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


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.

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Now, by popular demand - the U.S. Natural Gas Monthly Settlement Price Tracker.  LOL!  Instead of relying on my usual short hand explanation of the different natural gas prices, I'm cutting and pasting off the internet.  The emphasis added is my own.  Although I am not a gas trader, I have been told by several associates who are, or were, that the vast volume of physical gas is sold on monthly contracts that are priced off a settlement price or basis (Henry Hub).  The monthly settlement price should be the price that correlates most closely to the price on a royalty statement for a given month. There is a caveat however that depends on the specific "hub" where the gas is sold.  We hear about Henry Hub because it has been the traditional bench mark for basis prices at other hubs.  With the advent of unconventional production, many more hubs now have significance.  The associated gas coming from the Permian Basin in west Texas and New Mexico has the WAHA hub.  Of significance for Haynesville/Bossier shale royalty owners, much of Haynesville Basin production is priced on the basis at the Perryville Hub in northeast La instead of the Henry Hub in south Louisiana (between Abbeville and New Iberia).  The way I understand it, the settlement price at a given hub is the benchmark used for negotiating a sales contract for physical delivery of gas (as opposed to futures contracts, "paper trades").  The sales price is therefore a negotiated premium or discount to the monthly settlement price for that particular hub.

I'm going to stop now before I get too far in the weeds on something that I know only a little about and end by saying that I believe that the monthly settlement price is the best benchmark for comparing the royalty price for the same month on your royalty statement.  I'll post a link to an article on Perryville below.  I welcome any corrections or additions by those members who have a greater grasp on natural gas pricing and trading.


June Vine 2.68

June Tellurian 2.79

June Indigo 2.98

May Vine 2.57

May Tellurian 2.52

May Indigo 2.80

For reasons unknown by me, there always seems to be a wide spread in the sales price for natural gas on royalty statements by various operators.  I do believe that most sales are discounts of some amount from a hub basis price.  I don't see monthly settlement prices for Perryville and have assumed that given the relatively close geographic locations that they would be very close to the same price.  That may or may not be true and those that would care to look more closely at the hub pricing that would be informative for their gas sales, there are subscription services that may provide the more detailed information.  One that several of my business associates use is Natural Gas Intelligence.  I am not familiar with the cost and do not use it as I have access to much of the raw data that I use on a daily basis from other public record and paid sources.  Here is a link to a Natural Gas Intelligence Perryville Hub page.


A large portion of the Haynesville gas is sold at the Carthage hub.  Especially the Texas areas. The geographical location where the operating companies originally started their developments played a large part in where the gas was marketed.  Most of the legacy companies had marketing agreements in place at the onset of the Haynesville development.  This may explain some of the difference?  The later entrants and those operators that had some relief from bankruptcy courts may have found better markets?  However, some of the old lease language specifies that the price is set at the “nearest market”.  The geographic location of the well will determine the market (hub) for these wells and may also explain the difference.

I get so much gas sold at one price and another portion of the gas paid at another price.  Same well same company.  

Would this be an Exco well?

Indigo. And "oddly" enough I get paid the lower amount on the larger portion.  Neither Vine nor Tellurian does this. 

OLDDOG, have you ever asked for an explanation from Indigo?

I asked CHK when they had the wells, they informed me the volume and pricing was in the contract to the customer they were selling to and the smaller amount sold at the higher price was the "left over" gas that was sold at market minus transportation and other costs.  My assumption is that Indigo kept same "scheme".

I REALLY REALLY hated to see CHK buy Vine out, even though they pay me less.  I REALLY REALLY wish Tellurian would have bought them.

Without knowing your details, it is hard to say.  There could be a myriad of operating joint agreements tied to the well that divide the production.  Each entity marketing their own portion.

Pretty much what CHK told me. Im just not as eloquent in the English language as you ;)


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