Replies to This Discussion

Permalink Reply by Craig Wascom on May 2, 2013 at 14:43

Hi Joe,we leased Jan. 2011 for $350 in Pointe Coupee

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Permalink Reply by a on May 2, 2013 at 2:19

Attached is the lease expirations

Attachments:

• D__webdownloads_Anadarko_02Land_01 Land Overview[1].pdf, 3.5 MB

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Permalink Reply by Skip Peel - Mineral Consultant on May 2, 2013 at 2:30

Thanks, a.  Appears to be sufficient time for an operator to perform some exploration before they have to pull the trigger on most of the extension options especially in Medusa.  Since lease terms don't seem to be a negative it will be interesting to see who is interested in taking advantage of what I suspect would be a pretty cheap entry price.

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Permalink Reply by John Matherne on May 2, 2013 at 3:22

I was just wondering why a company would lease up so much land and only poke a couple of holes in it.

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Permalink Reply by Skip Peel - Mineral Consultant on May 2, 2013 at 3:32

Happens all the time, John.  Aggressive operators who wish to explore a potential resource play generally lease over a wide area.  Their strategy is to buy their leases in such a way that they discourage competition form other operators.  See the Brown Dense Group discussions where Southwestern Energy bought ~560,000 acres of leases and has yet to drill a commercial well.

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Permalink Reply by GoshDarn on May 2, 2013 at 4:42

I know my South Louisiana friends aren't too happy to hear about this downplay in the TMS, in that a number of the landowners whom I know still have leases that haven't been drilled.

But at least they got a little bit of bonus money (ahem). 

Of course, there is somewhat of a silver lining for us landowners in North Louisiana.

APC's aggressive approach in regards to the Haynesville Shale (and other formations in the NE La. fairway) . . . sorta bodes well for those under lease to such a savvy operator . . . since one would assume that APC will now have less S. La. distractions and stronger logistical resources to pursue N. La.

Plus, the secondary good news about APC is that their land-office personnel are quick to return phone calls.  Those are some sharp pencil pushers, to say the least.

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Permalink Reply by Joe Aldridge on May 2, 2013 at 19:11

GD,

I don't know where the TMS thing got started other than Jay. From the first pre-conference meeting on unitization it was clear to me that Anadarko's only interest was the Austin Chalk and they were using drilling techniques and technology that were not compatible with the chalk.They are including the reference to the TMS in this case for the purpose of the sale of their leases. Them bailing does not in any way affect the viability of the TMS and those that have a true interest in drilling and developing it hopefully understand that. If this means that they are freer to drill the HA then that's great. At least they won't be screwing things up down here any more.

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Permalink Reply by GoshDarn on May 3, 2013 at 10:03

I hear you, Joe.  

And if there's anything I've learned over the many years that my family has been leasing in N. La., going back about 100 years . . . is that the future depends on the drill bit and the proper application of technology (with the technology always changing).

And the more I learn, the more I realize how truly complex it all is.  I so regret not having had more discussions with my 2nd cousin back in the early '70's (i.e., a guy who was a top La. geologist).  His credentials were impeccable.  Sharp mind.  But my focus was on others things way back then.  Dumb me.   

Your insight is always appreciated, Joe.  Plus, it's your honest intent to help others that truly makes you a solid GHS member.

 

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Permalink Reply by John Parker on May 2, 2013 at 12:46

ShaleGeo:

In response to your comment that:

“Not good news for the TMS.  For a company with the market cap of Anadarko to bail out via an online auction, they must have determined that the play will not end up being economic.” (Underline added for emphasis)

I believe you are jumping the gun at this time by implying the whole TMS play will not be economic based on what Anadarko is doing. Additional data paints quite a different picture than can be observed from watching Anadarko’s performance and decisions.

Maybe the more correct analysis and statement of the current TMS play status at this time is that the deeper portion of the play which Anadarko and Devon leased the majority of their TMS prospective acreage in, has been determined by them, that the play will not end up being economic at this time.

However, the shallower updip window of the play from approx. elevation 11,000 to 12,500 has had some excellent production as good as or in some cases better than Bakken and Eagle Ford wells and appears to be close to being an economically viable commercial success (per EnCana & Goodrich recent statements & released data).

Currently EOG is continuing to infill lease in Avoyelles and EOG, EnCana and Goodrich all continue to drill and permit additional wells in the updip portion of the emerging TMS play.

Just as occurred in the early days of the Eagle Ford by some of the early Operators, it appears that Devon and Anadarko staked out their position too deep in the play.  Too Bad So Sad for all involved in that.

Also, keep in mind that judging “market cap” as a measure of “smarts” can be fundamentally flawed. Just ask IBM and Bill Gates about that subject. Biggest corporate blunder of the 20^th Century by the “big market cap smart guys”.

Jeff Wojahn - Executive Vice President and President-USA Division

“The Tuscaloosa Marine Shale has made significant strides towards commerciality over the last quarter as well performance continues to be strong and well costs are trending down. Goodrich Petroleum's Crosby 12H-1 well, which we have a 25% working interest in, delivered initial 30-day production rates higher than 1,200 barrels of oil equivalent per day and continues to perform above type curve expectations”

Jeff Wojahn - Executive Vice President and President-USA Division

“Yeah, this is Jeff. We’ve been doing two things in the TMS, one thing is to look at what we call a gel hybrid frac jobs in the Anderson wells and the most recent Goodrich Crosby wells areexamples of those wells. And those wells have IPs, 30-day IPs over 1,000 barrels of oil equivalent per day, which we’re quite satisfied with.”

Jeff Wojahn - Executive Vice President and President-USA Division

“Ross, it’s Jeff Wojahn. Right now we are really focused on a number of milestones that we set for ourselves. We believe that the recoveries for 7,500 foot horizontals could approach that 700,000 – 750,000 barrel EURs. There is obviously opportunity to increase that with a higher stimulation of our rock volume.”

Source: EnCana Earnings Transcript Apri 23^rd, 2013  http://seekingalpha.com/article/1362611-encana-s-ceo-discusses-q1-2...

Robert C. Turnham - President, Chief Operating Officer and Non-Independent Executive Director

“Thanks, Gil. Needless to say, we are extremely pleased with the results from the Crosby well in the TMS. As we mentioned in the release, the well peaked at an average 24-hour rate of approximately 1,300 barrels equivalent per day on a 15/64-inch choke, with approximately 1,200 barrels of oil and 600 Mcf of gas per day. The well has averaged 1,200 BOE per day over 15 days from a similar choke size, and is currently producing at that same rate.

Based on the current production trend, we expect the well to produce in excess of 30,000 to 33,000 barrels of oil in the first full 30-day period. This well is capable of producing at a much higher rate on a more open choke size, but as we have seen in our other shale plays, we feel it prudent to maintain a conservative early flowback plan, which will maintain maximum reservoir integrity.

We are very confident of the resource potential of the play. We're plotting production data from public sources. The Anderson 18 well has reached cumulative production of approximately 100,000 barrels of oil equivalent in approximately 7 months of production, which is significantly better than industry performance in the oil window of the Eagle Ford and compares very favorably to upper tier Bakken wells, which reach a similar amount of production in about 12 months.

Factoring in current LLS pricing of approximately $115 a barrel and 20% royalty, we generate gross and net revenue of $11.5 million and $9.2 million, respectively, in approximately 7 months.

The Anderson 17, which has a shorter lateral length by approximately 1,400 feet than the Anderson 18, has reached cumulative production in excess of 80,000 barrels of oil equivalent in 7 months, which is similar to many of the best Bakken wells at roughly the same point in time.

TMS production is approximately 90% to 95% black oil, priced off of LLS, which has a current uplift of approximately $20 over WTI. So as I described earlier, these BOE production numbers are significant, not only from a well performance basis, but in cash flow generation.

We now have approximately 8 to 13 months of production from the recently drilled and properly stimulated TMS wells, which production profiles have all gone hyperbolic, with the rates of decline flattening considerably.

As a reminder, in all shale plays, you typically see wells go hyperbolic beginning around months 6 to 9, and the TMS is no different. The wells to-date have also been flowing a 5.5-inch casing over the first few months, and we feel by running tubing earlier in the life of the well, we can improve early production rates and rates of return going forward.

When evaluating public data, we have generated preliminary type curves ranging from 400,000 BOE per well on short laterals to as much as 800,000 BOE per well on longer laterals, such as the Anderson 18 and likely the Crosby, which to-date has tracked above the Anderson 18 even though the lateral length is approximately 2,000 feet shorter and the well had 5 fewer frac stages.

Through 8 months of production, the Anderson 17 is tracking our mid-case type curve of approximately 600,000 BOE. We would obviously like to see more wells and more history from these wells to feel comfortable with these type curves at this point in time and believe they establish a solid range of potential EURs.

In addition to commercial rates of production and higher oil pricing, the play has certain additional inherent advantages, such as: Number one, our gas has a very high BTU content with 8 gallons of NGLs per million cubic feet of gas, which calculates to approximately 190 barrels of liquids yield per million cubic feet of gas produced; Number two, we have a 5% lower royalty burden in this play than what we have in the Eagle Ford, with average royalty across our acreage of approximately 20%; Third, we have a 2-year severance tax abatement on our Louisiana wells and expect something similar in Mississippi; And fourth, we have very little infrastructure and surface constraints, in that the oil is trucked from the lease for approximately $2 per barrel differential off of LLS pricing, and our acreage is located in a rural area with supported landowners.

Most of the wells drilled to date have either had drilling issues caused by well-bore instability from a specific 10-foot interval which we call the rubble zone or has been drilled and evaluated with a considerable amount of science performed on the well, like the Crosby, where we drilled a pilot hole, logged, cored and evaluated the formation.

Our coring of the Crosby indicates the quartz content in the lower half of the TMS comprises approximately 50% of the formation and the clay content is lower, both of which are positive indicators of a higher-quality source rock.

Going forward, we think we will take our current well cost estimate, without science or drilling issues, of $12.5 million to $13 million to $10 million to $11 million over time for a production and drilling days, better service company pricing due to increased capacity in the field, pad drilling, zipper fracs and other efficiency gains.

When factoring in our mid-case type curve of 600,000 barrels equivalent, which is again, driven off of production data from the Anderson 17H well, and using a $13 million completed well cost and $90 WTI pricing, we are projecting close to a 40% rate of return, which is very competitive with other nonconventional oil plays.

As we drive costs down, we expect to see an incremental 10% to 15% improvement in IRR for every $1 million of cost savings. And if we can hit our target of a $10 million completed well cost, we would generate in the neighborhood of a 75% internal rate of return.

In all of our horizontal plays, our drilling team has demonstrated the ability to reduce costs over time as they nail down the specific best practices for each area. This is confirmed by looking back at each of our primary plays and tracking drilling days to total depth.”

Source: Goodrich Earnings Transcript Feb 21st, 2013  http://seekingalpha.com/article/1213671-goodrich-petroleum-manageme...

This Chart clearly demonstrates the economic viability of the production achieved in the Updip Window of the emerging TMS play.  Especially this early in the development of the play in light of the fact that only a handful of wells have been drilled in comparison to the number of wells it took to be drilled in other plays to achieve this level of production.

I hope this information sheds a little more light and clarity on the subject of the current status of the TMS play.

~~ John

 

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Permalink Reply by John Parker on May 2, 2013 at 15:25

ShaleGeo:

Apparently you are having some difficulty focusing on the content of the information I furnished. Where does your:

"And yes, I have a well file on each and every well that has reached the TMS since inception.  Do you?” (underline added for emphasis) come from.

I never asked you if you have a well file on any, let alone all of the TMS wells since inception.

Second, while it is excellent that you have that data, are you talking about past vertical penetrations or all of the new horizontals, or both?

Please clarify what specific data set you are referencing that you rely on.

Thanks John

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Permalink Reply by Joe Aldridge on May 2, 2013 at 15:11

John,

Very nicely researched and stated. However, I disagree with the statement: "Just as occurred in the early days of the Eagle Ford by some of the early Operators, it appears that Devon and Anadarko staked out their position too deep in the play.  Too Bad So Sad for all involved in that." 

I personally don't see where Anadarko ever intended to drill or test the TMS. Their focus from the beginning in Central Louisiana has been the Austin Chalk and nothing else. Now they want to sell the leases so they are referring to the TMS in their literature for that purpose and that purpose alone.

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Permalink Reply by John Parker on May 2, 2013 at 15:19

Joe:

You are very correct in your assessment and it was an oversight/misstatement on my part for presenting it that way.  Thanks for clearing that up for all of the GoHaynesville readers. It is important to be fair and impartial in the reporting of information and I try hard to do that and much appreciate others help in correcting any mistakes I may unintentionally make.

Thanks John

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