Prices are rising along the Gulf Coast as demand in the Southeast and Texas outpaces supply. The Henry Hub spot price jumped 85 cents from $8.45/MMBtu last Wednesday to $9.30/MMBtu yesterday over the report week (Wednesday, May 18 to Wednesday, May 25). Prices in the South were higher, despite the region’s temperatures returning to normal after many weeks of above-average temperatures. According to data from PointLogic, declines in natural gas consumption by the electric power sector along the Gulf Coast, which fell by 0.6 billion cubic feet per day (Bcf/d) (12%) this report week, were more than offset by growth in feed gas deliveries to LNG export terminals in the region, which increased by more than 0.9 Bcf/d (9%) to 11.7 Bcf/d. After averaging 3F above normal last week, temperatures in the Houston Area averaged 79F this report week, on par with typical for this time of year, resulting in cooling degree days (CDDs) declining from 118 CDDs last week to 102 CDDs this report week. Deliveries of feed gas to Texas LNG export facilities grew by 0.4 Bcf/d, while deliveries to Louisiana terminals increased by 0.6 Bcf/d.
As temperatures fluctuate, prices in the Midwest rise in lockstep with the national average.
The spot price at the Chicago Citygate rose 77 cents from $8.16/MMBtu last Wednesday to $8.93/MMBtu yesterday. Even as regional demand in key sectors fell, higher spot natural gas prices at the Henry Hub kept Midwest prices high.
As natural gas’s share in energy generation rises in California, prices climb across the West. The price at PG&E Citygate in Northern California jumped 67 cents yesterday, from $9.70/MMBtu on Wednesday to $10.37/MMBtu yesterday, reflecting higher natural gas costs at significant origin points into the PG&E service zone. This report week, the price at Malin, Oregon, the northernmost delivery point into PG&E service region, increased by $1.07/MMBtu, from $9.70/MMBtu last Wednesday to $10.37/MMBtu yesterday. The price of natural gas in the Malin hub climbed 90 cents from $8.15/MMBtu last Wednesday to $9.05/MMBtu yesterday at Opal, Wyoming, the origin location of the Ruby Pipeline. The key pricing point for natural gas into the Pacific Northwest, Sumas on the British Columbia/Washington State border, climbed 87 cents from $7.95 last Wednesday to $8.82/MMBtu yesterday. This report week, temperatures over much of the West, notably in the Rocky Mountains, are below normal. This report week, the average temperature in the Seattle City Area was 56F, 2F lower than typical. According to statistics from PointLogic, natural gas usage in all sectors of the Pacific Northwest declined by 0.2 Bcf/d (13%).
From $8.71/MMBtu last Wednesday to $10.11/MMBtu yesterday, the pricing at SoCal Citygate in Southern California climbed $1.40. This report week, temperatures in the Riverside Area, inland from Los Angeles, averaged 68F, 4F cooler than the previous report week and 1F cooler than normal. According to statistics from PointLogic, natural gas consumption in the residential and commercial sectors in California declined by 0.1 Bcf/d (7%) while consumption in the electric power sector climbed by 0.2 Bcf/d (13%). California’s natural gas share of electricity generation jumped to 42.7 percent on May 24 from 31.2 percent the day before, the highest level since April 26.
Prices in the Northeast are rising as natural gas use in all industries rises. The spot price of natural gas jumped $1.04 from $7.99/MMBtu last Wednesday to $9.03/MMBtu yesterday at the Algonquin Citygate, which serves Boston-area customers. The spot price for New York City climbed 45 cents from $7.78/MMBtu last Wednesday to $8.23/MMBtu yesterday at the Transcontinental Pipeline Zone 6 trading point. According to statistics from PointLogic, natural gas use in New England and the New York and New Jersey area was up across the board this week, with temperatures ranging from several degrees above normal to several degrees below normal. Over the weekend, both regions saw above-average temperatures, resulting in higher natural gas use in the electric power sector. Temperatures in the Central Park Area of New York averaged 78F (14F over normal) throughout the weekend, resulting in 27 CDDs. The average temperature in the Boston Area on Sunday was 73F (13F above normal), resulting in 8 CDDs. Because temperatures were below normal on other days of the week, natural gas consumption in the residential and commercial sectors increased this week in both regions, resulting in 14 heating degree days (HDDs) in the New York Central Park Area and 28 HDDs in the Boston Area, respectively, up from 1 HDD and 10 HDDs last week.
Prices in Appalachia are rising, albeit at a slower rate than in most other markets. Even though natural gas usage in the region declined, spot prices grew in the Appalachian region, mirroring other prices across the United States, but not as much as at the Henry Hub. Total natural gas usage in Appalachia fell by 0.2 Bcf/d (3%) due to lower consumption by the electric power sector. The spot price for Tennessee Zone 4 Marcellus jumped 38 cents from last Wednesday to $7.85/MMBtu yesterday. Eastern Gas South in southwest Pennsylvania increased its price 54 cents from last Wednesday to $8.11/MMBtu Tuesday.
Prices in West Texas rise, but not as much as near the Gulf Coast. The price of natural gas at the Waha Hub in West Texas, which is near Permian Basin production, increased by 76 cents this report week, from $7.97/MMBtu last Wednesday to $8.73/MMBtu yesterday. The Waha Hub traded 57 cents below the Henry Hub price Tuesday, compared to 48 cents below the Henry Hub price last Wednesday. According to statistics from PointLogic, natural gas production and disposition (in-region consumption plus flows to other regions) in the Permian Basin region both declined by about 0.4 Bcf/d (2%) this week.
The supply of natural gas in the United States has decreased marginally week over week. According to statistics from PointLogic, overall natural gas supply in the United States declined by 0.2 percent (0.2 Bcf/d) over the previous report week. From the previous report week, dry natural gas output fell by 0.1 percent (0.1 Bcf/d), and average net imports from Canada fell by 1.9 percent (0.1 Bcf/d).
Natural gas demand in the United States climbs modestly as temperatures fluctuate. According to data from PointLogic, total natural gas consumption in the United States increased by 1.7 percent (1.0 Bcf/d) over the previous report week. This report week, temperatures in much of the West were below normal, while temperatures in the South, Mid-Continent, and Northeast were mainly above normal, but have moderated in comparison to previous weeks. Residential and commercial usage rose 16.3 percent (1.6 Bcf/d) week over week, accounting for the biggest growth in consumption. Natural gas deliveries to US LNG export plants (LNG pipeline receipts) increased as well, averaging 12.9 Bcf/d, up 0.9 Bcf/d from the previous week. Consumption in the industrial sector climbed by 1.4 percent (0.3 Bcf/d) week over week. Natural gas use for power generation was down 2.8 percent (0.9 Bcf/d) week over week, somewhat offsetting these gains. Mexico’s natural gas exports remained constant at 5.6 Bcf/d.
This week, US LNG shipments increased by five tankers over the previous week. According to shipping data provided by Bloomberg Finance, L.P., twenty-four LNG vessels (eight from Sabine Pass, five from Freeport, four from Corpus Christi, three from Cameron, and two each from Calcasieu Pass and Cove Point) with a combined LNG-carrying capacity of 90 Bcf departed the United States between May 19 and May 25. Higher exports are due in part to the completion of seasonal maintenance at LNG terminals this week.
What caused the price of natural gas to fall?
Definitely not before the end of the summer, according to Patrick de Haan, Gas Buddy’s head of petroleum analysis.
In an email, de Haan said, “I really don’t see much that would force prices down in the future weeks or even months.” “I don’t believe we’ll see any relief until global supply improves or global demand declines. All signals lead to up, not down, in terms of things like a resolution between Ukraine and Russia or an economic downturn. The supply situation is unlikely to improve very soon, and with the world economy still recovering from the pandemic, I don’t expect demand to drop down much either.”
Although Severin Borenstein, an energy economist at UC Berkeley’s Haas School of Business, agrees that a price drop is unlikely anytime soon, he does point to one encouraging prognosis.
The cost of gasoline is determined by the price of crude oil. Supply is currently limited, resulting in high pricing. The shortages began during the COVID-19 epidemic. Early in the epidemic, demand for oil fell, then rose, but production and supply struggled to keep up. Oil businesses, according to Borenstein, are having a difficult time rehiring staff and getting their equipment back up and running.
What is causing the decrease in natural gas production?
According to our recently issued Natural Gas Annual, natural gas production and consumption in the United States fell in 2020 due to mild winter weather and the impact of the COVID-19 epidemic on demand.
In the United States, less natural gas was consumed, lowering costs; the annual Henry Hub spot price for 2020 was $2.03 per million British thermal units (MMBtu), the lowest annual price since 1997.
Low costs helped boost natural gas exports and consumption in the electric power industry to new highs in 2020.
Is natural gas on the decline?
Natural gas demand in the United States is decreasing as temperatures increase in several major cities. According to data from PointLogic, total natural gas consumption in the United States declined by 3.5 percent (2.3 Bcf/d) from the previous report week.
What does the future hold for natural gas?
- The Henry Hub natural gas spot price was $6.59 per million British thermal units (MMBtu) in April, up from $4.90 in March and higher than the $2.66/MMBtu average in April 2021. The Henry Hub price is expected to average $7.83/MMBtu in 2Q22 and $8.59/MMBtu in 2H22. Natural gas storage levels are expected to be lower than the five-year average (20172021) this summer, resulting in high anticipated natural gas prices. Limited opportunities for natural gas-to-coal switching for power production contribute to lower-than-average storage levels, which we expect to maintain natural gas demand for power generation strong despite high prices. If summer temperatures are hotter than expected and energy consumption is higher, natural gas prices could soar dramatically above projected levels. Furthermore, we anticipate that liquefied natural gas (LNG) shipments from the United States will stay high throughout the summer. In 2023, we predict the Henry Hub spot price to average $4.74/MMBtu. The 2023 price prediction reflects our expectation that natural gas production would rise next year, but LNG export and demand growth will decelerate, resulting in greater storage levels in 2023 than in 2022.
- Natural gas stockpiles were estimated to be 1.6 trillion cubic feet (Tcf) at the end of April, which is 17% lower than the five-year average. At the end of April, inventories were 190 billion cubic feet (Bcf) greater than they were at the end of March. Because of below-normal temperatures, which increased demand for natural gas for heating despite relatively flat output, this increase was below the five-year average. Natural gas inventories are expected to rise by 418 Bcf in May, bringing the month’s total to 2.0 Tcf, which is 14% lower than the five-year average for this time of year. Natural gas inventories are expected to complete the 2022 injection season (end of October) at around 3.4 Tcf, which is 9% lower than the five-year average. Summer temperatures, on the other hand, will be critical to storage, and a hotter-than-normal summer with high energy demand could result in smaller stockpiles and higher prices than expected.
- Exports of US LNG averaged 11.6 billion cubic feet per day (Bcf/d) in April, slightly lower than the all-time high of nearly 12.0 Bcf/d recorded in March. From May to August, we expect US LNG exports to average 12.1 Bcf/d, which is slightly lower than our earlier prediction. This projection includes a little reduced LNG demand in Asia and Europe this summer compared to our prior forecast, owing in part to the continuation of high natural gas prices. We estimate that US LNG shipments will average 12.0 Bcf/d this year, up 23% from 2021. Capacity expansions have propelled LNG export growth in recent years. However, we do not anticipate any additional export facilities coming online during the forecast period, thus growth in LNG exports is expected to drop to 5% in 2023, with LNG exports averaging 12.6 Bcf/d.
- Natural gas consumption in the United States is expected to reach 85.7 Bcf/d in 2022, up 3% from 2021. Colder temperatures and higher usage in the residential and commercial sectors in 2022 compared to 2021 are to blame for the increase in natural gas consumption in the United States. In response to increased economic activity, we predict the industrial sector to consume more natural gas in 2022. Furthermore, despite high natural gas prices, forecast natural gas consumption in the electric power sector is expected to rise in 2022 due to limited natural gas-to-coal switching. We anticipate that natural gas consumption would average 85.3 Bcf/d in 2023, down 1%, owing to assumed milder winter temperatures (based on National Oceanic and Atmospheric Administration forecasts) that will reduce residential and commercial use.
- We estimate that dry natural gas output in the United States averaged 95.5 Bcf/d in April, up 0.4 Bcf/d from March. Despite the fact that production in April was lower than it was in December 2021, it has increased in each of the previous two months. Production increases in April were limited compared to March due to below-normal temperatures and snow in certain producing locations, as well as regular pipeline maintenance. In May, dry natural gas output is expected to average 95.8 Bcf/d, according to our projection. Dry natural gas output is expected to average 96.7 Bcf/d in 2022, which is 3.2 Bcf/d higher than in 2021. In 2023, we anticipate dry natural gas output to average 101.7 Bcf/d.
What factors are currently influencing natural gas prices?
Increases in natural gas supply usually lead to reduced prices, whereas declines in supply usually result in higher costs. Demand increases tend to lead to higher prices, while demand drops tend to lead to lower prices. Higher prices, on the other hand, tend to temper or reduce demand while encouraging output, whereas lower prices have the reverse impact.
Short-term spikes in demand and/or reductions in supply may cause major swings in natural gas prices, especially during the winter, due to natural gas supply infrastructure constraints and the inability of many natural gas consumers to switch fuels fast.
Is natural gas a viable option?
Supplies began to run out in the years following 2000, and gas prices continued to rise. The next unconventional resource is shale gas, which extracts gas from extremely tight shale rocks. It took a long horizontal well, fracked several times along its length, to expose huge sections of the shale and allow enough gas molecules to percolate to the well.
Mitchell Energy and Devon EnergyDVN proved shale gas in the Barnett Shale, and it swiftly expanded to other shale basins in the US. Natural gas prices had been steadily rising and had reached $7 per thousand cubic feet (Mcf) before growing shale gas knocked it down to below $4/Mcf in 2009, where it stayed for the most part until 2021. (Figure 1).
In the early 2000s, coalbed methane in Wyoming’s Powder River basin was at its peak, with over 24,000 wells drilled. However, many stranded and abandoned coalbed methane wells have attested to the price drop since then.
Shale gas was a game-changer.
The United States has surpassed Russia as the world’s top gas producer.
Long horizontal wells, a new technology, were quickly used in the United States to improve oil output. It resulted in the United States becoming self-sufficient in oil and gas for the first time since 1947.
The low cost of shale gas prompted industry to switch from coal to gas-fired power facilities. Gas burns far cleaner than coal, resulting in considerable reductions in greenhouse gas (GHG) emissions to the point that the US met the Paris Agreement signed in 2015.
However, additional investigations revealed that the claimed advantage of burning gas over coal was only valid if gas leakages in wellheads and pipelines were less than 2% of the gas passing through the pipes. The explanation was simple: gas leaks emit methane, which has a warming effect of 21-80 times that of carbon dioxide, the primary GHG released when coal, natural gas, or gasoline are burned.
Natural gas is not an effective substitute for coal-fired power stations if gas leakage reach 3%. Now, if the leaks are measured and rectified, as EDF (Environmental Defense Fund) has advocated in recent years, gas can become a valuable bridge to the future, as the oil and gas business has advocated. This realization has sparked a large-scale effort to seal gas leaks in wells, pipelines, gas processors, and other oil and gas infrastructure.
Liquefied natural gas (LNG) has just recently been exported from the United States. The United States is presently the world’s third largest LNG exporter, trailing only Australia (LNG from coalbed methane) and Qatar. LNG shipments are primarily exported out of Gulf Coast ports like Sabine Pass, Louisiana.
Jack Fusco, the CEO of Cheniere Energy, revealed some impressive data about a month ago. Natural gas was $2/Mcf in the United States, Europe, and Asia during the pandemic, he claimed (Figure 2). However, as economies flourished and businesses around the world sought gas for the clean energy transition, gas demand soared.
In September, prices in the United States were $5/Mcf, whereas in Europe and Asia, they were $20/Mcf. His company exports LNG and has nearly sold out of LNG production for the next 20 years.
For many years, Russia, the world’s second-largest gas producer behind the United States, has sold natural gas to Europe. Germany has traditionally received 40% of its gas from Russia. Some of this gas is delivered via a pipeline that runs through Ukraine, and some is delivered via the Nord Stream 1 pipeline that runs beneath the Baltic Sea.
Nord Stream 2 is a twin pipeline that was constructed just last month and is on the same track as its sister. Gazprom, the Russian state-owned enterprise, owns 100% of this new pipeline and also owns 51% of Nord Stream 1. A collection of European energy corporations, including Shell, is paying half of the $11 billion construction costs for Nord Stream 2.
This is where geopolitics comes in. Because it believed that more Russian gas would indicate too much Russian influence, as well as fewer LNG shipments from the US to Europe, the US imposed sanctions on Russian corporations. Because of the Solar Wind cyber attacks, Washington is likely to slap new sanctions on Russia, but Nord Stream 2 will not be targeted this time, ostensibly to restore relations with Germany.
Due to tensions with Russia over the ongoing crisis in eastern Ukraine, Ukraine is concerned that gas and pipeline lease money will be transferred to Nord Stream 2.
Due to lower storage and greater home heating expenditures in the coming winter, gas prices are rising in Europe and the United Kingdom. The shortfall is the result of a lack of long-term contracts between Europe and Gazprom, as well as a quick recovery following the Covid epidemic.
According to the International Energy Agency, Russia might be a trusted partner and even allow gas shipments to climb 15% to alleviate Europe’s gas supply shortage. With the launch of Nord Stream 2, Russia appears to have hinted at a deal.
Natural gas, oil, and coal industries have long contended that it is a bridge to renewable energy since it burns cleaner (emits less CO2) than coal and oil. That is correct.
However, this was before gas leaks in wells and pipelines reduced natural gas’s net GHG benefit over coal in power plants. Methane, the escaping gas, is 25 to 80 times more harmful than CO2 depending on whether it is released in the short or long term.
Since then, a concerted effort to reduce methane leakage from oil and gas operations has gained traction. EDF has exerted a significant influence by meticulously measuring methane emissions and demonstrating that they are greater than previously estimated levels, as well as by pressing for the installation of trustworthy measurement equipment to address the problem. As a result, if the leaks can be located and repaired, natural gas could be a viable option for a carbon-free future.
Indeed, BP has forecasted a bright future for natural gas, predicting that it will provide 22% of primary energy by 2050 “compared to 45 percent for renewables in their “Rapid” future scenario. DNV predicts that gas will remain relatively stable between 2020 and 2050, whereas oil and coal will begin to decline in 2025.
LNG is supplied to other nations to help them transition from coal to natural gas and reduce their greenhouse gas emissions. China imports a lot of LNG from the United States, but they continue to build new coal power plants purportedly to save employment because they mine a lot of coal, but also to help the poorer or less developed regions of their vast economy.
The most recent twist is the addition of an RSG label to LNG (responsibly-sourced gas). RSG is gas that has a minimal carbon footprint since methane leaks in wells, pipelines, and tanks are kept to a minimum, if not zero. This is part of a new movement.
A BP vessel recently delivered2 their latest LNG cargo to Southeast Asia, which was verified as safe “LNG with a carbon offset.” They calculated all GHG emissions from well production to terminal unloading and retired corresponding credits from the company’s internal carbon-trading portfolio.
PureWest Energy, Wyoming’s largest natural gas producer, recently became the first company in the United States to offer RSG to its consumers.
Project Canary, an evaluation firm, gave PureWest a platinum rating for gas generated in the previous quarter. This certification covered the carbon-neutral footprint of gas wells, as well as gas transmission and storage. This, according to the CEO, is the cleanest natural gas in terms of greenhouse gas emissions.
Renewable natural gas, or RNG, is another recent trend in the oil and gas business. RNG is commonly defined as gas produced from agricultural waste. ChevronCVX has announced a greater investment in biomethane gas from dairy products, in collaboration with Brightmark, an agricultural waste firm. Chevron plans to sell RNG as compressed natural gas for use in autos. It’s a positive step toward decarbonizing agriculture.
To summarize, natural gas has evolved from sandstones for much of its history in the United States to modern-day unconventionals such tight gas, coalbed methane, and shale gas. On the geopolitical scene, natural gas also manages to thrive. More recently, gas has demonstrated its versatility by adopting new labels like RSG and RNG, which will aid the world in overcoming the obstacles of the transition to renewable energy sources.
1. The Story of Man, by Cyril Aydon (Philadelphia: Running Press, 2007).
2. news from bp