U.S. NATURAL GAS MONTHLY SETTLEMENT PRICE TRACKER
2021 U.S. Natural Gas Monthly Settlement Prices
JAN: $2.467
FEB: $2.760
MAR: $2.854
APR: $2.586
MAY: $2.925
JUN: $2.984
JUL: $3.617
AUG: $4.044
SEP: $4.370
OCT: $5.841
NOV: $6.202
DEC: $5.447
AVERAGE MONTHLY PRICE FOR 2021: $3.841
2022 U.S. Natural Gas Monthly Settlement Prices
JAN: $4.024
FEB: $6.265
MAR: $4.568
APR: $5.336
MAY: $7.267
JUN: $8.908
JUL: $6.551
AUG: $8.687
SEPT: $9.353
OCT: $6.868
NOV: $5.186
DEC: $6.712
YEAR-TO-DATE AVG: $6.644
2023 U.S. Natural Gas Monthly Settlement Prices
JAN: $4.709
FEB: $3.109
MAR: $2.451
APR: $1.991
MAY: $2.117
JUN: $2.181
JUL: $2.603
AUG: $2.492
SEP: $2.556
OCT: $2.764
NOV: $3.164
DEC: $2.706
YEAR-TO-DATE AVG: $2.737
2024 U.S. Natural Gas Monthly Settlement Prices
JAN: $2.619
FEB: $2.490
MAR: $1.615
APR: $1.575
MAY: $1.614
JUN: $2.493
JUL: $2.628
AUG:$1.907
SEP: $1.930
OCT: $2.585
NOV: $2.346
DEC: $3.431
YEAR -TO-DATE AVG: $2.269
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U.S. market mechanisms
The natural gas market in the United States is split between the financial (futures) market, based on the NYMEX futures contract, and the physical market, the price paid for actual deliveries of natural gas and individual delivery points around the United States. Market mechanisms in Europe and other parts of the world are similar, but not as well developed or complex as in the United States.
Futures market
The standardized NYMEX natural gas futures contract is for delivery of 10,000 million Btu of energy (approximately 10,000,000 cu ft or 280,000 m3 of gas) at Henry Hub in Louisiana over a given delivery month consisting of a varying number of days. As a coarse approximation, 1000 cu ft of natural gas ≈ 1 million Btu ≈ 1 GJ. Monthly contracts expire 3–5 days in advance of the first day of the delivery month, at which points traders may either settle their positions financially with other traders in the market (if they have not done so already) or choose to "go physical" and accept delivery of physical natural gas (which is actually quite rare in the financial market).
Most financial transactions for natural gas actually take place off exchange in the over-the-counter (OTC) markets using "look-alike" contracts that match the general terms and characteristics of the NYMEX futures contract and settle against the final NYMEX contract value, but that are not subject to the regulations and market rules required on the actual exchange.
It is also important to note that nearly all participants in the financial gas market, whether on or off exchange, participate solely as a financial exercise in order to profit from the net cash flows that occur when financial contracts are settled among counterparties at the expiration of a trading contract. This practice allows for the hedging of financial exposure to transactions in the physical market by allowing physical suppliers and users of natural gas to net their gains in the financial market against the cost of their physical transactions that will occur later on. It also allows individuals and organizations with no need or exposure to large quantities of physical natural gas to participate in the natural gas market for the sole purpose of gaining from trading activities.
Physical market
Generally speaking, physical prices at the beginning of any calendar month at any particular delivery location are based on the final settled forward financial price for a given delivery period, plus the settled "basis" value for that location (see below). Once a forward contract period has expired, gas is then traded daily in a "day ahead market" wherein prices for any particular day (or occasional 2-3-day period when weekends and holidays are involved) are determined on the preceding day by traders using localized supply and demand conditions, in particular weather forecasts, at a particular delivery location. The average of all of the individual daily markets in a given month is then referred to as the "index" price for that month at that particular location, and it is not uncommon for the index price for a particular month to vary greatly from the settled futures price (plus basis) from a month earlier.
Many market participants, especially those transacting in gas at the wellhead stage, then add or subtract a small amount to the nearest physical market price to arrive at their ultimate final transaction price.
Once a particular day's gas obligations are finalized in the day-ahead market, traders (or more commonly lower-level personnel in the organization known as, "schedulers") will work together with counterparties and pipeline representatives to "schedule" the flows of gas into ("injections") and out of ("withdrawals") individual pipelines and meters. Because, in general, injections must equal withdrawals (i.e. the net volume injected and withdrawn on the pipeline should equal zero), pipeline scheduling and regulations are a major driver of trading activities, and quite often the financial penalties inflicted by pipelines onto shippers who violate their terms of service are well in excess of losses a trader may otherwise incur in the market correcting the problem.
Basis market
Because market conditions vary between Henry Hub and the roughly 40 or so physical trading locations around United States, financial traders also usually transact simultaneously in financial "basis" contracts intended to approximate these difference in geography and local market conditions. The rules around these contracts - and the conditions under which they are traded - are nearly identical to those for the underlying gas futures contract.
Derivatives and market instruments
Because the U.S. natural gas market is so large and well developed and has many independent parts, it enables many market participants to transact under complex structures and to use market instruments that are not otherwise available in a simple commodity market where the only transactions available are to purchase or sell the underlying product. For instance, options and other derivative transactions are very common, especially in the OTC market, as are "swap" transactions where participants exchange rights to future cash flows based on underlying index prices or delivery obligations or time periods. Participants use these tools to further hedge their financial exposure to the underlying price of natural gas.
Views: 23197
Replies to This Discussion
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Permalink Reply by NuevoRiche on -
we think they are adjusting the price of the gas
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Permalink Reply by Steve P on
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CHK is still far below the prices posted here. Just got the info on my royalties for June 2023, and the price is still $1.77/1.78. The differential for May and June add up to "real money." Almost 20%.
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Permalink Reply by Skip Peel - Mineral Consultant on
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No mcf price on a royalty statement will match the monthly settlement price I post here. That price is a Henry Hub price and the price the operator gets is a discount to that price. Haynesville operators monthly prices on royalty statements vary from one to the other. Each is a separate negotiation. With CHK, in addition to the unknown discount to the hub price, you are charged a marketing fee. Add that marketing charge back to the mcf price and see how close to the settlement price it is. The monthly settlement price is the Henry Hub and little Haynesville sourced gas goes through Henry. Louisiana Haynesville production in the east portion of the fairway mainly goes to the Perryville Hub. Gas from the western portion of the fairway goes to the Carthage Hub. Those hubs will have a slightly different monthly settlement price than Henry, usually a discount. Post production deductions are based on a price per mcf. For that reason the percentage of deduction is greater the lower the price is. For example, a 20 cents per mcf charge represents a 10% deduction at $2 gas. At $4 gas, that deduction is 5%. I know, it's all confusing. And O&G companies have zero incentive to make it less so.
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Permalink Reply by M B Gilster on
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My CHK OR & WI are all in the Bethany Longstreet field w/ the June stub showing $1.96-1.98 whereas the May range was $1.84-1.86
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Permalink Reply by Mister Sunday on
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XTO paid for June:
$2.00 MMBtu BSI KEYDETS DU #H1
$1.98 MMBtu BSI KEYDETS B 01
$1.99 MMBtu KEYDETS A-47 4H
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Permalink Reply by Skip Peel - Mineral Consultant on
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The 2023 depressed natural gas price should be one of the shorter downturns in the commodity price cycle. 2024 should be considerably better although I'm unsure when we may see gas significantly above $4 for any extended period of time.
For those who like crystal ball projections, the futures price strip is somewhat entertaining to view from time to time. I've never seen an analysis of how accurate it has been over time in anticipating future prices. Here is a link. Click on Load All.
https://www.cmegroup.com/markets/energy/natural-gas/henry-hub-natur...
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Permalink Reply by Mister Sunday on
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Cool! Thanks Skip! I'm looking for silver to take off to carry me a bit until my natural gas starts making me some money again. If it will just get up there enough to take care of my mortgage and utilities...
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Permalink Reply by Skip Peel - Mineral Consultant on
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You're welcome. Although natural gas prices are expected to be better in 2024, look a few years beyond that. The average monthly price for 2026 is $4.012. Of course this is an industry projection and may not be accurate but it would be safe to not expect or plan for the very high prices we experienced last year.
I think copper may do better than silver.
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Permalink Reply by Mister Sunday on
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I don’t think you can go wrong with any of the group 11 metals. Except the radioactive one!
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Thanks for providing this, Skip. Does the futures market have much or any impact on a company's decision on when to drill? As I've shared in other discussions, as of August of last year Comstock has permission to drill up to 5 CU horizontal wells (005, 11N, 14W) that cross my property in the Spider Field.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Jimmy, the futures market is all about speculating on the future price of natural gas. Futures are "paper trades" that commit to a volume and price at a future date. Then these future contracts are traded. I'm not sure if even a minor percentage ever represent physical gas sales. I know that mineral buyers look to the futures price strip but I don't think it has any influence on operators' drilling schedule. When the price gets low, drilling slows but doesn't change the reasons that a well or wells are drilled. Many considerations impact when a well is drilled. Other than the super majors, operators must maintain a cash flow that covers everyday expenses. They must also maintain a minimum monthly production volume to keep their O&G leases in force. That's the legal principle of "production in paying quantities". Then there is the question of take away capacity. Operators prefer to drill multiple wells as it reduces the completion costs. See zipper fracs. Some operators have minimum volume commitments (MVC) with their mid stream pipeline companies. They have to maintain a contractual minimum volume of gas going through a gathering system or pay a penalty. Everything else being equal, an operator would prefer to drill in units where they have the highest net royalty interest (NRI). That means the lowest royalty burden which equates to better profit. Then you have rig contracts. Some contracts are nearing their term and some are beginning or being negotiated. The rigs that drill long lateral horizontal wells have high day rates. They are not cheap. Those are some of the issues that go into drilling schedules that come to mind, I'm sure that are others.
As to the wells you mention, Cross unit lateral wells covering the south 330' of Section 29, Section 32 in 12N-14W and 5 in 11N-14W, it will be interesting to see what Comstock does. Section 29 had June production of 84,491 mcf, a long way from needing new wells to hold leases. Section 32 has no Haynesville well though Comstock took 8 permits to drill from 2010 to 2018 and let them all expire undrilled. That's always been one of my unanswered questions. Comstock did the same in one or more additional sections in that area. This is a real "iffy" area that I call the Logansport Low Porosity Zone. It covers the sections in 11N-16W (Logansport), 11N-15W and at least the western half of 11N-14W. The wells drilled in these townships were very poor producers and generally condemned the area. A few wells have drilled along the edge of the low porosity zone and these five wells would be similar. More linear feet of lateral in 29 and 32 than in 5. Also those five wells are only "spacing approvals", not permits to drill. Operators generally apply for more well lateral slots than they intend to drill at one time and I would expect that Comstock may drill two to see how they produce. They are many such alternate well applications (approved as field orders) that were granted many years ago and never drilled. Some were in areas that weren't deemed economic and some were replaced by applications for longer lateral wells.
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Wow, thanks for all that intel. I'm section 32, 12N, 14W. I'm getting royalties on one well (Dugan 32-29 HC) they drilled in 2019 that follows the same "line" as those in the Field Order starting in section 5 and extending across mine to 29. Gross quantity has ranged from 800K+ to a leveled off 120K give or take (understanding a well produces most of its product early on). I'll just keep my fingers crossed.
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