Replies to This Discussion

Permalink Reply by jim weyland on December 10, 2013 at 8:00

 joe,

i posted the opal price to illustrate the magnitude of the rockies' freeze off situation. i got that price from a table of cash commodity prices that the wsj shows every day.

there one can find ngi daily gas index prices. in addition to opal hub it shows pepl field zone, haynesville and marcellus hubs as well as tgpl zone 3 and zone 6. it also gives the hh cash price.

as to monthly hh prices, the cme nymex site shows, on a time delay basis, last trades for all ng contracts as well as life of contract highs and lows.

interestingly, the first time $5.00 shows is the jan 2021 contract.

jim 

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Permalink Reply by olddog573 on December 10, 2013 at 4:59

Question, what does a conventional well produce over it's lifetime compared to an unconventional? 

Also, don't you think operators will learn over time to not flow a 10 BCF/day well at high rates, but rather at reduced rates to facilitate a longer life to unconventional wells and to reduce the amount of time between drilling to hold the leases?  

Example: I have a well that has been flowing at 3MMCF/day and a well that was flowed at 10MMCF/day for around 2 years now and both were brought on at pretty much the same time.  The 3MM/day well is still going at 2.8 while the 10MM/day well is now at 1.8.  While the 10MMCF has produced close to 4BCF of gas, which is more than the other well, from all appearances seems that a new well will need to be drilled in the 10MM/day section before a well will need to be drilled in the 3MM/day section.

Long example and hope it makes sense, at least it does in my head.

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Permalink Reply by Skip Peel - Mineral Consultant on December 10, 2013 at 5:36

olddog, any comparison of convention vs unconventional gas wells would depend on specifics.  As a general question, I think it is unanswerable.  All Haynesville Shale wells of which I am aware are now produced on restricted choke programs because it increases EUR.  It is also difficult to compare the two wells in your example without some specifics.  Generally speaking energy companies look at unconventional reservoirs as the most predictable and efficient type of reserves.  They know what's there and what it will cost to produce it.  The first wells have returned, or hopefully will ultimately return, the fixed costs associated with the leases and infrastructure.  At that point the E&P world turns into the manufacturing world.  Some units will get their full complement of alternate unit wells earlier than others as drilling all the allowable wells in a unit sequentially is the least costly way to produce an mcf with the only restricting factor being the capacity of the gathering system.  Other units may not be fully developed for years.  As to when will new wells be drilled in those sections?  Probably no one including the operator knows at this time.  However if a unit well depletes to the point that it no longer meets the "production in paying quantities" definition an operator may choose to drill or a mineral owner in the unit may file suit in an attempt to compel development under the statute.

§124.  Production in paying quantities required; definition

When a mineral lease is being maintained by production of oil or gas, the production must be in paying quantities.  It is considered to be in paying quantities when production allocable to the total original right of the lessee to share in production under the lease is sufficient to induce a reasonably prudent operator to continue production in an effort to secure a return on his investment or to minimize any loss.  

As to all other minerals, it is sufficient if a reasonably prudent operator would continue production considering the particular circumstances in the light of the nature and customs of the industry involved.  In appropriate cases, such as the mining of lignite, a court may consider the total amount of production allocable to the mining plan or project of which a particular lease is a part, rather than merely the amount of production from that lease.  

Acts 1974, No. 50, §124, eff. Jan. 1, 1975.  Amended by Acts 1976, No. 129, §1. 

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Permalink Reply by jffree1 on December 2, 2013 at 4:46

Will this have an impact on the price of NG or just NGLs?

Cochin Reversal Project

approved...

Obama OKs pipeline (no, not that one) that will help Canada’s tar-s... 

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Permalink Reply by Clyde T. Williams on December 2, 2013 at 7:09

As we had this discussion many months ago as to how low would it go...now it is how high will it go...and it still depends on how much can we use NOW and next two years

LNG is the only cure for the <$4.25 pricing because as demonstrated during the last year - as soon as the price gets over $4 everyone start opening valves and prices drop...LA/TX prices depend on the FACT that we don't have the major power plant customers that were displaced from the LA/TX<>Pipelines to the NE-US by the PA/OH/NCar gas sources with a delivered price well below our with transport costs....

If some of the fuel cell techs get going then all the cities in LA/TX could start generating their own electricity which would then kill the ElectrCoops...so watch out the Times are Changing

If we can get the LNG exports going we may be okay for 3-5 years and if the NGL prices stay low then some of the PetroChems may come back in BR, Beaumt., Houston, and CChristi....

But we don't live in the real world as China, Argentina/Brazil, India, SArabia, Iran, SoAfrica are all getting on the FrackTrain and in 3-4 year can probably produce as much as we can and at better prices.

$5 by January 2015 but $3.50 by January 2017

Calif. Refugee - Tom

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Permalink Reply by dbob on December 2, 2013 at 17:44

Near term climate predictions for US are pretty cool:

http://www.cpc.ncep.noaa.gov/

I'm going $5 before Christmas this year, then drifting down into the $4.50 range until about this time next year.  

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Permalink Reply by essay on December 3, 2013 at 8:40

I really hope you're right about that.

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Permalink Reply by Joe Aldridge on December 3, 2013 at 10:06

I think we have seen the low point in NG prices. There are too many new demands being put on supply for the price to stay low. We may see some up and downs but nothing near the low price we've seen in the past. 

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Permalink Reply by Clyde T. Williams on December 3, 2013 at 14:39

Prices projected for the Los Angeles Depart of Water and Power have projected 2014 prices at $4.63/mmbtus-burnertip compared to $3.90-$4 2013.  Remember this is an enduser price - counting everything including 1500mi pipeline transport, some local storage....so $5 in 2015 maybe

TOM

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Permalink Reply by Krkyoldhag on December 18, 2013 at 9:12

Question:  I keep seeing more rigs passing my place..so there activity somewhere in Panola County.  But one of the so called 'experts' here tells me no way they going to drill HS here because the wells in Center produce so much more per well then the ones here inPanola.

I replied that sure..the drillers with leases there will prefer to drill where the best production wells are located.  But that I suspect that a lot of operators do NOT own leases there ..but hold most of Panola under lease.  That they will drill where they have leases.

Am I right or is it a fact that the Center locations are so much better it kills drilling here?

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Permalink Reply by tc on December 18, 2013 at 9:21

Panola is all about liquids.  As a NG only play its so-so, but add in liquids and it profitable.

• CGU 27 #53HH, Anadarko E&P: 2.275 MMcf/day IP, 16.0 Bbl/day liquids, 18/64" choke, 5,015 psi; Perfs: 10,997-15,741, length: 4,744 ft.; Carthage Field (Haynesville Shale), Panola Co., Survey: DILLARD, H, A-166 
• CGU 11 #52HH, Anadarko E&P: 5.66 MMcf/day IP, 162.0 Bbl/day liquids, 20/64" choke, 5,115 psi; Perfs: 11,060-17,198, length: 6,138 ft.; Carthage Field (Haynesville Shale), Panola Co., Survey: DUNCAN, S, A-158 
• CGU 11 #51HH, Anadarko E&P: 6.14 MMcf/day IP, 180.0 Bbl/day liquids, 20/64" choke, 515 psi; Perfs: 11,032-17,177, length: 6,145 ft.; Carthage Field (Haynesville Shale), Panola Co., Survey: DUNCAN, S, A-158 
• CGU 24 #56HH, Anadarko E&P: 2.919 MMcf/day IP, 69.0 Bbl/day liquids, ?/64" choke, 5,340 psi; Perfs: 10,855-16,176, length: 5,321 ft.; Carthage Field (Haynesville Shale), Panola Co., Survey: BLANKENSHIP, D, A-48 
• Parker-Hopper (Allocation) Unit #1H, EOG Resources: 9.601 MMcf/day IP, 135.0 Bbl/day liquids, 64/64" choke, 4,875 psi; Perfs: 11,142-19,130, length: 7,988 ft.; Carthage Field (Haynesville Shale), Panola Co., Survey: LINDSEY, C, A-386 
• Parker-Pierce-Hopper (Alloc) Unit #1H, EOG Resources: 5.225 MMcf/day IP, 136.0 Bbl/day liquids, 23/64" choke, 4,706 psi; Perfs: 11,142-18,641, length: 7,499 ft.; Carthage Field (Haynesville Shale), Panola Co., Survey: LINDSEY, C, A-386

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Permalink Reply by Skip Peel - Mineral Consultant on December 18, 2013 at 9:30

tc, those are some of the better wells.  APC has also drilled a lot that were not close to those IPs.  I'd like to know their average IP over the last two and a half years.  The easy answer is,  good enough to keep all those rigs under contract.

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