Tuesday, October 30, 2012

A Landowner Shout Out

I had a chance to stop by Emmaus in September.
Last week the blog surpassed a half a million pageviews and the TMS is just getting started.  As the frequent visitors to the blog know, this is a pro bono effort (translation: free)  Significant content is provided to all at no charge.  All I've asked for in return is support for our favorite charity.  I wanted to take this moment to present the top donors over the past year.  Recently, a mineral owner made quite a donation after selling some minerals ($20,000).  He asked to remain anonymous, but lets refer to him as Mr. Hegetsit.  My goal for the year is still to raise $100,000.  We've raised $56,270 to date and the year is quickly coming to a close. Over 90% of the visitors to the site are locals that live "in the trend".  I estimate that the oil industry has injected over $500,000,000 into the local economy via lease bonus checks.  The industry has already spent over $200,000,000 in well costs.  Over a half a billion dollars already invested in total.

Over the last 18 months since the inception of the blog, I have answered hundreds of emails and phone calls from landowners asking questions about the play or their land in general.  "Why won't they lease my land?". "Is my land in a good location?".  "They're drilling on my land but won't tell me anything!".  "What's the Thomas well doing?".  Landowners, I'm now giving you a "shout out" and saying that we need your support.  The year is almost over and the tax man will be coming soon.  Why not donate to a great cause instead of giving it to the IRS? My goal is to continue this as a free service despite the industry asking for a subscription service with weekly Scout Reports and metrics. This is your moment to speak loudly.
........And then we have those that continue to use it to attempt to move their penny stock:

Our favorite charity:

Donate Online (An anonymous option is available):
(In the Dedication or Gift box, enter “Kirk’s Challenge”)
Donate By Mail:
Emmaus House, Inc.
PO Box 1177
New York, NY  10035

Sunday, October 28, 2012

EOG Quickly Exhibits TMS Leadership

EOG didn't take long to exhibit their leadership and "know how" in the TMS.  They drilled the Dupuy Land Co. 20H-1 in record time.  At 583' per day, this is the fastest horizontal well drilled in the play in this latest TMS era.  A measured depth of 16907' in 29 days with a lateral of 5169'.  Impressive.  Many will ask if the western portion of the TMS-East is easier to drill.  I would definitely say not.  I believe that this is an experienced drilling department "doing what they do".

EOG's results in the Eagle Ford shale are legendary.  At the recent Harts DUG Eagle Ford Conference, it was interesting to see how EOG outperforms all of its competition.  In that play, their adjacent competitors are not getting nearly the same results.  As I've said many times, we're fortunate to have them in the TMS.  The bar has just been set higher.

Wednesday, October 24, 2012

Encana - Q3-2012 Results

Encana Management Discusses Q3 2012 Results - Earnings Call Transcript

October 24, 2012  

Tuscaloosa comments only:

We had tremendous interest in all of our joint venture offerings to date and fully expect to meet or exceed our targets. However, there are significant assets available for joint venture in both the Canadian and U.S. marketplace. As such, this may limit the size of the packages that can be dealt on and extend the time that it may take to complete a transaction.

For example, we've been advised that our combined Tuscaloosa Marine Shale, Eaglebine and Mississippian Lime package may be too large for most interested parties at this time, and so we are allowing the plays to be bid on individually. The value of Encana's joint venture offerings and asset packages greatly exceed the $1.5 billion to $2 billion net divestitures needed to meet our combined 2012 guidance and 2013 target, allowing us to be highly selective in the deals we choose to transact on.

Encana's motivation in completing joint venture transaction varies depending on the assets involved. In the case of the Duvernay, our early light oil plays in the USA division, the primary driver is to de-risk our capital program and accelerate the pace of which we can reach commerciality. With partnerships such as those that we've fostered with KOGAS and Mitsubishi, the plays involved have been largely delineated and the majority of the exploration risk has been removed. In other words, we achieved immediate value recognition for reserves and contingent resources associated with these types of assets.

Randall K. Eresman
Do you want to talk about Tuscaloosa as well and the Eaglebine?
Eric D. Marsh
Could. In the TMS, we have 2 rigs running. We have 2 wells completing, and let's see. We have one that's just about to come on. So we should have additional production on probably in the next couple of weeks. In the Eaglebine, we've had one rig running in the Eaglebine really drilling mostly in that Gresham area. It's going well. We're pleased with the results there. We have 2 additional wells that we'll be bringing on here this next week.
Brian Singer - Goldman Sachs Group Inc., Research Division
In the operational update in the press release, you indicated a couple of things. The Duvernay condensate yields were very promising, that some of the wells in the Eaglebine are exceeding expectations and that the Tuscaloosa focus is on reducing drilling cost. Can you give us a more specific update and perhaps, in the Eaglebine, holistic update on the well results versus your expectations and the cost trends?
Randall K. Eresman
Okay, do you just want that on the Eaglebine?
Brian Singer - Goldman Sachs Group Inc., Research Division
I guess for the Duvernay, Eaglebine and Tuscaloosa. Illustrating some of the more general remarks that you made on your release and then in the Eaglebine, specifically, you talk about some of the wells, maybe saying [ph] it's a little bit more holistic.
Randall K. Eresman
Okay, we'll start with Eric. Okay.
Eric D. Marsh
I think on the Eaglebine, Brian, I think the comment really is, is that like any place you drill, you have some that do better than others. And out of the wells we've done, we've had 3 or 4 of them that have been really good wells, and we'll give you an update on that probably in the fourth quarter. But overall, costs are in line; well performance is pretty much right online with our expectation, plus or minus; and then the area appears to be fairly honest as far as our drilling completion work. I think, in the TMS, I think it's all about the cost, it's all about working on our drilling cost and reducing the trouble times that Jeff just referred to.
Jeff E. Wojahn
Yes, maybe I can jump in as well, Brian. On TMS, one of the exciting things is that -- and we said this at Investor Day, and I'll maybe repeat it, a number of the wells that we drilled, some of the longer horizontals, were pretty good, pretty close to our target type curves. And we have a target type curve for that area of around 730,000 barrels EUR. A couple of our wells appear to be, with reasonable extrapolation of future declines, right on target. So the TM -- and the other thing we talked about at Investor Day is we've also appraised the reservoir or our land base pretty well. We have wells 25 miles apart and have similar production performance characteristics. So we're pretty confident about the resource potential of the TMS. And that it's a very, very large resource potential. Now, our focus is moving away from appraisal to sort of attack a target cost. And we're targeting to get our cost in that $13 million, $14 million, $15 million range. And I said this at Investor Day, we just drilled today along lateral 7,500-foot horizontal, 30-stage completion in the Haynesville that we brought on kind of mid-year this year. And those costs were in that range. So I have every confidence in our team's ability to replicate their performance that they've done in the Haynesville, because we're really talking about 13,000-foot depths with the same kind of challenges. So that's not to say that it's a slamdunk, that we can just take our Haynesville program and move it to the TMS. There is differences in the local geology, but we're really talking about costs not resource when it comes to TMS, which I feel very confident in.
Randall K. Eresman
The only package that we are changing right now is splitting up the combined 3 property package in the U.S., The Eaglebine, Tuscaloosa, Mississippian package and allowing bids to meet separately on those. We are though, as well, considering the possibility of some of our mature acreage. If we could do a direct sale, we might create some designer packages that might fit the market. But we haven't ruled those out yet.
Mark Polak - Scotiabank Global Banking and Markets, Research Division
Okay, great. And last for me just going through the release today and I'm looking at the planned number of wells for the sort of emerging oil and liquids-rich plays and comparing that to prior numbers, some of them looks like you've increased the number of planned wells this year and others, it's come down slightly. Is it fair to infer from that areas where you're having better than expected results and worse than expected results or are there other reasons that you'd be sort of shifting those plans around?
Randall K. Eresman
Yes, I'd say there generally are other reasons, and I can have Jeff talk a little bit about our changing plans in the TMS, for example.
Jeff E. Wojahn
Yes, Jeff Wojahn here, Mark. The TMS and the Eaglebine, one of the things we're very cognizant when we rolled out the program is that we did want operationally out step our learnings. And in the TMS, we've had some challenges or we've identified a challenge around well lower [ph] stability. And so we took a timeout while we've got our experts together from across the company to develop strategies rather than going ahead and just drilling money with old strategies that we thought would be of high risk. Likewise, in the Eaglebine as well, we went ahead with a one rig program because we thought that, that would be in line with our ability to learn from the information that we were gathering. So I think it's more of a function of prudence and discipline by the teams, on how they evaluate the opportunities and mostly that's how we feel about it.
Randall K. Eresman
And so far -- and the results we've had on the more recent TMS wells have proved that we have a good strategy.
Jeff E. Wojahn
Right, right. We have a number of drilling strategies, and we're sort of getting the early results on that. And so far, they corroborate the hypothesis that the teams have come forward relative to improving cost and decreasing drilling times. So we're making good progress. It's kind of slow and steady and we're hopefully trying not to outspend our learnings, and that's really what we want to do.
Mark Polak - Scotiabank Global Banking and Markets, Research Division
That's great. On the flip side of that, areas where you guys have increased the number of planned wells is that just freeing up where areas you have slowed down you've got that money available on the budget and reallocating that or the just results exceeding expectations?
Randall K. Eresman
That is largely what has happened. Yes, it's been reallocated across the business.

Wednesday, October 17, 2012

DUG Eagle Ford - Production Rates

Two days at the Harts "DUG Eagle Ford" conference were educational.  The Eagle Ford is quite a play. Lets hope that the TMS will be at the same place in three years.

The stats below were presented by U.S. Capital Advisors.  I thought that they could serve as an interesting comparison.  We seem to hear about the 4000 bopd "monster" Eagle Ford wells, but comparing to the averages across the entire play is interesting.  I conclude that the TMS will be competitive in the future.  Of course this assumes a significant decline in well costs.

Presented at Harts DUG Eagle Ford 2012

Sunday, October 14, 2012

Goodrich Denkmann 33-28 H-1 IP Estimate

Goodrich's frac job on the Denkmann 33-28 H-1 should be completed.  Here's some charts to use to make some estimates.  This should be a great location based on the thickness of pay in the area.  With a measured depth of 18278, I calculate a potential completed lateral length of 4948'.

Based on my algorithm that utilizes the parameters from the prior TMS completions, I'm predicting a 30 day initial potential of 857 boepd (bottom slide below).  I hear that the cement job may not have gone well.  If that's the case, then it could have a negative impact on the result.  I understand that the frac job planned for 14 stages with 400,000# of proppant per stage.  This will be an interesting datapoint because the lateral length is not very long, but they are using a lot of proppant per stage.

The charts below provide some comparisons for initial potentials (IP) of the prior completions.

The chart below illustrates that 400,000# of proppant per stage will make this well the 3rd highest so far.  More proppant is better but costs more.

The chart below at this early stage doesn't serve as a great predictor tool because the proppant levels have varied greatly across the wells.  

The chart below indicates that the total proppant should result in an initial potential of 430 boepd.

The chart below illustrates that the high level of proppant per stage should result in a higher than average initial potential.

The log below illustrates the impressive reservoir quality and thickness in this area.  The Denkmann location has an estimated pay thickness of 125'.  Based on 14 stages with 400,000# of average proppant per stage results in an estimated IP30 of 857 boepd.

DUG Eagle Ford

I'll be attending the DUG Eagle Ford conference in San Antonio this week. I hope to learn some more about the TMS's "Cretaceous Cousin".  Hopefully it will be a review of what the TMS will look like in two years.

Tuesday, October 9, 2012

EPA Hydraulic Fracturing Notification

Effective October 15, 2012, the EPA must be notified at least 2 days in advance of any hydraulically fractured wells.  It will be interesting to see how this plays out.

Monday, October 8, 2012

Thrive America

I was contacted by Charlotte Batson of Batson & Company informing me of an event that they are hosting in November near McComb, MS.  The two day seminar will focus on surface related issues regarding shale oil.  Topics such as leasing, land management, and business opportunities will be discussed.

Thursday, October 4, 2012

Devon Thomas 38H-1 Initial Potential

The initial potential for the Devon Thomas 38H-1 has been reported on SONRIS:
COMPLETED 9/28/12 AS A OIL WELL IN THE TMS RA SUA RES;PM F 384 BOPD; 105 MCFD; 2400 FTP; 09/64 CK; 192 BWPD; 0.50%BS&W; 273 GOR; 41.0 GRVTY PERFS 12383-17114' (ST: 10)

That equates to 402 boepd.  I expect the well to improve as it cleans up and as they open the choke.

On September 24, 2012, I made this prediction on the Thomas IP and IP30:
"Based on the information below, I would expect the well to IP in the 350-500 boepd range.  Devon is using more proppant per stage than in the past, so it could be higher.  I would expect the well to have little gas.  424 boepd is my prediction for an IP30."

That was based on our algorithm constructed from the database of existing completions along with a calculation of total feet of pay from well logs.

The IP for the well plotted directly on the best fit line on the chart below.

Wednesday, October 3, 2012

TMS Play Map

The play map below illustrates a good geographic spread of locations in the eastern half of the TMS-East.  EOG's upcoming activity will start to fill out the western portion of the TMS-East.  Halcon will quickly determine the potential in the TMS-West.  2013 will be significant for this play.

Base of TMS structure; Units and well locations

Tuesday, October 2, 2012

TMS Drilling Activity

********* revised map (Mark, thanks for the catch!) **************
The TMS has reached a new level with five operators actively drilling in the play.  Halcon and EOG don't appear to be wasting any time.

TMS: current drilling locations; Base of TMS structure

EOG Permits Two Horizontal TMS Wells

EOG has permitted the horizontal offsets to their two vertical pilot holes: Gauthier #1 and Dupuy #1.

EOG Gauthier 14H-1:
MD: 19037'
TVD: 13552'

EOG Dupuy Land Co 20H-1:
MD: 16768'
TVD: 11408'
Spud 9/27/12; Drilling at 7731'

Monday, October 1, 2012

Devon Weyerhaeuser 14H-1 - IP30

Devon's Weyerhaeuser 14H-1 well produced an IP30 of 692 boepd in July (639 bopd, 308 mcfgd)

An Unconventional Play Comparison

I've assembled data from 11 oily unconventional plays across the U.S. to make a comparison with the Tuscaloosa Marine Shale.  With only ten completions in the play, we're still very much in the "R&D" and "derisking" phase of this play.  To date, well costs have been a popular topic.

The chart below presents well costs vs estimated ultimate recoveries (EUR) for eleven unconventional plays.  I've also placed three TMS wells with their actual or AFE costs for comparison.  The decrease in costs is occurring and I expect the costs to continue to decline.  The AFE of the Weyerhaeuser 60H-1 of $12.1 million is the lowest that I've seen to date.  Keep in mind that once this play shifts to "development mode", the use of the resource play hub (RPH) approach, will result in significant cost savings.  I've heard that locations are currently costing $1 million.  Drilling 4-10 wells from one pad will be very cost effective.

The chart below indicates that for the TMS to have similar "cost to EUR" relationships, the drill costs have to range from $9-12 million with EUR's in the 620-750 MBOE range.  Encana has already announced that they believe 730 MBOE is achievable.  I understand that one of the TMS operators has $9.5 million for well costs in their 2013 budget.