In the News (EIA):
Following Hurricane Maria in 2017, Puerto Rico’s LNG imports return to previous levels in the second quarter of 2018:
In 2018, Puerto Rico’s liquefied natural gas (LNG) imports neared 2016 annual levels, according to the U.S. Department of Energy, Office of Fossil Energy’s (FE) recently released LNG Annual Report. Imports into Puerto Rico were disrupted in 2017 after Hurricane Maria made landfall as a strong Category 4 hurricane on September 20, 2017. Puerto Rico imported 60.3 billion cubic feet (Bcf) of LNG in 2018, which was comparable to the 61.3 Bcf of total LNG imports in 2016.
Puerto Rico relies on fuel imports to meet its power generation needs. Nearly half of its generation was fueled by petroleum products and one- third of its generation was fueled by natural gas in 2017. All LNG imports are for electricity generation. Since September 2016, Puerto Rico has imported 100% of its LNG from Trinidad through long-term contracts. On average from 2013–2016, Puerto Rico received two LNG cargos per month—about 5 Bcf per month—into its Peñuelas LNG terminal in Ponce, Puerto Rico, which is located on the southwestern coast. Peñuelas typically operates at almost 90% of its regasification capacity of 186 million cubic feet per day (MMcf/d). Hurricane Maria made landfall in September 2017, heavily affecting imports. As a result, total imports in 2017 declined to 46.4 Bcf, a year-on-year decrease of 24%. From September through December 2017, LNG receipts were cut in half, with only one cargo per month. Puerto Rico resumed a normal level of LNG imports four months after the hurricane, although restoration efforts on electricity infrastructure took more than seven months. By April 2018, the Puerto Rico Electric Power Authority (PREPA) had restored electric power to 95% of customers. According to FE data, Puerto Rico has tripled its LNG imports since they first received cargos in 2005. The month before Hurricane Maria, the Federal Energy Regulatory Commission (FERC) had approved a 60% expansion of the Peñuelas regasification capacity from 186 MMcf/d to a total of 279 MMcf/d. According to FERC filings, EcóElectrica, L.P., the parent company, stated that disruption to the PREPA electric system and delays in restoration efforts had delayed the project from entering service until May 2018. Since the expansion, Puerto Rico imported a record 8.26 Bcf in September 2018.
Natural gas spot prices rose at most locations this report week (Wednesday, February 27 to Wednesday, March 6). Henry Hub spot prices rose from $2.85 per million British thermal units (MMBtu) last Wednesday to $2.94/MMBtu yesterday. At the New York Mercantile Exchange (Nymex), the price of the April 2019 contract increased 4¢, from $2.799/MMBtu last Wednesday to $2.841/MMBtu yesterday. The price of the 12-month strip averaging April 2019 through March 2020 futures contracts climbed 4¢/MMBtu to $2.976/MMBtu. Net withdrawals from working gas totaled 149 billion cubic feet (Bcf) for the week ending March 1. Working natural gas stocks are 1,390 Bcf, which is 15% lower than the year-ago level and 25% lower than the five-year (2014–18) average for this week. The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 19¢/MMBtu, averaging $6.59/MMBtu for the week ending March 6. The price of ethane, propane, butane, and isobutane fell by 2%, 4%, 5%, and 5%, respectively. The price of natural gasoline remained flat week over week. According to Baker Hughes, for the week ending Tuesday, February 26, the natural gas rig count increased by 1 to 195. The number of oil-directed rigs fell by 10 to 843. The total rig count decreased by 9, and it now stands at 1,038.
Prices rise across the country amid unseasonably cold temperatures. This report week (Wednesday, February 27 to Wednesday, March 6), a stretch of colder-than-normal temperatures affected much of the country through the weekend and into the first half of the week. Henry Hub spot prices rose 9¢ from $2.85/MMBtu last Wednesday to $2.94/MMBtu yesterday. Henry Hub prices hit a high of $4.12/MMBtu on Monday as below-freezing temperatures affected parts of Texas and Louisiana. At the Chicago Citygate, prices increased 3¢ from $2.95/MMBtu last Wednesday to $2.98/MMBtu yesterday, with a weather-driven high of $8.97/MMBtu on Friday. Western prices rise in response to cold weekend before returning to previous levels. Temperatures in the West were forecast to be unusually cold over the weekend, leading to prices rising on Friday. Prices at PG&E Citygate in Northern California fell 15¢, down from $4.41/MMBtu last Wednesday to $4.26/MMBtu yesterday. This net decrease in price followed a Friday high of $6.07/MMBtu. Prices at SoCal Citygate increased 22¢ from $4.91/MMBtu last Wednesday to $5.13/MMBtu yesterday. Temperatures in Southern California remained within the normal range over the weekend, but they were forecast to be colder through the rest of this week. SoCal Citygate prices hit a high of $8.83/MMBtu on Monday. In addition to colder temperatures, maintenance at the CASA C compressor station near Phoenix, Arizona, was expected to reduce flows on the El Paso Natural Gas South Mainline, which flows into Southern California from Arizona. The maintenance began Tuesday and is expected to reduce capacity by 100 to 200 MMcf/d through Friday. Prices at the Waha Hub in West Texas, which is located near Permian Basin production activities, averaged $0.98/MMBtu last Wednesday, $1.87/MMBtu lower than Henry Hub prices. Yesterday, prices at the Waha Hub averaged $1.14/MMBtu, $1.80/MMBtu lower than Henry Hub prices. Similar to the Henry Hub, Waha hit a high of $3.11/MMBtu on Monday amid below-freezing temperatures in West Texas. Pacific Northwest prices spike to record highs amid cold weather and supply constraints. Spot prices at Sumas on the Canada-Washington border rose sharply to average $161.33/MMBtu on Friday, with an intra-day trading range of $125.00/MMBtu to $200.00/MMBtu (the latter being the highest recorded spot price in Natural Gas Intelligence’s price history). The price spike came as the region experienced unseasonably cold temperatures and significant supply constraints. Last October’s explosion on the Westcoast Energy Pipeline, which transports natural gas through British Columbia, Canada, and into the United States at Sumas, has led to reduced capacity on the pipeline all winter. Maintenance related to the explosion was planned for the weekend, which further lowered import capacity. In addition, since the first half of February, compression problems at the Jackson Prairie storage facility in southwest Washington have limited the rate at which natural gas can be withdrawn from the storage facility. As a result, when the cold temperatures moved into the Northwest and increased heating demand, natural gas withdrawals from the facility could not offset the imbalance between natural gas demand and supply availability in the region. The weekend maintenance was ultimately cut short, and Sumas prices fell to $15.63/MMBtu on Monday. Northeast prices rise. At the Algonquin Citygate, which serves Boston-area consumers, prices went up $1.28 from $5.71/MMBtu last Wednesday to $6.99/MMBtu yesterday, with a high of $9.44/MMBtu on Tuesday. At the Transcontinental Pipeline Zone 6 trading point for New York City, prices increased 18¢ from $2.92/MMBtu last Wednesday to $3.10/MMBtu yesterday, with a high of $4.98/MMBtu on Monday. Tennessee Zone 4 Marcellus spot prices increased 16¢ from $2.73/MMBtu last Wednesday to $2.89/MMBtu yesterday, with a high of $3.96/MMBtu on Monday. Prices at Dominion South in southwest Pennsylvania rose 12¢ from $2.74/MMBtu last Wednesday to $2.86/MMBtu yesterday, reaching a high of $4.12/MMBtu on Monday. Supply remains flat as Canadian imports rise, offsetting production declines. According to data from PointLogic Energy, the average total supply of natural gas remained the same as in the previous report week, averaging 93.9 Bcf/d. Dry natural gas production decreased by 1% compared with the previous report week as cold temperatures potentially affected production. Average net imports from Canada increased by 17% from last week. Demand rises sharply amid cold weather. Cold temperatures led total U.S. consumption of natural gas to rise by 11% compared with the previous report week, according to data from PointLogic Energy. Total U.S. consumption averaged 100.2 Bcf/d for the week, 32% higher than the same week last year. The residential and commercial sectors saw the largest increases as consumption rose by 16%. Natural gas consumed for power generation climbed by 9% week over week. Industrial sector consumption increased by 5% week over week. Natural gas exports to Mexico decreased 1%. Total daily demand (including exports) has exceeded 100 Bcf since February 24. U.S. LNG exports flat week over week. Eight LNG vessels (seven from Sabine Pass and one from Corpus Christi) with a combined LNG-carrying capacity of 28.8 Bcf departed the United States from February 28 to March 6, according to shipping data compiled by Bloomberg. Kinder Morgan’s Elba Island LNG project in Georgia received approval to introduce feed gas, back-up fuel, and boil-off gas, according to a FERC filing yesterday. Trains 1–6 are expected to enter service by the end of the month, with each train to be commissioned consecutively in one-month intervals. Trains 7–10 are projected to enter service in the third quarter of 2019. This week, Cheniere Energy—the developer of the Corpus Christi liquefaction terminal in Texas—and Bechtel have announced substantial completion of Corpus Christi Train 1. The first commercial delivery from Train 1 is expected in June 2019. Train 2 is currently being commissioned, with the first expected production of LNG in April 2019.
Net withdrawals from storage totaled 149 Bcf for the week ending March 1, compared with the five-year (2014–18) average net withdrawals of 109 Bcf and last year’s net withdrawals of 60 Bcf during the same week. Working gas stocks totaled 1,390 Bcf, which is 464 Bcf lower than the five-year average and 243 Bcf lower than last year at this time. According to The Desk survey of natural gas analysts, estimates of the weekly net change from working natural gas stocks ranged from net withdrawals of 124 Bcf to 155 Bcf, with a median estimate of 146 Bcf. The average rate of net withdrawals from storage is 8% lower than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 7.3 Bcf/d for the remainder of the withdrawal season, total inventories would be 1,172 Bcf on March 31, which is 464 Bcf lower than the five-year average of 1,636 Bcf for that time of year.