a 50-plus environment. So, in the world that we are in right now for 2020, 5% to 6% is the right way to think about it on an overall corporate basis.

Okay, terrific. Thanks, guys.

Your next question comes from Mike Dunn of Stifel FirstEnergy. Please go ahead. Your line is open.

Well, thanks. My questions have been answered. That's all for me.

Your next question comes from Chris Varcoe of the Calgary Herald. Please go ahead. Your line is open.

Hi, Tony. Several of my questions have been answered, but I'm just wanting to be clear, what will be the trigger for you to make a decision if you decided to cut capital spending sometime later in the year?

Okay. Yes, we are going to watch this commodity price after the extremely high volatility we've had over the past couple of weeks. And I think that we'll be monitoring it through the end of Q1 as we complete that part of the capital program. And I think with each of the upcoming quarters, we'll be making a decision about whether or not we stick with the entire remainder of the program.

And just as we're sitting here, looking at oil at $42 and obviously you talked about the instability, do you view this situation similar to the price downturn of 2015-2016 or do you view this in a different light which requires a different kind of a response?

Yes, that's a very thoughtful question. Sometimes you can only view these things in retrospect. I think they are very, very different events. The one that began in mid-'14, with hindsight, it's clear what led to it. You had a big technological change, you had an enormous amount of capital that was available to the industry to be employed in this new technology of horizontal wells in ultra-tide reservoirs, using multi-stage fracs. And it was impossible for OPEC, I mean, Saudi Arabia in particular, to continue to accommodate that increase in US production by restricting their own output and that a big supply event even in -- even as we were having increasing demand all the time led to a very long-term change in prices. Nobody knows for sure. We try to understand all the fundamentals that we can, but it's going to be impossible for us to be exactly right about it, but we did feel that the oil market was coming back into balance. And that's after we had kind of a failed rally that began early in '16 and ended in the fourth quarter of '18. There was another smaller failed rally in 2019. We were in the midst, I felt, of a little bit more sustainable rally at the end of '19 and the early part of 2020, really largely restoring balance in the market with just a little bit of kind of probability of continued assistance from OPEC, while demand was continuing to grow. And that was even after you had the negative impacts from the trade war. So, what we've observed in 2020 is in a sense it's even more uncertain, because it's such a rapid adjustment to demand probably impossible and this is what the commodity markets are indicating, probably impossible for OPEC…

There are no further questions at this time. I will turn the call back over to Anthony for any -- for closing remarks.

Okay. So, thank you for -- thank you for participating in our Q4 2019 conference call. As has been our previous practice, our Q1 2020 call will be preempted by our AGM presentation on April 28. Thanks, again.

This concludes today's conference call. Thank you for participation. You may now disconnect.