Vermilion Energy Inc. (VET) Q3 2018 Earnings Report, Transcript and Summary

Good morning. My name is Kim, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy's Third Quarter Results Conference Call. [Operator Instructions] Anthony Marino, President and CEO, you may begin your conference.

Thank you. 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 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 outlined the risk factors and assumptions relevant to this discussion. During this call, I'll provide you with an overview of our third quarter 2018 financial and operating results and 2019 budget, which were included in our Q3 release. The third quarter marks our first full quarter with the integration of the Spartan assets and our first quarter production and cash flow contribution from our Central and Eastern Europe business unit. We also completed a U.S. acquisition in the quarter, expanding our position in the Turner Sand fairway of the Powder River Basin in Wyoming. Vermilion is a much larger entity today, with a production base over 50% greater than it was 2 years ago. From this expanded land base, we delivered record quarterly production of 96,200 boe/d and record FFO of $261 million, which is twice the amount we generated in the third quarter of 2017. Our Board of Directors has approved the 2019 capital budget of $530 million with associated production guidance of 101,000 to 106,000 boe/d. The midpoint of this guidance range represents year-over-year production growth of 18% or 7% on a per-share basis. Including our projected 2019 results, Vermilion will have delivered compounded average production per share growth of 9% over the past 5 years, coming primarily from high-margin barrels with premium or advantage pricing relative to our peers. Given the recent volatility in Canadian oil differentials, I want to remind investors where our products are sold and what price benchmarks they are indexed to. The oil and gas produced from our international assets is indexed to Brent oil and European gas benchmarks, both of which trade at significant premiums to their North American counterparts. In turn, the vast majority of our North American oil is produced in areas that have relative pricing advantages to most Canadian oil streams. We have no heavy oil in our product mix. Approximately 70% of our Canadian light oils produced in southeast Saskatchewan and receives a price indexed to LSB. The remaining 30% of our Canadian oil production is comprised of condensate and live oil in West Central Alberta, plus a very small amount of Viking oil in the corroborate area of western Saskatchewan. This crudes are price referenced to the C5+ and MSW benchmarks, respectively. LSB and condensate differentials have widened recently but to a much lesser extent than WCS and MSW. LSB currently trades at USD 11.70 per barrel premium to MSW, while condensate currently trades at a USD 16.25 per barrel premium to MSW. So in summary, only 8% of our worldwide oil production or only 4% of our worldwide oil equivalent production is exposed to the currently very wide MSW, also known as Edmonton par price differentials. Despite the widening of Canadian oil differentials, our free cash flow profile has never been better. Based on the midpoint of our 2019 production guidance in the October 15 commodity strip, we expect to more than fully fund our capital program and our annual dividend, resulting in a total power ratio of approximately 82% and over $200 million in surplus cash beyond our planned cash outlays. I will now move to our Q3 operations review starting in Europe. In France, we did not drill any wells during Q3 yet production remained relatively flat at 11,400 boe/d. Our assets provide numerous low risk work over and infill drilling opportunities to offset declines and generate modest growth. In the Netherlands, Q3 production averaged 7,500 boe/d, an increase of 2% from the prior quarter. In mid-September, we brought the Eesveen-02 well at 60% working interest on production. The well is currently flowing at a restricted rate of 10 million cubic feet per day net and is expected to produce at this rate through 2019. We continue to work on advancing our future drilling permits in anticipation of a significantly accelerated drilling phase after 2019 and are encouraged by recent developments. We were recently granted a positive decision on our environmental impact assessments for the 2 wells included in our 2019 budget and are now awaiting final drilling approvals. As previously noted, we expect to drill the majority of future wells from existing well pads, which will reduce our surface footprint and help in the permitting process. In Ireland, production from Corrib averaged 51 million cubic feet a day or approximately 8,600 boe/d in Q3, a 9% decrease from the prior quarter. This decrease was primarily due to a planned plant turnaround in September, lasting approximately 4 days, which reduced our quarterly average production by approximately 450 boe/d net to Vermilion. Natural declines accounted for approximately 400 boe/d of the quarter-over-quarter decrease, which is consistent with our numerical simulation of reservoir performance. Our reservoir simulation model projects an average annual decline rate of approximately 15% over the remaining life of the field with a slightly higher decline rate in the early years and a slightly lower decline rate in the later years. Specifically, based on the model, we expect the field to decline at approximately 17% in 2019, decrease to 15% in 2020 and then level off at approximately 14% thereafter. With respect to our Corrib partnership, the Canada Pension Plan Investment Board, we continue to work through the final stages of acquisition approval and anticipate closing the transaction before the end of 2018. As noted in our Q3 2018 release, although the longer than anticipated closing of this transaction has a modest negative impact on our book production from Ireland, Vermilion will still benefit from all interim period cash flows from January 1, 2017 to closing as a reduction of purchase price. As a result of the cash flow that has been accrued since the effective date, we now anticipate the closing price with our incremental 1.5% working interest to be approximately EUR 6 million compared to EUR 19.4 million as announced in July 2017. In Germany, production in Q3 averaged 3,500 boe/d, which was in line with the previous quarter. Our capital activity in Germany continues to focus on well and facility maintenance and preparatory work for the drilling of our first operated well in Germany, the Burgmoor Z5 well at 46% working interest, which is expected to commence in Q1 2019. We continue to evaluate drilling opportunities on the ExxonMobil farming land. We have now identified several significant future exploration prospects, which we plan to drill over the next 5 years. More detail on these prospects can be found in our investor presentation on our website. In Central and Eastern Europe, first gas production commenced from our new Hungarian natural gas well at 100% working interest in the Battonya South concession. The well is brought on production in mid-August and contributed 195 boe/d to our Q3 results. Production from this well has recently been increased to 5.3 million cubic feet a day as compared to our original test flow rate at approximately 5.8 million cubic feet a day. Permitting activities have been initiated in preparation for our 2019 drilling campaign across Hungary, Slovakia and Croatia, where we plan to drill 10 gross, 7 net wells in aggregate. In Australia, production increased 14% quarter-over-quarter, to 4,700 barrels a day in Q3, primarily due to reinstatement of production, following well workovers in Q2. Another key well workover, which is part of our electrical submersible pump and increased fluid handling project was completed at the end of Q3 and should restore additional production in Q4. In addition to the workover activity in Q3, we continued to focus on preparatory activities for our upcoming 2 gross, 2 net well drilling campaign in Q4 2018. The jack-up rig is scheduled to arrive at the end of October, which should enable us to complete the planned wells by early January. In Canada, production averaged 57,400 boe/d in Q3, representing a 31% increase from the previous quarter, primarily due to a full quarter of contribution from the Spartan assets. Production was partially offset by downtime due to third-party gas plant maintenance, regulatory rate restrictions on certain wells and weather-related project delays. It was an active quarter with 5 rigs operating in Saskatchewan and 1 rig operating in Alberta in the Mannville project, which continues to deliver strong results in line with our expectations. The integration of Spartan is complete, and we're pleased with the results. We have combined the legacy Vermilion assets in Saskatchewan with a new larger set of Spartan assets and reformed this position into 4 integrated geographically based asset teams. During the third quarter, we relocated all of the former Spartan Calgary-based employees into our existing Vermilion office. We believe the project inventory is at least as large as what we identified at the time of acquisition and additionally includes significant waterflood upside at Oungre and Lougheed. Moreover, there are very large number of production and facility optimization projects and synergies within the now combined asset bases. In the United States, Q3 production averaged 3,000 boe/d, an increase of 280% from the prior quarter due to the production associated with the acquisition plus contributions from development activity started earlier in the year. In the acquisition, we acquired mineral land and producing assets in the Powder River Basin for a total cash consideration of approximately $186 million. The acquisition is comprised of low base decline, light oil weighted production and high-quality mineral leasehold in Campbell County, Wyoming, located approximately 65 kilometers northwest of Vermilion's prior operations. The assets include 55,700 net acres of land at approximately 96% working interest and 2,500 boe/d of production, which is 63% oil and NGLs with an estimated annual base decline rate of 13%. We have identified 93 future drilling locations, targeting light oil in the Turner and Parkman tight sandstones, which were expected to be developed using horizontal wells will multistage fracs. Significant infrastructure already exists in the area, including gas gathering and water source and disposal, which is expected to streamline future development. All of the production on the acquired land is operated and 93% is held by production, giving us control over the pace of development. The acquisition expands our presence in a highly prospective basin, where we already operate and are familiar with the land regulatory reservoir and geologic characteristics. Our purchase was accretive for all pertinent metrics, but the primary driver was to expand our land position and project inventory in the Turner play. If you ascribe no value to the production, the purchase price represent a cost of approximately CAD 3,400 per net acre or USD 2,600 per acre. The transaction was financed by drawing on our revolving credit facility. Following the acquisition, we expanded our credit facility commitment level to $1.8 billion from $1.6 billion, maintaining unutilized revolver capacity at approximately $450 million. Pro forma, the acquisition, our projected year-end 2019 debt-to-FFO ratio is forecasted to be 1.43x based on October 15 strip pricing as compared to 1.33x prior to the acquisition. As noted in my opening remarks, our Board of Directors has approved an E&D capital budget of $530 million for 2019, with associated production guidance of 101,000 to 106,000 boe/d. The budget will fund additional activity in all countries except Australia, where we accelerated the originally planned 2019 2-well drilling program into Q4 2018. The 2019 program reflects a full year of development on the Spartan assets, additional capital associated with the recently acquired assets in the Powder River Basin and also incorporates a significantly expanded drilling program in Europe. With respect to Europe, we plan to resume drilling in the Netherlands, significantly expand our drilling program in Central and Eastern Europe, commence our inaugural drilling campaign in Germany and continue with our low risk development plans in France. The majority of the new wells we plan in Europe during 2019 will be targeting natural gas, which continues to sell at a significant premium to North American gas. In total, we plan to drill 19 gross, 13.2 net wells in Europe in 2019, representing our most active drilling program over our 21-year history on the continent. This is more than 3x number of wells we drilled in 2018 and over 25% more than our previous high in Europe. In North America, our activity will continue to focus on our 3 core areas of West Central Alberta, targeting condensate-rich gas, southeast Saskatchewan, targeting light oil and the Powder River Basin in Wyoming, also targeting light oil, all of which are products with advantage market access, resulting in lower differentials. We plan to drill 19 gross, 16.7 net condensate-rich wells in West Central Alberta, 143 gross, 129 net light oil wells in southeast Saskatchewan; and 8, both gross and net, light oil wells in the Powder River Basin. A more detailed overview of our capital plans by country can be found in the Q3 release. At the October 15 strip, we expect to fully fund our 2019 E&D capital investment and dividends from internally generated fund flows from operations. Under that strip pricing and assuming excess cash is used to pay down debt, we project 2019 total payout ratio of 82% with a year-end debt-to-FFO ratio of 1.43x. Finally, I would like to point out that Vermilion received the top quartile ranking for 2018 for our industry sector in RobecoSAM's Annual Corporate Sustainability Assessment. We believe the integration of sustainable -- sustainability of principles into our business is the right thing to do, increase the shareholder returns and reduces long-term risks to our business model. This rating demonstrates our commitment to maintaining leadership and sustainability at ESG performance. Further demonstrating Vermilion's commitment, our Board of Directors has established a sustainability committee to provide oversight with respect to sustainability policy and performance. That concludes my planned remarks, we would be happy to address questions. Operator, would you please open the phone line?

[Operator Instructions] Your first question comes from David Popowich from CIBC.

I guess I had two questions, the first is just with respect to drilling activity in Canada. I was just wondering if you can comment on whether you've seen any fluctuations on how you plan to deploy capital in Canada over the course of 2019, just given recent weakness in differentials? Would you still expect to have upfront weighted program in the first quarter as you've had in the previous years? And then the second question I had is just with respect to share buybacks. And I guess, was wondering if just given the performance of the stock this year, if you guys have any change in your view on share buybacks in the capital allocation decision-making process?

Okay. Thanks very much, Dave, for those questions. The first one, in regard to -- do the diff changes affect our capital plan? As we have outlined in this release, they do not at the current levels. They did enter into where we decided to plan to deploy the capital for '19. As an example of that, we have -- actually in industry terms, we have a very high quality, probably the highest quality Cardium light oil halo position in the industry. Nonetheless, because the current diffs are so wide for MSW or Edmonton par crude, we decided to not drill any wells in the Cardium. So it has affected the mix a little bit but the wells that we're going to be drilling in Southeast Sask, the conde wells in West Central Alberta and the Powder River Basin wells, all benefit from a significantly better differentials in MSW. In particular, Powder River Basin has very low diffs to WTI, current contract for us is minus 260 from WTI, including transport. So LSB in Southeast Sask has moved to a significant, very significant premium to MSW and although its diff has widen a little bit, it's still leads to quite strong pricing and very, very high project returns because those wells are very productive and not very expensive. Conde has also widened out some from where it traded previously, usually typically flat or at a premium to WTI now. Its most recent data has showed about a $10 discount to WTI, probably, that will narrow. But in any case, the returns from those wells are extraordinarily strong, so we're going to continue to drill the conde wells. As far as the timing, we have a higher capital deployment as usual in Q1, just driven by weather and ground conditions. We're out relatively early with this budget in late October, and I would point out that if something were to significantly go amiss with the underlying commodity or with the differentials in the areas that we plan to drill in, we have complete flexibility in this drilling program to reduce the size or to a lesser extent, I would say, reallocate some capital. So if you were to end up in a really rapid and deep and protracted decline in commodities like perhaps you saw in mid-'14, we don't expect this to be the case, but were it to occur, we would have the capability to significantly scale back on that capital program and just reduce the amount of growth that we're reporting. So in answer to your second question on buyback. So it's certainly the case that we're generating way more FCF than we ever have in our history on the order of $600 million beyond our full capital program, and that's just not the capital program that stayed flat, but the capital program that continues to allow us to grow. That number is around $200 million more than we need for the current dividend levels. So in terms of cash surplus generation beyond our needs for capital and dividends, it is that a -- it's true, it is at a very high level where our pricing is today. At the same time, the company is underlevered compared to the sector. We do believe in returning cash to the owners of the company. In fact, it's occurred historically through dividends. In fact, over the company's history, we pay out more in dividends than we ever issue an equity. And this has been the mode for us and the method that we've used to return capital to the owners of the company, probably more so than any other business, I would say, in the upstream sector. The potential uses for that surplus cash include further debt reduction. They would include, over the long term, dividend increases. Our last dividend increase became effective in April of this year. And there is a potential in the future, getting specifically to your question, that we could employ buybacks as well. At present, what we've elected to do in consultation with our board, and we do discuss this topic each quarter, is to continue with our organic debt reduction with the objective of making absolutely sure that, starting from this under-levered point, that we will continue to make the balance sheet and the capital markets model of growth and income even safer. Again, while we don't expect to go into any kind of mid-2014 style collapse in commodities, we're always cognizant that the worldwide political situation is more unsettled probably than it has been in the past. And we're -- and so for that reason, at this point, in any case, we're not going to employ the buybacks. I would say they all remain options for the future. And we can assure you and our investor base that we're going to make absolutely certain as best we can that the company is a safe place to invest in and can run our growth and income model and our long-term dividend growth model with a very high degree of reliability.

[Operator Instructions] Your next question comes from Patrick O'Rourke from AltaCorp Capital.

Just a couple of quick questions on the capital allocation of the Powder River Basin assets next year. I noticed 6 of the 8 wells will be on the new property. Wondering what the purpose of these 6 wells are. Are they still in the delineation phase? I know that there is some vertical -- or pardon me, a horizontal well control already there in the Turner Sands and then that would this be from the 93 future locations? Or is there potential to add to that in the reserve report with this delineation drilling?

Yes, I think I'll take that one as well. Thanks, Pat, for the question. The existing production is about -- I know it's roughly half the split between the muddy waterflood and between Turner Sand production out of horizontals. So there are -- I feel like there is extensive outpost delineation of land base to identify where we ought to be drilling horizontal and a few Parkman wells as well going forward. So I don't think that this program is going to be characterized as delineation. It would be, I would say, broadly speaking, within existing control. The -- as far as the well count, we identified 93 locations for the Turner and the Parkman. However, only around half that number is on the initial GLJ report. So they would represent, over the course of the development of the property, if that's exactly the number, they may well go up over time. Roughly half of them would represent locations that are not recognized by the reserve engineering firm right now. At present, we have not expected any drilling in the Mowry or Niobrara shales. We -- our assessment at this point is probably immature in this location, however, industry activity has a tendency to expand that, and that maturity question is something that we're going to continue to evaluate, and I think, really, over the longer term, that would represent some upside as well to the location counts that we've quoted.

Your next question comes from the line of David Ramsay from Calrossie Investment.

Your stock is up quite sharply this morning, about 5.2% in an otherwise pretty good day for oil and gas stocks. And I haven't -- maybe I missed it, but I haven't heard any discussion as to anything particularly being disappointing in the results. Although, I did hear from one source that there was maybe some concern about Corrib declines being faster than expected or that the 2019 cash flow per share forecast in your present corporate presentation was lower than people were expecting. Can you address either of those as being -- in your view, is everything kind of unchanged from past guidance? Or it's in fact, there is some new news this quarter that we actually haven't discussed yet.

Thank you for the question, David. I mean, on each of those 3 points you raised, first of all, Corrib. We, first of all, attempted to be much more detailed in the disclosure of the future decline rates at Corrib based on our numerical reservoir simulation. The property over -- roughly the next 10-year period, will have an average decline rate of about 15%. In fact, as we calculate it, it's a little bit below 14.5%, but we have just rounded up to 15% in all of our disclosure. The decline rate that is projected for next year is 17%. The year after that, the simulation has a very slight bend on a similar clot, it's essentially exponential but just a tiny hyperbolic shape to it, putting it at about 15% in the second year from here. And then after that, we're bouncing around 14%, some years lower than that, with an average of about 14% as you finish out the coming decade. So those are the decline rates from Corrib. There may well be, in some quarters, a concern, I guess, about Corrib declining. It is a very high quality pool, and over time, it is going to recover the big, big majority of the gas that exists in this very large high permeability structure. And so it is just inevitable that as we pull those molecules out of the reservoir, that's what we seek to do, it is going to decline. Now the company is -- we're over 100,000 barrels a-day company. And so whether the decline next year is 17% or, for example, 15% in a single year, on a roughly 8,000 or 8,500 boe/d asset, it comes to about 170 boe a day. So this is not a -- it's a difference that perhaps the market is focusing on is not a very significant one. Even more importantly, when you put it into the context of the various significant free cash flow generation of our European region and the company as a whole, what we see and for this, I'd ask you, when you have a chance, please, to take a look at our investor presentation on our website, Slide 51. This is a compilation of our European production since we entered Europe in 1998. And below it, we have posted the reinvestment rate into Europe that is associated -- versus European cash flow generation that is associated with each of those production bars by year. I would point out for 2019, for Europe, we have on the order, I think it's 4% growth represented. We have our lowest reinvestment rate in our history in Europe. It's been coming down for the last 3 years. And next year, that reinvestment rate represents 29% of the cash flow from Europe. So the asset grows, it cranks out about 70% free cash flow, and it actually generates more free cash flow than it ever has in the past because pricing is up and it's a bigger regional set of units that you have before. So that is a quantitative illustration of how the perhaps miniscule differences decline in Corrib did not have a very large impact on our overall results and in fact, they continue to improve. The next point on Europe. We have a very active drilling program there next year. It's by far the largest in our history. We'll resume drilling in the Netherlands. We have a French program and permitting continues to be quite readily achievable there as well. We initiated drilling in Germany, and we have quite a large program that we're initiating in Central and Eastern Europe, where we expect to have a great deal of success. So I think that what we are doing is setting up overall for the European unit is a lot more growth with in fact, probably some of the best prospects that we've ever had in our portfolio. And while Corrib, most years will have a decline, and I'll get to my final point on that property itself in the second, I think we're making up for that elsewhere in our European business and in fact, improving it in terms of production growth and free cash flow generation. Now with respect to Corrib, we do expect to become operator there before the end of the year. And once operator, we're going to study all of the optimization possibilities that we have. And if we can mitigate that PDP decline, which I think is a possibility, but we don't want to promise it until we -- are operator and we have the opportunity to study things like additional compression or reconfigured compression and other optimization and redevelopment opportunities, we're not going to do anything other than, at this point, project a PDP decline. But we do intend to study those and focus on it very much as operator, and this is one of the main reasons that we wanted to get control of the operation in that asset. The second point on cash flow, we'll have a couple of points there. I think the -- probably the first one is that it's quite a volatile period for the underlying commodities but particularly, I would say, for these Canadian differentials and I'll just remind you as I talked about in the opening part of the call, we are very differential-advantaged versus the main Canadian products of WCS, the heavy oil blend that we don't have any component of in our portfolio and we have just a small component of the Cardium-based MSW or Edmonton par light crudes. Our other crudes in Canada are very advantaged. Nonetheless, those differentials have widened, they're kind of volatile at the moment. And as a result, I think these pricing differences are going to make comparability in forward projections of '19 cash flow more difficult and to compare back to some of the sell-side estimates may become difficult until that volatility, I guess, is resolved. The next point I'd like to make about our cash flow, at whatever deck a market participant would choose to project it at, is that it is in our view, getting to some very prodigious levels in '19, under the strict deck that we've elected to use, including recognizing the higher differentials in Canadian crudes, approaching 1.2 billion. Under the strip, you can see this if you choose to refer to our investor deck on Slide 12 and in terms of FCF, which we're defining very simply as FFO minus the full in the CapEx stream, including that required to grow, that number would be in excess of $600 million, 50% more than this year, more than double the level we were at 2 years ago. So FCF generation is very, very high and we think that is the most critical factor of all. With respect to any additional news, I mean, we're making disclosure as of today, so we don't have any -- have anything else to disclose. If we get something material during the quarter, we will. Otherwise, the next update will be at year-end, at the end of February. On the initial point that you made in your question about the stock, we're looking at it actually right here, and it's operating very significantly today. And the group is largely up. That's something that we don't really understand. We felt that this was quite a strong quarter, with very strong prospects going forward, including in a budget that we had just released for 2019. We think it's quite a low level of CapEx to continue to produce growth. This is what our company is about, free cash flow generation. So I mean for -- speaking for my own view of this market action, to me it does appear unwarranted and inexplicable and something that hopefully, over time, the market would remedy. And a final point, gosh, we do pay a monthly dividend. We've been paying one for 15 years. We've increased it 4x. We've never cut it. It is yielding about 8% right now. So I think, in terms of that 8% dividend yield for a dividend program and even a capital program that includes growth under this strip with over $200 million of extra cash generation, more than the needs for -- in the CapEx and dividends, to me, it looks like a very safe dividend given that cash generating capability, given the record of the company. So an ordinarily high yield seems to me to put you 8% ahead right at the beginning. And on top of that, you'd get extraordinarily strong compounded growth in per share production, even stronger growth in FFO per share and extremely rapid growth higher than those per share metrics in free cash flow per share. So in the short term, we have market movements that we can't understand, I would believe that over the medium and long terms, that this combination of extraordinary, to me, yield and extremely high growth rates would be an attractive one and hopefully, one which the market would seek to remedy.

So that's a great answer. If I can just do a couple of supplementaries related to that. Are the Corrib declines consistent with what you'd have in your engineering reports that are part of your net asset value. So that is the first question. Secondly, is there any risk related to those engineering reports, the reserve component of it because of these declines you see at Corrib? And I fully understand that reserves decline. And then third point would be, roughly, what percentage of your NAV would be Corrib today and post the taking over of the additional portion that's upcoming?

I can answer those first two, I don't have the NAVs. None of us have it with us here. But the first two, the answer is yes, consistent with the engineering report, there could be minor variations, but I don't think there's anything significant there. Secondly, are there risks to that engineering projection? There are always risk to it. It could be lower, it could be higher. Probably, it's a pretty reliable property. It's very high quality reservoir, very well described with, I think, over time 3 3Ds, including our most recently an ocean bed cable 3D for very accurate resolution, which should reduce any uncertainty around the size of the tank. Secondly, the numerical reservoir simulation that we performed has a great deal of pressure and rate data by well as well for the field as a whole. And since you take what I think is an accurate geologic description, tank size, from a well-logged core and 3D and then combine that with a history match of all this great pressure data, I would expect it to be quite accurate, really, there's so much better data and such a higher reservoir quality that I feel like it should be more accurate than the vast majority of pools and wells that you will work with in the worldwide oil industry. And so I think it would be pretty accurate, although it certainly could vary off a bit for any number of reasons. The risk on the upside, I would point out again is something that we're going to seek to evaluate as operator to see of this PDP decline rate could not be mitigated and maybe recoveries increased through some of the activities of that I outlined earlier in the question -- in the answer to your question.

Your next question comes from Arun Jayaram from JPMorgan.

I was wondering if you give us a little bit more color on the Netherlands drilling program. It looks like you're doing 2 wells for next year. What's the permit status? And just talk to us about the plans to accelerate to up to 6 wells or so by 2021.

Thank you, Arun, for that question. I'll start answering, and I think after that, I'll turn it over to Mike Kaluza, our COO, who will go on to maybe a little bit greater detail about the permitting sequence there. So to start up in more general terms, this Netherlands question is one that seems to generate a large degree of focus. And again, kind of inexplicably to us, given the diversification of our asset base and the amount of disclosure that we've attempted to make on it previously, the -- we did not drill in 2018. The permitting system over the past year or couple of years has changed in the Netherlands and it had slowed down due to seismicity in the Groningen field in the northeastern part of the country. Now we are not an owner in Groningen, it's a very large field, very large withdrawals. And unfortunately, there have been earthquakes that have been associated with gas withdrawal there. In our fields, some of which are good-sized fields to us but nonetheless, everything outside of Groningen falls within what is called Small Fields Policy in the Netherlands. We have, I think, overall, similarly have been slowed down by about -- by the knockoff effects from the seismicity in Groningen. And that is the reason, ultimately, that we did not drill in 2018. So the permitting system in the Netherlands is and has been clarified over time. We intend to drill 2 wells, I would say at least 2 wells in 2019. Mike in a second, we'll give you the details around that. Over the longer term, and then there is a small amount of production, I think, that comes on perhaps late in the year associated with some of that drilling, but I believe it's about 2% of our Netherlands production. And the Netherlands would make up about 8% of the company's production, so 2% of 8% would be the contribution from that '19 drilling. Of course it would be larger in later years beginning in 2020. Because they are -- the productivities from these wells are good and the Netherlands, I think, over the long term going to be a good growth business unit for us and one that generates a lot of free cash flow. Now in the longer term, we do intend to have a bigger development program. We have a very large number of prospects in the Netherlands. We think they're very well-defined. We've been in the country for 14 years, shooting our first seismic probe, not until 2017. Without any new seismic over the years, we had achieved a 74% rate on our Netherlands exploration. I do believe with this very high effort, high-quality and high-resolution seismic, it will be better in the future. The seismic actually does contribute to improved cycle times and reduced surface footprint and, therefore, better permitting characteristics as well. Given the high-quality of the seismic data set and the way it has helped us firm up and have great certainty and a very accurate location of the perspective pools in that data set area, what we will be doing with the majority of our drilling in the future is to drill fairly long departure, but not extraordinary by modern industry terms, fairly long departure wells of an S-shape, start out basically vertically from existing sites, have a long departure, perhaps up to 4 kilometers at a 2-kilometer, 2-vertical depth, turn to well back to basically vertical so that we could intercept all of the perspective zones there. And typically, we have 2 or 3 perspective intervals to produce from. Now we don't want to go through one of them horizontally, we want to see all of them so we would turn it back into an S shape. This S-shaped drilling, in the end, I think that will probably save money because when you're gone from existing sites, you don't have to replicate surface pad pipeline, many times facilities, so I think that given the way modern directional technology is, will probably more than offset that directional cost from a long-departure wells. And should produce a surface footprint and, I think, make aspects of the permitting process easier and faster and it gives us a great deal of confidence in achieving the long-term ramp up in the Netherlands activity that we've outlined in our release and more fully in our IR deck, our corporate presentation. And you can refer to Slide 61 to get more details on that. So with that, I would turn it over to Mike.

Sure. Thanks, Tony. So in the Netherlands, when you're going to drill a well, you basically have 2 sequential components to the permitting to get that well drilled. First is the environmental impact assessment and then the second is the actual drilling permit. So for our 2019 drill, we actually -- we've received the positive results for those -- for the EIA assessments, and we've submitted the actual drilling permit. So we're anticipating an approval date on those -- on the drilling permits probably in the order of 6 to 8 months, those have already been submitted, so that's given us ample time to get our final permit approval prior to our anticipated spud date, which is during Q3 of 2019. In regards to future programs, really, what we're trying to do is build a 3-year inventory of drilling permit. This would give us some certainty on the predictability of our capital programs. And by the end of 2018, we will have initiated 9 additional permits and then through the first half of 2019, we'll probably have another 4 to 5 permits in for approval. So that will give us a good start on that to set us up for the drilling beyond 2019 and 2020 going forward.

Great. And just my follow-up, Tony, I wonder if you could just set up the first operator, the well opportunity in Germany, supposed to occur in first half of the '19.

Certainly. So we're looking very much forward to drilling in Germany. We've had pretty good production profile there without drilling, just out of workovers. And the most significant event I'll speak, to a minor one at the very end, but the most significant event we have would be drilling at the Burgmoor Z5 well. This is in Dummersee-Uchte license. It is an extension really as play off of the existing pool kind of a semi-development prospect. It's in the order of 50 DCF gross. It has ultimately been worked into the original ExxonMobil producing Germany farmout that we made there. So under the deal that exists today, it's really in a sense the first farmout wells lower risk prospects. And we're very, I think we have a 46% post capital working interest in that well, and we're very much forward -- are looking forward to the drilling of it over the next number of years, about 1 well per year. We have set a very significant exploration prospects that will also be drilled on the ExxonMobil farm. And these very large prospects would still, in our view, pretty good chance factors are outlined on Slide 64 of the investor deck in terms of the -- at the higher end of the probability distribution, the larger potential field sizes, certain of these prospects could be as large as the TCF. And generally, we would have a 50% to 60% working interest on those as we've moved out later in that long-range plan period, getting probably 4 years out or so, we have some 100% very, very large prospects to drill as well outside of the farm in. So in addition, next year, we'll be doing a 1 to 2 sidetracks of existing wells in the development properties in Germany.

Your next question comes from [ Ming Feng ] from [ Pica Mulhane ].

Hey, Anthony. I just have a couple of follow-up questions. My first question pertains to crude oil marketing. For the Spartan assets, do you primarily just sell at [ Cromer ]?

We -- for Spartan, almost all of the crude is priced off of LSB. It's either LSB or Midale crude. Midale is a little lower quality and has a couple of dollar discount to LSB but all sold actually in Southeast Sask. There is a very small component, I think it's on the order of -- I don't know, maybe 800 barrels a day of Viking crude that does not go against the LSB marker. It is still in Saskatchewan. It's in Southwest Sask though. And sells into corroborate. It is really referenced into MSW. So our MSW components would be that small amount of Viking oil that we got from Spartan and then our legacy position, mainly in the Cardium in West Central Alberta.

Okay. So what percentage of your crude production for next year is using budget assumptions as exposed to MSW? It will be smaller?

It is. It is 8% of the global oil production and oil production's about half of our product mix, so it's about 4% of the boes and 8% overall.

Okay. My next question is just on the PRB. One is currently -- what kind of wellhead pricing are you getting on the PRB? And two, are you worried about egress because from what I'm hearing, EOG and TransEx ramp-up volumes and the outcome pipelines are completely full?

The answer to your questions are -- the first one, our price at the wellhead, this is after transport, is minus $2.60, minus $2.60 from WTI, so that's a very good dip in today's world. Secondly, there may be, probably given the quality of the Turner throughout the basin and the potential from some to shelf the projects there. In addition a few of the other stands apartment, which will have some of the Shannon Sussex, there is probably going to be a ramp up in the Powder, it's a good basin. However, it is that least a present overserved by the local refining. So I don't have a basin wide forecast to compare to, but I think in comparison to the other basins, this one would be probably have the best the demand/supply characteristics.

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

Kim, thank you, and thank you to all of our participants today. We look forward to speaking with you again after Q4 2018 year end results are reported in February.

So this concludes today's conference call. You may now disconnect.