CALGARY Oct 7, 2015 (Thomson StreetEvents) -- Edited Transcript of Bankers Petroleum Ltd earnings conference call or presentation Wednesday, October 7, 2015 at 12:30:00pm GMT TEXT version of Transcript ================================================================================ Corporate Participants ================================================================================ * David French Bankers Petroleum Ltd. - President and CEO * Suneel Gupta Bankers Petroleum Ltd. - EVP and COO * Doug Urch Bankers Petroleum Ltd. - EVP, Finance and CFO ================================================================================ Conference Call Participants ================================================================================ * David Dudlyke Dundee Capital Markets - Analyst * Darrell Bishop Haywood Securities Inc. - Analyst * Jamie Somerville TD Securities - Analyst * Isuru Seneviratne Radiant Value Management, LLC - Analyst ================================================================================ Presentation -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- Good morning. My name is Melissa and I will be your conference operator today. At this time, I would like to welcome everyone to the Bankers Petroleum Ltd. third-quarter operational update conference call. (Operator Instructions) Thank you. David French, President and CEO, you may begin your conference. -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [2] -------------------------------------------------------------------------------- Good morning. Thank you for joining the Bankers Petroleum third-quarter operational update. The third quarter was another good quarter for the Company, despite ongoing pressure on oil prices and the negative effect on the equity markets. Bankers results show a continued ability to do more with less and that capability will stay on to us as we approach 2016 with a mixed outlook on oil prices. It seems that a new investor report comes out daily with the second half of 2016 looking better and better, but we are focused on being ready and capable of strong performance, even in persistent low prices. The recipe for a strong rest of 2015 and a good 2016 is simple: maintain solid production performance, continue to drive improvement on what it costs to capture our barrels, and what it costs to produce them. Firstly, as to the solid production performance, the third-quarter production averages 19,598 barrels per day, down about 2% from the last quarter, but actually a slight increase over the reported first half of 3Q. Given that only 14 wells were drilled in 3Q to match capital to cash flow, arresting the decline over the quarter is a strong operational moment for the Company. This can only be associated with falling corporate declines. In 2015, we need to drill about 85 wells to offset our decline. This year, that number will be closer to 45 wells. That delta is because of EOR. Imagine if we can do that again in 2016 with the patterns initiated in 2015. That gets me to my second point: driving cost to capture. We are across the board working our traditional well costs down and expect to see progress heading into the end of the year. And we are exploring the potential of Bubullima, which looks to be significantly better than our bread-and-butter Patos wells. We have work to do to test aerial scope and economic watercuts, but the potential is strong. I look forward to discussing two to three more Bubullima wells as we test them in 4Q. The Bankers team has also planned another multilateral test and we are committed to bringing another 10 to 15 EOR patterns underflood for the rest of the year. As many of you have heard me say, EOR is no longer a side project for Bankers. These wells have similar reserves to their primary curves, at two-thirds the capital. They will easily help us do more with less. Thirdly, driving cost to produce down. We will discuss the actual cost improvements when we release financials, but all the indicators are in the right direction. The Company focused on targeted facilities projects to reduce waste, has clipped $7 a barrel from our costs over the last 3 years, and we are in the eighth inning of our projects around emulsion handling and gas capture. These will continue to give us headroom against low prices heading into 2016. But even if we do all of the above to deliver more with less, we need to think about price strategy for next year. Therefore, we have an effort in place to build a collar position of up to a third of our production. We took two collars late in the third quarter to get us between $54 and $58 Brent on 2,500 barrels a day. You will see us look to opportunistically add to this position as the markets allow. Lastly, before I turn the call over to Suneel, I wanted to comment on our progress towards resolving an outstanding prior-year cost recovery audit. Two weeks ago, we signed a formal terms of reference with our agency AKBN to utilize an international auditing firm to review the costs in those years and their applicability as hydrocarbon costs. This terms of reference marks a tremendous move forward for the efficacy and transparency of our business in Albania. We also sought and received Albanian court comfort that this terms of reference should be allowed to run its course before any tax is assessed. These are both very positive developments and we anticipate it will take a couple of months to get an opinion from the soon-to-be-selected auditor. All systems are on go for the Company, especially as we build towards 2016. I will now pass the call over to Suneel, our COO, for more details on the operations update. -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [3] -------------------------------------------------------------------------------- Thank you, David. Good morning, everyone. The third quarter of 2015 was a good quarter for Bankers, as we stabilized production and continued seeing the impact of our cost improvement initiatives. It was another responsible quarter where we maintained balance spending with cash flow. We drilled 14 wells in the quarter, including a well in Kucova, and are on track to drill just over 60 wells in the year as per our capital program. The Kucova horizontal well is the second drill in the Arreza pool. It encountered clean reservoir sections and the pressure was higher than expected. The well has been completed and recently brought on production. The first well at Kucova, drilled in the fourth quarter of last year, is producing at stable rates of 40 to 45 barrels of oil per day and the new well is a follow-up in the same pool. The highlight of the quarter is the Bubullima production in the Patos-Marinza field. These wells have high gas/oil ratios and watercuts in the range of 85% to 90%, but are delivering good oil rates and further optimization potential is available. We have 4 wells producing an average of about 200 barrels of oil per day, (technical difficulty) from 100 to 300 barrels of oil per day, with 1 well recently drilled and being optimized and 2 to 3 wells scheduled for drilling this quarter, one of which is currently being drilled now. Handling of the sour oil production and high water volumes is a challenge, but plans are being developed to support this program. We continue to be focused on our EOR program in the Patos-Marinza field, with 2 injector conversions in the quarter, bringing the total to 34 patterns, 6 waterflood, and 28 polymer flood patterns installed at the end of Q3. The EOR patterns are providing approximately 2,300 barrels incremental over the primary decline curve, representing about 12% of our current production. With the additional 10 to 15 conversions scheduled in the fourth quarter, we will have completed 23 to 28 conversions this year. The producer response timing has been 6 to 12 months typically and we are improving our simulations and forecasting confidence with this additional historical performance. With this response character and our pace of conversions, we have been able to affect our corporate decline, dropping it from 30% average per year on our base production to a decline range of 20% to 25% per year. As David mentioned, this helps us maintain production levels with less new drilling and capital spending. We will also be moving into new areas and converting more viscous oil patterns in the fourth quarter to expand our polymer flood application. Several other optimization and cost-cutting initiatives have continued in the quarter. We have reduced diluent blend further, from 7% earlier in the year to under 5%, and as low as 3.5% on some days with the lighter oil development and treating improvements. We have significantly reduced diesel and propane consumption, with initiatives to convert well pads to electricity for more efficient energy usage, and gathering gas from wells from our wells and facilities to further offset fuel needs. Emulsion gathering infrastructure projects are nearing completion. Specifically, the north emulsion gathering system, which will be complete in Q4, has projected to truck -- trucking cost savings of about $0.50 per barrel. And the west gathering system will reduce trucking a further $0.25 to $0.35 a barrel, bringing the in-field transportation cost down to below $1.50 per barrel from levels of above $2.50 per barrel last year. The gathering system will also reduce the impact of seasonal flooding. We continue to focus on improving our operating cost structure to improve our margins at these lower oil prices and have had significant impact from our projects that are underway. Thank you, everyone. We will now open to questions. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Operator [1] -------------------------------------------------------------------------------- (Operator Instructions) David Dudlyke, Capital Markets. -------------------------------------------------------------------------------- David Dudlyke, Dundee Capital Markets - Analyst [2] -------------------------------------------------------------------------------- Good morning, everyone. With regard to the Bubullima -- excellent results from the wells to date. Just a quick detail. You talk about the downtime for workover, so what would the production gross of that downtime being? Perhaps more importantly, what do you see as the incremental CapEx and perhaps OpEx for the sour and water treatment/disposal? So essentially, how much would you need to spend next year to basically open up and debottleneck your Bubullima plant? -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [3] -------------------------------------------------------------------------------- Yes, good morning, David. It's Suneel here. The Bubullima -- I think in terms of the workover, a lot of that is -- the Bubullima is still a zone that we're testing. So as we produce it for a while, we like to investigate and look at the pressure in the zone and also look that we can stimulate the zones. So the workovers are not actually taking up too much time for us to do so. It doesn't impact the production rate significantly, but there is a range of wells (inaudible) from 100 to about 300. In terms of the cost, what we're doing right now with the wells, we are not really using a consolidated larger scale development concept. So we're not using a larger sour facility or gathering systems to separate facility and gathering of the gas, and things like that. We are doing -- we're tying it into our existing infrastructure and making use of what we have. So in terms of the cost to build the larger facility for larger Bubullima development, that is something that we are establishing right now. And we're looking at how much of that can be incorporated into a 2016 program versus future years. So that's a number. We don't really have a good handle on exactly what that cost is. But right now, we're setting up the wells very similar to how we would other wells, but it's not a -- the expansion room is what would be limited for us and that's what we're looking at. So at this stage, it's too early for us to say. -------------------------------------------------------------------------------- David Dudlyke, Dundee Capital Markets - Analyst [4] -------------------------------------------------------------------------------- But given the prospective of high productivity wells, such as you are seeing at Bubullima, it must be a key area in terms of facility investment to debottleneck that particular part of your reservoir. But you can't quite put a hand -- you can't yet put handle in terms of the materiality of that investment? -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [5] -------------------------------------------------------------------------------- Correct, yes. We're looking at it at in full scale project economics because with the Bubullima, there's a lot of additional water that needs to be managed. So we would also look at our disposal system and the capacity of that disposal system, gathering the gas. But it being sour gas, we can't vent it; we need to flare it. So yes, we're looking at that full cycle economics on development of the Bubullima. But right now, we are still -- the wells that we have on are still largely being set up as single well batteries and run its tests. But for larger scale development, definitely we have -- and we are working on those plans, we just don't have them fully ready to disclose what the magnitude of our program for next year will be. -------------------------------------------------------------------------------- David Dudlyke, Dundee Capital Markets - Analyst [6] -------------------------------------------------------------------------------- Okay. If I might move to EOR, David, you made the comment that you expend two-thirds of the capital from EOR well relative to a standard horizontal well. And per your presentations, you expect it's roughly the same order of reserve recovery to the standard wells. And I must admit, that was my gut feeling. Can you perhaps -- if not online, but perhaps off-line -- remind me of the cost to date of the EOR program? Certainly the budget for this year was $28 million, I think, on a modestly revised down, but I can't recall or lay my hands on what you've spent to get to this 3,700 incremental barrels, what that has cost you, so I can sort of put that into my model in terms of capital productivity. -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [7] -------------------------------------------------------------------------------- Yes, David, I will get you the exact number. I can have Laura hand that to you. But I think it's going to be about twice the spend we've had of this year, so full and project costs. The reason why I talk about it being forward significantly less is obviously, you can't really convert wells unless they are drilled, so part of the four (multiple speakers) -- -------------------------------------------------------------------------------- David Dudlyke, Dundee Capital Markets - Analyst [8] -------------------------------------------------------------------------------- Yes, exactly. -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [9] -------------------------------------------------------------------------------- That's advantage to us is obviously we're spending the $1 million or so a well to set up the patterns, but the forward capital associated with that is probably even closer to less than half that. And then you are talking about a double booking of reserves. So say with going from our individual primary wells, add another 9% of incremental recovery, and we are seeing right now 8%-plus, if not double-digits, depending on where you are on the field, for the EOR booking. So for us, that's pretty exciting because the forward capital alone looks very attractive, but you always have to have a campaign of doing both. So why don't I have these guys hand you actual numbers, but it's going to be in the range of roughly twice the 2015 spend alone. And that's -- the nice thing is we're set up pretty well for probably half of the patterns already for next year because we've got polymer capacity in place to add a number of fairly inexpensive patterns heading into 2016. -------------------------------------------------------------------------------- David Dudlyke, Dundee Capital Markets - Analyst [10] -------------------------------------------------------------------------------- Okay. And on the same subject, you've got a -- you booked a modest 11 million barrels year end 2014 on EOR and I think that equated to some 76 or thereabout patterns. There are 2 factors. The degree with which or the comfort or the confidence with which you would like to open up that booking, because essentially that was about two years of the current run rate in terms of your EOR conversions. Are you as comfortable with perhaps, in terms of the empirical data, the reserve bookings per EOR pattern perhaps moving head of the 150,000 barrels that's imputed within the current bookings? Or perhaps extending the number of years -- the number of patterns that you might wish to see booking, which -- are you equally comfortable with either of those dimensions of what might be a future EOR booking at year end 2015? -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [11] -------------------------------------------------------------------------------- Well, we are in different locations, so I will probably answer that and see if there's anything else that Suneel would like to add. But the original 76 patterns essentially is a pretty -- it's a pretty conservative view of a pattern on either side of the existing patterns, which we were booked as PDPs. So it's pretty limited in scope and obviously, we've talked about it on this call before that we see potential going from that 75 to up to probably 300 patterns on what we know about our ability to do EOR now, which is really at the lower ranges of viscosity. What Suneel alluded to in his conversation, and this is where the second half of 2015's programs are important, is we are testing two things that we want to continue to evaluate to go beyond that sort of 300 patterns. And that is thicker sands and thicker oil. So we will know more probably at the end of 2016 about the next 25% of addressable crude in the field than we do now because we are essentially going to play below 2,000 centipoise; 1,800 or so today. We feel very good about the bookings associated with that. But we would like to push that number up to 3,000 centipoise and also know we can flood sands that are greater than 8 meters up to 15 and 20 meters in thickness. So can we sweep them effectively is the purpose of the next test, because it would play into how we develop wells if we think we need to address thicker sands differently. So pretty exciting opportunity. The run rates -- I think what we've seen from a historical performance tells us absolutely feel good about the ones that have already been booked and we think it's conservative. The question now is some technical questions around how we can process the rock that has slightly different characteristics. And I don't know, Suneel, is there anything else you want to add to that? -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [12] -------------------------------------------------------------------------------- Yes, no, that's exactly right, Dave. I think it's an important thing for the reserves assessment is the additional year of history and response. We always -- the last year when they came up with the response curves, we had very limited data. So this additional data is same kind of a profile as when we started doing the horizontal development. As we move through the program, our confidence level around being able to forecast and predict expansion of that program improves, which then would allow us to look at different areas of the field with the additional tests. So I would say right now, we just provided the information to our reserve evaluators and they'll go through it. We've had some very good response in line with what we're expecting, even better than we were expecting. So that should all play well for the reserves, but it's far too early for us to really say whether or not we are expecting any changes at this point. -------------------------------------------------------------------------------- David Dudlyke, Dundee Capital Markets - Analyst [13] -------------------------------------------------------------------------------- Okay. That's it for me. Thank you. Thank you all. Thank you very much. -------------------------------------------------------------------------------- Operator [14] -------------------------------------------------------------------------------- Darrell Bishop, Haywood Securities. -------------------------------------------------------------------------------- Darrell Bishop, Haywood Securities Inc. - Analyst [15] -------------------------------------------------------------------------------- Good morning, guys. I think David covered also a bunch of the questions I had on the Bubullima. Two questions for you. First one: David, you mentioned some capital cost savings that you are seeing out there. Just wanted to see if you could provide some color around well cost savings now that you guys are down to working with two rigs in the lower oil price environment here. And second question is in relation to the corporate decline rate. Obviously, 3,700 barrels a day coming from the water and polymer floods here in September is up pretty significantly from the 2,400 that you had in June. And I just wanted to know if you could provide some color around that bump that we've seen in the last three months. And if you can tie that into any performance changes or tweaks that you would have done to how you either inject water or polymer within the last 12 months of the program versus some of the earlier wells that you would have put onto polymer and waterflood. -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [16] -------------------------------------------------------------------------------- Well, Darrell, I will take a first pass, then I'll probably headed back to Suneel as well. So on the CapEx side, I think we have an internal -- as you know, we were drilling wells about $1.2 million a well or so. We were thinking that our run rates would be down closer to about $1 million a well as we head out of this year. We have gone back in conversations with all of our suppliers, because you guys probably know, we don't look like the same liquid market you would have in North America, where there's 10 different rig suppliers, then you just kind of price them down to whatever is available. I think we had pretty modest reversions as to cost and we are probably in the third or fourth inning of talking to contractors on costs. Most of the capital and OpEx savings -- especially OpEx -- have been driven on doing something different. But we anticipate being able to get -- we would like to be low that $1 million to a nine number that's a high nine heading into next year. Obviously, that's on our very typical wells. The Bubullima is a little bit deeper; probably cost you another $100,000 or so more, and maybe Suneel can add more than that. But that is all about drilling the wells efficiently. The guys have done a fabulous job getting us now into -- we've had some 10 1/2 day wells. That really makes a big difference on cutting rig rates, so it's really just about efficacy. And now it's a little bit of a broader conversation about reduction and CapEx across the supplier base. As to EOR, I don't think we want to project much further than to say in general, we're seeing very good response. As Suneel talked about, that 6 to 12 month response is giving us very nice relief in the second half of the year after we've done those injections. So the stuff we plan to do in 2015 we believe sets us up for another probably 1,000 barrels a day or more. And I would say probably more than that heading into next year in terms of decline mitigation. So every time we can stack 1,000 barrels a day into next year with declines that don't look the same, so they are on a plateau and they stay on that plateau for a period of time, all that does is give us an engine for cash to reinvest the following year and convert it to wells rather than fighting decline in wells that convert to growth. So for us, EOR in terms of mitigation -- it's going to be a piece of our business that we always want to find a room for in our capital because it sets us up. Even though we have to take wells off-line this year, it is excellent the following year and the year after that because it reduces the number of wells we have to drill to show growth to our investors. And we like that mix as a portfolio. Suneel, anything else to add? -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [17] -------------------------------------------------------------------------------- I just wanted to clarify, Darrell, for you: the total contribution coming from EOR is about 3,700 barrels per day. So around 19% to 20% of our total production. The incremental is 2,300 barrels of oil per day. That incremental is above where the primary decline would've been if we hadn't converted it to EOR. So this is actually very similar to the good numbers we had back in July at the last ops update. So it's just -- it's a very consistent program. Just as David mentioned, it's backfilling and it's just -- it's dealing with our -- or stemming our high decline that we had before we work with decline. The other part of that is because our drilling base has been reduced, we have a lot of our horizontal primary wells that are not as much in that steeper initial phase decline. They are moving into that shallower secondary decline. So those two impacts together are helping us reduce our overall average corporate decline from the 30% down to the 20% to 25%. -------------------------------------------------------------------------------- Darrell Bishop, Haywood Securities Inc. - Analyst [18] -------------------------------------------------------------------------------- Okay, great. Thanks for the clarification on that, Suneel. Any change, then, in your guys' stance in terms of when you start adding back rigs? At what Brent price, just given some of the cost savings that you're expecting? -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [19] -------------------------------------------------------------------------------- Yes, Darrell; this is David. I think we are still on the -- we used to talk about $70. I think that's a mid-$60s number, and I think we're still on a view that right now, we're probably not going to drill into a movement -- high $50s of Brent. Even though I think our numbers would justify that we can make the wells work, I think we still think right now we don't want to push too much against our general strategy of balancing operating cash to capital. So the general plan would be mid-$60s price. You would see us add every $4.50 to $5 Brent. -------------------------------------------------------------------------------- Darrell Bishop, Haywood Securities Inc. - Analyst [20] -------------------------------------------------------------------------------- Okay. That's great. Thanks, guys. -------------------------------------------------------------------------------- Operator [21] -------------------------------------------------------------------------------- Jamie Somerville, TD Securities. -------------------------------------------------------------------------------- Jamie Somerville, TD Securities - Analyst [22] -------------------------------------------------------------------------------- Good morning, guys. A couple of very quick clarifications -- sorry, maybe get into some detail. On the Bubullima, you said 4 wells producing 200 barrels a day. I think that's exactly the same as you said in July. But said you drilled the Bubullima well in Q3. That implies to me that at least one of your Bubullima wells is completely shut in for water or sour gas handling management. Is that correct? -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [23] -------------------------------------------------------------------------------- Yes, we do have one well that was recently brought on and it is currently shut in. As I mentioned, when we bring in these wells, we -- it takes a period of time to optimize the well and bring it up to the proper rate. So right now, that well is not in that average. So it needs to still be optimized. We don't really know what the potential is. We are expecting it will still -- once we drive down and get it to the stabilized production rate, that it will be similar to the other wells, but we don't really have much information on the performance of that well yet. -------------------------------------------------------------------------------- Jamie Somerville, TD Securities - Analyst [24] -------------------------------------------------------------------------------- Okay. And then you just clarified that EOR incremental production volumes from EOR have been flat over the last three months. Is that simply because we are waiting for the newer pilots to have production breakthrough while the older ones are running roughly flat? Or is there -- is that how we should be looking at it? -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [25] -------------------------------------------------------------------------------- Correct. When we get a response from patterns, there's a period where it all -- it will take some ramp-up to get up to the peak rate of the stabilized plateau rate. But once it reaches that plateau, we are hoping it stays there for a while. So three months ago, we saw a response from those central patterns, the ones that we had converted last year. We started seeing the response at about six months. So three months ago from now, it was over a -- fairly close to the plateau rates. And all it is saying is that it continued at those rates. And the earlier patterns, the [salt] patterns, some of them are -- have come off their plateau and they are starting to decline, but that was expected as part of the curve. So it's a balance of those two. So it's basically saying that the response is stable. The next response will be how long does that plateau last for those central patterns and when do we start seeing response for the wells that we converted earlier this year. And if there's enough overlap there, then we will see an increase to that incremental. Otherwise, the pace of the program is set so that we continue to have a nice, solid wedge which is a stable flat wedge of anywhere from that 2,300 to maybe as high as 3,000 or 4,000 barrels. So that is how the program has been designed with the 20 conversions plus per year. If we go with higher amount of conversions per year, of course that changes that. But right now, the pace kind of fits with creating a stable base. -------------------------------------------------------------------------------- Jamie Somerville, TD Securities - Analyst [26] -------------------------------------------------------------------------------- That's actually a good lead-in to my next question about your base decline rate guidance. You are saying that 20% to 25% you are expecting going into 2016 is with the benefit of EOR support. But is it fair to say that that's not including EOR support from pilots that could contribute new production or growing production, that is simply including the benefit of relatively stable production from the existing producing EOR pilots? -------------------------------------------------------------------------------- Suneel Gupta, Bankers Petroleum Ltd. - EVP and COO [27] -------------------------------------------------------------------------------- No, it's -- the better way to look at it, Jamie, is when we see a response from the patterns, they go up to a plateau rate. The question we have on our mind, though, is how long does that plateau last? What we're assuming is -- and based on the profiles that we model, it stays at that plateau for about maybe 12 months on average. And if it stays to 12 months, then once those patterns start declining, you see the response from the new patterns that were converted a year earlier. So there's kind of -- you are declining on some of the patterns, but then you are also increasing on other patterns and that's what stabilizes that wedge. So it's all about the pace. So as long as we are doing the continued program of 20 to 30 conversions per year, we should see a nice, stable wedge. But just the character of it, we don't expect that it will hit a plateau and stay there for five years or a long period of time. It's going to be probably in the range of a year to two years. We don't know the exact number yet, no. It will be a little bit more clear as we get more patterns that go through that plateau. So that's essentially what's happening in our model is that some of the patterns that were converted earlier -- like the 2013 patterns, a lot of those are on decline now. They've come off the plateau. And so the 2014 patterns are still at the plateau. So it's a trade-off. -------------------------------------------------------------------------------- Jamie Somerville, TD Securities - Analyst [28] -------------------------------------------------------------------------------- Okay. Thank you. -------------------------------------------------------------------------------- Operator [29] -------------------------------------------------------------------------------- (Operator Instructions) Isuru Sen, Radiant Value. -------------------------------------------------------------------------------- Isuru Seneviratne, Radiant Value Management, LLC - Analyst [30] -------------------------------------------------------------------------------- Thank you for the update. Just -- I think most of my questions were answered previously. But one idea that -- in terms of coming up with guidance of CapEx for next year, obviously the environment is pretty fluid. Do you have a sense of when you'd do that? -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [31] -------------------------------------------------------------------------------- Are you just asking about what we think for next year obviously? This is David; thanks for the question. I think we have -- we will be rolling off -- and part of the reason why we opened up a discussion a little bit about hedging strategy for this year is obviously we had a fairly effective hedge this year on 6,000 barrels a day at $80 Brent. And so that hedge value is, plus or minus simple rounding factors, probably $50 million of operating cash for the year. We poured our budget this year about $153 million. I think we are right on target to spend that. But I think when we go into next year, part of the advantage is -- obviously some of our operating costs have come down. That frees up a little bit more cash, as well as the individual wells are going to be less expensive into next year. But we expect a budget that is going to be in a post-hedge world probably representative of the value of that hedge. So we will talk about this in December, but I think we are looking for a number that's probably closer to $100 million of reinvestment revenue, $150 million, unless we see significant changes in pricing for next year. Because right now, we are still thinking it will be a number with a low five in the front of it as expectations for pricing for fiscal year 2016. But we are watching it closely and certainly making decisions around what we think the second half of next year works, but that's ballpark. -------------------------------------------------------------------------------- Isuru Seneviratne, Radiant Value Management, LLC - Analyst [32] -------------------------------------------------------------------------------- Okay. And you haven't really provisioned for any of the tax expenses if the arbitration goes against you. Is that a concern? Would that cut into CapEx or -- again, that's -- not assuming that's going happened, but is there provisioning for that are how do you think of that if that happens? -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [33] -------------------------------------------------------------------------------- So I will speak to my view of the process itself, then I guess I can talk to -- I will turn it over to Doug if he has any other comments around that. I think our view obviously is we're now moving into a process where we don't anticipate a significant provision, but that is certainly Doug's perspective as well. I think the terms of reference being signed is an important step in that over the next couple of months, we will have -- it will probably -- it will be one of the big four accounting firms. Go and look at cost expenses of the year in question and determine whether they are applicable for petroleum costs. We don't anticipate that there will be a significant concern coming out of this, in that we are very positive about the way the audit approach is going to work. We're very positive about the terms of reference as a way to resolve that dispute. And there's been a tremendous cooperation between ourselves and the agency as well as the Minister of Energy about how this should work. So I don't expect there will be anything other then we will just update you in a couple of months as to the process. But we've been very -- we've been very positive -- we have a very positive outlook in terms of how the process is working, going through and selecting the auditor as well as then just the review of the auditing books. So I don't know, Doug. Is there anything else you want ask as it relates to a specific provision? -------------------------------------------------------------------------------- Doug Urch, Bankers Petroleum Ltd. - EVP, Finance and CFO [34] -------------------------------------------------------------------------------- Yes, I guess with respect to profits tax as we see it coming forward in our model, we do provide a deferred tax liability in our balance sheet. So to the extent that the cost recovery audit -- it goes through this process, as we expect, and costs are allowed, as have been previously proved and spent in prior years, that this -- these existing tax assessment that we mentioned in the press release will be reduced. And we'll then just work off the profit tax provision that we've made in our financial statements to date. -------------------------------------------------------------------------------- Isuru Seneviratne, Radiant Value Management, LLC - Analyst [35] -------------------------------------------------------------------------------- Great. Thanks a lot, guys. Keep up good [year]. -------------------------------------------------------------------------------- Operator [36] -------------------------------------------------------------------------------- There are no further questions at this time. Mr. French, I turn the call back over to you. -------------------------------------------------------------------------------- David French, Bankers Petroleum Ltd. - President and CEO [37] -------------------------------------------------------------------------------- All right. Thanks, guys. I can say that all the things that we've done over the last three years continue to bear fruit. Doing more with less makes a huge difference as prices have fallen, but we look to be a very powerful engine for growth with even robust price improvements. I have nothing but optimism around where the business now and where it's headed. Our business is ready and capable to deliver into next year and well beyond. I thank everybody for participating on the call today. And by the way, I want to offer my congratulations and good luck to the Toronto Blue Jays. It's a pretty exciting time for baseball. I wish everyone well and have a great day. -------------------------------------------------------------------------------- Operator [38] -------------------------------------------------------------------------------- This concludes today's conference call. You may now disconnect.
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