The art of the promise
February 22, 2012
Yesterday, New Zealand Energy (NZ.V) announced production test results for its Copper Moki-2 well in the Taranaki Basin, located on the west coast of New Zealand's north island. Through a 24/64th inch choke, the oil has flowed for five days at 1,000 barrels per day (plus 820 mcf of natural gas – more on that shortly).
There is much nuance to this story, but I'll do my best to keep it short and focused.
This second well was drilled from the same pad as Copper Moki-1 (CM-1), which was placed into production in mid-December. CM-1 tested initially for two days at 1,100 barrels using a 28/64th inch choke diameter. The follow-up extended test, over 12 days at a 20/64th inch choke, yielded 521 barrels of oil and 508 mcf of natural gas. See my previous piece for the math (fifth paragraph). The narrowing of the choke, on a linear calculation (ie. no change in pressure), would cut flow by 49%, not far from the actual experience. Thereafter, it was placed on restricted production, still at 20/64th inches, flowing an average of 500 barrels per day since that time. Flow has declined to 434 barrels over the past 30 days, and the choke has been opened up to 24/64th inches, raising flow back again to the 500 barrel range. For me, this conjures up the picture of a car mechanic, under the hood, tweaking the accelerator lever to achieve and maintain a preferred rate of flow.
The 1,100 barrel test for CM-1 was through a choke diameter allowing 36% more flow than the 1,000 barrel test for CM-2. Conclusion? CM-2 is better than CM-1. On this more restrictive test, CM-2 almost matched the natural gas produced in the test for CM-1 (820 mcf versus 855 mcf).
For context, the neighbouring TAG Oil's Cheal-B5 well tested at 1700 barrels (and 1,000 mcf natural gas) using a choke diameter of 40/64th inches, or with a (linear-calculation) flow capacity of 2.8 times that of the CM-2 test. Do the math, folks (2.8 times 1,000???!!!). NZ has just hit two very good wells on its first two attempts.
Along with the four tanks on site, each holding 400 barrels, NZ has converted its water tank for additional daily capacity, having produced no water to date. Read that last phrase again… no water to date!
On the first well, the Company has been flaring off somewhere north of $7,000 worth of natural gas/liquids component per day. Double that for the second well and have the mechanic under the hood open up the flow rate. The moment the pipeline connects the natural gas to the grid (two months, I figure), I expect that both wells may be opened up. The oil's not going anywhere, so why waste the gas?
I've been asked for my opinion on whether or not NZ will do a financing soon. Just five minutes ago, a friend asked if I saw one in the works at $2.50. I honestly don't know but here's my thinking:
Even without the gas, CM-1 has been generating $1.35 million per month. Double that for CM-2, yielding $2.7 million. I figure the current gas flaring represents an opportunity cost of $210,000 per month (or more). Let's double that when we add in CM-2, showing a total of $420,000. With just 500 barrels of oil per day per well, then, once the gas is plugged in, the monthly take would be more than $3.1 million. Remember, we're only talking about two wells, both on restricted flow. For the sake of conservatism, let's not even open up the pipe. For the purposes of this conservative exercise in calculation, let's just maintain the combined 1,000 barrels, plus the gas.
The Company has just announced what I consider a scarily conservative estimate of just 3,000 BOE/day by end of 2012. This estimate is described as to incorporate the early success of these two wells and plans for another eight wells by year end.
Two or three weeks ago (I think), NZ had just over $13 million in the bank. Let's pretend that this now sits at $11 million.
They've noted the intent to drill two or three wells per pad and that the first four will all be drilled from this first pad.
Each pad costs about $2 million to make ready.
Each well costs about $3.5 million through to completion.
The natural gas hook-up will run another $1 million.
So… three more pads ($6 million); eight more wells ($28 million); and four gas connections ($4 million). By my count, the Taranaki basin work in 2012 rings up a cost of $38 million. Subtract the cash-in-the-bank of $11 million and you still need another $27 million. At a restricted flow, the first two wells, alone, will generate netbacks of $31 million over the remaining ten months of 2012, more than covering the operational costs as described for Taranaki. Keep in mind that this assumes zero success for any of the planned eight wells. What are the chances of that? Did I mention that the next-door neighbour has just hit twelve successful Taranaki wells in a row?
A more realistic scenario has these first two wells generating at least another 1.3 million dollars per month (or a total of $44 million for the remaining ten months of the year), even with a 20% decline in flow. Stress the point here that they're operating on an artificially restricted basis, awaiting the gas hook-up.
In other words, considered in a vacuum, the Taranaki operations are likely to be self-sustaining into the foreseeable future. Key phrase here is, "considered in a vacuum." Nothing operates in a vacuum. Hence, the economist's predictive (escape clause) refrain, "on the other hand." Success breeds success and in the hands of ambitious management (and that's what we're talking about here), I would not be surprised to see new funds enter the picture. John Proust likes to deal from strength. From where I'm sitting, his position looks pretty strong. Whether new money comes from a financing (I would hope at a higher level) or from some other kind of credit facility (my preference by a long stretch), I can't predict.
Let's not forget about the East Coast Basin. That, too, will require funds… lots of funds. I do not see the Taranaki Basin as covering the bill for exploration and development in the East Coast Basin. That would be too much of a reach. While it may help to get started, there needs to be a 'big brother' type relationship, such as TAG Oil has forged with Apache (up to $100 million) for its own East Coast efforts. At the same time, I know John Proust enough to say that he has no interest in giving away the farm, so to speak. He'll have his team poke some holes in the ground, study the output, and add clarity to that picture before making any deals. But that's just my guess, of course.
As for the Company's forecasted 2012 exit rate of 3,000 BOE, I'm asked if that includes gas, hence lowering the netbacks calculation. I don't know what it includes, and quite frankly, I see it as so low a figure in the face of what I'm anticipating that it's almost irrelevant. Let's just throw the 3,000 barrel figure in the hopper as straight oil for the sake of running the numbers. This would show a cash flow (from netbacks at the current level of $90/barrel) of just under $100 million. Using a conservative 6x cash flow valuation, this would yield a share price of $5.53. Personally, I see half of that coming from the first two wells, alone.
So… in my view, current share price ($2.96) reflects no meaningful value beyond the first two holes. Nothing from the planned eight wells in Taranaki and nothing for the 1.8 million acres in the East Coast Basin.
It's all good from here.
Under promise… over deliver.
Best,
Kevin Graham