Vermilion Energy Inc. (VET) Q2 2019 Earnings Report, Transcript and Summary

Good morning, my name is Chris, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Inc. Second Quarter 2019 Earnings Results. 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]. Anthony Marino, President and Chief Executive Officer you may begin the conference.

Good morning, ladies and gentlemen, thank you for joining us. I'm Tony Marino, President and CEO of Vermilion Energy. With me today are Mike Kaluza, Executive Vice President and COO; Lars Glemser, Vice President and CFO; Kyle Preston, now our Vice President of Investor Relations and other members of our management team who may be called upon during the Q&A session. As in our last quarterly call we will be referring to a PowerPoint presentation to discuss our second quarter 2019 financial and operating results. The presentation can be found on our website under Invest with Us and Events and Presentations. Slides 2 and 3 in the presentation refer to our advisory on forward-looking statements. These advisories describe the forward-looking information, non-GAAP measures, and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion. Slide 4, Q2 review. We delivered average production of 103,003 boe/d down slightly from the prior quarter. The decrease was primarily due to a third party refinery outage in France which temporarily curtailed our production in the Paris Basin impacting the quarter by approximately 1300 boe/d. Partially offsetting this were strong production results from our U.S. and Australia business units which increased by 21% and 14% respectively compared to Q1. I will talk about the operational results of each business unit later in this presentation. Q2 FFO was $223 million or $1.44 per basic share which was down 12% from the prior quarter. The decrease was primarily due to the refinery impact in France $11 million, the timing of crude lifting in Australia $8 million, and weaker natural gas prices in Europe and North America $22 million net of realized hedging gains. The results were positively impacted by stronger oil prices and lower operating costs which decreased 15% from the prior quarter to $11.04 per boe. Now getting to the country specific updates. Slide 5 France, Q2 production in France averaged 9800 boe/d down 15% from the prior quarter primarily due to the refinery outage that I referenced earlier. The Grandpuits refinery where all of our Paris Basin production is normally processed was shut down in Q2 due to a failure on the refineries main feedstock line. This pipeline doesn't carry Vermilion crude. Nonetheless, the refinery did not have enough feedstock available to operate until the line was repaired. During the outage we made arrangements to ship most but not all of our oil to alternate delivery points in France and Germany on trucks and barges. This reduced production by approximately 1300 boe/d and reduced after tax FFO by approximately $11 million due to reduced sales and higher transportation expense. We also had to expend 2 million in capital to put the necessary equipment in place for trucking and barging. The refinery recently returned to service and has resumed processing Vermillion deliveries. I want to recognize the tremendous effort and accomplishment of our French staff to put in place the trucking and barging operation in a very short time. In the trucking portion alone our distance hold was 1.5 million kilometers. Most importantly our French staff and their vendors did this without any significant safety or environmental incidents. Slide 6 Netherlands. In the Netherlands Q2 production increased 3% quarter-over-quarter to 8917 boe/d primarily due to our successful work over and maintenance program. We recently began site construction for the first well of our 2019 drilling program, the Weststellingwerf well 50% interest which is expected to commence drilling in August. During the second quarter we received the draft drilling permit for the Waalwijk South well also 50% interest, the second well in our planned 2019 drilling program. We expect to commence drilling this well in Q4. These wells will represent our first drilling in the Netherlands in two years. Slide 7 Ireland. In Ireland Q2 production decreased 5% from the prior quarter to 8201 boe/d. The decrease was primarily due to natural declines and some minor facility downtime. We have now been operating the Corrib facility for eight months and have focused on improving overall operating efficiency and costs. As a result of our efforts operating costs decreased 14% in the first half of 2019 compared to the first half of 2018. Looking forward we'll continue to focus on evaluating future facility and drilling projects and optimizing our maintenance activities. Slide 8 Germany. In Germany production in Q2 averaged 3473 boe/d, a decrease of 8% from the prior quarter primarily due to unplanned downtime on operated and non-operated assets. During the second quarter we successfully drilled our first operated exploratory well in Germany, Burgmoor Z5 well 46% working interest. This complex well was completed near the end of June and was then handed over to our partner ExxonMobil for well test activities in July. The well is drilled to a measured depth of 11,480 feet and encountered 260 feet of gross pay in the feet of gross pay in the Zechstein Carbonate. Around a half of the gross section has matrix porosity [ph] above our porosity cutoffs and the other half may contribute as well via natural fractures. During the fourth week of July ExxonMobil tested the well at a final flow rate of 8.8 million cubic feet a day. The test rate was limited due to weather conditions. Following the successful completion of our first operated well this summer we are planning to drill at least one exploration well in Germany each year over the next several years targeting other sizable gas prospects in the North German Basin. Slides 9 through 11 Central and Eastern Europe. In Central and Eastern Europe we commenced our 2019 drilling campaign during the second quarter. Including a well drilled and completed in July we drilled five 4.3 net exploration wells. Four of these five exploratory wells resulted in new gas discoveries while the commitment well in Hungary was dry. Slide 10 provides an overview of the Hungarian drilling results. We drilled a total of three 2.3 net exploration wells in Hungary during the second quarter and one 1.0 net subsequent to the quarter. The first well was a commitment well and did not encounter an economic quantity of gas. The second well 100% interest, encountered 15 feet of net gas pay and tested at a rate of 1.4 million cubic feet a day and 55 barrels a day of condensate. The third well 30% interest encountered 26 feet of net gas pay and tested at a rate of 2 million cubic feet a day. The fourth well 100% interest encountered 17 feet of net pay and floated at a rate of 3.4 million cubic feet a day on test. Slide 11 shows our Croatian results. Our first well in Croatia the Ceric-1 well 100% interest was quite a success in encountering 32 feet of net gas pay and testing at a rate of 15 million cubic feet a day. We're very encouraged with the initial results from our 2019 CEE drilling campaign to date. We look forward to the rest of our Hungarian and Croatian program and to initiating our Slovakian program later this year. These are high production rate, low capital cost wells and over time they will allow our CEE unit to contribute meaningfully to the sustainability of our capital markets model. Subsequent to the second quarter we further expanded our presence in the CEE as we were awarded two exploration licenses in Ukraine in a 50/50 partnership with UGV, a Ukrainian state owned gas producer. The two exploration licenses totaled 585,000 gross acres of land in the prolific Dnieper-Donuts Basin and are in close proximity to several multi TCF gas fields. Most of the Basin and subject license area is still not covered by 3D seismic and is under exploited and under attack in our view. The licenses include a modest back end weighted capital commitment over a five year period. Our entry into Ukraine is a natural progression of our CEE strategy. It aligns with our approach of capitalizing on opportunities in under exploited basins by using modern technologies to improve such success rates and recoveries. Ukraine has very high oil and gas prospectivity with minimal use of modern technology over the past 30 years. Similar to our approach with other new country entries we have partnered with a local established company UGV which provides regulatory knowhow, access to data, and access to services. Given that the licenses include a modest and back end loaded capital commitment over five years this provides us with plenty of lead time to plan and execute our future activities. Slide 13 Canada. In Canada production averaged 61,507 boe/d in Q2 representing a slight increase from the previous quarter. Contributions from our active Q1 drilling program were partially offset by unplanned facility downtime and spring breakup. Our Canadian revenue in Q2 was negatively impacted by weaker NGL and natural [ph] gas prices which were down 50% and 39% respectively relative to Q1. However, this was partially offset by lower OPEX which decreased 6.3% from the prior quarter to $10.79 per boe. Slide 14 United States. In the United States Q2 production increased 21% over the prior quarter to 4414 boe/d reflecting the positive contributions from our first half 2019 drilling campaign. We drilled, completed, and tied in four wells all 100% interest during the quarter. The wells have performed ahead of our expectations to date. The first two wells were equipped with rod pumps and produced at peak IP30 rates of 325 boe/d on average per well. The next two wells were equipped with ESPs and produced at a peak IP30 rates of 635 boe/d on average per well. With the higher production volumes during the quarter we also saw market improvement in our unit operating cost which decreased 15.5% from the prior quarter to $8.82 cents per boe in Q2. The fifth well of the program at 100% interest was Spud [ph] toward the end of Q2 and was drilled in less than 12 days representing a 28% improvement over the fastest well in the first half of 2019. We plan to complete this well and drill the remaining three 3.0 net wells of our 2019 program during the second half of the year. Taking over operatorship last year we've achieved a 15% reduction in drilling, completing, equipping, and tie-in cost and expect another 10% improvement in the remaining wells this year. Slide 15 Australia. In Australia Q2 production averaged 6689 barrels a day, an increase of 14% from the previous quarter due to a full quarter contribution from our two well program completed in January. We continue to manage production to meet our annual production target of 6000 barrels a day. Production for the first half of 2019 averaged 6278 barrels a day slightly above target. We received premium pricing on this crude. Year-to-date this premium to Brent has averaged U.S. $5.29 per barrel on contracted volumes and up to a U.S. $12.50 per barrel premium for spot liftings. For our Q2 sales volumes we realized an average price of $99.39 per barrel which translates to U.S. $74.32 a barrel reflecting a premium of U.S. $5.50 over dated Brent. Slide 16 corporate update. We have several other corporate developments that we reported with our Q2 2019 results. Our Board of Directors authorized an application to the TSX to implement a normal course issuer bid for a maximum amount of 5% of the issued and outstanding shares of Vermillion. The NCIB is intended to augment our ongoing return of capital via dividends. We plan to employ the NCIB under appropriate market conditions and will allocate excess free cash flow beyond our dividend stream to both debt reduction and buybacks. On June 12 2019 we entered into a series of cross currency interest rate swaps with the syndicated banks converting the remaining term of our 5.65% U.S. $300 million senior unsecured notes due March 2025 into a 265 million Euro obligation bearing interest at 3.275%. This swap is expected to reduce our annual cash interest costs by approximately $9 million. Along with our European gas hedging program and our M&A and country entry advantages we see this cross currency swap as another example of benefiting from our strong presence in Europe. And lastly on the ESG front Vermillion was recently rated AA in MSCI's annual ESG rankings for 2019 which is an improvement from our A rating last year. This new rating places us in the top 19% of oil and gas companies worldwide. We are determined to be the leader in energy sector ESG performance. Slide 17 hedging. The last topic I'd like to discuss is our hedging strategy. We actively hedge to manage our commodity price exposures and increase the stability of our cash flows which provides greater certainty for our dividend and capital programs. One of the unique advantages we have at Vermillion is the ability to hedge across multiple products and currencies owing to our internationally diversified asset base. We currently have approximately 40% of our expected net of royalty production hedge for Q3 2019 including 71% of anticipated European natural gas volumes for Q3 2019. European gas prices have been particularly weak this summer due to increased LNG deliveries. However, European gas remains in strong contango compared to the front month price with the calendar 2020 strip or NBP at approximately $8.50 per mmbtu. In fact the calendar year strips for each of the next three years are within about 1% of where they were a year ago. While our fundamental view on European gas is that the forward market realistically reflects supply and demand drivers were willing to lock in this curve and attended strong levels of free cash flow and expected project economics. Accordingly we have had 69% and 65% of our anticipated full year 2019 and 2020 European natural gas volumes respectively at prices which are expected to provide for strong project economics and free cash flows. The hedge program continues on into 2022 and we're continually raising our European gas hedge percentages into that strong contango curve. With respect to oil, we are one third hedged for the rest of this year at very attractive prices. Most of our structures are participating contracts either two way or a three way collars. Our average floor is $73.50 per barrel and our average swap is $87.88 per barrel. As always these are in Canadian dollars unless otherwise noted. Based on our 2019 capital budget and production guidance and applying the forward commodity strip and current hedge position, we expect to cover our full capital program and dividend with internally generated cash flow. Our 2019 capital program is designed to deliver annual production per share growth of 8%. We believe this level of growth combined with the dividend yield of 12% represents significant value. As we look forward to 2020 we believe that a redoubled emphasis on restrained and efficient capital investment both in North America and overseas, continuing to take advantage of unique opportunities afforded by our European assets in areas such as hedging, and our early stage success in the U.S., Germany, and the CEE will underpin continued sustainability in our capital markets model including our monthly dividend. The establishment of our NCIB gives us another tool to return capital to our owners and another vehicle to augment per share growth. 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 Dennis Fong with Canaccord Genuity. Your line is open.

Hey, good morning and thanks for taking my questions. The first one just quickly on the Burgmoor Z5 well I just wanted to understand it sounded like there was either a shortened testing period or something different from the standard testing that you guys did there, I just was wondering if you could provide a little bit more detail on that? I have a follow up question, thanks.

Okay, for sure Dennis, thank you. Yeah, so that well was being tested at a time of unusual weather conditions in Europe. Temperatures there were around 40C, 104F. It had been dry for several weeks and we never want to do very much flaring but some limited amount of flaring is required during the testing time and our operator there I think exactly correctly limited the task to a lower rate because the higher the rate that you test at the greater the temperatures are around that flare and we always want to take the utmost conservative approach when it regards safety and just didn't want to increase fire risk. So the well was steadily cleaning up as they typically do during the test and of course it would have been exciting to report an even higher rate but in the end I think we got the information necessary out of the tests despite the rates being held down. And I think we've got a very good result there. So that's the background on the testing.

Okay, great, thanks. And then the second question here is just on capital allocation and so forth. So I know you outlined that that excess free cash flow will be looked to be allocated between debt repayment and potentially share buybacks whenever that potentially gets approved by the TSX. I was curious as to how you guys plan on thinking about capital allocation on a go forward basis, if this could mean potential modifications to your capital spend profile, as well as what kind of priorities you guys have with respect to allocating dollars across various pockets [ph]?

Yeah, so you're asking about a kind of a forward capital profile. So as I spoke to a little bit in the presentation there we've got a long-term record of providing very significant per share growth, very steady record in PPS growth, cash flow growth particularly a free cash flow growth. And I think as we look forward -- looking at the market conditions and the difficulties that the independent energy sector, especially the intermediate sector I would say probably a little more pronounced in Canada but also a factor in the U.S. industry as well has I guess attracting capital. I think we will have an increased emphasis go forward on even further restraint in our capital budget levels. Now our capital program is substantially reduced from where it was in the early part of the decade even though the company has tripled in size. So we have I think had a very efficient capital program and that's why we've been able to run this growth and income model as we have during this time. But I think as we look forward we haven't set any kind of budget for 2020 and we're not going to speak numerically to that today. It would be later in the year. Last year we released was Q3, that was relatively actually I think the earliest of any of the intermediates in the budget cycle. That might be the case again and perhaps this year we will wait until even later in the year to release a budget just to look at the pricing conditions that are unfolding in front of us. But, I think it's very, very possible that we'll see a even greater emphasis on restraining capital and therefore perhaps less of an emphasis on growth than we have had in the past. The uses of that capital, first of all we've got our dividend program and we don't anticipate any change to that. And it is extraordinary to me that there are levels to which the yield has been traded in the market. We're certainly very committed to the dividend here and there can be an additional return of capital via the NCIB. We will look at the forward pricing conditions and look at the excess cash that is available beyond the use of dividends and then a portion of that excess cash would be allocated to the NCIB and a portion to the continued debt reduction.

Okay, and then last question here is just with respect to the potential installation of NCIB, how should we think about the DRIP program?

Yeah, let me just spend a couple of minutes kind of going through the history of the DRIP and why we have a DRIP. So the DRIP started at the beginning of the trust era in 2003 and it was the mode of the trust to offer a 5% discount for participants in the DRIP if they wanted to reinvest in shares of the company. We kind of recognize that large discount as an anachronism kind of related to the trust here. So when we were in the corporate era beginning in 2013 we reduced the discount to 3%. I believe we subsequently reduced it to 2% in 2016 and we eliminated the discount a little bit over a year ago. So what we offer currently is an undiscounted DRIP. Now there isn't a huge percentage uptake on the DRIP that currently I think for this year we have about 6% or so average uptake on it. So it is a pretty small amount. It's probably on the order of 20 million or 25 million a year that is reinvested and that's the first point I'd like to make. The magnitude is not very large. Given that you might first ask I think why do you have the DRIP at all then because I've seen some market commentary suggesting that it's sort of inconsistent with the other things that we are doing. Now, this DRIP at an undiscounted level exists as a service to our shareholders. I have had some bigger kind of institutions, I've had a family office tell me they participate. However we believe that the vast, vast majority of the participants in it are individual investors, what we would call retail investors. Now there's -- I think there's a perception out there in general that doesn't really specifically apply to a million or even energy companies but it's kind of about the financial markets overall that they're tilted against the little guys, that these -- the big institutions have greater economies of scale, lower transaction costs, that there are all these advantages that institutions and hedge funds have in their activities in the market. So for us the DRIP is something that we have had traditionally available for the benefit of small investors, retail investors and we have many of them in our company who own shares in our company and we do hear from them fairly frequently about their participation and their appreciation of having that DRIP. There is no discount on the DRIP. However it does mean that they at least can reinvest a cash stream that depending on their individual preferences if they're in the DRIP they know clearly don't have as great a preference for cash, they want to reinvest in the company, they can reinvest it with no transaction cost. So it's just a little thing that our company can do to level the playing field in the face of all this criticism that small investors just don't have an opportunity to be treated equally or have an equal chance in this market. So we have the DRIP, it's a deminimum amount, and I appreciate your question in combination with the NCIB, if you like you can view the NCIB if you -- Dennis I wouldn’t put you in this category but for those DRIP haters that exist out there you could view it as a way to immunize this small but apparently to them devilish impact from the DRIP.

Okay, thank you.

Your next question is from Asit Sen with Bank of America Merrill Lynch. Your line is open.

Thanks and good morning guys. Tony, appreciate the increased focus on capital returns but just wondering how you are thinking about the optimal or target debt level relative to the roughly $2 billion net debt and let's say two times net debt to EBITDA here?

Yes, so our target is to continue to delever as we have been really for the last five years in the debt ratio from the current level of about 2X to 1.5X. Actually, we would define the target in terms of debt to cash flow so if we're speaking in terms of debt to EBITDA this might be 1.3X or so. So we are determined to delever to that target. We have been on a downward path for about the last five years in that debt ratio. We seek that target even though our operating leverage is a lot less than other companies would have in the sector. This is because of the high margins that we start with, it's because of the product mix diversification that we have with the low correlation of pricing on the various commodity inputs to our model, and despite the fact that we do run a pretty consistent hedging program to further dampen down the volatility of the cash flow. So there are a variety of things to control the operating leverage which is sort of half the equation and it is lower than other companies. So the other part of the leverage question is the debt side and we do seek to bring it to this 1.5 level and it's not going to happen overnight. It does depend on commodity prices for sure but that is our target and that's why we don't take all of that excess cash and put it toward an NCIB. I might turn to Lars for just a second to comment on our interest cost and cost of debt while we contemplate that debt level.

Great, thanks Tony. I think I need to highlight as well is targeting a leverage ratio that is lower than where we are today. We will get there over time. I think the thing to highlight as well and this is an unique characteristic that we're afforded by our European presence is the ability to control the cost of the debt that we have on the balance sheet as well. We drew attention to the trade that we did in mid June where we swapped some of our U.S.D. debt to the Euro and that will now carry an interest rate of 3.275%. When you factor that in the overall cost of our debt to service it from an interest rate perspective is below 3.4% now. So I think that's just another unique attribute I would point out as well looking to deleverage overall operating leverage and then in addition to that a very competitive cost of capital in terms of what we are able to service that debt at as well. So I would just add that to Tony's comments.

Appreciate the details guys. So my follow-up here is on, Tony your comment on a restrained capital spending, could you remind us on your capital spending flexibility, in other words what's your current sustaining CAPEX levels to keep production flat and what are kind of the levers that you initially think about?

Okay, so we have related previously at the beginning of the year our estimate of sustaining CAPEX for 2019. So, the history on this is that we were quite early in the budget cycle vis-à-vis the other companies to put out our 2019 CAPEX. It has just been our tradition to release it with the Q3 results and that turned out to be kind of early in the market. A number of companies that were out with Q3 quite as early delayed it all the way to the end of the year. Circumstances were at the end of 2018 relating to this 2019 CAPEX budget that we have this rapidly cratering oil price. And we're about a month into the two and half month decline that started at the beginning of October at the time we released that budget. So we established our budget early and then of course we began to get inquiries about well how flexible is this budget, what are your priorities between if we're in this low oil price environment. I think it bottomed at $42 WTI in December and how would you respond to protracted weakness in the commodity. As we pointed out of at that time our priorities are balance sheet and dividend and CAPEX or growth well after that. So in the last quarter of the year after we had released the budget kind of the December, first part of January timeframe we actually established a whole range of alternative budgets, you know, ones that called for starting with the full 530 that we had for the year outlined at the release at the end of October. And then ones that steadily took the growth rate down. In fact, gosh, we had a whole full set of them. I think we had a 530 delay budget that is basically what we implemented this year. We pushed out certain projects to later in the year just to give greater flexibility entry year. We had I think a $400 million budget, a $300 million budget and $200 million budget that we constructed. And we've built up the actual projects inside of each of these budgets. So, the one that kept us flat at -- so we have $300 million and $400 million budgets. The one that kept us flat at 2018 production levels, annual 2018 to annual 2019 and making an adjustment for the acquisitions that we did in 2018 so you had to add back into the 2018 volume the months that we did not own the acquired assets really applied to Spartan and highlight. And so we established by taking away projects between the $300 million and $400 million budgets that to keep us flat at that level 2018 to 2019 was $365 million. So that's a sustaining CAPEX level required to be flat on the annual basis 2018 to 2019.

Appreciate the color Tony. Thank you.

Your next question is from Joseph Shutter [ph] with Shutter [ph] Energy Research. Your line is open.

Thank you very much, good morning Tony. Just to clarify on France, production now is back up to the 11,000 plus range and the trucking and all of that required during the interim unplanned outage is now behind you?

I'm sorry I missed the very first part of it.

We are talking about the plans with the 1300 boe today that was where you had the outages because of the Grandpuits refinery. Is that now behind you and shipments are shipping full amounts over 11,000 and not using trucks anymore and barges?

Yes, that is that is basically correct. The refinery just came on in the last week or so and they have started taking our oil directly in by pipeline. So I don't think we are running any more trucks and we're probably very close to getting all of the -- all the wells back on that we had shut down. So if we're not there today we should be there very, very shortly.

Okay, thank you. Second question on Ukraine, the area you're in the is just West of the disputed territories with Russia, is there any operational working problems in the area or is it totally within the government offices?

Okay, yeah so the two blocks that we have Balakliyska and Ivanivska are about I think that the closest they're about 150 kilometers from the [indiscernible] which is the occupied part of Eastern Ukraine. And no, there are no operational difficulties in conducting operations there. I would say where we think Ukraine as a country that is definitely on the way up, I'm sure you're probably pretty familiar with the recent election of a -- President Zelensky and continuing -- and accelerating I would say, expanding the progress of the country made ever since the MyDan [ph] five years ago. So, the country ranks pretty well on ease of doing business. I think that this government is very, very committed to transparency and to elimination of corruption. That's something that an advantage a million brings to the table is our exceptional ESG standards that we have. It applies on the contracting and governance side as well as the environmental side. And we think it's a great place to be because there just aren't very many places in the world where you can be around next to on our licenses for example in 18 TCF field yet you haven't had meaningful application of technology since the Soviet era. And for us that's exactly the position we want to be and we have the success already in the CEE which in Croatia alone we were able to produce a very significant result there in an area I don't think that anybody had really counted on for producing meaningful production and significant cash flow and good pricing environment at such low capital cost and now if you think of Ukraine as an extension or an amplification of this you've got an area that is amazingly hydrocarbon prone. I mean up to the discovery of the Siberian fields around the 1970's and the 1980's it was the big majority of the USSR's production yet it's kind of been frozen in time with respect to investment and technology and we are right next to these fields and it's not just the 18 TCF field there is a variety of multi TCF fields next to the license areas. Of course existing fields are not part of the licenses but the areas next to them are. There isn't much 3D that has been shot so, we think it's a great way to take care of this expanding European franchise that we have. It's a way to take advantage of the great ESG performance that our company has and we think it's going to be in a country that gets better and better and better over time. So, that's our view on Ukraine.

Yeah, no, I think that's a great idea and Ukraine definitely needs natural gas discoveries so that they don't have to import from Russia. Last question for me is once the TSX approves the NCIB and you have the option of buying shares, is there -- are you looking at waiting till you get free funds flow from higher commodity prices in 60's that you don't increase debt or you are willing to increase debt to take advantage of these very low prices for your stock and allow debt to go up a little bit once you have the TSX approval?

Yeah, we're going to look at the commodity environment. We want to do it in situations where we have excess cash beyond dividends and we're just starting with this NCIB with the application now. I think as you look forward to 2020 we have an opportunity to formulate a brand new budget under as I said in the call and it was in the introductory presentation and in one of the answers, one that I think will reflect redoubled emphasis on capital restraint and capital efficiency that will give us a great opportunity to look forward to the year at the commodity prices that we have at that time. But, the NCIB of course could be applied earlier but we're going to want to do it in situations where we can look at the market prices, the commodity strip, and say that we have excess cash beyond the need for dividends and then at that point we'll be dividing it up between debt reduction and the NCIB.

Okay, super. Thank you for taking my questions.

Your next question is from Mike Bowcott with TD Waterhouse. Your line is open.

Hi, just give us a [indiscernible] industry today versus what it was a decade ago, obviously planning and going forward is going to be challenging here, and I am trying to still reconcile the DRIP plan with the NCIB, it seems like it's contradict each other but I wondered if you have given any thought to creating some flexibility with regards to your dividend in terms of using that or provide yourself with greater flexibility to buy back your shares by maybe reducing your dividend and going to special dividends or something along those lines that you could then decide and give yourself greater flexibility going forward as to how best to apply that capital because your stocks is hitting 52 week lows here, obviously it is very frustrating, the market is obviously believing that the dividends are going to be in jeopardy and I guess trying to get some flexibility around that would be helpful, just curious of your thoughts on that?

Yeah, thanks, you have got several elements in the question I'm going to try to remember them and work backwards on here. So the first thing is yeah, the markets I think we totally hear you on that one, the market is saying that we don't believe this dividend. It's a funny thing right, because as we discuss it among the management team we're very well cognizant of the stock price and the market reaction as you point out at the very beginning your question and what has been a markedly different and difficult environment for energy equities. When we have our discussions we don't entertain reducing the dividend. We don't have any intent to reduce the dividend. Even today with the most recent down drift in commodity prices, it is still covered along with the full capital program even including all of the growth CAPEX it's covered. These uses of cash are covered by internal generation of cash. So we just have not entertained a reduction in the dividend and it's not something that we intend to do. Now as I say this I will never say and I never have said any time I've been asked this question that there was -- is there any circumstance in which you would reduce the dividend, well obviously if we had significantly lower commodity prices perhaps across the board and they stuck around for a significant period of time would we have to entertain a reduction in the dividend. The answer to that is yes but that's the only qualification I will put on this support for the dividend. We didn't cut the dividend when it went to $42 WTI in December. In previous history yes, as you point out conditions were different a few years ago but I think we got to $27 oil in Jan 2016. The dividend is something we're proud of, we think it's good for the owners of the company. We think it's good for the shareholders to get a dividend back. We think the model -- we think it's what has made the model successful over the years, it is what enforces capital discipline on an industry that has lacked capital discipline. I don't think that has so much applied to Vermillion myself but nonetheless it's the -- it's a wrap that the industry gets and it has forced us to put both overseas and in North America operations in place that have the right characteristics, the right margins, decline rates, capital efficiencies, such that we can generate enough cash flow to grow the assets and to throw off significant excess cash beyond that so that we can pay the dividend. And that's why we have those assets overseas, we shifted around the North American unit to be able to do the same thing. And so no, we don't intend to cut the dividend and bringing the NCIB the purpose of that is not to let us cut the dividend and instead use it for buybacks. It is there to augment the dividend. And it is true, stock seems awfully low to us. But it is a long-term effort that we are engaged in here. The dividend has been there for the long-term. Previously we intended to have it there for the long-term going forward. The NCIB just gives us the flexibility to using another tool to return capital to the owners of the company to try to redress inordinately low stock prices. It's even a way to give you another method to produce per share growth instead of just drilling for it. So we think that the flexibility associated with it is great but it's not there to -- it's not there to take away from the dividend. I think in the list of questions that you had we also had one about the DRIP. Now, Dennis Fong asked about that earlier and again what I would summarize out of that earlier answer is that first of all it's a deminimus amount. Secondly, it's there for the retail investors primarily and we don't want to take that away from them. Thirdly, I think people should view this NCIB as a positive thing in conjunction with the DRIP and instead of it somehow being contradictory to the DRIP if you're one of those bigger market participants that sees it like a real bad thing to have that DRIP available to choose by the retail investors then the NCIB gives a way of immunizing for that deminimus amount of issuance that occurs under the DRIP. I mean we'll look at all of our programs including the DRIP, we will continue to assess their validity, their relevance as we go forward. But that is one traditional service for the smaller investors of the company that at least based on what they report to us their use of it I know commissions have come down across the board but still the small investor does not get the razor thin transaction costs that these big hedge funds for example get. And they tell us that they see it as something positive that we do to help level the playing field.

Thanks for the update.

Your next question is from Arun Jayaram with J.P. Morgan. Your line is open.

Hey, good morning Tony. I was wondering if you could talk a little bit about the implications of the Burgmoor well but on the EUR from that initial well and just from on a go forward basis how Germany think will keep compete from capital?

Okay, thank you. So what are the implications of the Burgmoor well. So we have constructed a whole series of exploration prospects in Germany and kind of on this continuum of places that just haven't had very much investment Germany would sort of -- it would have had more investment say than Croatia. And a lot more investment than say Ukraine, so kind of establish a continuum, Germany, Croatia, Ukraine. But they're all on the under invested side of the spectrum. Way, way, way under invested compared to what you would ever see in North America and they've all got a different set of reasons. In the case of Germany it's really driven by the very large companies that dominated over the years and there was just onshore Europe isn't going to be the kind of thing that can move the needle for him. This is what we found earlier in producing acquisitions in France and Netherlands. In these places that are just -- they just don't get the capital because typically they can't move the needle for the bigger companies. There's a good investment stream available and that's why if you turn to the investor deck I'm sure you've seen this previously, we can have quite a record of outperformance upon taking over assets like that just because they get more emphasis -- investment emphasis than they could get as kind of just total cash cows under their previous ownership. And they still throw up a ton of free cash. I mean Europe overall throws off about two thirds free cash for us but nonetheless there's an investment stream that's available there that is just higher rate of return than you would find for the average project in North America, for the industry in North America. And we've got a whole string of these exploratory prospects. None of them is the same, they are not in our view -- they are independent prospects and so by that I mean that the success on one actually does not have a success -- or failure on one does not have a specific technical bearing in changing our estimates of success on the next wells. Now what we have outlined is that we intend to drill one exploration well per year for the next four years and this was the first of them here. The kind of the chance factors and the distributions for EUR are outlined elsewhere in our disclosure in our deck, in our corporate PowerPoint. But the way I simplified this down was to say if you just call them all roughly 50% chance factor projects and you drilled four of them in a row that would suggest that your chance of rolling snake eyes on the entire program would be about 6%, I think specifically 6.25%. The other 94% of the time you'd make at least one discovery, you would have a 6% chance of making four in a row. Any one of them is pretty significant to our German unit and a combination of them of course would be very, very powerful for us. So the first implication to talk about here is it means that we're not going to be completely shut out in this program. We've eliminated that 6% that we had prior to drilling the well. I don't think we're going to change the probabilities on the remaining prospects, because we do consider them technically to be independent of each other. Perhaps I guess you could that it suggests that there's a little bit of technical conservatism in our chance factors that we place on the prospects especially given getting four out of five so far this year in the CEE. Maybe those are kind of underwriting the chances on those a little bit that may well be the case. So there is -- I'm not going to commit to it here but there is some possibility that we're a little conservative in the placing of those chance factors. But I think the implication is first of all we're not going to be shut out; secondly, it makes us even more enthusiastic about the rest of the program. As you look at the next prospects these are some very large -- potentially very many multi pool prospects that we are drilling. I mean some of them are on the order of maybe a half a T in size gross. There's more than just three prospects that we've been maturing so we're going to have a few alternatives and maybe even longer program than what we have outlined. So I'm very optimistic about it. We don't have a new EUR estimate. The well tests was just done about a week ago, we will have to -- we're just in the process of the analysis to try to estimate that. So did I cover your questions on that.

You did, you did. I just had one quick follow-up Tony. In 2Q you had a little bit of unplanned downtime. I think you talked about France, Germany, Ireland, Netherlands. You did address France I think on the call. But is there any lingering impacts from Germany, Ireland, and Netherlands in 3Q and how do you think production is shaping up for the back half of the year relative to your 101,000 to 106,000 boe per day guide for the full year?

Yeah, the overall answer is we don't have any change to guidance. We're producing around the middle of the guidance range. And the first part of your question, any lingering problems in Netherlands, Ireland, or France -- Germany…

Germany, you just highlighted in the ops update that you just had some unexpected downtime. I was just trying to gauge if any of that had a knock on effect to Q3 in the back half of the year, you talked about France already on the call?

Yes, yes. So there's a small impact from France but I think on this other one I'd like to turn it to Mike Kaluza, our COO.

Yes, on the -- like you said that France has already been covered. In terms of Ireland there were just some minor shutdowns there. So there's no lingering effect there. In France we had a couple of issues with the -- one of our -- we had a pipeline leak on injector from one of our fields so we had the field down for several weeks. So that's been repaired, that's up and running again. And then the other issue is on one of our gas assets. We had some equipment down there that went down and it took us a little bit to find the parts to get that going again. But that's all been resolved also. So all those shut downs we referred to there, they've all been resolved and no future impacts from that.

Thanks.

This concludes the Q&A period. I'll now turn it back over to Anthony Marino for any closing remarks.

Thank you again for participating in our Q2 2019 conference call. We look forward to speaking with you again after our Q3 2019 results are reported in October.

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