Replies to This Discussion

Permalink Reply by Skip Peel - Mineral Consultant on November 5, 2013 at 13:54

ECA is down sizing their work force and concentrating on a modest number of oil and liquid plays.  I expect they will hold on to all of their Haynseville Shale leasehold  which is already HBP.  Any undrilled acreage in  E TX may get farmed out to others.  Maybe XTO.  Maybe EXCO.  There won't be any step out drilling but where the rock is proven I expect that existing leases will largely get drilled.

Permalink Reply by adubu on November 5, 2013 at 15:06

Skip-- where they have good rock are you implying that you think they will drill out the units with max number wells allowed per spacing at present 3.50 prices? Is spacing for H Shale wells 80 acres?

Permalink Reply by Skip Peel - Mineral Consultant on November 5, 2013 at 15:21

No.  I think they will operate the wells they have and only drill when and where they have to in order to maintain their producing leases.  They will spend the majority of available capital exploring for and developing liquids until the price of nat gas improves and they are in better financial shape.

Permalink Reply by jffree1 on November 6, 2013 at 2:10

EnCana put all of their eggs in the NG basket back in 2008 when the price was at a record high. They have to deal with reality now, if they want to survive, and that reality is that the price of gas is expected to be range bound into 2016, at least.

They have shaken up the entire management team and have a new VP over US (from BP, I believe). This little piece in the Dallas paper is a good summary of what they are trying to do.

Encana will close its Plano office, cut jobs

"Encana Corp. will close its Plano office as the company shifts its focus from dry natural gas to more profitable liquids and oils, the company announced Tuesday."

"Rather than operating in 30 different places, the company will refocus its resources on five oil and liquid-rich plays in Colorado, New Mexico, Louisiana/Mississippi and Alberta and British Columbia."

http://www.bizjournals.com/dallas/news/2013/11/05/encana-will-close...

Permalink Reply by adubu on November 6, 2013 at 2:18

Skip--- so you see drilling in dry gas shale only if operator has leases in good rock area not HBP. Any ideal locations and number of leases not HBP in La/TX that need to be drilled before leases expire? Any new leases being brought by operators in recent last few months?

Permalink Reply by Skip Peel - Mineral Consultant on November 6, 2013 at 2:28

Where there is an existing unit with a producing well and all the associated infrastructure in place operators will drill the occasional well.  Any speculation beyond that must take into account the particular circumstances of each operating company.  From what I'm reading on ECA I would expect them to farmout proven, undeveloped rock if they can.  If they can not find a taker than it's a flip of the coin whether they do something to HBP.   They could drill a shallow vertical or have some small local company do so under a shallow rights farmout.  Or they could allow the leases to expire.  I think it is pretty plain that they are not going to do anything as expensive as drill a new horizontal well and capitalize the required infrastructure to tie it to sales.  With the possible exception of some southern E TX HS the better rock has been located and developed IMO.  The area of the productive HS Basin is unlikely to increase in size in the future.  ECA has already stated in presentations that between them and their partner Shell they have modeled the entire basin.

Permalink Reply by adubu on November 6, 2013 at 3:17

Good analysis of present facts of HS. The only operator that will take on selective good proven rock in area today will be XTO

Permalink Reply by dbob on November 6, 2013 at 15:03

I think there is a possibility of BP and Anadarko would be interested in selected good proven rock, where it fit near their core, and had some potential to be the lower pressure, higher BTU gas. 

I'm not quite ready like Skip to say the Haynesville is fully modeled - The Barnett was fairly well developed when the wet gas portion of it really kicked it up a notch.  I think the productive area is likely to increase, although not in the next 2 years, and in a very opportunistic fashion.  Something along the lines of "oh, we have this James Lime, Cotton Valley or other holding and gas prices are high enough to allow to hold the acreage with something that will produce a low, reliable, but decent rate of return, and anything we get from the shallow formation becomes gravy.  

Permalink Reply by Skip Peel - Mineral Consultant on November 6, 2013 at 16:01

dbob, I think the Haynesville Shale modeling mentioned by ECA, which is also based on data from SWEPI (Shell), includes areas with liquids.  The specific areas that I have done some research on, while shale as opposed to sand, have liquid fractions over somewhat limited areal extents.  And they do not appear at this point to be as numerous as Cotton Valley liquid fairways. 

Permalink Reply by tc on November 6, 2013 at 4:40

Skip- Goodrich management agrees 100% with your analysis.  No drilling in core N LA, but due to lease obligations must drill 2.5 wells per year in the Angelina River Trend.

Gas volumes just depends on kind of what level of activity and when we drill Angelina River Trend wells. We have no plans to drill North Louisiana, Haynesville wells, and obviously nothing in East Texas. So that's an Angelina River Trend. So not going to be material differences on our gas likely up or down, but we'll type that up in January.Phillips Johnston - Capital One Securities, Inc., Research Division

Okay. And you mentioned the Angelina River Trend, obviously, that was a very good well drilled by an operator just to the west of your acreage. I was just wondering what sort of intel you sort of have on the completions process there?

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

Well, we are monitoring it for sure and we've been tracking that production for quite some time. I think, still, when you look at the use of our capital and the higher rates of return in the oil plays, we certainly would prefer to be drilling all better rates of return wells. But we do have a lease issue in the Angelina River Trend in which we need to currently drill 2.5 wells per year, which is why we put the $30 million allocation there. But clearly, that well, I believe, you're referring to, has made over 5 Bcf in 10 months and I think it's actually been updated to more than 6 Bcf in its first year. So that's obviously very prolific, but we're continuing to monitor that and schedule our capital in that area to maintain our leasehold block.

Permalink Reply by Skip Peel - Mineral Consultant on November 6, 2013 at 4:54

tc, $30M seems a reasonable price to pay for a lease block with a well producing 6 bcf/yr, don't you agree?!  LOL!  The Haynesville Shale remains a world class asset that most operators will hold on to for the long haul unless they are in desperate financial straits.  Improvements in development techniques/design and lower cost per mcf along with improved prices in the near future (3 to 5 years) will make for strong RORs and a dependable drilling inventory with limited additional infrastructure costs.

Permalink Reply by tc on November 6, 2013 at 5:40

Goodrich, like many landowners hope they don't have to drill very many of these monster wells before prices improve.  Goodrich this year let expire 8,000 acres of Eagle Ford and 20,000 acres of TMS to save capital, but thinks "CORE" areas of the Haynesville are very valuable and worth preserving.

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