TAG Oil's CEO Discusses F1Q 2014 Results - Earnings Call Transcript

| About: TAG Oil (TAOIF)
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TAG Oil Limited (OTCQX:TAOIF) F1Q 2014 Earnings Conference Call August 14, 2013 10:00 AM ET


Garth Johnson - CEO

Drew Cadenhead - COO


David Phung - Credit Suisse


Good day, ladies and gentlemen. Welcome to the TAG Oil Fiscal Q1 2014 Results Conference Call. My name is Dominique and I will be your operator 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 securities 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 and Director. Please proceed.

Garth Johnson

Thanks, Dominique. I’d just like to welcome everyone and thank you for participating in TAG Oil's conference call to discuss our Q1 fiscal year 2014 results and our upcoming drilling program that's going to be targeting on the p50 basis, approximately 411 Bcfs and 29 million barrels of oil and condensate within the next six to nine months.

Q1 was a quarter where our team focused on getting wells onstream, optimizing production configurations of our producers, and preparing for a busy drilling program that will consist of nine shallow wells in Taranaki, two deep Kapuni wells, and at least one more East Coast well in the next nine to 12 months. I'm happy to report the new Cheal gas plant and lifting equipment is performing very well. Declines on our Cheal producers are consistent with expectations, and we’re understanding the decline scenarios within the shallow gas play which has been the focus of the first six wells drilled at Sidewinder.

Drew Cadenhead, TAG’s COO is also on the call, and after I summarize some of the financial results from Q1, Drew will discuss what we’ve seen to date with our operations and talk about our upcoming program that will provide our shareholders with an opportunity to participate in the most active drilling program in New Zealand's history, a program that can dramatically change TAG’s production and reserve base quickly upon success.

Before I discuss our Q1 financial results if anyone wants any specific details of our quarterly results all information can be found at tagoil.com or on our SEDAR profile at sedar.com.

We ended the quarter in strong financial shape with $57.2 million in cash and $63.5 million in working capital and carry no debt. We own approximately $100 million in infrastructure custom built for TAG's operations that provides us capacity for future discoveries to be quickly monetized. We recorded Q1 revenue of $14.7 million, and net income before a non-cash share-based compensation charge of $4.5 million. Cash flow from operations slightly exceeded guidance of approximately $3 million per month, with cash flow coming in from ops being $9.5 million for the quarter.

In Q1, we produced 2,354 BOE per day compared to 1,691 BOE at Q4 2013 or 1,721 BOE at the comparable quarter last year. Our average oil price for the quarter was $104.87 and our average gas price was $5.72 per Mcf.

Subsequent to Q1, our production has averaged 2,403 BOEs per day for July, 57% of that being oil and 2,104 BOEs, 60% oil for August, with the differences coming from a reduction in some of our Sidewinder gas that Drew will discuss shortly.

Cash flow from ops that we have discussed previously, will be relatively unchanged as oil rates still remain in line with expectations, and obviously oil has much higher netbacks per barrel when compared to gas. So, we still anticipate fiscal year 2014 cash flow to remain at approximately $36 million for the year with no forecast of future success at this time. Obviously, we’re hoping for a pretty dramatic success, so things could change pretty quickly.

In terms of capital expenditure for the next 12 months, we anticipate incurring approximately $40 million to $42 million in capital expenditures related to the drilling program I mentioned earlier, as well as acquiring some seismic that is part of our work program commitments in Taranaki.

CapEx has been increased slightly, higher than what we had forecasted last quarter as a result of the different drilling plan for our Kapuni well that Drew will discuss.

At this time, I’d like to turn the discussion over to Drew to give us his thoughts on our operations to date, what we are seeing and what we can expect with the coming program.

Drew Cadenhead

Okay. Thanks for that, Garth. From an operational standpoint, I have to emphasize something Garth alluded to earlier. TAG has drilled more wells in the last three years in onshore Taranaki than were drilled in the previous 10 years combined. Yet still, there are more wells in one township of land in Southern Alberta than we have in our entire country down here. The significance of this is we are on the early stages of the learning curve down here when it comes to production forecasting. We just don’t have the history and precedence that you may be used to hearing about in other parts of the world. Now TAG does have the advantage of owning and operating everything we’ve done down here to date 100%, so we are very quickly developing solid forecasting methodologies, we can apply these to future discoveries.

Of our first discovery at fields like Sidewinder were a complete shot in the dark for us to initially forecast. What we have found is our oil pools like Cheal 90% of the wells have a nice predictable decline rate from the first day on, and we’ve learned the hard way that occasionally we drill a super high initial rate well up to 10 times higher than our average initial rates, but these wells do not decline at an equivalent rate to our average wells. Instead, they decline very quickly within 90 days usually to an average rate where they then take on a normal predictable decline rate.

Although, we always target oil pools in our shallow drilling program, occasionally we’ve run into high deliverability gas pools. And we never seem to find an average rate gas well on a BOE basis, we always seem to get these boomer gas wells that look pretty steady on the 10- to 15-day initial test, but again just like the super high initial rate oil wells, these wells decline very quickly over the first 90 to 120 days until such time as they flatten off and start their long reserve life at rates equivalent on a BOE basis to our average oil wells.

We used industry conservative GPP declines, but unfortunately longer-term production proved those initial forecasts were overly optimistic. I am trying to explain here why TAG’s production numbers are lower than what some of you were expecting. I am not making any excuses because the truth is when we drilled all of our wells last year and were waiting to tie them into our expanding facilities; I made a list of each well and what its stabilized test rates were. When we added up all the wells, the total was over 6,000 BOE per day, so a year ago before we finished our facilities, we gave guidance in the 4,000 BOE to 5,000 BOE per day range, at that time that was reasonable forecast. But by the time we started bringing wells on-stream, which still continues today, our 1,700 barrel a day oil well had dropped to 250 barrels a day, but steady now. Our 1,100 barrel a day oil well was down to 225 barrels a day, but steady. Our 10 million cubic feet of gas a day at Sidewinder is down to 5 million cubic feet a day, but steady now. Our 14 million cubic feet a day gas well at Cheal is down to 2 million a day, but steady now.

So no excuses, we’ve got it wrong in our forecasting of these new pools. Given the complete lack of data available, I don't know of a single reservoir engineer that would have forecasted any differently. What I can say is we now understand these reservoirs far better than we did a year ago. We can see all our existing wells are flattening out nicely now. We have confidence in our 5-to-10 year forecasting for all these wells, not including anything we'll drill in the future. And we can have confidence these pools will provide decades of predictable cash flow to TAG as we move it into the next phase of our business plan starting now.

I'll turn it back to you Garth at this point.

Garth Johnson

Thanks Drew. I think as we discussed at our year-end conference call and a little bit earlier, the program that we are set to get underway will provide our shareholders with an opportunity to participate in a fully funded program that hasn’t been seen in New Zealand before with the potential for some very significant results. We feel the program has been built to give us the opportunity to strengthen our reserve base and cash flow materially with some success.

As Drew mentioned, we’ve learnt a lot about Cheal and Sidewinder, and we're happy with Cheal's performance, we're still learning a lot about Sidewinder, but we feel there is a large amount of potential within these permits. From the shallow oil play and the deeper prospects, the Cardiff and Hellfire, not to mention the 12 billion barrel play in the East Coast unconventional.

We have a plan in place that allows TAG to stay in a strong financial position allowing us to continue to drill shallow pools and to combine these activities with transformational opportunities like TAG's Kapuni prospects and East Coast. Our deep Taranaki program and the East Coast are the newest items of business, they are happening within the next 30 days, and with our Cardiff well expected to be the first of those. We expect the spud date to be mid-September, and of course longer term, we’re very interested in the activity we’ve seen to-date in our Canterbury Basin where we own 1.2 million acres of land that has a confirmed working hydrocarbon system. We're always taking a look at new opportunities, as well as they emerge, new land offerings, acquisitions, anything that's accretive to our shareholders.

Specifically right now though TAG has contracted four rigs to be working simultaneously at times over the next nine to 12 months, using cash flow from our operations and a strong balance sheet. I think our ability to commit to such a program is what separates TAG from other junior explorers, and we're doing so with confidence in our team in New Zealand that we’ve learned from the results over the last couple of years of drilling, and we know that what we are drilling going forward stands up technically and commercially to grow TAG.

We have other opportunities farther out past fiscal year 2014 such as our shallow water offshore Kaheru prospect, with our partners targeting a p50 perspective resource assessed by a Sproule of almost 44 million barrels of oil. With our Hellfire prospect, where we’ve internally assessed the prospective resource on a p50 basis of 120 Bcf. There are lots of opportunities passed this current program that we're about to discuss, combining low risk shallow wells, higher-risk, higher-reward Kapuni plays, and the East Coast activity that we have coming with a goal of converting TAG to a much larger producer and a reserve-based company.

In terms of timing on our shallow program, we're presently about to start our first well on PEP 54877 that we call Cheal Northeast, and we’ll continue drilling a total of nine wells within the greater Cheal area that consists of Cheal Northeast, our Southern Cross permit, and Cheal South permit. We expect this program to provide TAG an opportunity to add reserves in production without a lot risk, while we also target our big stuff, Cardiff and Heatseeker.

I’m often asked what our expectations are of the coming shallow program, and over the quarter, our team completed assessments of the shallow prospective resources anticipated to be a potential recover from the nine wells, just the nine wells drilled on these three permits. The total came to on a p90, p50, and p10 basis, a total of 7.4 million barrels of oil, 16.55 million barrels of oil, and 37 million barrels of oil; with TAG’s net interest being 4.7 million barrels, 10.5 million barrels and quite possibly 23.6 million barrels.

Based on our last reserve report, with an average price of approximately $35 to $40 per barrel 2P from Sproule that adds up to a pretty significant amount of potential value that we’re targeting right now. We’ve also looked at the deeper Kapuni potential within our permits and we’re getting pretty excited as drilling approaches. At the current time, we have had our resource assessment completed by Sproule on Cardiff and we’ve conducted our own assessment internally by our technical team in New Zealand.

Drew will give us a discussion in a few minutes about some of the history of the deep Kapuni play, what he finds attractive, but initially a breakdown of our gas in place estimates are as follows; Sproule prepared this resource potential estimate on Cardiff; on a p90 basis, 137.3 Bcf plus 8 million barrels of condensate; on a p50, 215 Bcf, 12.8 million barrels; and on a p10, 341.4 Bcf and 21.5 million barrels which TAG owns 100%. Internally, we did a similar assessment on our Heatseeker prospect. On a p90 basis, we came up to 83 Bcf ; p50, 197 Bcf; and at p10, 469 Bcf, very significant targets coming up starting mid-September.

We also took a look at our Hellfire prospect that is a contingent well, we’ve got a two-well contract with the current rig plus an option, so Hellfire would be our option well with the potential resource estimated on a p90 basis of 53 Bcf, p50 of 120 Bcf, and p10 of 270 Bcf.

We’ve done a lot of work on the deep play in terms of costing, optimal well placement for Cardiff, and the majority of the work will apply to Heatseeker. We originally intended to drill a sidetrack well for Cardiff, sidetracking off a historical well drilled by Shell, but since decided, the data we’ve compiled supports drilling of a brand new well that that we’ll Cardiff-3 at a cost of approximately $14.6 million. It is a little higher than anticipated, but we fell for the additional $3 million. The optimal placement of the well to intercept the three zones we were targeting was critical to giving us the best chance of success in such an important well.

I think at this time, I'll turn the discussion back over to Drew, he can provide some background on the program, a discussion on the plan of Cardiff, maybe some history on the Kapuni play in New Zealand, and Drew maybe you could touch on where we stand on the East Coast well and the analysis of all the data we acquired during drilling of Ngapaeruru.

Drew Cadenhead

Okay, thanks again Garth, will do. As many of you are aware, TAG’s business plan has not wavered over the past few years. It has always been to build up a solid reserve and cash flow platform in the shallow Taranaki play, proceed conservatively through that phase of the plan to ensure preservation of our cash, avoid debt, and keep our share structure tight. Once we’ve achieved that stable platform we could begin taking shots at game breakers for our shareholders. Well, we've achieved the hard part. We’ve successfully built a stable, long reserve life platform of oil and gas pools to provide the cash flow necessary to not only sustain our lean operation, but fund the ongoing development of those pools, and most importantly we’re going to begin taking a few risks at the fence.

We’ve already drilled our first East Coast basin well, testing the unconventional source rocks in our Southern permit. Analysis of that data continues. All indications to-date are positive. We will be formalizing our completion recommendations for that well within the next six to eight weeks, once all the rock data has been analyzed and integrated with the petrophysical data that we now have. Just two days ago, after an extremely long process with the Gisborne District Council, we were granted their consent on a non-notified basis to drill our first well in the Northern permit. So now that program is underway as well, and don't forget, we are still spending Apache’s money over there.

But we’re also asked if we’re seeking another partner to replace Apache on the East Coast, and we have been approached by parties that are much bigger than ourselves to discuss that possibility. However, with the data that we received to-date and the data that is incoming right now and our present financial position, why would we? We’re in a position to at least take this program to the next phase, a pilot development program; and who knows, if we execute properly, we may move to the next stage of full blown production and development on our own as well.

Back in Taranaki, as I speak, we are moving to CBCC rig number one, a massive state of the art triple, on to our Cheal C site. It is a huge mobilization process. It will likely take the better part of four weeks, but once we’re ready to drill, we will spud Cardiff-3, right now tentatively forecast for mid-September.

Here’s TAG's first ever foray into the deep condensate-rich type gas play in Taranaki. The Taranaki Basin owes its roots to this play. The first discoveries ever made in New Zealand was 1.5 Tcf onshore Kapuni field, followed by the 5 Tcf offshore Maui field. This 4,000 to 5,000 meter deep formation is rich with condensate, up to 60 barrels per million, and there are many wells that produced after frac at 20 to 30 million cubic feet per day for many years. These are huge potential gas wells, with the added bonus of $125 a barrel of condensate.

As Garth mentioned, after much deliberation, we decided not to re-enter the original Cardiff 2A sidetrack-1 wellbore. The fact is wellbore has already had three unsuccessful attempts at reaching TD and properly evaluating the targets makes old guys like me a little superstitious. But that aside, our drilling guys have identified a potential up-hole well integrity issue with that original well, as Garth said, for a couple of million dollars more, on a $12 million well we can drill a brand new well. We’ll engineer it exactly as we want it, we can ensure safety and environmental protection, and more suitably target our multiple zones within the main Kapuni group prospect.

The Cardiff-3 will kick-off in about four weeks. It will likely take four to six weeks to drill, after which we will immediately re-locate the big rig about 15 kilometers to the Southwest to drill another similar prospect we call Heatseeker. Both these wells have the potential to materially change the scope of TAG oil. Call it stage two of TAG's business plan, it's time to go for it.

Back to you Garth.

Garth Johnson

Thanks Drew. I think that ends the discussion part of today’s call. We’d be happy to address any questions, Dominique?

Question-and-Answer Session


(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 through to info@tagoil.com for a response by the Company. Your first question comes from the line of David Phung of Credit Suisse.

David Phung - Credit Suisse

A couple of quick questions for you, I just want to make sure the $40 million to $42 million CapEx program, does that already include the $14.6 million for Cardiff?

Garth Johnson


David Phung - Credit Suisse

And that gas price during the quarter of above $5, do you expect that moving forward?

Garth Johnson

I believe, so. I think our historical average has been less. We’ve got a gas price that’s based on a gigajoule basis, and with the conversion plus we have a producer price indicator that basically acts as an escalator in our gas contracts. So, I would probably think that’s on the higher side, but probably in the $5 range would be something you can use for your purposes.

David Phung - Credit Suisse

Okay. And the tax horizon, I remember at one point you might have suggested that you might become taxable this year. How far out has that been pushed out now?

Garth Johnson

A couple of years at least.

David Phung - Credit Suisse

And going back to Cardiff, four to six weeks to drill, how long would that test be shortly after that?

Drew Cadenhead

We’ll probably move right to test, we can move -- we’ll move that rig off as I said David down to Heatseeker, but we'll move a service rig on shortly afterwards at least to complete the well, in other words to perforate and clean-up, we will have them clean-up and then we’ll we'll make a decision from that. These wells, they are tight gas sand wells, they will be needing fracing, we’ve got a frac application already into the board here, so we’re planning on it and fracing is not a bad word in Taranaki. It’s the only way that these deep formations produce and a number of other companies are fracing regularly down here, so we are not the only [force] (ph), but I would say we’d move straight to the perforation completion and then we’ll plan our frac program from that, so we’ll do that concurrently while we’re drilling down at Heatseeker, so within the next month or two after that, I would suspect we’ll be testing that well.

David Phung - Credit Suisse

And in your shallow program, you're going to start to spud your first well. Assuming the first well is successful, how long before that actually comes on production?

Garth Johnson

So, we are hoping to spud the first well, which we call Cheal E1 on Sunday, New Zealand Time, so we’re just moving the rig on to the site now, so we will be getting underway. We are allowed to production test for up to 90 days, each well, so we’ll actually complete these wells with the drilling rig, we’ll perforate them and move on to the next drilling well, so they would be ready to go and we’ll start testing concurrently almost immediately. Our facilities team is presently putting a plan in place of going to hopefully allow us to keep producing past that 90 days into more of a permanent mode, it’s a bit of a unique plan, I don’t want to get into too much detail about it right now, because it’s a bit a proprietary for us but really we hope to be in production right away and continue that for at least 90 days, and in fact hopefully continue that production continuously right from the get-go here.

So previously, we’ve said, look we’re going to needing six to eight months to tie these wells back to our Cheal A facility. We’re actually looking at a different style of production plan for us that deals with the gas on-site and that will allow us to start producing immediately. We can produce oil immediately, but we have do something with the gas, now we’ve got a plan we’re going to put in place here that may allow us to produce continuously basically right from day one of completion.

David Phung - Credit Suisse

So, you have a plan to conserve the gas or to somehow deal with it without causing any other issues?

Garth Johnson

Let’s say somehow deal with it.


This ends today’s question-and-answer session. I would like to hand the call back to Mr. Garth Johnson, Chief Executive Officer and Director for closing remarks.

Garth Johnson

Thanks, Dominique. I would like to thank everyone for participating in today’s call. We definitely are excited for the program to start this weekend, and we look forward to providing updates throughout the coming months as progress is made. If we didn't get to anyone that had any questions or if you think of a question later, please feel free just to email through to us at info@tagoil.com, and we will respond immediately. Thanks again.


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

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