Vermilion Energy Inc. (VET) Q4 2017 Earnings Report, Transcript and Summary

Good morning. My name is Sherine and I will be your conference operator today. At this time, I would like to welcome everyone to Vermilion Energy Inc. Fourth 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. Anthony Marino, President and CEO, you may begin your conference.

Thank you, Sherine. Good morning ladies and gentlemen, thank you for joining us. I'm Tony Marino, President and CEO of Vermilion Energy. With me today are Curtis Hicks, Executive Vice President and CFO; Mike Kaluza, Executive Vice President and COO; 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 fourth quarter and full year 2017 financial and operating results and our 2017 year end reserves and resource information, which was announced with our Q4 results this morning. Vermilion's Q4 production increased 8% from the prior quarter to an average of 72,821 boe/d. This increase was primarily driven by growth in Canada and the Netherlands, and the resumption of operations at Corrib, following unplanned downtime last September and early October as previously announced. Q4 production was partially restrained by cold weather in Canada late in the year, a force majeure event on a third-party gas gathering system in our Turner Sands play in Wyoming, and minor maintenance activities in Germany and Australia. Our annual 2017 production volumes increased by 7% or 3% on a per share basis to 68,021 boe/d at the lower end of our revised guidance range of 68,000 to 69,000 boe/d. As you recall we reduced our full year production guidance by 1,000 boe/d at the time of our Q3 release due to the unplanned downtime at Corrib. FFO in Q4, 2017, was $181 million or $1.49 per share, representing an increase of 38% from the previous quarter as a result of higher sales volumes and commodity prices. FFO for the full year was $603 million or $5 per share, up 18% from the prior year due to higher production volumes and higher commodity prices. We achieved this annual production and FFO growth on a total E&D capital investment of $320 million. We generated FCF of $282 million, which represents a 5% increase over the prior year and was more than sufficient to fund our dividend while enabling further debt reduction. As a result of the strong FFO and FCF profile, we achieved the total payout ratio of 88% in 2017, and reduced our trailing net debt to FFO ratio to 2.3 times in 2017 or 1.9 times based on Q4 2017 annualized FFO as compared to a trailing ratio of 2.8 times in 2016. Our Board of Directors approved a 7% increase in our monthly dividend to $0.23 per share from $0.215 per share, affected with the April 2018 dividend to be paid on May 15 2018. This is our fourth increase since we started paying a dividend in 2003 and we have never reduced our dividend. The increased dividend is readily funded within our projected FCF of the strip for 2018. After adjusting for the increased dividend we project the total payout ratio for 2018 of 87%, up modestly from 85% prior to the dividend increase. At the same time, we project 8% growth in production per share this year. Q4 operations review. I’ll now provide you with an update on operations starting in Europe. In the Netherlands, production increased 59% from the previous quarter to 9,400 boe/d following the amendment of permit restrictions on two of our pools and an inline test on the well that was drilled in Q3 2017. During the two months test period, this well, the Eesveen-02 in which we have a 60% working interest, reduced at a restricted rate of approximately 10 million cubic feet a day net of Vermilion. The well is expected to be on production in mid 2018. We also completed a 315 square kilometer 3D survey, our first new data acquisition since entering the Netherlands in 2004. In France, Q4 production increased 3% to an average of 11,200 boe/d with the increase primarily attributed to better well up time and ongoing well optimization. Activity during the quarter was focused on well workovers, advancing the drilling of two of our four Neocomian wells and preparing for the rest of our 2018 growing campaign. On the regulatory front, the French parliament approved the previously announced climate plan in December 2017. The new law prohibits the issuance of new exploration concessions and limits the renewal of certain existing production concessions beyond 2040. As we have previously indicated, we do not expect the new law to have a material impact on our future activity levels oil production profile. In Ireland, production from Corrib averaged 56 million cubic feet a day or 9,400 boe/d in Q4, a 15% increase from the previous quarter. As reported in our Q3 release, Corrib had an unplanned 31 day downtime period in September and early October. This downtime reduced Vermilion's Q4 production by approximately 1,200 boe/d and annual production by approximately 900 boe/d. We continue to work closely with Canada Pension Plan Investment Board and Shell on the transition of ownership and operations from Shell to CPPIB and Vermilion, and anticipate closing this transaction in the first half of 2018. In Germany, production in Q4 2017 averaged 4,200 boe/d, a decrease of 5% from the previous quarter. The decrease was primarily due to a temporary shut-in of one well in December for a SCADA installation. The well was brought back on production in mid Q1 2018. In Hungary, we were recently awarded a license for the Békéssámson concession for a 4-year term. The license is located adjacent to our existing Battonya South concession in southeast Hungary and covers approximately 330,000 net acres, more than doubling the size of our total land position in the country. Subsequent to year-end, we drilled and tested our first exploratory well at 100% working interest in the Battonya South concession. This well tested at a rate of 5.8 million cubic feet per day over the final two hours of the 22 hour test period at a stabilized wellhead pressured 1,065 PSI on a 0.55 inch diameter choke, and a shut-in well has pressure of 1,305 PSI. No water production was observed during the test. The well logged 21 feet of net gas pay with an average porosity of 31% from an Upper Miocene Pannonian sandstone occurring at a depth of approximately 3,450 feet. The well is expected to be brought on production in mid 2018. This marks the drilling of our first well in the Central and Eastern Europe business unit. In Canada, production averaged 32,900 boe/d in Q4, representing a 5% increase from the previous quarter and a quarterly record for the business unit. We drilled or participated in six gross 4.0 net Manville wells and brought on production nine gross 5.5 net Manville wells in Q4, which contributed to this growth. Subsequent to the end of the year, we announced an acquisition of a private southeast Saskatchewan producer for total consideration of $90.8 million. The acquisition added over 1,000 barrels a day of high net back 40° API oil and 42,600 net acres of land straddling the Saskatchewan and Manitoba border, near Vermilion's existing operations in Southeast Saskatchewan. The acquisition closed on February 15, and our team is now integrating these assets into our southeast Saskatchewan operation. In the United States, Q4 production averaged 750 boe/d, a decrease of 27% from the prior quarter. The drop in production was due in part to a force majeure event on a third-party gas gathering system, which has recently been brought back into service. Capital activity in Q4 was focused on the construction of three well pads in preparation for five gross, 5.0 net well 2018 drilling program. In Australia, Q4 production decreased 9% from the previous quarter to 5,000 barrels per day, primarily due to plant maintenance during the quarter, which was over an eight days of downtime. We continue to focus on maintenance and debottlenecking activities and planning for our 2019 drilling campaign, which we expect will restore production volumes to our long term target of approximately 6,000 barrels per day. 2017 reserves and resources. We continue to grow our reserves and resources in 2017. Based on an independent report by GLJ as at December 31, 2017, our 1P reserves increased modestly to 176.6 million barrels equivalent while 2P key reserves increased 3% to 298.5 million barrels equivalent. We replaced 103% and 134% of production at the 1P and 2P levels respectively in 2017. PDC reserve increased 1.3% to 123.8 million barrels equivalent at an average PDP F&D cost including future developments capital of $12.41/boe resulting in a PDP operating recycle ratio including FDC of 2.4 times. Our PDP reserves represent 70% of 1P reserves. Our organic 2P F&D cost including FDC, increased to $10.57/boe in 2017 compared to $5.57/boe in 2016. The largest driver of the increase in F&D cost was the strengthening of the euro relative to the Canadian dollar in GLJ's foreign exchange rate forecast as compared to the previous year, which increased FDC for our European properties. As a result of this higher F&D cost, our F&D operating recycle ratio, including FDC, decreased to 2.8x -- 2.8x in 2017 compared to 4.9x in 2016 and 3.6x in 2015. Despite the increase in reported F&D cost and the reduced recycle ratio as compared to 2016, these metrics remained strong relative to the oil and gas sector and reflect a significant improvement in capital efficiencies we've achieved over the last several years. In addition to growing our reserve base, we pursued various initiatives to expand our resource base to support our longer term growth profile. According to the independent report by GLJ as at December 31, 2017, our 2017 Resource Assessment indicates a risk best estimate for contingent resources of 176.7 million barrels equivalent in the Development Pending category and 32.8 million barrels equivalent in the Development Unclarified category. Over 80% of our risked contingent resources reside in the Development Pending category. Prospective resources were assessed at a best estimate of 153.4 million barrels equivalent. In 2017, we converted 205 million barrels equivalent of contingent resources and 1.7 million barrels equivalent of prospective resources to 2P reserves illustrating that our contingent and prospective resource bases remain at source of reserve additions. More detailed information on our reserves and resources can be found in our AIF and reserve press release issued this morning. Organizational update. We have several leadership changes that we announced with our Q4 release. All of them are internal promotions following the retirement of two of our existing leaders and equation of the new operating business unit in Ireland. I’ll provide a brief summary of these changes and lead you to review the individual biographies that are included in our press release. Curtis Hicks, currently Executive Vice President and Chief Financial Officer, is retiring effective in 2018 after 15 very successful years with our company. Curtis has been a key member of the executive team helping to guide Vermilion as we have expanded from two countries in 2003 to 10 countries today. We thank Curtis for his numerous contributions to Vermilion and wish him the best in his retirement. And let me say more personally that Curtis has been an extraordinary friend and colleague for me at Vermilion. I’ll miss his intelligence, kind manner and professionalism and I’ll also miss his participation in these quarterly calls. Internal promotion, leadership development and succession are very important at our company. The CFO role is a critical one and we have been fortunate to have a long time to prepare for Curtis’s retirement. Lars Glemser, currently our Director of Finance, will succeed Curtis as Vice President and Chief Financial Officer. Lars joined Vermilion in 2015 as Operations Controller and progressed through a developmental assignment in Investor Relations before becoming Vermilion's Director of Finance. A number of you may know Lars for his work and investor outreach both in his previous IR role and as Finance Director. While we miss Curtis, we are delighted to be able to effect his seamless transition and we are excited about working with Lars as Vermilion's CFO. In our operating units, we regularly rotate and refresh our leadership and maintain a mix of expatriate and national management in our non-Canadian businesses. In line with this philosophy, we are proud to announce a series of interlocking managing director appointments. Scott Seatter, currently Managing Director of the Netherlands Business Unit, will take over his Managing Director of the United States Business Unit. Scott replaces Dan Anderson, our current Managing Director in the U.S. who will be retiring in April 2018. I have had the honor of working with Dan several times in my career and I’d like to thank him for his contributions for Vermilion and wish him the best in his retirement. Replacing Scott in the Netherlands is Sven Tummers. Sven was previously commercial manager for us in the Netherlands and now has been promoted to Managing Director of the Netherlands Business Unit. In anticipation of the transfer of Corrib operatorship to Vermillion after the CPPIB Shell acquisition closes, we have created a new operating business unit in Ireland. Darcy Kerwin, previously Managing Director for our French Business Unit has been appointed to the newly created role of Managing Director, Ireland Business Unit. Replacing Darcy in France is Sylvain Nothhelfer. Sylvain was previously Technical Services Manager for the French Business Unit and now has been promoted to Managing Director of that unit. I am confident these appointees will continue to contribute to our safe and successful global operation in their new leadership roles. That concludes my planned remarks. We would be happy to address any questions that you might have. Operator, would you please open the phone lines to questions?

[Operator Instructions] Your first question comes from Dennis Fong from Canaccord Genuity. Your line is open.

Hi, good morning, guys. So just with this first well in the Hungary, given some of the relative successful tests, how should we think about the potential acceleration of CapEx in the country or is it maybe a little bit premature? And then secondly, how many wells you have committed via this license agreement that you have as well? Thank you.

Okay, Dennis, thank you for the question. We are really happy with the successful test that we had in Hungary. It will -- we believe generate production a couple of years earlier than we anticipated production beginning for the central and eastern Europe business unit. We have remaining - and answer to the second part of your question, we have remaining on Battonya South one well commitment, probably that well would get drilled in 2019. As part of the acceleration of activity, in Hungary or in the rest of the CEV, we have a lot of good prospects, I feel, in each of these countries. We have this type of gas drilling that we just announced in Hungary, available to us, and again at least one more well on Battonya South. We just, last summer, shot a 3D in Slovakia. This is a place that had very well seismic coverage, really just a few lines of 2D, some discoveries had been made on that very sparse 3D few decades ago, some were tied in, some tested at quite reasonable rates and we are not tied in. And so we felt there was a great deal of potential there as has been observed many times in the past across the world. To shoot a 3D in a place that prior only had 2D, and as I will point out, it was very sparse to the degree than previously in Slovakia. Typically when you do that in a place where it has been success on 2D, 3D before, you can find a lot of new prospects on 3D, and I am very-very optimistic about that program. It’s primarily a relatively Shell gas program most of the targets in 500 meter to 1,200 meter range. We do think from the very preliminary 3D interpretation that we've done there. There’s a perhaps a deeper set of targets as well. We may look at the possibility of accelerating that program given the data that we now have and probably relatively short permitting times there. At present there's no change for our run rates plan, but that is one possibility for acceleration. In addition, in Croatia, we're the largest oil and gas rights holder onshore. We took some successful 2D data there over the past year and we have those wells slated to wells that we intend to drill that are slated for the next couple of years, potentially beginning in 2019. And I don't really have any comment about whether we have an acceleration there or not. I think we're going to acquire some additional seismic, as part of that program and that might affect our decisions there. So that that really covers that business unit in terms of the activity, but we are very pleased with the results that we had on that first drilling, and I am optimistic that over the medium to long term, that can become a significant business unit for us in Europe as have the other countries that we've established a franchise in previously.

Okay, perfect, thank you very much.

Your next question comes from Tom Callaghan from RBC Capital Markets. Your line is open.

Hey, good morning guys. Just wanted to inquire on cash taxes there and specifically any color you may be able to provide around 2018 in terms of what you're expecting?

Sure, Tom. So for 2017, what happened in Q4, there was an administrative change in the Netherlands with respect to how we deal with ARO deductions and we are able in the Netherlands and in France to deduct future ARO on a unit of production basis. So we were able to -- there's a one-time acceleration that happened in Q4. It was about a $10 million positive impact to Vermilion. So that resulted in frankly in a claw back in taxes in Q4. So if we look out to '18, we see some modest increase in tax rates in France, from about 7% in '17 to sort of 10% to 13% in '18, in Australia, a modest increase from about 26% in '17 to sort of 30 to 32% range in '18. And then we see a big impact in the Netherlands. We had a negative tax rate this year because of the ARO deduction and that you know we're going to go 25% to 28% tax rate in '18. And that's a function of two things, the ARO impact that doesn't happen again in '18, but also we've had a significant shift in our production profile in the Netherlands. As we previously discussed, we had some regulatory issues that we dealt with this year, and as a result our production was held back. We see good production gains in 2018. And frankly that's going to be all taxed at the marginal rate because all of our shelter will have been used up with sort of the base production. So those are the two key considerations for why taxes are going up in the Netherlands in 2018. So overall, on a corporate basis, we were just around 5% this year on a cash-taxes basis, and we're going to go from about 11% to 14% range in 2018.

Perfect. Thank you very much.

Yes, you bet.

[Operator Instructions] Your next question comes from Patrick O'Rourke from O'Rourke Capital. Your line is open.

Thanks guys and congratulations on the retirement of Curtis. I'm going to miss you on the call here and thinking on about. Just a couple of quick questions, took a field mine on Hungary, but just curious in terms of specific well costs there, and then in terms of market access for that gas, would you be modeling that as - I know, it's pretty interconnected in Europe. Is that TTF type or German type pricing there?

Patrick, thanks for the question. For that well, probably typical work as the type of drilling we're doing in Hungary now. The cost would be about €2.6 million for the DCET to get it away from drilling to tie in, putting it around CAD 4 million. So they are pretty inexpensive wells for the potential production that is available. The price there is based on TCF, the European market really what the exception maybe if the Iberian Peninsula is very well interconnected. And, so with very minor basis between these various delivery points, the pricing is close to that TTF price. And the European market is one that continues to be very strong; in fact, there have been some very high gas price spikes very recently over the past week to some extraordinarily high levels due to very cold weather on the continent and in some cases due to lower production. So we expect it to continue to be a strong market, it’s a good market to hedge into and it’s a key part of our strategy.

Okay, great. And then just a second question, in terms of the Saskatchewan acquisition that you guys did, looking out there, are there rollup opportunities in the similar sort of size and nature available out there that you will be looking at it as just an asset you want to continue to grow or just strategically how you're looking at it at this point?

Well, I mean, the Saskatchewan in general and southeast Saska, specifically are excellent places to produce. You got good regulation, you have very low provincial loyalties, a lot of incentives to produce, you've got a great work force there, so it’s a desirable area from most perspectives. The light oil, which is by far the dominant product, there is just a little bit of gas, no heavy oil. The light oil in southeast Saska growing at a very high price. It's downstream of any auto mix, so it’s not subject to some of the other proms you get with, for example, WCS pricing in Canada. All these things make the region desirable. It is our next to west-central Alberta. It’s our other core area in Canada. It’s a place that we can very effectively execute our growth and free cash flow model. So we're very happy with the acquisition that we made of that little bit over 1,000 day barrels of very high netback oil that we closed in February. As with our other core areas in Canada and throughout the world, we are open to adding to those positions. We feel that we conduct our M&A activities, evaluation bidding, potentially closing transactions in a very disciplined fashion. So every deal that we would make has to test and has to pass the same set of tests. We don’t use an optimistic price aspect. We use the backward aided strip to evaluate. And then with that, we have the great fuel accretion for our owners, not out of leverage, but out of a real accretion assuming in these evaluations that we would have used all equity to finance. And this rate of return, well in excess of our cost of capital under that backward aided strip and it has to be capable of generating sufficient cash flow to cover its own CapEx stream to grow in any - and its share of any imputed dividends under the strip again. So these are very difficult tests for any asset to meet and they’re intended to ensure that when we make a deal, it adds to the value of the company for the existing owners. So, southeast Saska additions any further additions to the portfolio would be the same as anywhere else in the world. They have to meet those tests and it’s not a very easy set of criteria to meet. Therefore, we are open to it, but I wouldn’t call it likely that we continue to acquire in any particular area. I think it will happen over time. We can’t predict exactly when it would occur, but there’s nothing intending. And the main thing I want to leave you with is that if we were to make another deal there or in any other region, we’d be very confident that it’s adding to the sustainability of our model and to the value of the company for the existing shareholders.

Okay. And final question just very quickly before I hang up and listen here. In terms of Irish, the core of asset performance, I know, natural onset declined. We're sort of expected here in the first part of 2018. Just any change in that view or how the assets performing right now?

We have no change in that view. The core that's performing as we expected, at this point, it outperformed right up to the end of the year, having a significantly longer plateau at the midpoint than our midpoint expectation. And from here, we expect a decline rate that is in line with our previous forecast.

Okay. Thanks for that.

[Operator Instructions] We do not have any questions over the phone line at this time. I will turn the call over to the presenters.

Thank you again for participating in our Q4 and year end conference call. As a reminder, our 2018 AGM presentation will preempt our Q1 2018 conference call. We therefore look forward to speaking with you again after our Q2 2018 release in July.

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