Past articles in this series show where the Bakken is headed in 2013 and beyond.
Operators have done a great job, as they have developed pad drilling, zipper fracs, and pressure pumping techniques that not only have improved EURs, but also reduced costs. Companies have turned ideas into reality, and this is only the beginning.
Operators are getting more proficient, as the first quarter was spent drilling and not completing wells.
This is building an inventory, and now that the weather is nice we should see a large number of pad completions turned to sales in the third quarter.
Most operators are using two mile thirty stage laterals with large amounts of sand and ceramic tails. Better results are being seen from companies using more water and proppant. As the source rock is better stimulated, it will take more of both to fill in the fractures and keep crude flowing to the well bore. In my [previous] article, I covered EOG Resources (EOG). Its comment about Bakken rate of return could prove to be a turning point for this play. EOG is seeing returns in its Bakken wells that rival the Eagle Ford. These are triple digit returns, and more importantly show us that EOG's technologies and not geography are the reason for its outperformance.
From earlier posts, Parts I - IV of this series. Part IV.
Well costs continue to head lower. Most operators are reporting well costs decreasing 20% to 30% year-over-year. The unusually late winter in North Dakota forced some to put off completion work until the second quarter and just focus on getting wells drilled.
This is much more convenient now that pads production looks to increase exponentially over 2012. Companies like Kodiak put its mobile rigs to work punching holes. Since there was little to no completion crews to worry about, Kodiak didn't have to worry about time frames and how that would affect fraccing. Once the drilling is completed, the completion crew will zipper frac the wells. This can decrease times by a third. This coupled with lower oil service costs across the board, increase rates of return to levels that are much more economic.
Drilling in the first quarter threw analyst projections off as costs were higher as more drilling work got done, but very few wells were put to sales. I am expecting some very big top and bottom line numbers in the third quarter of this year.An incredible amount of information in this post, again, as usual.
From an earlier post:
Part I and Part II were linked here.
The first quarter has turned out to be much better than expected in the Bakken. Most operators spent time drilling from pads, which was a good thing as the winter lasted longer with more snow than originally expected. Pad drilling requires that all the wells be drilled before completion work begins. Batch drilling saves time and money.
Zipper fracs allow multiple wells to be fracced at the same time, which also lowers costs. The larger percentage of drilling vs. completion work means less production began in the first quarter. This did lower revenues, but more importantly, is the beginning of a new dynamic in the Bakken and at other basins in the United States.
Completing multiple wells with in a short time frame means production will be very high at those times. This means some quarters will have high revenues and EPS while others could be very low. This lumpy production will provide buying opportunities in the first and second quarters of the year. In parts one and two of this series, I discussed how the Bakken operators continue to benefit. Part 3 also touches on these points, but more importantly, starts with Oasis, which blew the doors off estimates.Cost of wells is well below $10 million.
Huge amount of information regarding Oasis.
With regard to COP:
Now the Eagle Ford, Permian, and Bakken have higher margins than the average of all of Conoco's production combined. This shows the economics of shale liquids are very good. Conoco's WTI/Bakken differentials are minus $5, and the Eagle Ford is plus $5. Even with well cost improvements in the Bakken, the Eagle Ford continues to be a better overall play.Costs for OXY USA wells has come down significantly:
Occidental is realizing improved well costs throughout all of its U.S. acreage. From 2012 to 2013, the Williston Basin has seen a 32% decrease. This was the best percentage of all U.S. plays for Occidental. Its drilling program is now planned months in advance. This not only decreases costs associated with downtime, but it has been able to decrease the number of hours needed to complete the wells. It has decreased the number of strings of casing. It has switched its cemented liners for slotted liners. Occidental is optimizing water usage, by using flow back-end or produced water on completions. Stimulation contracted costs are also headed lower. Four months ago, Occidental Bakken well costs averaged $10 million. Today the average is $8.2 million with a goal of $7.5 million. In 2013, it will run 6 to 7 rigs.