The battle over $2.15 natural gas waged on Friday, with bears already pouring their pumpkin-spiced lattes as weather models maintained a fall-like U.S. pattern through early September. Near-record production and liquefied natural gas (LNG) intake also held firm, leaving little reason for a significant move for the September Nymex futures contract, which settled Friday at $2.152/MMBtu, down seven-tenths of a cent on the day. October fell by the same amount to $2.156.
Spot gas prices continued to slide as demand was set to plummet through the weekend and into the final week of August. Led by dramatic losses on the East Coast, the NGI Spot Gas National Avg. tumbled 8 cents to $1.80.
Indeed, national demand is set to ease from strong recent levels to near normal as a cool shot continued to sweep across the Midwest and Northeast, according to NatGasWeather. A second system was bringing showers over portions of Texas and the South, cooling temperatures by several degrees.
“There remains locally strong demand across the West and portions of the southern United States due to highs of 90s to 100s, just not as widespread or as intense compared to recent heat,” the forecaster said.
There’s still expected to be a minor bump in national demand early in the week because of a warm break across the southern and eastern United States as 90-degree temperatures gain coverage, according to the firm. However, the weather data remains bearish Aug. 29-Sept 5 as a series of strong weather systems and cool fronts sweep across the northern, central and eastern United States with comfortable temperatures, including at times deep into the South.
Given the mild outlook, even more bearish with the upcoming Labor Day holiday, the next two to three weeks are likely to be difficult for natural gas, according to EBW Analytics Group. The best-case scenario for bulls would have been if the Energy Information Administration (EIA) reported an injection significantly below market expectations on Thursday.
“Instead, at 59 Bcf, EIA’s reported build was just 2 Bcf below the consensus, not enough to bring buyers back into the market,” EBW said.
The 59 Bcf injection was about 1.2 Bcf/d loose versus the five-year average when compared to degree days and normal seasonality, according to Genscape Inc., which had called for a 64 Bcf build. As a result, Lower 48 inventories were at 2,797 Bcf, building the surplus to last year to 369 Bcf and narrowing the deficit to the five-year average to 103 Bcf, EIA data showed.
“With roughly 11 more weeks of injections ahead, current forward curves indicate storage is trending to finish the injection season with about 3,660 Bcf in the ground before winter,” Genscape senior natural gas analyst Rick Margolin said.
Year-to-date, 1.7 Tcf of natural gas has been injected into storage caverns across the Lower 48, which compares to historical norms of only 1.3 Tcf (34% higher), according to Tudor, Pickering, Holt & Associates (TPH). The rapid replenishment has inflated inventories to a modest 4% deficit to the five-year average versus 22% when injection season began.
“It’s our view that the U.S. natural gas market will remain oversupplied in 4Q2019 and 1Q2020, with inventories exiting the year at an 18% surplus to the five-year average, with pricing to remain under pressure on the assumption that gas volumes continue to ramp into the full start-up of Gulf Coast Express,” TPH analysts said.
With LNG feed gas volumes breaking records at 6.5 Bcf/d and U.S. dry gas supply surpassing previous highs, the next few days should be interesting to watch, according to the firm. TPH is currently modeling a 50 Bcf build relative to norms of 51 Bcf.
Meanwhile, prices likely have further to fall. During the next three weeks, power sector demand for natural gas should rapidly decline, slipping by nearly 6 Bcf/d, according to EBW. Increases in LNG flows would offset less than one-fourth of this drop-off.
Low Henry Hub prices have plagued producers for most of 2019. The latest figure, comprised of actual day-ahead prices year to date and futures prices for September-December 2019, suggests that Henry Hub may average only $2.50/MMBtu, the second-lowest annual figure in at least 15 years, according to EBW.
“Calendar (Cal) year 2016 prices averaged only $2.47/MMBtu, as the blowtorch warm winter of 2015-16 slashed heating demand and led to massive oversupply conditions throughout the year,” the firm said.
Nymex futures for both Cal 2020 and Cal 2021 point to the potential for even lower prices ahead, closing Friday at $2.365 and $2.42, respectively. “The low figures highlight the extent of bearish expectations amid a currently oversupplied market and projections for a flood of Permian associated gas and weak global LNG demand,” EBW said.
With a burst of cooler and less humid air settling over the northeastern United States and setting the stage for an extended period of extremely mild temperatures, spot gas prices drifted even lower to cap the week.
Steep declines were seen across Appalachia and the Northeast, where dry air was forecast to continue making its southward progress, according to AccuWeather. Typical highs during the last part of August range from the middle 70s over northern Maine and the upper Great Lakes to the mid-80s over the Ohio Valley and the Chesapeake Bay region of the Mid-Atlantic states, the firm said. Lows typically range from the mid-50s across the northern tier to the middle and upper 60s over the Ohio Valley and lower Mid-Atlantic coast.
“However, since the air and high pressure system coming in had its origins over Northern Canada, temperatures are forecast to average between 5-10 degrees below normal” for the weekend, resulting in “temperatures being slashed by an average of 10-20 degrees from their peak” of the past week, AccuWeather senior meteorologist Alex Sosnowski said.
Highs were expected to generally range from the mid-60s over the northern tier and over the higher elevations of the central Appalachians to the upper 70s and lower 80s over the Ohio Valley and Chesapeake Bay region, according to the forecaster. Early-morning lows were forecast to range from the lower 40s in the Adirondack Mountains of northeastern New York state to the upper 60s over the lower part of the Chesapeake Bay.
AccuWeather was also monitoring an area of the Atlantic along the coast from Florida to the Carolinas for potential tropical development. Exactly how close to the coast a disturbance strengthens, if any tropical storm forms, may determine if more significant rain and wind develops along the Mid-Atlantic or New England shoreline and Interstate 95 corridor, it said.
Most spot gas losses in the southeastern United States were limited to less than a dime, including benchmark Henry Hub in south Louisiana, which fell 9 cents to $2.13.
Declines were a bit more pronounced in some areas of the Midcontinent, where ANR SW tumbled 15 cents to $1.395.
The Midwest also posted double-digit decreases, with Chicago Citygate shedding 10.5 cents to average $1.87.
Losses across Texas were rather small, while Waha managed to hold relatively steady.
On the pipeline front, a force majeure issued late Wednesday by Natural Gas Pipeline Company of America was continuing to constrain roughly 45 MMcf/d of Permian receipts intended to flow through Eddy County, NM. The pipeline cited a failure on the Indian Basin Lateral and provided no end date for the outage.
Across the northern border in Western Canada, NOVA/AECO C cash prices plunged 32 cents to average just C29 cents/gigajoule.
TC Energy Corp. invited Canadian natural gas producers to vote last Thursday on how capacity should be allocated on the NGTL system with the goal being reduced AECO volatility during shoulder season and times of maintenance, a pain point for producers in recent years. While a change in process is a positive step forward in reducing day-to-day volatility, TPH analysts said that upside would be limited given current Henry Hub pricing and a bearish outlook for the U.S. gas macro.
A deal on the stalled pipelines between Mexican utility Comisión Federal de Electricidad (CFE) and four private pipeline developers is expected to be signed in the coming days, according to reports.
Under the reported terms of the new agreement, transport fees would be raised for the first ten years of gas service and the contract terms would extend to 30 years, from 25. Mexico would realize nominal savings of $600 million over the duration of the contracts, according to preliminary analysis.
If a deal were reached it would mean gas could start flowing on the 2.6 Bcf/d Sur de Texas-Tuxpan marine pipeline, a crucial outlet for Texas natural gas and fundamental to reliable gas service to the southeast of Mexico. The $2.5 billion marine pipeline owned by Infraestructura Energética Nova (IEnova) and TC Energy Corp is ready to enter service but remains stalled as the pipeline spat continues.
In July, the CFE filed arbitration requests with four developers of seven stalled pipelines in the country in an attempt to amend the force majeure clauses of the 25-year firm capacity agreements built into the original contracts.
The other developers that are part of the reported deal are Mexican companies Fermaca and Grupo Carso.
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