• June Nymex futures up 3.8 cents to $2.639; July adds 4.0 cents to $2.674
  • Pipeline data shows new volumes headed for Freeport LNG: Genscape
  • New Pemex tax cuts on the way in effort to boost production

U.S. natural gas futures rebounded Thursday as traders brushed off government storage data that continued the recent run of above-normal inventory builds. In the spot market, prices mostly pushed lower, with the largest declines recorded in California, West Texas and the Northeast; the NGI Spot Gas National Avg. dropped 5.0 cents to $2.160/MMBtu.

The June Nymex futures contract settled 3.8 cents higher at $2.639 Thursday as the bulls reclaimed some of the ground they’d lost during a 5.8-cent sell-off the previous session. Further along the strip, July added 4.0 cents to settle at $2.674, while August picked up 3.8 cents to settle at $2.689.

“We saw a little rally in prices throughout the curve...despite not really having anything in the dataset that was more bullish day/day,” Bespoke Weather Services told clients after the settle Thursday. Balances could see improvement as more heat arrives, at which point “some upside risk into $2.65-2.70 still very much remains in play.

“The strongest heat comes late next week into next weekend, at which time we will see the chance for numerous record highs in the Southeast,” the forecaster said. “Some spots have a good chance to see a couple of days with highs near 100 degrees, which is very intense for any pattern in late May. Low 90s can be seen up into the Mid-Atlantic as well on the hottest days.”

Models suggest the hotter temperatures won’t be “unending” like the pattern observed last year, with recent data “showing the heat relax as we head toward early June,” according to Bespoke.

Meanwhile, the Energy Information Administration (EIA) on Thursday reported an on-target 106 Bcf weekly injection into U.S. natural gas stocks, and futures gained following the news.

The 106 Bcf figure, covering the week ended May 10, compares with a 104 Bcf build recorded in the year-ago period and a five-year average 89 Bcf injection.

Estimates prior to the report had EIA unveiling a low-triple-digit build in line with the actual number. Major surveys had pointed to a 104 Bcf build, with predictions ranging from 93 Bcf to 125 Bcf. Intercontinental Exchange EIA Financial Weekly Index futures settled Wednesday at 105 Bcf, while NGI’s model predicted a 102 Bcf injection.

Bespoke viewed the EIA report as neutral, with the final injection matching the firm’s prediction and generally matching the consensus.

“Balance-wise, this is tighter than last week’s 85 Bcf build,” Bespoke said, estimating that recent balances would put the market on track to end the injection season with 4.0 Tcf in the ground. Still, “weather adjusting can be more difficult in these low demand times of the year. While 4.0 Tcf is probably unrealistic, it shows that we still need to see material improvement in balances to avoid a large storage total heading into winter.”

Total Lower 48 working gas in underground storage stood at 1,653 Bcf as of May 10, 130 Bcf (8.5%) above year-ago levels but 286 Bcf (minus 14.7%) below the five-year average, according to EIA.

By region, the South Central posted the largest weekly injection at 32 Bcf, including 25 Bcf into nonsalt and 6 Bcf into salt stocks. The East injected 31 Bcf, while the Midwest injected 27 Bcf. In the Pacific, EIA recorded a 12 Bcf build, while 4 Bcf was refilled in the Mountain region for the week.

The 106 Bcf build implies the market was 0.1 Bcf/d looser than last year after adjusting for weather, according to Raymond James & Associates analysts. By their estimate the market has averaged 2.0 Bcf/d looser over the past four weeks.

Analysts with Jefferies LLC observed that the past six weeks have “certainly given storage a head start before we enter the hottest parts of summer, with all April/May injections above average.”

By the Jefferies team’s count, the recent run of hefty builds has nearly cut the deficit to the five-year average in half since the end of March.

“The six injections have totaled 523 Bcf, 75% above the five-year average and around 70 Bcf higher than the second highest year on record,” according to Jefferies. “While the two May injections have both been above average, demand has returned to more normal levels this month, with the aggregate May injection just 20% above average (and in line with prior year levels) versus April injections around 140% above average.”

The key drivers behind rebounding demand in May have been cooler weather and liquefied natural gas (LNG) feed gas demand that has reached new highs following maintenance-related reductions in April, according to Jefferies.

“We expect LNG feed gas flows to continue to ramp through the summer, though weather comps set up more difficult year/year as last summer was around 10% warmer versus the five-year average, helping to drive gas power burn to record summer highs,” the analysts said.

Further hinting at a continued ramp up in LNG feed gas demand, recent pipeline scrapes have shown new flows headed in the direction of the Freeport LNG terminal.

On Wednesday, flows on Gulf South’s Coastal Bend Header line showed around 80 MMcf/d of volumes scheduled for delivery at the “Stratton Ridge (To Freeport LNG)” meter, with those molecules possibly bound for the Freeport facility, according to Genscape Inc. analyst Allison Hurley. Scheduled nominations at the location for Thursday remained at 80 MMcf/d.

“Prior to May 15, the only other time this nomination point has posted non-zero scheduled flows was on gas day April 24, with roughly 25 MMcf of gas delivered” to the meter, Hurley said. “Genscape’s power line monitoring at the facility indicates that the facility’s liquefaction engines are not running at this time.

“It is important to note that while nominations from Gulf South at the ‘Stratton Ridge (To Freeport LNG)’ meter allow some visibility into gas deliveries headed toward Freeport LNG, the Stratton Ridge salt dome facility lies just upstream of the Freeport LNG facility” and could be the destination for some part of nominated volumes, the analyst said. “...Genscape analysts also believe that this Gulf South location will be the only reporting interstate pipeline meter where nominations will provide some visibility into Freeport feed gas volumes; additional pipeline connections to the liquefaction facility will be provided via non-reporting intrastate pipelines.”

According to Patrick Rau, NGI's Director of Strategy & Research, "Freeport Train 1 could see around 700 Mmcf/d or so of daily demand when that facility is running full throttle, which may happen sometime this quarter." That facility is only an hour or so south of Houston, and it could provide some gas-on-gas competition at the Houston Ship Channel over the short-term.

By October, Kinder Morgan's 2.0 Bcf/d Gulf Coast Express Pipeline should be in-service, and while that pipeline will move gas into the Agua Dulce market, it will increase overall supply in South Texas, which should flow through to the Houston Ship Channel.

“Indeed, current forward prices at the HSC are roughly 4-5 cents above NYMEX for June through August, fall to just a 0.5 cent premium in September, slip to a dime or so below NYMEX for the October-March 2020 strip, and remain negative thereafter,” Rau said.

Spring Temps, Weak Prices

Southeast spot prices held steady Thursday. Transco Zone 5 added 1.5 cents to $2.580.

Meanwhile, in California, SoCal Citygate shed 13.0 cents to $2.815, while SoCal Border Avg. dropped 29.5 cents to $1.845.

Southern California Gas (SoCalGas) was looking for demand on its system to ease over the next couple days, dropping from 2.3 million Dth on Wednesday to around 1.9-2.0 million Dth/d by the weekend.

Further upstream in West Texas, prices also saw hefty discounts, with locations in the constrained Permian Basin giving back gains from earlier in the week. Waha had climbed steadily since the start of the work week, going from averaging 27.5 cents as of last Friday’s trading to 86.0 cents Wednesday. On Thursday, Waha stumbled 63.0 cents to drop back to an average of 23.0 cents.

Permian Basin production in the month of May has declined 170 MMcf/d sequentially as weaker natural gas prices have taken their toll on the region’s output, according to Jefferies.

“Waha pricing is clearly still weighing on Permian production,” the analysts said, noting recent spot and forward prices languishing well shy of $1.

A handful of pricing locations in and around the Permian managed comparatively hefty increases at the front of the curve during the May 9-15 period, helped by hotter temperatures in the region.

Waha June prices jumped 13 cents to average 37.9 cents, while July rose 10 cents to average 62.9 cents, according to NGI’s Forward Look. The balance of summer (June-October) was up 7 cents to $1.02. The winter strip (November 2019-March 2020) picked up a penny to $2.20.

Mexico Roundup

This week, Howard Energy Partners (HEP) said it has completed most of its planned oil and natural gas midstream infrastructure in the Permian Basin’s Delaware sub-basin, enabling more opportunities to move supply south into Mexico.

The Delaware assets are part of a strategic joint venture that HEP operates with WPX Energy Inc., supported by a 600-mile-plus area of mutual interest in New Mexico’s Lea and Eddy counties and the West Texas counties of Reeves and Loving.

The midstream infrastructure buildout is the initial phase of a broader strategic plan by HEP, which includes moving more oil and gas volumes to the Gulf Coast for export and into Mexico via the Nueva Era gas system.

Meanwhile on Thursday, the CEO of Mexico’s state oil company Petróleos Mexicanos (Pemex), Octavio Romero Oropeza, said that the Finance Ministry would provide added tax cuts to the company in an effort to help turn around oil and gas production declines. This is in addition to the $8 billion debt refinancing package announced earlier this week.

Pemex management has pledged a 50% increase in natural gas output to 5.7 Bcf/d by 2024, but production of natural gas has fallen 42% since 2009. Natural gas production fell by 6.9% year/year to average 3.665 Bcf/d during the first quarter, while production of crude and condensates dropped by 11.8% to 1.66 million b/d.