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
YEAR -TO-DATE AVG: $2.045
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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: 20342
Replies to This Discussion
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Permalink Reply by Skip Peel - Mineral Consultant on
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You're welcome. If you can navigate SONRIS, you can examine the small handful of modern, long lateral wells that have "nibbled" around the edge of the low porosity zone. Once east of the eastern half of 11N-14W or south of those townships, well production returns to the average for the fairway. I suspect that other operators will eventually test the edges but I don't expect to see long laterals fully inside the zone. Porosity equals Gas In Place (GIP) and no completion design can fix low GIP.
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Permalink Reply by Jimmy Hamiter on
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I appreciate it!
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Permalink Reply by Steve P on -
Skip: Comstock drilled 4 CULs in 26/35 12 - 15 and 2 11 - 15 that seem to be pretty good wells. Moving West from that line there are few HA wells for a mile.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Steve: That's nibbling around the edge. I mentioned that there are a few but none that are more than a section into the townships If memory serves. And only Comstock knows how much of the production is coming from Section 2. All the ones that are further into the townships from the edge are old, early version wells that produced a quarter to a third what the same well design produced outside of the zone. While Chesapeake was drilling them, one after the other, we were trying to figure out why considering the IP results. At the time, the only thing that I could come up with was the possibility that the Mid-Bossier didn't exhibit the same low porosity. Now many of those sections are unleased and open for development to any company that thinks they can drill an economic Bossier well.
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Permalink Reply by NuevoRiche on
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So do the different gas companies use this price tracker to figure what the royalty owner will receive for his gas that month? Or do they use the price of gas the day the royalty check is issued?Thanks
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Permalink Reply by Skip Peel - Mineral Consultant on
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This is my price tracker based on the Henry Hub monthly settlement price published the last few days of each month for the coming month. No, the industry doesn't use this. Each company sells their gas on a negotiated price that uses a specific natural gas hub as the base price. If a company is selling their gas through the Perryville hub, they will negotiate the price for the coming month based on that hub's settlement price. As far as I know, that negotiated price will be something less than the hub price. A discount. Companies do not "publish" that price but it does appear on monthly royalty statements or on the EnergyLink.com website for the companies that use that site. There are multiple natural gas sales hubs and the main ones are covered on the EIA website. Henry Hub has been used as the main baseline price hub for decades although more gas likely goes through Perryville, Carthage and a handful of other regional hubs over the last fifteen years.
https://atlas.eia.gov/datasets/eia::natural-gas-trading-hubs/explore
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Permalink Reply by Mister Sunday on
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XTO paid for July:
$2.28 MMBtu BSI KEYDETS DU #H1
$2.06 MMBtu BSI KEYDETS B 01
$2.29 MMBtu KEYDETS A-47 4H
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Permalink Reply by Skip Peel - Mineral Consultant on
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Thanks, Mister Sunday. Those prices suck.
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Permalink Reply by Rock Man on
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Are these prices prior to any deductions (marketing, transmission, compression, etc)?
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Permalink Reply by Nat Gas Engineer on
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I am also in the Keydets unit and can confirm that the gas prices he stated for those three wells are prior to any deductions.
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Permalink Reply by Skip Peel - Mineral Consultant on
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Thanks, NGE. That's what I expected. I'd like to know what the net mcf price was after the post production deductions.
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Permalink Reply by Nat Gas Engineer on
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Skip, my net mcf price after post-production deductions calculates to be $1.75 for the Keydets A-47 well. Note that I only have 9-1/2 acres in the Keydets unit so my net value will be different than others. I am hoping to get the post-production deductions straightened out soon with XTO as our lease agreement does not allow for these deductions to be taken. I(we) went through this with them a few years back on the adjacent Boll Weevils unit we have interest in. Took about 8 months for them to get it straightened and the deductions reimbursed. Seems as though they (XTO) try to revert to a standard lease when new wells are drilled in a unit even though an existing lease agreement is already in place.
Sorry to take so long to respond. I had to find my slide rule to do this calc. I do have a few but all I can do is take them out of the case, remember that I am not smart enough to use it and then put it back in the desk drawer.
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