How Big is the Bakken?

By Mobile Guru

Recently I've written a couple articles explaining why I believe Northern Oil & Gas (NOG) is The Bargain of the Bakken, specifically comparing their metrics to those of Oasis (OAS) and Kodiak (KOG) to demonstrate why I believe Northern provides a lot more value for your investment dollar. This article will focus on a topic of keen interest to all oil & gas producers with property in the Williston Basin (commonly referred to as “The Bakken”), but particularly to those that are exclusive to, or have very heavy exposure there, including Continental Resources (CLR), EOG Resources (EOG), Whiting Petroleum (WLL), Oasis Petroleum (OAS), Kodiak (KOG), Triangle (TPLM) and my personal favorite at current prices, Northern Oil & Gas (NOG).

The Bakken is commonly considered the largest deposit of hydrocarbons in the Western Hemisphere, producing large quantities of very high quality light, sweet crude with high production levels of oil relative to natural gas. There is virtually zero dry hole risk and, in my opinion, huge potential for growth as estimates of the size growth both in area and in number of layers that can bear oil on an economic basis and as technology continues to advance, enabling producers to extract a higher percentage of the oil in play.

The Bakken is just one layer of oil bearing shale in the Williston Basin, and in recent years the Three Forks has been identified as another layer that produces economic quantities of oil and gas. Recently, in earnings calls and presentations, Continental Resources has disclosed that they have discovered 3 lower benches (layers) of the Three Forks that have shown very impressive early results; this discovery may increase the estimated amount of oil in the Williston Basin by 61% or 323 billion barrels of oil!

From Continental's Q4 2011 earnings call:

Harold Hamm (CEO & Chairman): “The latest game changer is the Three Forks lower benches. We've literally found an additional oil saturated reservoir in the Bakken that again, makes this world-class oil play bigger and better.”

Jack Stark (Senior Vice President for Exploration): “Continental acquired 6 cores of the entire Three Forks formation in 2011 and discovered there were up to 3 additional layers within the Three Forks formation. The significance of this discovery, and what makes it such a game changer, is that the volume of oil in play for the field almost doubles with these added reservoirs.”

“Based on our estimates, the oil in play now stands at around 900 billion barrels of oil versus our previous estimate of 577 billion barrels of oil. This in turn should ultimately translate into more technically recoverable reserves for the field.”

Stark went on to talk about the first two test wells that had been drilled. I think this is critically important in understanding the economics and long-term promise of the Williston Basin. A typical well can have a 6 month payback, with subsequent production largely going straight to the bottom line. But some estimates were that only 4% of the oil in the Williston Basin would ultimately be recovered. If advancing technology and ongoing exploration and discovery continuously increases that number, think about what happens to the value of the companies that control large amounts of acreage in that area!

This makes Continental's Q1 2012 earnings call all the more interesting. Read the following excerpts from Jeff Hume, President and COO:

“We are very pleased with the performance of our first 2 second-bench Three Forks producers, the Charlotte 2-22H and the Sunline 11-1. The Charlotte has produced 64,000 barrels of oil equivalent in 5.5 months and the Sunline has produced 48,000 barrels of oil equivalent in 2.8 months, and both wells continue to produce in line with the typical first-bench Three Forks producers. It looks like we're going to average around 650,000 EURs from early data, from early curves. So it looks very strong right now.”

“By year end, we plan to drill 8 additional wells to test not only the second bench of the Three Forks, but also the third bench as well. Our first third-bench well will be drilled in the 1,280-acre Charlotte unit. This well will be located 0.5 mile east of the Charlotte 2-22 second-bench producer and 660 feet east of the Charlotte 1-22 Middle Bakken producer. In addition to this third-bench test, we also plan to drill a first-bench Three Forks well between the 1-22 Middle Bakken well and the 2-22 second Three Forks well. When finished, this will be the first 1,280-acre unit in the play with wells completed in 4 different members of the Bakken petroleum system. We'll approve or disapprove that there's interference between those horizons. Right now, we don't believe there is, but we're going to do the work, spend the money to do that. I believe we just have a larger petroleum storage system than we previously thought, and the reserves will increase as we get that data in hand, and that will be later this year.”

“We also have a 320-acre development project underway for the Middle Bakken and first bench of the Three Forks. The Midnight Run project, as it is called, consists of 3 Middle Bakken producers and 3 Three Forks producers within one 1,280-acre unit. The wells in each horizon are spaced 1,320 feet apart, with the Middle Bakken wells offset 660 feet from centerlines of the Three Forks. These wells began producing in the first quarter with average IPs of 1,300 barrels of oil equivalent per day per well. Interference testing is underway, and results will help guide future drilling density for the play.”

When asked about where they will spend their $550 million CapEx increase, Hume responded “it's all entirely going to the Bakken.” (They produce in the Niobrara/DJ Basin, the Anadarko Woodford and the Bakken.) He added,

“we're obviously participating in all the acreage sales in our key plays, mainly the Bakken. Right now, we're very concentrated, very focused on consolidating acreage in the Bakken.”

So we have an $18 billion world class oil & gas producer at the forefront of pushing the envelope on maximizing the efficiency & productivity of an elephant oil & gas reservoir. They believe these 3 new layers will increase the amount of recoverable reserves 61% and they believe at least 6 wells can be drilled in a double section (3 to the Bakken and 3 to the Three Forks) and are putting their money where their mouth is by devoting their entire CapEx increase to the Williston Basin and by participating in all the acreage sales there.
Meanwhile, here are comments made by Mark Pappas, Chairman & CEO of EOG Resources, on their recent conference call:

Each of our 2011 quarterly calls had a business-as-usual tone for our Bakken Three Forks asset, even though we continue to be the largest Bakken oil producer in North Dakota. However, we've recently generated exciting and very significant results in 3 different parts of the play, indicating we have more potential upside and growth opportunities than we've previously indicated. The 3 focus areas are: First, in the last quarter, we mentioned early success in our partial core area with 320-acre downspacing compared to our original 640-acre spacing. We recently drilled 3 additional 320-acre downspaced wells, and all are successful with IP rates ranging from 992 to 1,393 barrels of oil per day. Working interest in these wells vary from 51% to 61%.

Additionally, production from the offsetting original 640-acre wells has doubled after the downspaced won [ph] after completions. The typical 640 acre well that had been online 4 to 5 years was producing 100 to 200 barrels of oil per day before the downspaced well was drilled, and is currently making 200 to 400 barrels of oil per day. This gives us production gain from both the new infill wells and the older producing wells. Based on these results, we'll implement 320 acre downspacing throughout our core area, and we'll also test 160 acre down-spacing.

In our Bakken Lite area, our original development plan was on 320 acres. And by next quarter, we'll have some 160 acre downspacing results.

In summary, the downspacing is working and the reserve impact will likely be larger than the 50 million net barrels of oil we indicated on the February call.
Second, we continue to achieve excellent results in our Antelope Extension area, which is 25 miles southwest of our core area. Both the Bakken and Three Forks are productive in this acreage. We've recently drilled a group of Clarks Creek wells. 4 wells were drilled in the Three Forks formation and had IP rates of 926, 1,393, 1,455 and 3,415 barrels of oil per day, plus 1 million to 3 million per day of rich gas. A Bakken well we recently drilled in this same area had an IP rate of 2,300 barrels of oil per day with similarly associated rich gas. We have 100% working interest in all these wells. These results are better than we expected.

Third, in Far Eastern Montana and Western North Dakota in our Diamond Point and Stateline areas, we've recently completed 7 wells that IPed at rates between 540 and 1,100 barrels of oil per day. We have an average 63% working interest in this area. All 7 wells have high rock quality that we expected, and this opens up a brand new large development area for us where we have identified over 200 drilling locations. Additionally, in late April, we commenced 2 waterflood pilots in our Core Parshall Field to try to improve our current approximately 8% recovery factor and we expect to have preliminary results by year-end 2012.

In summary, we're much more excited than we were a year ago about our remaining Bakken and Three Forks potential. The Chairman & CEO of a $33 billion company which happens to be the largest oil & gas producer in the Bakken and has major interests in 3 other fields has just said that they're much more excited about the Bakken given recent experience with how close they can drill wells and still have large production from the new wells and double the production of the existing wells!

As I stated earlier, the Bakken has virtually zero dry hole risk and, in my opinion, huge potential for growth as estimates of the size of the field grow both in area and in number of layers that can bear oil on an economic basis and as technology continues to advance, enabling producers to extract a higher percentage of the oil in play. Continental Resources has just stated that they are having impressive early success with three newly discovered layers that appear to have economic quantities of oil and that they are decreasing the amount of space between wells while still getting impressive results. EOG is also downspacing their wells and expanding their view of the size of the field. Drilling wells to several different layers or closer together increase the ability to achieve large cost savings by perhaps using the same wellbores or at least by using the same drilling pad. In essence, probably the 2 best of breed producers in the Bakken have just materially increased their view of the size of the field, the number of oil bearing layers in the field and the number of wells that can be drilled within a given area. I believe that trend will continue for many years, if not decades to come.

In the past couple weeks, I've shown why I believe Northern Oil & Gas (NOG) is the Bargain of the Bakken and how it is inexpensive compared to two other Bakken players. Given recent developments out of Continental and EOG, all the Bakken producers may well be substantially undervalued and Northern (who is involved in many of Continental's and EOG's wells and acreage), is all the more compelling!

The following is a guest post by fellow investor mobile guru, whose interest lie within the mobile revolution, start-ups & IPO's, and intellectual property. Production, acreage and other metrics were taken from respective company press releases, enterprise value data from Yahoo Finance.

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