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Small Adjustments for Natural Gas Futures, Spot Market Amid Shoulder Season Lull

  • June settles 0.9 cents lower at $2.732
  • “Whoever controls $2.72-2.74 controls momentum, and right now neither bulls nor bears have the edge,” says NatGasWeather
  • April 2018 saw smallest monthly storage injection for April going back to 1983: EIA
  • Northern Natural maintenance could put more pressure on Waha prices: Genscape

Natural gas futures inched lower Tuesday, with bears and bulls both struggling to gain the upper hand amid the competing influences of production growth and storage deficits. In the spot market, with moderate shoulder season weather in full swing across much of the Lower 48, most regional  averages finished within a few pennies of even; the NGI National Spot Gas Average climbed 2 cents to $2.35/MMBtu.

The June contract settled 0.9 cents lower at $2.732, giving up some of Monday’s 3-cent gain after trading as high as $2.773 and as low as $2.706. July settled 0.7 cents lower at $2.760.

NatGasWeather.com reported “slight changes in the midday weather data, with slightly stronger demand showing up, which for this time of the year occurs through both cooler and hotter trends. A relatively minor change bigger picture, as a very comfortable weather pattern is still on track for the next two weeks where highs of 70s and 80s will rule most of the country for light demand and larger than normal injections into supplies.

“...To our view, whoever controls $2.72-2.74 controls momentum, and right now neither bulls nor bears have the edge,” NatGasWeather said. “What the markets will be watching closely is just how long it takes to reduce current hefty deficits of minus 534 Bcf back to minus 400 Bcf, which will be a gradual process and might not happen until the second half of June.”

In its latest Short-Term Energy Outlook, released Tuesday, the Energy Information Administration (EIA) estimated a total net natural gas storage injection of 22 Bcf for April, leaving inventories 27% below the five-year average by the end of the month.

“If confirmed in the monthly data, the April 2018 injection would be the smallest April injection since 1983,” EIA said, attributing the lean monthly build to what it said was the coldest April in 21 years based on preliminary data.

EIA continued to report net storage withdrawals into the third week of April, the longest the withdrawal season has extended into April going back to at least 1994, the agency said.

Thanks to rising production, now projected to average a record 80.5 Bcf/d in 2018 and increase further to 83.3 Bcf/d in 2019, EIA expects inventories to refill at a faster rate than the five-year average through the remainder of the current injection season, leaving inventories at more than 3.5 Tcf by Oct. 31, or about 8% below the five-year average for end-of-October inventories.

EIA also noted the tight trading range recently for natural gas futures in the face of what would typically be bullish storage deficits.

“Similar to price movements in March, natural gas futures prices in April traded in the narrowest range since 1995, with a difference of just 22 cents/MMBtu between the high and low prices,” EIA said. “In comparison, natural gas futures prices traded in a 41-cent range on average each month in 2017.”

Meanwhile, crude oil markets got a shake-up Tuesday in the form of President Trump announcing his intentions to pull the United States out of the Iran nuclear deal.

Moody’s Analytics said the most likely outcome from the decision “is that Iran does not restart its nuclear program, the U.S. imposes oil sanctions on Iran, and there is partial compliance with those sanctions but not enough to persuade Iran to restart uranium enrichment.”

The firm estimated a decline of 400,000 b/d of Iranian crude oil production as a result of the president’s action, noting that it does not expect the administration’s sanctions to be multi-lateral.

The announcement “is not expected to lead to a spike in oil prices, because much of his decision has already been priced in by oil traders,” the firm said. “We expect West Texas Intermediate (WTI) oil to average $68/bbl this quarter, accompanied by appreciable volatility. For the rest of the year we expect oil prices to slowly slip from this level, finishing the year at $64/bbl.”

Nymex WTI June crude oil futures settled at $69.06/bbl, down $1.67 on the day.

Turning to the spot market, most points saw small adjustments amid forecasts calling for generally moderate shoulder season temperatures.

“Most of the eastern U.S. will enjoy partly cloudy conditions for the middle of the week, with the frontal zone moving offshore and surface high pressure building into the region,” said the National Weather Service (NWS) Tuesday. “Temperatures are expected to be near normal through Wednesday before warmer weather and higher humidity arrives by the end of the week.”

Prices in the Northeast were mixed Tuesday, as Iroquois Zone 2 added 10 cents to $2.45, while Transco Zone 6 New York pulled back 8 cents to $2.55. Further upstream in Appalachia, Dominion South climbed 12 cents to $2.08.

Transcontinental Gas Pipe Line Co. LLC (Transco) told FERC late last week that it’s ready to place into service modifications enabling bi-directional flow at four compressor stations as part of its Atlantic Sunrise expansion. The modifications will add 150,000 Dth/d of capacity to the existing 400,000 Dth/d of interim service on the project, according to the company.
Transco asked the Federal Energy Regulatory Commission to approve its request by May 18 in order to begin service by June 1.

The additional capacity would run from the River Road interconnection to delivery points on the Transco Mainline as far south as the Station 85 Zone 4 Pooling Point in Alabama, the company told FERC.

Atlantic Sunrise is designed to eventually provide 1.7 million Dth/d of capacity allowing constrained Marcellus Shale gas to reach markets in the Southeast through the Transco system.

Genscape analyst Laura Munder noted that the request for start-up does not cover the project’s greenfield mainline or greenfield compressor stations, which the firm estimates will start up by July and during 3Q2018, respectively.

Although the additional 150,000 Dth/d “is said to be available, it was noted in the request that none of the project shippers have shown desire for the additional capacity, so Transco plans to post the capacity as unsubscribed once FERC approves the request,” Munder said.

The request “comes as a bit of a surprise” because Transco parent Williams “did not mention the potential for additional interim capacity” during the first quarter conference call, Munder added. “However, construction/restoration at the requested facilities is seemingly complete per the request, so the May 18 requested approval date is acceptable.”

Prices from the Rockies to California eased Tuesday after double-digit gains at most points the day before. Kern River trimmed 2 cents to average $1.95, while Kern Delivery fell 14 cents to $2.11. SoCal Border Average dropped 9 cents to $2.10.

“Across the West, scattered showers and a few storms are expected from the Pacific Northwest to the northern Intermountain West/Rockies...into Wednesday as a cold front moves in from the eastern Pacific,” NWS said. “...Farther to the south over the Desert Southwest, hot weather will continue underneath upper level ridging, with temperatures near or slightly above 100 degrees for the lower elevations of Arizona, southern Nevada and eastern California.”

In West Texas, El Paso Permian gave up 4 cents to average $1.63, while Waha added a penny to $1.84.

The Waha hub could come under yet more pressure later this week as additional Northern Natural Gas (NNG) maintenance may further restrict northbound capacity out of the Permian Basin, according to Genscape analyst Vanessa Witte.

On Thursday (May 10), “NNG work will reduce the operational capacity through Group 831 ‘Field to Demarc’ from its normal 1.375 Bcf/d down to 1.08 Bcf/d,” Witte said. “NNG is already in the midst of multiple field zone maintenance events, the most prominent being the reduction in capacity through Demarc due to modifications along the mainline.

“This maintenance event began April 10, where operational capacity was originally reduced from around 1.6 Bcf/d to the current roughly 1.37 Bcf/d in various stages, with nominations hovering at or near stated capacity.”

This comes as maintenance at a compressor station in Beaver, OK, is expected to restrict Beaver North group operational capacity by 115 MMcf/d also on Thursday (May 10) and by 275 MMcf/d on May 15-16, down from 975 MMcf/d.

“Scheduled capacity though this group has been as high as 960 MMcf/d since April 1, though nominations have been in decline since the beginning of May and averaged only 700 MMcf/d,” Witte said. “...Additionally, Brownfield North began maintenance on May 1...that will continue to restrict Permian production by around 100 MMcf/d through May 31.”

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