EOG’s Permian Trifecta

EOG’s Permian Trifecta

EOG is now starting to put something together in the Texas side of the Delaware Basin. According to the company’s recently announced fourth quarter/end of year results, EOG has “confirmed a new shale play” with the completion of two Wolfcamp horizontals, where they have an estimated reserve potential of roughly 800 MMBoe net. So what is so new about the Delaware Wolfcamp? The answer to that is nothing really; it is just starting to unfold for EOG. The company has been very active in Crockett and Irion Counties developing the Midland Basin Wolfcamp. However, these are the first horizontal wells to be completed in Delaware Basin Wolfcamp for EOG. In New Mexico EOG is currently targeting the Leonardian-aged shales, but also has an inventory of gassy, historic Wolfcamp wells.

Here are a couple of tables comparing recent well results and operational metrics for EOG in the Permian Basin:

Just in case you are curious as to whom the other Delaware Basin Wolfcamp players are, I’ve provided a map below. The permit data was pulled in from the Drillinginfo web application and dropped into 3rd party GIS software.

EOG is a top-tier operator and arguably the best on-shore unconventional operator at that. So it will be very interesting to compare these three Permian Basin plays with one very good operator as time progresses. It should be intriguing to discover what types of drilling and completion techniques will work best in each of these specific reservoirs and which will be the most economic. Please feel free to provide any comments on these topics below and as always check out our other Unconventional Reservoir Blogs for news and analysis provided by DI Analytics.

Bakken 4Q12 Top Operator Highlights Part 1

Bakken 4Q12 Top Operator Highlights Part 1

Instead of grouping all the top Bakken operators highlights into one blog, I’ve decided to break it up into two segments. This way I will be able to report on operators that have already released, rather than waiting until all have made their quarterly announcements. The fourth quarter is the most exciting for conference calls since results from the entire year are usually discussed. So far, it seems like the general trend has been reduction in drill time, transition to pad drilling, and pretty much an overall attempt to bring drill and completion costs down. On top of this, operators are increasing production rates and optimizing completion techniques. Here is a quick rundown of some of top Bakken operators that have released so far:

Hess:
• Net Production averaged 56 Mboed in 2012, up 87%
• 4Q12 net production averaged 64 Mboed, up 68% from 4Q11
• Drill and completion costs down by 30% during the course of 2012 from 13.4 MM to 9 MM/well
• Fourth quarter marked a transition to pad drilling
• Hess moved from a higher cost 38-stage hybrid completion design to a lower cost sliding sleeve
• EURs averaged between 550 – 650 MBOE
• Average 30 day IP ranged between 750 -950 boed
• 2013 CapEx for Bakken operations is $2.2 billion compared to $3.1 billion in 2012
• 2013 forecasted net production to average between 64 – 70 Mboed
• Plan to operate 14 rig program
• Hess plans to bring 175 wells to production throughout the year. Roughly 2/3 will target the Middle Bakken while the remainder will be Three Forks wells.

OXY:
• Reducing activity in the Williston Basin
• Costs for unconventional efforts too high

XTO (ExxonMobil):
• Acquired 100% of Denbury Resources’ Bakken assets which consist of 196,000 net acres in ND and MT, along with 15 Mboed.
• Acquisition increases ExxonMobil’s acreage to nearly 600,000 net acres
• Denbury acreage is high-performing Middle Bakken and upper Three Forks area
• 2012 gross Bakken production 33,000 barrels/day

Marathon:
• 410,000 net acres
• Running 5 rigs and 2 frac crews
• 4Q12 average net Bakken production was 35 Mboed, compared to 30 Mboed at YE 2011
• Brought 18 gross wells to sales in the quarter
• 4Q average drill time, spud to spud, was 27 days
• Marathon’s Bakken production averages 90% oil, 5% NGLs, 5% dry gas
• The company plans 65-70 net wells in 2013
• Switching to multi-well, pad-drilling which can take drill time to 13 days/well (avg. 19 days)
• Plan to drill longer laterals, which will offset shorter drill time savings
• Bakken well costs in $8.5 to $8.8 MM range
• 40% of takeaway by rail compared to only 5% this time last year

MDU Resources (Fidelity Exploration and Production):
• Plans to invest $200 million in the Bakken this year
• Plan to operate 3 to 5 rigs
• Current net Bakken production at 7 Mboed
• Well costs are currently at $7.5 MM
• Drill times are at 17 days
• In Mountrail and Stark Counties MDU is targeting the Middle Bakken with Three Forks potential
• In Richland County MDU is drilling the shale and so far only able to drill 640s. Still learning how to drill 1280s in respect to wellbore stability.
• Finding that the completion techniques used in the middle member are not turning out good results in the shale. The two wells they have drilled in Richland County will have to be recompleted, and then MDU plans to drill a couple more in the area this year.

Below is a map that I have provided, with DI Desktop, to get a spatial perspective of where these mentioned companies have wells drilled and producing. One can get an idea of where the highly producing wells are located. Also, I have added a chart showing recent production metrics for these operators at YE 2012.

For more information on all things Bakken related check out the Bakken folder in the DNA section of Drillinginfo. This is found in the “DI -Shared with All Users Folder.” Also, come back and visit the Bakken URB in a couple weeks to read up on Part 2 of the earnings call highlights.

Forest Selling Non-Core Gas-Weighted Assets

Forest Selling Non-Core Gas-Weighted Assets

Yesterday Forest Oil Corporation announced that they were selling South Texas properties.  The company didn’t give too much detail on the subject other than it has entered into a definitive agreement to sell all of its properties in South Texas, excluding Eagle Ford Shale oil properties, for after-tax proceeds of $375 million to an undisclosed buyer.  The properties produced 66 MMcfe/d (86% natural gas) in the third quarter last year.  As of December 31, 2011 estimated proved reserves were 272 Bcfe (85% natural gas) and generated roughly $60 million of lease level income in 2012.

Digging a little deeper, I knew that Forest has a decent sized position in the Eagle Ford, but I wanted to get a better idea of their asset portfolio down in South Texas.  Where are their wells, where are their leases, and is there anything in this divestiture that could be prospective to the condensate or dry gas windows of the Eagle Ford?  In order to get an accurate picture of all their properties, I used DI Desktop and Drillinginfo to create shapefiles of all of Forest’s currently producing wells in South Texas and all leases filed in the past 3 years then plugged it into QGIS software.

 

Come to find out, Forest does not have any property in the other windows of the Eagle Ford Shale.  So this was sort of a disappointing discovery.  However, the company has amassed a plethora of gas wells in deep, southern Texas targeting various reservoirs over the past fifteen years or so.  These conventional wells are what are on the table for divestment.  So it appears Forest is trimming some fat and using these funds to pay down some debt.  This makes for a wise business decision, but not so much for an exciting unconventionals A&D blog.  I’m looking forward to Forest’s Eagle Ford drilling plans in 2013.  As of September 30, 2012 Forest has 91,000 net acres in the play and 40,000 net in the central fairway of Gonzales County.  Forest is using the rig walking system for multi-well pad drilling, where a four-well pad can be drilled in 65 days compared to four single-well sites which can take about 84 days, according to a recent corporate presentation.  Completed well costs have been reduced by 8-15% to $5.5 – $6.0 million, versus a single-well approach.  So enhancing well economics is a huge focus in their developmental stage.

Keep track of other Eagle Ford operators and activity in the DNA folder repository of Drillinginfo. DNA is open to all Drillinginfo account members.

Drilling Info Names New CFO to Manage Strategic Growth Initiatives [Press Release]

Drilling Info Inc. has named Dave Piazza as its new Chief Financial Officer, charged with leading the firm through growth initiatives and raising capital to support expansion.

Piazza joins during a year that saw Drilling Info garner a $165 million equity investment. In 2012, the company also acquired Dripping Springs, Texas-based Wellstorm Development Inc., an information management and development company, and Grand Prairie, Texas-based County Scans, the premier provider of deep, digitized U.S. mineral ownership data.

“I’m excited to be joining Drilling Info’s management team. They are singularly focused on solving problems and creating opportunities for the benefit of our oil and gas customers,” said Dave Piazza, CFO, Drilling Info. “Drilling Info represents one of the great success stories in the technology sector right now, and the team has a great vision for the future.”

Prior to joining Drilling Info, Piazza most recently served as CFO for eight years with Reston, Virginia-based QuadraMed Corporation, a leading provider of healthcare technologies and services. Prior to QuadraMed, he worked in the emerging telecommunications and technology sectors, building businesses from the ground up to compete with incumbents.

“A driven leader, Dave offers unique insights into Drilling Info’s strategy and brings deep entrepreneurial and growth experience,” said Allen Gilmer, CEO and chairman of Drilling Info. “He understands our culture and values, providing a great perspective to the team.”

Piazza received his bachelor’s degree in Accountancy from the University of Illinois at Urbana-Champaign. He is a member of the American Institute of CPAs.

About Drilling Info Inc.

Drilling Info Inc. is the “BOSS” SaaS-based oil and gas business intelligence and decision support technology platform for the global upstream E&P industry, facilitating faster, smarter decisions. The company services more than 3,000 companies globally from its Austin, Texas-based headquarters, and has more than 400 employees on five continents.

For more information, follow us on Twitter @drillinginfo or “Like” us on Facebook at www.facebook.com/drillinginfo

Cline Shale Holds Enormous Potential

Cline Shale Holds Enormous Potential

The Cline Shale oil play lying at roughly 9,250 feet below the surface along the eastern flank of the Midland Basin could possibly be a key component for energy independence for the U.S.  The play area runs roughly 140 miles north-south and about 70 miles wide through Howard, Glasscock, Reagan, and Sterling Counties.  Click here for more information on Cline Shale rock properties from a previous blog.

Devon and Chesapeake recently reported impressive test well results.  Devon’s wells show the formation contains 3.6 million barrels of recoverable oil per square mile.  A rough approximation, taking into account the 9,800 square mile area of the Cline, indicates over 30 billion barrels of recoverable oil.  This exceeds both the Bakken and Eagle Ford by far.  The USGS estimates the Bakken Shale to hold up to 4.3 billion barrels of recoverable oil, and the Eagle Ford has estimates at as much as 7 to 10 billion barrels of total recoverable reserves.  John Richels, president of Devon, gave an expected type curve value of 570 MBOE for a Cline Shale well, with 85% being oil and NGLs.

I have pulled in some Cline Shale producing horizontal wells in the map below with Drillinginfo.  Here one can see some of the more oily producers versus the higher gas producing wells.

 

Laredo Petroleum, still in the early stage of development, has completed 33 gross horizontal Cline Shale wells, more than any other operator exploring the play.  Laredo has 142,000 net acres in the central fairway.  Apache Corporation has 6 wells planned to be drilled this year, but with roughly 520,000 net acres prospective to the Cline, holds more acreage than any other company.  Devon Energy is still in the testing phase of the Cline.  However, Devon does hold 389,000 net acres in the Cline, but has only vaguely reported encouraging initial results.  Other E&P companies include Exco, Firewheel Energy, Callon Petroleum, Chesapeake, Range Resources, among others.

Here is a look at top operator leasing activity over the past 36 months by record date using Drillinginfo. The play actually extends northeastward a bit more into Mitchell, Borden and Scurry Counties.  However, the central portion of the play has seen the most activity to date.

Considering the magnitude of this amount of resource potential one can only expect to see an even bigger issue of housing constraints, as seen in North Dakota and South Texas.  From Snyder down to Midland and everywhere in between, I would expect to see a lot of housing infrastructure development.  Local communities are worried that the construction will not happen soon enough.  Abel Deloera, Snyder councilman and owner of Deloera Realty, said he gets 10 to 15 calls everyday from people searching for housing, sometimes in tears.  According to Doloera, Snyder lacks betwen 400 to 500 housing units and there has been a huge increase in land value in the area.  It should be very interesting to watch this prolific liquids-rich play unfold.  For more information on the Cline Shale and other exploration hotspots, feel free to check out the Emerging Plays Unconventional Reservoir Blogs.

Continental Resources is still “King in the North”

Continental Resources is still “King in the North”

What’s the number one oil producer in the most prolific tight oil field in the U.S. up to these days?  Well, Continental was already the largest leaseholder in the Bakken and now with a recent acquisition to purchase 120,000 more net acres, the company has strengthened its leasehold to approximately 1.1 million net acres.  The deal, purchased from an undisclosed seller, is valued at $650 million and along with acreage also includes current production from the property at about 6,500 boe/d.  Continental plans to finance a portion of the acquisition by selling off non-core assets in Michigan, the Illinois Basin, and other areas not mentioned east of the Mississippi River for $125 million. Production from those properties being sold averaged roughly 1,100 boe/d in the second quarter of 2012.  Both of these transactions are expected to close by year-end.  In respect to this, the company does have a decent portion of acreage expiring next year.  Upon closing of the acquired Bakken asset deal it might be interesting to see if Continental renews any of the expiring acreage outside of their core areas.

 

Continental has clearly established themselves as the top operator in the play.  According to a recent investor presentation, the company contributes to roughly 10% of the rigs, 10% of leased acreage, and 13% of total production out of the Bakken.  Below is a chart with data pulled from DI Desktop just showing daily peak liquids production.

Continental currently has 19 operated rigs, down from 26 in the first half of this year.  Target EURs are about 603 Mboe for a 10,000 foot lateral and 30 frac stages.  Single well completed well costs average roughly $9.2 million and $8.5 million for ECO-pad wells.  For more information on single-well economics and other operator metrics visit the Bakken folder in Drillinginfo under the DNA heading.