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April Chills Support Higher Weekly NatGas Spot Prices as Futures Market Sees Ample Supply

Winter refuses to go quietly, bringing some unseasonably cool April temperatures to the Midwest and East and boosting natural gas spot prices during the week ended Friday. The NGI Weekly Spot Gas Average climbed 43 cents to end at $2.77/MMBtu.

The biggest gains for the week occurred in the constrained New England market, where concerns over restrictions combined with above-normal heating demand to drive higher basis differentials. As prices spiked, Algonquin Gas Transmission opted to delay planned maintenance on its system and relieve some of the pressure.

Algonquin Citygate added nearly $5 week/week to average $7.39. Tennessee Zone 6 200L averaged $7.43 after trading at an average $2.71 one week earlier.

Midwest prices also got a boost as colder temperatures swept through during the week. Chicago Citygate jumped 44 cents week/week to average $2.83. In the Midcontinent, Northern Natural Ventura finished 46 cents higher at $2.81.

Prices generally strengthened across other regions as Henry Hub added 14 cents for the week to average $2.75.

Points in the Rockies increased but continued to trade at a negative basis to Henry amid gas-on-gas competition and generally moderate demand in the West. Cheyenne Hub ended the week at $2.10, up 14 cents, while Opal finished 10 cents higher at $2.06.

Forecasts for yet more April cold later in the month helped natural gas futures tick higher Friday, but surging production was still seen limiting upside heading into the shoulder season. The May contract settled at $2.701, climbing 2.6 cents on the day after trading as high as $2.717 and as low as $2.675. Week/week the May contract fell after ending the prior week -- shortened by the Good Friday holiday -- at $2.733.

NatGasWeather.com said midday weather guidance “was a little milder trending for the front week, but again colder trending on the back end, especially around April 18-20, seeing a stronger weather system into the East.

“The overall timeline of important features remains the same with a cold late season pattern across the northern and eastern U.S. through the middle of next week as several weather systems and associated cold blasts track through.”

After weather data trended colder Thursday night heading into Friday’s session, “this could have been a reason for bulls to push prices higher,” the firm said. “But yet again, front month futures have only managed a slight gain. There are risks of cooler trends across the northern U.S. for the end of April during the weekend, but will it matter when consistently colder trends over the past month have failed to spark a rally?”

Bespoke Weather Services said Friday it was revising its outlook to “slightly bearish” as colder temperatures look to decline in importance as the season progresses.

The firm said it’s also leaning bearish “after seeing an incredibly loose” Energy Information Administration (EIA) storage report Thursday “and a relative inability of prices to rally off of very constructive overnight weather trends...though we could see prices pop next week we do not see the makings of any sustained rally in natural gas, but instead see a loose balance amidst record production as enough to pull prices back below support once bullish weather eases.”

EIA reported a net decrease of 29 Bcf for Lower 48 gas stocks for the week ending March 30, but the figure came with an asterisk. In a footnote, the agency said the implied flow for the week was actually a withdrawal of 20 Bcf, with “nonflow-related adjustments” accounting for a 9 Bcf decrease in inventories in the South Central Nonsalt region for the period.

Markets seemed to latch on to the less impressive minus 20 Bcf “implied flow.” As soon as EIA’s 10:30 a.m. ET report crossed trading desks, the May contract slid close to 4 cents to as low as $2.651 before settling into a range of around $2.665-2.675 over the next half hour or so. By 11 a.m. ET, May was trading around $2.662, down about 5.6 cents from Wednesday’s settle.

The 20 Bcf implied withdrawal compares with a 4 Bcf pull in the year-ago period, while the five-year average is a withdrawal of 28 Bcf. Last week, EIA reported a 63 Bcf withdrawal for the week ended March 23.

Prior to the report, the market had been looking for a larger withdrawal than the implied flow.

The median taken from a Bloomberg survey had showed traders and analysts expecting a 26 Bcf withdrawal for the week, with responses ranging from 22 Bcf to 39 Bcf. A Reuters survey of 23 participants had settled on a median 26 Bcf draw with a range of 19 Bcf to 35 Bcf. IAF Advisors analyst Kyle Cooper had called for a withdrawal of 23 Bcf, in line with Intercontinental Exchange EIA storage futures, which had settled Wednesday at a withdrawal of 23 Bcf. OPIS by IHS Markit expected a withdrawal of 27 Bcf.

Shortly after the release of the storage data, Bespoke Weather Services said it viewed the report as looser than the 25 Bcf withdrawal it had predicted.

“Though stockpiles are marginally smaller than previously modeled, it is the minus 20 bcf implied flow that is indicative of current balance, and that shows a market that has continued to loosen dramatically over the last few weeks,” Bespoke said. “As expected, prices quickly dipped off of what was expected to be a loose print and already tested our $2.65 support level, which should be tested again.”

Including the net 9 Bcf decrease because of reclassification, total working gas in underground storage stood at 1,354 Bcf as of March 30, versus 2,051 Bcf a year ago and five-year average inventories of 1,701 Bcf, according to EIA. The year-on-year deficit increased week/week from 672 Bcf to 697 Bcf, while the year-on-five-year deficit widened slightly from 346 Bcf to 347 Bcf, EIA data show.

Looking at the implied flow by region, 18 Bcf was withdrawn in the Midwest, followed by the East, which saw a net 13 Bcf withdrawal. The Pacific region finished flat for the week, while 1 Bcf was withdrawn in the Mountain region. In the South Central, EIA reported an implied injection of 12 Bcf, including 7 Bcf injected into salt and 6 Bcf injected into nonsalt.

The draw of 29 Bcf “was a bit misleading due to 9 Bcf of nonflow-related adjustments -- the implied number was 20 Bcf, which came in below the lowest Street estimate,” analysts with Tudor, Pickering, Holt & Co. said Friday. “Henry Hub ended the day down 2% as the draw implied a stronger than expected shift to weather-adjusted oversupply, though there could be some noise in the number” from the Good Friday holiday.

The coming week “could still see some messiness from the weekend, but look for the market to still lean oversupplied through April.”

Genscape Inc. noted Friday that “compared to degree days and normal seasonality, the reported 20 Bcf withdrawal appears loose by plus-2.9 Bcf/d versus the prior five-year average. Headed into shoulder season we are starting to see storage reports loosen, which is consistent with our Forward Supply & Demand and SpringRock Production forecasts, both having consistently been pointing to supply growth this summer outpacing demand growth (even with expectations for structural demand increases).”

Meanwhile, data from OPIS by IHS Markit showed Lower 48 dry gas production averaging 79.9 Bcf/d for the week ending Thursday.

“On a daily basis, Lower 48 dry production has spent five of the last 10 days above the 80 Bcf/d mark,” according to the firm, which noted that growth in the Eagle Ford and Haynesville shales helped drive a nearly 0.3 Bcf/d week/week gain. In Texas, a 0.3 Bcf/d increase in gas output from the Eagle Ford was offset by a nearly 0.2 Bcf/d decline in Permian gas production.”

In the Southeast, OPIS noted, the Haynesville-Louisiana (LA) and the Other LA-North producing areas “each saw 0.1 Bcf/d increases in dry production.”

In the spot market Friday, prices in the Mid-Atlantic rose ahead of a cold front expected to sweep through over the weekend as points in the West retreated; the NGI National Spot Gas Average slipped 4 cents to $2.88/MMBtu.

A developing storm system over the southern Plains on Friday was expected to “cause a variety of weather impacts to the south-central U.S. to close out the week,” the National Weather Service (NWS) said. The southeastern United States and Virginia were expected to be affected by the same storm system going into Saturday as it tracked eastward. “Moderate to heavy rainfall is expected across much of Virginia and North Carolina, with some snow possible for the central Appalachians.”

Radiant Solutions on Friday was calling for temperatures to fall to around 11-14 degrees below normal by Sunday in major East Coast cities including Atlanta, New York, Philadelphia and Washington, DC.

Genscape’s regional demand forecasts had Appalachian demand climbing to 14.39 Bcf/d Saturday versus a recent seven-day average of 12.84 Bcf/d. Southeast and Mid-Atlantic demand was expected to peak at 16.4 Bcf/d Saturday versus a recent seven-day average of 15.03 Bcf/d.

Transco Zone 6 New York jumped 28 cents to $3.16 Friday, and further south Transco Zone 5 similarly gained 34 cents to $3.14. In Appalachia, Tetco M3 Delivery added 21 cents to $2.90.

In New England, Algonquin Citygate capped off a volatile week by shedding $1.14 to average $8.47.

Algonquin Gas Transmission recently delayed planned maintenance that likely contributed to elevated prices for the past week, and according to Genscape, demand “during the originally planned dates would have been well in excess of the capacity restrictions...raising questions as to the feasibility of implementing the capacity restrictions at this time.”

Meanwhile, plans to potentially shutter the roughly 2 GW Mystic Generating Station in Massachusetts have further complicated ISO New England’s (ISO-NE) task of meeting the region’s energy needs, according to Genscape.

With the week’s potential for gas shortages, “the Mystic power plant has come into and out of play,” the firm said. In the past few days “Mystic failed to clear into the into the New England power stack. Mystic provides baseload gas-fired generation that is somewhat insulated from pipeline constraints because it is fed with liquefied natural gas-sourced gas. Its absence from the stack was curious at a time of high power prices, and made even more intriguing by” operator Exelon Corp.’s announcement that it intends to retire the plant by 2022.

The week demonstrated, however, that “Mystic is very much needed in the ISO-NE. As a result, the ISO-NE initiated a process to prevent the retirement of Mystic.”

In the West, a number of points saw double digit declines amid expectations for generally mild demand for the weekend. Genscape’s forecast for the Pacific Northwest showed demand expected to ease slightly to around 1.6 Bcf/d by Monday after climbing as high as 2.09 Bcf/d over the prior week. Malin tumbled 18 cents to $2.05.

Further upstream, Rockies prices dropped almost across the board. Cheyenne Hub fell 15 cents to $2.08, while Opal gave up 18 cents to $2.00.

“Efforts to increase natural gas production in the Rockies are running into a brick wall -- make that several brick walls,” RBN Energy LLC analyst Housley Carr said in a recent note. “To the east, burgeoning gas production in the Marcellus/Utica shale region is surging into Midwest markets, pushing back on Rockies gas supplies. To the south, Permian gas production is ramping up toward 8 Bcf/d, most of it associated gas from crude-focused wells--volumes that will be produced even if gas prices plummet.

“To the west, Rockies gas faces an onslaught of renewables in power generation markets, where wind and solar are increasingly replacing gas-fired and coal generation, especially during nonpeak periods when the sun is shining and the wind is blowing,” Carr said. “To the north, Western Canadian producers facing a where-do-we-send-our-gas problem of their own” will be looking to take advantage of recently increased pipeline capacity.

Considering competition from hydro and wind/solar generation, competition from Western Canada and import and storage restrictions for Southern California Gas Co., among other factors, “you have a 2018 recipe for lower Western gas demand, more volatile gas prices and generally wider basis compared to Henry Hub,” according to Carr. “None of this bodes well for the Rockies, and the mid- to longer term it is only going to get worse.”

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