Natural Gas

In the News:

Countries in the Middle East and North Africa supply about one-third of global LNG

Nearly one-third (29%) of global liquefied natural gas (LNG) exports in 2022 was supplied by exporting countries of the Middle East and North Africa (MENA) region—Qatar, Oman, the United Arab Emirates (UAE), Algeria, and Egypt—according to data from the International Group of Liquefied Natural Gas Importers (GIIGNL). The MENA region's share of global LNG exports declined from 47% in 2013 to about 30% by 2020, as LNG exports from Australia and the United States have grown.

Qatar is the top LNG exporter in the MENA region, accounting for 70% of regional LNG exports in 2022. Globally, Qatar is one of the top three LNG exporters, with exports averaging 10.3 billion cubic feet per day (Bcf/d) during the last 10 years. Oman and the UAE are the second- and third-largest LNG exporters in the Middle East. Oman started exporting LNG in 2000, and exports have consistently averaged 1.2 Bcf/d over the last decade. LNG exports from the UAE (specifically from the emirate of Abu Dhabi) started in 1977 and averaged 0.7 Bcf/d over the last decade. LNG exports from Yemen started in 2010 and averaged 0.8 Bcf/d from 2011 to 2014, but they have been suspended since May 2015 following a military conflict.

In North Africa, two countries export LNG—Algeria and Egypt. Algeria was one of the world’s first LNG exporters and has over 40 years of LNG export history. Algeria’s LNG exports have remained stable over the last 10 years, ranging from 1.3 Bcf/d to 1.7 Bcf/d. Despite considerable domestic natural gas reserves, Algeria’s ability to increase LNG exports in the near term is limited due to insufficient investment to maintain and expand natural gas production from aging fields and growing domestic demand.

Egypt exported 0.9 Bcf/d in both 2021 and 2022. LNG exports from Egypt depend on domestic demand and the volume of available natural gas for export. In recent years, domestic natural gas consumption in Egypt has increased while production declined, which contributed to Egypt temporarily suspending its LNG exports in 2015. Egypt has been importing natural gas from Israel via the East Mediterranean Gas (EMG) pipeline (up to 0.7 Bcf/d) and the Arab Gas Pipeline (AGP) (up to 0.2 Bcf/d). At the start of the Israeli-Hamas conflict beginning in October, Israel suspended exports to Egypt via the EMG pipeline because of production stoppages at the offshore Tamar field, which supplies the EMG pipeline (Tamar field production has since been restarted).

Egypt’s LNG exports peak in winter months when domestic demand is low, and Egypt can export surplus natural gas (including imports from Israel) as LNG. During last winter (November 2022 through March 2023) Egypt’s LNG exports averaged 2.0 Bcf/d, according to data from CEDIGAZ.

Most of the MENA region's LNG exports are shipped to South Asia and East Asia, which accounted for 65% (9.7 Bcf/d) of the region’s LNG exports in 2022. The share of the MENA region's LNG exports going to South Asia and East Asia has remained fairly consistent over the past 10 years, varying between 60% and 70% of the total. The MENA region's LNG exports to Europe, which fluctuate depending on European natural gas demand, have ranged from 3.5 Bcf/d to 4.8 Bcf/d during the past 10 years. In 2022, MENA’s exports to Europe averaged 4.5 Bcf/d, 30% of the MENA region's total LNG exports. Up to 4% of exports from the MENA region are supplied to other MENA region countries—Kuwait and the UAE (specifically the emirate of Dubai).

Market Highlights:

Prices

• Henry Hub spot price: The Henry Hub spot price fell 2 cents from $2.72 per million British thermal units (MMBtu) last Wednesday to $2.70/MMBtu yesterday.
• Henry Hub futures price: The December 2023 NYMEX contract expired Tuesday at $2.706/MMBtu, down 19 cents from last Wednesday. The January 2024 NYMEX contract price decreased to $2.804/MMBtu, down 23 cents from last Wednesday to yesterday. The price of the 12-month strip averaging January 2024 through December 2024 futures contracts declined 12 cents to $2.983/MMBtu.
• Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, November 22 to Wednesday, November 29). Price changes ranged from a decrease of $1.23/MMBtu at the Algonquin Citygate to an increase of $2.00/MMBtu at Northwest Sumas.
• Price changes in the Northeast were mixed this week. At the Algonquin Citygate, which serves Boston-area consumers, the price went down $1.23 from $4.73/MMBtu last Wednesday to $3.50/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 4 cents from $2.45/MMBtu last Wednesday to $2.49/MMBtu yesterday. The Algonquin Citygate price reached a weekly high of $10.15/MMBtu on Tuesday, as colder weather moved into the region. Temperatures in the Boston Area averaged 39°F this report week, resulting in 183 heating degree days (HDDs), 42 HDDs more than last week. Natural gas consumption in New England increased 16% (0.4 billion cubic feet per day [Bcf/d]), according to data from S&P Global Commodity Insights. This increase was driven by a 35% (0.5 Bcf/d) increase in residential and commercial sector consumption to meet increased demand for space heating. In addition, since October 20, the Millstone nuclear power station in Waterford, Connecticut, has been operating at approximately 40% of capacity, which is contributing to increased natural gas consumption for electric power generation to make up for lower nuclear power-generation capacity.
• In the Midwest, the Chicago Citygate price was unchanged from last Wednesday at $2.55/MMBtu despite a 32% (4.9 Bcf/d) increase in natural gas consumption. Residential and commercial sector consumption rose 60% (4.2 Bcf/d) week over week. Temperatures in the Chicago Area averaged 29°F this week, 8°F below normal, which resulted in 249 HDDs, 109 HDDs more than last week and 51 HDDs more than normal. Natural gas storage inventories in the Midwest totaled 1,111 billion cubic feet for the week ending November 24, which is 6.5% more than year-ago levels and 6.7% more than the five-year (2018–2022) average. In addition, net natural gas flows into the Mid-Continent region, which come from Canada, the Rocky Mountain region, and the Northeast region, increased 3% (0.3 Bcf/d), according to data from S&P Global Commodity Insights.
• Prices across the West Coast increased this week. The price at PG&E Citygate in Northern California rose $1.26, up from $4.90/MMBtu last Wednesday to $6.16/MMBtu yesterday, and the price at the SoCal Citygate in Southern California increased $1.93 from $4.26/MMBtu last Wednesday to $6.19/MMBtu yesterday. Natural gas consumption in California increased 13% (0.7 Bcf/d), according to data from S&P Global Commodity Insights. Temperatures in the Sacramento Area averaged 50°F this week, resulting in 105 HDDs, 36 HDDs more than last week. The price at Northwest Sumas on the Canada-Washington border rose $2.00 from $3.87/MMBtu last Wednesday to $5.87/MMBtu yesterday. Natural gas consumption in the Pacific Northwest increased 23% (0.6 Bcf/d). Temperatures in the Seattle-Tacoma Area averaged 38°F, resulting in 189 HDDs, 42 HDDs more than last week. In addition, maintenance on the Gas Transmission Northwest pipeline reduced available pipeline capacity by approximately 0.7 Bcf/d for natural gas deliveries into the Pacific Northwest.

Daily spot prices by region are available on the EIA website.

• International futures prices: International natural gas futures prices decreased this report week. According to Bloomberg Finance, L.P., weekly average front-month futures prices for liquefied natural gas (LNG) cargoes in East Asia decreased 26 cents to a weekly average of $16.57/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands decreased 45 cents to a weekly average of $13.97/MMBtu. In the same week last year (week ending November 30, 2022), the prices were $31.01/MMBtu in East Asia and $40.01/MMBtu at TTF.
• Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, rose by 9 cents/MMBtu, averaging $6.78/MMBtu for the week ending November 29. Weekly average ethane prices fell 1%, while weekly average natural gas prices at the Houston Ship Channel rose 7%. The ethane premium to natural gas fell 25% week over week. The ethylene spot price and the ethylene premium to ethane were both unchanged on the week. The average weekly propane price and Brent crude oil price both rose 1%, and the propane discount relative to crude oil increased 1% on the week. Normal butane prices rose 1%, isobutane prices rose 9%, and natural gasoline prices remained relatively unchanged.

Supply and Demand

• Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas rose by 1.0% (1.1 Bcf/d) compared with the previous report week. Dry natural gas production grew by 0.3% (0.3 Bcf/d) to a weekly average of 105.5 Bcf/d, and average net imports from Canada increased by 14.5% (0.8 Bcf/d) from last week. U.S. dry natural gas has averaged above 105 Bcf/d so far in November, an increase of 2.5% (2.6 Bcf/d) from October, as production grew in both the Appalachian and Permian regions and the Cana-Woodford basin in Oklahoma.
• Demand: Total U.S. consumption of natural gas rose by 21.0% (17.3 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Residential and commercial sector consumption climbed by 50.8% (13.8 Bcf/d) as colder weather moved across the country. Natural gas consumed for power generation rose by 6.7% (2.1 Bcf/d) week over week, and industrial sector consumption increased by 5.5% (1.3 Bcf/d). Natural gas exports to Mexico increased 4.0% (0.2 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 14.3 Bcf/d, or 0.1 Bcf/d lower than last week.

Liquefied Natural Gas (LNG)

• Pipeline receipts: Average natural gas deliveries to U.S. LNG export terminals decreased by 0.6% (0.1 Bcf/d) week over week, averaging 14.3 Bcf/d, according to data from S&P Global Commodity Insights. Natural gas deliveries to terminals in South Louisiana decreased by 1.5% (0.1 Bcf/d) to 8.7 Bcf/d. Natural gas deliveries to terminals in South Texas increased by 1.7% (0.1 Bcf/d), and natural gas deliveries to terminals outside the Gulf Coast decreased by 2.2% (less than 0.1 Bcf/d).
• Vessels departing U.S. ports: Twenty-four LNG vessels (nine from Sabine Pass; four each from Calcasieu Pass and Freeport; three each from Cameron and Corpus Christi; and one from Cove Point) with a combined LNG-carrying capacity of 91 Bcf departed the United States between November 23 and November 29, according to shipping data provided by Bloomberg Finance, L.P.
• LNG terminals: On November 27, Freeport LNG Development, L.P. received approval from the Federal Energy Regulatory Commission (FERC) to return to service Phase 2 facilities, which includes LNG Loop 2 and Dock 2 for ship loading.

Rig Count

• According to Baker Hughes, for the week ending Tuesday, November 21, the natural gas rig count increased by 3 rigs from a week ago to 117 rigs. The Haynesville and Marcellus each added one rig, and one rig was added among unidentified producing regions. The number of oil-directed rigs remained unchanged from a week ago at 500 rigs; the Cana Woodford added 1 rig and the DJ-Niobrara dropped 1 rig. The total rig count, which includes 5 miscellaneous rigs, stands at 622 rigs, 162 fewer rigs than last year at this time.

Storage

• Net injections into storage totaled 10 Bcf for the week ending November 24, compared with the five-year (2018–2022) average net withdrawals of 44 Bcf and last year's net withdrawals of 80 Bcf during the same week. Working natural gas stocks totaled 3,836 Bcf, which is 303 Bcf (9%) more than the five-year average and 341 Bcf (10%) more than last year at this time. We have not reported a net injection this late in November in the last 10 years.
• According to The Desk survey of natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net withdrawals of 18 Bcf to net injections of 10 Bcf, with a median estimate of net withdrawals of 3 Bcf.

See also:

• Natural Gas Analysis Reports
• Short-Term Energy Outlook