Vermilion Energy Inc. (VET) Q2 2018 Earnings Report, Transcript and Summary

Good morning. My name is Christina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Inc. Second Quarter Results Conference Call. [Operator Instructions] Thank you. Anthony Marino, Chief Executive Officer, you may begin your conference.

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; and Kyle Preston, our Director of Investor Relations. I'd 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 second quarter 2018 financial and operating results and updated guidance. The most notable event during Q2 was the acquisition of Spartan Energy, which was announced on April 16 and closed on May 28. This was the largest acquisition in Vermilion's history. The integration of both the assets and employees has progressed extraordinarily well. We're excited about the opportunities that these assets bring to Vermillion, and we're even more delighted with the creativity and capability that the former Spartan staff brings to our company. With respect to organization, we have combined the legacy Vermillion positions in Saskatchewan with the new larger set of Spartan assets and reformed this position into 4 geographically based asset teams. These asset teams have integrated geoscience, engineering and production disciplines. So that they are self-contained technical entities, fully capable of developing the assets in each of the 4 areas. 3 of the 4 asset teams are led by former Spartan technical professionals and 1 by a technical professional who was already with Vermillion working Saskatchewan. Although it has only been 2 months since we closed, we've already begun identifying additional development and production optimization opportunities within the asset base, beyond those, which we recognized at the time of the transaction. Along with a number of cost-saving opportunities, which we expect to become evident in future quarters. Including the partial contribution from the Spartan acquisition, Vermilion's Q2 production increased 15% from the prior quarter to 80,625 boe/d. Organic growth in Canada, France and the U.S. also contributed to the quarter-over-quarter increase following our first quarter 2018 drilling programs in these countries. Production was down slightly in our other business units due to a combination of natural decline, maintenance and third-party facility downtime. For the remainder of the year, we expect production to continue to increase in most business units and for Vermilion overall due to ongoing drilling, lower downtime and in some cases, regulatory approvals. FFO in Q2 was $193 million or $1.43 per basic share representing an increase of 23% from the previous quarter as a result of higher production and commodity prices, partially offset by realized hedging and FX losses of $32 million during the quarter. Cash outflows for E&D CapEx, ARO and dividends totaled $161 million in Q2 resulting in a total payout ratio of 84%. Q2 operations review. In France, Q2 production averaged 11,700 boe/d, an increase of 6% from the prior quarter following the completion of our Q1, 2018 drilling program in the Neocomian and Champotran fields. Production also benefited from less downtime compared to the previous quarter in addition to the successful execution of several workovers during the first half of the year. In the Netherlands, Q2 production averaged 7,300 boe/d, which was down 3% from the prior quarter as we focus primarily on maintenance, permitting and evaluation of the 3D seismic data acquired last year. From our initial assessment of the 3D seismic data, we have already identified 15 new drilling prospects, the majority of which can be reached from existing wellbores. Subsequent to the end of the second quarter, we received regulatory approval for the production plan for the Eesveen-02, which is expected to come on production in mid-August. We continue to pursue permitting for the 3 wells, 1.5 net originally planned for 2018 but have experienced delays, which will likely push the drilling of these wells into 2019. We believe these permitting delays are largely driven by regulatory bandwidth being consumed by the response to the seismicity in the Groningen field, which occurred at the beginning of 2018. I would like to remind call participants that Vermilion has no ownership in the Groningen field. As we have stated in the past, permitting in the Netherlands has always been a challenge and it certainly has not gotten any easier following the seismic activity in Groningen. Nonetheless, we are seeing progress on certain files and the Eesveen-02 production plan that I mentioned earlier is an example of that. Furthermore, the Ministry of Economic Affairs recently published a policy letter reiterating its support for small fields development in the Netherlands. We believe the majority of our future wells can be drilled from existing well sites, which should help with the permitting process and improve operating efficiencies. Although we don't expect to drill this year, we believe we can increase the pace of development in the Netherlands over the next few years in part due to using more existing wellbores -- well sites and drilling longer departure wells to access new pools. Our estimate, as outlined in our corporate presentation on our website, is that we can reach an activity level of 6 or more wells per year by 2021, which should supply meaningful long-term growth in this high netback jurisdiction given the high natural productivities that these wells typically have. I would also point out that last year's 3D survey is the first new data we have acquired in our 14-year tenure in the Netherlands. Even without new data, over that time, we achieved a 74% historical success rate in this conventional hydrocarbon province. We would expect that this very high-quality new 3D would give us success rates that would be even higher in the future. In Ireland, production from Corrib averaged 57 million cubic feet a day or 9,400 boe/d in Q2, a 7% decrease from the prior quarter due to natural declines and minor plant downtime related to external electricity supply issues. Production declines were consistent with our numerical simulation of reservoir performance. We continue to work with our partners on the transition of ownership and operatorship from Shell to CPPIB and Vermilion. The transition has progressed well in all technical aspects and we are ready to operate Corrib. We anticipate receiving final approvals from the necessary authorities and closing the transaction in the second half of 2018. Although this closing date is later than our original expectation, and will have a modest impact on our book production from Ireland, the later closing has no net cash impact on Vermilion. We will still benefit from all interim period cash flows between January 1, 2017 and the closing date as a reduction of purchase price. In Germany, production in Q2 2018 averaged 3,400 boe/d, a decrease of 9% from the previous quarter. The decrease was primarily due to downtime at a nonoperated gas processing facility, resulting in 22 days of downtime during the quarter. We expect the facility to be fully back online later in the third quarter of 2018. In Hungary, we are nearing completion of the tie-in of the successful well we drilled in Q1 on the Battonya South concession and expect to bring it on production in the next few weeks. We are also advancing permits for our 2019 drilling program in the CEE, where we plan to drill a second well in Hungary, 1 to 2 wells in Croatia and up to 4 wells in Slovakia. In Canada, production averaged 43,800 boe/d in Q2, 2018, representing a 37% increase from the previous quarter, primarily due to the contribution from the Spartan assets. Production also benefited from our successful Q1 drilling program and less weather-related downtime and third-party maintenance. We drilled or participated in 18 gross wells, 16.2 net and brought on production 9 gross wells, 7.9 net during Q2 with the majority of the drilling activity in the quarter focused on the acquired Spartan assets. We currently have 4 rigs operating on the Spartan lands and 1 rig operating on our legacy southeast Saskatchewan assets, along with 1 rig operating in Alberta. In the United States, Q2 production averaged 780 boe/d, an increase of 27% from the prior quarter, primarily due to the contribution from 2 of the 5 gross wells, 5.0 net, drilled in Q1 2018 and resumption of gas sales following the restart of a third-party gas facility. The 2 wells placed on production averaged peak 30-day production rates of 280 boe/d per well, 84% oil. Two of the remaining wells are in the process of being completed and 1 well was shut-in after initial testing due to uneconomic production levels. In Australia, production averaged 4,100 boe/d in Q2, representing a 17% decrease from the previous quarter, primarily due to downtime associated with well workover activity to optimize our electrical submersible pumps. These maintenance activities have been completed and we expect to recover this production during the second half of the year. To take advantage of the offshore service conditions on the northwest shelf, we have decided to accelerate our originally planned 2019 2-well drilling program into Q4, 2018. There are several significant advantages to conducting this activity ahead of our original schedule. First, in our Australian drilling programs, we always have to assemble or take part in a consortium of other operators to mobilize a rig at a reasonable cost. A suitable jackup is already working for another operator on the northwest shelf and the presence of this rig generates economies in mobilization and demobilization, support vessels and other services. Second, offshore services are already tightening and the potential for higher service costs exists in 2019. Finally, engaging the rig that is currently operating on the northwest shelf should ensure that our wells are completed and the rig is gone before the onset of cyclone season in Q1, 2019. Although the earlier drilling won't contribute production in 2018, it will save approximately $12 million in capital as compared to drilling in 2019 or about 18% on the $65 million program. As a result of this accelerated drilling program in Australia, along with some minor adjustments to account for changes in ForEx exchange rates, we have increased our 2018 capital budget by $70 million to $500 million. In addition, we have also reallocated some capital and revised the production mix between business units to account for the permitting delays in the Netherlands. Our 2018 corporate production guidance remains unchanged at 86,000 to 90,000 boe/d, and we continue to anticipate an exit rate in excess of 100,000 boe/d. The change in capital allocation and production mix across business units can be found in our updated corporate presentation located on our website. Based on the forward commodity strip, we expect to fully fund our revised capital program and our dividend with internally generated FFO, resulting in a total payout ratio of 90% despite not getting any production contribution from the 2 Australian wells this year. Lastly, I would like to point out some of our recent achievements in sustainability and ESG, both of which are fundamental to our business. For 2018, we are once again awarded an A rating from the MSCI ESG rating agency, marking the second consecutive year Vermilion has scored at that level. Our Governance Metrics score ranked in the top decile globally. Vermilion also scored 82 out of 100 on the annual ratings conducted by Sustainalytics, ranking us at the top of our peer group. Both of these ratings are a product of our commitment to maintaining leadership and sustainability and ESG performance. 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 Brian Kristjansen from Macquarie.

Can you quantify the impact to the core production in the quarter that was due to the electrical interruptions?

Brian, I'll turn that question to Mike Kaluza, our COO.

Brian, thanks for the question. Yes, it was -- the majority of it [was decline], so it was only several hours that shut that down so -- probably on the order of 100 barrels per day.

[Operator Instructions] Your next question comes from Greg Pardy from RBC Capital Markets.

Maybe just to continue on just with a few of the operational questions. Tony, with the -- with Australia now done in terms of the workovers, how much should we be thinking about that bouncing back to -- I mean, I know where it's -- maybe it's 4,000, 4,500, 5,000 barrels a day, just trying to get a feel there?

Yes, with the workovers, they're probably running about -- our run rate should be on the order of probably 5,300 to 5,500 barrels a day is what we're looking at when we get those fully optimized.

Okay, great. Okay. That's helpful. And then with Corrib then, you mentioned that the decline is consistent with your expectations. Is that still about a 15% annualized rate?

Yes. We do a -- this is Tony, answering this one. We do a pretty detailed numerical reservoir simulation taking all this pressure in production data that we get from the individual well. So we can do a pretty accurate match of the data, we got a real detailed geologic description from the various 3Ds that have been shot and the core data and log data that we have in the field. So that reservoir simulation shows an average decline as we go forward of about 15%. It bounces around a little bit each year but some years are a little lower, some years are a little higher but yes, it's an average of 15% and that hasn't changed.

Okay. And maybe just the last one for me, I guess what did jump out just a little bit was just the oil, gas mix in Canada. Can you -- I think you mentioned you -- your activity was limited on your lands, to begin with. But can you give us an idea just how those numbers would have shaken out the way they did? And this is -- someone was asking, is this kind of the new norm? [Interest kind of] oil, gas mix ex the Spartan properties?

Yes. Greg, we noticed that in your comments this morning that came out after we released. For us, really, the oil, gas mix in Canada wasn't different than what we had expected. The -- I don't think in general it's a whole lot different than maybe the consensus estimates. We have -- perhaps there's some fluctuation that was introduced by having Spartan come in mid-quarter but we're just not aware of anything that is different in the proportion of oil and gas in Canada versus where we had expected to be.

[Operator Instructions] Your next question comes from Jason Frew from Crédit Suisse.

Tony, I just wondered if you could clarify the $70 million CapEx increase? Is that -- did I hear you say that's largely Australia pretty much, just minor from FX? If could you clarify that. And then secondly, could you just give us some additional color on any reallocation and production mix for 2018? Just how you managed that?

Okay. On the first one, the $70 million change, so between $5 million and $10 million was due to FX. So I think, if I remember correctly, $6 million, $7 million FX versus the original budget. The remainder is the Australian drilling program. We did have a few million that we planned already this year that was going to be invested to prepare for next year's drilling and that's why that total doesn't put to a number in excess of $70 million. The second question on the production mix, we've outlined in the new corporate presentation, the estimates by business unit shown graphically in there, for example, for the Netherlands, we'll be down about 2,000 boe/d from the original estimates that we had made, putting us at a level that is above last year's but about flat with where we were in '16. And that Netherlands' production is made up by additional production in primarily in Canada. We've adjusted all of the business units for the latest estimates but that is mainly the shift that you get in the mix as a result of the permitting in the Netherlands.

And your next question comes from Darren Engels from GMP.

Tony, quick question on the capital program, with the acceleration of the capital spending in Australia into Q4 this year, can you give us a sense of what 2019 capital spending is going to look like now?

We haven't guided to 2019 yet, Darren, we're working on the budget, trying to take into account the projects that are available to us now with having Spartan in the portfolio. What doing Australia this year will do is take that chunk of capital that would have otherwise been invested in '19 and just taking it into '18. And at the same time, generating a 2-year savings of about $12 million, but we are -- we don't have an estimate yet for next year that we're willing to release.

And your next question comes from Sanjeev Bahl from Edison.

Tony, just one question for myself. Canadian units OpEx clearly has gone up once you've included the Spartan assets. So I was just wondering what we should expect for the full year? Are there any synergies that could potentially bring these down over time?

Yes. In fact, there are quite a few synergies and reductions I think that will occur out of the Spartan assets. We've -- we've got a few ones that occurred just in administrative areas before I get to the field operations but -- for example, we're capable of generating about $2 million a year just out of different marketing arrangements, consolidated insurance for the company is probably about another $0.5 million a year. G&A items like reserve evaluations are about $0.5 million a year. Now, this is out of the -- these are not part of the very basic production operation consolidations and improvements we think we can make. And that number with respect to the OpEx on the Spartan assets would be probably a reduction of about $2 to $3 per boe over time. That's what we think we can achieve. Doesn't all show up immediately but it's something that we're pretty confident we will get.

And there are no further questions at this time. I'd like to turn the call back over to Mr. Marino.

Thank you, again for participating in our Q2 conference call. We look forward to speaking with you again after our Q3 2018 results and 2019 budget release in October.

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