Graph and download economic data for Henry Hub Natural Gas Spot Price (DHHNGSP) from 1997-01-07 to 2025-07-28 about natural resources, gas, price, and USA.

Average natural gas in the U.S. Henry Hub stood at 2.53 U.S. dollars per million British thermal unit in 2023, a decrease when compared to the previous year. Henry hub natural gas prices peaked in 2008 at 8.85 U.S. dollars per million British thermal unit.

Natural gas rose to 3.09 USD/MMBtu on August 1, 2025, up 0.10% from the previous day. Over the past month, Natural gas's price has fallen 11.31%, but it is still 57.26% higher than a year ago, according to trading on a contract for difference (CFD) that tracks the benchmark market for this commodity. Natural gas - values, historical data, forecasts and news - updated on August of 2025.

On July 4, 2025, the Henry Hub natural gas spot price amounted to 3.19 U.S. dollars per million British thermal units. In January 2025, a cold front was feared to impact refiners, leading to a spike in prices. The European gas benchmark Dutch TTF also rose amid colder weather. What is Henry Hub? The Henry Hub price is seen as the most important benchmark for the U.S. natural gas market. As of 1990, it has been used for pricing of natural gas traded on the New York Mercantile Exchange and later the Intercontinental Exchange. The hub in question is a distribution pipeline system in Louisiana and began operating in the 1950s. The highest Henry Hub annual average prices were recorded in 2005 and 2008, when they climbed to over eight U.S. dollars per million British thermal units. Weekly average prices also reached nearly 10 U.S. dollars in 2022 as a result of global supply constraints. Natural gas export prices In recent years, the U.S. has been incentivized to build up its liquefaction and LNG export capacities as it widens the potential customer pool. With sanctions on Russian energy imports, many European countries looked to the U.S. for procuring natural gas from 2022 onward. In line with Henry Hub pricing development, the monthly LNG export price also showed volatility depending on market and geopolitical events.

United States - Henry Hub Natural Gas Spot Price was 3.12000 $ Per Mil. BTU in July of 2025, according to the United States Federal Reserve. Historically, United States - Henry Hub Natural Gas Spot Price reached a record high of 23.86000 in February of 2021 and a record low of 1.05000 in December of 1998. Trading Economics provides the current actual value, an historical data chart and related indicators for United States - Henry Hub Natural Gas Spot Price - last updated from the United States Federal Reserve on August of 2025.

United States - Henry Hub Natural Gas Spot Price was 2.19000 $ Per Mil. BTU in January of 2024, according to the United States Federal Reserve. Historically, United States - Henry Hub Natural Gas Spot Price reached a record high of 8.86000 in January of 2008 and a record low of 2.03000 in January of 2020. Trading Economics provides the current actual value, an historical data chart and related indicators for United States - Henry Hub Natural Gas Spot Price - last updated from the United States Federal Reserve on August of 2025.

Graph and download economic data for Global price of Natural Gas, US Henry Hub Gas (PNGASUSUSDQ) from Q1 1991 to Q1 2025 about henry hub, gas, World, and price.

Graph and download economic data for Global price of Natural Gas, US Henry Hub Gas (PNGASUSUSDM) from Jan 1991 to Jun 2025 about henry hub, gas, World, and price.

Natural gas account for 1/4 of the global demand and roughly 1/3 of the US energy demand. After oil, Natural gas is the most dominate sort of energy. So, being about to improve natural gas demand prediction is extremely valuable.

Therefore, this project aims to predict the demand of Natural Gas in the US by combining a wide range of datasets including the time series of major Natural Gas Prices including US Henry Hub. Data comes from U.S. Energy Information Administration. Need to forecast the price of natural gas based on the historical data.

Data

Dataset contains Daily prices of Natural gas, starting from January 1997 to current year. Prices are in nominal dollars.

Time series of major Natural Gas Prices including US Henry Hub. Data comes from U.S. Energy Information Administration EIA

Dataset contains Monthly and Daily prices of Natural gas, starting from Ja...

The average monthly price for natural gas in the United States amounted to **** nominal U.S. dollars per million British thermal units (Btu) in May 2025. By contrast, natural gas prices in Europe were about three times higher than those in the U.S. Prices in Europe tend to be notably higher than those in the U.S. as the latter benefits from being a major hydrocarbon producer. Europe's import reliance European prices for natural gas rose most notable throughout the second half of 2021 and much of 2022, peaking at over ** U.S. dollars per million Btu in August 2022. The sharp rise was due to supply chain issues and economic strain following the COVID-19 pandemic, which was further exacerbated by Russia’s invasion of Ukraine in early 2022. As a result of the war, many countries began looking for alternative sources, and Russian pipeline gas imports to the European Union declined as a result. Meanwhile, LNG was a great beneficiary, with LNG demand in Europe rising by more than ** percent between 2021 and 2023. How domestic natural gas production shapes prices As intimated, the United States’ position among the leaders of worldwide natural gas production is one of the main reasons for why prices for this commodity are so low across the country. In 2023, the U.S. produced more than ************ cubic meters of natural gas, which allays domestic demand and allows for far lower purchasing prices.

Gas export to Japan has become an important source of revenue for Indonesia since the 1970s. Traditionally, the gas was priced with linkage to the oil price. However, changes in the market during the early 2010s has put pressure to this traditional pricing mechanism. Using the Vector Auto-regression (VAR) approach, this research aims to understand whether the spot LNG import pricing in Japan is moving away from JCC linkage or not, and the extent of the change if there is any. LNG price analyzed in this research is the Japanese spot cargo import price, published by the Japanese Ministry of Economy, Trade and Industry from March 2014 to November 2017. The Japanese LNG spot price was regressed against US Henry Hub (HH) and UK NBP gas hub prices, Japan Customs-Cleared (JCC) crude oil price, and Japan imported coal price in the same period.The historical decomposition of the VAR model suggests that the spot LNG price in Japan were increasingly affected by US Henry Hub and UK NBP gas prices, while the effect of JCC crude oil price is weaker, and Japanese imported coal having no significant effect towards Japanese spot LNG price. The impact of mature gas hub prices is also dynamic: HH is showing stronger effect in the mid 2016, then it changed to the domination of NBP in mid 2017.The result further indicates the increasing connectivity of gas price around the world, with US and UK price affecting Japanese gas price through spot LNG trade. Due to the demand condition in Japan and East Asian market in general, the continuation of US/European gas hub price effect is likely to happen until early 2020s, as the slight deficit in this region might be fulfilled by spot LNG import. Under the new domestic gas pricing regulation in Indonesia, the continuation of NBP impact towards gas pricing in Japan might reduce the price to the level at which fulfilling the increasing domestic gas demand is more efficient than exporting LNG.

The global natural gas price index stood at 200.29 index points in June 2025. Natural gas prices increased that month as cooling demand increased. The global price index takes into account indices from Europe, Japan, and the United States – some of the largest natural gas trading markets. The U.S. is the leading natural gas exporter in the world. Means of trading natural gas Liquefied natural gas (LNG) is the most common form of trading natural gas. Although piped gas is often the preferred choice for transportation between neighboring producing and consuming countries, seaborne trade as LNG has grown in market volume. This is in part thanks to high consumption in pipeline-inaccessible areas such Japan, Korea, and China, as well as the recent increase in LNG trade by European countries. Major natural gas price benchmarks The natural gas prices often used as global benchmarks are Europe’s Dutch TTF traded on the Intercontinental Exchange, Indonesian LNG in Japan, and the U.S. Henry Hub traded on the New York Mercantile Exchange. 2022 was an especially volatile year for natural gas prices, as supply was severely constrained following sanctions on Russian imports. Other reasons for recent spikes in gas prices are related to issues at refineries, changes in demand, and problems along seaborne supply routes.

Propane fell to 0.70 USD/Gal on August 1, 2025, down 2.49% from the previous day. Over the past month, Propane's price has fallen 3.32%, and is down 3.36% compared to the same time last year, according to trading on a contract for difference (CFD) that tracks the benchmark market for this commodity. Propane - values, historical data, forecasts and news - updated on August of 2025.

Natural gas distributors have benefited mainly from the enormous outburst of natural gas availability in the United States since the early 2000s because of the growing prevalence of advanced drilling techniques employed by upstream producers in the Oil Drilling and Gas Extraction industry. Natural gas is used to generate electricity, produce useful thermal output and as an industrial feedstock. Many end users, mainly electric power plants, have been pressed to transition to using this energy source at the expense of others because of its increased affordability and comparatively lower environmental impact. Despite the rising popularity of renewable energy like wind and solar, natural gas already has years of historical infrastructure built, making the supply chain much easier to navigate, leading the country to rely on it for most of its energy needs. Revenue is set to swell at a CAGR of 4.6% through the end of 2025 to $199.3 billion, including a 9.5% dip in 2025, as gas prices will rebound. Despite revenue growing swiftly as the need for gas overwhelmingly expanded during the current period, distributors have also endured wild swings in revenue because of highly volatile market conditions. For example, the price of natural gas fell in 2020 amid shutdowns as excess supply was built. Prices then spiked in 2021 and 2022 before falling again in 2023 as the industry stabilized following economic turmoil. Despite all this, the residential sector has been a saving grace, as prices have continued to climb yearly despite outside factors. Even so, overall profit has been pushed down as distributors lowered their selling prices. Natural gas production will climb marginally, while infrastructure investments will boost pipeline and export capacity. Thanks to global tensions, total domestic consumption is set to strengthen. Even so, consumption may be constrained growth as some markets slowly switch to renewable energy, constraining growth. Prices are also set to remain stagnant, which may prevent significant revenue spikes. Overall, revenue is set to climb at a CAGR of 0.7% through the end of 2030 to $205.9 billion.

United States' electricity producers paid about 2.75 U.S. dollars per million British thermal unit for natural gas in 2024. Meanwhile, coal power plant operators paid an average of 2.48 U.S. dollars. In the last decade, the price of natural gas used for electricity generation has seen a net decrease, followed by a considerable rise in 2022. Coal, on the other hand, has consistently been among the cheapest fuel types used in the power sector. Natural gas prices and the influence of oil demand As it is often produced alongside oil, prices for natural gas are shaped by overall market developments of the oil and gas industry. When an overproduction of oil led to the oil glut between 2015 and 2016, natural gas prices fell notably. The same circumstance could be observed in 2020 when a fall in oil demand brought many benchmarks such as WTI and Brent to historic lows and also resulted in the Henry Hub price falling to a 21-year low. Apart from petroleum, which is an expensive and inefficient means of power production, fossil fuel costs for electricity generation have declined since 2022. Shift away from conventional energy sources Although renewable technologies were once thought to be very expensive, greater investments have quickly rendered their levelized cost of energy generation on par with fossil fuels, especially when deployed on a utility-scale. The aging coal fleet is a prime example of the increasing necessity to switch to carbon neutral technologies. Older coal plants are dealing with increasing maintenance costs as well as environmental regulations forcing the installation of pollution controls.

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Description

Spartan Delta is a highly attractive E&P company with a three year 113% return using strip pricing and a 10% FCF/EV exit multiple, equivalent to a 29% IRR over that time period. My thesis rests on 3 points.

- Management is phenomenal, having already made cash distributions to shareholders worth multiples of what they have raised over the last 5 years, using their acquire, develop, and sell approach.

- In the past year they have quietly assembled a new oil/condensate land base that 2 other industry players have recently gone all-in on. This will move them from a primarily gas producer to a more balanced liquids weighting of 40% over time, vastly improving netbacks and free cash flow.

- While I model everything on forward strip, there is a reasonable case to be made that AECO is grossly mispriced. With Canada’s first LNG facility coming online in the next few months (export capabilities of 11% of western Canads total production), the discount to Henry Hub should narrow back to transportation costs, repricing LT AECO from $3 cad to $4. If this were to occur the upside return is 222% on a 3-year basis.

Cap Table and Target Price:

History:

The Spartan management team has been together for 15 years in a few different vehicles (see appendix), but this iteration of Spartan Delta (SDE) started in December 2019. Since that time they have raised $537mm of equity from investors while returning $1,809mm via dividends and special distributions, and still having equity value of $761mm. In total that equates to a 4.8x MOIC. A quick timeline for SDE:

- Dec 2019, initial equity raise in a shell at $1.00 per share

- May 2020, buy Bellatrix deep basin assets out of bankruptcy, raise equity at $2.00. SDE uses these assets to get to scale and harvest cash flows

- May 2021 buy Montney footprint, August 2021 acquire Velvet to finish Montney footprint. Shares issued $4.35 and $5.05

SDE proceeded to grow and derisk their acquired Montney assets for the next 1.5 years before selling them to Crescent point for $1.7 billion. Post closing, SDE paid out a $9.50 special distribution to shareholders and issued 1 share of newco Logan Energy, worth 70c at the time. Shareholders also kept their SDE shares, now worth about $3.50. With a prior $1 per share distribution made in 2022 you can see how well shareholders who bought in via the equity raises have done.

One of the co-founders of SDE moved over to Logan while remaining Chairman of SDE. His partner, Fotis Kalantzis remained at SDE along with most of the senior team.

New Duvernay Play:

Since that 2023 distribution and spin, SDE has been quietly building up a new land play in the Duvernay, while using the original deep basin assets for cash flow and scale. Same game plan.

- Nov 2023 announced west shale Duvernay land buys for $25mm. Comes with 400 boe/d (who cares) And 137,000 acres of land (interesting)

Management says at the time “After over a decade of development, Spartan believes the Duvernay is poised to offer repeatable, economic results with a significant depth of inventory. Similar to Spartan’s entry into the up-dip oil window of the Montney in 2021, the Company views its timing on the entry into the West Shale Basin Duvernay as optimal as the fairway is fragmented, undercapitalized and supports growth with available egress and existing underutilized infrastructure. Additionally, the West Shale Basin Duvernay possess geotechnical attributes comparable to the Kaybob Duvernay and the East Shale Basin Duvernay. Recent activity and new top-tier well results from bordering operators demonstrate the commerciality and scalability of the play”

- May 2024 announced a Willesden Green Duvernay acquisition for $53 million. Comes with 1,600 producing BOE/D and 38,000 acres. This is on top of small tuck ins over prior months bringing acreage to 240,000 net.

Initial well results on SDE Duvernay lands have been promising, but there have also been two recent transactions of comparable producers going all-in on the play.

Model:

Let’s take a quick look at the model before jumping into the new play.

We see in 2024 almost all production is coming from the deep basin/legacy assets (gas and lower value liquids). Over time as Duvernay wells are drilled the company economics (netbacks) on strip pricing improve greatly.

Here’s how I get there on new well drilling:

Quick note: stay-flat deep basin capex should be about $100mm a year to maintain 35k boe/d of production (mostly gas).

Crux of my thesis then comes down to the assumptions on the new Duvernay wells. Before that, using above assumptions heres how cash flow evolves.

I get to my target price by using a 10% forward UFCF/EV on Dec 31 2027, so on a 3 year timeframe.

New Duvernay Play:

The key assumptions above are the Initial Production 365 metrics, cost per well and condensate rate. For those less familiar, condensate is a natural gas liquid that is primarily used in Alberta as a mixer for heavy oil to become less viscous so it can flow on pipes. Alberta is a net importer of Condensate, so it is normally priced at WTI +- a couple dollars. With current usd/cad fx rates at 1.44 spot is currently $105 cad a barrel

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SDE has 390 net sections of land and estimates 300 net locations for drilling (which I think is low and will go higher over time). In my assumptions above you can see I start them off at 8 Duvernay wells drilled this year trending to 12 in 2027. So in my outyear they would still have ~ 24 years of drilling inventory.

To date they have brought on stream 2 wells. The first was drilled by the previous owner in 2019 and only completed in 2024. IP30 rates were ,1394 boe/d coming out 82% liquids and 58% condy. The second well hit issues when drilling and completing so was only 60% of the normal well length. Despite that the well produced 937 boe/d IP30 coming out 92% liquids and 80% condy.

They have drilled another 2 wells which were likely brought on stream in December and we should get a first look at results in the coming weeks. Well costs were at the high end of the $11.5mm-$13.5mm range but should trend down towards 12mm over time as the play begins to get productionzied.

The 2 wells detailed above, which adjusted for well 2 completion issues, averaged 1,477 IP30 and support an IP365 assumption of 600 boe. However 2 wells is a very small sample size. Luckily a comparable, Paramount Resources, has just gone all-in on the play and has provided more details on the play.

Paramount Resources (POU) announced on November 14th that they would be selling their Montney lands for $3.3 billion which is 2/3rds of their production. Paramount is using the proceeds to make a $15 cash distribution to shareholders and to go all-in on developing the Willesden Green Duvernay.

“The sale of the assets represents a pivotal milestone for Paramount as it continues to successfully execute its strategy of early-stage resource capture, delineation and development followed by strategic value realization. Following closing of the transaction, Paramount will focus on the development of its Duvernay assets at Willesden Green and Kaybob North, which have significant growth potential and production that all flows through company-owned-and-operated infrastructure.”

Post close Paramount plans to use their large cash balance to grow Duvernay production aggressively, taking total production from 30k boe/d today (only a small amount Duvernay) to 60k boe/d in exit 2026 (most of the growth being Duvernay). Here’s what they said

“Paramount's production immediately following closing of the transaction will be approximately 30,000 Boe/d (barrels of oil equivalent per day) (46 per cent liquids), substantially all of which flows through company owned and operated infrastructure. The company expects that the post transaction budget will result in average 2025 sales volumes of 37,500 Boe/d to 42,500 Boe/d (48 per cent liquids), driven primarily by fourth quarter production growth at Willesden Green, and a 2025 exit rate in excess of 45,000 Boe/d.

Approximately $560-million of the posttransaction budget, at the midpoint, is allocated to the Willesden Green Duvernay development. Capital activities will include the completion of the first phase of the company's new Alhambra plant, with start-up expected in the fourth quarter of 2025, as well as the continued execution of the drilling program to feed the plant on start-up. In addition, Paramount is, conditional upon completion of the transaction, accelerating the second phase of the Alhambra plant, with start-up of this phase expected to occur in the fourth quarter of 2026. Each phase of the Alhambra plant will provide 18,000 Boe/d of raw handling capacity (comprising 50 MMcf/d (million cubic feet per day) of raw gas