Replies to This Discussion

Permalink Reply by scott brion on July 27, 2012 at 12:35am

Hi Melissa,

http://www.hh-law.com/userfiles/file/docs/Gas%20Lease%20Termination...

The link above takes you to a presentation on lease expiration / termination issues.  I am spending most of my time working on these issues in Tioga/Lycoming and SW Bradford county and find this to be a good summary of the legal issues.  I am not an attorney, but am putting together a landowner group to pursue lease surrenders where operators are trying to claim HBP status without legal or operating basis.  I would be happy to share information with you.

Permalink Reply by Frank Nesmith on August 1, 2012 at 10:49am

My sister lives in Bradford County and went to a Chesapeake meeting last night. She came home pretty upset. Said CHK wants to increase the size of the units to 1280 acres and only pay them royalties every 6 months. She was so upset that I had a hard time understanding her. Is any of this true?

Permalink Reply by Moldyoak on August 2, 2012 at 1:45am

They've been requesting the 1280 unit size expansion for over two years now; in some cases, they've actually requested language changes that essentially would allow for open-ended unit sizing.  The semi-annual royalty thing seems bizarre; that's a new one.

Re: the Landex issue, the only way of which I'm aware to keep up with it is to (1) either manually search for the name or unit of interest, or (2) check it multiple times per day, as those entries filed earliest are the first to go when the results exceed 250 entries.  So you need to check it early, by around 10 or 11 AM, and then usually one or two more times thereafter.  I don't know if any other way to go through everything if you are simply looking at all filings for the day.

Permalink Reply by Frank Nesmith on August 3, 2012 at 4:06am

Thanks. I'm trying to calm her down. She tells me that CHK said they will turn down the wells (reduce flow) if people didn't agree. I love her, but she doesn't always get things all right. Anyone else know what's going on there?

Permalink Reply by Wayne Miller on August 4, 2012 at 3:04am

 One way to make sure you see them all is to search Instrument #'s one at a time for the ones missing. I decided it was not worth the time for my unit maps since most of the changes are "paper-work". I anyone sees any that I miss, let me know.

Permalink Reply by melissa humphrey on August 4, 2012 at 2:12pm

i. Going to 1280 is a good thing. A well in Bradford planned at 12 stages had top cut short to 2 because of completion troubles. Suppose that was the only well in your unit for 5 years? Larger size gives greater geologic diversity.

ii. Hve nit hear of semi annual, seems late to start in with that. For small acreage it might be easier.

iii. CHK is not going to shut down wells because you don't sign.

Many companies are finding out their optimum lateral length is in the 6-6500 ft area. In order to incue ceent width, they need more than 640 A max. Yes thyey can do a split N and S bur see above.

reailty is there is lots of gas down there and proportioannly you get teh same either way. relax be thrilled you have gas !

Permalink Reply by LW on August 4, 2012 at 3:36pm

Thank you Melissa. Always good information. I did a guess estimate calculation for our unit that split and even with the count of wells cut in half, we are ahead in the long run because our split resulted in the unit being much smaller than the original 640. This is using the same production figure in all calculations. I assume it will be better yet with longer laterals. Plus less environmental impact is always good. I understand the hesitancy to change unit size because of HBP fear. I think most of us want the money as soon as possible. Hopefully that will happen sooner than later.
Will you please explain what 'top cut short' with that well means and tell us the well name and location?
Thank you!

Permalink Reply by Frank Nesmith on August 9, 2012 at 10:41pm

But why is Aubrey just now recording so many deeds there? Tons of them are being recorded with Jamestown and Larchmont now. CHK has had these leases just about forever and these are all just now being recorded as such. My sister was glad that AM never put his companies name on her lease and now it's been put on it in the last part of July. 

Permalink Reply by melissa humphrey on August 10, 2012 at 3:21am

No special insight here but our guess, assignments have an effective date and if recorded late still validate production allocation from the effective date. We think Chesapeake has a over booked courthouse workload and that would be prioritized. The OUTPUT in the area is mammoth and it appears McClendon needs cash flow fast, with all his legal problems.  

 

Here is a question, does Larchmont’s 2.5% come out of 100 or is the parcel’s royalty burden deducted 1^st. If it is not the latter, it seems landowners can assess Larchmont for their decimal interest due from another working interest- McClendon’s.

KELP???

 

Melissa

 

Storage # was +24 vs a weather adj model expectation of 32. That is good. Close to

1Bcf/d short.

Permalink Reply by Frank Nesmith on August 10, 2012 at 4:46am

I could be wrong, but I think the 2.5% comes out of the 100%.  With that, AM has to pay the proportionate share of the well costs, as well. That why she was wondering about it. She also bought some stock with her signing bonus, so she watches them pretty close and comes to me for questions. She has two issues. 

1. She's mad (like most other stockholders) at AM's actions. She's wondering why he took so long to transfer the property and if he took personal proceeds all along.

2. Now that he inked his private holding to her deed. (I think he used Larchmont for hers), she's afraid he will take loans out on it, like he did with others. She's getting close to retiring and was contemplating selling and is worried that may hold up a sale. I'm not sure how that works, so maybe someone can enlighten me.

ps-She also asked me about the stock she has, with the news of the investigation being plastered everywhere this morning. You know what. It's old news and I think this too shall pass. I don't see any reason to dump it now. Too much gas hasn't been even put into market yet. 

Permalink Reply by Tug Steward on August 10, 2012 at 2:35pm

Melissa . . .  not so on pt i (agree on ii and iii).

Simply put, the 1280 acre unit is being created at this time to hold land by production (HBP).  True, an operator could plan and ultimately develop a 1280 unit with multiple wells spaced accordingly from a single pad but that is unlikely (at this point in time).  Evidence of such? Open the GE KMZ files our kind host provides on this website and study what you see.  Most units range from 600-800some acres – the approximate number of acres to drill (typical) 6 wells (3 northish, 3 southish) spaced 600 to 1000 feet apart.  It’s been a fairly recent (yr+) development that we see split units and quandrant units that conform to the unit acre limit of 640 but still enable an operator to hold the land by production.  This is a strategy by the operators where lessors have not signed the ratification and amendment enabling the larger unit. So . . . if I were central to a unit that is being “expanded”, my royalties could conceivably be diluted (unfavorable) while, if I were on the periphery of a newly expanded unit, I might share in production that ‘my’ shale didn’t produce (favorable for that person, but fair?).  One might expect, don’t you think, as markets for gas improve and drilling resumes, with additional pad development, that amended units will be filed reflecting the actual drilling and spacing of wells?  Until then, it would seem there might be marginal losers and marginal winners. 

 

The choice for a landowner to sign or not sign the R&A isn’t necessarily simple and every property, given its location specific to ongoing development plans, and specific to what drilling that has already taken place in the unit, will suggest the better option.

Permalink Reply by melissa humphrey on August 10, 2012 at 4:43pm

Minor in the scheme of things but considering paper work and efficiency- we think larger is favorable to the gasco. No one loses or gains gas-value at unit size of 600 or 1200 or any number. Of course it is all proportional. If you have 60 A, you over time will get the value of 60A. Yes, gascos can make N & S to cut unit size and even make 1 well a unit, but they do need length, 6500 ft or so.

 

Also, though it can change, gascos seem to be drilling 2 wells per unit when they are 600+.

It maybe a matter of efficiency as well, 2 wells feeding into gathering?

 

The only disadvantage we see in a bigger unit is unless worded otherwise, the gasco would drill 1 well and sit. I think diversification offsets the mentioned disadvantage. To a degree, SE Bradford’s rock is so rich, we don’t think the gascos want to sit ----unless gas is just too low, under 2.50-3 ?  ---- in which case most mineral owners don’t want their gas sold anyway.

 

That is our view anyway.

 

 

 

We don’t think if gas were $3 or 8 there would be difference in gascos unit size choices. Reaching out too far from the center site has to have consequences, probably limiting length. It would seem not being too big would help in capturing more, leaving less wasted.

 

We re so early, most cos are just now experimenting with spacing- not sure Chesapeake even is? Southwestern, (smart scientists) I hear 2^nd hand is going to perhaps 7 wells per 684 A vs prior 6. A few gascos have mentioned the fact of interference, which comes into play at some point. Am told that has a lot to do with rock physics and while Fayetteville may work with 40 A spacing, another shale might be losing via interference at 80 A.

 

I believe Ultra, less conservative, is trying out 600 A and Equitable (PA Pittsburgh based)

Might be messing with 4-500 - of course that is SW PA and probably classified as  somewhat different than NE.

 

HBP of course isn’t a trick but part and parcel to gas development. It would be irresponsible to not HBP. No question gascos that loaded in ‘06-’10 are behind between the econ slowdown and now, low gas prices. Gasco risk  isn’t just having to pay up for expired leases but it is very disruptive for continuous block development. Additionally 2^nd time around, with  NE US culture, the gascos may find parcels who ask for impossible addendums and block a lot of development including already paid for bonus et al.

 

I think I fell off track. THANKS for your response, hoping to see expanding discussion here.

Melissa

PS- Yes TUG you are so right, how one's parcel will likely fit into a unit is primary. That assessemt should be critical to negloating position.

BTW- why do gascos try and lease evry small piece? IE a 5 acre not in  a bore line. Why pay up vs keeping that gas for themselves? ideas?