Notes From EOG's 2Q15 Conference Call -- August 7, 2015

In a long note like this, there will be factual and typographical errors. If this information is important to you, go to the source. This is not an investment site. Do not make any investment or financial decisions based on what you read here or what  you think you may have read here. 

Highlights from EOG's 2Q15 earnings / conference call transcript with regard to the Bakken operations only.

Net resource potential in the Bakken/Three Forks:

• 1 billion boe ("just over")
• represents 2.5x EOG's original estimate of 420 million boe
• remaining drilling activity increased from 580 to over 1500 net drilling locations
• 760 million boe remaining; decades of drilling
• premier asset
• [760 million / 1500 = EURs of 500,000 boe]

EOG has split the Bakken into two categories: Core and Non-Core 

• main focus will be on the Core Bakken in the near term

Core Bakken

• returns competitive with Eagle Ford and the Delaware Basin
• includes acreage in EOG's Bakken core and Antelope extension
• 120,000 net acres
• 590 net drilling locations
• 360 million boe: remaining net resource potential (360/120 = 3,000 boe/acre)
• 10 years of drilling

Non-Core Bakken

• Bakken Lite, State Line, Elm Coulee (Montana)
• non-core acreage "will be very economic even with low oil prices"
• 110,000 net acres
• 400 million boe (400 million / 110,000 = 3,600 boe/acre)
• 950 net drilling locations
• decades of drilling 

Riverview 102-32H, first Bakken well in the Antelope extension using high density completion

• maximum rate: 3,395 bopd
• 6 million cfpd
• with an average rate of 2,760 bopd for July, 2015, this short 4,300' lateral will be the highest rate ever recorded for the Bakken or Three Forks
• "EOG excited to continue applying high density completions throughout the entire play"

Completion costs in the Bakken

• $7.1 million for a 8,400' treated lateral
• represents a 20% decrease in well costs from 2014
• most savings due to efficiency gains, not vendor cost reductions
• sustainable over time
• drilling times: averaging 8.2 days spud-to-TD for a 8,400' lateral
• record drilling time for EOG: 5.6 days

Completion efficiencies

• 10 completion stages per day (up from 4.5 stages per day in 2014)
• plug drill out times have been cut in half since 2014

Cost savings not limited to CAPEX cuts

• added infrastructure this year in Bakken core: results in dramatic LOE reductions
• 2Q15 LOE is down more than 25% from 1Q15

Miscellaneous

"The first one is, we continue to drill our laterals in better rock. We're drilling -- we are taking a lot of time and effort, picking out the best quality rock in each one of these plays and keeping the lateral in that longer. And then and to execute that well is very important. And when we do that, we now are doing a much better job with these high density fracs and better distributing the frac along the lateral, connecting up more of that good rock. And it certainly lowering our decline rates over time and that makes it easier to grow production."

"Really, even if oil stays where it is right now, we are going to go ahead and move forward in a pretty aggressive fashion on that DUC inventory in the first part of the year. That would be the highest return decision that we could make with our capital. And so we will be starting completion fairly aggressive on these DUCs early next year."

"We are set up so well with the DUC inventory that even with the low prices we would have enough cash flow to keep production flat."

"I think next year, Pearce, what we are saying is that even with the minimum, even with the low-price cash flow scenario the highest return investment we could make in the company would be to begin completing those DUCs and complete those DUCs earlier in the year versus spending that money on other things. So the quality of these DUCs is very high quality. So we have infrastructure in place. So that would be the highest return place to put the money."

In the Eagle Ford: "We have about 3.2 billion barrels of recoverable oil out of 7200 locations. That's an average of about 40 acre spacing."

[Wow, wow, wow -- I said this a long, long time ago in the blog.] "So we used to think, it has really been a shift in thinking, we used to think that these big fracs just connected up a lot of rock both laterally and vertically, but as we go forward and we change the design and we get more data we become more convinced that the frac is just, especially these high density fracs is really most effective very, very close to the wellbore. So that is really helping to boost our confidence and that we're going to add additional reserve potential going forward."

With regard to "radial separation," see these two posts:

• September 22, 2014
• October 17, 2012