Vermilion Energy Inc

TSX:VET

Earnings Call Transcript 2019-Q3

[Operator]

Thank you for standing by and welcome to the Vermilion Energy Inc. Third Quarter 2019 Earnings Results Conference Call. [Operator Instructions] I would now like to hand the conference over to your speaker today, Mr. Anthony Marino, President and Chief Executive Officer of Vermilion. Thank you. Please go ahead, sir.

[Anthony William Marino, President, CEO & Non]

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'll be referring to a PowerPoint presentation to discuss our third quarter 2019 financial and operating results and 2020 capital budget. 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.I'll start off with an overview of our Q3 results, followed by a discussion about our 2020 budget and business model.Slide 4, Q3 2019 Review. Our third quarter operational results were impacted by plant turnaround activity, unplanned downtime, weather-related delays and a moderate carryover impact from the refinery outage in France that began in the second quarter. Our Q3 production decreased by approximately 5,800 boe/d or 6% from the prior quarter to 97,200 boe/d. The bulk of this variance, about 4,300 boe/d, was due to a very high level of unplanned downtime and weather delays. Although we budget for typical levels of unplanned downtime and weather conditions, these factors affected our Q3 results to a much greater degree than we had expected. Despite the lower production and commodity prices, we generated FFO of $216 million in the third quarter, which was down 3% from the prior quarter. Our quarterly FFO benefited from hedging gains, lower G&A expense and lower taxes.We have reduced our 2019 capital investment guidance by $10 million to $520 million as a reflection of a lower growth strategy, which I will discuss shortly. We've also revised our 2019 annual production guidance range to 100,000 boe/d to 101,000 boe/d from 101,000 boe/d to 106,000 boe/d to account for the unplanned downtime, weather delays and our lower capital program. We expect to deliver at the midpoint of this revised production guidance range, still reflecting strong year-over-year production per share growth of 5%.Now I'll get into some of the country-specific updates, starting with our international regions. Slide 5, Europe Q3 Highlights. Q3 production in France increased 6% from the prior quarter to an average of 10,300 boe/d, primarily due to the restart of the Grandpuits refinery in early August. That impact from the refinery outage reduced our Q3 2019 production volumes by approximately 400 boe/d. Almost all of our wells in the Paris Basin have now returned to pre-shutdown production levels.In the Netherlands, Q3 production averaged 7,400 boe/d, a decrease of 17% from the prior quarter. The decrease was primarily due to a planned turnaround and subsequent unexpected downtime to repair a gas compressor, which extended the length of the turnaround. The combined impact was a reduction in Netherlands production of approximately 1,200 boe/d from the prior quarter. Our facilities have returned to service and production has been restored. We are currently in the process of drilling the Weststellingwerf well, 0.5 net, and we expect drilling to be completed before the end of the year. Assuming success at Weststellingwerf, we plan to bring this well on production during the first half of 2020.In Ireland, production averaged 7,200 boe/d in Q3, a decrease of 12% from the prior quarter, primarily due to planned and unplanned downtime at Corrib. Our planned turnaround was successfully completed over a 4-day period in mid-September. However, later in the month we identified the need for repairs in one of the plant auxiliary systems, which required shutting the plant down for approximately 10 days spanning the quarter end. The combined impact of the planned and unplanned downtime was approximately 800 boe/d in the third quarter.In Germany, production averaged 3,300 boe/d in Q3, a decrease of 6% from the prior quarter, primarily due to unplanned downtime on several operated and nonoperated assets. Following the successful drilling of the Burgmoor Z5 well, 46% working interest, completed early in the third quarter of 2019, we continue to evaluate plan alternatives and expect to bring the well on production in late 2020.Slide 6, Central and Eastern Europe and Australia Q3 Highlights. In Central and Eastern Europe, we drilled our second natural gas exploration well in Croatia during Q3 following the successful discovery we announced with our Q2 release. This second well tested at a stabilized rate of 17.2 million cubic feet per day, slightly better than the first Croatian well, which tested at a rate of 15 million cubic feet per day. Although these were limited-duration tests, the results are encouraging because they prove up a very good shale gas play, which we believe could lead to additional similar discoveries in the SA-10 block. We are currently engaging in tie-in planning for these wells. During the third quarter we were also provisionally awarded the SA-7 license in Croatia, which will add approximately 500,000 net acres contiguous with our existing land position in the country. In Hungary, we completed tie-in activities for the MH-21 0.3 net and Battonya E-9 1.0 net wells, drilled in the second and third quarters of 2019, respectively. The Battonya E-9 well, which tested at a rate of 3.4 million cubic feet per day, was brought on production last week. The MH-21 well, which tested at a rate of 2 million cubic feet a day, is expected to start up in Q4 2019.In Australia, production averaged 5,600 barrels a day in Q3 2019, a decrease of 17% from the previous quarter, primarily due to well management and unplanned trestle maintenance on the Wandoo platform. Year-to-date production in Australia has averaged just over 6,000 barrels a day, which is in line with our annual target. We realized an average selling price of AUS 93.71 per barrel, which translates to approximately $71.00 per barrel, reflecting a premium of approximately $9.00 over dated Brent. We have seen a significant improvement in pricing for Wandoo crude in anticipation of IMO 2020 coming into effect, and we expect these stronger pricing levels to continue into Q4 2019 and 2020.Slide 7, North America Q3 Highlights. In Canada, production averaged 58,500 boe/d in Q3 2019, a decrease of 5% from the prior quarter. The decrease was primarily due to planned turnarounds in both Alberta and Saskatchewan, drilling and completion delays caused by abnormally wet weather in Alberta and other unplanned downtimes. We drilled or participated in 40 38.3 net wells in the third quarter of 2019, all of which were drilled in Saskatchewan as a result of the wet weather in Alberta throughout the summer. Our drilling and completion activity in Alberta was delayed until late September due to extremely wet ground conditions, which is 3 months later than we typically resume post breakup. According to Environment Canada, Edmonton has 54 days of rain this summer, making it the wettest summer in nearly 40 years. The picture on this slide illustrates the conditions of one of our well sites in Alberta.In the United States, third quarter production increased 12% from the prior quarter to 4,900 boe/d, primarily driven by production contributions from our 2019 Hilight drilling campaign. We completed and brought on production four 4.0 net additional wells during the third quarter. The first 2 wells drilled in the quarter were brought on production in late August at a peak IP30 rate of 600 boe/d per well, 86% oil and NGLs. The other 2 wells were brought on production at the end of September and are currently producing at an average rate of 500 boe/d per well, 92% oil and NGLs. All 4 wells drilled in the third quarter of 2019 were equipped with electrical submersible pumps.Through ongoing learnings and efficiency improvements in the US, we have achieved a 20% reduction in our second half 2019 DCET costs compared to our first half 2019 program. As a result of these cost savings, we've added two 1.5 net wells to our 2019 program and plan to drill these wells in Q4.Slide 8, 2020 Budget Overview. In the next part of this presentation, I'll review our 2020 budget, but we'd first like to discuss our philosophy in preparing the budget and realigning our growth targets in the current market.Slide 9, Growth and Income History. Throughout Vermilion's 25-year history, we have repeatedly made the necessary adjustments to adapt to the changing landscape around us. Our business model has focused on sustainable growth and income, which we have successfully delivered to our shareholders over the years. As you can see in the exhibits included on this slide, Vermilion has generated compounded annual growth in production per share of over 8% since 2012, even stronger per-share growth in reserves, and we've paid out $3.7 billion or $39.00 per share in distributions and dividends since 2003. We did this while making significant improvements in our economic sustainability, as you can see in the lower right chart. Even including the dividends paid out as shares through our DRIP, we have achieved a total payout ratio of close to 100% over the past 3 years and are currently at our lowest total payout ratio since 2008. Despite this positive track record, our share price is at its lowest level in 15 years.Slide 10, Growth Target Realignment. As many of you are aware, the capital markets environment for oil and gas companies has changed dramatically over recent years due to a multitude of factors, including poor investment returns from energy issuers, increased focus on ESG and SRI mandates and a growing concern about the future of fossil fuels amongst the general public and investors. This has led to compression of valuation multiples across the entire sector, with many companies, including Vermilion, trading significantly below their historical valuation metrics.One of our advantages is our short investment cycle time with minimal fixed commitments. Consequently, we have flexibility to adjust our investment and growth levels to provide the combination of return of capital and growth which we think will maximize shareholder value in a changing capital markets environment. Based on the current capital and commodity market environment, we believe a strategy that is even more focused on free cash flow generation will create the most value for our shareholders. While maintaining our dividend at current levels, we have elected to reduce our growth rate and to introduce additional flexibility in how we return capital to investors. This lower-growth strategy was embedded in the preparation of our 2020 budget as well as our capital plans for the remainder of 2019.Slide 11, 2020 Budget. Our Board of Directors has approved a 2020 capital budget of $450 million with associated production guidance of 100,000 to 103,000 boe/d. This budget is designed to deliver modest annual production growth of approximately 1%.In Europe, we plan to drill 13 8.7 net wells in continuous significant workover programs in France, Netherlands and Germany and facility optimization in Ireland. The capital budget includes approximately $20 million of strategic non-production-adding capital invested in order to facilitate our long-term future growth plans from these business units.In North America, our activity will focus on our 3 core areas of southeast Saskatchewan for light oil, west-central Alberta for condensate-rich natural gas and the Powder River Basin in Wyoming for light oil. We have made significant progress in approving the capital and operating efficiencies on the North American assets we acquired in 2018, and we plan to continue this trend during 2020. In addition, we will be phasing out our DRIP over the course of the next year, prorating the available DRIP shares by 25% each quarter starting in Q1 2020 until the DRIP is completely eliminated in Q4 2020. The DRIP has been a shareholder service that we have provided since our first income distribution in 2003, with discounted share purchases offered until 2018. However, we feel that in an environment of lower trading commissions, the establishment of our NCIB and lower energy issuer multiples, the elimination of the DRIP is in the best interests of our broad shareholder group.Slide 12, Production and CapEx. Slide 12 illustrates how 2020 production and CapEx line up compared to prior years. As you can see, we are delivering a modest increase in production, represented by the blue bars, while spending less capital, represented by the yellow dots. Assuming WTI remains at approximately $55.00 per barrel in 2020 and holding all other commodities at the recent strip, we expect to be able to cover our entire capital program and dividend for a payout ratio at or below 100%. Sustaining CapEx, which we estimate at $420 million, and the dividend can be covered at a WTI price of approximately $52.50 per barrel. Should commodity prices increase from current levels, any excess cash generated beyond our capital program and dividend will be allocated to a combination of debt reduction and share buybacks.Slide 13, Hedging. Our hedging program has served us well during these volatile commodity cycles. We continue to actively hedge for the remainder of this year and through 2022. As of August 24 -- excuse me, as of October 24 -- we have 51% of our expected net of royalty production hedged for Q4 2019. More than half of our Q4 corporate hedge position consists of 2-way callers and 3-way structures, which allow participation in price increases up to contract ceilings. For 2020, approximately 35% of our production is hedged, with 54% of our hedge position in participating structures.With respect to individual products within our mix, we have currently hedged 74% of anticipated European natural gas volumes for Q4 2019. We have also hedged 75% of our anticipated full-year 2020 European natural gas volumes at prices which are expected to provide for strong project economics and free cash flows. At present, 47% of our expected Q4 oil production is hedged. For Q4 2019, 51% of our North America natural gas production is priced away from AECO due to diversification hedges and the location of a portion of our gas production in Saskatchewan and Wyoming.In conclusion, we remain committed to a low-risk capital markets model that returns significant cash directly to shareholders. We are also committed to leadership in environmental, social and governance performance. We are proud to note that in Q3, Vermilion received top-quartile rankings for 2019 for our industry sector in both the Sustainalytics and SAM, formerly known as RobecoSAM, assessments. We believe the integration of sustainability principles into our business strategy is the right thing to do, will increase long-term shareholder return and will decrease long-term risk to our business model. These ratings demonstrate our commitment to maintaining leadership in sustainability and ESG performance.We would be happy to address questions. Operator, would you please open the phone line.

[Operator]

[Operator Instructions.] And your first question comes from the line of Patrick O'Rourke from AltaCorp Capital.

[Patrick Joseph O'Rourke]

Just wanted to ask you a quick question on the U.S. asset and maybe the strategy here going forward in 2020. It's one of the few assets that seems to be seeing an increasing focus at the margin when you look at the percentage of capital it's seeing relative to the whole budget in 2020 versus 2019. Is this 10-well program, is there going to be a geological exploratory element to it, or do you guys think you have a pretty good handle on what you're doing there and it's more just moving into a bit of a development mode at this point?

[Anthony William Marino, President, CEO & Non]

The U.S. program is really one of development drilling. It is not necessarily in-field drilling. There is delineation of the Hilight Turner Pool with wells that are broadly away from the current development area, so we're able to drill wells in a new reservoir that has already been delineated as being within the Turner Pool. So it's not really exploratory in nature. We think we've got good certainty on the expected results there.

[Patrick Joseph O'Rourke]

Okay. And the wells that you've drilled to date, at least the way they look, you've got a couple that are above type curve and a few that are mainly in line with type curve, so you're fairly comfortable with that type curve at this point in time?

[Anthony William Marino, President, CEO & Non]

Yes, Patrick, that assessment is correct. Some are above the type curve, some are in line with it and we're comfortable that the type curve, or perhaps something a little bit better, is deliverable out of that drilling program.

[Operator]

[Operator Instructions.] And there are no further questions at this time. Mr. Anthony Marino, I turn the call back over to you for some closing remarks.

[Anthony William Marino, President, CEO & Non]

Thank you again for participating in our Q3 2019 conference call. We look forward to speaking with you again after our Q4 2019 results are reported in the new year.

[Operator]

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.