Boy Scout Well peak production

realizing the numbers are initial peak production.......how does that production translate to money? not royalties, or amount per acre......but how much money in todays prices, did this well produce on that "day of peak production"?

1,560 barrels of condensate

1,008 barrels of NGL

7.1 MMCF natgas

 

sounds very impressive.

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Permalink Reply by Ron D. Jockefeller on September 5, 2012 at 5:55pm

That's a really tricky question because hydrocarbons are worth more or less depending on their specific chemical characteristics and their location (which determines access to trading hubs and consuming markets).  Natgas is the easiest to price because it's typically just methane with a standard BTU content.  But if you are in Tokyo it might be $14 per MCF whereas it might be $1 per MCF in the NE corner of PA.  Additionally you need to process the NGLs to get them out of the raw natgas stream, which you can't do if you don't have natgas processing facilities set up and pipes to move the NGLs to market.  BUT... all that being said.  Figure a barrel of condensate price would be based on oil prices and how light it is in degrees API (lighter is better).  Look here:  http://crudemarketing.chevron.com/posted_pricing_daily_california.asp 

So figure north of $100/bbl for the condensate.  Figure the NGLs trade at something like 50% of oil, though they are depressed now because of a big ethane surplus, so call that $50/bbl.  And figure gas at $3/MCF.

$100 x 1,560 = $156,000

$50 x 1,008 =  $50,400

$3 x 7,100 = $21,300

Total = $227,700 / day

Figure that well cost $8 million, so payback would be in less than 2 months assuming a standard decline rate.  Not too shabby, eh?

These #s assume those products can get to market, which they can't right now.  So you'll have to wait for the midstream to catch up to the production.

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on September 6, 2012 at 2:18am
NGLs are nowhere near $50/bbl. They don't trade at 50% of oil. Devon--in a presentation a few months back--hoped that they would track oil at 47%, and that was not quite right. They're more like 38% which is a big difference long term. A well paying back in two months is usually unheard of, unless it's a conventional and just happens to be a really lucky gusher. Shale economics are very difficult to pin down. Peak rate is great for investment presentations but we still don't have a good vision of true decline yet.
Permalink Reply by mark moll on September 6, 2012 at 5:01am

my understanding is the BOE conversion does not at all relate to $ value.

Permalink Reply by Ron D. Jockefeller on September 6, 2012 at 6:43am

Oh, I totally agree, Marcus.  NGL prices are a wreck, esp. ethane.  That was back of the envelope math.  

Also, I meant to type "assuming *no* standard decline rate".  

Decline rates are maybe a 1.8b factor in this play.  Nobody has a good idea of EURs yet, so I can make a case for acreage valuations anywhere from less than $1,000 to close to $40,000 depending on spacing.

Permalink Reply by Peter Schueler on September 7, 2012 at 2:33am

Ron,

Thanks for posting your calcs.

Here's the basis for my own valuation "The well tested at a gross peak rate of 1,560 barrels of condensate per day and 7.1 MMCF per day of natural gas. Based upon composition analysis, the gas being produced is 1,310 BTU rich gas. Assuming full ethane recovery, the composition above is expected to produce an additional 142 barrels of NGLs per MMCF of natural gas and result in a natural gas shrink of 25%. In ethane rejection mode, the composition is expected to yield 84 barrels of NGLs per MMCF of natural gas and result in a natural gas shrink of 17%."

I've used the following prices:

condensate @ $81/bbl which is the current posted price from ARG and Ergon for this product in Ohio.

I assumed that the economics for separating ethane, which requires cryogenic processing, could not be justified due the low current prices, about 30 cents per gallon or $12.60/bbl. I assumed that this fraction of the well output is equivalent to 58bbl per mmcf of gas (142-84) at a dry gas reduction of 7.1 (.25-.17)= .568mmcf/day but will remain as gas and sold as same.

This leaves the propane, pentane, and higher fractions that can be separated using simpler separating processes. These are higher value products that I assume have a value of about $35/bbl. Their extraction is yields 84bbls/day/mmcf and reduces the gas volume by 17% or 1.207mmcf/day.

Natural gas today is quoted at $2.75/mcf at Henry Hub, OK and having no better info for local gas I have used that price.

Gas revenue/day                       (7.1 - 1.207) x2.75x1000  = $16,205

propane/pentane rev/day         84x7.1x35                         = $20,874

Condensate rev/day                 1560x81                           =  $126,360

        Total $/day                                                               =  $163,439

         Total $/30 day month                                             = $4,933,170

The unit for this well is 613 acres which yields a monthly revenue of $8047/acre. A 20% royalty would be $1609/acre/mo. I think we can also assume that the unit could accommodate two or possibly three more wells.

It's clear that the condensate is what makes this well a real winner. Now the critical question is the decline rate.

I hope the Boy Scouts are getting full benefit from this well!

Permalink Reply by hopeforoil on September 7, 2012 at 2:44am
FYI Henry hub is located in Louisiana not Oklahoma
Permalink Reply by Peter Schueler on September 7, 2012 at 2:51am

Thanks for the correction. I was thinking of the oil hub in Cushing, OK. Henry Hub is in Erath, LA near the Gulf Coast.

Permalink Reply by hopeforoil on September 7, 2012 at 3:26am
Sure thinG. Let's hope Gulfport can continue to replicate their success
0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on September 7, 2012 at 4:55am

The problem with 1.8b is that the exponent is mathematically illogical.  Basing EUR with a b-factor higher than 1.0 is technically impossible, though many companies use it to make their books look shiny.  In the coming year we should see massive write-downs for nat gas EUR across all of the shale plays.  The only b-factor that seems to be in line with mathematical logic is 0<b<1.  Otherwise the declines can be extrapolated out ad infinitum with no basis in the natural world.

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on September 7, 2012 at 8:03am

Yes, mostly.  The problem is in how the E&P companies project out the life of a well in regards to decline.  CHK has some of their Marcellus assets charted out to 200 months.  That's absolute bullshit and what's more they know it.  With steep shale declines--and they're all steep, across the board--you have maybe two years to pay for the well.  After that it's like owning an annuity with an inverse interest payment.  The pay outs decrease less YOY, but they still will decrease to the point where operating the well is no longer profitable.  Drilling a dry gas well in the Marcellus today is like lighting 70% of your money on fire.  Hence the desire for liquids from the Utica.  The reality is that no matter how much good news we're hearing--and there's plenty of it--nobody has a real handle on decline rates.  It will take dozens of wells operating for several years before accurate type curves can be modeled and hyperbolic declines become evident.  I couldn't hazard a guess as to a proper b-factor as I am simply too far from the numbers to make an accurate guess.  What I do know is that a b-factor>1 is mathematically impossible, because infinity cannot be a number that is naturally occurring.  

Permalink Reply by Ron D. Jockefeller on September 9, 2012 at 10:02am

What are the odds that you will have a date with Heather Locklear tonight?  I would estimate them at 1 in infinity.  :-)

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on September 9, 2012 at 4:26pm

A valid point.  I stand corrected.  

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