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: 1956
Replies to This Discussion
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Permalink Reply by Skip Peel - Mineral Consultant on
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Thanks, James. The original calculations of decline rates (2008-2010) were for 70-75% in the first 12 months. That was in the "lease retention" phase of the play when there was little interest in adjusting well designs and choke protocols. The period immediately following saw a handful of companies experimenting with "restricted choke" programs and over a year or so all operators moved to restricted chokes. That dropped the first year of the curve by maybe 20%. In the next iteration of well and completion designs. longer laterals dropped the curve again. I suspect that if you model some additional wells you may find that the Koala #5 has a more shallow decline curve than the average. It takes longer for the current long lateral wells to "clean up" and reach their maximum 24 hour flow rate. The volumes of water and proppant are so much larger that clean up can take days or in some cases weeks. That can often create a higher volume produced in the second month than in the first. If the well was completed late in the first month of reported production then the second and third months will be greater so production is increasing. In the majority of cases I have seen, decline, for an individual well, will always begin by the fourth month excepting unusual cases. I have heard of only one other instance of flat production volumes for a length of time as long as 18 months. That was a Louisiana Haynesville well so I was able to access some additional information. It turned out that the "toe" of that well was drilled in to an area of heavy faulting. Attempting to drill through a fault with a significant "throw" is a bad idea but drilling up to a fault can allow the frac to connect with a much larger natural fracture network in the shale.
I'll look for EUR statements in Haynesville operator's press releases and corporate presentation and update their decline curve. I believe there are some in the second quarter operating results recently released by publicly traded Haynesville operators.
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Permalink Reply by Rock Man on
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Appears that all this is considering undiscounted ROR - which is intriguing but not what operators are looking at. The time / value of $$$ over time can only be truly evaluated using discounted economics which considers various PV (present value numbers) numbers.
Depending on the discounted economic results, NOT drilling may be the best move (and keep money in the bank).
Not a simple analysis to do on back of envelope / need one of those economic software tools .
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Permalink Reply by Skip Peel - Mineral Consultant on
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I agree and I have seen some of those pv formulas. They are above my pay grade. I do think that the modest IRRs claimed by some operators are accurate and underpin their claims to make a profit at some of these ridiculously low nat gas prices. Still some post IRRs based on $3 or $2.50 gas and the actual realized internal rate of return would have to discounted back from there. I think that if it were not for hedges there would be few instances of any profit for most.
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Permalink Reply by dbob on
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IMHO, hedges are important. The other thing that is important is for those operators who either directly own the a portion of the mineral interest, and/or who have leases paying less than 25% to the mineral owner.
I think with the risks involved, most would want a 30 to 40% IRR before really committing.
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Permalink Reply by Rock Man on
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Lots of factors do into the realized gas price that operators / producers receive. This includes deducts for transport, gathering, compression (if needed / comes into play for more depleted wells) and plant processing fees.
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Permalink Reply by Bud on -
Using Skip's numbers, what would the unit price of gas need to be to get a good return on drilling?
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Permalink Reply by Skip Peel - Mineral Consultant on
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Depends on the cost to produce an mcf and get it to a sales point. It does vary across the fairway and operator. I'm away from my computer, which has no power if I was there,so I can't pull up any data to support a reply. I suggest you go to the websites for Chesapeake, Comstock and Goodrich and review the most recent corporate presentations. They are quite recent so a good barometer. They like to frame the metric as Internal Rate of Return (IRR). You might want to cut and paste the pertinent parts of those presentations here so we can discuss. I'm thinking that currently the break even price is in the range of $1.90 to $2.35. For a fair review, you would need to include current the hedge price for each operator..
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