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Executives

Lorenzo Donadeo – President and CEO

Curtis Hicks – EVP and CFO

Analysts

Greg Pardy – RBC Capital Markets

Dirk Lever – AltaCorp Capital

Patrick Bryden – Scotia Bank

Gordon Tait – BMO Capital Markets

Travis Wood – TD Securities

Jason Frew – Credit Suisse

Cristina Lopez – Macquarie

Vermilion Energy Inc. (VET) Q2 2013 Earnings Call August 1, 2013 11:00 AM ET

Operator

Good morning. My name is Jonathan and I will be your conference operator today. At this time I would like to welcome everyone to Vermilion’s Second Quarter Earnings Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. (Operator Instructions) Thank you.

Mr. Donadeo, you may begin your conference.

Lorenzo Donadeo

Thank you, Jonathan. Good morning ladies and gentlemen and thank you for joining us today to discuss our second quarter 2013 financial and operating results. I’m Lorenzo Donadeo, President and CEO of Vermilion. Joining me today are Curtis Hicks, Executive Vice President and CFO, Tony Marino, Executive Vice President and Chief Operating Officer and Dean Morrison, our Director of Investor Relations.

Earlier, this morning, we announced record operating results driven by consistent operational execution and strong production and drilling results year-to-date. Thus far in 2013 we’ve achieved growth across all four of our operating areas resulting in record consolidated three and six month production volumes of 42,813 and 20,772 Boes per day respectively. Today in view of our strong operational performance we are further increasing our production guidance for 2013 to between 40,500 and 41,000 Boe per day, up from our previously upwardly two revised guidance of 39,500 to 40,500 Boe per day and original guidance of 39,000 to 40,500 Boe per day.

Our strong quarter-over-quarter production growth of 11% was primarily attributable to production additions from our Cardium and Mannville drilling in Canada and high productivity from our two-well sidetrack program in Australia. In Canada we increased Cardium production by 13% to over 9500 Boe per day during the second quarter. Since entering the play in 2009 we’ve drilled 202 gross wells that’s 141 net in the Cardium. Our well performance continues to outpace out of our peers in the area demonstrating the quality of our land position in the West Pembina region. Our lean results reflect our continued efforts to optimize completion technology and well design. We’ve been able to demonstrate consistent production improvement and a significant reduction in per-section costs by drilling long-reach 1.5-mile horizontal wells.

And as a result we are now planning on drilling a higher percentage of 1.5-mile wells and several 2-mile pilot wells over the remainder of 2013. Optimization of frac design and fluids, implementation of multi-well pads and the drilling of longer horizontal wells have enabled us to reduce well costs from more than $5 million per section at the outset of our development in 2009 to approximately $3 million per section today.

In 2013 our pursuit of ongoing well cost reduction and enhanced environmental stewardship as well as to several alternative processes for the recycling of frac flowback water, a project that remains in the evaluation stage. We’ve also initiated a water injection pilot to test the applicability of water-flooding of the reservoir. On the operations front our per unit cost remain less than $6 per Boe from our operated production resulting in very strong operating FX of more than $65 per Boe during the second quarter.

Continued efficiencies and improvements in cost control will remain a key focus of our Cardium team given that our current drilling rate of 40 to 60 wells per year, we anticipate our Cardium drilling inventory will last at least another five to six years. In addition to the Cardium we’ve initiated the development of our significant inventory of Manville condensate-rich natural gas targets in the Drayton Valley area. During 2013, our plans are to drill a total of six gross or 3.2 net Mannville wells targeting the Ellerslie formation.

At Mid-July we had drilled and completed four Ellerslie wells with three of those wells on production. In the fourth month of production the first well is producing at a rate of approximately 3.5 million cubic feet per day of sales gas with 496 barrels per day of natural gas liquids which is about 79% of that is condensate. In its third month of production, the second well is producing at approximately 4.5 million cubic feet per day of sales gas with 322 barrels per day of natural gas liquids and 70% of that is condensate. The third well was brought on production in early July and during the first two weeks of production averaged approximately 1.3 million cubic feet per day of sales gas with 466 barrels per day of associated natural gas liquids again 77% of those liquids were condensate and as that an average flowing tubing pressure of 1,125 pounds per square inch, so very strong flowing tubing pressure.

So in Australia we completed a two-well sidetrack drilling program in early April that utilize the longest horizontal section of Wandoo to-date have 3,400 meters. The wells were subsequently brought on production at restricted rates and have demonstrated productive capacity in excess of 6,000 barrels per day and 3,000 barrels per day respectively. These wells are being produced intermittently to meet current marketing agreements and provide long-term certainty to our customers. Our current plan is to maintain our long-term Wandoo field production rate within our prior guidance of between 6,000 barrels per day and 8,000 barrels per day. We anticipate maintaining these production levels in Australia for the foreseeable future with drilling programs approximately every two years. During the second quarter we also concluded an initial four-well infill drilling program in the Champotran field in France.

The program was subsequently expanded to five wells in order to drill a two-kilometer step-out well to the south of the existing field. All five of the wells were successful with the four infill wells completed in June and the extension well completed in July. All five wells were on production before the end of July and currently have per-well production rates in excess of 300 barrels per day at low water cuts. In aggregate, current production from the wells is approximately 1,800 barrels per day at a 4% water cut. Additional activities in France included workovers, recompletions and facility upgrades in both the Paris and Aquitaine Basins.

We continue to integrate the assets we acquired in France in 2012 and have identified potential opportunities to increase production through seismic data acquisition, workovers, optimized water-flood management and development drilling. Our French business is now an organic growth asset, featuring low base decline rates, high netbacks from Brent-indexed production, strong cash flow generation and high capital efficiencies on development projects. We are increasing our France-based technical staffing to identify and execute additional investment opportunities in these large, complex, conventional light oil fields in both the Paris and Aquitaine Basins.

In the Netherlands we continued permitting and preparations for a three-well drilling campaign in the second half of this year. Late in the first quarter we completed our Garijp debottlenecking project which has enabled us to throughput incremental production during the second quarter from two wells previously drilled at Vinkega. We also completed and commissioned surface facilities for the multi-zone Langezwaag-1 well it’s got a 42% working interest mid-way through the second quarter. The well is currently producing from the Vlieland zone at an average rate of 3 million cubic feet per day net to Vermilion.

As you move forward we intend to increase activity in the Netherlands each year to maintain a rolling inventory of projects so that each year’s capital program will involve a combination of drilling new wells and the tie-in of previous successes and working towards this objective we have more than doubled our undeveloped acreage position in Netherlands to more than 435,000 net acres over the last year. Like our French business unit we now consider our Netherlands business unit to be an organic growth business and we are increasing our technical staffing in the Netherlands to turn our substantial inventory of prospect leads into drillable projects.

With respect to current well and facility deliverability we are not currently producing at full capacity in our Australia, Netherlands business units. Our conservative approach to utilizing available well deliverability is supported by several considerations. In general we seek to maximize capital efficiency which means that in some cases we do not install facility capacity and well equipment to maximize initial production rates.

In other cases there are technical and commercial drivers such as reservoir management or long-term product marketing considerations that lead us to whole production levels below available deliverability. Our capital markets model is based on low risk ratable organic growth along with income to our shareholders.

We believe that our conservative approach to production management reduces the risk of execution of our growth and income model in the future time periods. On the land front we continue to expand our position in the Duvernay liquids-rich natural gas resource play adding an additional 36.6 net sections in the second quarter and nine net sections in July.

In total we have amassed 318 net sections in the Edson and Drayton Valley areas spanning the breadth of the liquids-rich natural gas fairway at a cost of approximately $76 million or $375 per acre so a very reasonable cost. To-date we drilled three vertical stratigraphic test wells and plan to drill our first horizontal well late this year with anticipated completion to incur in the first half of 2014.

Our Duvernay rates generally underlie our Cardium and Mannville liquids-rich gas positions, allowing for potential infrastructure, operational and time advantages should be elect to pursue for seeing full field development of the play. Combined the Mannville and Duvernay positions provide us with exploration and development opportunities in our core Canadian operating region that have the potential to deliver strong production and reserve growth in the latter half of the decade.

In Ireland tunneling activities related to the completion of the nine kilometer onshore pipeline for Corrib continued during the second quarter. Various other onshore and offshore activities are progressed as well over the first half of 2013 including umbilical lays to the offshore wells, onshore pipelining in segments outside the tunnel and construction of the TBM reception site.

Tunneling, construction, commissioning and start-up activities are anticipated to take approximately 18 months to complete with first gas anticipated between the end of 2014 and early 2015. Peak production from the project is expected to be reached in mid-2015 with production levels of approximately 55 million cubic feet per day that’s 9000 Boe per day net to Vermilion.

On the financial front we continue to benefit from strong pricing driven by our significant exposure to Brent-based crude oil. WTI-based crude oil and the European gas are Brent-based crude production representing 41% of total production averaged $105.25 per barrel in the quarter.

WTI crude representing 25% of our production averaged $94.22 per barrel. Vermilion’s natural gas production in Netherlands representing approximately 50% of production we see an average price of $10.82 per Mcf during the second quarter of 2013 and that’s a premium of $7.29 per Mcf as compared to equal.

As a result of this pricing and our strong production volumes we generated new record quarterly fund flows from operations of $174.6 million that’s a $1.73 per share in the second quarter of 2013. This compares to $163.6 million or $1.65 per share in the first quarter of 2013 and $127.8 million or $1.30 per share in the second quarter of 2012. Combined the strong fund flows from operation for the first and second quarters of 2013 resulted in record six month fund flows from operations of $338 million a year-over-year increase of 21%.

And finally in June our syndicate of lenders agreed to increase our three-year revolving borrowing base from $950 million to $1.2 billion. At the end of the second quarter we had available capacity the borrowing base of $591 million and a net debt to annualized second quarter cash, second quarter fund flows from operations ratio of 1.97 times. And in addition to the revolver we have a $225 million term facility over and above that. As a result we believe that Vermilion remains well positioned to deliver strong operational financial performance over the next several years.

Our objective remains to produce ratable annual growth at the consolidated company level of approximately 5% to 7% because consideration of Corrib’s future impact. With Corribs anticipated contribution to our production and cash flow streams we continue to target overall growth of approximately 30% to 50,000 barrels of oil equivalent per day from 2012 to 2015 and fund flows from operations growth of approximately 40% over the same period.

Near term growth and cash flow are expected to be driven by continued Cardium and Mannville development in Canada. Oil development activities in France and high net back natural gas drilling in the Netherlands. A significant increment of production growth and free cash flow growth is expected from Corrib between the end of 2014 and early 2015 with the full production during 2015.

Our Australian business unit is expect it provides steady production as well as significant free cash flow. Our confidence in the business continues to grow reflected by our increase in the monthly dividend of 5.3%. In January of 2013 from $0.19 to $0.20 per share. With the increasing certainty for Corrib development timing and the anticipated strength of future cash flows from all of our worldwide businesses.

We are committed and I believe we are well position to provide a reliable and growth dividend stream to investors. In advance of our growth we recently elected to list our shares for trading on the New York Stock Exchange under the ticker symbol VET. The shares began trading on March 12, 2013. Over time as we look to expand recognition and awareness of Vermilion on a global basis. We believe the secondary listing will assist in broadening our investor appeal and improving trading liquidity.

Vermilion’s conservative fiscal management and capital discipline leaves us well positioned to execute our growth and income model and provide the growth the investors on a per share basis. The management and directors of Vermilion continue to hold approximately 8% of the outstanding shares and remain committed to delivering superior awards to all stakeholders.

So with that I will conclude my formal remarks and operator please open the floor to question.

Question-Answer Session

Operator

(Operator Instructions). Your first question comes from the line of Greg Pardy with RBC Capital Markets. Your line is open.

Greg Pardy – RBC Capital Markets

Thanks. Good morning. Just a couple of questions. First one just on France I mean those assets I guess that acquisition you did I guess was last year has worked out well for you. Do you see any other opportunities acquisitions wise and then secondly is just more of a knit question; just curious as to whether you can give us some guidance on what you expect overall corporate cash taxes to be for 2013? Thanks very much.

Lorenzo Donadeo

Yeah. On the first question, I mean in terms of acquisitions in France there are some that we have kind of been watching. There is I guess nothing that I guess imminent I guess, if we can put it that way. But I mean there are other opportunities there that we’ll be watching closely and determine whether we could execute it in a range that will create value for the company.

There was a number of other acquisitions that we are looking at both internationally in our area of focus as well as domestically. The domestic acquisitions that we’re looking at are probably more oil related acquisitions and we’re looking at a number of opportunities again focused on opportunities that we think fit in well with our portfolio and fit in well with our business our growth and income model and at a price that’s complete value for the company.

And on the cash tax side, Curtis?

Curtis Hicks

Yeah Greg cash tax is not an absolute number obviously highly dependent on two factors one. The first one is commodity pricing and the second is internal events within various operating companies that impact the tax calculations. But as we sit today assuming sort of current price that going forward we would forecast PRRT, which is the Petroleum Resource Rent Tax in Australia. It’s a total about $50 million to $55 million for the year, which is about double the six months number at $24 million. We would corporate income taxes to come in the $140 million to $150 million range again about double the $72 million that we booked for the first six months. And so, total forecast $205 million but subject obviously to change based on the factors I alluded to earlier.

Greg Pardy – RBC Capital Markets

Okay that’s great Curtis. Maybe just to go back just on the acquisitions and one of the questions about Vermilion that does come up is in terms of the acquisitions that you are doing whether you would ever tackle something of significant scale that would increase the size of the company by 50% or something like that big numbers. Is your general orientation then to be doing rifle shot acquisitions, bolt-ons basically asset deals that are still going to in essence not spoil the growth I think that you have got ahead or are you fairly agnostic as you look at potential transactions?

Lorenzo Donadeo

That’s good question, Greg. I think from our perspective if you look at Vermilion historically, we’ve always done deals probably under $500 million and those were the deals that really we feel really are in our niche space and then created lot of value for us as an organization. I mean, I think, we I don’t think, we’ve ever done a deal over that size. I don’t anticipate us doing anything in excess of that size in the near term. And you never say never, if the right opportunity came along but we’re bit reluctant of doing sort of those transformational deals.

Greg Pardy – RBC Capital Markets

Okay. And then you said, I think you said CAD$100 million to CAD$500 million?

Lorenzo Donadeo

Ye something under $500 million yeah.

Greg Pardy – RBC Capital Markets

Okay, okay. Very good. Thanks a lot guys.

Lorenzo Donadeo

Yeah. Thank you.

Operator

Your next question comes from the line of Dirk Lever with AltaCorp Capital. Your line is open.

Dirk Lever – AltaCorp Capital

Good morning. Congratulations on some great results. I wanted to focus on the Netherlands. Last year you had a couple of very good well as you have done some debottlenecking, you stated that you will not be running production at full capacity in order to maximize your economics long-term and monitoring the wells.

But I’m wondering if you can give us some guidance on what you are looking at longer-term of expansion of capacity if you are saying that you have got an organic growth business in the Netherlands that does underlie that you will be expanding capacity as you go. So, what kind of rates can we look at? Would it be 5% to 7% or is it something a little bit larger than that?

Curtis Hicks

Okay, Dirk. The overall consolidated organic growth target for the company is in that 5% to 7% range that you quoted I think that over time and it will take, it will take a few years to develop this substantial inventory of wells to tie-in each year and to avoid any kind of ups and downs to the production profile as a result of certain big wells declining. But overtime after so doing, I think that the Netherlands has the capability to – had a minimum grow in line with our corporate 5% to 7% organic target and potentially at higher growths rates than that.

We actually see a great deal of potential in the Netherlands land base. We had a very large number of prospect leads even before adding the last three concessions over the past, over about the past year. And even thought not only – not all those leads are going to progress to drillable projects. I think a lot of them will. I expect that we’ll generate a lot of prospects on the new lands and as a result I think it’s a quite a long-term profile of growth and getting back to your question probably one that supports growth rates at or above the consolidated corporate organic target.

Dirk Lever – AltaCorp Capital

Thank you. And then when you are looking at the Netherlands obviously the economics that are there are very strong. When you compare the economics in the Netherlands compared to Canada, what stands out as generating greater returns? Obviously they can grow at the same pace but when you are just looking at it on a project-by-project basis, which stands out higher?

Curtis Hicks

The fact is that there is a set of very high rate of return projects in a number of places in the company. Netherlands offers very, very high rates of return. There is French development, which we have embarked on with the Champotran drilling program probably offers comparable rates of return. The Mannville in Canada with the well results that we have been getting also offers very high rates of return in the actually just in terms of IRR part of the Australian wells and probably the higher we have in the portfolio. In addition to that, we have the ongoing Cardium program that has been very successful and I think actually getting some of the most consistent strong results you would find anywhere in the Cardium play. So, we have a whole set of choices. We’re going to do some of each and any of those top five projects in the company offer – offer very competitive investment results. It’s very difficult to characterize any one of those five as being substantially better than the others.

Dirk Lever – AltaCorp Capital

Thanks very much, Tony.

Operator

Your next question comes from the line of Patrick Bryden with Scotia Bank. Your line is open.

Patrick Bryden – Scotia Bank

Good morning gentlemen. Just firstly on the Duvernay I’m curious if you can provide a little bit of elaboration in terms of the well profile that you would be looking at say if we are looking at questions like length and number of stages and then the well cost that might be anticipated for that? And I guess, in addition to that, I’m just wondering what your view is on the pace at which you would be looking to go there as industry is also de-risking and what you might learn from them?

Curtis Hicks

So, let’s see the, the first question would be well length. And as we move to drill this first well for us in a play. We are looking at drilling just about a mile maybe a short of a mile on the first well. The, we’re still determining the number of stages to pump but spacing of the stages will probably be in the range of 100 meters per stage, which if we, if we drilled up to a mile or close to it preliminarily that would suggest perhaps a 14 stage job. And again, we are still determining that based on the current technical work.

The cost to the well, when we’re doing is evaluation wells like this first one. We’re going to be higher than they would be in a – on a pad drilling development scenario. So, I would say the initial wells, the initial well that we’re going to drill probably would be in the range of $13 million or $14 million. We do think that in a pad drilling development program, we can get that down a lot. I would think probably to less than $10 million a well project proceeds to full development. In answer to the part of the question about the philosophy about to what degree we watch the rest of the industry activity. We began acquiring these leases and all these licenses in 2011 so we have been watching the industry for over two years now by the time we drilled well probably of about 30 months of industry data there is more that comes in all the time, and we think that that’s a sufficient period to get a good idea of how we want to go about drilling in that and completing this first well.

Before we do further wells to evaluate the land block and we’re not driven by any kind of land expiry given that the first license was in 2011 and subsequently we’ve acquired licenses over the next two years so there is no expiry driver. And there is also no requirement for us to bring this project right away in right away to achieve our targeted organic growth rates given the other the large number of other projects we have in the company. So, given the fact that we’re not in a – we’re not under any pressure to evaluate we’ll probably do this first one and perhaps the second one on the, on another part of our very extensive land block to evaluate those results and then determine how we want to go about further development.

Patrick Bryden – Scotia Bank

Okay, great that’s perfect. And then just the second question from me you’ve increased your guidance for the second time this year and I don’t want to ask you to unduly show your hand for the second half, but can you give us a sense, if possible, as to what your expectations for Q3-Q4 production might look like and would your view be to remain kind of tempered here or could there be further outperformance? Thank you

Lorenzo Donadeo

Yeah Pat, so as we sort of run that model and then we got annual guidance at 40,541,000 so if you marry that up with our first half production really that production in the second half will be pretty consistent with first half production at somewhere between the guidance number is 40.541,000 barrels a day and. And we see Q3-Q4 production being pretty consistent.

Patrick Bryden – Scotia Bank

(Inaudible) appreciate it. Thanks very much.

Operator

Your next question comes from the line of Gordon Tait with BMO Capital Markets. Your line is open.

Gordon Tait – BMO Capital Markets

Good morning. Just a couple of questions, back on France, you mentioned that you drilled about 4 to 5 infill wells in Champotran; just wondering what the potential there is? How many more infill wells or how much of the acreage there would be amenable to infill drilling?

Curtis Hicks

Okay, yeah in this initial drilling program that we did in Champotran are actually picking up drilling at previously Vermilion had drilled the field a number of years ago. We drilled four infill wells actually and then we had the extension well at the south a 2 kilometer extension test. In terms of the drilling that’s developed by gas or the potential number of locations that are opened up by having these quite successful pad wells it’s one the order of 20 plus potential locations and those would be directly related to the success of this year’s five well program there are other concepts that we have in this quite large field and that would over a period of time lead to potentially another significant number of locations beyond that approximately 20 that I’m contributing to the results of this year’s drilling program.

Gordon Tait – BMO Capital Markets

And then with France, it seems to me it was an area that generated a lot of cash flow, pretty light reinvestment rate; I think it was 30% or 35% but now it sounds like you’re going to turn into some – you’re looking for some growth prospects there. So can we assume a, a higher level of reinvestment in France and then b, also maybe higher decline levels as you grow up more of the property there?

Curtis Hicks

If you’re defining me reinvestment in terms of a percentage of FFO we would say or our guess would be at this point we haven’t set our 2014 budget, but our guess would be that we’ll see a comparable percentage of reinvestment to of FFO to what we had in the past, that’s said the level of FFO was rising and as a result we would end up with growing capital programs in the country greater level of investment in the country year-after-year actually well still generating higher levels of free cash flow as well.

Gordon Tait – BMO Capital Markets

Okay, so about the same percentages. Then lastly, with the strength in oil prices, are you looking at more hedges for next year?

Curtis Hicks

Gordon, and I think the answer is no, we’re going to stick with our previously stated strategy we’re hedging 50% of our volumes net of royalties we’ll continue with that strategy through the first gas at Korab that which time we’ll reevaluate whether we want to hedge in itself to what extent we want to hedge. So I think you can – you’ll see us consistently hedge at that 50% level.

Gordon Tait – BMO Capital Markets

Okay, thanks.

Operator

Your next question comes from the line of Travis Wood from TD Securities. Your line is open.

Travis Wood – TD Securities

Yeah, good morning guys. Just a question on the Cardium. You’ve mentioned that you’re starting to focus a bit more on the longer reach wells; so have you seen a step function or an impact on the IP rate basis and do you think GLJ will reevaluate the program that you did this year and look at the EOR bookings? Then a second question just in the same area; drilling the Mannville we’ve seen some pretty strong rates coming from the Ellerslie; so are you beginning to think about, just as you did when you started to ramp up the Cardium, some infrastructure expansion from that play and then what type of capacity are you thinking about if you are?

Curtis Hicks

Okay, the first question on the Mannville performance of the longer wells are one and a half versus one mile. The wells do generate a higher IP, we when we do this measurement or this comparison of what the longer wells to the original one mile wells we always make an adjustment or the reservoir quality specifically on what we call fiage or porosity thickness product we compare what a one mile well did or would have done in that area versus our actually one, our actual one and a half mile performance. And the typical ratio that we’ve been getting is about 1.4 times the productivity of the one mile long well taken as adjustment for the porosity height product in each section that we drill.

The EUR performance actually may be slightly better than that because we’re seeing a little bit lower declines on the one and half mile long wells. By the way, on that we are going to begin to drill some two mile long wells in the Cardium later on this year and we believe we can achieve some further capital efficiency improvements by doing that, by moving from one and a half to two mile long wells just as we have in moving from the one to the one and a half mile long wells again keeping in mind that when we made that first move from one to one and a half miles we only generated about a 25% increase in capital cost.

The second part of that Cardium question about the reserve bookings really all we could say there is, since it is an independent assessment by GLJ is that, we’re, we know that that will take into account the higher rate performance and presumably that lower decline performance that we’ve seen in the real early basis of production and will though generate a new EUR out of that, but impossible really for us to say right now what – what their assessment would be.

In the Mannville question, it is quite a large inventory of prospects that we generated we began I think to reflect this in the resource reports that we released earlier this year in which the independent assessment was that there were on the order of 225 net wells in the entire set of Mannville intervals in our land positions from Drayton Valley down to (inaudible). So will be a growing program over time as you mentioned as we conducted over time in the Cardium. And there will be some infrastructure investment I don’t know how much share we would in our 2014 budget but probably a modest level of infrastructure so that we could move some of these gas volumes and higher gas volumes and therefore get the real target that they were – that we’re after there which is the condensate production on those wells. I don’t think it will be an a large amount of money I wouldn’t put it in the material – at the material scale but certainly there will be a modest amount of infrastructure investment over time to the fullest extent possible we’re going to utilize infrastructure that we put in for the Cardium as well. Certain surface pads, that in the cases where these locations overlaying certainly the roads, pipelines, our company-owned gas plants which we’ll use at current capacity and have the potential to expand and our oil batteries may come into play as well. So all those things will serve to mute the amount of infrastructure investment that we have to make to ramp up the Mannville production.

Travis Wood – TD Securities

Thank you very much.

Operator

Your next question comes from the line of Jason Frew with Credit Suisse. Your line is open.

Jason Frew – Credit Suisse

Hi, there. I notice the UK government appears to have shifted towards incentives for building the shale gas industry. I guess first, do you see this development providing an opportunity for Vermilion. And second, could you comment a little more broadly on shale gas industry development in Europe?

Lorenzo Donadeo

Yeah. I think in terms of the UK that’s something that fits into our area of focus. Our European focus, we are doing some work there, we’re not sure whether it fits sort of what we’re looking for but we are going to right now and doing the technical work on that. It seems like we’re having some – they have government support but maybe not so much support from the public. So, I guess there is some challenges there but I think in general I think shale gas in Europe, in France they have a frac ban on right now and we’re working closely with the government there just try and get them more comfortable with shale gas in France. I think that’s probably if you would ask me last year what I thought if I would have said is probably four to five years old that they may look at it and I think that windows maybe getting tighter now it’s maybe I would say two to three years old.

So I think that there is a good chance they’ll allow it. I think they want to do their work in France and they want to do their technical work and make sure that, that could be done safely in an environmentally friendly way. I think they see it as an asset that can create a lot of employment, create a lot of investment foreign direct investment that will be beneficial and a big resource that they have that they want to get value for. So, I’m hopeful that over the next two to three years we’ll see something there. In terms of the rest of the Europe, the boons come off and grows on some of the areas like Poland and some of those areas. There is still other areas that we’re looking at in, in the European area we think still look perspective and we have our international new ventures team that’s focused on that. And we’re trying to capture early stage opportunities where we can get in there low cost and recapture large blocks of land. So we’re progressing that and we’re quite happy with the progress we’re making there but it does take time.

We see sort of that part of our business is being something that we’re really not looking for it to really do anything for us till the end of the decade really. We want to get in there early, low cost progressing at a slower pace and then look for it add – we’re success in that production at the end of the decade.

Jason Frew – Credit Suisse

Okay. Thanks for those color.

Lorenzo Donadeo

Yeah. Thank you.

Operator

(Operator Instructions). Your next question comes from the line of Cristina Lopez with Macquarie. Your line is open.

Cristina Lopez – Macquarie

Hi, gentlemen. Congratulations on the quarter. Just a quick question. Most of mine have been answered and I apologize if this one was already asked. With respect to the infill drilling program in France, can you address per well drilling costs in the area?

Curtis Hicks

Yes. Those infill wells cost about €3.5 million a well. So, we would be looking at around $4.5 million per well.

Cristina Lopez – Macquarie

And then what’s the timeframe for permitting the wells?

Curtis Hicks

It varies, we do a very complete stakeholder consultation. France has a very strict and I think effective and efficient regulatory system that we work in. And it’s difficult to characterize the exact permitting time because it varies with the target if we’re drilling off an existing pad and we do try to build our pads with some capability to expand. But typically I think to use a rough number we would say that we can usually get authorization to drill within a year of initiating a project.

Cristina Lopez – Macquarie

And then, in the Netherlands now with the debottlenecking complete, do you have – and obviously understanding that you’ve been restricting production there. Do you have sufficient capacity now for the 3-well program that’s expected to be drilled and what potential rates might be coming from those wells?

Curtis Hicks

With the expansion of the Garijp gas gathering system and some of the related compression, we do have capability for all of our wells that we intend to drill later this year. And we haven’t disclosed projections of productivity on those wells, typically the Netherlands wells are quite prolific given that these are conventional really high permeability sandstones that we’re targeting.

Cristina Lopez – Macquarie

And last question with respect to Australia. Given the rates that you’ve been able to produce test these latest two sidetrack wells, is that now a possibility that you can even push the drilling program further than the two-year window that you’ve been using or will you just keep up with that two-year window?

Curtis Hicks

Those are very prolific wells a lot better than probably we expected certainly the best wells that we drilled in our drilling campaigns to-date. The – to some degree doing to 2015 which is about a – 2015 probably for a base plan is a bit of a lengthening from the schedule that we had previously talked about of drilling about every one and a half years. So, for a rough longer range plan I still think it’s reasonable that we would want to drill in 2015.

Cristina Lopez – Macquarie

Perfect. That’s all I have. Thank you so much.

Operator

(Operator Instructions). There are no further questions at this time. Mr. Donadeo, I’ll turn the call back over to you.

Lorenzo Donadeo

Thank you, operator. And thank you everyone for participating in our conference call this morning.

Operator

Well, ladies and gentlemen, this concludes today’s conference call. You may now disconnect.

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