Vermilion Energy Inc. (VET) Q2 2017 Earnings Report, Transcript and Summary

Good morning. My name is Stephanie and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Second Quarter 2017 Earnings Release 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] Thank you. Anthony Marino, President and CEO, you may begin your conference.

Good morning, ladies and gentlemen. Thank you for joining us. I am Tony Marino, President and CEO of Vermilion Energy. With me today are Mike Kaluza, Executive Vice President and COO; Curtis Hicks, Executive Vice President and CFO; and Kyle Preston, our Director of Investor Relations. I would like to refer to the advisory regarding forward-looking statements contained in today’s news release. These advisories describe the forward-looking information, non-GAAP measures, and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion. During this call, I will provide you with an overview of our second quarter 2017 financial and operating results. Vermilion’s second quarter results were in line with our expectations. Following an active Q1 drilling campaign in Canada, the U.S. and France, we achieved higher quarterly production volumes in each of these countries. This contributed to quarter-over-quarter production growth for the company of 4% to 67,240 BOE/D. FFO for the quarter was $147.1 million or $1.22 per share, representing an increase of 3% over the prior quarter despite lower commodity prices. After accounting for development CapEx of $59 million and cash dividends of $49 million, we generated approximately $40 million of excess cash flow during the quarter. This resulted in a net payout of 75% and allowed us to reduce net debt by 5% to $1.3 billion implying a debt to annualized FFO ratio of 2.2 times. The most notable growth during the quarter came from our Canadian business unit, where production increased 14% quarter-over-quarter to 20,563 BOE/D. This growth continued beyond the second quarter with Canadian production reaching 30,000 BOE/D in early July, an all-time record for the business unit. The growth in Canada was in large part due to the ongoing success of our Mannville condensate play in West Central Alberta, where we have brought 15 gross or 10.3 net Mannville wells on production so far this year and have achieved an average IP60 rate of 470 BOE/D. Production from the Mannville averaged 14,700 BOE/D during Q2, an increase of 23% from Q1. Results from our Cardium and Midale light oil plays were in line with expectations, while we continue to see a significant improvement in cost efficiencies. In the Cardium, drill, complete, equip and tie-in or de-set well costs averaged $2.3 million on a per section basis for the 2017 program compared to $3.2 million during our last Cardium program in 2014. In the Midale, per well cost decreased to $1.7 million for the 2017 program compared to $3 million in 2014. In the U.S., the 3 Turner Sand wells we drilled in Q1 were put on production during Q2. After a period of intermittent production testing, the three wells are now producing at a combined rate of 760 BOE/D in the third month of production. Two of the wells are performing above our type curve for the southern part of the play at current rates of approximately 330 BOE/D and 325 BOE/D respectively, but production is still gradually increasing. The third well reached a peak IP30 of 140 BOE/D and is currently producing approximately 110 BOE/D. Similar to our Canadian plays, we continue to see costs come down in our Turner Sand development. Average de-set well cost decreased to $3.5 million for the 2017 program compared to $4.2 million in 2016. The 17% reduction in well costs was achieved even though average lateral length increased by 15% to 5,300 feet as compared to 4,600 feet previously. Our continued well cost reduction and improvements in mechanical success in the 17 drilling program set the stage for increased development in our Turner Sand play. Moving to Europe, in France, production increased 5% quarter-over-quarter to 11,368 BOE/D. We drilled and completed our first wells in the Neocomian fields in the first half of the year and have now placed all 4 wells on production. The combined IP30 oil rate from the four horizontal Neocomian wells was 600 barrels a day, which exceeded our expectations. As you may recall, we acquired the Neocomian fields through the acquisition of ZaZa Energy in 2012. And prior to the first half drilling program had increased production in reserves by roughly 50% solely through work-overs and artificial lift optimization, the 100% success rate and better than expected production results on this inaugural drilling program validate the long-term development potential of the Neocomian fields. We plan to drill more Neocomian wells in 2018. I’d like to make a brief comment on recent political developments in France that affect our industry. As many of you are aware, the newly elected French government recently reaffirmed its intention to not grant new exploration permits. This policy pronouncement on expiration permits is consistent with President [indiscernible] previously announced campaign platform and is not a surprise to us. We do not expect this new legislation if passed to have a material impact on Vermilion because our French operations are focused on development activities such as well work-overs, infill drilling and waterflood optimization, with only a small allocation of capital to exploration activities. France has been an important part of our history, being the first international investment in our very successful international growth and income model. This summer, we celebrated our 20th anniversary in France and we are proud of the environmentally and socially responsible business that we have developed there, including the carbon reduction projects in our operations. We see our French business having another 20 to 25 years of life using the same style of sustainable development, which is in line with the new French government’s objectives for our carbon neutral economy. Last quarter, we announced a reallocation of capital and deferral of production in the Netherlands due to some permitting delays on a few wells. We are pleased that in the second quarter we received the required permits to execute our drilling and seismic programs for 2017. In addition, last week, we received ministry authorization to increase production on one of our key wells pending a public comment period. With the receipt of these permits, we expect to resume production growth from our Netherlands business unit in the second half of 2017 and to continue this growth in 2018, while we continue to advance various permits to support our longer term growth plans. Permitting in the Netherlands has always been a time-consuming and challenging process. During our Investor Day in April, we outlined the new permitting process that came into effect in the Netherlands in January 2017. The new process will allow the drilling facility and production permitting aspects of our projects to run largely in parallel with the objective of enhancing the transparency of the entire project to the public. Although this may increase the timelines for certain component approvals with the various elements running in parallel, we expect the new permitting framework will reduce overall cycle times and ultimately improve the process for both communities and operators. We have a strong track record of profitable growth in the Netherlands delivering 7 years of consecutive growth at a 13% CAGR prior to 2017. While we were disappointed to break this string of production increases in ‘17 due to the permitting delays, we remain committed to the Netherlands and are confident in the longer term growth opportunities there. In Ireland, we had another strong quarter achieving average production of 10,634 BOE/D in Q2 and 10,718 BOE/D for the first half of 2017, representing approximately 98% of rated plant capacity. The project continues to outperform expectations for well deliverability and downtime. Two weeks ago, we announced a strategic partnership in Corrib, with the Canada Pension Plan Investment Board, whereby CPPIB will acquire Shell’s 45% interest in the project. At closing which we expect to occur in the first half of 2018, we expect to assume operatorship with CPPIB planning to transfer the operating entity along with 1.5% working interest of $1 million or €19.4 million before closing adjustments or $28.4 million at current exchange rates before increasing our working interest in Corrib to 20%. As outlined in our press release, this incremental interest equates to approximately 850 BOE/D production at current rates and approximately 2 million BOE of 2P reserves at year end ‘16. Assuming a purchase price of $28.4 million before closing adjustments, the transaction metrics are estimated at approximately $33,400 per BOE/D, $15.40 per BOE of 2P reserves including future development capital and 3.3x 2017 operating cash flow using the forward commodity strip. We expect the acquisition to be accretive for all pertinent per share metrics including production, fund flows from operations, reserves and net asset value. Corrib is an important free cash flow positive element in our portfolio and obtaining operatorship has been one of our strategic objectives. We are very pleased that we can achieve this objective as part of a very capital efficient and accretive acquisition. Following the assumption of operatorship at Corrib, we will operate approximately 87% of our production base as compared to 72% currently. Finally, with respect to the Corrib transaction, we are very honored to have CPPIB as a partner. CPPIB is a world class investment firm with an exceptional understanding of energy projects and a very exacting approach to investing in them. We believe Vermilion shares strengths and energy investing and we look forward to a long-term and productive relationship with CPPIB. Elsewhere in Europe, we have assimilated the German producing assets we bought from NG following closing at the end of 2017. Our workover and artificial lift optimization activities have already generated approximately a 10% increase in production on these former NG assets as compared to Q1 levels. In Central Europe and Eastern Europe, we continue to analyze well and seismic data and are preparing to drill our first well in the region in Hungary in the first half of 2018. In Australia we continue our debottlenecking project to increase throughput on Wandoo platform B with a modest increase in production volumes expected later in 2017. Lastly, we announced a $20 million increase to our 2017 capital budget to reflect the acceleration of Canadian drilling and completion activity in the fourth quarter of 2017 that was originally planned for 2018. This allows us to lock in current services costs and to avoid the pre-breakup service constraints we experienced in the first quarter of the year. Our 2017 capital budget is now $315 million, up from $295 million previously to reflect this accelerated activity. The incremental activity will include the drilling of additional Cardium and Mannville wells, completion and well tie in activities and some predrill expenditures for wells to be drilled in 2018. Because the increased capital investment will occur in late in ‘17, our production guidance this year is unaffected at 69,000 BOE/D to 70,000 BOE/D. We are currently reviewing our 2018 plans and will provide a formal ‘18 budget at the time of our Q3 ‘17 results. However, we can save now that the additional capital investment in 2017 will positively impact 2018 either by reducing capital investment or increasing production rates as compared to our previously announced targets. That concludes my planned remarks. We would be happy to address any questions that you might have. Operator, would you please open the phone line to questions.

[Operator Instructions] Your first question comes from Greg Pardy with RBC Capital Markets. Please go ahead.

Thanks. Good morning. Tony couple of questions for you and maybe the first one is you mentioned [indiscernible] was just under 15,000 BOE a day, how would that map to condensate maybe just as a percent of your Canadian liquids production at this juncture and how might that change in 2018 with the activity?

Okay. Let me refer that question to Mike Kaluza, our COO.

Hello Greg. Yes for just overall for Canada what we are looking at is about 22% crude and about 10% conde and we have about 13% NGLs and the rest being gas. But we are looking at an ‘18 it’s probably pretty similar breakdown to what we saw in ‘17. Obviously, we want to increase that overall conde weighting closer to 50% as we continue to develop the our light oil and in the conde rich play.

Okay, great. And then just the other one is, Tony maybe just in terms of what spending and production might look like in the third and fourth quarter I mean you have kind of lot of activity in the first half of the year, so presumably the second half is pretty strong?

Yes. With respect to your production question, so we built about 3,000 BOE/D from Q1 to Q2. And we would have we think roughly that quarterly build rate for the rest of the year to put us within the 69,000 BOE/D to 70,000 BOE/D range. Now, each year our quarterly profile varies. This year it happens to be one that builds every quarter. We didn’t have to make some adjustments in this year’s operating plan to adjust for the unexpected permitting delays we got in the Netherlands. But because of the flexibility we have in the company we are able to adjust capital, we were able to bring forward some additional production. In a number of business units we are particularly doing that in North America, although there are other contributors to the growth. And that’s why we are able to still stay within the range despite taking this hit which in – from the Netherlands which we do expect to recover next year. So that is the – that’s the production profile. With respect to capital spending we got our $350 million annual target that – a budget now that we intend to hit. That would call for something I think on the order of about $80 million in CapEx per quarter into the last two quarters of the year.

Okay, great. And just to make sure I have got it and so the third quarter versus second up around 3,000 BOE a day, I think you said and then to hit your numbers you would probably be up another 5,000 or 6,000 in the fourth quarter, is that about right or I or did you say sort of 3,000 sequentially in each?

We built roughly 3,000 a quarter, just like we did from Q1 to Q2, it could be up a little bit more than that in Q4, but I don’t think we would be up 5,000 or 6,000 barrels a day from Q3 to Q4. I think that would be a little bit too rapid of the build for the end of the year.

Okay, great. Thanks very much.

Your next question comes from Menno Hulshof with TD Securities. Please go ahead.

Thanks and good morning. I will just start with a question on Corrib, could you just walk us through what needs to be done between now and closing which I believe the first half of 2018 to assume operatorship of the platform from a regulatory and staffing perspective?

Yes. I will touch on a briefly and then if I would leave something out I would ask Mike Kaluza to add to it. So we need to get our Vermilion operated safety case approved by the government, we need certain regulatory approvals within Ireland and we will be working with Shell to affect the transfer of the employees to Vermilion such that I think that our most reasonable target for taking over as operator is the middle of 2018. Mike do you have anything to add to that list?

That’s it I think from the regulatory standpoint and the safety case is obviously one of the critical path items. Along those lines now we are jut working through the full integration of their – of Shell’s operating services, so there is multiple work teams set up with the lead on each one of those probably six to eight of those going through the different components all the way from IT to human resources to production operations. So there is teams set up both on Shell side and our side to work through all those specific issues. So when we do take over operatorship, we have everything has been tested and we get the ground running. So that’s all part of the process in addition to [indiscernible] stock.

Okay. And just if I take a step back and I look at your position at Corrib now you’ve got 20%, you are the operator, you only took your working interest by 1.5% in conjunction with the transaction, so did you have the option of taking it higher and if so what was your thought process on that?

That increase of 1.5% in our working interest to ‘20 is something that we arrived at pretty early in our partnership discussions with CPPIBs, so it’s ever since we started with them is what we plan to have as our stepped-up ownership. It’s a very, very good asset and we are really happy with the transaction. We think our metrics on are really good and it’s a type of investment we would like to make. Corrib does represent 15% of the company’s production base, it’s high netback doesn’t have very much in the way of maintenance capital requirements, so it’s a significant contributor to FFO. And we just want to be mindful of a single field concentration and that is really why we limited our increase at this point to 1.5%.

Okay. Thanks Tony. And then I have got one more just on the Netherlands, it looks like you made quite a bit of headway in terms of getting some of those permits across the line, so maybe you can just talk us through which permits are still outstanding and how that generally meshes into your planned activity levels into 2018 and beyond?

Okay. Yes, we nailed down the remaining permitting items that we have to execute the drilling and seismic were 17. We got an MEA approval to ramp up production on one of the wells that has to go through a six week public comment period before we can actually effect the production increase, the ongoing permitting activities are going to be more or less continuous ones to set up the capital program for the next few years. We got certain winnings plan applications that are still in effect to continue the ramp up of certain existing fields. So from here the way I see it’s just going to be our continuous permitting activity that we have under the new regulatory framework that the Netherlands has put in place at the beginning of this year.

Okay. Thanks Tony. That’s it for me.

Thank you, Menno.

Your next question comes from David Popowich with CIBC. Please go ahead.

Yes. Thanks for taking my question guys. I just want to ask about some of the economic runs you guys have in your presentation, it looks like there has been a few changes to some of the plays, I was mainly interested in the Lower Mannville developments, it looks like you are taking your IP 365 and your assumptions down for the Ellerslie, so you guys were saying the well results were really good and you are actually deploying more capital to that play in the second half of the year, so I was just wondering if you could kind of square that circle for me I guess?

Yes. I will begin to speak to this. I don’t think that we made very significant changes to the type curve, we are really just taking the entire well set from the beginning and trying to show the average results. The – you know that we made changes to the liquid yields. I think some of those went up, some of the BOE/D rates went down in this update to the IR deck, reflects probably a year of additional activity that we are including in there. So there were something to one up, something that went down. I don’t know if we actually modified the costs in that economic run, but they continue to drop a little bit. We saw another 3% drop from $3.5 million de-set cost to $3.4 million de-set cost in this particular set of runs. And I believe the new IRR that we show using $50 WTI is 87%. So it’s a really higher rate of return is one of the very best ones in the portfolio, one of the best projects I think you could find anywhere in North American, in fact in number of – that there a lot of independent research supports that. We are one of only a couple of key players in this Ellerslie development fare away. So it’s a very strong project. We make minor adjustments up and down to the elements of that type curve. We just try to keep it as accurate as possible. I would say these ones are overall minor. Actually I think about 7 wells of the 12 wells that we have brought on recently are actually better than that type curve and this year’s drilling program looks like it’s going to be a little bit better. So I see the play is continuing to improve as we understand it better geologically and we do grind out a little bit of cost reduction all the time. So those would be – it’s a good question that you ask and those would be my comments about a strong play. We will always update the type curves.

Perfect. Thanks Tony.

Your next question comes from Patrick O'Rourke with AltaCorp Capital. Please go ahead.

Thank you. Good morning guys. Just a couple of questions real quick on the U.S. development here, you had the three wells, two of them were quite strong, one looks a little bit weaker, I am just wondering the difference between the two strong ones and the third well, is this geological, was this operational, how do you sort of explain that right now. And then when you look at the inventory a lot of its still in the contingent basket here, do these wells allow you to shift more of that to the 2P and bringing into the formal reserve report this year?

Yes. Okay. So Patrick, the last part of it, I would think so. I think that the drilling that we have done will allow some additional reserve bookings, in the end, it’s up to DOJ, but I think under NI 51 101 we would probably qualify for a shift from contingent to reserves for some of the locations and perhaps there are more contingent locations to replace those as a result of the activity. Two of the three wells were quite good, probably perhaps the best wells we drilled there are over 300 BOE/D of Ps, it’s highly oily, they continue to ramp up. One of the three wells is not that good of a well around 100 BOE/D and it was drilled to the north of the other two wells. It was kind of two parts to the play for us a Northern area and a Southern area. And from our results so far, we think the Southern area is quite a bit stronger, it isn’t to say that the Northern area isn’t going to be economic. Actually I think it would continue to make progress on the learning curve both with respect to costs and probably productivities. Now specifically that well that we drilled in the north this time were north of the stronger wells to the south was a unit commitment well. We formed a Federal exploratory unit there, it’s called Three Horn unit. To meet the commitments we are getting all those lands held by unit we have to drill our first well and get what’s called the paying well determination on it from the BLM and that is what this Northern well was. So it was drilled in a place where we didn’t have a great deal of well control, because the rules require these to be a certain distance away from existing production. And as a result of that we spent quite a bit of time on that lateral out of the zone I don’t know I think it was on the order of 60% in zone. So typically, we do quite a bit better than that and that’s probably one reason it wasn’t quite as productive. Furthermore, it moved into the Northern – further into the north part of the acreage than the other two wells. And we know that area we kind of have a reduction in our productivity as we go in that direction, but it was necessary to get all the lands [indiscernible] and that’s why we drilled it with less well control and a little bit more out of zone than we would achieved in the south.

Okay. And then if this play begins to see increasing capital I know that’s a couple of other operators to the west of you I believe are starting to increase their capital, are there any sort of takeaway constraints that you can foresee here, can you start to ramp up development if you like what you see?

Yes, there are not really takeaway constraints. I think really – probably compared to what the powder has done historically, Powder River Basin has done historically this current wave of development, I don’t think is going to fill up the historic infrastructure that is out there. Locally, we have to always make sure that we got enough gas processing capacity and that sort of thing for the relatively low GORs that we produced, but really on a broader sense, I don’t think that at least our part of the Powder River Basin would be constrained. I do want to point out there is a number of good plays in the Powder River. Ours is a little bit different than those ones that the operators have maybe 40 kilometers or 50 kilometers to the west of us. They are really in the deeper part of the basin has got some advantages and some disadvantages, because it’s deeper and more highly pressured. It’s certainly more expensive. Some of it’s there is black oil. Some of it is retrograde condensate. We prefer the black oil play that we have in the Eastern side of the basin. We are very shallow with this compared to a typical horizontal multi-stage frac development, where only about 4,500 feet sometimes less, true vertical depth. And we like having lower costs. We like that in this geologic setting, which is really a halo play of the same age as our Cardium, it’s what originally attracted us to it. We get in this type of setting we get black oil production, which we prefer for the long-term productivity of the wells and the lower costs. We have not really pushed it very far yet with respect to well lengths. That’s something we are going to do gradually as we debug the drilling and completion. And I think that’s yet another way in addition to just the continuous improvements we will make in the fracs by trial and error. That’s another way to drive productivity for the well. So, we are pretty optimistic for the long-term. But given a real mild land expiry profile, which is held by the formation of this unit, we haven’t had to push it very fast in the development of our Turner Sand play.

Okay, thanks a lot.

Thanks, Patrick.

Your next question comes from Dennis Fong with Canaccord Genuity. Please go ahead.

Perfect. Thank you. Good morning, guys. Just too quickly follow-up on a little bit of those U.S. questions, just in terms of maybe on a capital allocation basis and kind of relative return for the Turner Sand, how do you guys think about that kind of going into ‘18 and even beyond with respect to allocating capital to that US play?

Yes, Dennis, that’s a good question too. The play currently with the results we have right now sits kind of in the middle of our capital slate, pretty high half cycle returns. I think at $50 oil, these are 50%, 60% IRRs and those are good returns, but they are not the top ones in our portfolio like as we got – as we talked about earlier of one of the questions on the Mannville and even actually compared to some of the European development. So, it’s not really at the top today. We have done a couple of wells a year for the last two or three years to continue to try to debug the drilling and completion. I think we have achieved that. We used to have a fair number of mechanical problems in drilling and cracking these wells and we seem to have gotten past that in the ‘17 program. That’s one reason that we wanted to continue to drill. So, we could be setup for bigger development. And I think as we go forward we are going to continue this continuous learning curve on costs. We are going to get more data points about where we have the greatest productivity in that quite large land base that we have about 130 or 135 net sections, almost all at 100%, almost all contiguous. And this will contribute I think along with frac improvements, well length increases to learning curve and productivity as well as on cost. So, I think we will be able to begin to allocate more capital to the play as we go forward and it’s rates of return, I do expect to move up narrowing that gap versus the highest rate of return projects in the portfolio.

Okay, perfect. And then I just have one more question on accelerating the CapEx from 2018 – some of the CapEx in 2018 into Q4 this year. Are you guys just trying to be a little bit more proactive in potentially anticipating some issues around breakup next spring and does it have any like even remote issue or kind of relation to the acceleration of some capital as you have shifted money from the Netherlands into Canada this year?

Yes, Dennis, it is really more the former reason rather than the latter. It doesn’t have really anything to do with the delays in the Netherlands. We had already made that adjustment. But the first thing that you mentioned is the case the question of services in the kind of the first quarter of the year and some of the problems that we run into around breakup. In the Q1 ‘17 program in Canada, we felt we had locked down all of our services at pretty good prices. But what we found as we got into the second half of the first quarter is that certain key elements or an element of the completions namely the pressure pumping that we felt we have locked down became unavailable, because the vendor was stuck on some well pads that where they had to complete their activities and therefore they couldn’t get to our wells before breakup. So, we were faced with accepting some combination of a few things that we haven’t counted on and we didn’t really prefer, one is to pay higher costs and we did that in some cases. I think actually some of the pressure pumping tickets where maybe 10% or 20% above what we thought we would have had as a result of the changes on a few of these wells, because of the vendor being unable to get there. In a couple of cases, we had to do some matting, roadwork and matting to allow completion into breakup and in other cases, we just had to put off the completions until after breakup, because we just couldn’t get in there. And we just don’t like that jam up of activity that we get at the end of Q1. At certain times a service industry especially in these role sensitive elements like pressure pumping becomes quite constrained. The way around that is to more a level loader activity. So, we are shifting some of this Mannville and Cardium that we had intended for Q1 ‘18 back into ‘17 where we are confident that services will be available and we think we will get – I’m pretty confident we will get lower prices on it as well, because it level loads service company activity too. So that is really the reason for that change. Now, with respect to the company overall for CapEx and production, we put out targets earlier for 2018 and we will make some type of adjustment to those targets. Either we will provide for more production in 2018 or we will provide for less CapEx or something in between and we haven’t made that decision which way to go. We’ll look at conditions as we get close to the release of a formal budget and guidance at the time we released Q3.

Okay, alright. Perfect. So, you are just being frankly proactive in terms of ensuring that you can secure activity and services during what I guess you would believe is the most integral part of ensuring that you can hit potentially those early production guidance numbers?

Absolutely, Dennis. You said it better than I there. That’s exactly what we are seeking to do.

Perfect. Alright, thank you.

[Operator Instructions] Your next question comes from Travis Wood with National Bank Financial. Please go ahead.

Good morning. Just a quick follow-up on the last question. Can you give us a magnitude on how much savings in terms of percentage that you think you could save in Q4 versus the last pressure pumping through that you had running?

I think roughly, Travis, roughly if in the end we do 10% or 20% better on a subset of the total well cost that might lead us to 5% or 10% savings on the program as a whole, but it really does more than that. It kind of prevents some end of season cost train wrecks. If we actually have to end up completing into breakup and it also gives us much more certain delivery on the production dates and therefore the production stream for the year if we do this. So, it’s got some cost advantages and it’s just got some risk advantages to us. It’s a more sensible operating program to level it out rather than because the calendar flips at December 31 jamming all this activity into Q1. It’s more of a continuous budgeting process and maybe that’s what some of this 2-year budgeting that we have been doing gives us better insight into how to do that.

Okay. And then taking it to the corporate level, we have you driving some free cash through this year and into next year, can you help us understand or remind us of the priorities that you will use that free cash for whether it’s balance sheet or what you are seeing on the M&A front?

Yes. I mean, the priorities for the company have really not changed over the past 3 years I’d say ever since we entered the downturn. It becomes first of all to make sure that our balance sheet is very strong. And at the end of this, I think I will turn this to Curtis just for a brief discussion of where we stand there, but that’s a top priority and we made good progress on that alone in this quarter I think with some impressive free cash generation and debt reduction. Beyond that over the longer term, I don’t think at all in this price environment even if we could afford it. In this price environment, we still would not increase the dividend. We would like to see higher prices before we do that. We don’t want to specify the absolute level at which we want to get to before we do that. But I think it remains the company’s long-term model to have dividend growth. And then thirdly to further augment growth rates, now, we have got pretty strong growth rates as it stands in terms of production per share organically 5% to 7% per year. As you pointed out in your question, we have tended to augment that with accretive M&A and then we will continue to seek to do that. I mean, core would be a very small example of doing that and achieving some other strategic objectives at the same time. But in any transaction we look at, we would seek to further bolster that free cash flow that we generate. So, it’s a very disciplined and exacting way of evaluating that only means certain assets could meet the requirements of the model. And if we do any M&A, that’s what we are going to insist on. With that, I might just turn it to Curtis for a discussion of the balance sheet to get to the first part of your question.

Sure. As Tony alluded to in his opening remarks, our annualized debt to FFO was running at about 2.2. Today, that’s down from about 2.8 a year ago. So, we have got a naturally de-levered the balance sheet through a combination of free cash flow applied to debt combined with higher commodity prices, which obviously serves to generate more free cash flow. As we have stated over the years, our internal target in a normalized commodity price environment is leverage of 1.5x or less. We think we can get there again by continuing the process that we are in by naturally de-levering over time. We are not uncomfortable with no absolute debt levels at $1.3 billion relative to the asset base particularly given the growth prospects that we have got over the next few years. So there is no sense in us responding or reacting to a situation to try and force the balance sheet lower at this stage. We will keep an eye on it. We will certainly continue to run the business model on a fully sustainable basis and we think we can achieve our internal targets here naturally over time.

Okay, thank you. And then is there any change to where you guys see the most opportunity on the business development front regionally? And then if we are speaking Europe, could you try to get more specific around country-based opportunities?

I mean, all three regions within the portfolio I think are valid for M&A. It’s certainly true in Europe, where we have some big competitive advantages and we have tended to make higher rate of return deals. Taking advantage of this franchise we have and this reputation we have with good governments and sellers to be a responsible operator. I think you can see that Corrib is an example of that. In North America, we are able to bolt on to the existing plays, primarily what we have with the Cardium, Mannville in West Central Alberta and I think that will continue at a very small scale, primarily adding undeveloped land or maybe very small amounts of production might be associated with it, but typically undeveloped for purposes of horizontal multistage frac development. We would have bolt-on deals, I think continuing in West Central Alberta. Probably between Canada and the United States for new areas, Canada offers better opportunity. The market in general might be getting a little bit more reasonable in North America as you have continued to have these price disappointments – commodity price disappointments and some of them mania for extremely high rates of growth has maybe subsided. Nonetheless, it hasn’t been the place where we have been able to make large high rate of return acquisitions. And I don’t expect that to be radically different now even though again there maybe a little bit of improvement. Australia remains a valid region for us. I think it maybe over the long-term has M&A potential. The fact is since getting into Wandoo in the ‘04 through ‘06 period. We got an asset there that fits very well within portfolio free cash flow. We are able to have stable production. We are able to find new projects all the time in addition to those that we had previously had in the portfolio to continue its long life role as a generator of free cash and stable production. Since entering Wandoo at that time, we haven’t found a similar asset yet in Australia, but we would be – we continue to be open to be evaluating the possibilities there. So, I think all three regions are valid for M&A model and it’s – in answer the specifics to your question, we can’t identify any particular asset right now. We can’t say what the timing would be. It’s opportunistic. It’s always based on strong rate of return contribution of the free cash flow model, per share accretion across the board over the long-term. I think those types of deals will occur, but we can’t at all say what time – what the timing of it might be.

Okay, thank you. And just very quickly taking it back to the balance sheet you maybe one of or maybe the only one left with a drip now that you have eliminated the premium drip you have with the free cash, have you guys had the conversation to completely eliminate the drip. I understand that you have tightened the discount, but is that something that we could see heading into 2018.

Yes. So on the history of it, we have the fee drip in place as a temporary – very low cost of issuance program, ratable program from I think early ‘15 until it was tapered off completely here in Q2. So, the fee drip is gone. We still have the traditional drip that we have had around ever since Vermilion began making distributions in 2003 back in the energy trust area and that’s we continue to have that drip as a service for the shareholders through the new corporate area when we have been paying a monthly dividend. We have twice narrowed the discount on that drip. It used to have traditional trust here of 5%. I think maybe 4 years ago, we narrowed that to 3% and then we took it down to 2% last year. There is a possibility of continuing to narrow that discount. I don’t think that we want to eliminate the drip completely. We feel like it’s a service that a minority of our – a significant minority of our shareholders want to have in place. So that makes it easy for them to reinvest. If they don’t want their cash and they do believe in the future performance of the company it’s the most inexpensive way that they can plow that income component back into for $1 million. And I don’t think we want to change that from the business entities perspective it is by far the lowest cost of financing that you can come up with, with only a 2% fee essentially to the company and no combined fee and discount 2% total cost to issue equity which is far less than any other type of the equity issuances that you could find. Now, we continue to grow significantly on a per share basis. In fact if you look in our IR materials there are some independent research showing that we are in the top quartile of per share growth even as we have this income component and that fully accounts for any issuance under the drip. So to us, that’s a key measure, are we growing on a per share basis that’s even before you account for any potential M&A that might be accretive to production per share or cash flow or free cash flow per share. And as long as we are doing that, we don’t think it’s inappropriate to continue to offer this service to the shareholders to allow them to reinvest especially given the very, very low cost of issuance that it has for the business entity.

Okay, great. Thanks. Thanks for the time.

Thank you, Travis.

There are no further questions at this time.

Thank you again for participating in our conference call. We look forward to speaking with you again after our Q3 release.