Helped by cooler-trending forecasts, U.S. natural gas futures shaved off a little over a penny Tuesday after trading in a narrow range. Spot prices were mixed on a combination of hotter temperatures in the West and cooler conditions further East; the NGI Spot Gas National Avg. slid 1.0 cent to $2.065/MMBtu.
The August Nymex futures contract settled at $2.300, down 1.2 cents after trading as high as $2.328 and as low as $2.291. September gave up 1.8 cents to settle at $2.275, while October settled at $2.301, also off 1.8 cents.
Heading into Tuesday’s trading, guidance trended cooler overnight to drop a small amount of demand from the outlook, according to NatGasWeather. The mid-day Global Forecast System data came in “a touch warmer” for early next week but cooler for the first week of August, translating to a drop of 6 cooling degree days compared to 24 hours earlier.
“Timing of major weather features to impact the U.S. the next two weeks remains on track, with light national demand through Friday on strong cooling east of the Rockies, then increasing this weekend through early August as a warmer U.S. pattern returns,” NatGasWeather said. “…We continue to see flaws in the late July and early August pattern where weather systems will be able to provide areas of showers and cooling across the southern and central or east-central U.S. to prevent widespread heat.
“So while the pattern next week into early August is a relatively warm one with widespread highs of upper 80s to 90s, it still might not drop weekly builds under five-year averages.”
As for this week’s Energy Information Administration storage report, Energy Aspects issued a preliminary estimate for a 31 Bcf build for the period ending July 19.
“A 2.0 Bcf/d week/week gain in power sector gas demand and a 1.6 Bcf/d week/week loss in gas production, mostly driven by shut-ins related to Hurricane Barry, will halve the injection rate week/week,” the firm said.
Looking back at lessons learned from Barry’s impact on liquefied natural gas (LNG) feed gas volumes, questions remain over how much storage capacity Lower 48 export facilities have to absorb weather-related disruptions to loadings, according to BTU Analytics.
“Cheniere’s Sabine Pass currently has five storage tanks with approximately 17 Bcfe of storage capacity,” BTU analyst Tony Scott said. “However, two of those tanks are currently out of commission and have been since Feb. 8, 2018 after being ordered to shut down due to cracks. The reduction in storage capacity leaves Sabine Pass with only about 10.2 Bcfe of operational storage capacity.”
BTU estimates suggested that Sabine Pass could generate LNG for slightly more than three days without loading a vessel before filling its current storage capacity. Adding in the two tanks currently out of commission would grow that time frame to around five days.
“The smaller Cove Point and Elba Island facilities could continue operations for over three weeks in between loading vessels,” Scott said. “Both facilities were originally designed to provide peak shaving services in the winter time via imports and have significantly more storage relative to their export capacity as a result.”
Conversely, the first wave of Gulf Coast LNG projects, including Sabine Pass, Corpus Christi, Freeport and Cameron, all have somewhere between 13.9 Bcfe to 17.4 Bcfe of storage capacity. Once all four facilities are fully in operation, this would be enough to accommodate around four to six days of full utilization without loading any vessels, according to BTU.
“While Hurricane Barry tracked far to the east of Sabine and Cameron,” an observed dip in deliveries as the cyclone approached shows how “storm activity in the Gulf could have a significant impact on feed gas demand at the facilities going forward,” Scott said. “As an example, Sabine, Cameron and Freeport are separated by less than 100 miles and will combine for over 10 Bcf/d of demand when finished.”
As the second wave of U.S. LNG export projects gains steam, “the concentration of facilities in a small corridor could add significant volatility to demand in the years ahead.”
Meanwhile, domestic LNG exports should see continued support from low domestic prices, according to a new report from McKinsey & Co., which is forecasting North American natural gas demand to reach 125 Bcf/d by 2030 but with prices remaining below $3/Mcf during that time frame.
The firm’s North American Gas Outlook through 2030 was issued Tuesday by the McKinsey Energy Insights arm, highlighting expected changes in demand and supply. In addition to supporting LNG exports, analysts also see low prices unlocking more domestic demand, with the share of gas in the power mix likely to climb by 5 Bcf/d as more coal plants are retired.
“Debottlenecking and capacity additions that are currently or soon to be in progress will lead Appalachia to take a much larger role in supply, though associated gas from the Permian Basin will remain a substantial — and low-cost — supply source for much of the U.S. Gulf Coast,” researchers said.
Abundant gas resources will equal low prices for a long stretch, said McKinsey partner Dumitru Dediu. More than 1,000 Tcf, enough to meet demand for the next 20 years, is at cost economics “well below $3.00/MMBtu.”
Spot prices moves were mixed throughout California and the Rockies Tuesday, though those regions generally held onto gains recorded in Monday’s trading. After surging $1.540 on Monday, SoCal Citygate eased 22.5 cents to average $3.490. SoCal Border Avg. added 3.0 cents to $3.220, while PG&E Citygate slid 3.0 cents to $2.820.
Further upstream in the Rockies, Kern River gave back 6.0 cents to average $2.220. A day earlier, prices there jumped 40.0 cents on average.
A heat wave blanketing the western United States should support higher basis differentials for pricing locations from the Pacific Northwest to the Rockies to Southern California through the end of this week, according to Genscape.
“Southern California demand is on the rise as the heat wave moves onshore,” Genscape senior natural gas analyst Rick Margolin said Tuesday. In the Los Angeles Basin, “temperatures are forecast to run in the 90s through the end of the week, about 8-10 degrees above normal.”
Nominated demand for the region, including Southern California Gas, plus Kern River, Mojave and El Paso Natural Gas, was up to 3.35 Bcf/d Tuesday, a 40-day high, according to Genscape’s estimates.
Elsewhere, PG&E on-system demand was up to 2.49 Bcf/d as of Tuesday, a summer-to-date high.
“Pacific Northwest demand is also on the rise, hitting 1.9 Bcf/d” for Tuesday, Margolin said. “While that is not its highest level this summer, it is about 180 MMcf/d greater than the July month-to-date average.”
For the most part, spot prices were steady east of the Rockies Tuesday, with cooler conditions moving across much of the Lower 48 following intense heat over the weekend. Benchmark Henry Hub picked up 1.0 cent to $2.285.
“A cool front with showers and thunderstorms will continue advancing through the southern and eastern U.S. the next few days, easing highs into the 70s and 80s for much lighter demand,” NatGasWeather said.
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