Mr. Preston’s comments are spot on, and while it is still early in the evolution of the horizontal Niobrara, there are certainly reasons to draw parallels to the Bakken play in the Williston Basin in particular. Over the past few years, lease prices in the public forums (State of North Dakota and BLM sales) have gone through the roof, with isolated parcels (partial mineral interests under lands that are proximal to existing production) have exceeded $10,000 per net mineral acre. Recent prices for lands under which the State of Wyoming owns the minerals, all of which are shown on the website for the Office of State Lands and Investments for the State, have topped $3,000 per net mineral acre. Before you start counting the windfall, however, you should understand that a key determinant in the valuation of your interests is the geological analysis that is being made by the many different parties now acquiring interests in the play. The thing that makes this play attractive to oil and gas companies is the certainty that the Niobrara (and other source rock intervals) is present. HOWEVER, no one can state with any certainty that the minerals attributable to your property are going to be economically viable without actually drilling wells. A lot of parties are buying leases to speculate that prices, as they did in the Williston Basin and other areas around the country, will continue to increase and that they will be able to sell the leases for a nice fat profit. The leading operators in the play — EOG, Noble, Continental, Slawson, Anschutz, Anadarko and a few others — have specific areas that they are targeting based on a few key factors: (a) proximity to strong shows in the Niobrara and other zones as evidenced by production from vertical wells on or near to a property; (b) subsurface data from wells on or near a property which indicates that the Niobrara is sufficiently charged with hydrocarbons and also under sufficient pressure to be economically productive; © well data that shows that there are sufficient microfractures in the Niobrara reservoir interval to be able for a well to be stmulated with the latest in completion technologies — the multi-stage frac — which creates sizeable conduits for the hydrocarbons to get to the wellbore; (d) seismic or other data which indicates that an area may be subject to subtle features in the basement that might enhance the presence of natural fractures/microfractures as an indicator of possible reservoir quality rock; and (e) some combination of one or more of these factors. Each company has a staff utilizing different evaluation methodologies and the result is that different groups wind up focusing on different project areas within the broader basin and project area. The areas that are going to receive the highest lease bonus prices are the areas that have the best geological indicators, as well as the most competition for lease acquisition.
One of the things that I have experienced in the Williston Basin is that the best operators are not paying the most (and are usually closest to the least) initial bonuses for leases…they rely largely on word of mouth about the quality of their drilling and completion efforts to sell mineral owners on the notion that they are the preferred alternative in maximizing the value of the minerals by maximizing the value of the royalty derived from actual production. My experience is that this premise is correct — where economically viable production is found, the mineral owner usually receives multiples of the original bonus payments in royalties from production.
A few words about this concept of “economic viability” when viewed from an operator’s perspective: these wells are very expensive to drill and complete, and the profitability of any well is most often a function (a) of keeping lease acquisition costs down; (b) of keeping drilling costs down; © of keeping completion costs down; and (d) maximizing the production rate so that the revenues from the sales of production attributable to a well recoup the total investment for the well in the least period of time — the Bakken rule of thumb is 24 to 30 months, for example. Noble has published data to show that a typically drilled and completed horizontal well with a 4,000’-4,500’ lateral under a 640 acre spacing unit in the Colorado portion of the DJ Basin will average approximately 290,000 barrels of oil based on a total well cost of approximately $3,500,000.00, excluding the cost of the lease(s), so recoupment of the investment at the earliest possible date is critical for a company deploying these amounts of capital.
If you want to do something proactive to attempt to promote either leasing or other activity to derive the greatest value, you can either hire someone to compile the geologic data necessary to validate the value of your minerals, or attempt to find someone or some smaller company to assist you in marketing/developing your mineral interest. Of course, if their offer is right, I suppose it doesn’t matter how you derive value for your asset!
If you want to take some capital out of the perceived current value of your minerals, don’t be afraid to see if you can get a group to do a hydrid deal, where you receive some money up-front and a later payment based on different performance parameters. I applaud your effort to get better informed and wish you good luck with your acreage!