Dave's Energy

Tuesday, October 04, 2011

What's a Bakken Shale well worth?

In and around energy conferences and among energy guys I hang around with, this question will elicit various responses, partly because there is no "one" Bakken Shale type well. The Bakken play continues to expand and wells vary depending on whether you are asking about the Middle Bakken formation or the lower Three Forks/Sanish formation, and also whether you are talking about the core of Montrail County, ND or the fringe out near the Montana border or into Montana or Saskatchewan. However, for my friends who are not constantly crunching numbers across all these play types, and for the students I work with on understanding the sector, I thought I'd share a very basic model for evaluating the Net Present Value of a single Bakken well. I'll call this a core Middle Bakken well. Using this, with some adjustments when required, you can make conclusions about the value of various companies producing and exploring in the area.

Thanks to the fine people at companies like Continental Resources, Whiting Petroleum, Brigham Exploration, Northern Oil and Gas, Kodiak Oil & Gas, and Triangle Petroleum, as well as the North Dakota Industrial Commission's Oil and Gas website it is fairly easy to find information on the production history of wells drilled in the area.

Companies have discussed in many presentations and press releases wells with initial production rates of 500 barrels of oil per day (BOPD), or 1,000 bopd, or even 2,000-3,000 bopd. With ever changing horizontal drilling and multi-stage frac techniques, the numbers continue to evolve, but with hundreds to thousands of data points now available, we can simulate our own well "type curve" based on what we know of these many existing wells. For those new to the subject, apologies for some missing assumptions, but you should know first off that all these wells follow a pattern of very high initial production with production rates that decline at a decreasing rate. That is, the production per day looks like a falling curve that flattens out over time.

Based on known data in the Bakken region, I will use the following as basic assumptions:

1) Initial production rate of 1800 bopd (ignoring associated natural gas production)
2) Average 30 day production (first month) of 700 bopd
3) First year decline of 55% from initial sustained 30-day rate
4) Decreasing rate of production decline through year 7 to get to an exit rate of about 100 bopd
5) $6 million cost to drill and complete a well
6) Lease Operating expenses and production taxes totaling $20 per barrel to produce
7) Local Oil Price sales realization of $65 per barrel (this takes into account transport costs, etc)
8) Expected life of well: 11-15 years
9) Expected Ultimate Recovery (EUR) of oil: 700,000 barrels per well
10) Discount rate of 10%

The production "Type Curve" looks something like this, which is just a graphic representation of the amount of well produced on a per day basis through time:

Here's a simple spreadsheet you can build to calculate this all yourself, with inputs shown in blue and calculated cells shown in black. Once you have created the average production per day based on annual exit rates, you can calculate the annual production, then apply a net cash flow number (realized oil price less cash costs) to get an annual cash flow, then discount that back for each year (CF / (1 + R) raised to the number of years out). Click on the image below to see it more clearly:

Please note that a few items are simplified here. For example, the cost of production is assumed to be perfectly variable ($20/barrel), yet some production costs are fixed and therefore will be relatively higher on a per barrel basis as the well gets older. It turns out this isn't a huge impact on valuation, however. Also, the "stub end" of production is truncated here for simplicity (the years beyond year 10) but it turns out, again, that these are less important to value than what happens in the first 5 years.

Results and things to note:

A) The NPV of a well is about $15.7 million with IRR of 100%, even at $65 oil
B) The NPV is about $22 per barrel ($15.7 MM NPV/ 700,000 barrels EUR) , indicating what reserves might be worth on a company's books and definitely what they would be worth in an acquisition.
C) Payback is under 12 months (although most companies will conservatively tell you 18 months - this is due to a mix of wells that may produce less than this modeled well)
D) If you change oil price to $85, NPV goes to $25MM per well ($36 per barrel), with 159% IRR and 6-9 month payback on investment.
E) If you change oil price to $45, NPV goes to $6MM per well ($8 per barrel), with 43% IRR and 24-36 month payback on investment.

So now when a company tells you they have 100 core Bakken wells to drill, you can have a thumbnail idea of value: $600MM cost to drill all those wells, with NPV of $2.2 Billion. SO you ask yourself: How many acres does it take to have room for 100 wells? At two wells per 640-acre section, that would require a lease position of 32,000 acres. Not a huge position for most companies. This means a lot of value can be created in a small area. It is important to note that many believe the ultimate development of the Bakken will see 6 wells per section, so there is even more value in good acreage, and even a small area can potentially be very valuable.

So there ya go...fodder for your next cocktail party chat regarding the value of a Bakken shale oil well. Disclaimer: don't take my word for it, read the 10Ks and presentations of all the companies doing the hard work up there.

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  • Dave -- Excellent post. Thanks for putting in the energy to do it. 700K seems a bit higher than the average number most companies are giving for EURs, and $6 million drilling costs is a bit lower, but that's the beauty of your spreadsheet -- they mostly work out to still have pretty good IRRs. ... We appreciate your expertise.

    By Anonymous Anonymous, at 12:09 PM  

  • I think you mean PV in this context and not NPV.

    NPV would be 100 x 15,670 = $1.567B

    PV = 100 x 21,679= $2.2B - excludes intial outlay of $6 MM


    By Anonymous Anonymous, at 4:26 PM  

  • I'm wondering how did you calculate the Gross Product?

    By Anonymous Anonymous, at 12:42 PM  

  • Dave:
    Thanks for this. Very helpful. A couple of questions about your assumptions:

    (1) To arrive at the $65/Bbl crude netback price, did you assume a differential to WTI and crude transportation costs. If so, what did you use. If not, where am I off base?, and
    (2)What goes into your $20/Bbl lease operating expense?

    By Anonymous Anonymous, at 4:26 AM  

  • In answer to the last three questions:

    1) the netback of $65 was calculated at the time using a differential to WTI and expected transport costs. Please note I wrote that blog entry in 2011. Th spreadsheet is intended to give you a method by which you can calculate value based on whatever YOUR current assumptions are.

    2) With regard to production costs, see comment #1. I typically use the average of the smaller producers based on a 4-qtr rolling lease op cost plus prod. taxes and gathering.

    3) Gross production is calculated as the average daily production multiplied by 365 days. So for year 1, if this well is producing 507.5 barrels per day for 365 days, that is 185,237 barrels for the year (i.e.: 185.2 mboe on the spreadsheet). Note that the 507.5 daily average is just the average of the entry rate of 700 barrels per day and the assumed exit rate of 315 barrels per day (which I get by applying a simple 55% first-year decline rate). Typical Bakken wells these days may have steeper decline rates but also often higher entry rates. That varies by region as well. Calculate accordingly.

    By Blogger David J. Anderson, at 1:29 PM  

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