David Anderson, retired Hedge Fund manager and Director of Energy Research of Palo Alto Investors, recently published a great article expanding on
how to value an oil well in the Bakken, an area attracting a fair amount of
attention lately, with its growing amount of proved oil reservoirs and production
capacity. You can find the article
here:
The advances in drilling techniques and technology (i.e.
horizontal drilling, hydraulic fracturing, infill drilling and other advanced
recovery techniques) have contributed to the increase in U.S. oil production, something that hasn't happened in quite some time now.. The Bakken shale oil formation, with plenty
of growth potential and room for further exploration, has become a highly
profitable region for E&P companies.
Below is an excerpt from a WSJ interview with Harold Hamm, the
CEO of Continental Resources, regarding how much oil the Bakken is estimated to have:
How much oil does Bakken have? The official estimate of the U.S. Geological Survey a few years ago was between four and five billion barrels. Mr. Hamm disagrees: “No way. We estimate that the entire field, fully developed, in Bakken is 24 billion barrels.”
If he’s right, that’ll double America’s proven oil reserves. “Bakken is almost twice as big as the oil reserve in Prudhoe Bay, Alaska,” he continues. According to Department of Energy data, North Dakota is on pace to surpass California in oil production in the next few years. Mr. Hamm explains over lunch in Washington, D.C., that the more his company drills, the more oil it finds. Continental Resources has seen its “proved reserves” of oil and natural gas (mostly in North Dakota) skyrocket to 421 million barrels this summer from 118 million barrels in 2006.
Looking further into the topic of valuing oil reserves I
came across another interesting publication, written by Rhett Campbell. The
article is titled, “Valuing Oil and Gas Reserves,” and is a bit broader than
the one written by Dave Anderson, but informative nonetheless. Rhett Campbell discusses
some of the main components that go into valuing an oil reserve. Below is an excerpt
discussing proved reserves, which are generally one of the most important types:
The category of proved reserves, occasionally called P-1 reserves, is generally broken down, at a minimum, into four subcategories:
- Proved developed producing (PDP) reserves are those for which the well is completed, and the reserves are currently being produced. This is the most valuable category of P-1 reserves because volume, pressure, and production data are readily available and generally accurate.
- Proved developed non-producing (PDNP) reserves are those for which the well-bore exists and the reserves are identified but are not currently producing for some reason. In this category, the reserves can be produced by either turning on production or accomplishing a mechanical repair operation. The significance of this category is that no additional capital expenditure within the well-bore is required, though expenditures may be required on the surface.
- Proved behind-pipe (PBP) reserves are those for which a reservoir different from the one currently producing but accessible through the same well-bore has been identified. However, because the operator must conduct operations (such as perforation and fracture stimulation) in a different zone, there is greater risk that the PBP reserves may not be recovered.
- Proved undeveloped (PUD) are the lowest category of proved reserves and the least valuable because a new well-bore is required to be drilled and completed, with accompanying risk, to recover the value. Exploiting these reserves requires the most capital investment and entails the greatest risk.
You can find the full article here:
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