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Executives

John Wright – President and CEO

Peter Scott – SVP and CFO

Rene LaPrade – SVP, Operations

Tim Sweeney - General Counsel.

Analysts

Patrick O'Rourke - Stifel Nicolaus

Brian Kristjansen - Canaccord Genuity

Ed Irvin - Wells Fargo

Petrobakken Energy (PBKEF.PK) Q3 2012 Earnings Call November 8, 2012 11:00 AM ET

Operator

Good morning, ladies and gentlemen, and thank you for standing by. My name is [Sequiline] and I will be your conference operator today. At this time, I would like to welcome everyone to PetroBakken’s third quarter results conference call. All lines are currently on mute to prevent any background noise.

I would like to remind you that this conference call is being recorded today and is also being webcast on PetroBakken’s website. After the speakers’ remarks, there will be a question-and-answer session. If you have dialed into the call and would like to ask a question, you will have an opportunity at that time. We will also be taking questions for those listening to the webcast. To submit your question, simply click on the link entitled “ask a question” at any time during this conference call.

I would now like to turn the call over to Mr. John Wright, President and Chief Executive Officer. Please go ahead, Mr. Wright.

John Wright

Thank you, Sequiline and good morning everyone. I would like to welcome everyone to our third quarter 2012 investor conference call. Today I am joined by Peter Scott, our Senior Vice President and Chief Financial Officer; Rene LaPrade, our Senior Vice President-Operations; and Tim Sweeney, our General Counsel.

The agenda for this morning’s call will consist of a discussion of our third quarter financial and operational highlights as well as peek into our fourth quarter and the year to come. At the conclusion of this presentation, we’ll open the call up for questions and answers.

We would like to caution everyone that information provided during this conference call constitutes forward-looking information. Specifically, forward-looking statements will be made relating to financial results, results from operations, and the timing of certain projects. Actual results achieved during the forecast period may vary as a result of numerous risks, uncertainties and other factors.

At this time I will turn the call over to Rene LaPrade for a discussion of our third quarter operational results.

Rene LaPrade

Thank you, John. Typical for us we are very busy operationally in the second half of the year and 2012 was following true to form. Through our focused effort, we are executing our capital plan and the results forthcoming. In early November, our production based on field estimates is at 45,000 boe per day. This is an increase of nearly 6000 boes per day over the September average of 39,200 boe per day.

Since the end of the third quarter, our operations are continuing at a very strong pace. We currently have 17 drilling rigs, 6 frac spreads and 13 completion service rigs working in the field. Since the end of the quarter, we have drilled 41 net wells and about 31 net wells on production, with a current inventory of 53 wells readying to be completed or brought on production. From now until the end of the year, we will drill another 42 net wells and bring 74 net wells on to production. With this activity our total drill count for the fourth quarter will be 83 net wells with 105 net wells coming on to production in the fourth quarter.

We expect to complete our battery and gathering system expansion in our Brazeau area of West Pembina by the end of November which will significantly reduce current well restriction, result in reduced trucking expenses and fewer production interruptions and will add at least another 2500 boes a day to our production base by the end of November or as of November.

With current production levels of 45,000 boes a day, another 74 net wells to bring on production and the Brazeau battery completion, we’re well on our way to achieving our 2012 exit production rate of 52,000 to 56,000 boes per day. Field activity is progressing well and we are looking to keep the momentum going by accelerating some first half 2013 capital into November and December of this year. As a result, we are updating our forecast to 2012 capital expenditures to $975 million, prior to disposition, $340 million after disposition. The increase is a result of three primary factors: one, a successful land acquisition strategy establishing a potential new resource play; two, advancing first quarter 2013 billings to take advantage of available services and keeping high quality crews working for us and three, a decision to advance facility and optimization capital during the winter to minimize mobilization expenses and set us up for continued execution in Q1 2013. Unlike this year when we slowed activity down as we entered Q1.

We continue on a path to capture more resource. At land sales, we acquired acreage in our existing plays and 218 net sections in a potential new resource play and we have exposed capital to farm-in on an existing play. In total we have spent about $25 million more than the original capital plan on these activities.

On the drilling front, we will drill another 15 net wells in the Cardium, partially offset by a decrease of 10 net wells in the Bakken which were Mississippian location. Given the cost differences in these wells, we will spend about $35 million in 2012 and the timing of the acceleration will not impact 2012 production but certainly improves first half 2013 production compared to previous plans.

And finally, the acceleration of capital from Q1 2013 for facilities and optimization with the spending of $30 million in November and December for infrastructure in southeast Saskatchewan will allow for production increases as well as help reduce downtime impact during spring breakdown. With respect to the third quarter we averaged 38,500 boes per day. In the Bakken, third quarter production averaged 15,800 boes per day, an increase of 6% over the second quarter as the majority of the shut-in production related to spring breakup conditions were restrored. In the Cardium, third quarter production averaged 14,700 boes per a day, a decrease of 7% from the second quarter due to a delay start to our second half capital program and restricted production and downtime resulting from routine maintenance of individual wells and facilities.

Our southeast Saskatchewan business unit continues to provide a low-decline light oil rich production base. Production averaged 5400 boes per day in the third quarter of 2012. In Alberta, BC unit we averaged 2600 (ph) boe per day. Net capital expenditures for 2012 are estimated to be $340 million, less 420 boes of disposition since late December 2011 for proceeds of $650 million, $635 million of which will impact 2012.

I will now turn the call over to Peter Scott to provide an update on our third quarter financial results.

Peter Scott

Thanks Rene and good morning everybody. As Rene mentioned, our third quarter production was 38,500 boes per day, and comparing that to the second quarter it was relatively flat as we mentioned it’s continued to grow and we’re now at 45,000 boes per day.

During the third quarter, we achieved an operating net backs of $45.09 per boe, again that’s flat to the second quarter but it is down 10% compared to the third quarter of last year, mainly due to lower pricing driven by wider crude oil differentials.

Funds flow from operations for the quarter was $122 million or $0.65 per weight average share outstanding, essentially the same as the second quarter. However the year over year decrease was 20% primarily due to the lower net back that I mentioned and higher interest expense associated with terming out our credit facility into the high yield market which generated additional liquidity for us.

To give you an idea of the impact of commodity prices, our realized oil and liquid prices decreased 12% in the quarter compared to a year ago while WTI in Canadian dollar term increased 4%. Oil differentials did improve each month during the quarter as the growth in railing capacity helped alleviate product congestion and in September differentials were slightly narrower than the historical average. October and November differentials continued to look narrow but we do expect them to widen out again due to significant refinery turnarounds occurring late in the fourth quarter and into the first quarter of 2013.

For our planning purposes we continue to use an average of 10% off WTI for differentials to work out for the volatility in the market. Production expenses for the quarter improved on both an absolute and per boe basis compared to a year ago and compared to the second quarter they improved – they decreased by 7% which is expected given that we have come out of the spring breakup season.

Similar to last year, production costs are expected to be decreased throughout the balance of 2012 as we restore and grow production and complete infrastructure which will reduce our oil tracking activity. Capital expenditures before disposition totaled $283 million in the quarter resulting in 82 net wells drilled as Rene mentioned. Capital spending will increase in the fourth quarter as a result of the acceleration of the capital activities that we discussed.

We have maintained our dividend rate throughout 2012 with $0.08 per share per month. Since the start of 2012, we had a DRIP available to investors with the current participation rate of 62% and on our cash basis our dividend represent only 14% of funds flow from operations for the third quarter and we expect our dividend to be maintained. At the end of the quarter, we had approximately $400 million of debt drawn on our credit facility, that has a lending capacity of $1.4 billion plus an accordion feature which would allow us to potentially increase it by another $100 million.

We currently have a $1 billion of available credit under facility, and then we have a diversified debt capital structure with a layered maturity profile which complements the long-term nature of our light oil focused assets. I will now pass the call over to John Wright who will discuss the recently announced reorganization of PetroBakken.

John Wright

Thanks Peter. On October 29 of this year PetroBakken and Petrobank entered into an arrangement agreement that will see Petrobank shareholders receive Petrobank’s proportionate interest in PetroBakken. This reorganization is subject to the approval of shareholders at each of Petrobank and PetroBakken which we expect to receive in mid-December of 2012. If approved, the amount of shares outstanding in PetroBakken will not change. Petrobank shareholders will receive in aggregate a number of new PetroBakken shares equal to the number of PetroBakken shares held by Petrobank immediately prior to reorganization. So to reiterate this reorganization will not result in any changes for the business of PetroBakken or our existing board and senior management.

I also like to make a quick comment regarding our accelerated capital program. As you can tell we will be finishing our 2012 capital program early this year just as we finished our capital program early in 2011, rather than cut back our activity levels we are looking to level load our drilling activity. We want to maintain momentum and reduce downtime related to spring breakup. While this early investment has little impact on 2012, it does set us up nicely for level load our production into the first quarter and first half of 2013.

We’re excited where PetroBakken is today and where we’re going. Our operations are proceeding as expected and production is growing commensurate with our activity as we march towards meeting our production exit rate of 52,000 to 56,000 boe per day. Results in our resource plays continue to deliver and we’ve successfully gained access to new potential resource plays that will provide our shareholders growth for the company well beyond the Bakken, Cardium.

And speaking of shareholders, we eagerly look forward to welcoming to Petrobank shareholders as our direct shareholders and the ownership structure get simplified.

Finally, later today we will post our investor day presentations on our website. These presentations will provide detailed information surrounding our drilling and completion practices, our southern Saskatchewan business units or the cash cow for the company, our Cardium growth plans, the emerging plays that we’re looking at, including a bit of a tease around our new play area. There is also a section on our current AUR activities and the advances we’ve accomplished to date using natural gas injection, and there is an review of our marketing practices with some discussion around some of the rail options that we utilize to maximize to receive the sales price for our product.

That concludes our summary of the third quarter. We now invite any PetroBakken related questions, would ask the Petrobank questions be asked at their conference call next week. I will of course discuss anything related to the spin-out and I would ask the operator to explain how the questioning process will proceed.

Question-and-Answer Session

Operator

(Operator Instructions) We do have a question from the line of Patrick O'Rourke with Stifel Nicolaus.

Patrick O'Rourke - Stifel Nicolaus

Patrick O'Rourke here on behalf of Kurt Molnar. I just have a quick question, looking at the production in the Cardium for the last three sequential quarters, we have seen the gas production rise while the oil production has decreased. Just looking at some context around that as to whether it’s a function of the commodity mix of the new wellbores coming online or is this a function of increasing gas to oil ratio in the legacy wells?

Rene LaPrade

Thanks for the question Patrick. It’s Rene LaPrade here. From our perspective most of the gas that you are seeing increase in the Cardium is a result of gas conservation. In one main case what we're doing is tying in a lot of these wells and as a result you see the production (inaudible) with those increasing. From a standpoint of gas to oil ratios, we don’t see anything – there are areas that are gasier in certain instances like the Brazeau area. And overall if you look at West Pembina and some of the areas that we are pretty confident that we’re producing an oil rich basin, not a gas rich. So a lot of the increase in gas production by ratio is in fact due to these wells actually being tied in gas and conserved.

Operator

We do have a question from the line of Brian Kristjansen from Canaccord Genuity.

Brian Kristjansen - Canaccord Genuity

Hey John, can you break down $100 million with respect to what’s gone to drilling, what’s gone to land, what’s gone specifically on the land to the new land play?

John Wright

I can’t. I think actually Rene has a little note in his prepared remarks there, and I will let him walk through it just so he kept the numbers right on.

Rene LaPrade

Yeah, we’ve brought as far as on the drilling front, we are spending $35 million more in 2012 to accelerate our drilling. And in that pace it’s mostly the movement to Cardium wells offsetting 10 wells that we are going in the Bakken. Those 10 wells in the Bakken were Mississippian locations. So there is $35 million there. There is also $30 million more that we’re spending associated with the acceleration of optimization project and some facility project, infrastructure projects in southeast Saskatchewan. That would be the secondary one and then thirdly, there would be dollars spent in the course of $25 million additional on land and again those lands increase capital spans across farm-ins, some recent acquisitions we’ve done and some deals otherwise deals, associated land deals that we have done here this last quarter.

Brian Kristjansen - Canaccord Genuity

Can we get a number on the 218 or we’ll stay tuned for that one?

John Wright

No, well stay tuned for that one, it’s typical you can imagine Brian, we like to be early in these things. So you can assure that we maintain discipline on in terms of what we pay there.

Brian Kristjansen - Canaccord Genuity

And with respect to maybe this will come out in a teaser in investor day but your intent to drill on the new play in the next six months?

John Wright

Yeah, keep your eyes open for well licenses that it would certainly be our intent to test some ideas but to be clear – none of this stuff has been layered into create a 2013 program. This is 1, 2, 3, 4, 5 years out, it's just part of the continued growth in our inventory base more than anything.

Operator

And our next question comes from the line of Ed Irvin with Wells Fargo.

Ed Irvin - Wells Fargo

My question is what is the average output of these new wells? Is it 100 barrels per day or 200 barrels a day?

John Wright

So average is a tough number, we saw some of our production curves in some of our presentation materials. Cardium wells are typically recovering in the first year 35,000 to 40,000 barrels with some gas associated with that, so that’s an average of around the 100 barrels a day. IP rates are in the 200 to 300 barrel a day range. Bakken wells might IP that high but typically are a little less production in the first year although we do get 30,000 to 35,000 barrels out of one of those wells typically in the first year as well.

Ed Irvin - Wells Fargo

Okay. The reason I am asking is you’ve 45,000 right now, and when you add 2500 with the new area that’s coming on stream, and then we’re going to have 74 net wells, and that’s saying for the specific 4 net wells are close to 100 barrels a day, then we’re going to be way over 52,000.

John Wright

I think we have been trying to say that all along, that’s been a big part of our explanation of the play. And you are right, I would caution everyone who does the math is everything isn’t additive. We’re always fighting declines on our existing base production and we are also fighting a much deeper decline on the wells we brought on yesterday, which of course look at the first day and will decline for the next 30 years. So it's a combination of – we’re running up to down escalator but we’re able to run significantly faster than the escalators going down. So that’s kind of how to look at it.

Ed Irvin - Wells Fargo

Well the other question I had is, it looks like to me that we’re getting way ahead with our drilling versus completion and this looks like this is what – 29 to 30 wells waiting to be completed.

John Wright

Sorry to interrupt – I think what we have is – what we will have by year end is 20 net wells that will launch not beyond on production from our 2012 drilling program. So we’ve got 6 frac spreads working in the field right now which are essentially running really behind the drilling rigs that we have, we have 17 of those running. Of course, what happens with the drilling as it begins to actually tear off now where we have much rigs working through December, those fracs will catch up. Where we sort of get left with is just on the map and basically running into December we will probably end up in the range of having 20 wells. That would be not on production. So I think that’s a pretty small inventory overall.

Ed Irvin - Wells Fargo

How much do you see the frac cost coming down?

John Wright

Fracing, we’ve done I think a – or our completions and drilling group have done a marvellous job of getting their cost aligned, a lot of that is through some innovation. I think we've seen overall costs drop in this quarter somewhere the order of 8% on the completion side. I would expect we will see other our cost initiatives from our drilling and completion people but we are seeing those costs come down I think activity wise in the industry, that's had an effect but I think also some of the innovations in the field that we are utilizing helped.

Ed Irvin - Wells Fargo

Do you see that continuing – in other words, do you think there is a surplus of frac units out there and that’s going to be out in the fourth and first quarter next year?

John Wright

At present, with the gas price the way they are, there is more horsepower available obviously in the field which is an advantage for PetroBakken obviously being oil weighted. I can’t with my crystal ball tell you what’s going to happen into next year but certainly we’re encouraged by what we are seeing certainly this quarter and first quarter 2013.

Ed Irvin - Wells Fargo

Now with all this excess natural gas has (inaudible) –

John Wright

So there were some questions up your warrant, we have some encouraging results that I think we’ve got – we will have posted up on our website as well as our investor day presentation. We are seeing some encouraging results out of the pilots that we do have on at present. And I would encourage everybody to have a look at those presentations on site to make your own at least understanding of it. So it is on the site and will be posted here.

Ed Irvin - Wells Fargo

So you encourage to keep on going?

John Wright

Absolutely. We are seeing some significant results – well not significant but certainly encouraging what we are seeing from injection teams.

Operator

Sir there seems to be no further questions at this time.

John Wright

Okay. Well, we’ve got a number of questions on the webcast. So I am going to ask Tim Sweeney to take us through some of those.

Tim Sweeney

Thanks John. First question comes from Jody Chandler (inaudible). We’re now up to 512 net sections in the new resource plays, given the frac nature of the zones on Duvernay, Montney, Nordegg, Swan Hills, I am curious as to whether we might actually have more drilling locations from these new properties than we do in the Cardium and Bakken combined?

John Wright

I can give you a little depth of insight into our land base and this information will be in the web package that we’re going to be posting for investor day here surrounding our emerging plays. So the concept is that a lot of these new areas we’re chasing we do in fact have rights covering two or three different prospects in one section of land. What’s interesting is we don’t know we have all rate. So we have a total of 512 sections of land in this prospective area that we think is in the oil window and should yield some pretty good long-term drilling inventory for us. Other than that when you stack all the zones and eliminate the rights that we don't have, we actually have slightly more than that, we have 563 effective resource sections where we could drill at least one well in one of our prospective zones.

And kind of in order of intensity and again this is in the investor package under emerging plays, we’ve got about 131 prospective sections in the Duvernay, we have 77 prospective sections in Nordegg, 70 prospective sections in Montney, 67 prospective sections in Beaverhill Lake and then we are not talking about the zone of interest but we then have accumulated our 218 sections land block on – the play that’s next to come – or one of the plays that are next to come and on those we've made an estimate that yeah we probably could see total drilling inventory well in excess of what we've built up in the Cardium and approaching what we were able to accomplish in the Bakken I think but that’s going to take some time for us to derisk and delineate but right now we’re only carrying 125 derisked locations in our drilling inventory at this time.

Tim Sweeney

Thanks John. Another question from Jody Chandler related to emerging plays. The last time you told us that you had quietly accumulated a massive chunk of land (indiscernible) when you cracked the Bakken. That was a big step change in value for shareholders. And can I get the credit about this news or is this too early?

John Wright

Jody, I will tell you, we’re cautiously excited and I think the rewards in some of these assets are going to come over the next number of years, not the next number of quarters. But yeah we’re definitely excited, and let’s be really clear, owning the resource is the key to our long-term growth because once we have the resource under our belts in our name, as technology improves, gas prices change, as our ability to get more and more over ground changes, we get capture more and more of resource. So owning the real estate has always been step one for us. And yes, we are excited.

Tim Sweeney

Next question comes from Rafael Casio. Is it possible to know why the split of PetroBakken and Petrobank was done one year sooner?

John Wright

I think when you mentioned one year sooner, you say this is not being done at the end of 2013. And just to be clear, our guidance has always been that we were going to -- we being Petrobank, were going to try and accomplish this distribution as soon as possible but at the latest we didn't think it would take us any longer than the end of 2013. The goal of Petrobank was always to unlock the value for the Petrobank shareholders in as efficient manner and as quicker manner as possible and I think we’ve been able to achieve that. We’re very happy with the structure that we’ve come up here that we think is a win-win on both side and we look forward to both simplifying PetroBakken’s ownership structure but also creating two separate focused companies with their respective shareholder base.

Tim Sweeney

Another question from Rafael, (inaudible) new land acquired?

John Wright

I think we have narrowed this down to Alberta and we will leave at that for now.

Tim Sweeney

Our next question comes from Brian McDermott, for Peter, will the increase flow to PetroBakken’s shares cause it to be included in any share price in this but it is not already included in?

Peter Scott

Thanks Brian. No, I don’t think there will be any changes to that. There will likely be a little bit of rebalancing that, I’d expect to happen through the indexes that when they do that.

Tim Sweeney

Another question for you from Stephen Gitz. How does the reorganization impact the senior note holders structural position and subsidiary guarantees?

Peter Scott

There is no change to that, everything is based of that, of course also the way we structure the transaction (inaudible) there has been no change at all.

Tim Sweeney

Next question comes from Chris Golf. Previously stated the leverage target of 2 times, at this level at the end of the third quarter – the next question is from Chris Golf for Peter Scott. How do you expect to finance the upcoming convert to 30 and sub-13 CapEx spending?

Peter Scott

Thanks Chris. So we have ample liquidity on our credit facility. So we would be able to draw on that, if there was any (technical difficulty) put to us on a convert. Obviously as we stated in the past we look to maintain liquidity, we would look for opportunity to be able to term that out in the market at the appropriate time. So if there is no issue with that, being able to deal with anything complex.

Tim Sweeney

And the second part of the question from Chris Golf. Please state the leverage target of 2 times (technical difficulty)

Peter Scott

Yeah, that is our target and we also say this from time to time we may bounce above that. So we don’t want to run sustainably there. I do expect EBITDA growth in 2013 with the plans that we’re currently working on and the with outlining to the marketplace in the coming months here, and with that, I do expect us to have improvement.

Tim Sweeney

A question from Peter Moore for John. Will there be savings in the mid-securities before they begin trading the regular way on closing the reorganization (ph)?

John Wright

I may redirect that question to Tim, our general counsel, let him answer that.

Tim Sweeney

Thanks John. I believe that there will be a – we will post information on that as it becomes available. We’re on that market at the moment.

Operator

There seems to be no further questions at this time. (Operator Instructions)

John Wright

Thanks for that Sequiline. We haven’t actually changed our orientation but there is bit of a whiteout rolling through Calgary right now. So perhaps there are some blizzard conditions on the phone line.

Operator

And we do have a question too from the line of Chris Golf from Shankman (ph).

Unidentified Analyst

I have one additional question, for ’13 CapEx I know that you haven’t released that guidance but just with the point forward of some of that spending to $100 million, directionally would you assume that ’13 spending would be kind of in line or down from ’12 levels because of that pull-forward of spending or can I not really make that kind of reference yet?

John Wright

Thanks Chris. I think you could expect that because we're pulling forward in spending, you would see a little bit lower spending in 2013 as a result of that. So again we haven’t outlined those plans in detail, that’s just the general comment around that. As we’re working through those plans and finalizing them we will advise the market accordingly.

Unidentified Analyst

And then just a general on some costs, I know from a lot of the U.S. service companies are experiencing a lot of margin declines, are you seeing that in your cost bases, would you expect year-over-year in the fourth quarter at least that you would benefit somewhat from lower cost relative to the prior year at least?

Rene LaPrade

This is Rene LaPrade. Thanks for the question. Yes, I think we will see some cost efficiency, there is obviously for us, there is economies of scale which helps us on a cost basis. But there is for the fact that industry is on the gas side certainly less active – we’re taking advantage of that. I think that's a big part of our strategy here is actually drilling in these periods of time where a) it’s accessible and we are a winter driller, and number two, the inactivity in the market gives an advantage on cost. So I would expect we would see some further reduction in costs. I think we made some inroads there already and we will look to continue to do so. I am not sure what we will see in going into the second half of 2013 whether that will change there, lot of commodity prices will make that, will determine that.

Operator

And our next question comes from the line of Bill Manumit who is a private investor.

Unidentified Analyst

I was wondering about the gas injection project in Bakken and perhaps you could give some information on how many injectors there are and voidage replacement ratio you’re getting and what you might be doing to protect yourself on the long-term price of your gas supply?

Rene LaPrade

Rene LaPrade here, thanks for the question. I can certainly answer the first part of it and is we have three gas pilots injecting at present. One is a very – it’s more of an experiment with two other pilots that are two pilots. Those two pilots we’re seeing some very encouraging results. In other words, we are seeing some reaction on the declines that we’re seeing on the oil rates in the offset wells. So we are seeing again some communication in a good sense from a standpoint to represurring. Our early days on as far as what is replacement, we are not at that point. Where we are working at a voidage replacement above 1.0 but we will be moving towards that here as we begin to ramp up injection.

Some of these pilot things, we are doing a lot of reservoir simulation work in determining some characteristics of the reservoir. So we’re taking this sort of in a -- the strategy is to take this in and look at the reservoir and then begin ramping up on a voidage replacement basis. So I would expect that we would be looking at replacement – voidage replacement ratio greater than one here in the near year.

John Wright

Bill, maybe I could just – it’s John Wright, I can answer the last part of your question about gas price protection. I think one of the beauties of using natural gas as an injection fluid is a) we get it all back, or most of it back, and b) we can stock to buy, we don't talk about it much. In fact, I don’t even think we have an appendix about it anymore but we have a very extensive inventory of natural gas opportunities in the company, by the nature of the rougher inventory they never make it on to our A list or B list. So we don't drill them but they are always there and if we ever have to self supply that, I think we’re very well set up for that. And the beauty of the gas going in at the low price as it comes out later the higher price we kind of win on that basis too. So there is some them gas storage implications for this as well.

Unidentified Analyst

I was more concerned about the gas going in at the high price.

John Wright

Yeah, that’s certainly not the case today, and I hope maybe I wasn’t fair. If we end up having to self-supply high prices low price is just a transfer price mechanism for us on our balance sheet. It’s the cost that we neither get the benefit for nor have the expense for some sort of our own supply with the exception of the royalty component that we pay our own gas over to them. So I think we’re pretty well hedged for that not unlike some of the major oil sands players who have a natural gas arm to self-supply their own natural gas.

Operator

And sir, I do not see any further questions at this time.

John Wright

Well, thank you Sequiline and thank you everyone who joined us today. Again we look forward to providing further update as we rush to get the ball over the goal line here. We are running at a pretty high rate. We’re kind of having a lot of fun out in the field and we’re getting some pretty good wells coming on stream here. So we look forward to updating you and encourage everyone to visit our website and check out those presentations.

Operator

Ladies and gentlemen, that does conclude the conference call today. We thank you for your participation and ask that you please disconnect your lines.

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