Vermilion Energy (VET) Q4 2018 Earnings Conference Call Transcript

Vermilion Energy (VET 1.69%)
Q4 2018 Earnings Conference Call
Feb. 28, 2019 11:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants
  
  

  See all our earnings call transcripts.

Prepared Remarks:

Operator

Good morning, my name is Amy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Inc. 2018 fourth quarter and year-end 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] I would now like to turn the call over to Mr. Anthony Marino, president and CEO. Please go ahead.

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; Kyle Preston, our director of Investor Relations and other members of our management team who may be called upon during the Q&A session, if required. We changed the format of this conference call to include a PowerPoint presentation, which is provided in the webcast and can also be found on our website under Invest with Us and Events and Presentations.

I'll use a slide deck this morning to provide you with an overview of our fourth quarter 2018 financial and operating results, as well as our 2018 reserves update, which was included in our Q4 release. Slides 2 and 3 in the presentation refer to our advisory on forward-looking statements. These advisories describe the forward-looking information and non-GAAP measures and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion. Slide 4, Q4 review.

We'll start with our Q4 results. We delivered record production of 101,621 boe/d which represents a 6% increase over the prior quarter, primarily driven by strong quarter-over-quarter growth from our Netherlands, Canadian and US business units. I will talk about the operational results of each business unit later in the presentation. Q4 FFO was $222 million or $1.46 per basic share, which was down 15% from the prior quarter.

The decrease was primarily due to lower commodity prices, which were partially offset by higher production. The Q4 results included a realized hedging loss of $28 million. So, if we normalized for this, we would have produced FFO of approximately $250 million or $1 billion on an annualized basis. Slide 5, 2018 review.

Looking at our full-year 2018 results, we increased production by 28% year over year to 87,270 boe/d or 10% on a per share basis. This was within 1% of the mid-point of our annual guidance range of 86,000 boe/d to 90,000 boe/d. FFO was $839 million or $5.96 per basic share, which is up 39% from the prior year or 19% on a per share basis. The 2018 results included a realized hedging loss of $111 million.

In contrast, I would note that our 2019 hedge position currently shows a gain of approximately $15 million as of February 22. Our net earnings in 2018 were $272 million or $1.93 per basic share, which is an increase of 336% over 2017 or 271% on a per share basis. We generated a return on capital employed or ROCE of 9% in 2018, which is more than double our five-year average ROCE of 4%. Capital expenditures totaled $518 million, which was 2% above our budget of $510 million.

Higher investment was primarily due to the acceleration of some 2019 drilling in Canada into Q4 2018, allowing us to level load activity and take advantage of favorable services prices. Our payout ratio was 104% for the year. Our intent is to operate as a self-funded entity and we remained clearly on that path in 2019. Slide 6, France.

Getting into the country by country operational review, we'll start with France. France continues to be a very efficient generator of free cash and delivered modest quarter-over-quarter production growth to 11,450 boe/d. We continue to see strong performance from our 2018 Champotran wells in the Paris Basin and continued workover success in the Aquitaine Basin, where we have been growing slightly without doing any drilling. As a reminder, our oil production in France is price reference to the benchmark which traded at $8.95 per barrel premium over WTI during Q4.

Slide 7, Netherlands. In the Netherlands, Q4 production increased 17% quarter over quarter to 8,750 boe/d, primarily due to the full-quarter contribution from the Eesveen-2 well, which we brought on production late in the third quarter at a restricted rate of 10 million cubic feet per day in net to Vermilion. Other activity during the quarter was focused on workovers, facility maintenance and advancing the permits for 2019 drilling campaign. We also consolidated the working interest in some of our existing onshore fields and added minor working interest in several non-operated offshore licenses.

Due to the continued strength in European gas prices, we realized an average gas price of $10.95 per MCF on our Netherlands gas production in Q4 2018. Slide 8, Ireland. In Ireland, Q4 production increased 1% over the prior quarter to 8,670 boe/d. The increase was a result of higher uptime compared to Q3 and the incremental 1.5% working interest in Corrib added in December with the closing of the CPPIB transaction.

The cash consideration at closing was $9 million, which was more than offset by the assumption of $15 million in positive net working capital as a result of taking over the operating company. Integration of staff, processes and systems has been completed and we welcome the former Shell employees to Vermilion. Most importantly, Vermilion now has operating control of our Corrib asset, bringing the proportion of our production that we operate to approximately 90% on a worldwide basis. Similar to the Netherlands, we received European gas prices and realized an average price of $11.15 per Mcf on our Irish natural gas sales in Q4.

Slide 9, Germany. In Germany, production in Q4 averaged 3,740 boe/d, an increase of 7% from the prior quarter. This increase was primarily the result of the restoration of gas processing at a non-operated facility. Much of our activity in Germany over Q4 2018 was focused on pre-drill related activities for the Burgmoor Z5 well, which we expect to spud in March.

This well will test an undrained flank of the Burgmoor Field and has as a mean estimate of 50 BCF of recoverable gas under the prospective resource category. Slide 10, Central and Eastern Europe. In the CEE, production averaged 480 boe/d in Q4, an increase of 145% over the prior quarter due to a full quarter production from the Hungarian well we drilled last year. We will have a step change in our activity in 2019 with 10 gross, seven net wells planned across Hungary, Slovakia and Croatia.

Most of our work over the past several months has been focused on getting all the necessary permits in place and completing various pre-drill activities. These efforts are progressing as planned and we expect to spud our first 2019 well in March in Hungary. As part of our ongoing advancement of long-term development plans, we acquired an additional 150 linear kilometers of 2D seismic data in Croatia and we were granted the Topolcany license in Slovakia which is adjacent to our existing Trnava license. This license added a 50% interest in 300,000 net acres, bringing our total CEE land position to over 3.2 million net acres.

Slide 11, Canada. In Canada, production averaged a record 60,800 boe/d in Q4, a 6% increase from the previous quarter. We had strong operating performance across all of our Canadian assets and brought 57 net new wells on production, which contributed to the increase. We continue to be impressed by the quality and opportunity set that came with the Spartan assets we acquired last year.

We noted at our Investor Day in November 2018 that we have increased our internally estimated drilling inventory from the Spartan assets by approximately 50% to over 1,500 locations. At our Investor Day, we also related that we have internally estimated the potential for approximately 60 million barrels of net waterflood recovery potential on the Spartan assets, which is a project class we didn't count on in our original evaluation of the Spartan deal. Our year-end reserve report recognizes 11.8 million barrels equivalent of 2P reserves and 30 million barrels equivalent best estimate contingent resource for the new waterflood projects that came in Spartan. As we are all aware, Canadian oil differentials were highly volatile during Q4 2018.

Although the average price for Vermilion's Canadian oil production was affected by these wider differentials, it was impacted to a lesser degree than the headline differentials for Alberta light oil and heavy oil. Our Alberta condensate and Saskatchewan light oil displayed relative pricing advantages over the Alberta black oil products, both heavy and light. To put this into perspective. The Saskatchewan LSB index price traded at a USD11.52 per barrel premium over MSW, the Alberta light oil marker, in Q4 2018, compared to USD0.22 per barrel discount in Q4 2017.

While Alberta condensate traded at USD12.77 per barrel premium over MSW in Q4 2018, compared to USD3.71 per barrel premium in Q4 2017. On a go-forward basis, approximately 41% of our total 2019 oil production is indexed to LSB and 9% is indexed to Alberta condensate, while only 8% is indexed to MSW. Slide 12, United States. In the US, Q4 production increased 19% over the prior quarter to 3,550 boe/d, reflecting a full quarter of production associated with the Powder River Basin acquisition completed in Q3.

We drilled and completed our first well, one net, on the newly acquired Hilight assets late in the fourth quarter and brought on production in mid-December. We elected to use a rod pump artificial lift system on this well instead of an electrical submersible pump or ESP. Although a rod pump offers lower pump displacement than an ESP, it reduces sand flowback and pump failure frequency, but still recovers the same amount of oil and gas as an ESP over the life of the well. With rod pump, we get a slower ramp up to peak rates, but at a lower capital cost.

After being on production for over two months, the well is producing on trend with the type curve for rod pump well. The current rate from the well is 290 boe/d, 86% oil, and continues to increase as the well cleans up. As you can see in the production plot on Slide 12, the rod pump oil starts out of lower rate than an ESP well but steadily increases over several months, and by month nine, the cumulative production from the rod pump well is expected to match the ESP well. Slides 13 and 14, Australia.

In Australia, Q4 production averaged 4,170 barrels a day, down 11% from the previous quarter. The decrease was due to a planned shutdown for maintenance and other downtime required to allow the drilling of two new wells. We began drilling the B15 and be B16 wells in early November, and completed the wells in late January. Both wells were drilled at vertical depths of approximately 630 meters, but with measured depth of 4,960 meters and 3,697 meters for the B15 and B16 wells, respectively.

With very high ratios of measured depth to true vertical depth, these are some of the most extreme extended reach wells with shallow depth anywhere in the world. The B15 well also featured an approximate 180-degree turn to allow drainage of oil trapped against the updip bounding fault for the Wandoo field. Both wells were successfully tested in February. The B15 well tested at an oil rate of 8,800 barrels a day over a 48-hour period, and the B-16 well tested at an oil rate of 7,600 barrels a day over a 36-hour period.

We plan to intermittently produce the new wells at restricted rates to maximize long-term value. We are targeting approximately a 6,000 barrel per day average rate for Australia this year. We received an average price of $97.19 per barrel or USD73.60 per barrel for Australian oil sales in Q4 2018, which reflects an approximate premium of USD5.90 over the Brent oil benchmark in Q4, another example of the advantage pricing we received from our international assets. Slide 15, global crude oil pricing advantage.

During my review of each of our business units, I highlighted the pricing advantage we have in each of our regions. I wanted to leave you with a summary illustrating the advantage we have within our oil portfolio, including our Canadian oil production. In this table, we show you our oil product mix and relative pricing to WTI. Only 8% of our 2019 oil production is price referenced to MSW or Edmonton par, with the other products in our oil mix price advantage relative to Alberta black oils.

In aggregate, our companywide oil product mix sells at a weighted average premium of approximately $1.25 per barrel relative to WTI. Slide 16 and 17, 2018 reserves. We delivered strong reserve results in 2018 as evaluated by GLJ. Our proved plus probable or 2P reserves increased 63% to 488 million barrels equivalent, reflecting a year-over-year increase of 31% on a per share basis.

Our proved or 1P reserves increased 69% to 298 million barrels equivalent. And our proved developed producing or PDP reserves increased 55% to 192 million barrels equivalent. Through our development activities, we replaced 187% of 2P reserves, 157% of 1P reserves and 130% of PDP reserves. Including acquisitions, we replaced 695% of 2P reserves, 481% of 1P reserves and 314% of PDP reserves.

Our operating recycle ratio including future development capital or FDC at the 2P level increased to 4.1x in 2018, compared to 2.8x in 2017, as a result of higher operating net backs and a significant decrease to our F&D costs including FDC. Organic F&D costs including FDC decreased 26% in 2018 to $7.79 per BOE, compared to $10.57 per BOE in 2017, and were approximately the same as our three-year average of $7.85 per BOE. These metrics remain strong relative to historical industry averages and reflect a significant improvement in our capital efficiency over the last several years. In addition to increasing our reserve base, we also increased our contingent and prospective resource estimates as per GLJ's evaluation.

The best estimate for contingent resources in the development pending category increased 36% year over year to 240 million barrels equivalent, and the best estimate for contingent resources in the development and clarified category increased 13% year over year to 37 million barrels equivalent. The best estimate for prospective resources was assessed at 161 million barrels equivalent, a 5% increase over the prior year. Slide 18, 2019 economic sustainability. I'd now like to touch on our 2019 outlook and sustainability.

Our 2019 capital budget of $530 million and production guidance of 101,000 boe/d to 106,000 boe/d remain unchanged from what we announced on October 25, 2018. The mid-point of the production range represents 8% year-over-year production per share growth. Based on the February 22, 2018, forward strip, we are approximately 7% overfunded for our CAPEX and cash dividends. The chart on Slide 18, which is included in our monthly corporate presentation, illustrates flexibility we have in our capital program.

We estimate our sustaining or stay-flat capital at $365 million and annual cash dividends at approximately $400 million. As you can see in this chart, we can cover our sustaining capital and cash dividends at approximately $40 WTI assuming all natural gas prices remain at the February 22nd strip, and we can cover our growth capital just over $50 WTI. Forward prices are well above these levels at this time. Nonetheless, if we were to see a substantial decrease in commodity prices, we have the flexibility to adjust our capital program as needed to maintain this self-funded status.

In that event, we would reduce our growth capital first in order to protect our balance sheet and dividend. We didn't cut our dividend in February 2016 when WTI went down to $26 a barrel, and we have no intention of cutting our dividend with WTI at $57 today. Slide 19, 2018 ESG performance. I would like to point out that Vermilion was recently named to the CDP Climate Leadership at A minus level for the second consecutive year in 2018.

We were again the only Canadian oil and gas company and one of only two North American oil and gas companies to receive this designation, ranking Vermilion in the top 5% of oil and gas companies globally. We received several other recognitions throughout 2018 for our ESG performance, which we have summarized on this slide. As we indicated in our Q3 2018 report, our board of directors has recently established a Sustainability Committee to provide oversight with respect to our sustainability policy and performance further demonstrating our commitment to ESG. We've been a leader in sustainability and the establishment of a dedicated board committee reflects the centrality of ESG to our corporate strategy.

Finally, we would encourage you to view our 2018 sustainability report via the link at the bottom of this slide. That concludes my planned remarks, we would be happy to address questions. Operator, would you please open the phone line. 

Questions and Answers:

Operator

[Operator instructions] Your first question today comes from the line of Greg Pardy of RBC Capital Markets. Your line is open.

Greg Pardy -- RBC Capital Markets -- Analyst

Thanks. And thanks, Tony, for running to that presentation. I've got a couple of questions for you. The first one is just a bit open-ended, but what are the priorities for you and just Vermilion this year?

Anthony Marino -- President and Chief Executive Officer

Greg, I'm sorry, would you repeat your question, please?

Greg Pardy -- RBC Capital Markets -- Analyst

It just relates to priorities for the company for 2019.

Anthony Marino -- President and Chief Executive Officer

In terms of our priorities, I think our -- well, certainly, our top priority in our Company is actually premier safety and environmental performance. We think this is correlated to financial and market performance and we put our communities and our employee safety and protection of the environment ahead of any other priority. So, that is definitely No. 1.

No. 2, our intent is with prices where they are at today to execute on the capital program that we've outlined to more than fund our dividends and that capital program while producing at the targeted production levels and with the excess cash to further retire debt; we started out at a level that's somewhat below the -- in terms of debt ratio, somewhat below the sector averages and we intend to further delever from there, providing additional safety to our capital markets model and flexibility to the company. So beyond that, we intend to advance certain strategic projects for the longer term. You've heard a few of these discussed in the conference call, beginning waterflood activity in Southeast Sask, continuing with the development of last year's acquisitions in Southeast Sask and Wyoming and ramping up our European drilling activity to actually a record level for us.

So I guess that would summarize that for you.

Greg Pardy -- RBC Capital Markets -- Analyst

No, no, that's helpful. And maybe just as a follow-up then. You touched on it, but 2019 pretty big year, I think on the exploration side, I think you touched on the first well in Germany, but could you give us a setup just on what the exploration program looks like for the year. And I'm talking outside of Slovakia and so forth.

Anthony Marino -- President and Chief Executive Officer

Outside of the CEE, what is the exploration program for the year?

Greg Pardy -- RBC Capital Markets -- Analyst

Yes.

Anthony Marino -- President and Chief Executive Officer

The -- well, the first activity is in Germany, the semi -- exploratory semi-extensional well at Burgmoor Z5 and [Inaudible] fairly large prospect area, and that well will begin to drill in Q1. I think it will be done by the end of Q2. We intend a two gross; it's approximately one net well program in the Netherlands and those would be considered new pool new pool tests. The other drilling activity that we have in France is really -- it's really development and non-exploration at Champotran.

So, if we take the CEE out of it, that is the exploration program in Europe and in fact in the company.

Greg Pardy -- RBC Capital Markets -- Analyst

That's perfect. Listen, thanks very much.

Anthony Marino -- President and Chief Executive Officer

Thank you, Greg.

Operator

[Operator instructions] Your next question comes from the line of Brian Kristjansen of Macquarie. Your line is open.

Brian Kristjansen -- Macquarie Capital Inc. -- Analyst

Thanks. Tony, just had a question about the next Hungarian well spudding in March. When do you expect to have that on? And is there any facility requirements adjacent to that location, I assume that's the Dombiratos is one location?

Anthony Marino -- President and Chief Executive Officer

Yes, the Dombiratos and -- I will turn to Mike Kaluza, our COO, to answer that question.

Mike Kaluza -- Chief Operating Officer

Hi, Brian, this is Mike. Yes, in Hungary, the Dombiratos, yes, that is the -- the first of the four wells will be drilling in there, that will be spudding in the March time frame. That's actually pretty close to the -- pretty close, the infrastructure is very similar to the well we drilled last year. So, the typically, time frames are probably four to six months to get the permits and and get the construction done and get that online.

So, roads like about Q3 on production date for that. Following that, we'll move directly over to that the second well [Inaudible]; we got the permit and has -- that we'll be drilling that. And then, we'll follow up to our third and fourth wells. So, kind of continuous drilling program out there, maybe a slight break between the third and fourth wells, but those are all relatively quick permits and tie-ins and on-production dates.

Brian Kristjansen -- Macquarie Capital Inc. -- Analyst

Perfect.

Operator

[Operator instructions] Your next question comes from the line of Tom James, a private investor.

Unknown Speaker

Hello. I see that last year you lost a $111 million in hedging program. I came online a little bit late, so I was just wondering if you could discuss the current hedging program and your outlook for oil prices in 2019. Thank you.

Anthony Marino -- President and Chief Executive Officer

Mr. James, the current hedging program is outlined in our corporate presentation, not the smaller deck that we used for this call, but the complete IR deck on the website. That is Slides 43 for an annual average and 44 for a quarterly reflection for '19 and '20. So we at present are -- for 2019, we are 27% hedged on a boe/d basis.

It varies by product. For oil, we are 21% hedged. For European gas, we are 66% hedged. And for North American gas, which is a much more minor product for us, not a big part of our cash flow mix, we are 14% hedged.

The hedge position is a little bit heavier in the case of oil at the beginning of the year and lower as we go forward. We are not particularly espousing a view about oil prices at this point; you can kind of see with just the numerical percent volatility in oil price it's really something that is probably impossible for anybody in the world to predict. In general, we did would say that prices in the range where they're at today on an average basis maybe too slightly higher probably represents a appropriate reflection of the kind of cost curve that would be required to meet growing demand for the next few years. While that seems to be roughly correct average price for us, the volatility -- and you've seen us tremendously over the past year up, down radically in Q4 and then quite a rebound already in Q1, it is very possible.

And I guess our basic internal view is that these prices can be very volatile with short cycles of high amplitude perhaps producing an average that is somewhere in the range of today's prices or perhaps a few dollars higher. We do think that the Brent differential will continue, to WTI part of the differential to WTI and of course that's an advantage that we have for Vermilion. You didn't ask, but I'll just further point out that the places that we produce from within the North American portfolio and especially the ones that we invest in, we think, are very advantaged locations and crude types, Southeast Sask with limited dips to WTI for the LSB product; the [Inaudible] in Alberta, which is consumed within the province [Inaudible] for the heavy oil, which has a similarly, very modest depth to WTI and the Powder River Basin light oil again a comparable depth to WTI as was other two products. Those are the ones that we invest in North America, and part of the reason that we're in those places in addition to very strong technical characteristics that give us low F&D is good rates -- good production rates from our drilling unlimited capital is that they are advantaged marketing locations.

We do produce some Alberta light oil, Edmonton par, MSW. This primarily comes from our Cardium project. We do only a very small amount of development activities, the very best wells really I think within that play, but it has been a -- in our view, it has been and could be a somewhat more vulnerable crude, a little bit more related potentially to heavy oil prices in Alberta so that's not an emphasis in our investment program.

Unknown Speaker

Thank you very much.

Anthony Marino -- President and Chief Executive Officer

Thank you.

Operator

Your next question comes from the line of David Popowich of CIBC. Your line is open.

David Popowich -- CIBC -- Analyst

Thanks for taking my question, guys. I guess I just wanted to ask about your booking practices for the Spartan energy reserves. I noticed in your updated presentation you guys have decreased the number of book Frac'd Midale and Open Hole Frobisher locations in your presentation. So for instance, you're saying -- at the time of your investor day, you were saying you had about 432 Midale wells in inventory now, it's about 370, and you said you had about 850 Frobisher locations, but now you have about 540.

So, I just want to get some clarification on how your views on that asset may or may not have changed over the past few months. Thank you.

Anthony Marino -- President and Chief Executive Officer

Dave, our views on the asset with respect to primary development locations have gone up and up and up actually since we've had it. In general, as I stated in the call, we see -- originally, we saw about 1,000 primary locations and didn't count on any waterflood at the time we made the Spartan deal and we now see it in the range of 1,500 primary locations; this would include all the play types there and interest catch one that we have mainly Frac'd Midale and Open Hole, Mississippian Frobisher, Alida, Tilston, but it would also include a small amount for the Viking assets in Southwest Sask that we got with Spartan. So that has gone up. In addition, we were quite optimistic about the waterfloods as I mentioned.

So that's our development activity view of Spartan. We -- when we heard your question there we couldn't -- we can't quite trace through the well count numbers that you were talking about. They do reflect -- they should reflect only what is on the reserve and resource reports with the Spartan we have updated that slide. And we'll just have to check with you and get back to you on the well counts because they are -- our view of the assets is the activity or the development inventory that is available has gone up and will clarify with you the exact counts there.

David Popowich -- CIBC -- Analyst

I will send -- it's in the drilling project slide, Slide 27, in March 29th of your presentation so.

Anthony Marino -- President and Chief Executive Officer

We're looking at it here, and portion of the Spartan would be in the other drilling projects because we did not, for example, list -- I don't know it's on the order of 100 Viking, so that might be part of the difference here and we'll just trace through this and get back to you, but I can assure you that absolutely the primary project availability has gone up significantly on Spartan along with the -- as a result of the activity we've had to date and the additional time that we've had to own those assets.

David Popowich -- CIBC -- Analyst

Sure. Thanks. I appreciate the answer and I'll follow up with Kyle shortly. Thanks, Tony.

Anthony Marino -- President and Chief Executive Officer

Thank you, Dave.

Operator

And this concludes our Q&A portion for today. I will now turn the call back over to Mr. Marino for any closing remarks.

Anthony Marino -- President and Chief Executive Officer

Thank you again for participating in our Q4 2018 conference call. We look forward to speaking with you again after our Q1 2019 results are reported in April.

Operator

[Operator signoff]

Duration: 38 minutes

Call Participants:

Anthony Marino -- President and Chief Executive Officer

Greg Pardy -- RBC Capital Markets -- Analyst

Brian Kristjansen -- Macquarie Capital Inc. -- Analyst

Mike Kaluza -- Chief Operating Officer

David Popowich -- CIBC -- Analyst

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