In part 1, we discussed the premise for this blog series: how dropping oil prices will impact the Bakken. To answer that question, initial production rates and their role in determining if an operator will invest in a well or not, had to be explored. Following that, one needs to understand the link between dropping oil prices to a well and operational costs.
For well costs, it is important to note the phase in which the Williston Basin is currently in. Roughly 85 to 90 percent of new wells drilled in the Williston Basin are for infill drilling on multi-well pads. Much of the play has been proven and leases that allow operators to produce have been held by production. Wildcatting, or testing new areas, is not prevalent in the Williston Basin. Think of the Bakken as an effort to mine the oil—we know where it is—as opposed to exploring for it. As crude prices drop, this could be a good thing for the Williston Basin. Like most things, savings come in volume for operators. In the case of well costs, the more wells that are drilled per pad, the cheaper the cost for each well due to the transportation, design and logistics costs associated with bringing every single well online.
Other inputs to well costs, however, can drive the price up of each well even if it is part of an infill drilling program. The move to using higher than average sand volumes or greater water volumes can increase the cost of wells. Continental Resources is a prime example of that. The operator recently said its well costs were higher than previous quarters due to completion design changes. The question for every operator is whether or not the changes to completion design and investment in those new designs can produce an increase in hydrocarbon totals that net a profit in the 15 to 25 percent range, the magic profit number for many producers. The answer of course varies, and we have seen operators tweak their respective methodology to yield both positive and not so positive financial results and/or production number gains.
After well costs, there are operating costs. Operating costs also vary well-to-well and field-to-field. KLJ’s study highlights which fields in the Williston Basin produce the highest IP rates, which fields are most profitable and which areas produce the most water. Based on the water production areas, one can see an area that could be a point of concern for operators looking to cut operations costs. Wells that produce greater volumes of water require water disposal, an added cost that cuts into overall net profits that could be amplified if low oil prices cut into the overall profit for a given well. Current or future well sites that are not connected to an electrical grid, and are instead running or will run on diesel generators, for example, could also be a concern as the lack of power at a well site requires increased operating costs. Operating costs offer exploration and production companies the quickest way to cut back on spending.
The Relationship Between Crude Price and The Bakken, Part 1