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Cooler Temperatures Ahead Leave Weekly Prices Lower; TCO Explosion Pressures Appalachia

It was a sluggish start to the week for natural gas and despite some late-week support from a pipeline explosion and a brief return of hot weather to key demand areas, prices ended the week in the red; the NGI Weekly National Spot Gas Average fell a penny to $2.58.

Weather was front and center for the better part of the week as population-dense regions like the Northeast got a break from the heat. Temperatures in New York were in the 70s for most of the week but then were forecast to climb back into the low 80s by Friday. Boston highs barely reached the low 60s for most of the week, but were expected to soar into the low 80s by Saturday. Meanwhile, Texas failed to get a reprieve from the late summerlike heat, with temperatures reaching the 90s and locally 100s in some areas, with no end in sight showing up in weather outlooks.

Despite most pricing hubs posting losses of less than a dime, some Appalachian markets posted double-digit drops for the week, stemming from Thursday morning’s explosion and fire on Columbia Gas Transmission LLC’s  (TCO) Leach Xpress Pipeline in West Virginia. TCO said about 1.3 Bcf/d of firm service on the pipeline, which only began flowing gas in January, could be disrupted indefinitely following the incident in Marshall County, WV, prompting the company to issue a force majeure.

TCO said that until further notice, capacity on the segment would be cut to zero. A spokesperson for TransCanada Corp., which owns the TCO system, said the incident occurred at 4:15 a.m. ET. The cause of the blast remains unclear and the impacted area has been isolated, the company said.

Dominion South dropped 16 cents from June 4 to 8, falling to $2.31. Tetco M-3 Delivery was down 14 cents to $2.38. While most Appalachian pricing locations declined on the cut in exporting capacity, Columbia Gas Transmission prices ended the week 2 cents higher at $2.70.

“This is clearly a reaction to the explosion as export capacity out of the Mid-Atlantic region has been cut substantially,” Genscape Inc. analyst Vanessa Witte told NGI. “While some production will be shut-in, most of the gas will be rerouted from TCO onto other pipes. This means that export capacity out of the region will be more fully utilized and could lead to the region once again feeling constrained with respect to export capacity.”

Some Northeast points put up slightly heftier losses. Transco zone 6-NY was down 8 cents from June 1-8 to $2.64, while Algonquin City-gate tumbled 13 cents to $2.46.

Part of the decline at Algonquin came as Genscape reported that a liquefied natural gas (LNG) cargo on the BW Boston was en route from Atlantic LNG in Trinidad and Tobago and was expected to arrive Thursday.

Assuming a full cargo, the LNG shipment will fill most of Everett's storage inventory, which Genscape estimates has only 396 MMcf out of 3.35 Bcf remaining. Everett is the primary fuel source for Exelon’s Mystic Generation Station, but the power plant has not cleared a day-ahead generation schedule since June 1 and has not shown significant generation since the morning of June 3, Genscape said.

The maximum estimated burn it has observed is ~290 MMcf/d, “but Mystic has not run a full daily output schedule from CC units 8 & 9 (the two units fueled by Everett) since April 9. A now-operational Salem Harbor plant in the same zone reduces the power transmission risk of Mystic not running,” analyst Josh Garcia said.

Meanwhile, the Permian Basin was a shining star for the June 4-8 period, with gains of more than 20 cents seen across West Texas and southeastern New Mexico. El Paso-Permian surged 31 cents to $2.18, while Waha rose 20 cents to $2.24.

The Permian Basin extended its lead in the U.S. rig count, adding three rigs to grow its count to 480, a whopping 30% increase from 368 a year ago, Friday’s Baker Hughes Inc. rig count data showed. According to a more detailed breakdown of that data by NGI’s Shale Daily, four rigs were added in the Delaware Basin, while one was lost in the Midland Basin.

The Permian may be facing oil and natural gas pipeline bottlenecks, as well as a dearth of supplies and labor, but that has not stopped activity levels and investments from increasing, particularly by private operators, according to analysts. Data indicate a strong expansion recently by private exploration and production companies in an area called the Midland North, which would be in West Texas, where activity has moved into the development phase.

Turning to Nymex futures action, the impact from the TCO event hit the market swiftly. Nymex July futures jumped about a nickel before the market even opened on Thursday. Support remained strong just before the storage report from the Energy Information Administration (EIA) and even though prices eventually pulled back, the prompt month settled Thursday at $ 2.93, up 3.4 cents on the day. From June 4-8, the July contract dropped 4 cents to $2.89.

“With supply growth being so critical to the health of summer fundamentals, it is no surprise that this morning's Columbia Gas incident” in West Virginia was met with price upside, Societe Generale (SocGen) natural gas analyst Breanne Dougherty said late Thursday. “Until the storage deficit softens, ALL bullish news is expected to get a pronounced market response.”

The July contract jumped as high as $2.987 before the EIA storage report’s 10:30 a.m. ET release, but fell back to $2.96 as the reported figure -- a 92 Bcf injection -- crossed trading desks. The prompt-month eventually ended the day at $2.93, up just 3.4 cents.

The net 92 Bcf storage build compared with a 103 Bcf injection for the same week last year and the five-year average build of 104 Bcf. There were 71 cooling degree days (CDD) last week, compared with 44 CDDs at the same time last year and a 30-year normal of 42 CDDs. In the week ended May 25, 96 Bcf was added to storage.

At 1,817 Bcf, stocks were 799 Bcf below year-ago levels and 512 Bcf below the five-year average of 2,329 Bcf.

Before the data’s release, market estimates were wide ranging, between 77 Bcf and 98 Bcf, and short of the triple-digit injection some would expect from a holiday weekend. INTL FCStone Financial Inc. Senior Vice President Tom Saal told NGI that the story was the Memorial Day weekend. “If we got over 100 Bcf, I wouldn’t be surprised. That weekend should produce a big number.” His official estimate, however, was for a 97 Bcf injection.

ION Energy’s Kyle Cooper also projected a 97 Bcf injection, while a preliminary Bloomberg survey had a median estimate of an 89 Bcf build. A Reuters poll pointed to a 90 Bcf injection, and the Intercontinental Exchange EIA Financial Weekly Index settled Wednesday at an injection of 94 Bcf.

“This print is significantly looser from last week, indicating a slightly smaller injection despite very significant heat,” Bespoke Weather Services said. “However, Memorial Day holiday demand destruction likely played a large role, keeping us from reading too much into this.”

The forecaster was right on target with its 92 Bcf storage injection estimate. Bespoke’s Jacob Meisel said the EIA print indicated that the market is not tightening, something the forecaster’s daily power burn tracking had shown.

Given’s Thursday’s rally, SocGen’s Dougherty said market bulls have finally found confidence. While she was quick to note that the investment firm was not prepared to call the recent rise of the front to average just under $3/MMBtu a run, “it does bring the market almost in line with our base-case balance 2018 price view.”

Still, SocGen holds its bullish bias and emphasized that “we see potential for core summer prices to surge over $3.15/MMBtu under the right scenario,” Dougherty said. Hot weather could provide such a scenario, but so could any type of supply disruption or even slowed production growth pace.

“We reiterate that our base-case requires production to grow to 79 Bcf/d by the end of June and to 82 Bcf/d by end-2018 in order to meet summer market demand and this year's storage refill requirement,” she said.

Production averaged 78.7 Bcf/d for week ending June 1, according to SocGen. This was a slight increase from the prior week, which was detrimentally impacted by Millenium maintenance. “All eyes are on growth now, and hopefully June will provide some glimpse of the growth pace to come for the rest of this summer. We have yet to see a signal of a production surge, and the market appears increasingly uneasy about the delay in the wave that it has been anticipating for 2018,” Dougherty said.

Indeed, Lower 48 dry gas production has continued to hover around the 78 Bcf/d range, about 1.6 Bcf/d below Genscape Inc.’s forecast, although the data and analytics firm said it did not expect that delta to last long once maintenance season ends.

But Mobius Risk Group analysts said all the storage injections so far this year have implied demand growth of 1-3 Bcf/d, with an average of about 2.25 Bcf/d. “Continued implied year-on-year demand growth in excess of 1 Bcf/d throughout this summer could result in an end-of-October inventory level of less than 3,400 Bcf, which may not provide enough safety margin for a colder than normal winter,” analysts said.

If demand growth, however, turns out to be closer to what recent EIA storage reports have implied (2 Bcf/d), then end-of-October inventory level could fall below 3,300 Bcf, which should be supportive of higher prices heading into the winter months, Mobius said.

On the other hand, greater-than-expected production growth and mild summer temperatures could send prices lower, but should not create “containment pricing” in late October and early November (i.e., October and November cash trading significantly below summer 2019), “since inventory levels are not projected to exceed 3,700 Bcf, even in the mildest of weather scenarios,” analysts said.

Some industry experts, meanwhile, have lowered their end-of-October storage targets and opined that the market does not need as much storage as it has historically thanks to robust production growth. INTL FCStone’s Saal, however, said having adequate storage levels ahead of the peak winter season remains critical.

“The supply has to be where the demand is,” he said. “That Marcellus supply didn’t keep prices from going higher in January. We still pulled a lot of gas out of storage.”

If the United States experiences another winter like 2017-2018 and storage inventories start the season lower, “then we might get higher prices. You can’t assume shale production is going to bail us out in the wintertime,” he said.

With storage inventories now trailing year-ago levels by more than 30%, storage is below 2 Tcf after the first June injection for only the second time in the last decade, Jefferies analysts noted. The last time storage was sub-2.0 Tcf at this point was in 2014, when storage was much lower (~1.5 Tcf).

During that time, pricing averaged ~$4/MMBtu for much of the 2014 refill season, although production levels were substantially lower at that time (summer 2014 production of 69.7 Bcf/d versus 78.2 Bcf/d in May 2018). Given higher prices, gas power demand averaged only 27 Bcf/d from June-September 2014 versus the June-September 2017 average of 31.3 Bcf/d, Jefferies said.

As for this year, gas power burn was 3.1 Bcf/d higher year/year in May and continues to maintain a ~2.4 Bcf/d higher year/year rate through the first week of June. While gas prices did average ~13% lower in May year/year, the higher burn likely shows some of the shift in the U.S. power generation mix (more gas/less coal), Jefferies analysts said.

Additionally, the National Oceanic and Atmospheric Administration weather outlook for the next two weeks, next month and the next three months all predict warmer-than-average weather over much of the United States, “which could further increase power burn versus last year. We estimate that if power burn averages 2 Bcf/d higher year/year through the summer, while gas continues to run at ~7 Bcf/d higher year/year, then storage will end the refill season at 3.4-3.5 Tcf (below the five-year average of 3.8 Tcf),” Jefferies said.

Turning to the crude oil market, July crude treaded water during the week in anticipation of an Organization of the Petroleum Exporting Countries (OPEC) meeting set for June 22, in part, to discuss the possibility of key producers raising output to compensate for potential supply shortfalls stemming from U.S. sanctions against Iran and the loss of Venezuela output. The supply reduction put in place has pulled since last year about 1.8 million b/d total from the market.

Crude oil futures was up 99 cents from June 4-8 to reach $65.74.

Recent statements from Saudi Arabia and Russia indicate that OPEC and Russia may increase output by up to 1 million b/d after the June meeting in order to make up for actual losses from Venezuela and anticipated losses from Iran, SocGen said. The investment bank has factored in higher output, excluding those two countries, starting in 3Q18. “However, the gains will be gradual and start out less than 1 million b/d. The initial focus will be on making up for Venezuela,” Dougherty said.

As for demand, SocGen expects global oil demand to remain fairly healthy, with a projected growth of 1.6  million b/d in 2018 and 1.4 million b/d in 2019. “The main driver should be emerging markets, including China and India. However, growth should ease slightly in 2019 in emerging Asia and the U.S.,” Dougherty said.

With OPEC (excluding Venezuela and Iran) plus Russia eventually increasing supply by up to 1 million b/d, overall OPEC crude output should stabilize, SocGen said. Following substantial stockdraws from the Organisation for Economic Co-operation and Development in 2018, it projects minimal stock builds in 2019. “However, this year’s draws should provide ongoing price support next year, and this is the core of our moderately bullish price outlook,” Dougherty said.

The biggest upside risk would be if OPEC decides not to increase crude output in 3Q17 or increases it more slowly (10% probability, $10 crude price impact), SocGen said. The biggest downside risks would be if OPEC increases more and faster than expected, or if economic and oil demand growth sharply underperform (for both risks, 20% probability, $10 crude price impact).

For 3Q18, its forecasts for Intercontinental Exchange Brent and Nymex West Texas Intermediate (WTI) have been increased to $80/bbl and $75/bbl, respectively; these represent upward revisions of $12 and $11. For 4Q18, Brent and WTI have been revised to $78 (+$14) and $73 (+$13). For 2019, Brent and WTI have been adjusted to $72.75 (+$7.75) and $67.75 (+$6.75). For 2020, Brent and WTI have been increased to $70 (+$5) and $65 (+$4).

Turning back to natural gas, spot market action on Friday was fairly quiet as most pricing locations retreated on light weekend demand and a cool-down expected in key region in the week ahead.

Columbia Gas Transmission spot gas prices stabilized after Thursday’s explosion-related gain, slipping just a few pennies Friday to average $2.74 after trading in a tight range of 6 cents. Despite the dip in prices, activity was stronger day/day, with the number of deals increasing to 204 on Friday from 114 on Thursday. Traded volumes rose to 1,183 MMBtu/d from 626 MMBtu/d.

Other Appalachian pricing held steady at most pricing hubs. Dominion South traded at $2.11, unchanged from the previous day. Tennessee zone 4 Marcellus rose a penny to $1.92, while Tetco M3 delivery dropped 7 cents to $2.14. The Appalachia Regional Average was down 1 cent to $2.20.

In the Northeast, prices retreated rather significantly even as temperatures in the region were expected to rise during the weekend. NatGasWeather said that warming is forecast to spread across the northern and eastern U.S. through Saturday, with temperatures in the 70s and 80s gaining ground.

Despite the higher temperatures, Genscape projected Appalachia demand to fall to around 6.45 Bcf/d for the weekend before edging back up to 7.12 Bcf/d on Monday, which is still well below Friday’s projected demand of 8.95 Bcf/d. New England demand was expected to slide to 1.40 Bcf/d for the weekend and then rise to 1.60 by Monday, compared with Friday’s expected demand of 2.35 Bcf/d.

At Transco zone 6-NY, spot gas plunged 45 cents to $2.32. Tennessee zone 6 200 leg was down 6 cents to $2.53, while Iroquois, Waddington was down 9 cents to $2.57. At New England’s Algonquin City-gate, spot gas tumbled 13 cents to $2.21.

Over in the Rockies, drops of 20-plus cents were the norm amid the lighter weekend demand picture. Opal spot gas averaged $2.19, a drop of a quarter on the day. Northwest Wyoming Pool slid 26 cents to $2.13, and Kern River plunged 25 cents to $2.18.

Meanwhile, spot gas in Louisiana and Texas also retreated, although declines were not nearly as pronounced as very warm to hot conditions were expected to continue over the central and southern U.S. with daytime highs in the 90s to 100s, including Texas and the Southeast, according to NatGasWeather.

Despite the ongoing intense heat, Genscape expects demand to ease somewhat in the coming days. Friday’s projected demand in Louisiana was expected to reach 4.15 Bcf/d, but by Monday, demand was expected to top out at 3.37 Bcf/d. A similar level of demand was expected for the remainder of the week.

Texas demand was projected to hit 1.83 Bcf/d on Friday and then slide to around 1.36 Bcf/d for the entire June 11-15 work week, Genscape said.

At the benchmark Henry Hub, spot gas fell 7 cents to $2.86, while Southern Natural dropped a nickel to reach $2.82. Houston Ship Channel traded at $2.95, erasing all of Thursday’s gains.

Prices in the Permian Basin collapsed ahead of the weekend, with El Paso-Permian plunging 28 cents to $2.04. Waha tumbled 30 cents to $2.09.

California prices fared no better. SoCal Citygate slid 37 cents to 2.41, while PG&E Citygate dropped 12 cents to $2.87.

 

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