Vermilion Energy Inc. (VET) Q2 2018 Earnings Conference Call Transcript

Vermilion Energy Inc. (VET -0.25%)
Q2 2018 Earnings Conference Call
July 30, 2018, 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

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. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press * then the number 1 on your telephone keypad. If you would like to withdraw your question, press the # key. Thank you.

Anthony Marino, President and Chief Executive Officer, you may begin your conference.

Anthony Marino -- President and Chief Executive Officer

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 about the opportunities that these assets bring to Vermilion, 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 Vermilion position in Saskatchewan with the new, larger set of Spartan assets and reform this position into four geographically based asset teams. These asset teams have integrated geo-science, engineering, and production disciplines so that they are self-contained, technical entities fully capable of developing the assets in each of the 4 areas.

Three of the four asset teams are led by former Spartan technical professionals and one by a technical professional who was already with Vermilion working Saskatchewan. Although it has only been two 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 other business units due to a contribution 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 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 focused 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 well bores.

Subsequent to the end of the second quarter, we received regulatory approval for the production plan for the Ace Vein II well, which is expected to come on production in mid-August. We continue to pursue permitting for the three 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 Ace Vein 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 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 six or more wells per year by 2021, which should supply meaningful long-term growth in this high-net backed 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 CPPID 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 non-operated 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, one to two wells in Croatia, and up to four 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 four rigs operating on the Spartan lands, and one rig operating on our legacy Southeast Saskatchewan assets, along with one 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 two of the five gross wells (5.0 net) drilled in Q1, 2018, and resumption of gas sales followed the restart of a third-party gas facility. The two 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 one well was shut-in after initial testing due to uneconomic production levels.

In Australia, production averaged 4,800 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 two-well drilling program into Q4 2018.

There are several significant advantages to conducting this activity ahead of our original schedule. First, in our Australia drilling programs, we always have to assemble or take par tin consortium of other operators to mobilize a rig at a reasonable cost. A suitable jack-up 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 two 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 were once again awarded an A rating from the MFCI ESG rating agency, marking the second consecutive year Vermilion has scored at that level. Our governance metric 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 in 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?

Questions and Answers:

Operator

Certainly. At this time, I would like to remind everything, in order to ask a question, please press * then the number 1 on your telephone keypad. Your first question comes from Brian Kristjansen from Macquarie. Your line is open.

Brian Kristjansen -- Macquarie Capital Markets -- Analyst

Good morning, Tony. Can you quantify the impact to the core production in the quarter that was due to the electrical interruption?

Anthony Marino -- President and Chief Executive Officer

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

Michael Kaluza -- Executive Vice President and Chief Operating Officer

Hey, Brian. Thanks for the question. The majority of it was the client. So, it was only several hours that they shut that down, so it's probably on the order of 100 barrels a day.

Brian Kristjansen -- Macquarie Capital Markets -- Analyst

Okay, thanks.

Operator

Again, if you would like to ask a question, please press * then the number 1 on your telephone keypad. Your next question comes from Greg Pardy from RBC Capital Markets. Your line is open.

Greg Pardy, CFA -- RBC Capital Markets -- Analyst

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

Anthony Marino -- President and Chief Executive Officer

Yeah, 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.

Greg Pardy, CFA -- RBC Capital Markets -- Analyst

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

Anthony Marino -- President and Chief Executive Officer

Yeah, we do a -- this is Tony answering this one. We do a pretty detailed numerical reservoir simulation taking all this pressure and production data that we get from the individual wells, so we can do a pretty accurate match of the data. We've 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 yeah, it's an average of 15% and that hasn't changed.

Greg Pardy, CFA -- RBC Capital Markets -- Analyst

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

Anthony Marino -- President and Chief Executive Officer

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. I don't think in general it's a whole lot different than maybe the consensus estimates. 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 than the proportion of oil and gas in Canada versus where we had expected to be.

Greg Pardy, CFA -- RBC Capital Markets -- Analyst

Okay. No, that's fine, Tony. Thanks for that.

Anthony Marino -- President and Chief Executive Officer

For sure, Greg. Thank you.

Operator

Again, if you would like to ask a question, please press * then the number 1 on your telephone keypad. Your next question comes from Jason Frew from Credit Suisse. Your line is open.

Jason Frew -- Credit Suisse -- Analyst

Hi, Tony. I just wondered if you could clarify the $75 million capex increase. Did I hear you say that's largely Australia pretty much? Just minor from FX? If you could clarify that. Then secondly, could you just give us some additional color on any reallocation and production mix for 2018, just how you managed that? Thank you.

Anthony Marino -- President and Chief Executive Officer

Okay. On the first one, the $70 million change. Between $5 and $10 million was due to FX. If I remember correctly, $6, $7 million FX versus the original budget. The remainder is the Australia 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 units 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. That Netherlands production is made up by additional production primarily in Canada. We've adjusted all 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.

Jason Frew -- Credit Suisse -- Analyst

Okay. Thank you.

Operator

Your next question comes from Darren Engles from GMP. Your line is open.

Darren B. Engels, CA, CFA -- GMP FirstEnergy -- Analyst

Hi, Tony. A quick question on the capital program. With the acceleration of 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?

Anthony Marino -- President and Chief Executive Officer

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 Australia this year will do is take that chunk of capital that would've otherwise been invested in '19 and just taking it into '18. And at the same time, generating a two-year savings of about $12 million, but we don't have an estimate yet for next year that we're willing to release.

Darren B. Engels, CA, CFA -- GMP FirstEnergy -- Analyst

Fair enough. Thank you very much.

Anthony Marino -- President and Chief Executive Officer

Thank you, Darren.

Operator

Your next question comes from Sanjeev Val from Edison. Your line is open.

Sanjeev Val -- Edison Capital Holdings -- Analyst

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

Anthony Marino -- President and Chief Executive Officer

Yes. In fact, there are quite a few synergies and reductions I think that will occur out of the Spartan assets. 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 half million for the year. G&A items like reserve evaluations are about a half million a year.

These are not part of the very basic production operation consolidations and improvements we think we can make. That number, with respect to the opex on the Spartan assets would be probably a reduction of about $2.00 to $3.00 per boe over time. That's what we think we can achieve. It doesn't all show up immediately, but it's something we're pretty confident we will get.

Sanjeev Val -- Edison Capital Holdings -- Analyst

Thanks.

Operator

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

Anthony Marino -- President and Chief Executive Officer

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.

Operator

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

Duration: 26 minutes

Call participants:

Anthony Marino -- President and Chief Executive Officer

Michael Kaluza -- Executive Vice President and Chief Operating Officer

Brian Kristjansen -- Macquarie Capital Markets -- Analyst

Greg Pardy, CFA -- RBC Capital Markets -- Analyst

Jason Frew -- Credit Suisse -- Analyst

Sanjeev Val -- Edison Capital Holdings -- Analyst

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