Vermilion Energy Inc.
Q3 2014 Earnings Call Transcript

Published: 10 Nov 2014

[Operator:]

Good morning. My name is Courtney, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy, Inc. Third Quarter 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. Lorenzo Donadeo, Vermilion CEO, you may begin your conference.

[Lorenzo Donadeo:]

Thank you, operator. And good morning, ladies and gentlemen, and thank you for joining us today to discuss our third quarter 2014 financial and operating results. I’m Lorenzo Donadeo, Chief Executive Officer of Vermilion. And on the call today are Tony Marino, President and Chief Operating Officer; Curtis Hicks, Executive Vice President and Chief Financial Officer; and Dean Morrison, our Director of Investor Relations. Earlier this morning, we announced our financial and operating results for the third quarter of 2014. These results continue to highlight the stable and profitable nature of our operations, which have grown significantly year-over-year through consistent operational execution and value-added acquisitions. During the quarter, we generated fund flows from operations of $197.9 million or $1.85 per basic share and this compares to $216.1 million or $2.05 per basic share in the prior quarter and $165.6 million or $1.63 per basic share in the third quarter of 2013. The quarter-over-quarter decrease was primarily attributable to lower commodity pricing combined with the build in crude oil inventories in France and Australia of approximately 104,000 barrels. Year-over-year funds flow from operations grew 19%, largely in line with our production growth. While commodity prices were weaker year-over-year, the impact was largely offset by comparable weakening of the Canadian dollar over the same period. Third quarter production averaged 49,920 boes per day an increase of 20% compared to 41,510 boe per day in the third quarter of 2013. Our strong year-over-year growth was largely attributable to the continued development of our Cardium light-oil and Mannville condensate-rich gas plays in Canada. The time of previously discovered gas volumes in the Netherlands and our recent acquisition in both Germany and southeast Saskatchewan had established key new regions for growth and development. Our Germany acquisition completed in February of this year provides us with entry into a sizeable market with a long history of oil and gas development activity, low political risks and strong marketing fundamentals. The assets are free cash flow generating, low decline assets with near-term development opportunity in addition to the longer-term, low permeability gas prospectivity. We believe that our conventional and unconventional expertise coupled with new access to proprietary technical data will position us for future development and expansion opportunities in the region. Following the acquisition, we’re participating in the drilling of the Deblinghausen Z7a development well, 25% working interest in Germany. The well logged 81 meters of net pay in the Zechstein Carbonate and was tested in late September 2014 for the period of 17 days. During production testing, the well produced at an average rate of 10.2 million cubic feet per day at a flowing tubing pressure of 1,840 psi. In October, this well was placed on production at an initial gross production rate of 16.5 million cubic feet per day of raw gas at a flowing tubing pressure of approximately 1,300 psi confirming our current views on the prospectivity of the region. In late April 2014, we announced the completion of our acquisition in southeast Saskatchewan and establishing a new core area for Vermilion in Canada. The acquired assets consist of high netback, light oil production in the Northgate region and include approximately 57,000 net acres of land, approximately 80% undeveloped, seven oil batteries and preferential access to 50% or greater capacity at a third-party solution gas facility that is nearing completion. During the third quarter, we initiated a two-rig, 12-well Midale drilling program and successfully expanded our southeast Saskatchewan land through the purchase at Crown land sales of approximately 15,000 net acres of undeveloped land to the Northwest of our existing lands at an estimated 60 new development locations. Additionally, in late September, we completed an $11.1 million transaction, which marks our first acquisition in the United States. This transaction represents a low-cost entry position in the prolific Powder River Basin of Northeastern Wyoming providing both a promising tight oil development project, and the human resources necessary to support future growth and acquisitions in the region. Through the transaction, we acquired approximately 68,000 acres of land, 98% undeveloped with current working interest production of approximately 200 barrels per day, 100% oil, proved plus probable reserves estimated at 2.2 million boe, which is 82% oil and contingent resource of 10 million boes, 82% oil. Transaction metrics with no deduction for land value, equate to approximately $56,000 per boe per day and $20.98 per boe including future development costs of approximately $35.3 million. The land base includes 53,000 net acres at a 70% operated working interest in a promising tight oil project in the Turner Sand at a depth of approximately 1,500 meters. The most recently completed well on this land block, 70% working interest is currently producing approximately 220 barrels per day of oil in its fourth month of production from an approximately 1,100 meter hydraulically fractured horizontal lateral. In Canada, we remained active drilling conventional horizontal wells in each of our Cardium light-oil and Mannville condensate-rich gas resource plays in Central Alberta as well as in our new Midale oil play in southeastern Saskatchewan. In the Cardium, we believe we’ll achieve incremental improvements in production efficiency and a significant reduction in per section costs through our utilization of long-reach horizontal wells, some as long as 2.25 miles. These efficiency and cost improvements enable us to achieve even better economics than those achieved in 2010 in the sweet spots of our Cardium acreage despite a portion of our current development activities now being located toward the thinner outer fringes of our development area. Our Mannville condensate-rich gas program continues to achieve robust economics with after tax rates of return currently in excess of 100%. We’ve really just begun development of this play having now drilled about 3% of our Mannville prospect inventory, resulting in exit production for the third quarter of 2014 of approximately 4,000 boe per day. Needless to say, we’re excited about this play. And we think it will provide significant growth over the next several years. We also continue to appraise our position in the unconventional Duvernay condensate-rich gas resource play, where we’ve amassed 317 net sections at the relatively low cost of $76 million, and that’s about $375 per acre. Our position comprises three largely contiguous blocks in the Edson, West Pembina and Niton areas and to-date, we’ve drilled three vertical stratigraphic test wells, and have completed drilling operations on two horizontal appraisal wells. The first horizontal appraisal well drilled is 1,180 meters horizontal length is located in the downdip part of our Edson block where condensate yields are expected to be lower than the average and our overall land position. We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct microseismic monitoring in the stratigraphic test well when we frac the horizontal well, expected to occur during the fourth quarter of 2014 that is the fracing of the horizontal well. Our second horizontal appraisal well, 1,280 meters of horizontal length, which we operate at a 34.8% working interest, is located along a shared lease-line in the Pembina block to allow partner participation. Completion activities on the Pembina well, including microseismic monitoring, were completed during the third quarter. The well was brought on production in October 2014 and has produced for 16 days. Raw gas rate has averaged 2.2 million cubic feet per day with expected sales gas rate of 1.8 million cubic feet per day after liquids shrink and plant fuel with an estimated hydrocarbon liquids rate of approximately 180 barrels per day, approximately 60% pentanes plus. The well is producing at restricted rates using a 12/64 inch downhole choke to generate an estimated flowing bottomhole pressure of 4,200 psi and that’s with about 55% drawdown. Our Edson Duvernay horizontal appraisal well 100% working interest is expected to be brought on production late in Q4 of 2014. Our development-phase target for Duvernay well cost including drill, complete, equip and tie-in is $12 million to $15 million. We believe that development-phase savings will be achievable through learning-curve improvements, lower lease construction costs, economies of scale in procurement and lower evaluation expenditures such as the elimination of microseismic monitoring. We anticipate that the production results and interpreted fracture geometries from the microseismic data of these appraisal wells will assist us in optimizing completions on future development-phase horizontal wells. We’re confident that we will be able to project the appraisal well results to higher condensate yield locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window. Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational, and timing advantages if we progress to full development of the Duvernay condensate-rich resource play. In combination, our Cardium, 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 into the next decade. Moving to Europe, we had an active quarter with drilling programs in both France and the Netherlands. Following up on our highly successful 2013 Champotran drilling program, we drilled the final three of five Champotran wells planned for 2014 during the third quarter. All five wells achieved first oil during the third quarter and were currently producing at oil rates averaging approximately 200 barrels per day per well. We also continued preparations for the phased transfer of our Vic Bihl gas production from the Lacq gas processing facility to an alternative third-party. Delays in receiving required permit transfers have delayed our expectations of bringing approximately 850 Mcf per day of solution gas back on-stream to early 2015. The remaining 3,400 Mcf per day of gas cap gas is now expected to be back on production in early 2016. In the Netherlands, we drilled the Diever-02 exploratory well; we have a 45% working interest during the third quarter in the Drenthe IIIb concession on lands acquired in October 2013. This well primarily targeted the Permian sandstones and encountered two well-developed gas bearing intervals in the Akkrum and Slochteren formations with a net pay thickness of approximately 36 meters. A three-hour clean-up test was conducted on the Slochteren formation, which delivered 25.7 million cubic feet per day of gas on a 40/64 choke with 2,615 psi flowing tubing pressure with no indications of pressure drop during the test. The flow rate was limited by the 3.5 inch diameter of the tubing and the capacity of the test equipment. The well is expected to be tied-in with production from the Slochteren formation in Q4 2015 at an estimated rate of approximately 1,000 boes per day, net to Vermilion. The Akkrum formation is anticipated to be perforated at a later date once the Slochteren formation has been fully produced. Subsequent to the end of the third quarter, we drilled a gas discovery well in the Netherlands at the Langezwaag-02 location. We have a 42.3% working interest in the Gorredijk concession. This extended reach well recorded significant gas shows in two meters of Vlieland Sandstone and 21 meters of Zechstein-2 Carbonate. Open hole logs could not be run in the highly deviated well. The Langezwaag-02 well was first flow tested from the Zechstein-2 Carbonate at 12.4 million cubic feet per day through a 48/64 inch choke at a flowing tubing pressure of approximately 1,300 psi. Our second flow test in the Vlieland Sandstone yielded rates of 2.7 million cubic feet per day through a 32/64 inch choke at a flowing tubing pressure of approximately 960 psi. The remaining well of the 2014 drilling campaign is expected to be drilled and completed during the fourth quarter of 2014. Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014. Shell, the project’s operator successfully completed offshore work over and pipeline operations during the third quarter and the wells are ready for operation. Shell also significantly advanced tunnel outfitting, which is now estimated to be approximately 95% complete following installation of flow and umbilical lines in the 4.9 kilometer tunnel. Remaining activities include final cable installation, hydro-testing and grouting, as well as commissioning of the gas processing facility and finalization of operating permits. We anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 million cubic feet per day, which is about 9,700 boes per day net to Vermilion. In Australia, we continue preparations from our upcoming 2015 drilling program; 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. Today, in view of our consistent operational performance, we’re further narrowing our production guidance for 2014 to a range of 49,000 to 49,500 boes per day, from our previous guidance range of 48,500 to 49,500 boe per day and currently expect production to be near the upper end of this refined range. And I believe we’ve had three upward production guidance numbers that we provided to the market and we’re now at the upper end of our third increase in guidance. We anticipate providing formal 2015 production and capital expenditure guidance details in early December 2014. While it remains under review, we currently anticipate our 2015 capital budget will be less than 2014 capital expenditure levels. However, we do not currently anticipate this will impact our expectation for 2015 production levels in the 55,000 to 57,000 boe per day range which has been reflected in our corporate presentation since March of this year. Assuming commodity prices remain near current levels for the remainder of 2014, we continue to believe that we can fully fund our net dividends and development capital expenditures excluding capital investment at Corrib with fund flows from operations during 2014. At the end of the third quarter, we had available debt capacity of approximately $775 million including a $250 million acquisition based accordion feature. We believe this leaves us uniquely positioned to potentially grow and further diversify our asset base through acquisitions in North America or internationally, should suitable opportunities arise. With our conservative balance sheet, relatively low cost of capital, and significant anticipated free cash flow growth including from Corrib, we have a distinctive advantage when transacting in today’s well supplied, acquisition market. In keeping with our strategy of pursuing long-term growth in our three core regions in North America, Europe and Australia, we have established two new offices led by locally-experienced management with strong track records of success. As the operating headquarters of our new U.S. Business Unit, we have opened an office in Denver, Colorado, Daniel Anderson has joined Vermilion as Managing Director for our U.S. subsidiary. Mr. Anderson has 30 years of experience in the upstream and midstream energy sectors throughout the U.S. He was formerly President of Baytex Energy USA, with previous management and technical roles at Berry Petroleum, Williams Companies, Santa Fe Snyder and ConocoPhillips. Mr. Anderson has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. Further strengthening our capabilities for growth in the U.S., Timothy Morris has joined Vermilion as Director of U.S. Business Development. Mr. Morris has more than 30 years of experience in land management and business development in the U.S. He was formerly Vice President of U.S. Business Development for Baytex Energy Corporation, with previous management and land roles at Berco Resources, Santa Fe Snyder and Sohio. Mr. Morris has a Bachelor of Science degree in Minerals Land Management from the University of Colorado and is a Certified Petroleum Landman. As the operating headquarters of our German Business Unit, we have established an office in Berlin. Albrecht Möhring has been appointed Managing Director of Vermilion’s German Business Unit. Mr. Möhring brings 30 years of diverse experience in the energy business to Vermilion. He was formerly a Managing Director for Germany with GDF Suez, with previous roles as Group Exploration and Operations Manager in Paris for GDF Suez and in management with Preussag Energie in Germany, the predecessor of GDF Suez in Germany. Mr. Möhring has a Master of Science degree in Petroleum Engineering from the University of Clausthal. The management and directors of Vermilion continue to hold approximately 6% of the outstanding shares and remain committed to delivering superior rewards to all stakeholders. In 2014, Vermilion celebrated 20 years as a publicly traded company. This has been a demanding but also a tremendously rewarding 20 years. During that time, we remained committed to stewarding our company in the best interest of our shareholders. We’re pleased with the results having delivered a compound annual total return to shareholders at the end of the third quarter of 36.4% since our inception. So with that, I’ll conclude my formal remarks. And operator, please open the floor to questions.

[Operator:]

(Operator Instructions). Your first question comes from the line of Pavan Hoskote with Goldman Sachs. Your line is open.

[Pavan Hoskote:]

Thank you. Good morning everyone. You had some positive updates in Netherlands and Germany. Can you please put that into context in terms of what that means of million from a production perspective going forward? And then on a related point, can you discuss your views on European cash price realizations and how you expect that to move in relation to Brent oil prices?

[Lorenzo Donadeo:]

Okay. I’ll maybe touch on the second part first then I’ll pass it over to Tony to speak to how the drilling results we’ve had in Germany and Netherlands will affect production. In terms of gas price realizations in Europe, I’m sure you’ve all seen that Russians just signed another third year supply agreement with China, which is both similar size to the previous one they signed couple of months back. I think in combination this is -- I think I worked it all roughly, but it look like it has bored another 3 bcf per day supply total of the both 5 or 6 bcf per day of total supply and my numbers might be a little bit off, but it’s quite significant. So, third year supply arrangement to China. As you all know Russia provides about 30% of Europe’s gas needs. And Russia has always been very committed to tying gas prices in Europe to oil equivalent. With Brent coming off, gas prices have come off a little bit. Our view longer term in Europe and we’re still currently realizing close to about $10 per Mcf just under about $9.75 something like that per Mcf. Our view is that we’re quite bullish on European gas in the longer-term. We feel that in the $10 range it’s pretty reasonable area that we’ll achieve some good support from the new supply contracts that were announced with fresher delivery in China. The only alternative to Russian gas into Europe is really landed LNG from North America, which will take at least something north of $10. So, I think the $10 per Mcf is always going to be supportive price in Europe. You’re going to get fluctuations around that, but I think longer-term we feel that’s a pretty solid price. And it’s really one of the reasons why we’ve had -- we’ve always been bullish on European gas, it’s one of the reasons that we’ve had European focus when (inaudible) comes on here mid next year, we’ll have on a combined basis in Europe. We’ll have about a 120, 130 million cubic feet per day of European gas production. And we’re really just starting and we’ll have cash flow out of our European business, it’s going to be somewhere between $550 million and $650 million per year depending on commodity prices. What’s going to be our dominant position in Europe is only becoming more solidified and it’s going to gather momentum. I think these discoveries that we’ve had in Netherlands and in Germany, I think we amplify our views on the prospectivity of our European land holding. So with that I’ll pass it on to Tony to speak about the production growth.

[Tony Marino:]

Okay. Pavan, [Lorenzo] answered to the first part of your question there about the productivity once those wells are put in line. So, in the case of the Netherlands wells, we’d expect them to be tied in probably Q3 and Q4 next year in aggregate to our interest those wells would have an impact of about 1,500 boe a day for the Diever and Langezwaag together. They of course have higher deliverability than that number, but we don’t tend to build our facilities there to produce at a maximum rates, beginning we like to maintain our capital efficiency by having better facility utilization and sometimes that results in having wells restricted in the early phases of their production periods. So, again for those two wells, I’d say at least 1,500 boe/d in European gas is our interest. In terms of the Deblinghausen Z7a well. We would say that to our interest that well will probably be producing at around 500 boe/d, hydrocarbon gas for the foreseeable future. So, those would be the two impacts in Netherlands and Germany from that set of wells, really should have all of these business units continuing to grow as I have from 12% to 13%, 13% to 14% and as Lorenzo was saying we haven’t yet said the CapEx budget for this year, but I think they put us in a position to continue that growth on a BU-by-BU basis.

[Pavan Hoskote:]

Got it. Thanks for that. And then a quick follow-up question on the Duvernay shale. Recognizing that we are still awaiting results from the second well and you’ve not formally put out your 2015 budget, but how much of a Duvernay focus should we expect in the 2015 program given the early stage nature of the play, the higher well costs and the lower commodity prices?

[Lorenzo Donadeo:]

Tony, why don’t you speak to that?

[Tony Marino:]

Okay. Yes. Well, of course it will, how much we put into any program is going to depend on the size of the overall budget and that’s something that we’re still working through. The thing about the Duvernay of course is that we’re not really driven by near-term expirees to have to drill further wells. So we do have the option if we choose to of continuing to watch the industry activity, continuing to learn from the industry on ways to bring down the well costs and improve the productivity. And I think we’ve certainly benefited from that already and that’s had impact I think on our ability to do pretty well in the initial efforts that we’ve reported there in the Pembina area. So again, it’s really just too early to say but we are very fortunate in a case of Duvernay to not have to be driven by any external factors. I think we’ve got a potential valuable -- very valuable land base. They’re very large sized, contiguous which is unusual in the play. And of course, when you have that combination of size and the continuity or land base, it should allow much better capital efficiencies in the development of a resource play. So, we’re optimistic, not making any commitments at this point about how we might capitalize it in the near term. And we think that the wells so far or the well that we have on production so far demonstrates pretty good option value for the company in this play.

[Pavan Hoskote:]

Got it. And one last question, you announced an acquisition of Powder River basin assets. I was hoping, you can give us a little bit more color in terms of the choice of display over potentially other plays in the U.S. And can you also discuss your initial expectations on well productivity and costs?

[Tony Marino:]

Okay. Yes, this particular land base that we bought is in the Powder River basin, it’s in one of the Turner Sands, which was one of the actual top types of plays that we identified in our reconnaissance of U.S. We like it, because it is shallow, it’s about 5,000 feet that will definitely make it cheaper than a lot of the title oil plays. We like it, because it is a clastic reservoir; and like a lot of clastics it actually has okay permeability for a tight rock. And we like the fact that we also have this contiguous land base there, adjacent to existing producing fields, so it’s halo type of play like we saw in the Cardium. So, those are the desirable characteristics that we were able to get into this play and those are the things that we’re seeking in the U.S. As far as the productivity here, actually at the time that we made this deal, we really made the assessment on these geologic characteristics that I was talking about. We’re fortunate that there was well that was just being put on production at -- a horizontal well with a contemporary style of frac that was being put on production at the time we were closing the deal and that well built up to peak production rate of about 220 barrels of oil a day during its fourth month of production. So, it’s only a three quarter mile long well. We think that we could do better in the future with the longer well. We think it had a good modern completion, but I am sure there are ways we can optimize on that. So, that’s really pretty encouraging productivity for a reservoir that occurs at such a shallower depth. As far as well cost that initial one-off was about $4.5 million. We think that we can bring those down to $3 million to $3.5 million per well. To do that would actually be quite a bit less of the learning curve than we achieved in the Cardium. So, we think something like that is achievable. And our hope and our intent overtime is that if we take this play slowly really understand it as we continue to evaluate it and develop it that we could do considerably better than the current well in terms of productivity and bring those well costs down in the range that’s we think appropriate for a shallow play like that.

[Pavan Hoskote:]

Thank you.

[Operator:]

Your next question comes from the line of Greg Pardy with RBC Capital Markets. Your line is open.

[Greg Pardy:]

Yes, thanks. Good morning. Just a couple of kind of needy questions for Curtis. I was just wondering can you give us a sense of cash tax for the year, I know it’s a modeling question, but just wanted to get a feel for that?

[Curtis Hicks:]

Sure, Greg. I mean I think in a couple of jurisdictions tax has been fairly consistent through the year. One area that has been a little bit more volatile is in France, we’re forecasting tax rates in the low 20%, 22%, sort of maybe after 26%, I don’t think we’ll get that high. And as at the end of the Q2, we were probably up in the 28% range. The discrepancy there results from the fact that oil prices have come up in the second half and [playing] particularly less third of the year and as a result we don’t believe that we will trigger the large corporations’ tax in France that is applied to companies that generate €250 million of revenues or more. And keep in mind that that revenue number is applied to each operating entity that we have in France, in which we’ve got the four separate entities. So [Viva], the original subsidiary in France is our largest and certainly was on track to beat the €250 million in revenue. So, we’ve been able to pull back a little bit in France in terms of our tax liability. So, low 20%, 22% to probably 24% is not a bad number. In the Netherlands, we’re in about 6.5% to 7% pretty consistent. In Australia right in around 40% on a combined PRT and CIT basis. That has been relatively unchanged. And in Germany, we’ve brought that down a little bit from -- it’s not big dollars, but from 9% to 10% work, 3% to 4% range and the change there stems from the fact that we’ve been able to work that country a little bit more and get a little more comfortable with our ability to take a greater portion of the acquisition price as a deduction this year. So, we started the year a little more conservative, but with time we’ve been able to be comfortable with a bigger deduction. So we’ve provided guidance of about $175 million in total taxes that still is going to be subject to move plus or minus a little bit depending on the impact of Q4 capital activities, as well as any other in commodity price moves.

[Greg Pardy:]

Okay, thanks very much for that. And just one question just with your Australian oil realizations, are those essentially a fixed premium brand that you’re going to receive or that you do receive?

[Curtis Hicks:]

Well, we do receive on the bulk of our crude, we sell it to a niche Japanese refinery market. We are selling under a contract that receives [Brent +7] today. That’s an annual contract that runs till the end of March. We do initiate some spot sales through the year to be able to sell crude obviously the Japanese refineries don’t acquire. And so it’s subject to whatever the market bears at the time the market has been somewhat saturated with crudes, the premium pricing isn’t there today as it was say a year ago. So we’re selling that crude for just a slight premium to Brent.

[Greg Pardy:]

Okay, great. And last question is maybe just to come back to the U.S. given that you’ve opened an office, he’s made a couple of big hirers. It looks like should we be reading into this and there is a bigger, broader trust that we’re going to see going to the U.S. some of next couple of years?

[Curtis Hicks:]

Well I’ll maybe touch on that and then -- but I think generally we’ve expanded our focus areas. I mean we were sort of prior to Tony comment on board, we weren’t really all that comfortable with the U.S., just because we didn’t have senior management expansion in country, but with Tony’s significant background and working throughout the U.S., we feel a lot more comfortable, we had a very successful sort of history of working in a number of basins there. And I think we supplemented his expertise with some pretty impressive guys that now allow us to have another alternative sort of hunting ground for the company. We feel that was -- these three areas now sort of expanded I guess with Canada going, to North America, Europe and then Australia, we think we’re really well position to see the company go to sort of new levels. And I think we’re well positioned as a company now in these three areas to really grow over the next 10 years to pretty significant levels. And yes, you should expect over time, more growth and more acquisitions in the U.S., because we do see it as an area where we can profitably grow and do some value-added acquisitions. But you do have to be patient and you have to be disciplined, and so that won’t change.

[Greg Pardy:]

Okay. And Lorenzo, when it comes at some point, right, the question, just focus in the portfolio is going to creep on you. How do you, I mean the three reasons that you’ve outlined are obviously pretty big in a context of the oil and gas business. Is there essentially -- every opportunity is agnostic from the standpoint of geography, it really kind of comes back to the economics and the running room that you’ve got or are you now -- do you think you’re starting to see a little bit more of an orientation towards North America versus Europe? Just trying to get an understanding there.

[Tony Marino:]

Yes. We’ve had this question about being spread out I think since 1998. And I think if you look at our results as a company, you got compound returns of 36%. I mean I think that sort of speaks for itself. We have had to sort of explain to questions from shareholders about being pretty diversified. I mean because people were worried about other companies and I won’t mention names but I think everybody knows it, other large international companies in Canada that were spread out and had problems. But keep in mind those companies were in probably five or six different regions, maybe more and quite a lot -- they looked a lot different than we do. I mean Vermilion, our Australia business is pretty focused, obviously it is one asset. We’ve been mining it since 2004 and we’ve done a pretty good job with that. Europe, we look at that as one region. I know it’s a bunch of different countries, but it’s really if you look at the distance from France to Netherlands and Netherlands to Ireland and there is no difference in going from Fort St. John to Grand Prairie to southeast Saskatchewan into Manitoba. So we look at that as one kind of region, similar to what our people’s Canadian business appears any businesses. And the North America just an extension to that, I mean probably the U.S. is just an extension to that. So, yes, we are kind of agnostic. We’re really just focused on creating value and we think that we’ve got the infrastructure and the people to continue to provide strong returns in these three regions without being too concerned about whether they fit into one compressed query or like some others have tried. But I mean from our perspective, we think that diversification is what provides the opportunity to be disciplined and to pick your spots and find the areas where you can create the most value.

[Greg Pardy:]

Okay. Very good. Thanks very much.

[Tony Marino:]

Yes, thank you.

[Operator:]

(Operator Instructions). Your next question comes from the line of Travis Wood with TD Securities. Your line is open.

[Travis Wood:]

Good morning and thanks guys. A lot of the questions have already been addressed. But I have one question on the Mannville, and it’s just respect to the Q4 drilling. Of the 6.7 net wells left, do you have a sense of the timing that those will be on production through the rest of the year?

[Tony Marino:]

Yes. Travis, probably the majority of the Q4 drilling would be coming on, whether it’s a Cardium or the Mannville, probably the majority will come on in January. Some will get on before the end of the year. Number of the wells are drilled from pads; those pads have to be completely drilled before the completions can start. So, predominantly beginning of ‘15.

[Travis Wood:]

Okay. And then just a question kind of taking a step back in the context of the market today. From if we look at the jurisdictions and where you’re operating and kind of the cost side of the equation with the slide in the commodity. Are you starting to see, specifically services costs whether it’s drilling or completion but are you seeing service costs slip at all in terms of re-pricing that and how does that compare from Europe into Canada so far?

[Tony Marino:]

We are determined to bring down services costs heading into the New Year’s program. I think it’s something we can achieve either with or without a big drop in industry activity. And eventually, there probably will be a drop in activity. We’ll have to see how all the capital announcements are that will come out over the next couple of months. But probably activity will drop. And if it isn’t significant in Q1, I bet it will be significant later in the year. So, I think for North America, the answer is yes. In Europe, we’ll also seek to make reductions in our services costs and I think we’ll achieve some. Now I don’t know that that market in terms of activity will be -- North America. For one thing a lot of it is driven by European gas, which continues to have very, very strong prices. And you do have to do longer term planning in Europe because there just isn’t the fleet onshore services that you have to select from in North America. So perhaps in a less pronounced way, we’ll make reductions in Europe and I definitely think we’ll have them in North America.

[Travis Wood:]

Okay, very good. That’s all. Thank you.

[Operator:]

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

[Gordon Tait:]

Good morning. Just wanted to ask you about your European gas hedging. Are you getting more exposure to the European gas markets coming on and what you’re doing in Netherlands and Germany? Are you looking at being a little more active in terms of hedging that production?

[Lorenzo Donadeo:]

Yes. I mean we’ve been pretty active in hedging European gas and we’ve been layering probably since middle of last year, layering in some 2015 hedges and we’re starting to become a little more active in 2015. So, we are -- the price levels right now are like in like I mentioned sort of in that 965, 975 an Mcf maybe a little bit higher in the first quarter and fourth quarter, but have levels that we’re pretty happy with.

[Gordon Tait:]

Okay. And with the recent well results you’ve had in the Netherlands, I think that was the Diever exploration well. How does that well, how did the results of that well compare to some of the wells you had drilled say in the last few years, is this kind of in line with those results or is it sounds like a pretty strong rate of this producing.

[Tony Marino:]

Yes Gordon, the Diever well looks like a good one, I would say it’s in the upper-end of the results that we’ve achieved in the Netherlands, we haven’t disclosed EOR estimates for it yet. We actually over the years will drill the numbers of good wells, but I’d say this is in that upper-end of the range for what we’ve drilled.

[Gordon Tait:]

And then when you compare, when you look at the Germany versus the Netherlands. How does the prospects look when you look at well costs, type curves, EORs. Does it favor one over the other at this point?

[Tony Marino:]

There are good prospects actually in both countries. I would say Germany is more diverse in terms of the play types at least as far as what we’re pursuing, we’re predominantly natural gas in the Netherlands typically Rotliegend and Zechstein prospects. So, there is a certain mode as far as well economics and they’re quite strong in that country. We have a small actual acreage position now that we didn’t use to have, it gives us some potential for oil development down the line, but is primarily those Rotliegend and Vlieland and Zechstein targets in Netherlands. Germany is I would say more diverse in terms of having a combination of oil and gas targets, we think they’re pretty strong there. Since it does have a greater number of oil targets than does the Netherlands for us, it becomes a little bit hard to exactly describe which set of prospects are better, I’d say that both are very strong and we’re hopeful and intending to expand our business in Germany overtime and have to be involved in different types of prospects there.

[Gordon Tait:]

Okay, thanks.

[Operator:]

Your next question comes from the line of Kyle Preston with National Bank. Your line is open.

[Kyle Preston:]

Yes, thanks. Good morning guys. Just wondering if you can tell us how are you thinking about the dividend right now just in the context of the current commodity price environment. I know you’ve indicated in the past that you’d like to potentially provide a regular increase there, is that something we can expect this year? Thanks.

[Lorenzo Donadeo:]

Yes. Regarding dividend I mean we’re just going through and putting together our plans for capital spending for 2015. And as we mentioned, we’ll be providing sort of an update in early December. I think our plans always have been sort of in a general nature, our strategy has always been that we’d like to provide steady sort of reliable and growing dividend so that hasn’t changed. We haven’t made a decision in terms of the dividend for 2015. It will depend on where commodity prices sort of level off because we want to be cautious and prudent in terms of how we manage our sustainability as a company. ,So we’re going to just be reviewing that over the next few weeks and see where commodity prices level off, I mean there is a number of key catalysts I guess with the [OPAC] meeting and those types of things in the next few weeks. And so, we’ll be evaluating all that data with our Board and then decide in terms of what we might do for dividends for 2015. But the strong message is that, our strategy hasn’t changed and we do want to provide sort of reliable and steadily going dividends of overtime. And we think that with the cash flow growth that we’ve got in front of our company we’ll be able to deliver that over the medium term and longer term and continue to provide today growing dividends for our shareholders.

[Kyle Preston:]

Okay, great. Thanks a lot.

[Lorenzo Donadeo:]

Yes, thanks.

[Operator:]

(Operator Instructions). There are no further questions at this time. I will turn the call back over to the presenters.

[Lorenzo Donadeo:]

Okay. Well, thank you operator and thank you everyone for participating in our conference call today. Thanks for the questions. And thank you very much. Bye, bye.

[Operator:]

This conclude today’s conference call. You may now disconnect.