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Executives

Garth A. Johnson – Chief Executive Officer

Drew Cadenhead – Chief Operating Officer

Analysts

David Phung – Credit Suisse

Darrell Bishop – National Bank Financial

David J. Goodman – Dundee Securities Ltd.

TAG Oil Ltd. (OTCQX:TAOIF) F3Q13 Earnings Call February 19, 2013 2:00 PM ET

Operator

Welcome to the TAG Oil Q3 2013 Fiscal Year Results Conference Call. My name is Tawanda, and I will be your operator today. During the presentation, all participants will be in a listen-only mode. After the speakers’ remark, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded.

Before we begin, the Company has asked me to read the following statement. Today’s presentation by management contains forward-looking statements within the meaning of applicable security laws. These forward-looking statements represent the Company’s present expectations or belief concerning future event. The Company cautions that such statements are necessarily based on certain assumptions, which are subject to risk and uncertainties which could cause actual results to differ materially from those indicated today.

These risks and uncertainties include but are not limited to risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, volatility of commodity prices, and precision of reserved estimates, environmental risk, competition from other producers, availability of financing and changes in the regulatory and taxation environment.

Actual results may vary materially from the information provided during this presentation, and there is no representation by the Company that the actual results realized in the future will be the same in whole or in part as those presented today.

Further information on these risk factors are also set forth in filings that the company and its independent evaluator have made, including the Company’s most recently filed reports in Canada under National Instrument 51-101, which can be found under the Company’s SEDAR profile at www.sedar.com.

Also the Company undertakes no obligation except as otherwise required by law, to update these forward-looking statements in the event that management beliefs, estimates, or opinions or other factors change.

I would now like to hand the call over to the host for today’s call, Mr. Garth Johnson, Chief Executive Officer and Director. Please proceed, sir.

Garth A. Johnson

Thank you very much. Welcome everyone for TAG’s first conference call to discuss the Q3 results of fiscal 2013.

So far this year, we’ve had a lot of success following on our calendar 2012 drilling program. We’ve initiated our 2013 drilling program, which we’ve recently news released. At this point in time, TAG is proud to say, we’ve had some fantastic success drilling. We’ve taken on an aggressive infrastructure program, that’s required some time and patience and a serious capital investment by our team and of course by TAG and our shareholders. That infrastructure program is on time and on budget, and is going really, really well.

We do intend to have the plant built by the end of the March, which will be fantastic. We’ll be able to produce, sell and market all our oil and gas, which previously we weren’t in a position to do. We’re also – be able to market and process third-party gas if and when we’re requested to.

We’re financially strong. We’ve had again a fantastic year of drilling. We’ve got currently $72 million in cash. We’ve got nice cash flow right now. That cash flow is picking up pretty dramatically after March 31, when the plant at Cheal is finished. We own 100% of all our infrastructure, approximately $60 million worth of infrastructure between our Cheal and Sidewinder facilities on our pipeline. And importantly, we do not have any other contracted output or processing through the plant right now, so it’s 100% owned and controlled infrastructure.

We’ve got a great land position in Taranaki with low-risk drilling opportunities for the next two to three years, probably a little bit more than 2 to 3 years. We’ve got mid-risk prospects that house the potential to increase our cash flow and production reserves dramatically in our deeper plains certainly referred to as Cardiff, Heatseeker and Hellfire. And then we’ve got of course our East Coast and Canterbury plays.

East Coast we intent to start drilling in April of 2013. We do have consent to drill two wells in our Southern permit, which we’re very excited to have completed. And we’ve got a busy year ahead of us.

I’ll go through a quick summary of the Q3 results, then I’ll introduce through Cadenhead, our COO to run us through an operational and infrastructural update, and then we’ll have a Q&A session shortly after.

For Q3 2013, which is the period ended December 31, 2012 we recorded revenues of $10.85 million for the quarter, $32.29 million for the nine months till December 31. We had net income of $638,000 for the three months and just over $5 million for the nine months. Net income before stock compensation, which is a non-cash expense was $2.7 million for the quarter and $9.4 million for the nine months period.

Our cash flow from operations was 140,000, well that included a timing difference from basically when we produced and delivered our oil to when it was actually paid for $4 million. We sill have a good cash flow from operations. For the nine-month period that was $15.12 million in cash flow from operations.

Production for the quarter was 1,727 BOEs with 55:45 oil to gas. And we had a very strong balance sheet at quarter-end; a balance sheet that’s gotten stronger after December 31, resulting from the Apache settlement that we announced. That resulted in the cash balance of about $72 million, so that includes a lump-sum payment from Apache.

Today, we’ve got about 59,600,000 shares outstanding, that includes just over 212,000 shares that we bought back in our normal course issuer bid, average price that we’ve bought our shares back was about $5.13.

At the quarter end, we had just about $63 million in cash. We do not have any debt, and our working capital was $68 million, again that’s increased to just around $72 million in cash on hand with the lump-sum payment from Apache.

During the quarter, we spent just about $21 million in capital expenditures, primarily that’s related to Cheal infrastructure and some drilling costs. For the nine-months, we’ve spent $54.29 million, $4 million of that was on exploration properties in the East Coast and Canterbury, the balance was spent in development, drilling and infrastructure.

On a go-forward basis, we have news released our intended program, consisting of minimum 13 wells per calendar 2013, that’s likely going to move up to 14 wells. I can’t believe we’re going to be drilling our Sidewinder-A7 well, after Sidewinder-A6. Drew can talk us through that shortly.

We also have the opportunity based on success to add a few more wells. We could possibly drill an additional two or three Taranaki wells, based on drilling success being continued.

Capital program for that Taranaki drilling program is approximately $37 million to $45 million, so a minimum of $37 million based on success up to $45 million. That includes $10 million that will be spent by our new joint venture partner on certain of our Taranaki drilling permits.

In addition, we’ll drill a couple of wells on the East Coast. Most likely we’ll have one initially – our first well would be in April in our southern permit, referred to as PEP 38349 followed by one in the North permit, now 38348.

Dry hole costs for those wells to be approximately $9.5 million. On a success case, we would add another $5 million to complete and test those wells. The total capital program including all drilling would be about $47 million, upwards of $50 million to $55 million if things continue on with the success we’ve had over the last couple of years.

We have no requirement to dilute our shareholders. We can pay for this program primarily using cash flow, but we’ll be ramping up in April. And we do we have the Apache settlement cash set aside that will pay for the East Coast program.

So importantly we’ve fighted ourselves on minimizing delusion and I think that strategy has worked well. Really our business plan has been to drill the lowest risk prospects that we had initially. Increased our cash flow, get our infrastructure underway, start taking some slightly riskier shots at deeper prospects like Cardiff, and of course our big upside play on East Coast, while we also developed new frontier acreages such as our million acres on the Canterbury basin as well.

That’s pretty much it from me. I’ll hand the meeting over to our Chief Operating Officer, Drew Cadenhead to walk us through an operations update, and maybe he would touch on the infrastructure progress as well. Drew?

Drew Cadenhead

Okay. Yeah, thanks guys. I’d just apologize to everyone first, here I’ve got a bit of a scratchy throat, so if I have to stop or cough for a second, please forgive me for that. Again just to clarify to everyone on line, my name is Drew Cadenhead, I am TAG’s Chief Operating Officer. I am calling in from New Plymouth this morning on the North Island of New Zealand where I oversee all of TAG’s operations.

As most of you know, we focus exclusively on New Zealand. We’re by far the most active operator in this country. And as Garth just eluded to earlier, our game plan has been pretty consistent over the past five years and that was to focus on the shallow, onshore oil prone play. Our goal is to build up our reserve basin, our cash flow, drilling these exploration wells. They are not less than 2000 meters, they cost us all around $2 million to drill.

And we really said to ourselves not until we’re happy that we had a solid base of long reserve life index wells and we are cash flow, more free cash flow every month than we could spend, would we begin expanding our portfolio outside that’s sort of bread and butter shallow oil plain. Now that’s where we find TAG today. We are in the same dual position where we can start to spread all pass that and that’s probably why we are – well, I am personally more excited than I have ever been for the next couple of years coming up at TAG.

We’ve had tremendous success, as Garth mentioned with the drill bit over the past two years. We drilled over 20 successful wells in a row now. We’ve drilled past the capacity of our own infrastructure. We are already cash flowing more than we can spend drilling anyways, and as Garth mentioned, we still have $72 million cash in the bank.

Now we are about to commission a material expansion of our oil facility at Cheal. We are going to fire up a brand new gas plant at Cheal. And as we mentioned earlier for the first time in our corporate history, we will become completely unrestrained in producing, in processing, in transporting and in marketing all of our oil and gas. In short, which we’ve basically told all the third parties that we used to depend on to produce our oil and gas, we no longer need them. And by the way, here is our number, in case you need us.

As I mentioned, 2013 is going to be another record setter for TAG operations. We’ll drill more wells in the 12 month period than we ever have before. We will commission our new facilities by the end of March that will completely restrain our production capabilities. We’ll expand our exploration portfolio into deeper, higher oil targets and we will drill the first well ever of targeting that unconventional source-rock play in the East Coast Basin.

We’ll all just take a minute here and give a bit more detail about our year coming up. While we have already started drilling, we are off the guns already with the drilling of Sidewinder-A5, another successful well for us. I am actually going to take a minute and talk about Sidewinder, before we get into Cheal, our primary property, but Sidewinder as most of you know is the shallow low pressure gas play for TAG. We think there are maybe some out there as well, but for now we’re just focusing on the gas.

We committed to building our Sidewinder gas plant after only drilling and testing our first well Sidewinder-A1. We always knew that these were shallow, low-pressure, but very high deliverability gas wells. We have 3D seismic covering our 8,000 acre permit. We can see, it looks just like Cheal. There’s lots of small reservoirs covering a very large area. We want to keep our gas plant flowing at 5 million to 10 million cubic feet a day, that’s sort of it’s designed for. We knew that we need to keep drilling new wells, these shallow wells they are going to drain off quickly.

So that was the plan, unfortunately we got little bit sucker punched I guess by one radical landowner is the area, who effectively caused a suspension of our drilling activities for pretty much a year, the past year through the court system here. Now we eventually won that appeal, as we knew we would, we will always win these appeals. That we will never be stopped from drilling by land owners here, the crowned admiral back in this country has legislature allowing us access to them, the people can’t stall us and that’s really what we’ve seen in the Sidewinder.

That year delay in drilling saw our rates drop from $8 million to $10 million that we started off, but down to about $2 million to $3 million a day, where we are now. That’s a drop of over 1000 BOE’s a day, that we wouldn’t have liked to seen happen. We would have liked to continue drilling and filling in and keeping our plant full but this does happen.

So that’s over, now we are back drilling I guess, Sidewinder-A5 looks good, Sidewinder-A6 is underway already, we plan to drill A7 as Garth said and well I’ve got on Garth on line A8, looking like a good one too Garth. So we may move straight to that if we keep having good luck before we move that rig off the site.

So hopefully we’re back up where we want to be within a couple of months here at Sidewinder. Later in 2013, possibly 2014, we’ll bring a big rig into Sidewinder and we’ll test that deeper Hellfire prospect that Garth mentioned earlier. And I’m going to talk more about that in a minute, but that’s really a rap up of Sidewinder. Next I’d like to move on and talk a little bit about Cheal.

Of course, our biggest news at Cheal is all about infrastructure. Within six weeks, we will be commissioning our expanded oil plant. We will be processing and selling all our own gas through our new gas plants and pipeline system, we will be bringing on all the new wells we’ve discovered in the last couple of years at the same time for the first time ever, and we certainly understand it’s very frustrating for some investors to keep hearing about TAG’s potential flow rates, and what we have behind in pipe. But we’re about to find out whether it all looks like together for the first time.

Now I can’t tell you exactly, what the BOEs per day will be, the day we fire up the new equipment up and obviously there is going to be some fine tuning to get the new plant up to maximum efficiency. What I can tell you is when I make a list of every well we have capable of production, and I list each wells tested capabilities, that total is in excess of 5,000 BOEs a day. And our challenge at TAG, we’ll be getting every well flowing at its maximum capacity.

Remember we’re heavily oil weighted at Cheal. Every oil well is artificially lifted with various types of pumps. So it’s not just a matter of cranking open all the valves and the way she goes. Wells continuously need tuning up, they need wax cutting, they need the pump suggested et cetera.

Well undoubtedly need to optimize each well to match our new infrastructure. Of course we remodeled all this before we committed to this $30 million or $40 million project, but the one thing, our experienced team knows for sure down here, and that models are always wrong. Once we have this plant up and running, we’re going to discover some bottlenecks in places that modeling list we will find some wells, it’s climbing faster than we thought, others might outperform our expectations.

I guess what I am giving out here is, I am not going to make any long-term guidance forecast on this call today. So give us a couple of months, whether to get this plant up and running. Let’s get it optimized, all our existing wells optimized, bring on the new wells in the meantime. Our goal is to maximize our production potential over the longer-term through this plant.

Now whether that’s a 4,000 BOEs a day or 5,000 BOEs a day or 6,000 BOEs a day, I honestly can’t predict that right now. What I can say is, given the operational limitations that we face here in New Zealand, i.e. rig availability, service availability; it is not likely that we’re going to double or triple our present capabilities that I’ve been mentioning, strictly by drilling the shallow play.

Our goal is to maintain the types of production rates I have mentioned, with the many years of shallow drilling we have in front of us. We aim to minimize the decline by drilling 10 or 15 shallow wells a year, for years to come, and we already have that prospect bang in our present portfolio, so we are set to do that as Garth said probably three, four, five years out, we’ve got that number of opportunities ready to drill out.

But to take that next big step in production levels to double or triple where we are now, we need to start drilling higher reward target here at TAG, and this is the year that we start doing that. Before I get into those let me summarize, our shallow program at Cheal for you for this year.

This year’s drilling program is all about our successful land block offer to New Zealand government in December. We did very aggressively and we were successful in being awarded all four blocks that we wanted; these blocks offer was critical for us, the land surround are offset to our Cheal property. We have proprietary 2D and 3D-seismic covering lands already, we can see dozens of drillable locations ready to go on the lands; this successful award basically set us up for a few more years of continuous drilling as we have been for last two years, and all of its surrounding are 100% owned infrastructure.

We committed to a total of nine shallow wells on the three permits that are directly adjacent to our Cheal permit. We are already well underway in securing land access agreement for the new drilling pads. We’ll soon submit our drilling applications to the local councils. We’ll drill all nine wells with Webster’s Nova-1 rig, which we have rate for first refusal over. We’ll user our Cheal production station as the hub for the new sites, tying back these satellite sites to the hub for oil and gas processing.

Our drilling team continues to shave a few more dollars off our total cost for these shallow wells every time we drill another well. The local service companies have all recognized TAG as sort of the company in Taranaki to [Kapuni], many are increasing their discounts to us based on the volume of work we continue to deliver to them.

Already, our shallow drilling records are unprecedented down here. No one has ever done it like TAG is doing and we are really starting to get our cost down, and starting to appreciate what volume can do for you as far as economics go.

As I said, we are not all about shallow this year, we have three deep gas targets in Taranaki to drill this year as well as our East Coast. So first, let me talk about the Taranaki deep targets.

The first target we are going to drill is called Cardiff. Now Cardiff is an oil well that sits on our Cheal C site. We have drilled four successful shallow wells at our C site, but Cardiff is a whole new ball game for us. Cardiff 1 well was drilled by STOS at Shell Todd Oil Services in 1992 down underneath by 5000 meters depths, so deep tight gas sand play. Three gas condensing zones were encountered in that well, but the sands were low permeability, and that are $1 in Mcf at that time, they walk from the well.

15 years later, another local player, who no longer exist down here tried to re-drill the Cardiff well. They had trouble drilling that, they barged the drilling up, they tried four separate times to re-drill the original well before their paying partner finally closed the bank on them. We ended up basically almost inheriting this prospect when we bought the Cheal permit, which this part of prospect falls within.

The prospect is a tight sand. It’s a prudent resource play, there is gap, this is a big structure full of gas, condensate rich gas, it’s just the tight sand. Our independent reserve analyst, Paul have signed about 215 Bcf at about 13 million barrel of condensate to the prospect. So there is not much doubt that it’s loaded with gas and condensate. All that’s really we’d have to find out if we can get it out, how fast reserves will come out. The wells have been tested, the original wells were tested, one zone tested up to 3 million cubic feet a day, and about 1000 barrels of condensate with that. So they will flow.

Our sea site is now tied into our Cheal production station with our new infrastructure at the A site, where is the home of our brand new gas plant. So just about any flow rates from this deep re-drill will prove economic to us, but there are analog zones in the play trend that have produced up to 30 million cubic feet a day with stimulation from sands identical to these, in other words as well that were drilled that did 2 million, 3 million a day were frac and then did 30 million a day and they are still continuing some of the best wells at Taranaki. Now that’s the kind of reward we are hoping forward this well again; this is how we can leapfrog our production about the sort of steady shallow oil production that we presently enjoy.

We have two other very similar plays we are going to drill after Cardiff. Heatseeker is deep test on one of the new blocks that we’ve just been awarded in the December blocks offer. This prospect is adjacent to the biggest onshore pool in Taranaki, the 1.3 Bcf 65 million barrel Kapuni field. We are only a few miles away from Kapuni again another game changer for TAG.

And finally in Taranaki as we have mentioned before another large deep gas prospect will be drilled right underneath our Sidewinder gas production station. We call this prospect Hellfire. We think it’s probably as big as Cardiff, maybe a little bit bigger. Right on the same trend, we have 3D seismic defining this for a disclosure at about 4000 meters depth.

So in summary, in Taranaki, we are going to drill 14, 15 wells probably this year; three of those are deep high reward type wells. Shallow program is intended to maintain maximum production levels through our newly completed facilities, and we have years of that shallow drilling in front of us already identified here in Taranaki.

We have got a great land picture, 100% control over all the infrastructure we need to produce our hydrocarbons. As many of you know we enjoy premium oil pricing down here, presently over $120 a barrel. We are in the process of finalizing our gas contracts for our new gas coming out of our Cheal gas plant that will see us getting north of $5 an Mcf to start with, and moving up from there. So our cash flow is going to be solid for many years to come. Even if we never drilled another well, fortunately I think what happened down here.

And finally 2013 will also see us test the unconventional source-rock play in the East Coast basin. Now I don’t intend to get into a long discussion here about Apache’s departure from our JV, let’s just leave it at this, but the technical aspects of the play have never looked better.

Our work over the last 18 months with Apache has fine tuned our interpretation, and I personally have never been more excited about this play and, had in we are left with plenty of Apache’s cash to pay for our first wells, and I don’t see the downside here personally. We’re in the final stages of having our well consents approved on the East Coast as Garth mentioned.

We don’t predict any further delays, admittedly, there has been for the last 12 months, but we’re pretty much there now. We plan to move the Nova-1 rig over as soon as we’re done at Sidewinder and we’ll spread our first East Coast wells probably in April. We get to use Apache’s money, but maintain 100% of the play, I don’t see it gets any better than that.

That’s the end of the summary of our operations here for this quarterly conference call. I guess at this point I’ll turn the call back to Garth, the moderator and take it from there.

Question-and-Answer Session

Operator

Thank you (Operator Instructions) In an effort to keep the teleconference relatively brief, we may not be able to get to all callers. However, if we don’t answer your questions, please email them at info@tagoil.com again that’s info@tagoil.com for a response by the Company. (Operator Instructions) Your first question comes from the line of David Phung with Credit Suisse. Please proceed.

David Phung – Credit Suisse

Hey, good morning, guys. First question is production testing, do you think you get the Cheal C4, Sidewinder-A5 and Sidewinder – potentially Sidewinder-A6 production test before fiscal year-end?

Garth A. Johnson

I can answer that, yes. Sidewinder-A5, Sidewinder-A6 of course we have haven’t drilled 6, we’re just drilling it right now; hopefully it’s going to be a successful well as well. We already have Sidewinder-A5, tidy and straight to our plant, so we won’t test it to flair, we will test it straight to production, and we will do that as soon as we move the rig off of Sidewinder-6, which is also like about 10 days from now.

So we just for safety purposes, we don’t want to be flowing Sidewinder-A5 and sitting about 4.5 meters from Sidewinder-A6 well ahead, once you move over to Sidewinder-A7 if the rig actually swings around 180 degrees on the sight everything kind of gets out of the way for us, so we can tie it straight in Sidewinder-A5 and Sidewinder-A6.

C4, I don’t believe we will have that tested, we have a single lift operation over at the C side it’s kind of a temporary operation to get our infrastructure completed, which we have hooked upon C1 right now, so it’s equal to a mini Cheal plant over there, jet pumping system. So I don’t believe we will have C4 tested before fiscal year-end, but Sidewinder-5 and 6 we should have, will have.

David Phung – Credit Suisse

Okay. And maybe Cheal B-8, I don’t recall seeing test result for C, but what’s the well producing right now and how much of restriction do you have on it?

Garth A. Johnson

Right. B-8 is temporary tied in as well, what we have done is we’re primarily tying in all of our wells in all of our sites as part of this infrastructure expansion, so we got a bunch of checks down looking up all the wells, so we got 2 and 3 ace pipe running all over the place, tying together wells of B-8 is tied in together with two other wells at the B side right now, and we don’t have a way of individually testing each well, until we get the permanent piping done to separator, so I can’t actually answer the question of how B-8 is doing other than we switch wells around, and then we see how our daily production changes, but there is a bit of guess there for sure. If I had to take the guess, at B-8 I would say, it’s probably doing somewhere between 150 and 200 barrels a day, but I can’t verify that through a test separator for another few weeks here.

David Phung – Credit Suisse

Okay. And last question here. There was a comment in the press release regarding good production practices and commingling your zones, if you do drill these zones separately to accelerate it, would you add certain points to see something that would give you the comfort that you could commingle the zones in the future?

Garth A. Johnson

The problem I mean commingling is not a big deal in our industry. Obviously the problem with our zones is this waxy oil that we have to deal with. We have this paraffin rich oil here in Taranaki and if we have got zones that are 400 meters apart, and we have to artificially lift them somehow, then if you set your pump to artificially lift the top one, then the bottom one doesn’t get it and if you set it for the bottom one, then the top one doesn’t it get it. So it’s a very difficult to commingle two zones that are 100 meters apart, 10 to 50-60 meters apart, that’s no problem for us and we have a few of those that are going, but the other ones that I am referring to is really two different zones, the Urenui zone and Mt. Messenger zone; they are 400-500 meters apart.

We have been a great example of that as Cheal A-11 where we tested the Mt. Messenger zone first, the deeper zone it floated 350 barrels a day. We plugged that and moved up the Urenui and we tested that and it floated 500 barrels a day. So is it alright just leave the Urenui going, so that Urenui is still going right now, the Mt. Messenger is plugged and sitting below, it’s burn in a hole in our pocket basically if we said no, there is another 350 barrels a day and they are ready to go. The question is and what we alluded to in our press release is, we have to make that decision this year, do we economically justify a new well decided.

If Urenui well is on low decline, our declines are variable depending on our pump rates and that sort of thing, but they are quite low on the Mt. Messenger and Urenui’s hand. If it looks like, it’s going to maintain quite a low decline rate then for sure, let’s get after a new well, and go poke one into the Mt. Messenger right between the well and take the Mt. Messenger 350 barrels at the same time, but at Urenui it looks like it’s going to die off in a year or two, then we’ll just drain that off, that would be our GPP practice, get it down to a rate that uneconomic for us and then bring on the underlining Mt. Messenger.

David Phung – Credit Suisse

Perfect, thanks.

Operator

Your next question comes from the line of Darrell Bishop with National Bank Financial. Please proceed.

Darrell Bishop – National Bank Financial

Hi good morning guys, I’ve got just two quick questions, first everyone recognized that the current producing wells are not really indicative of the future performance because there have been cycled and constrained ahead of the infrastructure, but can you provide any color with respect to what you’re seeing in regards to the performance of these wells, declines of deliverability et cetera, and then second, can you give an overview of the work that you guys have done to build your expectations that these behind pipe volumes, support that ramp up to more that 5000 barrels a day?

Garth A. Johnson

Right, okay I can answer that. I think I got into that a little bit in my operational speech there but, here right now what we’re obviously trying to get all of our wells tied in, and we’ll deliver March 31. Probably the biggest question that we don’t know right now, we won’t know until we do that is how efficiently the plant performs right off the bat, like I said we have modeled everything, we calculated how many barrels we can lift, but whenever you put a significant addition into an existing plant like this net, and the gas plant and the gas stripping stream, three very complex and once we have the plant running we just have to see how it performs and how we’re going to optimize each well.

We have tested each well after we drilled it normally tested two plants just on temporary checks on pipe, and just to get 10 day test off on the well, and those are the numbers, then in the lot of the cases I am talking about when I say – if I make a list of every well we have drilled, and what the flow rate capability of those are, if there is 25 wells that is available for production we’d achieve in Sidewinder probably half of those are actually on stream right now. So I can say okay that well doing 187 barrels and this must do 315 barrels, and that was doing 55 barrels, those are the numbers that go in.

The other half of wells, okay, we tested that for 10 days, at IP it averaged out at some number we trying to give it a sort of an IP-30, IP-60, IP-90 kind of rate that we put on to our list and when I put those numbers down the list, and add them all up, that’s we get to just a little over 5000, about 5100 barrels a day, but again those are individually wells testing with no restrains, no constrains, not going into a new plant and finding weird things happening, so we have those.

I’d certainly rather be in the position of having that list of wells with that total BOEs beside it than having said we’re going to be at 5,000 BOEs a day but actually we’re only at 10% of that right now and we need to find that other 90% in our next few wells.

We have the wells, they add up to that number whether they are going to actually flow at that exact number coming to the plant, maybe better, who knows maybe there’s less restraint, maybe these things all will hang faster, now that we have more available lifting capacity, we can lower our down hold pressures better, this is what we’re hoping for, but we really just won’t know that until we get the thing up and running and get it optimized.

Our engineers will be tuning things up for a couple of months, I’m sure after we get the thing going and we’ll be in a much better position to provide guidance moving forward.

Darrell Bishop – National Bank Financial

Okay. Thanks for that, good luck with the start up.

Garth A. Johnson

Thanks.

Drew Cadenhead

Thank you.

Operator

Your next question comes from the line of David with Dundee Securities. Please proceed.

David J. Goodman – Dundee Securities Ltd.

Yes, good morning everyone, I guess I want to follow up on that last question. Am I hearing essentially some sort of guidance with regard essentially, the number was 5000 BOEs per day for the end of March, am I hearing essentially what appears to be a pragmatic view point offered by yourself Drew, which is essentially – we add up all the wells, we get to something no for 5000, but frankly we’ve just got to see how the plant operates, and we’ve just got to go through a series of fine tuning, and we may get to 5000, we may end up at a number slightly short of that or even better, I mean that’s my summary of it, is it that you’re moving away from this guidance, that you have put up in the last press releases, towards what looks like a far more pragmatic approach to debottlenecking and see what wells will deliver?

Drew Cadenhead

Yes I mean I hope that all of you guys on the line now say yes whatever, give me the number I need to put it into my equation hear to see if I am going to buy or sell, and we’d like to do that, if you have 500 gas wells in southern Alberta you can do that, but when you have 25 oil wells that need pumping and 12 of them you’ve never even had on long-term production for sure, it makes me nervous to give a number and say March 31 we’re going to be doing x, it makes me nervous I am trying to just give the data that we have for you guys and give you a feel for all the data that we have and like I said I’m feeling very comfortable about the numbers we’re talking about because I can see each well and I’ve seen the test of each well and I put them down on a list and add them up, that’s how they got.

So, you’re exactly right I think, your summary is accurate. We actually have facility engineer here, our facilities manager, Ex-VP of AltaGas, in Alberta many of the guys will be familiar with mid stream, this guy is awesome and he is incredibly bullish on the fact that we’re going to have better listing capabilities out of this new plant than we had in the past to artificially lift our oil wells.

So we’ll wait and see how it goes, they said I’m in a much more comfortable position knowing we have the wells ready to go, ready to be tied in, we don’t have to go find the stuff still it’s there we’re going to be drilling past that all this year, we’ll see how they do once we get them hooked up.

David J. Goodman – Dundee Securities Ltd.

Okay, fair enough. And you also made a comment with regard to the, you said that you had something like two to three years drilling inventory of these shallow Miocene prospect, but you also went on saying, I just want to make sure I understood it correctly. You went on to say that your expectation was that the drilling inventory should do no more than, only the way you manage that inventory. If you do no more than hold the line on production, inventory providers stable baseline cash flow will reduce coming from these deeper (inaudible) prospect that you planned to drill. Did I understand you correctly or is that guidance built into the baseline?

Drew Cadenhead

Yeah, I think that’s a good summary as well. We have drilled a couple of wells in the Miocene shallow, Miocene play that were certainly materially larger than what we had expected, B5 and B7 kind of mine which adjusted 1700 barrels a day and 1100 barrels a day respectively, but those wells have declined very quickly and what we have realized, we are very excited about the time and but what we have realized quickly is those were just good ones that paid off in about 15 days and then declined quite early down to sort of normal wells which are 300, 400, 500 barrel day well.

So, given the declines that we have in this pool, which probably on the oil side maybe 25% the first year and 15% to 20% after that. On the gas side little bit faster. The first year obviously maybe 50% in the first year and then 15% to 20% after that. Given those kind of declines and the rate at which we can drill wells, giving our production – what our production forecast is for here, what we are hoping to get, yeah, we would like to think that we can maintain the numbers, 4000, 5000, 6000 barrels a day going through this plan by drilling 10 to 15 wells a year and that’s assuming that we are going to have some dry holes in there and we are not going to have the 100% success rate that we have enjoyed over the last two years here.

Certainly, we are stepping out into little bit bigger exploitation and development areas. We are going to have some dry holes sooner or later, touchwood, may be we won’t, but Garth told me, I am not allowed to, but nonetheless I am pretty sure, we are going to. But I think that’s the plan to try and maintain that stable base, it’s a tremendous cash flow base for a company where we have got 15 guys in our office down here. We don’t have a lot of G&A happening. It’s a tremendous cash base for us to keep on going just by taking shots at some bigger stuff.

David J. Goodman – Dundee Securities Ltd.

Okay, well done. Thanks for your candor. Now let’s just move from the volumes to the pricing. You touched on the improvement in pricing. Now I see for fiscal Q3, you did about $4.79 per mcf of the gas. I think you touched on what you expect or how contracted to sell the gas to the [MGE]. So can you speak to that going from the – essentially what uplifting range and realizations we might expect from the oil and the gas side by virtually completing the infrastructure?

Drew Cadenhead

Right, we are just in the process of finalizing our gas contracts for our new gas coming out of our Cheal plant. Right now, we have not finalized those yet, but I did mention that we are expecting north of $5 of them by that. We can’t give the exact number right now, but it is a new contract for us, so we are cancelling all contracts that we have had with other takers. As I said third parties that were taking our gas and processing it, we are processing ourselves, we are stripping off our own liquids, we are selling spec gas directly to the New Zealand market into Vector’s infrastructure into their trunk infrastructure here in the country and cutting a new deal with those infrastructure owners, the major trunk line owners that are going to be more profitable gas prices than what we are presently being seeing over the last few quarters.

David J. Goodman – Dundee Securities Ltd.

Okay. And if I may, two more questions, fairly quick ones I believe. You referred to the unconstrained capacity you have in the mid-stream, but perhaps you can provide some details? What are the capacity limits of this new infrastructure once you completed it?

Drew Cadenhead

Right. Again the engineers will say, okay this gas plant will do 30 million a day and this pipeline will do 40 million a day, and then you put it all together and you go, ah, well we forgot about this one bottleneck rate here that restrains at 22 million a day. Right now, as I know, it’s 30 million cubic feet a day of gas coming out of our gas plant. We have plenty of pipeline available, we have a four and six inch line heading over to the major trunk lines, but plenty of room there to move, so that’s our gas capability.

Oil is strictly a matter of lifting capability there. Again, we are using a jet pumping system which is a hot water power fluid, jet pumping system, so it’s really not a matter of separation. We can separate I think up to 20,000 barrels a day in our separators in the plant, it’s really a matter of how much we can lift, which is how much power fluid you have and I would say we are not going to have any pumps moving up. We are doubling the oil capacity that we’re at, that we are seeing right now, which is a couple of thousands a barrels a day at Cheal. We have no problems doubling that, perhaps more than that.

David J. Goodman – Dundee Securities Ltd.

Okay. Last upon this; you talked about the possibility of expanding your drilling program beyond 2013. Are there any permit constraints that might – are there any permit constraints to securing new drilling locations that I should think of?

Drew Cadenhead

No. If we go above the numbers that we have quoted in our press release, a couple more. Those are likely going to be a couple more at Sidewinder, which we already have a permit for and we have well approvals for it, an extra four wells at Sidewinder. So if we have a couple more wells, that’s where it’s going to be. So no, there won’t be any permit conditions that might limit how many wells we drill this year.

David J. Goodman – Dundee Securities Ltd.

Okay. Drew. Thank you very much.

Drew Cadenhead

Okay, David.

Operator

I will now like to turn the conference over the Garth Johnson for closing remarks.

Garth A. Johnson

Okay, thank you very much. Just to clarify a couple of things. We do have in regards to the gas price. I think Drew has talked in New Zealand dollars. So our current sales price is New Zealand $5.20 a mcf and I think we are seeing prices going forward relatively similar to that. The big thing to us is a lot of our gas at Cheal that we do produced, we are not selling. So that will be a significant contribution to the financial statements.

In addition, in terms of consents, I think we are good for drilling. However we are currently consenting a number of our sites for our new blocks. We don’t anticipate anything too major in terms of delays, but there is always that opportunity. Drew, do you have anything to add to that?

Drew Cadenhead

Yeah, no, I told that when I was answering the question and just in the last as I said in my opening remarks, our consenting process in going on very well. I am understating it, it’s going on great. We have some – we’ve been meeting with some very friendly people out in the field. There has been some concern here and everywhere in the world about people opposing oil and gas exploration. What we are finding again is that is a very, very small minority of people out there that are creating the stir and as we walk from farm to farm and talk to people they are going, hey good to see you guys, yeah, we are happy to have you here, come on in.

We are not really seeing any problems whatsoever in getting the surface access agreements that we need to get for our new sites. We actually signed up our first two yesterday, which are going to provide us for that first five wells of the nine wells that we need, so we are well on our way already.

Garth A. Johnson

Okay, thanks Drew. So we will sum it all up. Thank you very much for calling in and listening and participating in the Q3 2013 results discussion. Just to refresh, where we’ve had a fantastic 2012, 2013 is going great so far. And I think we are really just getting into a position now to transform TAG again and hopefully our share price will reflect that.

I think what we can honestly say is, we do execute, we have done everything that we have said, we will do. We have invested in infrastructure when needed. Our drilling programs going really well or minimizing dilution. We are financially strong with growing cash flow. We have got continuous drilling on our shallow program. We are moving into the deeper program with Cardiff, Heatseeker and Hellfire and of course, we have got our first well coming in the East Coast where we are targeting our resource play, of that we’ve had independent assessments on 10% of our land base estimating about 12 billion barrels of oil in place there.

Our big challenge I guess is with these wells and maybe Drew can comment real quickly on this in terms of what our desired output is from those wells, but essentially it’s we know the oils there, the kitchen is working, it’s how fast we can we get it out and Drew maybe just to end the call, can you maybe just touch upon what we are looking to compensate the initial two well?

Drew Cadenhead

Initial wells are going to be – they are going to be vertical wells and just about vertical wells, they are going to be stress test, now we are going to cut some core and the zones where we are going to dig, the zones are thick, the source-rock zone is up to 600 meters thick. They are really proof of concept wells, what we would like to see is well, if we see good looking zones on core and on logs where we well the logs, will case the wells, we will proof them, we will have float test and see if we can get to move hydrocarbons in as we have said to many before.

The zones tend to be naturally fractured to start with, there is nice light oil, thunder high pressure. We may well see some significant move along in these initial wells, if not we will certainly move to stimulate these wells in the future. It’s not part of the original plan for our conceding process over there, but we will move to that. So really the proof of concept wells, if we can show more of a hydrocarbons oil moving into our well bores, not from these source rocks we’re going to be on our way.

Garth A. Johnson

Okay, thanks Drew. That’s it for the call. If anyone has any questions, please feel free to give us call or e-mail at info@tagoil.com. Thank you.

Operator

Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect and have a good day.

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