Saturday, August 25, 2012

Modelling an Unprofitable Oil Well

Imagine you drill an oil well that produces 7000 bbl the first month, quickly falls to 100 bbl/d, and then levels off into a 12% annual decline rate.

What kind of revenue is that going to produce? Assume a reasonable royalty rate and that the well is drilled someplace unfavorable where the realized prices for oil are low. And what's the present value of that revenue discounted back at 10 percent (i.e. PV-10)? Here's a helpful chart for thinking about this:



The present value of the revenues is asymptotically approaching $10 million, and in fact the present value of the oil well is $10mm even if you assume that it spends decades as a stripper well producing under 10 barrels per day. (That's because at a 10% discount rate, the revenues 20 years from now aren't worth very much - only 12 cents on the dollar.)

So, if this well was very deep with a gigantic lateral and tons of perforations and completion expense, it may have cost $8 to 10 million dollars. That would make it either a breakeven or modestly profitable proposition.

If the well was drilled by an entity with a cost of capital of 50 percent, it would definitely be a losing proposition. That would be a sign that the entity did not make effective capital allocation decisions. The decisions could be rational if the entity had hidden motives; perhaps principal/agent conflicts like a desire to look busy and stay employed drilling wells.

By the way, how could the agents of that entity hide this? They would want to focus attention on the highest point on the chart, namely the nearly-instantaneous rate of initial production, and avoid discussing the rate of production decline, the present value of revenue, the present value relative to cost, and the internal rate of return of the well relative to other opportunities (like buying back debt) or to doing nothing.

What would be the end game for that strategy? An entity that will reinvest capital at negative rates of return will eventually deplete all of its capital and become worthless, unless the principals relieve the agents of control.

11 comments:

Stock Chump said...

Where is the well drilled? In some cases (example given below in California) is that you cannot put in artificial lift until a well stops naturally flowing.

This is from Veneco (VQ) conference call

http://seekingalpha.com/article/798381-venoco-management-discusses-q2-2012-results-earnings-call-transcript?part=single

Since regulations require the wells to stop flowing before installing artificial lift, the wells may produce at lower rates for quite some time until they finally stop flowing and we can install lift equipment to maximize production. As an example, one of the wells we drilled earlier this year flowed for 4 months, much of that time at low rates before it stopped flowing in late July. Now that it is on pump it is producing over 400 barrels of oil per day, and overall field production now over 2,000 barrels per day.

CP said...

What if it was drilled in the Bakken? And what if it was already on pump?

CP said...

What was your point, by the way?

That there aren't any companies drilling uneconomic wells that use the instantaneous IP rate as a smokescreen?

PD said...

CP,

I am glad you wrote this post. There are way too many guys doing this, and also being allowed to report IP rates too quickly and not disclose how they are being measured. Their are bakken blogs that post IP rates within 5 days, and they are using a 200 ton frac! that means the IP rate is like 60-80% (not way to determine unless you have a processing facility on surface) frac fluids being circulated uphole. Its a bunch of BS.

On another note, if you know you have to support wells right of way, via water flood or pump, most good operators will try and do it right away, because you get synergies on upfront capital.

Stock Chump - regulations ahve a lot of rules, sometimes you can put on artificial lift right away if you own all the surrounding land. Also the regulator wants to see how the reservoir reacts to teh wells drilled before they allow artificial, because there are different tax incentives and royalty rates for different methods. certain states, its the wild west and the regulator is non existent.

CP brings up a good point, oil guys in general are snake oil traders, almost as bad as real estate developers.

CP said...

A well in western Canada today, on average, costs three times as much to drill and complete as it did six years ago (see attached Figure 1). The big ramp up in the transition period between 2004 and 2010 – from $1.3-million to $3.6-million per well – was not because of general inflation, but the quick migration into the capital-intense world of unconventional plays like shale gas and light, tight oil (LTO).

http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/how-rising-well-costs-are-reshaping-the-oil-patch/article4491408/

CP said...

Thanks, PD.

I didn't realize that frac fluids were bing included in IP rates. Is that true even if bbl figures are ostensibly being reported, e.g in North Dakota?

Stock Chump said...

My point is that regulations might make it look like a well is uneconomical to drill but in fact is.

Just being contrarian, not saying anything was wrong with your analysis. I also hope to inform (although PD comment is better education).

There are plenty of companies that put out adjusted EBITDA or earnings etc that are meaningless... same can be said for oil wells.

CP said...

That's hilarious!

So, under your theory, bashful oil companies - which happily tell us the instantaneous-IP rates - are holding back information to suggest that they aren't losing 50 cents for every dollar they spend drilling wells?

Stock Chump said...

No, my point was that current production rates / decline rates could be lower because artificial lift is not yet present.

There could be other reasons such as little or no transport capacity. A well in a new area can also give VALUABLE information that helps the next well drilled at a higher production (learning the best way to frac that area).

NFX last quarterly call

"Let's talk about the Uteland Butte first. Our early wells in this play were drilled under Monument Butte field. They IP-ed at around 500 barrels a day, but we were confident that the play was even more prospective as we moved to the north, deeper and into the higher-pressured regime. The data we gathered from these early wells was instrumental in our ability to capture additional acreage in the Central Basin during 2011. We have recently migrated our drilling campaign to the pressured regime in the Uteland Butte play. And our most recent well commenced production at nearly 1,500 barrels of oil equivalent per day, of which, nearly 90% was oil. The well averaged nearly 1,300 barrels equivalent a day over the first 7 days of production. We have 2 wells to date in the pressured formation at the Uteland Butte and their average production is at least 3x that of a normally-pressured Uteland Butte."

My comment further agreed with you saying that some companies put out crappy metrics, Adjusted EBITDA, Adjusted earnings etc AGREEING with you that IP rates are probably worthless.

CP said...

It looks like my analysis was correct. The company in question just reported that their $100mm in drilling expenses last year resulted in production with a PV-10 of half that figure.

CP said...

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