Vermilion Energy Inc.
Q4 2015 Earnings Call Transcript

Published: 29 Feb 2016

[Operator:]

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 Year-End 2015 Operating and Financial 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. Lorenzo Donadeo, CEO of Vermilion Energy, you may begin your conference.

[Lorenzo Donadeo:]

Thank you, Connor. Good morning, ladies and gentlemen, and thank you for joining us today. I am Lorenzo Donadeo, CEO of Vermilion. Joining me today are Tony Marino, President and COO; Curtis Hicks, Executive Vice President and CFO; and Dean Morrison, our Director of Investor Relations. Please refer to the advisory regarding 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. This morning, we announced a record annual production of 54,922 BOE per day for 2015, an increase of 11% compared to 2014. Strong operational execution allowed us to achieve this record production, despite a nearly 4,000 BOE per day shortfall and anticipated Corrib volumes associated with regulatory delays, and a 30% decrease in exploration and development capital spending as compared to the prior-year. Annual fund flows from operations was $516.2 million or $4.71 per basic share in 2015, as compared to $804.9 million or $7.63 per basic share in 2014. Higher production during the year, partially offset the impact of a nearly 50% drop in oil prices. Fourth quarter fund flows from operations was $1.22 per basic share, beating analysts’ consensus of $1.11 per share by 10%. This month - this morning, we also released the details of our reserves and resource evaluations for 2015. As reported both proved and proved plus probable or 2P reserves by 6% in 2015 to 161 million BOE and 261 million BOE, respectively. At the 2P level, we successfully replaced 170% of 2015 production adding 34 million BOE of 2P reserves. 30.5 million BOE or 90% of this growth came from exploration and development activities, with the remaining 3.5 million BOE coming from acquisitions. Our 2P finding and development costs including future development costs or FDC, decreased by 48% to $8.98 per BOE, while 2P finding, development and acquisition costs, including FDC, decreased 55% to $10.03 per BOE. Despite lower netbacks in 2015, the significant decrease in finding and development costs generated an operating recycle ratio of 3.6x for 2015 versus 3.2x in 2014. Our fully burdened after-tax cash based recycle ratio also remains strong at 2.9x. This demonstrates our ability to not only maintain, but improve our high level of investment efficiency in 2015, despite the decline in commodity prices. Our 2015 reserves report was supplemented with an evaluation by GLJ of our contingent resources in the Development Pending category. The low best and high estimates of our contingent resources in the Development Pending category are 95.1 million BOE, 160.7 million BOE and 254.7 million BOE, respectively. Approximately 80% of our best estimate contingent resources reside in the Development Pending category, reflecting the high-quality nature of our contingent resource base. While we have been faced with depressed commodity prices and significant volatility, the three key tenets of our long-term strategy remain intact. These guiding principles have allowed Vermilion to weather the many highs and lows experienced during several challenging business cycles over the past two decades. They underpin the sustainability of our business model, our strong position in the industry and our track record of outperformance. The three key priorities encapsulated within our long-term strategy in order of importance are

[Operator:]

[Operator Instructions] We’ll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Travis Wood with TD Securities. Your line is open.

[Travis Wood:]

Yes, good morning guys. Just some questions on the dividend and the capital program as we look out in this, we’ll call it, $35 oil price environment. When you talk about balancing the cash flows, what other metrics are you looking at in terms of keeping the liquidity and the leverage position intact as you look to move capital or the dividends in this lower for longer environment?

[Lorenzo Donadeo:]

Thanks Travis. Yes, I mean, I think the thing that we are really focused on is maintaining, first of all, our financial flexibility. As you see, we've got considerable financial flexibility with our available bank line that's unutilized at this point in time. The other thing that we are doing is we are adjusting our capital spending, so that we stay pretty close to about a 100% payout net of the dividends. And so really those would probably be the two primary factors that we look at. The debt to cash flow is moving up like in line with most of our peers, maybe a little bit lower than some of the peers. And although we are not comfortable at those levels, I think that they are manageable, because we don't believe that oil prices are sustainable at this level and so we are really just focused on minimizing any incremental debt that we put on the balance sheet. We always say that we really don't have a debt to cash flow problem. We have a cash flow problem, not a debt problem, and because we really do believe that oil prices will strengthen going forward and we think we can manage our debt levels under that type of a scenario.

[Travis Wood:]

Okay. So safe to say that you're targeting - of the outputs, you're targeting to keep the payout at a 100%?

[Lorenzo Donadeo:]

Yes, and I think if we were to look at any acquisitions that were larger in size, then we'd always have to look at what kind of cash flow that brings to the company and how it all fits in with the overall debt levels.

[Travis Wood:]

Okay. Thank you very much.

[Lorenzo Donadeo:]

Yes. Thanks Travis.

[Operator:]

Your next question comes from the line of Kyle Preston with National Bank. Your line is open.

[Kyle Preston:]

Yes, thank you. Good morning guys. Congratulations on a good quarter in this challenging environment here. Just got a couple of questions for you. The first one on these two sidetrack wells you're going to drill in Australia. I guess, you are planning to do that in Q2. What kind of - are you expecting similar rates for this last well you just drilled, and also will you look to manage that production between the 6,000 and 8,000 or potentially produce above that?

[Tony Marino:]

Yes, Kyle, the answer to both of your questions is, yes, we'll have probably quite high productivity out of each of the next two wells. The exact rates are a little bit hard to predict, but dating back to the ‘13 program and including the well that we drilled last year, we've always had rates that are in the 4,000-plus barrel a day range for a well on - putting the wells on production. The second ,question we would look to manage that production and probably keep it in the range of the mid-point that you talked about, somewhere in the range of 7,000 barrels per day would be our expectation for this year. So we would be husbanding some productivity that we could apply in future years to maintain flat to growing profile out of Australia ensure that we can supply the market for this valuable crude over the long-term and probably not have to apply very much capital in the next couple of years if we are in fact able to get the types of wells that we have drilled over the recent past.

[Kyle Preston:]

Okay, great. Thanks for that. And just another question here, just on Corrib. Once we had Corrib up and running at capacity, what does your operating cost profile look like there? And then just related question, what's your view on European gas prices going forward?

[Tony Marino:]

Okay. On the first one, what would Corrib OpEx look like? It's going to be a relatively low OpEx property. We are just in the early phases of collecting actual operating data, but we do believe that an OpEx of around $1 dollar Canadian per MCF is a reasonable level. Perhaps it’ll start out a little bit higher than that, but we think over time it ought to trend to around a $1 or less. These are high productivity wells. There shouldn't be a great deal of continuous maintenance activity, and therefore the unit OpEx should be pretty low. And that of course is going to lead to quite a high netback in the diverse market where we get pricing that is pretty close to national balancing point and where the fiscal regime established by contract has no royalties and we are tax-sheltered for some period of time. Even beyond that - beyond that netback, we should see quite an excellent translation to free cash flow because we don't expect that much in the way of maintenance capital. So the project has been a long time coming, but we certainly do think we are going to see quite a significant contribution to FFO and really strong translation to free cash flow out of the property now that it’s on production. With respect to European gas prices, they have declined quite a bit from where they were at a year ago. Currently reported in Canadian dollar terms, the two main markets in Europe for - that we report TTF in the Netherlands and the NDP in U.K. are in the range of $6 to maybe $6.25 Canadian per MMbtu. That surprised that is a lot stronger than the one that we have in North America, but it is down a third or in fact a little bit more from where we were maybe a year ago. That decline has been driven by several factors. One is that it was a very warm winter in Europe. Second is that there is an expectation in the forward curve which is fairly flat at that price that there will be deliveries of LNG from the U.S. into the European market. And thirdly, from some work that we've done in-house, we think that there is just a greater degree of correlation between European gas and crude oil and some of the other financial markets than had existed in the past, used to be that market completely had a mind of its own, but we are starting to observe this greater degree of correlation. And I think all three of these factors have led to the reduction in European gas prices. This reduction actually isn't outside the realm of what we thought could happen. We do think that it probably represents something of the lower end that you would see in prices and that there is upside from here. In our investors’ materials, we've outlined a couple of pages of explanation of what we see as the fundamentals in that market. And basically we see a market where probably supply and demand should be pretty well-balanced over the next few years and that includes even having significant deliveries of some of these stray cargoes of LNG from the U.S. into Europe. We do think that longer term these European prices will not incentivize LNG built for the European market. We think that that will take the something in the range of $8.50 Canadian per MMBtu or a higher price, and actually the prices that exist today will barely support the deliveries of these unassigned cargoes into the European market. Yes, it's economic to provide them, but not nearly as economic probably as the LNG companies had expected. So for this and a variety of reasons, including switching from coal to gas and the U.K., which is already incentivized for the carbon floor and the potential for more coal to gas switching on the continent in the future, as presumably carbon floors continue to increase, we think that - it's fundamentally - it's a market that fundamentally supports the prize we have today and the forward curve reflects that. I would finally point out that we are quite significantly hedged for the European gas, 44% for 2016. We have some long-term hedges that extend into 2017, and in fact into 2018. We think that the price that we get there today is an acceptable one from a standpoint of development activities for gas in Europe and also from a standpoint of our willingness to continue to hedge at this price, so we do remain moderately active in that market adding to this substantial hedge position that we already have in place. So fundamentally we’re constructive on this market and we feel that pricing that we have can give us quite a lot of profitability.

[Kyle Preston:]

All right. Great. Thanks Tony. That’s it for me.

[Tony Marino:]

Thank you, Kyle.

[Operator:]

Your next question comes from the line of Nima Billou with Veritas. Your line is open.

[Nima Billou:]

Good morning. Just wondering how much longer - I mean, you’ve done a good job, and obviously, it's due to the investment in DRIP being able to reduce CapEx, but still maintain production guidance. How much longer before this reduced investment starts to catch up with production volumes and where could you see that heading first? Obviously you’re constructive on prices recovering, so you'd want to increase investment in the future but should they stay low, when would we start to see the effects of this sort of reduced investment?

[Tony Marino:]

Yes, we have been able to - as you said Nima, we have been able to absorb quite a substantial reduction in capital and maintain the productivity in 2015 and into 2016 as well in our guidance. This is due to greater efficiency out of the projects. Part of this is certainly due to the reduction in services prices, part of it we think is durable just in terms of learning curve, process improvements that we made on the cost side. And on top of that, we actually continued to get higher productivity both in our semi-convention development that we have in North America and in fact in the conventional assets in Europe and Australia as well. So it's really, I would say, a broad-based improvement in the capital efficiency of the company, starting at already very strong levels but it in fact has moved up substantially over the last couple of years and that's reflected also in the FD&A cost and in the recycle ratios which have actually gone up for us in 2015 versus previous years. As we look ahead to 2017, we do expect a significant uptick in the average production from Corrib for the year, and that alone, probably in part something like a 5% or so increase to our company's production level. And this is a nice structural advantage that we have in our ability to maintain rates, and in fact maintain growth even at lower capital levels. We haven't yet constructed the capital budget for 2017, and that will be a driver of how much production growth overall we are able to achieve. I'd be hopeful that given the continued progress that we have made in cost and productivity that we'll continue broad-based growth in the company, but we'll actually have to look at the budgets as we approach ‘17 to be able to definitively give you an answer on that.

[Nima Billou:]

Appreciate the candor and the detail. Final question, you had mentioned that basically your funds flow would be balanced this year. I just want to get an understanding, it would be balanced with CapEx and dividends, correct? Is that what you meant?

[Lorenzo Donadeo:]

Yes.

[Nima Billou:]

Okay.

[Lorenzo Donadeo:]

It would be basically cash flow net of our net dividends and net of DRIP and capital spending would be close to being balanced.

[Nima Billou:]

What commodity you had said more strip more, it sounded like current pricing. What commodity assumption feeds into that analysis broadly? Is it $30, $35 oil?

[Lorenzo Donadeo:]

Yes, it was at the - I think that was at our - the most recent strip pricing as of about a week ago. So I think it's somewhere around $35, $36 WTI.

[Nima Billou:]

Okay. You guys are doing a very good job managing your business under difficult commodity conditions.

[Lorenzo Donadeo:]

Well, thank you.

[Nima Billou:]

My final question I would say is, where - when things do recover, where would be priority areas? Would it be - I guess, you probably more constructive on domestic light oil pricing and may be international gas pricing but where would the areas you’d first like to put money to work?

[Tony Marino:]

Yes. We actually have a really broad-based set of alternatives to invest in kind of during this low activity that we've begun in ‘15 and now to a greater degree in ‘16. We actually find that we are able to advance a lot of these projects technically, and in terms of the expected economics cost levels and productivities such that we got a lot of choices. But let me list probably the top three places I think that we would go back to - three or four places that we would go back to in a moderately higher capital world. And in so saying to, I want to point out that the required capital levels that we would have to have growth at our targets organically in the mid-single digits are probably a lot, lot lower than they have ever been in the past. So even a significantly increased organically growth rate would probably be done at quite a bit lower CapEx than you would have seen a couple of years ago. But to list those projects in order, I think number one, we would resume Netherlands gas activity. Secondly, we would like to go back to the French light oil projects. Thirdly, the Mannville project in west central Alberta has tremendous economics, even at the current prices, even at the quite low gas prices that we are seeing in Western Canada today and that's because there is so much condensate being produced, essentially at no discount to WTI out of those Mannville Wells that it alone can carry the economic before you ever account for the NGLs and the residue gas. And then fourthly, we'd like to see a resumption of more significant activity in the Turner Sand light oil price project in Wyoming. This is all before we get to more activity in the Midale in southeast Sask where the economics have improved dramatically with way, way lower cost than we had at the time for the wells that we drilled and completed there versus what we had at the time that we made the entry at the southeast Sask a couple of years ago, that's before any activity in the Cardium, which has always been a very strong project and we have had - we have no drilling plan for ‘16 and only a little bit in ‘15, so there are a large number of strong Cardium wells alone that we could turn back to in resuming the program. And I’d say finally that this is completely without - this is completely ignoring the very significant dry gas opportunities that we've developed in west central Canada as well where we drilled some very, very strong amount of Notikewin wells that are capable of being economic even in the current environment. Finally of course we'll have our ongoing planned activity in Germany for European gas under the very significant farm out that we did with ExxonMobil and Shell which closed at the beginning of this year. So I think there I probably listed seven or eight places that we can turn with the kind of an order of preference for the way we would attack those projects.

[Nima Billou:]

Yes. Thank you for listing them in priority. That's a lot of good information you should be thinking ahead. Thanks for the information.

[Lorenzo Donadeo:]

Yes, thank you.

[Operator:]

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

[Greg Pardy:]

Yes. Thanks. Good morning. Tony, could you perhaps just touch on your Canadian gas volumes in the fourth quarter? Really strong numbers there. And maybe just as a follow-up on your comments around CapEx. I mean, from the sustaining CapEx standpoint now ex-Corrib, are we - is $235 million or $225 million now a pretty good number to think about going forward? Thanks very much.

[Tony Marino:]

Thank you, Greg. Let me take, first of all, your second question on the sustaining CapEx. Your rough estimate of $235 million I think is not a bad one at all for the level required to stay flat, and of course, as we are talking about one of the previous questions, that is going to be way, way down from where it would have been a year ago or two years ago, even though the company has grown significantly in production volumes. So I would say somewhere in that range, perhaps a little bit more, perhaps a little bit less in the $235 million, but I think that is pretty close to a reasonable estimate. With respect to your question about Canadian natural gas production in Q4, it was strong. It was strong for two reasons. First of all, it was augmented by the well that I talked about earlier. We drill about a 13 million cubic-foot a day producer in the Notikewin in our Ferrier area which is kind of a new core area for us that we haven't talked about very much before, and two-mile my long multistage frac well that is probably one of the top few gas producing wells in Alberta. It's an extremely productive area. We have a great deal of inventory in Ferrier. At present, that well, like the other ones that we would drill probably over the next couple of years, there would be expiry-driven, it's not a place that we are putting very large amounts of capital in just because of lower gas prices that we have in Western Canada. Nonetheless those wells are actually quite economic at current prices just because of productivities are so high, the costs are coming down. They are not really all that expensive to drill and complete. The other driver for the increase in gas production was just the residue volumes that we make as sort of a byproduct in the Mannville wells around 40% to 45% of the stream from those wells is hydrocarbon liquids and about three-quarters to 80% of that is condensate, but there still is a meaningful residue volume and well not really required for the economics of those wells, it is a saleable product, and as a result, it augments the cash flows and it's the other reason that you see a little bit higher natural gas production in North America in Q4.

[Greg Pardy:]

Okay, great. And what did the Ferrier well cost you just D&C?

[Tony Marino:]

I think for that two-mile long Ferrier, which is - for the two-mile long Notikewin well at Ferrier, we are in the range of $5 million to drill and complete.

[Greg Pardy:]

Okay. Thanks very much.

[Operator:]

Your next question comes from the line of Ray Kwan with BMO Capital Markets. Your line is open.

[Ray Kwan:]

Yes. Hi guys. Just on Corrib. Just wondering how many more wells are planned to be put on production before year-end and just for clarification for my sake, is the 5,500 BOEs a day that’s producing from Corrib, that’s net to you guys. Is that still from two wells? And I guess, the last question on Corrib, and this is just purely out of curiosity is just, have you seen anything noticeable, or is it kind of in line with your expectations in terms of the water to gas ratios? That's it for me.

[Tony Marino:]

Okay. In order, they are first how many wells are on, how many are left to bring on? Two of the six are on. The rest will be brought on this year including the P2, which was last well to be made available and there is still a short flow line segment that has to be run to tie it into the subsea manifold next to the current Q2. The second question, does that 5,500 BOE/d that we are currently producing net to our interest come from the just the two? That is correct. And third question, are those rates in line with what we expected? They are very nearly exactly what we budgeted. We would say that the productivity indexes from the wells that are on - the productivity indexes from the wells that are on are probably better - are certainly better than we expected. Secondly, we've been pleasantly surprised that there hasn't been any major source of downtime. There is, as with any start-up, there is - there have been minor downtown items and that's why we are still on the budget, even though I would say the PIs are better than expected. Furthermore at present, well, the midstream utility is doing its integrity testing on the new segment of pipe that was put in for the project a few years ago, the top rates from the field are limited in any case, so you can't really take advantage of the better productivity right now. The fourth question with respect to water gas ratios. I've not seen any report of water being produced yet from the field, so there is nothing to report there.

[Ray Kwan:]

And in the two wells that are on right now, are they restricted whatsoever or is it just kind of on?

[Tony Marino:]

Yes, they are restricted.

[Ray Kwan:]

Perfect. Thank you.

[Operator:]

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

[Lorenzo Donadeo:]

Great. Well, thank you, Connor. Thank you everyone for participating in our conference call, and thank you all for your continued ongoing support.

[Operator:]

This concludes today's conference call. You may now disconnect.