With over eight thousand horizontal wells drilled to date in the Middle Bakken and Three Forks formations of the Williston Basin, the data set of drilling results and production histories would seem more than sufficient to draw conclusions with regard to expected drilling economics and investment returns in the play. Still, establishing a meaningful economic model for the Bakken often proves to be a challenging task. Three major factors contribute.
First, there is hardly a single "type curve" that one can use for the play as a whole. In fact, it would be appropriate to think of the Bakken as an assembly of many operating areas often with distinctly different geologic and petro-physical characteristics (depth; over-pressuring; the presence of specific pay zones; each pay zone's thickness and hydrocarbon charge; gas-oil ratio - just to name a few). As a result, decline rates and curve shape vary from area to area, often quite substantially. So does the cost of drilling and completing wells.
The situation is well illustrated by the slide from a recent presentation by WPX Energy (WPX), a Bakken operator with acreage concentrated primarily in the Dunn County (below). (Worth noting, WPX ranks various areas within the Bakken in accordance with the F&D cost, not the EUR.)
Second, operating techniques - including well and completion design - have evolved continuously over the play's history, rendering performance comparisons between different generations of wells complicated or plainly not meaningful. Lateral length, frac size, and the use of ceramic proppant versus sand are just a few of many factors that need to be taken into consideration. Moreover, well completion "style" differs, often substantially, from operator to operator. As a result, well performance - which reflects those differences in addition to the underlying rock quality - does not correlate perfectly with productive potential of the formation in each specific area.
Third, well performance and cost structure change as companies transition to pad drilling. Such transition is typically accompanied by inventory high-grading: as operators are no longer under pressure to drill every spacing unit to hold acreage by production, they have the ability to allocate capital solely to "sure bet" areas. As a consequence, on-going drilling results for operators who have transitioned to full development mode may be dominated by a small number of multi-well pads in carefully selected locations that may not be representative of the acreage as a whole. Simplistic drilling location math - (current NPV per well) x (well density) x (number of units under lease) = (value of operator's position in the play) - simply does not work.
Perhaps the greatest challenge of all is the statistical nature of horizontal shale wells. The shape of actual decline curve varies from well to well, even within relatively small areas. Initial production (IP) rates are notorious for being a misleading indicator of a well's future economic value.
With all these uncertainties in mind, drilling statistics summarized by WPX are quite valuable and deserve a close review.
The chart below from WPX's presentation provides a performance summary for wells drilled in the Middle Bakken formation by various operators since January 2011. The slide shows average cumulative production per well over the first 180 days and 365 days by operator. The samples include only wells with laterals of 5,000 feet or greater.
· The 180-day performance sample covers 26 operators with at least 15 wells producing for at least 180 days. The 1,828 wells included in the sample had average cumulative production of ~57,200 barrels of oil in the first 180 days.
· The 365-day performance sample includes 23 operators with at least 10 wells producing for at least 365 days. The 1,132 wells in this group had average cumulative production of ~92,100 barrels of oil during the first year.
(Source: WPX Energy September 2013 Investor Presentation)
The chart reveals several notable trends:
· As one might expect, actual average well productivity across the play is quite different from well results typically highlighted in press releases and investor presentations. Still, the "average" well in the play appears solidly economic, although drilling returns are not overwhelming.
· The ranking is led by Independents. At the top are the "usual suspects:" EOG Resources (EOG), Slawson Exploration (private), Whiting Petroleum (WLL), Kodiak Oil & Gas (KOG), Newfield Exploration (NFX) and QEP Resources (QEP). (EOG would likely be at the top of the chart if well results were adjusted for lateral length.) WPX, the provider of the analysis, ranks very strongly as well and is leading the chart.
· Major Oils trail behind smaller Independents: Conoco (COP), Hess (HES) and Marathon Oil (MRO) are in the middle of the pack, while Exxon/XTO (XOM) and Occidental Petroleum (OXY), surprisingly, trail far behind the others. Statoil (STO) (former Brigham) is the sole exception, ranking among the best.
For all the reasons mentioned in the beginning of this note, average cumulative production data is not sufficient to derive average EUR per well (because type curves vary area to area). However, using a variety of decline curve models, the average metrics shown on the chart above seem to be consistent with a EUR range of 500-600 Mbo per well. The result is in fact encouraging, as it implies robust economics for the majority of the wells in a $100 per barrel WTI environment.
To put this data point in perspective, it may be instructive to compare the metrics from WPX's analysis to those used, for example, by Kodiak Oil & Gas in their guidance. Kodiak's model well economics are summarized on the slide below. (It is interesting to note the difference between the cumulative first-year production volumes implied by Kodiak's 750 Mbo and 850 Mbo cases versus the actual first-year cumulative production for Kodiak's wells shown on WPX's chart).
(Source: Kodiak Oil & Gas September 2013 Investor Presentation)
Using Kodiak's model as a starting point, I derive a PV-10% of $13-$18 million for an "average" Middle Bakken well (before subtracting the well cost), assuming 500-600 Mbo EUR range and $85 per barrel WTI. The Present Value declines materially if higher (e.g., 15%-20%) discount rates are used.
Kodiak uses a $9.5 million drill & complete cost. Clearly, Kodiak's well cost is higher than the average for the play (Kodiak operates in the deep, over-pressured part of the basin). Using a lower average well cost assumption of $7.5 million for the play as a whole, the "average" well remains profitable, although returns are substantially lower than those shown on Kodiak's slide.
As a simple check, I calculate cumulative 365-day netback from the average well with a first-year production of 92,100 barrels of oil, which amounts to $5.0-$5.5 million (includes natural gas revenues; assumes 20% royalties and $85 WTI). Payout period for such well comes out in the 2-year range (which would be viewed as acceptable, albeit not excellent, by many operators).
Taking into consideration operating leverage, the difference between the top quartile and bottom quartile wells is quite significant. Even a seemingly small variance in first-year cumulative production may have a massive impact on the well's NPV. Let's assume, for illustrative purposes, that a well with an EUR of 600,000 barrels of oil has a PV-15% value of $5 million to the operator. An identical well with a 500,000 bo EUR may have PV-15% equal to zero, and a well with 400,000 bo EUR may be money-losing once cost of capital is taken into account.
While companies' press releases and investor presentations are dominated by initial production rates data, cumulative production metrics have an obvious advantage as a measure of a well's economic success. The metric is particularly relevant if the investor's hurdle rate is high.
While the statistics provided by WPX fall somewhat short of what is often used in operators' model curves, the data nonetheless lends support to a positive outlook for the Bakken. Drilling returns in the play will likely improve from their already solidly economic levels as companies transition to pad drilling and high-grade their inventories. The returns should also benefit from optimized costs, operating efficiencies, and continuously improving well productivity.
Disclaimer: Opinions expressed in this material by the author are not an investment recommendation and are not meant to be relied upon in investment decisions. The author is not acting in an investment advisor capacity. This is not an investment research report. The author's opinions expressed herein address only select aspects of potential investment in securities of the companies mentioned in the text and cannot be a substitute for comprehensive investment analysis. Any analysis presented herein is illustrative in nature, limited in scope, based on an incomplete set of information, and has limitations to its accuracy. The author recommends that potential and existing investors conduct thorough investment research of their own, including detailed review of the companies' SEC filings, and consult a qualified investment advisor. The information upon which this material is based was obtained from sources believed to be reliable, but has not been independently verified. Therefore, the author cannot guarantee its accuracy. Any opinions or estimates constitute the author's best judgment as of the date of publication, and are subject to change without notice.