Haynesville Well Economics: Back of the Envelope Calculations
Recent site discussions have caused me to revisit potential economics based on 2nd quarter 2020 corporate presentations. I am modeling 4 actual wells in this back of the envelope exercise.
Haynesville Well Economics:
4 Wells: 27,520 linear feet of perforated lateral at a total D&C (Drilling & Completion) cost of $51,391,335.
Current industry average (?) EUR of 2.5 Bcf per 1000’ of lateral
Estimated EUR for the 4 well group: 68.8 Bcf (First 18 months reported production: 45,894,657)
The decline at the 18-month point is approximately 67% of the total Estimated Ultimate Recoverable which sounds about right for these high decline horizontal wells. At 24 months the decline should be approximately 80%.
Leaving out LOE (Lease Operating Expense) and factoring a 25% NRI (Net Royalty Interest):
Each 1000’ of lateral should produce an EUR of 2.5 Bcf. If we assume that the operator
Nets 75% of that then 1.875 Bcf. Plug in whatever you think the average price per mcf over
the life of the wells and then arbitrarily a net profit per mcf, say 10 cents.
1,875,000,000 X $0.10 = $18,750,000 or about ten times the D&C cost.
27.52: Total lateral lengths divided by 1000’. 27.52 X $18,750,000 = $516,000,000, ~half a billion dollars.
Admittedly this is a very simplistic formula which assumes much and leaves out a number of costs over time that are too difficult to project. The actual realized profit is something less and the EUR is for the life of the well, let’s say 20 years with 80% in the first 24 months. I am taking the 2.5 Bcf volume per 1000’ of perforated lateral from corporate presentations. This metric has been used continually over the last 2 years by more than one operator. This metric is based on the current long lateral, high intensity frack well designs. It should be kept in mind that in the units being produced by these 4 wells, there was no original old-style unit well, and that both sections are located in an area deemed economic for both Haynesville and Bossier shale wells. Although the state allows up to 8 horizontal laterals in each formation, the current industry average is 6 based on the higher intensity frack designs. So, 12 total “lateral slots” per unit: 6 Haynesville, 6 Bossier. Using a very simplistic metric, there would be approximately 67% of the technically recoverable reserves remaining undeveloped in these two sections.
I invite members to comment on my math and assumptions. I am deliberately taking a very simplistic approach but think that it is a good starting point to think about Haynesville Basin economics. I am using metrics based only on Louisiana Haynesville operators. Texas metrics may vary. I am not modeling royalty income here, just well cost and estimated potential return on investment by operators. This group of wells is producing from two units (sections). The lateral lengths vary by well from the shortest, 6192’, to the longest, 7313’. So, there is unequal lateral lengths in each of the sections. By production volume to date, one section has produced 37.5% and the other 62.5%. Also keep in mind that this exercise in production and profitability potential is based on the life of the well. Natural gas price will obviously vary over that time by some unknowable factor and the “present value of a dollar” should not be overlooked for a twenty years span of time.
? Now that the majority of production is by private companies, the ability to assume that the statements by publicly traded companies is an accurate standard for alloperators is less certain. If this is a true average, then some wells produce more and some less per 1000’ of lateral. I suspect that this metric is only applicable to long lateral wells with high intensity fracks like the group of wells modeled here. Companies continue to drill wells of various lengths depending on the unique situation of each. Some of the publicly traded companies break down there remaining undeveloped well locations by the length lateral they could accommodate. The lengths are usually broken down as 4500’, 7500’ and 10,000’. Keep in mind that it takes 3 sections, north to south, to drill a lateral over 10,000’, so that doesn’t happen often. Chesapeake has drilled a few. A 2 section lateral would have a maximum allowable theoretical lateral length of approximately 9900’. As long lateral wells have become the norm, companies forming new units in areas not previously developed have on occasion formed 2 section, 1280 acre units.
Views: 1971
Replies to This Discussion
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Permalink Reply by daddy bill on
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Skip your numbers seem a little high. At 10 cents profit per mcf to make a half billion dollars on 4 wells just think what a company could make if the price goes up and you make 50 cents per mcf. The key word is per mcf not cubic feet. Figure it out.
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Permalink Reply by Skip Peel - Mineral Consultant on
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daddy bill, ?. I'm not using cubic feet. I am using mcf (thousand cubic feet) the standard pricing metric. Yes, natural gas prices do not have to rise much to have a substantive impact on rate of return. A 50 cent RoR would be significant. I am deliberately trying to be conservative with my variables. We should keep in mind that once the monthly settlement basis price of natural gas becomes greater than the price hedged, operators must account for that as a loss. I expect we will see a meaningful increase in hedge prices for all quarters of 2021. Thanks for your input.
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Skip I will try a different tact. Assume the gross price per mcf is 2.00. The royalty owners are assumed to receive 25 percent or fifty cents per mcf. This is 5 times your half a billion dollars for 10 cents profit. the royalty owners would therefore receive 2,500,000,000 dollars. I do not know the acreage developed by these 4 wells but if we assume 1280 acres this would be 1,953,000 dollars per acre.
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Permalink Reply by Skip Peel - Mineral Consultant on
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daddy bill, you are missing the post production deductions for royalty interests. Take that 50 cents per mcf and reduce it by your percentage post production deductions for gather & treating, dehydrating, transportation, etc. I warned against trying to turn this into a royalty calculation, it is not configured for that. And because the variance in post production deductions may be impacted by minimum volume commitments and marketing fees in addition to those deductions listed above, that would take a whole different set of calculations and would be difficult to pose as an "average" royalty income. Also my calculations are for production over twenty years.
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Skip okay let's cut it by i/3 for post production costs, the royalty per acre is only 1,302,000 dollars per acre. Is this realistic?
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Permalink Reply by Skip Peel - Mineral Consultant on
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Not realistic at current prices. Post production costs are not based on a percentage of the sale price. They are based on an mcf. For this reason, as the price goes down, the percentage of post production deductions goes up. Taking gathering and treating as an example, if the cost is 35 cents per mcf that would equal 18.4 percent of a $1.90/mcf gross sales price. That is only one of a number of deductions. If the price is $2.50/mcf, the G&T cost would be equal to 14 percent. At $3, 11.6%.
Post production costs vary greatly so trying to come up with an average is an exercise in futility. I know of wells literally next door to one another operated by different companies. One has a G&T cost of ~$0.30/mcf and the other has a cost of ~$1.20 /mcf. Choose whatever percentage you wish and then figure the decline rate of production over twenty years. You're really getting us in the weeds here. :-)
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Permalink Reply by dbob on
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Skip
in this sequence "
Leaving out LOE (Lease Operating Expense) and factoring a 25% NRI (Net Royalty Interest):
Each 1000’ of lateral should produce an EUR of 2.5 Bcf. If we assume that the operator
Nets 75% of that then 1.875 Bcf. Plug in whatever you think the average price per mcf over
the life of the wells and then arbitrarily a net profit per mcf, say 10 cents.
1,875,000,000 X $0.10 = $18,750,000 or about ten times the D&C cost.
27.52: Total lateral lengths divided by 1000’. 27.52 X $18,750,000 = $516,000,000, ~half a billion dollars."
1,875,000,000 should actually be 1,875,000 mcf
So your value should be $5,160,000.
Think of it a different way - the example wells have made about 45,900,000 mcf. 45,900,000 mcf X $0.10 = $4.59 million.
Anyway, it ends up being pretty close to a 10% net return assuming $0.10/mcf.
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Well dbob spoiled my fun. Remember in my first post I said the key was mcf not cubic feet and told you to figure it out. You were so busy educating me that you never stopped to think you were espousing ridiculous numbers that were inflated by a factor of one thousand. can you imagine wells making $125,000,000 each of profit on 10 cents per mcf. Old petroleum engineer here with 60 years in the business.
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Permalink Reply by Skip Peel - Mineral Consultant on
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dbob, you are correct thanks for catching my error. daddy bill, your cubic feet comment didn't register. Went right over my head. Sorry for missing it. I got caught up in your attempt to turn my calculation into one for royalty income.
So, back to the original reason for going through this exercise. As the rig count has rebounded on slightly better gas prices, and anticipation they will continue to improve, we are back to the rig count we had when I began the weekly rig report in February. And as unlikely as it may seem, Haynesville shale operators are turning a profit. Do either of you think the 10% net return is too low?
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Permalink Reply by James L. Williams on -
I did a back of the envelope estimate of what royalty owners could expect in Western San Augustine county where there have recently been some good wells drilled in both the Haynesville Shale and Bossier Shale. I tried to identify all assumptions so someone can duplicate the analysis with different assumptions for their particular situation. Here is the analysis:
Economics of Gas Wells along State Hwy 21 in West San Augustine County
System Engineer’s like to say that if you cannot show that something works on the back of an envelope it is probably not a good idea. This is an analysis of the payoff of natural gas wells drilled along State Hwy 21 near the Attoyac River where sufficient wells have recently been drilled in both the Haynesville and Bossier Shales to provide some guidance on what might be expected.
It is generally considered now that with enhanced fracking the EUR from both formations is about 2.5 Bcf per 1000 feet of lateral. For estimating purposes assume a unit of 1280 acres, one mile running east and west and two miles running north and south to support 10,000-foot laterals. If we assume that each lateral drains out to 400 feet to each side of the lateral, the area drained by each well is
Drained area = 10,000 feet X 800 feet/ (43,560 sq. ft./acre)
= 183.65 acres/well
The Unit has 1280 acres so
Number of wells = 1280 acres/ 183.65 acres/well = 6.97 wells
To be conservative round down to 6 wells per formation.
There are two formations, so the total number of wells is 12.
Each well has an EUR of 2.5 Bcf/1000 ft. of lateral. Discount that to 2.2 Bcf to account for less than perfect fracks so EUR for each well is 2.2 Bcf/1000 ft X 10,000 ft/well = 22 Bcf/well.
EUR for the Unit = 12 wells X 22 Bcf/well = 264 Bcf
If we assume that the price received for the gas is $2.50/Mcf and gathering and transportation costs $0.30/Mcf, then the net price is $2.20/Mcf.
If we conservatively assume that the royalty is 1/5 then the royalty owners receive 264E9 cf X $2.20/1000 cf X (1/5) =
$116,160,000.
The royalty per acre is $116,160,000/1280 acre = $90,750/acre.
Comstock Resources recently bought gas production in this part of the Haynesville Shale and in a recent presentation estimated a life for the field of 58 years, so it may take a long time to get the projected income.
Estimating the Present Value is problematical because there are a lot of important things that we do not know, like the operator’s plans, do they need cash flow, are they willing to wait for higher prices, etc. And there are a lot of important things that are unknowable, like are Democrats going to win the next election with a “blue wave,” taking over all branches of government with a super majority as is the situation now in California, after which they can impose regulations to discourage drilling or, as they ultimately desire, ban fracking altogether.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Nice analysis James. Just the kind of reply I was hoping for. Thank you. Would you agree that for individual well life, twenty years is in the ball park? What I think many mineral owning members of the site would like is an estimate of how that $90.750 per acre is paid out in monthly royalty over time. We know well production is front end loaded. I think that currently 80% of EUR in the first 24 months is a reasonable assumption.
I'm not concerned about what Democrats will do. I'm concerned about what the natural gas segment of the industry will do. They have wasted valuable time in making changes to best operating practices and pushing public relations efforts in support of natural gas. I hope there is still time but I suspect the window is closing fast.
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Permalink Reply by James L. Williams on
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Skip,
I'm 84 years old, retired aerospace engineer, so I don't have any contacts in the oil and gas industry and only know what I read plus insight from the RRC site. I've seen the estimate that 75 or 80% of the gas is produced in the first two years, and that may have been true for the wells drilled back 7 or 8 years ago. I don't have insight into the operator's procedures, but the more recent wells aren't following that path. It may be that the operators are deliberately restricting flow to improve EUR.
Take a look at BP America's Koala #5 H (Lease #283268) located South of Denning on Hwy 21 just East of the Attoyac River (where I was born). It was completed in mid-July 2017. I estimated it to be,perhaps, a 17 to 18 Bcf EUR well. Production to June 2020 was 10,261,460 Mcf. That's 60% in 3 years if EUR is 17 Bcf.
Production was:
Year 1: 4,405,830 Mcf
Year 2: 3,801,593 Mcf
Year 3: 2,055,037 Mcf
Year 3 production was 25% of production through the first 2 years.
I doubt BP America has a cash flow problem, so they may have curtailed production some recently due to the current low NG price.This well started decline at about 18 months and is well into decline now so in another year we should be better able to predict production over time for the rest of the well's life.
If my EUR estimate of 17 Bcf is about right, then 26% came out the first year, 48% in two years, and 60% in three years.
I'll have to do some research to see if Koala #5 H is exceptional or typical. From a cursory glance at some recent wells picked at random it appeared to be good but not an outlier.
This might be useful for estimating income from recent wells. Of course income depends on Natural Gas price. (It appears from a cursory glance that Haynesville and Bossier wells are very similar in production.)
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