In the News (EIA):
U.S. natural gas exports to Mexico reach record highs in June 2021:
Natural gas exports from the United States to Mexico surpassed 7 billion cubic feet per day (Bcf/d) on multiple days during June, according to pipeline data from Wood Mackenzie. The record high for the month was 7.4 Bcf/d on June 24. Increased power demand, high temperatures, and greater industrial demand, combined, drove the increased demand for natural gas. New pipeline additions have helped facilitate the increased volume of natural gas flowing to natural gas-fired power plants, industrial plants, and pipeline interconnections throughout Mexico. Natural gas pipeline exports from the United States to Mexico averaged 6.9 Bcf/d for June 2021, according to Wood Mackenzie estimates, which was a year-on-year increase of 25% and a 44% increase compared with the five-year (2016-20) average. Most of the increase can be attributed to greater flows on two cross-border pipelines: the Sur de Texas-Tuxpan Pipeline, which has a capacity of 2.6 Bcf/d and delivers natural gas from the U.S. border at Brownsville, Texas, to Tuxpan in Veracruz, Mexico; and the Trans-Pecos Pipeline (part of the Wahalajara system), which has a capacity of 1.4 Bcf/d and delivers natural gas to the U.S. border at Presidio, Texas. The Sur de Texas-Tuxpan Pipeline increased flows from about 0.8 Bcf/d in June 2020 to an estimated 1.7 Bcf/d in June 2021. The increased volume has been facilitated by recently expanded domestic pipeline connections and expansions of existing pipeline infrastructure in Mexico. The expanded infrastructure has allowed more natural gas to flow to power plants in the Mexico City region and to Mérida markets in the Yucatán Peninsula. The Wahalajara pipeline system, which connects the Waha Hub in West Texas to Guadalajara and other population centers in West-Central Mexico, has had increased flows coming from the Trans-Pecos Pipeline from about 0.2 Bcf/d in June 2020 to an estimated 0.8 Bcf/d in June 2021. Some of the increase on the Wahalajara pipeline system is from the increased flow capacity on the Villa de Reyes-Aguascalientes-Guadalajara Pipeline (VAG) in Central Mexico and subsequent delivery points that entered service upon its completion in October 2020. With increased access to natural gas imports, Mexico has increased its use of natural gas to generate electricity. Seasonally high temperatures in areas of northern and central Mexico during parts of June increased demand for electricity. Natural gas-fired power generation in Mexico was up 19% in June compared with last year. About 4.9 Bcf/d of natural gas was used for power generation in June 2021, compared with 4.2 Bcf/d in June 2020 and 4.4 Bcf/d in June 2019, according to Wood Mackenzie data. Natural gas used for industrial purposes also contributed to the increased natural gas demand in June. Industrial sector natural gas demand reached 3.3 Bcf/d in June 2021, up 31% from June 2020, largely driven by the recovery from COVID-19 and the related economic effects. Over the past few years, Mexico has relied increasingly on imported natural gas from U.S. pipelines. Pipeline imports accounted for 76% of Mexico’s total natural gas supply in June 2021, up from 40% in June 2015. Both domestic production and imports of liquefied natural gas (LNG) have been declining as a share of Mexico’s total natural gas supply.
Natural gas spot prices rose at most locations this report week (Wednesday, July 7 to Wednesday, July 14). The Henry Hub spot price rose from $3.60 per million British thermal units (MMBtu) last Wednesday to $3.75/MMBtu yesterday. The price of the August 2021 NYMEX contract increased 6¢, from $3.596/MMBtu last Wednesday to $3.660/MMBtu yesterday. The price of the 12-month strip averaging August 2021 through July 2022 futures contracts climbed 6¢/MMBtu to $3.478/MMBtu. The net injections to working gas totaled 55 billion cubic feet (Bcf) for the week ending July 9. Working natural gas stocks totaled 2,629 Bcf, which is 17% lower than the year-ago level and 7% lower than the five-year (2016–2020) average for this week. The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 4¢/MMBtu, averaging $9.33/MMBtu for the week ending July 14. Ethane prices rose 1%, while natural gas prices on the Houston Ship Channel rose 2%, narrowing the ethane premium to natural gas by 2% on a heat-value parity. Propane and normal butane prices fell 1%, isobutane prices fell 2%, and natural gasoline prices increased by 1%, following almost no change in the Brent crude oil prices. According to Baker Hughes, for the week ending Tuesday, July 6, the natural gas rig count increased by 2 to 101. The number of oil-directed rigs rose by 2 to 378. The total rig count increased by 4, and it now stands at 479.
Gulf Coast prices drift higher this week. This report week (Wednesday, July 7 to Wednesday, July 14), the Henry Hub spot price rose 15¢ from $3.60/MMBtu last Wednesday to $3.75/MMBtu yesterday. Temperatures were well above normal in the West, but generally near-normal or cooler-than-normal in the eastern half of the country. Prices in the western United States increase along with calls for energy conservation. The price at PG&E Citygate in Northern California rose 31¢, up from $4.71/MMBtu last Wednesday to $5.02/MMBtu yesterday. The price at SoCal Citygate in Southern California increased $1.19 from $5.26/MMBtu last Wednesday to $6.45/MMBtu yesterday. The California Independent System Operator (CAISO) issued a Flex Alert for Monday, July 12, urging residents to conserve electricity. High temperatures in the region and multiple wildfires were affecting transmission lines, limiting electricity imports from Oregon to California. On Tuesday July 13, the Flex Alert was lifted because CAISO predicted cooler temperatures. Amid the high demand, SoCalGas experienced six consecutive days of storage withdrawals during the report week, withdrawing from July 8–13. Midwest prices increase this week. Prices in the Midwest generally followed the price increase at the Henry Hub this week amid seasonally mild temperatures. At the Chicago Citygate, the price increased 15¢ from $3.41/MMBtu last Wednesday to $3.56/MMBtu yesterday. According to our Hourly Electric Grid Monitor, relatively weak wind generation in the areas served by the Midcontinent Independent System Operator (MISO) over the past week has led to a need for natural gas-fired generators to comcdce online to balance electricity demand in the region despite the cooler temperatures. Northeast Prices increase this week. At the Algonquin Citygate, which serves Boston-area consumers, the price went up 53¢ from $3.01/MMBtu last Wednesday to $3.54/MMBtu yesterday. At the Transcontinental Pipeline Zone 6 trading point for New York City, the price increased 37¢ from $3.26/MMBtu last Wednesday to $3.63/MMBtu yesterday. These price increases were accompanied by a decrease in dry natural gas production in the Northeast region since July 10, from 34.5 Bcf/d to 33.1 Bcf/d on July 14, according to IHS Markit and warmer temperatures compared to the previous week. Appalachian Basin prices drift higher with Henry Hub pricing this week. The Tennessee Zone 4 Marcellus spot price increased 40¢ from $2.65/MMBtu last Wednesday to $3.05/MMBtu yesterday. The price at Eastern Gas South (formerly known as Dominion South until June 1, 2021) in southwest Pennsylvania rose 39¢ from $2.73/MMBtu last Wednesday to $3.12/MMBtu yesterday. The price increases come amid a 1.4 Bcf/d decline in dry natural gas production in the Northeast, according IHS estimates. The Appalachian price increases come despite maintenance which began on the Rockies Express Pipeline (REX) on July 13 at the Bainbridge compressor station in Indiana, limiting flows from the Appalachian Basin to the Midwest. Permian prices decrease with slightly decreased natural gas consumption in the electric power sector. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $3.44/MMBtu last Wednesday, 16¢/MMBtu lower than the Henry Hub price. Yesterday, the price at the Waha Hub averaged $3.39/MMBtu, 36¢/MMBtu lower than the Henry Hub price. Temperatures in Texas were below normal this week, and consumption of natural gas in the electric power sector in Texas declined by 2.6%. At the same time, supply in the Permian Basin increased 1.6%. U.S. production increases 1.1% compared with last week. According to data from IHS Markit, the average total supply of natural gas rose by 1.1% compared with the previous report week. Dry natural gas production grew by 1.0% compared with the previous report week. Average net imports from Canada increased by 2.7% from last week. This was accompanied by a decrease in the price at Sumas on the Canada-Washington border, which fell 16¢ from $3.46/MMBtu last Wednesday to $3.30/MMBtu yesterday. U.S. consumption increases based on a strong increase in power generation. Total U.S. consumption of natural gas rose by 2.1% compared with the previous report week, according to data from IHS Markit. Natural gas consumed for power generation climbed by 3.4% week over week especially in the West. Industrial sector consumption increased by 1.5% week over week. Residential and commercial sector consumption declined by 2.2%. Natural gas exports to Mexico increased 2.3%. Natural gas deliveries to U.S. liquefied natural gas (LNG) export facilities (LNG pipeline receipts) averaged 10.8 Bcf/d, slightly lower by 0.18 Bcf/d than last week. U.S. LNG exports are flat week over week. Twenty LNG vessels (seven from Sabine Pass, four each from Corpus Christi and Freeport, three from Cameron, and one each from Cove Point and Elba Island) with a combined LNG-carrying capacity of 71 Bcf departed the United States July 8–14, 2021, according to shipping data provided by Bloomberg Finance, L.P. The Cameron LNG export facility operated by Sempra Energy conducted a brief scheduled maintenance on one of its trains last week, according to SP Global Platts. Natural gas feedgas deliveries to Cameron LNG declined to 1.3 Bcf/d on July 12, 2021, compared with 1.9 Bcf/d average July 1–11. The train has since returned to service, and feedgas deliveries to the terminal have averaged 1.9 Bcf/d July 13–14, 2021.
The net injections into storage totaled 55 Bcf for the week ending July 9, compared with the five-year (2016–2020) average net injections of 54 Bcf and last year’s net injections of 47 Bcf during the same week. Working natural gas stocks totaled 2,629 Bcf, which is 189 Bcf lower than the five-year average and 543 Bcf lower than last year at this time. According to The Desk survey of natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net injections of 39 Bcf to 55 Bcf, with a median estimate of 49 Bcf. The average rate of injections into storage is 16% lower than the five-year average so far in the refill season (April through October). If the rate of injections into storage matched the five-year average of 7.9 Bcf/d for the remainder of the refill season, the total inventory would be 3,530 Bcf on October 31, which is 189 Bcf lower than the five-year average of 3,719 Bcf for that time of year.