TAG Oil Ltd. (OTCQX:TAOIF) F4Q13 Earnings Conference Call June 28, 2013 4:00 PM ET
Garth E. Johnson – Chief Executive Officer
Drew Cadenhead – Chief Operating Officer
David Phung – Credit Suisse
Good day ladies and gentlemen, and welcome to the TAG Oil Conference Call to discuss TAG’s fiscal year 2014 drilling program as well as fiscal 2013 year-end results. My name is Glen, and I will be your operator for today. During the presentation, all participants will be in a listen-only mode. After the speakers’ remarks, 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 beliefs concerning future events. The Company cautions that such statements are necessarily based on certain assumptions, which are subject to risks 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 risks, 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’s beliefs, estimates or opinions or other factors change.
I would now like to hand the call over to your host for today’s call, Mr. Garth Johnson, Chief Executive Officer of TAG. Please proceed sir.
Garth E. Johnson
Thanks, Glen. Welcome to everyone. Thanks for participating in TAG Oil’s conference call to discuss our fiscal year 2014 work program and to summarize our 2013 results.
Fiscal 2014 is going to be the most active and exciting year TAG had ever experienced, and it’s a year where the drill bit has the potential to transform TAG substantially. We have four types of exploration plays, any of which can have a significant effect on TAG if successful. At this time, I would like to also introduce Drew Cadenhead, TAG’s Chief Operating Officer who is joining us from New Zealand; and Randy Toone is also on the line, TAG Oil’s New Zealand Country Manager.
I’ll discuss TAG’s 2013 fiscal year results, and then I’ll touch briefly on our 2014 drilling program, and I’ll turn it over to Drew to walk us through his thoughts on the program and how we will apply what we learned today to build value for TAG’s shareholders over the coming years.
If any of the participants on today’s call would like more specific details on TAG’s financial statements, MD&A, or oil and gas disclosure, all the information can be found on our website at tagoil.com or on SEDAR.
We ended fiscal-year 2013 in great financial shape with $69 million in cash, $68 million in working capital, and we carry no debt. We have approximately $100 million in 100% owned infrastructure. On that sort of valuation, my personal opinion is, we can support a $6 share price just with those assets leaving a free option on our big plays coming this year that we’ll talk about shortly.
At the current date, after the vast majority of our infrastructure and drilling costs have been paid, we have over $60 million in the bank, we still carry no debt. We’ve established baseline production that generates cash flow from operations on a go-forward basis of approximately $3 million per month.
2013 was the year of infrastructure. It was the year of drilling wells that were essentially included in our 2012 2P reserves that Drew can talk about from what Sproule assessed in 2012, and we recorded revenue of $44.5 million, up from $42.9 million last year. We recorded cash flow from operations of just over $34 million compared to $15.6 million last year, and we reported net income of just over $5 million or $10.7 million before non-cash deduction for stock based compensation.
I did have an e-mail request come in from a shareholder requesting how much more stock option compensation we have on a go-forward basis, and just to answer that question early on. I think there is about $2 million left in fiscal 2014 to be amortized.
Included in fiscal 2013 net income was a one-time impairment charge to the income statement amounting to just over $13 million related to CapEx costs at our Sidewinder project.
The background of this impairment charge relates to issues around timing of well testing and speed of which we had hoped to drill at Sidewinder. In fiscal 2013, we incurred a significant amount of our drilling costs due to the timing of when we tested the wells with a limited amount of production data to provide Sproule for our reserve reports, I believe, approximately two weeks of production data.
This required Sproule to use a volumetric determination to calculate our reserves rather than decline analysis. The volumetrics has historically not been very accurate nor favorable to TAG, and we can address any questions if anyone has but a little bit more detail, the volumetric calculation reserves Sproule assigned to Sidewinder-5 and Sidewinder-6 was approximately 0.5 Bcf recoverable. In a couple of months that we have those wells on production, we very closely produced, I think, almost that 0.5 Bcf, and we're continuing to produce about 1,000 BOEs per day from Sidewinder over the last 90 days.
Another issue was related to the pace in which we plan to drill Sidewinder wells, and that pace was disrupted by consenting arbitration process that TAG ended up winning, but it took us 18 months to do so. We always knew the key to success early on at Sidewinder was built on the back of the knowledge of these initial gas wells, aren't huge reserve wells, but they are good, low risk cash flow producers, and TAG has a number of them identified on our 3D seismic.
These initial gas wells were essentially being drilled with encouraging economics that would build our reserves out slowly, fund other drilling of Sidewinder that would target potential oil zones, and elsewhere through Taranaki, including our deeper Hellfire prospect that sits just a couple of thousand meters below Sidewinder shallow wells. We’ve learnt a lot through that process, and I don’t think we’ll see it happen again. We definitely are planning things differently to avoid delays in the future, and we’re consenting a number of new well pads at Cheal and at Sidewinder far in advance when we need to use them, so we can avoid any future delays.
In terms of production for fiscal 2013, we produced an average of 1,756 BOEs and 55% oil compared to 1,433 BOEs and 64% oil last year. Our average oil price for the year was $111 versus $116 last year. Our average gas price was $4.63 per Mcf versus $4.16 last year. I believe yesterday, we brought on a – or just this week, we brought on a few new wells to our plant, and again Drew can talk about it. Yesterday, we have produced about 2,660 barrels of oil equivalent, 1,406 of that being oil. We still have a couple of wells behind pipe. We’ll bring those on to production shortly.
At this point, I’ll turn the call over to Drew. He can give us a quick review of our reserves report for 2013.
Okay, thanks, Garth. The team here at TAG, we classified, as Garth said, fiscal-year 2013 is the year of the infrastructure build-out for us. The previous two years saw our operations focused on drilling the shallow Miocene play in onshore Taranaki and proving up sufficient reserves and establishing sufficient cash flow to take us to that next step of our business plan. To achieve that, we needed to focus this past year on a $40 million facility expansion. We’ve already proven we know how to have success with the drill bit down here.
This year, we needed to expand our existing oil facility at Cheal, add in an entirely new refrig gas plant to that existing Cheal facility, and beef up the gas compression capabilities at both Cheal and Sidewinder.
With a lean team of only about a dozen professionals handling all the operations down here in New Zealand, we knew that focusing on a major infrastructure build-out project as we did would result in a minor slowdown of drilling operations. Now, we still managed to drill six new wells in Taranaki this year, all successful, and our first ever unconventional tight oil test on the East Coast Basin, and I’ll be discussing these projects in more detail later in this conference call.
As far as our reserve situation looks, we are pleased to announce a moderate growth in 2P reserves even though we concentrated most of the year on successfully completing this major infrastructure project. We produced a total of 641,000 BOEs during the year or an average of about 1,750 as Garth said. Taking that production into account, we managed about a 4% increase in 2P reserves to 6.1 million BOEs, and we maintained our NPV10 at a little over $200 million. It’s noteworthy that 88% of our 2P reserves are oil.
We feel timing didn’t help us with the actual optics of this year’s reserve report. With a fiscal year end of March 31 and then infrastructure project start-up date of March 27, we didn’t have time to bring a lot of our behind pipe production on-stream to provide sufficient data to Sproule for this year’s report. As a result, Sproule is mandated by the rules of National Instrument 51-101 to volumetrically estimate proven and probable reserves in newly drilled areas.
Now, the original discovery wells in Cheal have now been producing since August 2007. So, we have nearly six years of production data on some of our wells now to help us determine how our new wells will behave and produce over time. What we know for sure is all our wells produce far greater ultimate reserves than what was historically predicted using early volumetric data. A great example of this is Cheal-B3, which after the first year of production was volumetrically assigned ultimate recoverable reserves of 70,000 barrels.
Now, after only five years, don’t forget most of these wells will have a 15-year to 20-year reserve life, that particular well has produced about 400,000 barrels. Once we get a few years of production history under our belts for each pool, Sproule can revert to using a decline analysis to determine ultimate recoverable reserves. That analysis more accurately reflects the nature of our drainage areas for these Miocene turbidite reservoirs. The seismic sees the sweet spot that’s where we drill, but the ultimate drainage occurs over a much larger area than just that sweet spot. That’s the situation we find ourselves in this year with a number of our new wells.
Sproule doesn’t have enough production history to use a decline analysis yet, so instead they map the sweet spot volumetrically at this time what we think are very conservative reserve numbers. This is particularly evident at Sidewinder, where our new wells, as Garth mentioned, Sidewinder-A5 and Sidewinder-A6 were volumetrically assigned a total of approximately 0.5 Bcf of ultimate recoverable reserves between the two wells in this year’s report.
In the first 90 days of production since fiscal year-end, those two wells have now surpassed that reserve allotment, and they show no signs of slowing down. There will obviously be reserve upgrades next year, but the result of this overly conservative reserve assessment in all our new wells definitely separates what we estimate internally for TAG reserves from what Sproule has assigned us this year. At Sidewinder, this discrepancy has resulted in an impairment on the property this year given we had the long consenting delay in getting these new wells drilled, as Garth mentioned earlier, and then only a few weeks’ production data before our fiscal year-end. We’re actually considering commissioning a mid-year reserve report update this year, which given the production data we have achieved since the cut-off for this year’s report, we are certain will materially effect the reserves we’re disclosing at this time.
One thing I would like to mention with respect to our reserves is that 80% increase in 2P original oil in place Sproule has assigned to our core producing formation in Taranaki, the Mt. Messenger formation. This increase in recognized 2P original oil in place can be attributed to Sproule’s recognition of the extent to which bearing sands must be contributing to production from individual wells. It stems back to the comment I just made on volumetric reserve determination versus decline analysis earlier.
Sproule is now starting to concede that much larger areas of gross sands have to be contributing to the production from our wells in order to balance existing well performance with volumes in place. The alternative is to assign unlikely recovery factors greater than 60% or 70% to the existing areas to account for what we’ve already produced.
Now what this all means is a very positive outlook for continued additions of proven and probable reserves in the future of our core properties. Now, I know original oil in place doesn’t have any bearing on our NPV now, what it does mean is an independent third-party recognizes the extent of the oil accumulations within our properties and it is only up to TAG to keep drilling and shift those original oil in place numbers to proven reserves.
To date, we have drilled up less than 25% of the Cheal Mining License and 10% of Sidewinder. We’ve just increased that acreage further with a successful 2012 blocks offer award more than doubling again our acreage right adjacent to these proven areas. So, we’re looking forward to many years of continued drilling on this core shallow cash flow machine that we have established now in Taranaki.
I will leave the reserve discussion at this point and turn the floor back over to Garth. I can certainly address any specific questions regarding TAG’s reserves later in this call when we take questions. Garth?
Garth E. Johnson
Thanks Drew. Yeah, we’ll hand it back to Drew shortly to talk about the operations. I just want to give everyone my thoughts on the upcoming program. TAG shareholders will be participating in a program that’s never been seen in New Zealand before, never been done before, with the potential for some very significant results.
We’ve contracted four rigs to be working simultaneously to drill a minimum of nine shallow Taranaki wells, two deep Kapuni wells in Taranaki, and at least one more East Coast unconventional well in the next six to nine months with a cost to TAG of approximately $39 million. It is fully funded using cash flow on our strong balance sheet.
I think this ability to commit to such a program is what separates TAG from many other junior explorers, and we are doing so with confidence that what we drill stands up technically and can be done safely, methodically to obtain the best results possible.
We have established low risk baseline production and cash flow at Cheal and Sidewinder, have got many more years to drill there. We have an understanding now regarding the relatively low declines associated with the shallow production.
We’ve maintained a respectable capital structure with less than 60 million shares outstanding. We have got a strong balance sheet, no debt, 100% of our infrastructure is owned, and the infrastructure is built to meet our needs for the future.
A lot of other companies are scrambling and needing to dilute to carryout their programs, to complete acquisitions, and doing so with probably three to four times more people on the payroll. So, we are pretty proud of what we’ve resulted and the foundation that we built that would carry us into the future.
Fiscal year 2014 provides our shareholders with a number of new drilling catalysts and success in one or all of the plays that we are going to be drilling inclusive of the deep Kapuni plays, the East Coast unconventional, and possibly even Canterbury. It will give TAG the opportunity to become a much larger producer and a reserve-based company.
We look at the nine shallow Taranaki wells to be drilled by the end of calendar 2013 as an opportunity to increase our reserves, maintain and possibly grow our baseline production and cash flow, and continue this for many, many years at relatively low risk. It also allows us to add deep drilling and more focus to our East Coast operations, and we have brought in a JV partner in East West Petroleum to our shallow Taranaki program that allows to focus on the deeper and the East Coast plays, and we also have a carry on those initial Taranaki plays up to $10 million, which mitigates a little bit of risk on that shallow play.
Upon success with our joint venture in Taranaki, we can tie-in in any commercial discoveries to our Cheal facility within approximately six months. We are really excited to be approaching the spud dates for least two of our deep prospects called Cardiff and Heatseeker, and with another deep prospect called Hellfire possibly being drilled, but currently we have it as a contingent success on Cardiff and Heatseeker. The deep play in New Zealand has very successful onshore analogs such as the 1.5 Tcf, 65 million barrel field called Kapuni and 800 Bcf Mangahewa Field, all within close distances to all our deep plays. Cardiff is located just to the east of the landmark Kapuni discovery, south of Mangahewa. And we’re targeting a large structure assessed by Sproule that’s having prospective resources on a p50 basis just under 215 Bcf, just under 13 million barrels of condensate.
Based on past drilling done in early 1990s by Shell, we see Cardiff has low-to-moderate risk, and Drew can talk us through that shortly. Shell previously owned and drilled the original Cardiff well in the early 1990s and have historically assessed significantly larger resource potential to the Cardiff prospect than Sproule did. We consider that adding even more upside potential to the program.
The original Cardiff discovery was made at a time when gas and condensate prices were much lower making Shell’s discovery uneconomic at that time, and technology to produce the tight plays was not as robust as it is today. We know that gas and condensate are there. We just need to utilize new technology to get it out, and that’s what our program is designed to do.
Following Cardiff, we will drill the Heatseeker well, which is very similar to Cardiff, and follow the trend of deep producers in the Taranaki production fairway. Unlike Cardiff though, Heatseeker doesn’t have a well into it already, which does increase the risk profile. As to the location of the permit, the seismic interpretation we’ve done to-date, all this supports the decision to drill. Heatseeker sits within a new 26,327 acre permit that TAG was awarded in December 2012, and we expect there to be a large amount of shallow prospectivity in the Miocene similar to Cheal as well, but we acquired the permit with a near-term focus on Heatseeker.
We’re also advancing our East Coast unconventional play where we have drilled one well to date called Ngapaeruru-1, and we encountered 155 meters of potential tight oil and gas pay while drilling. We’ve collected a huge amount of unconventional data, and that data is being assessed now and results to-date look very promising. Again, Drew will talk us through some of the details and the timing on the go forward there, but I think the data we have collected will help us better understand the long-term feasibility of the East Coast opportunity shortly.
At the same time, looking forward to our next East Coast well that is expected to be drilled in December-January, we recently signed an access agreement at our number one location for drilling in our northern permit in East Coast called Waitangi Hill. This is where an old 1910 wellbore was drilled approximately 200 meters and TAG found it full to the brim of 50 degree API oil with gas bubbling through it today. We can’t wait to get at this; it’s been our number one target. It was one of the reasons our ex-partner really was attracted to the play. It’s got 50 degree API bubbling through it, and that oil has been typed as coming from the source rocks.
I’m also pleasantly surprised and encouraged to report the results of our recent seismic acquisition on our frontier acreage in the Canterbury Basin where TAG owns 100% of 1.2 million acres of onshore and offshore land on New Zealand's South Island. We are excited about the offshore acreage, where nearby our permit boundary, Anadarko is expected to drill a well in late 2014, early 2015. But added to this, Canterbury like the East Coast has a confirmed onshore hydrocarbon kitchen working as evidenced by oil and gas seeps throughout the Basin, and an offshore discovery made in the Cutter-1 well produced over 10 million cubic feet of gas per day and over 2,000 barrels of condensate on test.
Our focus in Canterbury to-date has been onshore, and in November of 2012, we acquired 80 kilometers of seismic of our four interesting leads identified originally by geochemical surface data. Historically, seismic acquisition in Canterbury hasn’t been of very high quality. However, TAG seismic program is very successful in acquiring clearly imaged subsurface at a quality not ever seen before over our four leads. Based on this data, TAG has sought approval for – from New Zealand Petroleum and Minerals to acquire an additional 40 km’s of seismic to allow us to better understand the closure and aerial extends of the four leads prior to making a commitment to drill one or possibly all these leads.
At this time, I will turn it back over to Drew to give us his thoughts on upcoming operations, and then we can take questions after that.
Okay, thanks again, Garth. Our CEO just gave a pretty thorough recap of our operational plan for the coming year. I’ll just add a few details to a few of the projects. Our bread and butter shallow Miocene play will take the first steps outside our core areas in 2014. At Cheal, three sites were established when we took over 100% operatorship a few years back. Cheal A site, B site, and C site, all had at least a few wells on them when we took over, but today, we have 12 wells on A site, nine wells on B site, and five wells on the C site. We are now building the Cheal D and E sites, and once those are built, we’ll continue with three further sites in the Cheal area; F, G, and a prospect we call Southern Cross. Every one of those new sites is consented for 12 wells, each as are our A, B, and C sites. So not only will TAG continue drilling from our established sites over the next few years, these new sites set us up for many years of continued drilling on our core project.
Owning and operating all of our own infrastructure makes it easy for us to create a hub-and-spoke type facilities scheme with all new sites being tied back to the Cheal A site, where our production station sits. As Garth alluded to earlier, having this core oil area with long-term, if not spectacular, but steady cash flow, now let’sTAG carefully pick and choose a number of higher impact opportunities to expand into each year from here on in.
It’s the same story at Sidewinder where we have developed only about 10% of our land to date. We see Sidewinder as our next Cheal. So, we have already begun the process of obtaining and permitting an additional five sites to locate drilling pads that will essentially allow us to exploit the entire permit over the coming years. Right now, we only have one site, the Sidewinder A site, which now has seven of the eight consented wells drilled on it to date.
The next five permits at Sidewinder will all be consented for 12 wells each, so combined with our Cheal area sites, we will have well over 100 wells consented for future drilling. But the big news for TAG this year will be stepping into the deeper condensate rich Eocene play in Taranaki.
The oil and gas business in New Zealand was built on a few of these deeper, tight sand reservoirs. Fields like the 4.5 TCF Maui pool, the 1.5 TCF Kapuni pool, Mangahewa, Pohokura, they are all pools and exactly the same formation, the Kapuni sands. Our first foray into this new play type will be the redrilling of the proven Cardiff well.
Now, twinning an historical well is a great way to start this new path for TAG. We already know the structures there, it’s full of gas and condensate, it’s just a matter of deliverability. previous operators basically made a mess of this play, inexperienced drillers, wrong completion types, disaster testing operations, it wasn’t pretty. That’s where we feel we really have an advantage. Our combination of seasoned kiwi explorers have seen the development of all of Cardiff’s analog pools over the years, and we’ve seen what works and what doesn’t work down here.
Adding over a 100 years of Western Canadian drilling experience, on staff here in New Plymouth , and we’re on the cutting edge of all that North American technology that exploded in the last few years when it comes to resource plays like this. We’re really excited about Cardiff. it will be drilled right from our C site at Cheal, which has a brand new four-inch and six-inch pipeline connecting directly back to our production station at Cheal A as well as 11 kilometers of six-inch pipeline tying that sea site directly into the main New Zealand gas transmission trunkline.
Now after Cardiff comes to play that probably excites me the most; Heatseeker is a classic explorer’s prospect. If you picture this, a massive anticline feature, almost a perfect upside down mixing bowl sitting on a table. That’s what the 1.5 Tcf Kapuni field looks like on seismic. That pool was discovered in the 1950s, has only 18 wells into it, but has drained over 1 Tcf of gas, 65 million barrels of condensate to-date, and it keeps on spewing hydrocarbons today.
Now, picture right beside that upside down bowl on the table, what looks like an identical upside down bowl sitting right beside it. the only problem is someone has erected a wall, so you can only see three quarters of that bowl. That’s Heatseeker, three-way dip closure is clearly seen on existing seismic, but the fourth and critical direction of dip closure is situated right under Egmont National Park where Mount Taranaki, our picturous volcano is situated. No seismic has ever or will ever be shot in this park.
The nature of the structural belt in this area suggests that there will be that critical fourth direction of closure, but there is only one way to find out and that’s to drill a well. We’ve got a deep rig contracted. We have a service access agreement signed. We’ll move the rig on right after Cardiff and find out. As Garth said earlier, any one of these deep plays has the potential to really transform TAG if we’re successful. Being in the strong financial position we are in allows us to take a few of these shots every year without risk to our core stable bank balance and without further dilution to our existing shareholders.
Finally, I’ll give a few more details regarding our East Coast tight oil project. As I know, that’s what most of you’re into TAG for, just in case those billions of barrels of resource actually become reserves. We can’t give up too much detail at this stage as there is a critical land sale occurring in New Zealand later this year, bid deadline is September 26, and there are few blocks up for bid offsetting us within the East Coast Basin. But I can tell you, we are extremely proud of the operational job we did in the drilling of our first deep test on the East Coast.
Ngapaeruru-1 was drilled without a hitch in about three weeks. We anticipated and encountered extreme overpressures. We encountered swelling mud stones and a few other nasty drilling obstacles that have been a nemesis of past drillers in this tricky basin. But again, our combination of Kiwi experience and North American technology allowed us to drill our well easily, collect all the critical data we intended to, and not have a single environmental, health, or safety issue.
The small minority of anti-fossil fuel opposition we had before we spudded the well barely had time to organize a protest before we were gone. The vast majority of our neighbors there, all of the regulatory bodies like local and regional councils couldn’t believe what a professional operation it turned out to be. Drilling is new to these people. I think they were expecting wooden derricks and a spindle top blowout or something. The results of this first well were encouraging to say the least. In order to keep that over pressuring in check, we took no chances and used extremely heavy mud weights while drilling.
Despite that, we went from over 1000 meters of zero oil and gas shows through the over burden to instantaneous strong shows once we entered our target zone. Those shows continued unabated for 155 meters before they instantly disappeared to absolutely no shows again until TD, and that tells us a couple of things; number one, the seal looks to be working as no shows were seen above the zone. The zone itself definitely has hydrocarbons in it, but of course that was expected.
We knew these source rocks were working from the quality and quantity of oil and gas seeps in this basin, but probably most important is that there seems to be permeability associated with the zone. That’s the only way we would see the shows we did even given the high mud weights we were using.
We collected a lot of core, we shot Schlumberger’s logs I’ve never even heard of before focusing on unconventional parameters and we collected live samples of liberated gas from the drilling mud itself.
All of this data is now in various labs, mainly in New Zealand and Australia, where we’re working with specialists from around the globe to interpret and plan the next step to be taken with the play, and in particular this wellbore. What I can tell you is, we will definitely be completing this well, probably not for at least three to four months until we get all the data back from the labs and it’s all interpreted, but Ngapaeruru-1 was not a red light, it was not an orange light, it is definitely a green light from what we have seen so far.
Well, that’s everything I wanted to cover in my operational update for today. I’ll turn it back over to Garth to open the Q&A section of the call. Garth, are you there? I think Glen is going to open the floor to calls.
(Operator Instructions) In an effort to keep the teleconference relatively brief, we may not be able to all callers. However, if we don’t answer your question, please e-mail them through to email@example.com for response by the company. And our first question comes from the line of David Phung, Credit Suisse. Please proceed.
David Phung – Credit Suisse
Hey, good afternoon guys. So, current production is about 2,660s and you still have two wells behind pipe. What do you expect the production to be after you bring those wells on?
Yeah, we’ve got a couple of wells behind the pipe still tie in. We also have two of our key wells just undergoing regular maintenance, wax-cutting right now. So, given that we’ve tested all these wells, we do expect production once all wells are on shortly here to be at about 3000 BOEs a day.
David Phung – Credit Suisse
And I remember last time you were expecting in second half of this year, you’ll be averaging around that 3000, do you need to bring that down a little bit considering that you are going to be at 3000 regularly once you bring these wells on?
Yeah, we’re conservatively hoping that we don’t need to do that David. Most of the wells that we brought on now have moved into that stabilized production flow that really slowed decline section of our curve now, and we’re still optimizing wells as we move forward here, part of our biggest push in the last month or two here is to go well by well and look at our pumping procedures. And each well we do, we’re making a little bit of improvement on each one of them, a little bit of gains. So at this time, I think we’ll leave guidance as we said in that 2,500 to 3,000 barrel range for the rest of the year, and if that changes, we’ll certainly let you know.
David Phung – Credit Suisse
Okay. And one peculiar is, maybe a little bit nitpicky, you’re saying that the Cheal-C3 well, you are seeing an increased oil rate over time and you’re needing to install oil pumping equipment there. Is that the only well where you’re experiencing that and what are the before and after oil (inaudible)?
You’re breaking up a little bit there, David, but I think I’ve got most of that question. Cheal-C3 is starting to look like it’s more like an oil well, and do we have any other wells like that? we have one other well like that; it’s Cheal-A8, which originally on initial 15-day test showed itself as a pure gas well. We built facilities to assume that. Same thing with C3, we have built facilities to assume that, but on further production from those wells, we noted that they very quickly turned to predominantly oil producers. So, obviously, a streak of gas sand within these multilayer turbidite sands, but the rest of them being oil, gas obviously going to flow preferentially to oil first. So once that initial streak of the gas sand had spewed out, the oil started coming afterwards. so we’re shifting two wells that we previously thought were going to be gas wells, Cheal-A8 and Cheal-C3 into Cheal oil producers with our regular pumping configurations.
David Phung – Credit Suisse
Okay. So it’s not – the gas is from a differential interval then, it’s not really a mini gas cap of some sort, right?
No. These reservoirs are not single volumes, turbidite reservoirs are a series of – in a 20-meter section, there might be 30 different sands separated with shales that are 0.5 meter thick each. And oddly in these sands, once in a while, we just get one of those sands that has oil or gas or even water, once in a while in it, and the rest of them are all oil, and they don’t need – particularly need to be at the top, they could be in the middle, they could be at the bottom. It’s a very strange physical phenomena, but well proven in these Mt. Messenger and Urenui reservoirs. So, it is not a gas cap situation where we’ve blown off the energy from the pool. It’s single lens of sand within the overall net package of sands that happen to be gas bearing, but the rest are oil bearing, it appears now.
David Phung – Credit Suisse
Okay. And maybe just a little bit more detail on Cardiff there. How many intervals are you planning to fracture stimulate, and can you talk about in a little bit more detail on how you plan on stimulating those zones?
Right. There are three main zones in the Kapuni Sands that we’re going to be looking at Cardiff. The top zone is called the McKee Sands, then the K1A Sand, and then the K3 Sand, the deepest one. The deepest is the thickest. Second one is the middle one and the top one is the thinnest. All three sands have been produced and tested, gas and condensate in the past in sub-economic rates. As I said, it was a complete disaster by the past operators who ended up having bad casing jobs. There were a number sidetracks drilled and wells abandoned and tools lost downhole, and they never really did get a proper definitive test on any of those zones.
We are going to drill a clean well through all three of those zones staying well away from all of that stuff that went on in the past. We’re going to be about 300 meters away from all that stuff. That well is based on our 3D seismic. We are going to be on the top of the structure on the brightest amplitude. We’ll have a clean set of logs across all three of those zones, and from those logs and from the information we gather while we are drilling, we’ll plan our fracking procedure. We’ve got our fracking consent already in to the local regional councils here. We do plan on fracking all three zones. We’ll start at the bottom zone, the thickest zone, the K3A and take that one definitively itself first, so we will frac that, we will test it, we will give it a chance to make a definitive decision on it before if it’s not economic for us, and then we will move up to the second one and the same thing, test that definitively and then move up to the final McKee sand and test that one.
So at the end of the day, we may well have a continuing completion operation going on there for the next 10 or 15 years; as one zone depletes off we’ll go up to the next one, but initially we want to have a fair chance at all three, we don’t want a chance any interflow between the three, we want to test each one individually and get definitive answers for each one.
David Phung – Credit Suisse
Okay, perfect. Thanks.
And that concludes the Q&A session of this call. I would now like to turn the conference back over to Mr. Johnson for closing remarks.
Garth E. Johnson
Okay. Thank you very much everyone for calling in. We appreciate your time and your support, and we are looking forward to an exciting 2014 fiscal year. We will continue communications via conference calls on a quarterly basis, and we do appreciate everyone’s attendance to the call.
I recently heard someone that I respect a lot use the following term, it is a little cheeky, but I thought I could end the meeting with it, and it goes like this. The only risk in owning this stock right now is not owning enough, I think our Board, our management team is definitely onside with that because we’ve got relatively low valuation right now. I think we’ve worked through a number of issues that caused some concern with our shareholders. We’ve got a strong reserve base, infrastructure, strong balance sheet, and a fantastic program that our team has put together for 2014.
So, with that, we’ll end the call and I really appreciate everyone’s support. Thank you.
Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect and have a great day.
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