Dave's Energy

Tuesday, October 18, 2011

Why I look for 200% Reserve Replacement in an E&P Investment

One of the key things I have always looked for when evaluating an investment in an oil and gas exploration and production (E&P) company, is the ability to economically replace reserves at a rate of over 200% of annual production. That is, for every barrel a company produces, I want to be able to see that the cash flow generated from that production allows them to go find and replace that barrel with two more barrels (2 new barrels replacing one produced = 200% reserve replacement). Doing so with internally generated cash flow allows a company to grow reserves at a reasonable rate, benchmarking around 10%, without raising capital and diluting investors. Why, you may ask, does it take a 200% reserve replacement ratio to grow reserves just 10% annually? Some of you already know the answer, but let's run through an example.

Let me start with the simple example I've shared over the years. I'm simplifying here, but if you are a producer that can find a barrel (Bbl) of oil for $20, produce it for $10 and sell it for $50, you'd be pretty happy. This mathematical model allows for growth in reserves and production and a positive return on capital. First you should recall that an E&P company needs to at least replace each unit of oil it produces with a like unit, otherwise it is just depleting away it's existing asset base. Therefore, the sale of each unit must generate enough excess cash flow to go replace that unit at a cost equal or below that excess cash flow. Let's say your operating metrics look something like this:

1) Drilling and completion cost of your latest well: $6,000,000
2) Size of new reserve from this well: 300,000 Bbls
3) Finding cost per Bbl: $6,000,000 / 300,000 = $20.00 per Bbl
4) Producing life (expected reserve life) of well: 10 years (note that production is not linear, that it comes on at the highest rate it will acheive and will decline over time due to reservoir and pressure depletion)
5) Lease Operating Cost per unit (to flow it from well, maintain well ops, etc): $10.00 per Bbl
6) Sale price per Bbl: $50.00

Therefore, each unit produced will generate cash flow of $50.00 minus $10.00 in lease operating costs, or $40.00 per unit. But now you have depleted your asset base by 1 barrel, so what do you do? You take your $40.00 in cash flow and go invest it into a new drilling program. Since your finding costs are $20.00 per Bbl for a 300,000 Bbl well (assuming here you have a repeatable drilling program), you have the ability to replace your one unit produced with two more. Note that another way to look at it is that the $50 -$10 - $20 finding costs gives you excess of $20 which is "full cycle" free cash flow that allows you to create one new barrel through drilling. So don't be fooled by the $50 - $10 calculation, at first glance you might imagine I was ignoring finding costs. Full Cycle cash flow must be no less than zero to stay flat in reserves, or be positive to grow the company.

This is essentially how you grow the company. In this case above, your company would have the ability to replace reserves on a 2-to-1 basis. But note that producing one actual Bbl doesn't actually get you two because you don't drill wells that are just two Bbls in size. In the absence of borrowing money to drill, you actually need to produce enough of your existing reserve to get the money to drill the next well. In this case, you'd have to produce 150,000 Bbls (half your expected reserves for that well) before you had enough money to drill your next $6MM well…this might take a couple years. The sooner you get your cash back, the sooner you can drill your next well. This is why the first months and first year of production is important.

So let's assume you have 3 million barrel (3MM Bbls) of total reserves at the beginning of the example. You spent $60MM to develop those reserves and have total finding costs of $20.00 per Bbl, which are on your balance sheet as an asset. Your average reserve life is about 10 years, and for simplicity, lets say you are producing 300,000 Bbls each year (this assumes linear production and no decline but is not relevant for the example). You are therefore generating $40/Bbl in cash flow times 300,000 Bbls for $12,000,000 per year. You can use that to drill 2 new wells at $6MM each and come up with another 600,000 Bbls of new reserves. This would be considered a 200% reserve replacement ratio (600,000 Bbls new / 300,000 Bbls produced). But although you replaced 200% of what you produced, your underlying reserve base grew by just 10%:

3,000,000 Bbls beginning reserves
- 300,000 Bbls produced
+ 600,000 Bbls found
= 3,300,000 BBls ending reserves.

In this case, you grew your company's reserve base by 10% annually by achieving a 200% replacement ratio on production.

Of course, if you have a bad year and you spend $12MM in drilling costs and only find 300,000 Bbls of oil you find that your reserves did not grow at all. This is essentially the position many of the larger integrated companies find themselves in: it is very hard to grow reserves once you get to a certain size. The big guys tend to just replace production at a 100% rate, give or take a few percent. Those are not growth companies. Also note that industry-wide finding costs are likely to be in the $15-$20/Bbl range these days and anyone who can improve on that has a big growth advantage.

So…using the FASB 69 supplemental disclosures at the back of every public E&P 10-K:

1) look at annual finding costs (total capital expenditures for drilling / total change in reserves, adjusted for prior period changes)
2) Calculate operational cash flow per barrel produced (Rev - Op Cost) and full-cycle cash flow (Rev - Op Cost - Finding Cost). Compare Op Cash flow to Avg Finding Costs to determine CF per Bbl
3) Look at total reserve replacement (total new reserves / total production)
4) Compare across companies and over rolling 5-year periods (one year isn't a fair assessment period for a growing E&P company) and you will find significant differences that can lead you to asking the right questions about a company's value and ability to grow. Of course, history doesn't predict the future, but positive trends in a company's costs over time should tell you something about the type of reserves the company is chasing and how they are managing their growth. Consistent reserve replacement should be a sign of strength while highly volatile results may be cause for further investigation.

There are many nuances to these calculations which I won't go into here (for example, how to factor in annual reserve adjustments based on price changes and vs. technical reassessments, and the amount of PUD - Proven Undeveloped - reserves that any given company is booking along with their Proven reserves). Again, this example is intended to cover the basics for now. In a later post, I will show an example of the many inputs and calculations.

But now you should start to get pretty excited about a company that has finding costs of $10/Bbl, operating costs of $10/Bbl and is selling oil at $75+ per barrel. You will realize that the ability to grow reserves quickly and economically goes up exponentially when you have all the right cost structures and the ability to repeat drilling success in a given area. For those of you new to this, that is what the industry refers to a "resource" play…an area that has a known resource that can be accessed with existing techniques to result in known well outcomes that cluster around a statistical mean. Hence, the value of a Bakken oil well that I discussed in my earlier post becomes more important when repeatable with known economics. At the end of this year, when 10-Ks come out in April with audited reserve numbers, I believe we will see tremendous reserve growth in the Bakken players, with exceptional finding cost results and industry-leading economics.

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