eog discusses q2 results - bakken

transscript from EOG's Earnings call as it relates to their Bakken operations. Mark Papa comments... (also commentary regarding their shipments by rail from Bakken - i.e. how they solve the Bakken discount)

"I'll now shift to the Bakken Three Forks. 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 downspacing.

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."

"I'll now address 2 other EOG key differentiators: Crude-by-rail and sand plants. Our St. James crude-by-rail facility received its first Bakken crude oil shipment on April 15, allowing us to begin capturing the current $15 Bakken in LLS price uplift. We now have the capability to move our Bakken, Eagle Ford and Wolfcamp crude to either Cushing or St. James. Based on current differentials, the best NPV for our rail tanker fleet is to move our EOG Bakken oil to St. James and sell our Eagle Ford in the Houston and Corpus Christi markets. We expect our St. James facility to handle 50,000 barrels a day by June, increasing to 70,000 barrels a day by year end. We've provided guidance on our U.S. oil differentials relative to WTI for the second quarter in yesterday's press release.

For those modeling this net back benefit, remember that May will be a debugging month while we iron out the startup kinks, though likely to facility will run at intermittent capacity. We will not have the St. James facility fully operational for the entire second quarter, and not all of EOG's oil production will be sold to St. James. As market conditions and differentials change, we have great flexibility and can rapidly revise where we sell our production and how we get our production to market."



In the Q&A session

Relevant to the infill drilling for North Stockyard...

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And my follow-up question. Mark, you talked about the offset wells in Bakken increasing in the core part of the field as you've gone down from 640 to 320s. What exactly is going on there? And can you comment, was that a positive surprise for you?

Mark G. Papa

It was a surprise, yes. We didn't expect that. Our theory is that when we frac those wells originally, which would've been the 640-acre wells 4, 5 years ago that looking back, we probably didn't get as efficient of a stimulation as we might have liked and that we now are going to bigger fracs today than what we did back then, and that in the downspaced well, we gave a bigger frac and we probably stimulated some of that area even around the 640-acre original well. So that's kind of -- that's one theory that seems to make the most sense to me, that we would frac new rock around even the older well. So it's kind of an extra bonus, really, on there, which kind of cinches the case for the downspacing there, really. And the other thing it tells us is that clearly the 640-acre original spacing was too wide. So it makes it kind of a slam dunk case for the 320-acre spacing, and then it just opens the question about well is 320 still too wide? And should we investigate 160? So that'll be the next step we're look at too. On the spacing on both the Eagle Ford and the Bakken, clearly, what we did in retrospect is we started out with too wide of spacing and in both of them now, we're densifying the spacing, and we’ll densify it until we conclude okay, this is too dense of a spacing. And maybe in the Eagle Ford example maybe 65 acres is as dense as we want to go, maybe 40 acres is, we don't know. But I guess you live and you learn. The other way we could've done it is we could have gone to ultra-dense spacing to start, and then said this is too dense and then work the way to wider spacing, but we're doing it the other way. So we'll just see how it plays out, but we're concluded that the initial spacing was too wide, and we'll just work inwards until we conclude that now okay this is too close in terms of spacing.