From Newfield Conference Call -- The Bakken, North Dakota, USA

Link here.

To the Williston Basin. We've been behind in our Williston Basin program all year and have taken proactive steps to adjust course. Simply stated, we had expected to exit 2011 with net production of about 15,000 barrels of oil per day. And today, we're about half that rate. Our issues relate to weather, delays in the arrival of necessary services in the field and the result in inability to complete wells timely. Compared to our original guidance, the Williston Basin is down 6 Bcf. We've reduced our operated rig count, and we'll defer completions on more than a dozen horizontal wells into 2012. This is an obvious area for us to institute strict capital discipline and preserve our budget.

Our Williston issues are not related to the subsurface. We have great assets in the Williston that can provide some of the highest returns we have in the company. Our wells have performed extremely well once online, and we've demonstrated our ability to drill wells efficiently. There's a table in NFX that shows our recent well results. The recent tightness in the service market and the subsequent cost increases have forced us to better manage our investments in late 2011.

Later:

A question on the Bakken and on spending kind of aligned with that. The $11 million well cost, that seems high relative to even some of the other operators in that play now. Why are the costs so much higher?

Lee K. Boothby

Well, I think, first of all, I guess I would take issue with your comment on the well cost. We've put ourself out and compared our drilling curves and our costs against all the operators in the area. In each of the areas that we're active, I can tell you that we're very competitive as far as the wells that we're drilling. I will tell you that all our wells this year are proportionally much higher as a result of drilling the 1,000-foot laterals. Last year and even today, we can back off and drill a 4,000- to 5,000-foot lateral in the neighborhood of $7 million. Earlier this year, we were in an 8 5 to 9 3 environment. And we've seen that number go up to 11. Now the lateral lengths that we have today are between 9,000 and 10,000 feet. And I can tell you in the $11 million, there is some element of trouble cost that are built into that, that are a reflection of what we've seen in 2011. Now many of the costs that you historically see don't have trouble cost built into them. And in the environment that we're currently drilling today, you are far more likely to see increasing costs associated with that area than you are in areas where the rig count is much low. So that is a fully-loaded facilities, trouble cost, as well as drilling complete. Now as we look forward and you see some of the contracts that you have in place for stimulation services roll-off, and you see the basin moderate or more services come in, I fully expect that number will back off. But I'd be naive in thinking that if we would be seeing a $9 million well cost anytime soon.